The board overseeing the Los Angeles Department of Water and Power gave the publicly owned utility the go-ahead to join CAISO’s Extended Day-Ahead Market (EDAM), a move expected to increase the LADWP’s annual net revenue by almost $40 million, according to a Dec. 17 announcement.
With the Los Angeles Board of Water and Power Commissioners’ backing, LADWP is slated to officially enter the EDAM in mid-2027. By joining the market, LADWP officials said it aims to enhance operational flexibility and reliability while assisting Los Angeles and California to achieve 100% clean energy by 2035.
Additionally, “[a]s an active EDAM participant, LADWP estimates a potential increase in net revenue from $20 million to $59 million annually based on the current analysis and depending on the final number of EDAM participants,” Ann Santilli, LADWP’s CFO, said in a statement. “The majority of the projected increased revenue is expected to result from savings in adjusted production and operation costs.”
LADWP noted in the announcement that it will “retain local control over its generation and transmission assets, as well as its ratemaking authority, similar to its involvement in the WEIM.”
The largest municipal utility in the U.S., LADWP has been participating in CAISO’s real-time Western Energy Imbalance Market (WEIM) since April 2021. EDAM will expand the capability of the WEIM by including trading of day-ahead energy, which requires increased coordination among participants. As it works to attract members, the ISO faces competition from SPP’s Markets+ day-ahead offering, which has generated especially strong interest in the Northwest and Southwest.
Four Arizona utilities announced their plans to join SPP’s Markets+ day-ahead market in November. In addition, the Bonneville Power Administration has expressed a “leaning” toward Markets+ over CAISO’s EDAM.
Although Powerex has yet to make a formal commitment to a day-ahead market, it has clearly signaled an intention to join Markets+ and not join EDAM.
However, EDAM has notched several wins in the competition for participants. PacifiCorp, Portland General Electric and Balancing Authority of Northern California have signed EDAM implementation agreements with CAISO.
Additionally, Idaho Power, NV Energy, BHE Montana, PNM and Seattle City Light have all signaled their intent to join EDAM.
“We are thrilled to see the Los Angeles Department of Water and Power, the largest municipal power utility in the United States, formally commit to the Extended Day-Ahead Market,” CAISO CEO Elliot Mainzer said in a statement. “This commitment underscores the importance of expanding market participation to enhance grid reliability and efficiency across the West. LADWP’s involvement will provide greater access and connectivity to diverse energy resources, building on the substantial economic, reliability, and environmental benefits we’ve already seen from the Western Energy Imbalance Market.”
Extensive Reach
While LADWP’s service territory is limited to the city of Los Angeles, its reach extends far into other parts of the West. The utility owns and operates more than 3,600 miles of transmission lines spanning five states, including half the capacity on the 3,100-MW Pacific DC Intertie linking the L.A. metro area with the Bonneville Power Administration’s balancing authority area in the Pacific Northwest.
LADWP’s other interstate transmission assets include 60% of the contract capacity rights on the Southern Transmission System line connecting Southern California with the Intermountain Power Project (IPP) in Utah, a 36% ownership stake in the Mead-Adelanto Transmission Project connected to Nevada and co-ownership of the Navajo-McCullough Transmission Line between the now-retired Navajo Generating Station in Arizona and the McCullough substation in Nevada.
The utility also controls about 8,000 MW of generating capacity, including the 1,900-MW coal-fired IPP, 15% of the output from the 2,080-MW Hoover Dam in Nevada and 5.7% of output from the 3,300-MW Palo Verde nuclear generating station in Arizona.
IPP is slated for conversion to an 840-MW natural gas-fired plant in 2025, including turbines capable of burning a fuel mixture containing 30% hydrogen. In 2023, LADWP was authorized to convert its Scattergood Generating Station, the largest gas-fired plant in Los Angeles, to hydrogen.
As renewable energy development challenges in New England have mounted over the past several years, Massachusetts agencies are facing a massive influx of alternative compliance payments (ACPs) from electricity suppliers.
ACPs, which are paid by utilities when they fail to meet the state’s clean energy requirements, are intended to help Massachusetts meet its statutory climate goals. However, the state’s spending of ACP money has lagged far behind the pace of collection; financial records indicate that the state’s ACP deposits surpassed $500 million in 2024.
While officials and clean energy developers hope the current shortage of renewable energy certificates (RECs) will ease in the coming years and reduce the reliance on ACPs, significant questions remain about the role the REC markets will play in the clean energy transition going forward.
With the first programs dating back to the early 2000s, Massachusetts’ electricity standards are complicated web of technical requirements that collectively direct electricity suppliers to purchase increasing amounts of clean energy.
These programs include the Massachusetts Department of Energy Resources’ Renewable Portfolio Standard (RPS), Clean Peak Standard (CPS) and Alternative Portfolio Standard (APS), and the Department of Environmental Protection’s Clean Energy Standard (CES).
ACPs, which are paid to the state instead of to clean energy developers, function as a cap on the cost of the certificates needed to meet various state requirements, protecting ratepayers from dramatic price spikes.
ACP revenues received by both the DOER and DEP have ballooned since 2020. The DOER’s ACP fund reached about $379 million in mid-2024, while the DEP’s Climate Protection and Mitigation Expendable Trust increased from about $2 million at the start of 2020 to about $186 million at the start of 2024.
Meanwhile, as payments accumulate, some project developers have argued that shortcomings of the REC markets — including low ACP rates — are hindering the development of new renewables.
“These programs have incentivized some projects to come online, but definitely not as fast or robustly as we would like,” said Kat Burnham of Advanced Energy United. She added that the uptick in ACPs over recent years likely indicates that “current programs were not doing enough to stimulate the development of renewable resources.”
