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July 31, 2024

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NYISO to Ask FERC for Order 2023 Compliance Extension

RENSSELAER, N.Y. — NYISO on Wednesday said it plans to file a motion with FERC for an extension on the compliance deadline for Order 2023, according to a presentation given to stakeholders.

Thinh Nguyen, NYISO senior manager of interconnection projects, told the Transmission Planning Advisory Subcommittee (TPAS) and Electric System Planning Working Group (ESPWG) meeting that the ISO has 90 days to make its request to the commission, following the order’s publication in the Federal Register that day.

Nguyen added that NYISO plans to hold meetings focused on the interconnection queue and Order 2023 compliance that will be held after regular TPAS sessions and be potentially named the Interconnection Issues Task Force.

NYISO’s presentation also noted how, though it and several other RTOs have already asked FERC for a rehearing on Order 2023, the ISO might still comply with the order, as it is unclear if the commission will grant a rehearing (RM22-14). (See FERC Order 2023 Gets Rehearing Requests from Around the Industry.)

The ISO has been actively working to streamline its congested interconnection queue, and while it believes Order 2023 could improve efficiencies, it also cautioned stakeholders that it believes some of FERC’s directives may be legally inconsistent or counterproductive to the order’s goals.

Stakeholders probed NYISO staff for detailed information about the transition process and its potential implications.

Doreen Saia, an attorney with Greenberg Traurig, asked whether much of the transition was still to be determined or if the ISO could share some specifics.

Nguyen acknowledged that many of the specific details are to be determined but added that “for us to make a meaningful transition, we may need to sit down and figure out what this new process will look like and come up with a transition rule that will complement our own study process.”

Mark Reeder, representing the Alliance for Clean Energy New York, asked about the frequency of the newly proposed task force’s meetings and the expected outcomes.

“It’s too early to decide whether these will be biweekly or monthly meetings, but we want to make sure that when we host these meetings that we are coming to stakeholders with meaningful information rather than just general updates,” Nguyen said.

NYISO promised to return to stakeholders with more details on how it proposes to comply with Order 2023 and how proposed revisions might impact current interconnection processes.

Comprehensive Reliability Plan

NYISO also presented an updated draft of the Comprehensive Reliability Plan, with additional sections for dispatchable emission-free resources (DEFRs) and other developing technologies, as well as the short-term reliability needs recently identified in New York City.

The newly added “Beyond the CRP — Road to 2040” section, featuring DEFRs, was included in response to stakeholder requests. (See “Comprehensive Reliability Plan,” NYISO Proposes 48 Market Projects for 2024.) The CRP, which is the last part of the reliability planning process, is conducted every two years and evaluates the future risks to reliability and the viability of proposed solutions identified in earlier Reliability Needs Assessments.

FERC Order 2023

Historical generating capacity fuel mix in New York (2000-2023) | | NYISO

Mark Younger, president of Hudson Energy Economics, and Kevin Lang, partner at Couch White, questioned NYISO’s reliance on NERC data for reliability assessments, rather than using New York-specific data. Younger said New York City certainly has a reliability need in the short term but argued that using state data might lead to a more accurate accounting of potential shortfalls.

ISO staff said they are discussing the subject internally, though they emphasized that confidentiality concerns are a main reason New York data is not used.

NYISO aims to release its final CRP draft by late September and will seek committee approval in October.

Class Year & Expedited Deliverability Study Update

NYISO reported that 84 projects are officially part of Class Year 2023 and released a list of the 16 projects that have executed their expedited deliverability study (EDS) agreements.

The CY study assesses the feasibility of new projects looking to enter NYISO’s grid, while the EDS process is a more fast-tracked grid feasibility assessment for prioritized energy projects.

NYISO Manager of Facility Studies Wenjin Yan said the ISO must first finalize the EDS base case and estimated the study would finish next January.

Reeder suggested the ISO should consider tariff changes to allow for later entry into the EDS and consider starting another study after the current one is completed in early 2024 to enable projects to move ahead more quickly.

Yan said NYISO anticipates presenting CY23 for committee approval in July and August 2024.

NYC PPTN

NYISO gave a quick update on the New York City public policy transmission needs assessment, stating that the ISO is finalizing the baseline case and will share the data with developers upon completion.

The ISO reminded stakeholders, however, that the information would only be given to developers who have completed the requisite Critical Energy Infrastructure Information Non-Disclosure Agreement. According to both staff and stakeholders present, there is no set deadline for completing a CEII agreement.

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NJ BPU President Fiordaliso Dies

Joseph L. Fiordaliso, who led the New Jersey Board of Public Utilities as it embraced an aggressive and sweeping clean energy agenda marked by a major investment in offshore wind, has died, Gov. Phil Murphy (D) said Thursday.

Fiordaliso, 78, a BPU commissioner since 2005 and a former deputy chief of staff to former Gov. Richard Codey, spoke frequently about the need to adopt aggressive policies to combat climate change, saying he did not want future generations to look back at the agency’s efforts and question why it didn’t do more.

“Climate is changing,” he said at the board’s most recent meeting, on Aug. 16, shortly before it voted to enact a permanent community solar program after two well-received pilot programs. “And we all better be adults about the fact that we have to do something about it, not hide our heads in the sand. Because it’s not going to get any better; it’s only going to get worse.”

Fiordaliso’s death leaves the agency leaderless as it confronts increasing challenges to the state’s clean energy investment and especially the OSW program, which is facing community and special interest opposition and several lawsuits, as well as developer concerns about increasing costs that have raised questions about project viability.

The passing of the president removes a key font of experience on the board. Three of the four remaining BPU commissioners — Democrats Christine Guhl-Sadovy and Zenon Christodoulou, and Republican Marian Abdou — joined the board in the past year. The fourth, Republican Mary-Anna Holden, was appointed in 2012.

Under New Jersey law, the governor picks the BPU president and the senate can either confirm or reject the candidate.

Murphy, in a statement announcing Fiordaliso’s death, called Fiordaliso a “consummate public servant, a trusted colleague and a good friend.” The governor’s office did not say how or when Fiordaliso died, but the Associated Press said he died Wednesday.