“New projects aren’t coming online at the volume they need, and shortages are the result,” said Aidan Foley, founder of the renewable developer Glenvale Solar. “I think long-term, the question is whether this is a mechanism that’s supposed to work for new build assets, or is it just one to harvest RECs from the existing assets?”
Project Development Challenges
Massachusetts launched its RPS in 2003, and the standard has gradually increased over the past two decades.
The state has added several other standards and carveouts aimed at boosting specific resource types or attributes. Across New England, all six states have some form of RPS.
Prior to 2021, the ACP rate for Class I resources — the main category of renewables for the RPS program — was indexed for inflation. In 2021, the administration of Gov. Charlie Baker (R) began reducing the rate. Gov. Maura Healey (D) took office in early 2023.
While the consumer price index for the Northeast increased by about 15% between 2020 and 2023, the Class I ACP rate declined from over $70 to $40, where it remains today. The ACP rate for the CES, which can also be met with Class I RECs, sits at $35 today, compared to about $54 in 2020.
The CPS, which is intended to reduce peak-load emissions and is particularly important for energy storage resources, has kept a constant $45 ACP rate since its introduction in 2020.
As ACP rates have declined, mounting pressures from inflation, supply chain constraints, rising interest rates and regulatory battles have posed major challenges for clean energy development since 2020. These factors have made it harder for developers to finance new renewable projects and have helped contribute to a shortage of RECs on the market.
The New England Clean Energy Connect Project (NECEC), a major transmission line that will facilitate the import of up to 1,200 MW of power from Quebec, has faced major delays and is now expected to come online by early 2026. (See Avangrid Sues NextEra over ‘Scorched-earth Scheme’ to Stop NECEC.)
Vineyard Wind 1, which began producing power in early 2024 and was expected to be completed later in the year, has been prohibited from producing power since a blade collapsed in the summer and still has a significant amount of work remaining on construction. Developers recently resumed work installing turbine blades.
Earlier-stage offshore wind projects are also struggling; in 2023, the developers of two major wind projects totaling about 2,400 MW of capacity backed out of their contracts, citing cost increases. While Massachusetts and Rhode Island selected 2,878 MW of offshore wind power in a recent procurement, the contracts have not been finalized and will likely feature significantly higher prices than previous procurements. (See Multistate Offshore Wind Solicitation Lands 2,878 MW for Mass., RI.)
Michael Judge, undersecretary of energy at the Massachusetts Executive Office of Energy and Environmental Affairs, said the delays to NECEC have had a particularly large effect on the CES.
“The second that comes online, 20% of our electricity is going to come from [NECEC], and it’s going to generate Clean Energy Standard-eligible certificates,” Judge told RTO Insider. “That will likely significantly reduce — if not eliminate — the collection of ACP in that program.”
The Role of Portfolio Standards
“These portfolio standard programs on their own are not a very good tool for financing projects; the way that projects get financed is through long-term contracts,” Judge said, adding that developers “assign a very low value to the RECs beyond the first few years of a project, because the prices can swing pretty significantly.”
In addition to power purchase agreements, the state’s Solar Massachusetts Renewable Target program is specifically aimed at supporting the development of solar within the state, Judge noted.
“The RECs alone are not the driving force for most project development,” said Jessica Robertson, director of policy and business development in New England for New Leaf Energy. Robertson said REC markets are “certainly a piece of the puzzle, but generally … developers are still seeking a PPA or some other long-term contract.”
Glenvale’s Foley said most developers prefer procurements as financing mechanisms but said he thinks the REC markets could provide significant value for new projects if the markets are set up to serve this purpose.
In comments submitted to the DEP in early 2024, Glenvale asked the DEP to “consider improvements to the CES program that can stimulate new project supply to Massachusetts energy consumers.” The company recommended that the department raise the ACP to account for inflation and incentivize long-term contracts for RECs to help stimulate project development.
Larry Chretien, executive director of the Green Energy Consumers Alliance, has also argued in favor of increasing the Class I ACP rate. He said the markets have shown that the current rate is “absolutely” too low and is “not helping new projects get built.”
United’s Burnham expressed hope that recent state policy changes outside the REC markets will help spur renewable development and reduce shortages. She highlighted the state’s recent clean energy permitting and siting reforms and procurement authorizations as one reason for optimism. (See Mass. Clean Energy Permitting, Gas Reform Bill Back on Track.)
“I suspect that we’ll see more development rather than payments to the ACP,” Burnham said. “There is a shared prioritization in investing in the clean energy industry here in Massachusetts.”
Accumulation of Funds
While the state has been ramping up clean energy programs funded by ACPs, challenges with agency bandwidth have made it difficult to spend the money as quickly as it has flowed in.
ACPs for the DOER programs are deposited into a custodial fund held by the Massachusetts Clean Energy Center, with expenditures from the fund controlled by the department. The fund has grown from about $54 million in 2020 to $379 million at the end of June 2024.
While the DOER took in nearly $264 million in ACPs over a two-year period ending in June 2024, it only distributed about $52 million from the program over this same period.
For the DEP, data from the Massachusetts Office of the Comptroller indicates the department’s Climate Protection and Mitigation Expendable Trust has about $196 million available for spending in 2025.
In 2023 and 2024, the DEP trust has registered about $203 million in revenue, compared to about $34 million in expenses and $76 million transferred out of the fund over this period.
The Massachusetts Attorney General’s Office, the state’s official ratepayer advocate, declined to comment.
“When we look at the last couple of years, a lot happened in the world, so there were a lot of different priorities, particularly in 2020 and 2021,” DOER Commissioner Elizabeth Mahony said. “But since we came into office [in 2023], we’ve been trying to utilize these funds in a way that supports the industry, so that we can create projects that therefore create credits, so we don’t have to collect ACP.”
Mahony said the DOER is working to deploy the funds through a range of initiatives, including a storage grant program, building decarbonization efforts for low- to moderate-income households, decarbonization and clean energy deployment at state facilities, heat pump training at community colleges, the state’s Climate Leader Communities program and improving low-income solar access.
From the Climate Mitigation Trust, the department has spent $50 million to seed the state’s Community Climate Bank, $20 million on decarbonization and clean energy projects through the Massachusetts Water Resources Authority, $20 million for the DOER’s Affordable Housing Decarbonization Grant Program, $10 million for the purchase of electric school buses and $7 million on flood resilience.
“You do have to ramp up resources to actually run these programs, but we have been planning for it,” Undersecretary Judge said.
Mahony and Judge both highlighted a series of emergency rulemakings for the CPS in 2024, which the state took “to reduce the reliance on ACP going forward,” Judge said.
In July, facing significant undersupply in the market, the DOER decreased the minimum standard for the CPS to protect ratepayers from excessive costs. In October, the DOER increased the ACP rates for future years. The rate was previously set to decline starting in 2025 but will now increase from $45 to $65 in 2026.
The DEP solicited stakeholder feedback on potential reforms to the CES in late 2023, including a possible ACP rate increase and incentives for new projects and long-term planning, but has not acted on these changes.
“The DEP is still working on that. … It’s more of an internal resource thing,” Judge said, adding that he expects the department to take additional steps at some point in 2025.
“Our goal ultimately is for clean energy projects to be developed, so that they are providing any number of benefits to the grid, including the availability of credits,” Mahony said.
Green Energy Consumers’ Chretien praised the Healey administration’s leadership on clean energy but said there should be more transparency and public engagement around how the ACP funds are used.
“The legislation that created these standards lets the bureaucracy determine what to do with the money,” Chretien said. “It’s not very transparent.” As the state works to meet the challenge of scaling up clean energy while protecting ratepayers from substantial cost increases, “I think they owe the public a little bit of input” on how to spend the accumulated ACP funds.
Energy Secretary Jennifer Granholm says her department’s newly updated analysis of U.S. LNG exports finds that business as usual is unsustainable.
The U.S. already is the world’s largest producer and exporter of natural gas. Increasing export volumes would create economic risks for Americans and cause environmental damage, she wrote Dec. 17.
Reaction was swift and fell along predictable lines, with environmentalists calling for greater protections, the energy industry saying it is counting the days until President Donald Trump is back in office and various organizations worried about costs for their constituents.
The Department of Energy’s release of the “2024 LNG Export Study: Energy, Economic and Environmental Assessment of U.S. LNG Exports” report summary and its four appendices kicked off a 60-day public comment period.
In her statement that accompanied the announcement, Granholm said DOE paused decisions on new LNG exports earlier in 2024 to allow for the study to be completed.
She acknowledged, however, that the 60-day comment period would push into the second term of Trump, whose energy and environmental policies and priorities differ vastly from those of President Joe Biden.
Granholm nonetheless urged the next administration to take into consideration the findings of the study. “Regardless of what happens in each cycle of elections, the effect of increased energy prices for domestic consumers combined with the negative impacts to local communities and the climate will continue to grow as exports increase,” she wrote.
She highlighted key takeaways:
U.S. natural gas exports have expanded at an astounding rate and are on track to continue to double again by 2030 even without additional authorizations. Further growth risks outstripping global demand.
While increased LNG exports benefit those in the natural gas supply chain, a wide range of U.S. consumers will face higher prices because of these exports — for the gas itself, for electricity generated with that gas, and for consumer goods produced with that gas and/or electricity.
Increased exports would mean increased health impacts on the communities near gas production facilities, which tend to also be near other polluting industries.
Existing U.S. LNG exports are sufficient to meet global demand. Increasing the export volume might slow development of emissions-free renewable power sources and is likely to increase net global carbon dioxide emissions, even under aggressive carbon-capture scenarios.
The destination of LNG exports must be considered. Demand already has flattened among allies such as Europe and Japan, leaving China as the dominant importer of LNG.
Granholm said special environmental scrutiny must be paid to very large LNG projects: “An LNG project exporting 4 billion cubic feet per day — considering its direct life cycle emissions — would yield more annual greenhouse gas emissions by itself than 141 of the world’s countries each did in 2023.”
Reactions
American Energy Alliance President Thomas Pyle said the study epitomizes four years of misguided energy policy.
“On election day, the American people rejected these kinds of artificial limits on America’s energy export potential,” he said. “I look forward to this study being thrown in the trash bin on Jan. 20, 2025, because that’s where it belongs.”
The Industrial Energy Consumers of America agreed with the economic conclusions. “It is not surprising that the study finds that between 2020 and 2050, overall energy costs for the industrial sector will go up $125 billion and lead to inflationary impacts,” it said. “IECA urges the DOE and Congress to put in place a policy to insulate the U.S. from the negative impacts of increased LNG exports. Our recommended policy is an LNG inventory policy that is an America First policy.”
“It’s time to lift the pause on new LNG export permits and restore American energy leadership around the world,” American Petroleum Institute President Mike Sommers said in a statement. “After nearly a year of a politically motivated pause that has only weakened global energy security, it’s never been clearer that U.S. LNG is critical for meeting growing demand for affordable, reliable energy while supporting our allies overseas.”
The Environmental Defense Fund said the study showed the urgent need to cut methane pollution. “Under no circumstances is it ever acceptable to generate profits for oil and gas companies at the expense of energy access, affordability or the environment here at home,” Senior Vice President Mark Brownstein said. “With U.S. gas exports already at historic high levels and with even more projects approved and on the way, today’s study sounds the alarm.”
The Consumer Energy Alliance was disappointed with the study. “It’s unfortunate to see what began as an election-year ploy turned into a predictable and pre-determined outcome that will slow environmental progress,” President David Holt said. “By arguing to limit exports of LNG produced under America’s strict environmental standards, we limit the opportunity for other nations to enjoy the same success we have had in cutting emissions by using gas instead of higher-emitting fuels.”