“As president of the BPU since the beginning of my administration, Joe skillfully led our work to responsibly transition to a clean energy economy while always putting the needs of consumers first,” Murphy said. “Every time you saw Joe he was wearing his signature offshore wind pin or handing one out to anyone and everyone he met.”

To Fiordaliso, the pin — fashioned in the shape of a wind turbine — demonstrated support for the OSW program. But it drew criticism from opponents who saw in it a sign that he was too closely aligned with the OSW sector. The pin even drew the attention of a Republican lawmaker who quizzed Fiordaliso about it at a recent budget hearing.

Fiordaliso, however, said his interest was in doing what was best for the state and for ratepayers. In fact, at the board’s June meeting, he lashed out at the state’s two offshore wind developers who he said had created “delay after delay after delay … almost since Day 1.

“So I’m issuing a recommendation to those developers: Put your nose to the grindstone, and let’s get this going again,” he warned them. “Because my patience is short, and your delays are intolerable. And if you can’t do that, we have to have a very intense discussion.” (See NJ BPU Pulls Offshore Tx Project Mod from Agenda After Complaint.)

Top Priority

Murphy, who appointed Fiordaliso as BPU president on Jan. 15, 2018, has set a target for the state to develop 11 GW of OSW capacity by 2040. The BPU has approved three projects, totaling 3.758 GW, in two solicitations and is expected to announce the winners of a third round early in 2024, which could add 4 GW. In addition, the state has moved aggressively to jump-start a logistics sector to support the OSW projects, along with those of other states, which include the development of the New Jersey Wind Port to handle material and equipment for use in the projects. (See NJ Opens Third OSW Solicitation Seeking 4 GW+.)

Doug O’Malley, executive director of Environment New Jersey, an environmental group, said that Fiordaliso’s lengthy tenure as a BPU commissioner meant he was present in, and accrued a great depth knowledge of, the early years of the solar sector in the early 2000s. The BPU’s support helped put the state in the forefront of solar capacity development.

Fiordaliso also saw the inactivity on OSW during the tenure of Republican Gov. Chris Christie, from 2010 to 2018, and the BPU’s aggressive embrace of OSW when Murphy appointed Fiordaliso as the agency’s president will be a key plank of his legacy, O’Malley said.

“Wind was arguably the top priority for President Fiordaliso,” he said. “He cared deeply about offshore wind as kind of a new technology that you can harness.”

“Obviously, offshore wind has had choppy waters this year,” he said. “But we would not be in the position we are in without President Fiordaliso’s leadership.”

Other parts of the BPU’s aggressive agenda under Fiordaliso also have ruffled feathers. The agency is facing criticism from Republicans and business groups over the expense of the clean energy programs, including the lack of clarity on how much it will cost ratepayers. The programs include extensive subsidies for the purchase of electric vehicles (EVs) and trucks and the development of charging sites, proposals for subsidies of energy storage systems and plans to promote the use of electric heat and water systems in buildings and reduce the use of fossil fuels.

The New Jersey Business and Industry Association (NJBIA), which frequently disagreed with the BPU over cost concerns and the focus on electricity instead of other alternative energy forms, said in a statement prompted by his death that Fiordaliso was “truly and passionately committed to his job and its many missions.”

“Even when we didn’t agree on policy issues, President Fiordaliso always had an open door, took part in many NJBIA events and had receptive ears to our concerns,” said the statement from CEO Michele Siekerka.

Anjuli Ramos-Busot, director of the Sierra Club of New Jersey, released a statement that called Fiordaliso a “fighter for renewables and a proud supporter of offshore wind.

“He understood the severity of climate change and had a vision for the BPU to combat it,” she said.

Tough Upbringing

Fiordaliso grew up in a cold-water apartment in Newark, and he never forgot his roots as he was putting together policy, O’Malley said. That was particularly evident in Fiordaliso’s support for the state community solar program, which provides discounted clean energy to low- and moderate-income ratepayers, O’Malley said. (See NJ Opens Community Solar and Nuclear Support Programs.)

“He was a big supporter of making clean energy, especially solar, more accessible for more people,” O’Malley said. “He wanted to make sure the clean energy could reach every New Jersey resident.”

Fiordaliso graduated with a degree in business education from Montclair State University and was a teacher from 1967 to 1986, according to the university’s website. He was director of government relations for the Saint Barnabas Health Care System and served three terms as mayor of Livingston, N.J.

He was a member of the National Association of Regulatory Utility Commissioners’ Committee on Critical Infrastructure and Committee on Energy Resources and the Environment and also sat on the Executive Committee for the Regional Greenhouse Gas Initiative (RGGI) and RGGI’s Strategic Communications Team, according to the BPU website.

He also was board member of the Organization of PJM States Inc. and of the advisory council to the board of directors of the Electric Power Research Institute. In May 2023, FERC appointed Fiordaliso to the Joint Federal-State Task Force on Electric Transmission.

At the BPU’s meeting last month, Fiordaliso introduced several interns and spoke about the role of the board.

“We are doing work that’s going to help, hopefully save future generations,” he said. “It’s not many times in one’s career, and I’ve been working a long time, that you can actually say that I’m doing something that is going to affect future generations in a positive way.”

He noted that he had spent all but five years of his working life in the public sector.

“It is one of the most gratifying experiences I think a human being can have,” he said. “You may not make a million dollars but the satisfaction that you get from doing what you do is certainly worth a million dollars.”

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Report Touts Value of Demand Response, Flags Challenges Facing It

A new report dives into the role demand response (DR) and distributed energy resources (DER) play in the reliability of the rapidly evolving North American power grid.

“Unlocking the Full Potential of DERs: Overcoming Capacity Pricing and Other Barriers to Ensure Grid Reliability” is a collaboration by energy consultant Wood Mackenzie and DER developer CPower.

The report notes what the North American Electric Reliability Corporation and others have warned about: Large swaths of the United States face a growing risk of outages in peak demand periods or during emergencies as the nation moves from a centralized, predictable power flow to a distributed, dynamic grid.

The report continues:

While DR is not a baseload resource, it has proved highly reliable under severe conditions as traditional dispatchable power is supplanted by intermittent renewables.

DR, as the largest class of DER, is an increasingly important part of the resource stack in energy markets — the diverse sizes, locations and types of DR assets adds resilience and flexibility.