Market Analysis
Also on Dec. 17, S&P Global announced a comprehensive study of its own on U.S. LNG exports that reached some different conclusions from the DOE study.
“On their current trajectory, growing exports of U.S. liquefied natural gas would support nearly half a million domestic jobs annually and contribute $1.3 trillion to U.S. gross domestic product through 2040 while having a negligible impact on domestic gas prices,” it said.
“The emergence of the U.S. LNG industry has placed the United States in the pole position with global demand for gas expected to grow through 2040 alongside the rapid growth of renewables,” S&P Global Vice Chairman Daniel Yergin said. “Continued growth in U.S. LNG capacity would have outsized impact in terms of jobs, GDP and labor income.
“In addition to domestic economic benefits, being the world’s leading LNG supplier adds a new dimension to U.S. influence abroad. It was U.S. LNG that replaced nearly half of Russia gas supply to Europe after the outbreak of war in Ukraine.”
In its 2024 Long-Term Reliability Assessment (LTRA) published Dec. 17, NERC warned that large parts of the North American grid face “mounting resource adequacy challenges over the next 10 years” because of “surging demand growth” coupled with continued retirement of thermal generators.
“We are experiencing a period of profound change, one that represents both some promise but also some challenges,” John Moura, NERC’s director of reliability assessments and planning analysis, said in a media call accompanying the release of the assessment. “We’re seeing demand growth like we haven’t seen in decades. …
“From the electric industry perspective, that growth is exciting; it’s a signal of innovation and economic momentum. But as we all know, growth must be met with reliability readiness.”
The ERO recommended that resource planners, market operators and regulators “carefully manage” future generator deactivations and ensure that essential reliability services are maintained as the grid transitions to new energy resources.
In the assessment, NERC found that most of the grid faces either high or elevated risk of energy shortfalls from 2025 to 2029. High risk indicates that shortfalls are likely to occur under normal peak summer or winter conditions, while elevated risk means shortfalls can occur during extreme weather such as wide-area heat waves or deep freeze events.
MISO is the only area recorded as high risk, with shortfalls possible as early as 2025. The assessment noted that retirements of coal-fired generation have combined with “slower-than-anticipated resource additions since the 2023 LTRA” to cause “a sharp [projected] decline in anticipated resources beginning next summer.” Also contributing to the potential shortfall is a rise in forecasted peak demand in 2026 and afterward.
SPP faces potential shortfalls in 2025 as well, although this region is rated as an elevated risk rather than high; NERC said demand may outstrip supply during times of low wind and natural gas supplies. ERCOT, PJM, SaskPower and New England all face shortfalls beginning in 2026; Ontario and British Columbia in 2027; and California, Manitoba Hydro and SERC-East (comprising North and South Carolina) in 2028.
SERC Central and Southeast, WECC-Alberta, WECC-Northwest, WECC-Southwest and the Northeast Power Coordinating Council’s Quebec, Maritimes and New York subregions were all assessed as normal risk, meaning they “are expected to have sufficient resources under a broad range of assessed conditions.”
A large part of the generation shortfall in high- or elevated-risk areas is the result of retiring resources, NERC said. While the assessment found that the grid possessed over 8 GW more generation in 2024 than in 2023 — rising to 1,048 GW overall — most of this growth came from solar and battery hybrid facilities, which added more than 17 GW of capacity in all. Conversely, the share of generation coming from coal plants declined by over 8 GW, with petroleum generation falling by more than 1 GW as well.
NERC Manager of Reliability Assessments Mark Olson observed that not only has traditional generation continued to fall as a share of the overall mix, but new resources have also come onto the grid slower than predicted in last year’s LTRA. The amount of solar generation that came online in 2024 was 14 GW lower than expected, he said, raising concerns that generation may fail to keep pace with surging demand from rapid growth in data centers and industrial applications.
One “bright spot” in this year’s LTRA, as Olson put it, was the development of transmission, with 28,275 miles of projects over 100 kV in construction or in stages of development for the next 10 years. This represents significantly more than projected in the 2023 LTRA (18,675 miles) and above the average of 18,900 miles per 10-year period published in the last five LTRAs.
This year’s LTRA found 28,275 miles of transmission projects of at least 100 kV, greater than last year’s LTRA. However, the increase is mostly in projects in the planning or conceptual phases, rather than in construction. | NERC
Olson cautioned that so far, the new projects represented by this year’s LTRA are for the most part not actually under construction but in the planning or conceptual phases. He said that “siting and permitting issues” are a major cause of delay for over 1,200 miles of transmission projects.
Jim Matheson, CEO of the National Rural Electric Cooperative Association, said in a statement that the LTRA represented “a grim picture of our nation’s energy future.” Matheson repeated his request in a letter to President-elect Donald Trump earlier in December to help ensure that energy projects are built “efficiently … and at reasonable cost.”
“This report points directly to the need for a pro-energy policy agenda that prioritizes reliability and affordability for American families and businesses,” Matheson said. “We urge President Trump and congressional leaders to prioritize reliability right out of the gate next year before it’s too late.”
Todd Snitchler of the Electric Power Supply Association highlighted the LTRA’s demand growth projections, warning the grid urgently needs investment in new resources and a resource planning approach that can support the volume of work that will be needed.
“While past policy and regulatory approaches have put pressure on markets and power developers, resulting in supply imbalances, higher prices and reliability concerns, now is the time for all stakeholders, decision-makers and market participants to come to the table and find collaborative approaches to meet the urgent need at hand,” Snitchler said. “EPSA continues to highlight the importance of policies and market decisions that support Americans’ access to the dispatchable resources needed for reliability.”
The U.S. Department of Energy’s Loan Programs Office offered a conditional $15 billion loan to Pacific Gas & Electric (PG&E) to support the California-based utility’s energy infrastructure and clean energy initiatives, the agency announced Dec. 17.
The conditional loan, which is not yet finalized, would provide federal funds for PG&E’s operation of its hydroelectric fleet, expansion of battery storage, enhancements to the utility’s transmission systems and the enablement of virtual power plants in PG&E’s service area, the agency said in an announcement.
“Investments in a clean and resilient grid for northern and central California will have significant returns for our customers in safety, reliability and economic growth,” PG&E’s CEO Patti Poppe said in a statement. “The DOE loan program can help us accelerate the pace and impact of this work, which supports thousands of living wage jobs, at a lower cost to our customers.”
The utility said funding the projects “could save customers up to $1 billion net present value over the life of the financing, while paying for critical investments in safety and reliability to serve customers.”
The loan is the second LPO investment made under the office’s Energy Infrastructure Reinvestment program, funded by the Inflation Reduction Act. On Dec. 12, the LPO announced a conditional $2.5 billion loan under the program to Wisconsin Electric Power Co., a subsidiary of the Milwaukee-based WEC Energy Group.
More announcements could be on the way. The LPO has a pipeline of $139.2 billion in applications under the Energy Infrastructure Reinvestment program across 47 applications located in every region of the country.
Commenting on the announcement in a newsletter, investment bank Jefferies said the loan “is a positive development” but added that “the receipt of funds could hinge on the Trump Administration.”
“It remains to be seen what portion of the $15 billion, eligible to be drawn through 2031, the utility is ultimately able to access,” the investment bank said.
However, speaking at the U.S. Energy Association’s Advanced Energy Technology Showcase on Dec. 12, LPO Director Jigar Shah said conditional and final loans should be safe from any claw-back attempts by the incoming Trump administration. Existing LPO loan contracts were honored during President-elect Donald Trump’s previous four years in the White House, and conditional commitments are signed contracts.
The conditional loan to PG&E is subject to certain conditions that both the utility and the DOE must meet before the department can authorize the loan to be funded.
PG&E submitted its loan application to LPO in June 2023. The money would support PG&E’s 61 hydropower powerhouses that produce more than 3.8 GW. Additionally, the utility, which has 4.2 GW of battery storage under contract, would use part of the loan to fund further expansions of battery storage, PG&E said in a news release.
The utility’s transmission infrastructure would see enhancements to help reduce congestion and improve reliability. The loan would also allow PG&E to “integrate more renewable energy and demand management by deploying and interconnecting [virtual power plants],” according to the news release.
The $15 billion comes after the utility received blame for a series of California wildfires starting in 2015. The fires included the 2018 Camp Fire, which leveled the town of Paradise, killed 84 people and drove PG&E to file for bankruptcy reorganization in January 2019.
Stakeholders on Dec. 12 said they are inching closer to developing the scenarios that will inform the Western Transmission Expansion Coalition’s (WestTEC) transmission planning study.
John Muhs, a senior consultant with Energy Strategies and member of the WestTEC Scenario Planning Subcommittee, said during a webinar that the group has decided on a set of drivers that will underpin the development of the scenarios in the study. The drivers include changes in the regulatory landscape, technology costs and supply chains.
“The general idea is that we view these drivers as a lens through which to develop, you know, key points of a future scenario narrative,” Muhs said.
The WestTEC study, jointly facilitated by Western Power Pool and WECC, will address long-term interregional transmission needs across the Western Interconnection. The WestTEC Steering Committee unanimously approved the project’s study plan in September. (See WestTEC Committee OKs Plan for ‘Actionable’ Tx Study.)
The study is expected to take place over the next two years. The goal is to produce transmission portfolios for 10- and 20-year planning horizons. In addition to enhancing Western reliability, the portfolios will also factor in economic efficiencies and state policy goals.
The study will include a reference case that considers current trends, policies and projections in transmission planning. In addition, the scenario planning subcommittee will develop two separate cases to reflect alternative potential future developments, according to the study plan.
Being able to compare and understand transmission needs across the three scenarios “will be a key outcome of the WestTEC study,” Muhs said.
Members of the subcommittee will develop scenarios over the holidays. The committee will refine those ideas through March 2025, when approval of the planning scenarios and completion of the 20-year resource plan is expected. The 10-year horizon transmission assessment and report should be done in August 2025, according to the presentation.
SPP’s Board of Directors said Dec. 17 it has selected COO Lanny Nickell as its next CEO, effective April 1.
Nickell will replace CEO Barbara Sugg following a three-month transition period. Sugg announced her retirement in August after 27 years with SPP. (See SPP’s Sugg Announces Retirement from RTO.)
Armed with 28 years of experience with SPP, Nickell said he was “deeply honored” to be selected to “serve the organization I’ve been proud to call home.”
“I’m grateful to have had the opportunity to learn from and work alongside Barbara for as long as I have, and I’m grateful for her visionary leadership,” Nickell said in a press release. “SPP’s mission of ensuring reliable electric service for millions of consumers remains my driving passion. I look forward to building on our strong foundation and continuing to work diligently with our stakeholders to meet our future challenges.”
“Lanny brings unparalleled experience, deep organizational knowledge and a passion for the organization’s stakeholder culture,” board Chair John Cupparo said. “His leadership will ensure we continue to deliver on SPP’s mission and successfully navigate the generational challenges confronting our industry, region and organization.”
Nickell joined SPP from Central and South West Corp., now American Electric Power, in 1997. He was quickly promoted to the management team and was named vice president of operations in 2008 and vice president of engineering in 2011. Nickell was promoted to COO in 2020.
His promotion to CEO continues SPP’s tradition dating back to the 1970s, when its headcount stood at 14, of hiring its leaders from within. Sugg was named CEO in 2020, replacing Nick Brown, who replaced John Marschewski in 2003. SPP became an RTO in 2004.