DR needs strong, consistent capacity price signals to promote enrollment and retention. These signals include ensuring that wholesale energy prices do not erode capacity prices; maintaining capacity pricing stability and predictability for customers who want to participate in DR programs, especially commercial/industrial customers; and addressing the common misconception that DR has zero costs and can stay in a capacity market as the price rides down to zero.

DR carries no capital costs but there are administrative and opportunity costs — so it is easy, even advantageous, for customers to stop participating when prices fall.

Adequate capacity pricing and capacity accreditation for DR are important.

The right price signals, such as a price floor, would reassure participants about the viability of the DR market.

CPower is developing what it calls the “Customer-Powered Grid” through DER monetization and virtual power plants — it has 6.3 GW of capacity at 20,000 sites across the U.S. It is owned by LS Power.

Wood Mackenzie provides global research, analysis and consulting in energy, renewables and natural resources.

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Environmental Orgs Request Rehearing on ISO-NE Reliability Program

The Sierra Club, the Union of Concerned Scientists and the Conservation Law Foundation jointly filed for rehearing Tuesday over FERC’s approval of changes to ISO-NE’s Inventoried Energy Program (IEP) (ER23-1588), arguing that ISO-NE failed to adequately justify the program and that it likely would increase costs for consumers.

The groups wrote that FERC’s approval of the program “errs in failing to examine whether tripling the costs of the [IEP] is just and reasonable in light of the lack of evidence that IEP payments would incent oil and gas generators to procure more fuel than they would otherwise.”

The nonprofits added that the commission’s decision also “errs in failing to consider new information about winter energy adequacy that is relevant to the need for the IEP, and thus to whether consumers would receive benefits proportionate to the enormous additional cost proposed.”

ISO-NE’s IEP is intended to compensate generators for keeping stored fuel onsite to ensure the region’s winter grid reliability, while the disputed changes to the program include the introduction of indexed rates meant to reflect changes in natural gas prices.

In ISO-NE’s original filing of the IEP changes, the RTO argued the changes “are designed to align key parameters of the IEP rates, terms and conditions with current market conditions and to make other improvements necessary to attract sufficient investment in incremental inventoried energy to support winter reliability.”

FERC unanimously approved ISO-NE’s proposed changes in an August ruling. (See FERC Approves Updates to ISO-NE Inventoried Energy Program.) In the order, FERC dismissed a range of complaints from the organizations and state consumer advocates related to the cost and justification of the program.

“The purpose of the Inventoried Energy Program is to incentivize resources to maintain inventoried energy to support winter reliability, and ISO-NE’s proposed revisions are designed to improve the program’s ability to achieve this goal,” FERC wrote.

In the rehearing request, the environmental organizations called FERC’s ruling “arbitrary and capricious.”

The groups wrote that FERC did not adequately consider the effect of changes to the region’s winter risk profile since the creation of the IEP, or whether the program actually would spur changes in behavior of generators. (See Study: Limited Exposure to Supply Shortfall for ISO-NE During Extreme Weather.)

“Most of the generators who receive a payment under the IEP, they’re already obligated to perform as capacity resources,” Casey Roberts, senior attorney with the Sierra Club Environmental Law Program, told RTO Insider. “In order to do that, they have to have fuel, otherwise they can’t run.”

Roberts argued FERC’s lack of scrutiny of the program’s justification and benefits sets a bad precedent for the approval of reliability programs.

“This really goes down to FERC’s core responsibility of protecting consumers from paying excessive rates,” Roberts said.

If FERC stands by its ruling, the environmental organizations could appeal FERC’s decision in court.

In June 2022, the U.S. Court of Appeals ruled the IEP could not compensate coal, hydro, biomass and nuclear generators because the incentive would not change their inventory operations. However, the court left the rest of the IEP in place, ruling that oil, natural gas and refuse generators are eligible for payments. (See Court Strikes a Blow to ISO-NE Winter Plan.)

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NRDC Lays out Responsible Tx Expansion Recommendations

The U.S. must double the number of transmission projects permitted and built each year to meet its clean energy potential, the Natural Resources Defense Council said Wednesday in a report recommending ways to speed permitting rules to allow enough construction to meet midcentury climate goals.

“We also must double the rate at which we expand the transmission system and simultaneously shift to building large interstate transmission lines instead of the small local lines that are mostly added today,” said NRDC Senior Advocate Nathanael Greene, the report’s lead author.

The Inflation Reduction Act is a huge opportunity for the country to roll out renewable energy and make significant progress on cutting greenhouse gas emissions, while the heat and natural disasters this summer show that climate change is happening and must be addressed, Greene said in an interview.

“Those two things I think allowed people to put building things higher on their priority list,” he added.

Issues around permitting have been a major focus for those working on federal energy policy all year, but so far, Congress has passed only a small package that largely ignored transmission. (See Lawmakers, White House Promise More Work on Permitting After Debt Deal.)

It is unclear whether lawmakers will be able to come up with another legislative package, but given the limited time due to the need to fund government operations and election season kicking into gear, NRDC wanted to express views on the subject to help inform any potential legislation, Greene said.

“This is an important conversation for Congress to be having because if a window opens, that’s not going to be open for long, and people need to know what’s important, what to do, what not to do,” he said. “Because it’ll have to happen quickly when it happens.”

A deal could be attached to some kind of must-pass bill this year, which would leave little time for members to examine the legislation, he added.

The report identifies four major barriers to getting needed transmission built, the first being the need to obtain federal authority to site, permit and allocate costs for large interstate lines while increasing community engagement.

FERC and the Department of Energy should work quickly to implement their strengthened authority to designate new “national interest transmission corridors,” the report said. (See States, RTOs Caution DOE on Transmission Corridors.)

NRDC is critical of FERC’s “rubber stamping” of natural gas pipelines, so it wants the agency to do more robust environmental reviews and provide stronger landowner protections when it comes to expanding the electric grid under its limited siting authority. While NRDC has litigated some of FERC’s implementation of the Natural Gas Act, that same kind of “bright line” siting authority would help expand the grid, Greene said.

“As long as it’s a political question about whether they’ll use that authority, it’s always going to be harder for them to do that permitting,” he added.

Ultimately, Congress should pass a law giving DOE authority to plan and FERC the ability to site large, interstate transmission lines, the report said.

Given that many of the projects NRDC wants to see built will cross state lines, having federal agencies planning and siting them makes sense, Greene said.

Another major recommendation is for FERC to “consider all the benefits of transmission” and then allocate them based on who benefits. The commission can implement rules to broadly allocate costs of new transmission to states, but if it fails to do so, then Congress should pass legislation requiring that, the NRDC said.

A pending notice of proposed rulemaking would update FERC’s planning and cost allocation rules. And while Chairman Willie Phillips has called that a priority, it has yet to pass.

Dealing with NIMBY

The report’s second recommendation is meant to deal with the opposition transmission projects often encounter because people do not want major infrastructure built near their homes, but that can be minimized by making community engagement a pre-requisite to siting rather than an afterthought.

“We know all the pieces of doing permitting better,” Greene said. “We just need to integrate and hold people accountable.”

The report suggests ensuring that communities gain benefits from hosting clean energy infrastructure. Specific benefits would vary by project, but they include jobs, environmental protections, financial contributions and energy benefits.

“Some developers already routinely negotiate community benefit packages for their projects,” the report said. “States should incentivize or require this as a best practice.”

The Inflation Reduction Act also earmarked money to help beef up permitting regulators in the states so they can adequately review the expanded pace of transmission development, Greene said.

The report’s third recommendation is to improve federal coordination, accountability and staffing of clean energy permitting and environmental reviews. That can be done without undermining the purpose behind the National Environmental Policy Act, the report said.

“Environmental reviews can be made much more efficient through increased agency resources, greater use of programmatic reviews, and permitting solutions that are tailored specifically to clean energy projects,” the report said.

The final recommendation is to embrace “smart from the start” planning to ensure that clean energy projects deliver conservation benefits and mitigate the impacts. That involves early and robust stakeholder engagement, planning at a landscape level, conservation of lands with important natural resources and cultural values, and moving projects to “low-conflict areas.”

“‘Smart from the start’ is designed to make permitting more efficient and to protect high-value lands by strategically focusing on regional or landscape-level efforts to mitigate the impact of renewable energy resources,” the report said. “These larger mitigation efforts often produce greater conservation outcomes than disparate project-level mitigation.”

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Report: Many US Utilities not Delivering on Energy Efficiency

Eversource Massachusetts scored 85 out of 100 points, taking the No. 1 spot on the American Council for an Energy Efficient Economy’s (ACEEE) 2023 Utility Energy Efficiency Scorecard, while Florida Power & Light and Ohio Edison held down the bottom of the list with 3 and 2.5 points respectively.

Published every three years, the recently released scorecard reflects the uneven, inconsistent role that energy efficiency plays in U.S. utilities’ efforts to decarbonize their power supplies, help customers cut their monthly energy bills and make their systems more resilient. The 53 utilities ranked on the scorecard, some of the nation’s largest, serve about 79 million residential customers, or 60% of U.S. households, in 31 states, the report says.

With their “enormous customer bases and the ability to scale solutions … the utility sector is perhaps the best positioned of any sector to deliver energy savings to Americans,” said Mike Specian, ACEEE’s research manager and lead author of the report. But, the scorecard shows, many are not doing so.

At the top of the list, 16 utilities managed to earn more than 50 points, and at the bottom, 16 earned less than 25.

Based on 2021 data, the scorecard shows investments in and energy savings from utility efficiency programs trending downward, Specian said. Total energy savings across all 53 utilities were 18.7 TWh in 2021, a 5.4% decrease since ACEEE’s last utility scorecard in 2020, which was based on 2018 data.

Utility spending on efficiency totaled $7.6 billion in 2021, a 4.9% drop from 2018, which, ACEEE said, contributed to a 19% drop in peak demand reduction. On average, U.S. utilities are spending 2.23% of their revenue on efficiency programs.

The figures for individual utilities underline the negative impact of these trends. Entergy Louisiana (No. 43, with 17 points) spent 0.21% of its revenue on energy efficiency, less than one-tenth of the national average. As a result, the utility’s energy efficiency programs shaved a meager 0.1% off its energy sales.

The caveat on such figures, and the rankings in general, is that they are based on data from 2021 and therefore may not reflect any changes in efficiency programs utilities might have made since then. In particular, as load management technology ― like smart thermostats ― evolve, lines between efficiency and demand response are starting to blur.

David Jacot, director of efficiency services at the Los Angeles Department of Water and Power (LADWP), said the public power utility recently consolidated its efficiency, DR and distributed energy services as part of its aggressive efficiency goals, a development not reflected in the scorecard.

But, Specian cautioned, most utilities are not connecting their energy efficiency programs to their decarbonization or emission-reduction goals. “In fact, 28 of our 53 evaluated utilities have established some form of carbon-reduction goals, [but] those targets have yet to work their way into efficiency programs,” he said.

Only the two Massachusetts utilities, Eversource Energy and National Grid, have “explicitly incorporated [greenhouse gas] reduction goals into their energy efficiency programs,” he said.

If and to what extent the billions in funding for energy efficiency in the Inflation Reduction Act will affect utility programs remains uncertain, in large part because, like other IRA programs, the incentives and rebates for efficiency have been slow to roll out.

The IRA’s $8.5 billion for rebates and tax credits for energy-efficient home upgrades will be administered by the states, and the U.S. Department of Energy only recently opened the application process for states to submit plans on how they will ensure the money is used to cut consumer energy bills and emissions. (See DOE Opens Applications for $8.5 in IRA Home Efficiency Funds.)

Utilities could have a central role in these programs for raising customer awareness of the IRA rebates and incentives. Many utilities already offer rebates on efficient appliances and promote their expertise as “trusted advisers” for customers considering home upgrades.

State Regulation

Downward trends notwithstanding, during a recent webinar on the scorecard, Specian focused on the report’s more encouraging findings, such as the correlation between state energy efficiency mandates and utility performance, and increasing investments in efficiency programs for low-income customers.

Utilities at the top of the list, as well as those that shot up in the rankings, often are in states that have set targets for utility efficiency programs.

Michigan, for example, passed its first energy efficiency law in 2008, requiring utilities to meet specific savings goals, and then upped the targets in 2016. Home-state utilities DTE Energy and Consumers Energy have exceeded those mandates every year, putting them in the scorecard’s Nos. 5 and 6 spots, respectively.