Sugg told RTO Insider she plans to spend more time with her two grandchildren and take care of her elderly mother.
“It’s been an honor to lead this organization through a transformative period of growth and maturation. I’m deeply grateful for the opportunity, and I’m thrilled to pass the reins to Lanny, a trusted colleague and partner whose leadership will undoubtedly take the company to new heights,” she said a statement.
Nickell holds a bachelor’s degree in electrical engineering from the University of Tulsa and is a graduate of Harvard Business School’s Advanced Management Program.
FERC has ordered American Efficient to defend its energy efficiency programs in PJM and MISO or pay a $722 million penalty and return $253 million in profits to ratepayers.
The commission’s Dec. 16 show-cause order directed the company demonstrate how it did not violate the Federal Power Act, FERC’s anti-manipulation rule and the MISO and PJM tariffs “through a manipulative scheme and course of business in PJM and MISO that extracted millions of dollars in capacity payments for a purported energy efficiency project that did not actually cause reductions in energy use” (IN24-2). (See “American Efficient Pushes Back on Allegations of Tariff Violations,” PJM Asks FERC to Eliminate Energy Efficiency from Capacity Market.)
The commission said the company has 30 days to either elect for a hearing before an administrative law judge or request a prompt penalty assessment.
“We are greatly encouraged by FERC’s enforcement action today against American Efficient, which is fully consistent with the findings of our investigation of its conduct in the MISO markets,” MISO Monitor David Patton said. “We continue to encourage MISO to respond to our recommendation to remove energy efficiency from its capacity market or to substantially improve its tariff to eliminate this type of gaming of MISO’s capacity market in the future.”
In a report attached to the order, FERC Office of Enforcement (OE) staff report allege that, instead of using capacity market revenues to deliver reduced demand, the company and its subsidiaries ran a market research program that determined how much consumption would be avoided if certain products were sold and then bid those savings into capacity markets “as if it caused the savings.”
OE said American Efficient did not deliver reductions in consumption, acquire ownership or rights to capacity savings associated with product installations, or “have a nexus with end-use customer projects.”
“American Efficient has exploited those markets, enriching itself, its individual investors, its various holding companies, and its investment bank counterparties by receiving capacity payments for a purported energy efficiency project that does not actually do anything to reduce demand,” OE said in the report. “Over the past 10 years, the company has cleared half a billion dollars in capacity without offering any real energy efficiency, providing any demand reductions or making the grid any more reliable. Its program receives more capacity payments than any single generator in PJM, and it offers nothing in return.”
The report says that, by purchasing “environmental attributes” and sales data associated with products sold at retailers such as Home Depot, Lowe’s and Costco, American Efficient claimed to have rights to enter those savings into capacity markets. Enforcement staff, however, argued the company did not inform consumers that it was claiming rights to any capacity associated with their purchase of efficient devices nor did it enter into any agreements with consumers or hold rights over any projects.
The report explained that EE programs typically include a host of measures to reduce demand, including marking down efficient products at the retail level, incentivizing residential consumers to install efficient appliances or incentivizing commercial and industrial customers to retrofit their businesses. Utility programs are subject to review by state commissions through measurement and verification processes.
Third-party programs have included efforts by a university to improve the efficiency of cold water distribution infrastructure and a school district improving lighting and building envelopes across its system.
OE staff analysis found traditional utility EE programs paid $20 to $100 per appliance for direct discounts, while American Efficient paid 15 cents on average. That analysis found the company paid around $0.001/kWh for energy savings it calculated — around 1% of what utility programs paid.
‘At Best Unethical’
The OE report notes the company had been barred from the ISO-NE and MISO capacity markets and that independent market monitors for MISO and PJM both referred the company to the Enforcement office in April 2021. It also states that American Efficient’s policy director left the company and voluntarily provided testimony for Enforcement staff, which wrote that she had “concluded that it had become nothing more than a ‘wealth transfer’ from ratepayers and was being run in a manner that was ‘at best unethical.’”
American Efficient did not inform PJM after being disqualified from MISO and ISO-NE, the report says, and instead expanded its program in the RTO’s Base Residual Auctions, increasing to account for nearly three-quarters of EE in PJM. The RTO’s stakeholders in August voted to outright eliminate EE from the capacity market , which FERC approved in November (ER24-2995). (See PJM Stakeholders Endorse Elimination of EE Participation in Capacity Market.)
“American Efficient defrauded the markets and ISO/RTOs by presenting its market data program as a capacity resource,” OE wrote in its report. “To carry out that scheme and ensure that it maximized its capacity payments, American Efficient concealed the true nature of the program by making false statements to market regulators. For example, it claimed that it provided ‘incentives’ and reductions in energy usage. Without any evidence or factual basis, the company also claimed that its program influenced or even dictated customer behavior.
“The company also repeatedly represented to PJM and MISO that its program met the respective tariffs’ EER definitions when the program did not. Finally, American Efficient also withheld material information from PJM and MISO to avoid scrutiny of its capacity market activities,” the report said.
Responding to the notification that OE intended to recommend an administrative proceeding, American Efficient defended its program by saying neither the RTO monitors nor the investigation had demonstrated fraud. The company argued that PJM had acknowledged in its stakeholder process and FERC filing to eliminate EE from the capacity market that its tariff does not require a causal link between capacity revenues and reduced capacity demand through EE programs. The company said it effectively followed the tariff language and was being expected to comply with anticipated rule changes.
“While the market monitors in PJM and MISO have strong policy preferences that EERs [EE resources] be removed from the markets, they are not arguing (nor could they, based on the record) that American Efficient misrepresented its program when seeking approval,” the company wrote. “Instead, the allegations go directly to the fundamental features of American Efficient’s EER program. There is no support for the allegation in the preliminary findings that American Efficient had a scheme with an intent to defraud the markets when the features were transparently presented to the RTOs, scrutinized by RTO staff and subsequently approved.