Dominion Energy was the scorecard’s most-improved utility, jumping from No. 50 in 2020 to No. 27 this year. Specian attributed its better performance, in large part, to efficiency goals set in Virginia’s Clean Economy Act, passed in 2020.

At the same time, rankings for Ohio utilities nosedived this year after the state legislature passed a law in 2019 ending its energy efficiency standards. Duke Ohio and AEP Ohio fell from No. 18 and No. 21, respectively, to tie for No. 49 this year. Ohio Edison tumbled from No. 34 to the very bottom of the list.

State mandates also can act as a brake on utility innovation. Public Service Electric and Gas rose from No. 42 in the 2020 rankings to No. 25 this year, largely because of New Jersey’s efficiency targets. But Susanna Chiu, PSE&G director of energy services, said regulations set by the Board of Public Utilities create a three-year cycle for planning new utility efficiency programs.

The current cycle, which runs through June 30, 2024, did not include decarbonization or more innovative DR programs. Those will have to wait for the next three-year planning cycle, which will run from mid-2024 to mid-2027, Chiu said. PSE&G is envisioning a one-stop-shop approach in which customers can choose efficiency services that are customized for their homes and their own efficiency and decarbonization goals, she said.

Low-income Programs

Total utility spending on efficiency may have dropped, but the money spent on programs for low-income customers has grown to more than 12% of overall efficiency spending — a 17% increase since the 2020 report — resulting in an 9.5% increase in savings per residential customer, Specian said.

Digging in deeper, ACEEE added new categories on equity to this year’s scorecard, which revealed some of the gaps that still exist in efficiency programs for low-income customers. Baltimore Gas and Electric dropped from No. 5 in 2020 to No. 12 this year, after losing points on some of the new equity categories.

In a separate, written analysis of the utility’s score, Specian praised BGE for its innovative program offerings, including “12 valuable efficiency programs not commonly available across the rest of the country.” Yet the utility lost points for “a lack of efficiency workforce initiatives, low levels of community engagement during program development and a failure to direct customers at risk of utility shutoff toward efficiency programs that could lower their bills,” he said.

Speaking during the webinar, Sanya Carley, professor of energy policy and city planning at the University of Pennsylvania, said efficiency programs can be a critical tool in helping low-income customers avoid disconnection.

A 2020 report from ACEEE found that low-income households have a heavier “energy burden,” spending 8.1% of their disposable income on energy versus the 2.3% for more well-off households.

Only 13 utilities on the scorecard direct customers at risk of disconnection to efficiency programs, Carley said, and existing efficiency programs may not address the needs of such “energy insecure” households. Living in an energy-inefficient home ― with gaps in walls, or windows that don’t close ― is one of the factors that may signal risk of disconnection, she said.

Carley has collaborated with researchers at the University of Indiana to launch an online Utility Disconnection Dashboard, tracking disconnections across the country.

“Some of the same utilities that have the highest rates of disconnection are the ones not directing their customers toward energy efficiency,” she said. “Does this mean that energy efficiency programs are too late to help or too little? The data don’t reveal answers to these questions, but we should of course ask them.”

Efficiency After LEDs

While it was not part of individual rankings, ACEEE did ask utilities what they see as major barriers to energy efficiency.

Responses ranged from the predictable ― inflation, supply chain delays and lack of skilled workers ― to the more existential, such as the rising cost of efficient technologies once programs address “low-hanging fruit,” such as switching out older light bulbs for LEDs.

“Utilities that have been successfully implementing energy efficiency for years reported experiencing market saturation for some efficiency measures and decreasing amounts of remaining savings,” the report says. “Others claimed that there was no technology that could easily fill the gap left by lighting.”

Lakin Garth, director for emerging technologies at the Smart Electric Power Alliance (SEPA), agrees some utilities eventually may face a declining stock of buildings to retrofit.

“You’ve got a certain number of buildings out there, and you’re acquiring all the most cost-effective energy efficiency over a three-, four- or five-year period. … Those same opportunities might not be there in six or seven or eight years,” Garth said. “But that doesn’t mean that the investment itself should decline.”

According to the National Association of Home Builders (NAHB), close to half of all homes in the U.S. were built before 1970 — before the first energy efficiency codes were passed later in the decade. California’s first energy efficiency code was adopted in 1976 and is updated every three years.

Given the large opportunity the NAHB figures represent, Vincent Barnes, senior vice president of policy and research at the Alliance to Save Energy, says the key obstacles to utility energy efficiency programs are utility regulation and business models.

“We don’t treat energy efficiency at par with other energy resources that utilities can respect as an asset,” Barnes said. “It really is about looking at energy efficiency as an energy resource and therefore identifying energy efficiency investments as capital investments — like transmission, like distribution — and the reason we have to do that is because the way the structure is currently set up, the only assets are supply-side assets.”

Energy efficiency programs address customers’ consumption behind the meter, he said. “It’s not until we’re able to identify those investments that are behind the meter, and energy efficiency also, as capital assets, [that we will] be able to actually achieve that greater investment number that we might be looking for.”

One encouraging development, Barnes noted, is that PSE&G has gained approval from the BPU to treat at least some of its energy efficiency investments as “regulatory assets” that can be included in the utility’s rate base.

Chiu confirmed that such efficiency investments do “earn a return … which makes those investments an alternative to pipes and wires.”

LADWP’s ‘Headroom’

In the No. 10 spot, LADWP is the highest scoring of the three public power utilities on the ACEEE scorecard. The other two are Long Island Power Authority (No. 16) and the Salt River Project (No. 23).

As an unregulated utility, LADWP has been able to approach efficiency from a totally different angle, Jacot said. “We really got in earnest behind energy efficiency around 2010 and made it a part of what we call our supply portfolio,” he said. “In other words, we treat energy efficiency as a generation resource … the cheapest marginal generation resource.”

Between 2010 and 2020, the utility cut its retail kilowatt-hours by 15% and is on track for another 15% cut by 2030, Jacot said, and those savings have created “headroom” for LADWP to absorb new load without building new generation.

Vehicle electrification is a case in point. As the utility’s customers plug in their Teslas and Ford F-150 Lightnings, “we’ve created the headroom through energy efficiency; that capacity is already there,” he said.

LADWP will have to build out its system eventually to meet the demands of widespread electrification and more frequent and intense heat waves, but the utility’s aggressive efficiency programs have bought it some time, he said.

Jacot stressed the ability of public power utilities like LADWP to innovate and try out new programs quickly, without going through the drawn-out regulatory approval process investor-owned utilities typically face. With the integration of LADWP’s efficiency and DR programs, Jacot is overseeing and exploring new possibilities for both programs.

“I can coordinate not only overall energy use reduction but smart energy management and load-shifting capabilities,” for example, using smart thermostats and heat pump water heaters, he said.

Heat pumps can be set at a variable speed to reduce overall consumption, and then set to run at specific times of the day for DR, he said.

Like PSE&G, LADWP’s goal is to have a one-stop-shop for customers to take advantage of both efficiency and DR programs, he said.

Next-gen Efficiency

Today’s energy efficiency programs trace their roots to the 1973 oil crisis, when the Middle Eastern countries in the Organization of Petroleum Exporting Countries slapped an embargo on exports to the U.S. to protest American support for Israel.

Efficiency then meant closing schools and businesses, rationing gasoline and reducing speed limits on the nation’s highways to 55 mph.

The challenges today are technologically more complex but could be equally essential to President Joe Biden’s goals of decarbonizing the grid by 2035 and building out a net-zero economy by 2050.

At LADWP, Jacot sees the value of efficiency evolving in different directions as solar and storage come on the grid.

“We’re in a transitionary period where energy efficiency at some points of the day actually doesn’t do you much good,” he said. Specifically, during mid-day peaks in solar production, “energy efficiency isn’t really helping. … So, the quantification of the benefits of energy efficiency on the demand side, the kilowatt side, is very much in transition.”

However, Jacot said, as more storage is deployed to sop up excess solar production, and electrification drives more demand for power, LADWP will “want all the energy efficiency we can get because it increases the amount of available storage and lowers the amount of storage you need to get through the night.”

SEPA’s Garth also sees efficiency as essential for maintaining reliability and affordability as the grid is decarbonized and transportation and buildings are electrified.

“If we’re electrifying or planning to electrify all these uses, then these utilities should be thinking about how to do that in the most efficient way possible,” he said. “Probably the next generation of efficiency programs is how do we electrify responsibly and efficiently and how do we identify the parts of the market that have been overlooked in the past?”

But producing the clean power needed for electrification will require significant capital investments, which utilities could seek to recover through higher rates, he said. “So, it only seems logical that in a decarbonized world … the investments made in energy efficiency are commensurate with the investments that are made to clean up generation or to reduce carbon emissions.”

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Wash. Allowance Prices Surge Again in 3rd Cap-and-trade Auction

Washington carbon prices continued to rise last week after the state’s latest cap-and-trade auction cleared at $63.03, up 13% from the May auction.

The August auction represented the third quarterly sale of allowances by the state, raising roughly $542 million in revenue on 8.6 million allowances sold, according to the Washington Department of Ecology. That translates into about $1.462 billion raised so far this year, with one regular quarterly and one supplemental auction still to go.

Washington Carbon Allowance (WCA) prices have risen steadily with each auction, with the February sale clearing at $48.50 and May’s hitting $56.01. The cap-and-trade program went into effect on Jan. 1, 2023.

“Prices at quarterly auctions are determined by auction participant behavior, so we can’t really speculate as to why bidding has resulted in any increasing settlement prices,” Claire Boyte-White, Ecology’s policy relations manager on cap-and-invest issues, said in an email to NetZero Insider.

“Because our program is still new, one potential explanation is that market participants are still getting their feet under them as they develop their compliance and decarbonization strategies” Boyte-White wrote.

In a summary of the auction results, emissions markets analytics company cCarbon noted that both the California cap-and-trade and Regional Greenhouse Gas Initiative markets saw prices peak during their third auctions before pulling back from those highs.

“Only time will tell if Washington’s WCAs will follow a similar trend!” cCarbon said.

The company also pointed out that financial traders increased their takings in Washington’s most recent auction, winning 14.5% of allowances compared with 10% in the previous auction.

“This increase, coupled with a lower bid ratio of 1.79, strongly suggests that compliance entities are content with their current holding at these price levels,” cCarbon said.

High allowance prices have been blamed for Washington having the highest gasoline prices in the nation this summer, outpacing even California, the only other state with a cap-and-trade program. (See Cap-and-trade Driving up Washington Gasoline Prices, Critics Say.)

Washington officials have been exploring whether the state should link up with the California-Quebec cap-and-trade system as a way to reduce prices, and hope to make a decision this year. That combined market is roughly six times as liquid as Washington’s, with allowance prices hovering at about $35.

Last week’s WCA auction once again exceeded the soft cap of $51.90 that triggers a requirement to hold a supplemental Allowance Price Containment Reserve (APCR) auction, a mechanism intended to contain carbon costs for industry by releasing more allowances into the market. The first APCR auction held in early August raised about $62.5 million on 1,054,809 allowances sold. (See Wash. Raises $62.5M from Cap-and-trade Reserve Auction.)

The next APCR auction is scheduled for Nov. 8 and will offer 1.58 million allowances.

“We anticipate that these extra APCR allowances will moderate prices in the short term,” cCarbon said in its summary. “Indeed, we are already seeing signs of this impact on the prices and demand from compliance entities in this third WCA auction.”

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Mass. Utilities Submit Grid Modernization Drafts

Eversource and National Grid expect their annual peak electricity load in Massachusetts to more than double by 2050, the utilities told the state’s Department of Energy Resources (DOER) last week.

The projections are part of the draft electric sector modernization plans (ESMPs) submitted to DOER by Massachusetts’ investor-owned electric utilities, which detail the electric distribution companies’ plans to meet the massive increase in electricity demand associated with the electrification transportation and heating in the state.

The wide-ranging drafts also include near-term investment proposals, five- and 10-year demand forecasts and solutions planning, and they mark a major change in how the state conducts grid planning.

The Grid Modernization Advisory Council (GMAC), a stakeholder committee created by the state’s 2022 Act Driving Clean Energy and Offshore Wind and convened by DOER, will review the filings, solicit public feedback and provide comments on the utilities’ drafts.