“Put simply, an enforcement action based upon fundamental features of American Efficient’s EER program that MISO and PJM knew and approved of would be inequitable.”
The company instead recommended that FERC open a technical conference to consider industry-wide changes to how EE participates in capacity markets and how its contributions are measured and verified.
After the monitors’ referrals, American Efficient met with commission staff and argued that it had not violated any FERC or RTO rules and enforcement action was unnecessary. Preliminary findings were presented to the company in July 2023 and a response was submitted the following September.
Enforcement staff sought to interview company personnel, according to the OE report, but American Efficient sent a letter in October 2023 stating that it would not make witnesses available. OE then requested that the preliminary investigation be made formal, which was granted in October 2023. Several former employees and third-party investors spoke with investigators in the proceeding.
The U.S. Department of Energy has slashed the list of 10 potential National Interest Electric Transmission Corridors it released in May to just three much narrower corridors in the third phase of its designation process, the department announced Dec. 16.
Established under the Federal Power Act, NIETCs are geographically defined areas in which the secretary of energy finds “present or expected transmission capacity constraints or congestion that adversely affects consumers,” according to the announcement published in the Federal Register. Transmission projects located within a NIETC are eligible for special DOE financing and FERC permitting processes aimed at accelerating development and construction.
DOE set out a four-step process for NIETC designations in December 2023, including an initial information-gathering phase to help identify potential NIETCs, followed by the release of the preliminary list of 10 possible corridors in May. (See On the Road to NIETCs, DOE Releases Preliminary List of 10 Tx Corridors.)
The three proposed NIETCs selected in Phase 3 are:
the Lake Erie-Canada Corridor, including parts of Lake Erie and Pennsylvania;
the Southwestern Grid Connector Corridor, including parts of Colorado, New Mexico and a small portion of western Oklahoma; and
the Tribal Energy Access Corridor, including central parts of North Dakota, South Dakota, Nebraska and five tribal reservations.
According to DOE, its decisions on these three corridors were based on its own analysis and the public comments it received during the first two phases of the process, as well as priorities set in the department’s National Transmission Needs Study released in October 2023.
“Transmission development in these areas is critical to address transmission needs … unmet through existing planning processes,” DOE said. All three corridors also have one or more transmission projects under development, which DOE sees having near-term impacts on easing grid congestion, helping to put more renewable energy online and cutting consumer costs.
For example, the Lake Erie-Canada Corridor is a slimmed-down version of the Mid-Atlantic-Canada corridor on the Phase 2 list of 10 potential NIETCs. The Phase 3 version contains a smaller area in Pennsylvania and a larger area in Lake Erie. NextEra Energy Transmission’s Lake Erie Connector project, a 73-mile underwater line, could be located in the corridor, allowing for bidirectional energy flows between Pennsylvania and Ontario.
While the project is still in the early phases of development, a transmission corridor with that kind of HVDC line would increase capacity for clean energy integration on the grid, as well as support resource adequacy in PJM via the connection with Canada, according to DOE.
The Tribal Energy Access Corridor is a similarly “refined” version of DOE’s Phase 2 Northern Plains potential NIETC, with most of the corridor running along existing rights of ways and connecting several tribal reservations to existing or planned HVDCs.
The corridor includes parts of the Dakotas, Nebraska, the Cheyenne River Reservation, Pine Ridge Reservation, Rosebud Indian Reservation, Standing Rock Reservation and Yankton Reservation.
NIETC designation here could help the Transmission and Renewables Interstate Bulk Electric Supply (TRIBES) HVDC project being developed by the Western Area Power Administration and other tribal and regional stakeholders, as well as relieving congestion and preparing for future demand growth. Nebraska, for example, is becoming a hub for data center development as part of a new “Silicon Prairie.”
While highlighting these projects, DOE noted that “NIETC designation is not a route determination for any particular transmission project, nor is it an endorsement of one or more transmission solutions.”
Why These, not Those?
Declining to comment on specific corridors, Dylan Reed, senior adviser for external affairs in DOE’s Grid Deployment Office, listed a number of reasons for the exclusion of the other Phase 2 potential NIETCs.
“NIETC designation can disrupt effective transmission planning or ongoing transmission project development in the region. That was one consideration,” Reed told RTO Insider.
“[No. 2] … there appeared to be limited [ability for] a NIETC designation to further transmission in the near term in that area. In some cases, we lacked sufficient information to be able to narrow the boundaries to facilitate timely designation,” he said.
Beyond prioritizing NIETCs that might meet shorter-term needs, DOE pointed to its own limitations of staffing and time for taking Phase 3 NIETCs to a final designation in Phase 4. The department is opening a 60-day comment period, which will include three webinars, one on each of the proposed NIETCs. The comment period will close Feb. 14, 2025.
Another key component of Phase 3 is determining whether the potential corridors will need a full environmental review under the National Environmental Policy Act. A NEPA review for each corridor could be required if DOE determines that “NIETC designation is a major federal action significantly affecting the quality of the human environment,” according to the announcement.
The department is also asking for additional input on other meetings or community engagement activities it should plan as part of its environmental reviews.
A full NEPA review could take two years, so Reed would not speculate on when final NIETC designations might be made. He also declined to speculate on what impacts, if any, the incoming administration of President-elect Donald Trump might have on the NIETC process.
But DOE said its decision not to move the other Phase 2 projects forward does not mean those areas do not have transmission needs. “Rather, DOE is exercising its discretion to focus on other potential NIETCs at this time and may in the future revisit these or other areas through the opening of a new designation process,” it said.
NIETC vs. NIMBY
Even before it was cut from the list, the Delta-Plains corridor drew strong political and public opposition within Oklahoma over the possibility of eminent domain acquisition of private lands.