“It’s really taking a forward-looking approach for the first time in Massachusetts’ history,” said Kyle Murray, Massachusetts program director for the Acadia Center and GMAC voting member. Murray said grid planning in the state historically has happened in an “ad hoc manner.”

Murray added that one of the council’s goals is to engage the public in the grid modernization process and include voices that historically have been absent from these proceedings.

The draft ESMPs outline the large infrastructure investments that will be needed to enable the clean energy transition, including huge increases in peak electrical loads. National Grid expects its annual peak to increase from about 4.6 GW to 10.7 GW.

National Grid 2025-2029 proposed ESMP investments | National Grid

“Annual peak load, which is the maximum demand on the system in a given year, is expected to grow across our network 7% by 2029 and 21% by 2034 relative to 2022 levels, and more than double by 2050,” National Grid wrote in its 726-page report.

Eversource expects an even larger increase for its system, anticipating its peak to rise from about 6.1 GW to 15.3 GW.

“The majority of this 150% increase in electric demand by 2050 is driven by electrification of heating needs (about 50%) with the remaining driven primarily by electrification of transportation needs (25%) and normal load (25%),” Eversource wrote.

The utilities also noted that the increasing reliance on distributed energy resources (DERs) will further strain the grid and necessitate additional upgrades.

To meet the expected demand increases, Eversource proposed building 12 new substations and upgrading 16 existing substations. The company also proposed three new substations and 14 upgrades to accommodate additional solar resources. National Grid proposed upgrading or expanding 18 existing substations and building 28 new substations by 2034.

“Absent making these system investments in advance of these new peak demand levels, the expected load growth will result in overloads of existing equipment, which would impact the safety and reliability of our network operation,” National Grid wrote.

National Grid peak load forecasts | National Grid

Murray said one of his main hopes for the process is to help clear out the interconnection backlog of renewable energy projects.

“We know we need as many renewables on the market as possible, and yet they’re coming on at a pace that’s kind of like a trickle,” Murray said.

“Building system capacity with substations and battery storage systems will provide a critical foundation for enabling electrification and reliable interconnection of DERs,” Eversource wrote.

The utilities emphasized the importance of early public engagement while making these investments, and jointly proposed the creation of a Community Engagement Stakeholder Advisory Group (CESAG) to help boost engagement with potentially impacted communities. Under the utilities’ proposal, the group would be led by the utilities, with members agreed upon by the GMAC.

Eversource 2025-2034 proposed capital investments | Eversource

In an August letter to the GMAC, María Belén Power, undersecretary of environmental justice and equity at the Office of Energy and Environmental Affairs, stressed the importance of including environmental justice communities in the infrastructure siting process.

“[Environmental justice] populations should be engaged in public processes from the very beginning, not as an after-thought, and the engagement must be coupled with meaningful outcomes and results,” Power wrote. “Adding equity or community outreach as a final step in the process does not allow for a meaningful process. Successful community outreach happens when the voices and perspective of those most vulnerable are reflected in the outcome.”

Power said all communities affected by new grid infrastructure should be given ample opportunity to participate in siting processes, with accommodation made for the different languages spoken by residents. The undersecretary also emphasized the importance of considering the cumulative effects of grid infrastructure.

“When planning for new energy infrastructure or enhancement of existing ones, we must ensure we are not causing additional harm to those who have historically been overburdened,” Power said. “When possible and if feasible, if a project may cause additional harm or burden on EJ populations, an alternative site should be identified.”

The utilities also outlined some mechanisms to reduce future demand, including energy efficiency, advanced metering infrastructure, managed charging and time varying rates.

“Regulatory and tariff changes that enable time-varying rates and recognize the shift toward greater electrification are required to support more impactful offerings to offset peak demand growth with increasingly flexible loads and expanded deployment of distributed resources,” National Grid wrote.

Larry Chretien, executive director of the Green Energy Consumers Alliance and a GMAC member, told RTO Insider he still is reviewing the drafts, but agreed on the need to develop programs like time-varying rates and managed charging focused on reducing peak demand. High demand peaks lead to both higher costs for consumers and increased fossil fuel combustion.

“We think it’s sacred that we’ve got to reach our climate goals, but we also want to make sure that it can be afforded by folks who are economically vulnerable,” Chretien said. “I want to push the utilities on trying to bend the demand.”

The GMAC will hold public listening sessions Oct. 30 and Nov. 1, with final feedback and recommendations from the GMAC due Nov. 20. The utilities then must file their final ESMPs with the Department of Public Utilities in January.

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Stakeholder Soapbox: The Cost of Inaction — An Outdated Grid, Overpriced Power

Jason Stanek | Maryland PSC

By Jason Stanek

The nation has a looming problem. The infrastructure upon which millions of Americans rely on to power their daily lives is growing older while demand on regional power grids is breaking all-time records with increasing regularity. The country’s regional grid operators lack sufficient access to generation in neighboring regions, resulting in preventable power outages and soaring electricity prices during extreme weather events. Even under normal operating conditions, a lack of import and export capability between various parts of the country can result in higher power costs.

The construction of high-voltage transmission lines between regions has been stymied over the years for various reasons, but it is clear we increasingly need new interregional lines, both now and in the future. One relatively simple way to accomplish this would be for Congress to direct FERC to establish a minimum interregional transfer capacity requirement to ensure that grid operators have enough capacity to export or import a certain amount of power to neighboring regions at all times. Doing so will strengthen the nation’s resilience to extreme weather events, increase overall grid reliability and ultimately reduce the cost of delivered electricity to customers.

Fortunately, this policy option has recently been the focus of significant discussion by stakeholders. Late last year, FERC discussed such a minimum transfer standard. Notably, in its post-workshop comments, the U.S. Department of Energy emphasized that its draft National Transmission Needs Study finds a “pressing need for additional electric transmission infrastructure, including interregional transmission.” Additionally, this topic has merited review by the Joint Federal-State Task Force on Electric Transmission, a collaborative dialogue between FERC commissioners and state utility regulators.

So, what’s the “right” amount of transfer capacity? Some grid experts have called for a minimum interregional transfer capacity requirement ranging from 15 to 30% of peak load. While there are benefits and costs associated with a higher or lower percentage, there is wisdom in setting a uniform minimum requirement. As I recently testified before the Senate Energy and Natural Resources Committee, it would be more expeditious if Congress were to define and set a reasonable threshold rather than tasking FERC with a multiyear stakeholder process to determine the requirement, a process that would surely further delay critical projects’ buildout.

The need for new transmission lines also serves to mitigate the impact of extreme weather events, which are undeniably increasing in severity and frequency. In the first seven months of this year, 15 extreme weather events across the country — several of which caused power outages — each resulted in $1 billion or more in damages. These events accounted for the most disasters over the period since 1980. Extreme weather has also contributed significantly to congestion costs in recent years. While power outages during storms are never fully preventable, we can prepare our electric grid to better withstand them, as interregional transmission lines can transport available power from several states away to areas where local generators cannot meet demand.

Further, as I testified, long-distance wires connecting regions serve as an important insurance policy: While grid operators hope to avoid asking neighboring grids for electricity, it is important to have the ability to do so when a situation arises. For example, the addition of high-capacity interregional transmission lines from Texas to neighboring regions could have prevented the devastating storm-induced outages in February 2021, according to an analysis from power sector consulting firm Grid Strategies. Given the tremendous cost savings associated with additional interregional transmission capacity, a line could have paid for itself in four days during that cold snap.

More recently, some utilities could have saved upward of nearly $100 million per gigawatt of capacity in late 2022 if they were able to wheel more power in from the Midwest or New York. Instead, unplanned generation losses of all types exceeded 70 GW, and several balancing authorities ordered firm load shed of more than 5 GW over the Christmas holiday.

Moreover, increasing congestion on the regional power grids — when there is insufficient transmission capacity to deliver the most affordable power to customers, forcing more expensive generating units to run — cost the U.S. an estimated $20.8 billion in 2022, according to Grid Strategies. While this savings estimate can be debated, it is indisputable that customers pay more when they are unable to access cheaper supplies of electricity.

These facts are not lost on utility regulators. During the past year, members of the federal-state transmission task force reviewed the merits of a minimum transfer capacity standard and, more broadly, the need for more interregional transmission. In an op-ed published by RTO Insider in April, former Arkansas Public Service Commission Chair Ted Thomas touted the “significant reliability benefits” a standard would provide. (See Stakeholder Soapbox: Transmission Keeps the Lights On.)

At a task force meeting, former FERC Chair Richard Glick recognized that over the last decade, “there really hasn’t been any interregional transmission built … so we’re in a situation where I believe we need to consider, are there reforms that are necessary to move forward?”

Vermont Public Utility Commissioner Riley Allen found that there is a “growing body of evidence [that] interregional transmission can contribute to a significant degree on a triad of needs,” including affordability, reliability and clean energy. And Dan Scripps, chair of the Michigan Public Service Commission, similarly emphasized that “there’s no doubt that increased interregional transfers and interregional transmission can also offer additional benefits, particularly economic benefits, but ultimately the real value is ensuring that we have a grid that can support reliability and enhanced resilience, particularly in times when the grid operates in ways other than for which it is originally planned.”

I agree with my colleagues on these points, but I also know that the cost of developing new energy infrastructure projects must be weighed against a number of competing considerations. That said, I am confident that building more interregional transmission lines is a good, near-term investment that will deliver benefits now and for future generations. The facts are clear; it’s the political will that is needed.

Jason Stanek is the former Chairman of the Maryland Public Service Commission and previously served as a co-chair of the Joint Federal-State Task Force on Electric Transmission.

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Settlement Possible Between PJM And Several Generation Owners over Winter Storm Complaints

Several generation owners and PJM are progressing toward an agreement regarding the non-performance charges the RTO assessed in its allegation the generators failed to meet their capacity obligations during the December 2022 winter storm, according to the settlement judge mediating the deliberations (EL23-53, et al.).

Judge Matthew J. Vlissides Jr. wrote in a Sept. 1 status report that a “majority of the participants indicated that they reached a settlement in principle” as of the previous day’s conference and he recommended terminating the process without holding further meetings. (See FERC Sends Elliott Complaints Against PJM to Settlement Judge.)

“These participants represent that they are finalizing the settlement materials and anticipate filing the settlement package by late September 2023,” he said.

East Kentucky Power Cooperative spokesperson Nick Comer said EKPC is pleased the parties have reached a settlement in principle but wouldn’t comment further until the terms have been filed with the commission. PJM declined to comment.

The companies involved in the settlement procedures include Essential Power (EL23-53), Aurora Generation (EL23-54), the Coalition of PJM Capacity Resources (EL23-55), Talen Energy (EL23-56), Lee County Generating Station (EL23-57), SunEnergy1 (EL23-58), Lincoln Generating Facility (EL23-59), Parkway Generation Keys (EL23-60), Old Dominion Electric Cooperative (EL23-61), Energy Harbor (EL23-63), Calpine (EL23-66), Invenergy (EL23-67) and EKPC (EL23-74).

PJM stated the penalties from Winter Storm Elliott total about $1.8 billion, though during stakeholder meetings it has said it’s likely some percentage of generators will default on the penalties. To reduce the impact to those companies, PJM filed to extend the payment period for non-performance charges to nine months, which FERC approved in April. (See “FERC Approves Alternative Billing Schedule,” PJM: Elliott Nonperformance Penalties Total More Than $1.8B.)

The commission established the settlement judge procedure June 5 to see if the parties involved in a dozen complaints could reach an agreement within 60 days and extended the process an additional month on Aug. 14 after Vlissides wrote a progress report finding the parties were “significantly progressing” toward settlement.

PJM asked the commission to establish a settlement judge in April, arguing that while it maintains the penalties are valid, a faster resolution could support the long-term health of the capacity market and result in more consistent settlement outcomes.

“The capacity market also is designed in large measure to signal the need for new capacity resource investment, and the expectations of the financial and investment community accordingly are an important backdrop to the operation of this market,” PJM said in its earlier filings. “Timely, consensual resolution of these disputes thus could, potentially, help support the long-term health of the resource adequacy construct in the PJM region.”

The complaints argued PJM improperly declared emergencies in regions where it was not warranted and continued to export to other balancing authorities in contravention of its tariff and the RTO had not provided generators with the required notifications they were expected to be available to allow them to procure fuel.