As originally proposed, the corridor would have stretched 645 miles from Little Rock, Ark., through the Oklahoma Panhandle, with an 18-mile right of way in some portions.
“I won’t let anyone steamroll Oklahomans or their private property rights,” Gov. Kevin Stitt (R) posted on X. “The feds don’t get to just come here and claim eminent domain for a green energy project that nobody wants.”
Attorney General Gentner Drummond (R) sent a letter to U.S. Energy Secretary Jennifer Granholm calling the corridor “classic federal overreach” and pledged to protect private property rights.
DOE gave Oklahoma’s leadership advance notice on Dec. 13 that the Delta-Plains corridor would not be moving forward.
With or without a NIETC, the region does not lack for proposed transmission projects that could run into similar NIMBYism. The Southwestern Grid Connector corridor will graze the western edge of Oklahoma’s state line. DOE notes two projects in development in the potential NIETC: the Heartland Spirit Connector project by NextEra Energy Transmission, and the Southline Phase 3 project by Grid United.
Invenergy also has proposed the Cimarron Link to unlock access to the Oklahoma Panhandle’s “inexhaustible wind energy.”
BOSTON — Energy experts from across the Northeast gathered for Raab Associates’ New England Electricity Restructuring Roundtable on Dec. 13 for a preview of some of the key issues that will dominate policy discussions in the coming year.
While 2024 brought notable success on state-level climate policy in Massachusetts, the new year brings significant uncertainty regarding whether the change in federal administration will slow the momentum of the clean energy transition in the region. (See Mass. Clean Energy Permitting, Gas Reform Bill Back on Track.)
Prior to the passage of a major omnibus climate bill in November, “the first thing on the list of challenges was siting and permitting,” said Rebecca Tepper, secretary of the Massachusetts Executive Office of Energy and Environmental Affairs.
The new climate law creates a streamlined siting and permitting process for clean energy infrastructure, capping the state’s review of permitting applications to 15 months for large projects. Tepper said collaboration between a wide range of stakeholders through the state’s Commission on Energy Infrastructure Siting and Permitting was essential to passing the bill with widespread support.
Looking forward, Tepper said the state’s “big challenge for [2025] is interconnection; you’re going to see us really focusing on that next year.”
Tepper also highlighted the possibility of another offshore wind procurement in 2025 and said the state is exploring the potential of new interregional transmission links with New York, PJM or Québec. “We see a lot of opportunity for further hydro coming from Canada,” she said.
Serge Abergel, COO of Hydro-Québec Energy Services, said increased transmission capacity between New England and Québec could help speed up decarbonization and reduce the need to overbuild renewables as the Northeastern U.S. achieves a highly decarbonized system. (See Québec, New England See Shifting Role for Canadian Hydropower.)
He said Hydro-Québec’s modeling indicates that an additional export-neutral transmission line between the regions could provide major benefits by 2040. A new line “could reduce the length of a major outage by about two days, and it could save [New England] $2 [billion] to $3 billion over those two days,” Abergel said.
Recent drought conditions have caused the company to reduce exports over the spot market to New England, causing some observers to question the reliability of Québec supply in the future and whether the benefits of new transmission capacity would justify the costs.
While ISO-NE’s exports to Québec have increased during the drought, imports continue to play a key reliability role on the grid: They earned $29 million in Pay-for-Performance credits during two capacity scarcity events this summer, far more than any other resource class. (See NEPOOL Markets Committee Briefs: Dec. 10, 2024.)
Abergel said there is uncertainty over the degree that climate change has influenced the current drought and said the conditions are “on par with the worst cycle we’ve seen in the past.”
“Our firm commitments are always met, but our spot market sales fluctuate,” he said, adding that the New England Clean Energy Connect transmission project — which includes a 20-year contract for Québec to send baseload power to New England — should be in service in December 2025.
Hydro-Québec’s energy supply should also receive a major boost from a new agreement between Québec and Newfoundland and Labrador, which was announced the day before the roundtable. The agreement would increase the price Québec pays for power from the Churchill Falls hydroelectric generating station in Labrador while paving the way for a significant increase in generation capacity.
FERC Preview
Former FERC Chair Richard Glick, now a principal at GQS New Energy Strategies, previewed what the new year could bring for the commission.
As states work to decarbonize their power supply, Glick said the incoming Trump administration “will have an impact, but maybe not as much of an impact as some fear,” adding that he is “still very bullish on what’s going on in the clean energy side.”
He also praised FERC’s work on Order 1920-A, calling it “a very helpful order” that should increase the likelihood of successful transmission projects.
Under a Republican-led commission, grid operators may be afforded greater flexibility on both orders, Glick said. He added that, under the Trump administration, FERC could look more favorably at pipeline expansion projects and proposals to allow fossil generators to skip ahead in the interconnection queue for reliability purposes.
Electric Vehicle Outlook
The roundtable also featured a panel focused on transportation decarbonization, with speakers discussing the growth of the U.S. electric vehicle industry and the potential of managed charging.
Roger Kranenburg, vice president of energy strategy and policy for Eversource Energy, said he remains optimistic about the overall upward trend of EV sales despite recent growth challenges and a less favorable stance from the incoming administration. He emphasized the major role that fleet-level electrification will play in transportation decarbonization.
“Fleets are coming, and they’re going to transition faster” than individual consumers, Kranenburg said. “It’s all an economic decision.”
Chris Rauscher, head of grid services and virtual power plants at Sunrun, highlighted the potential of EVs to help eliminate peak demand costs and emissions.
There currently is “way more capacity in electric vehicles than there is in stationary storage in the U.S.,” Rauscher said, adding that, when modeling 200,000 bidirectional EVs on the New England power system, just 30% of the vehicles’ battery capacity would eliminate the need for oil peakers on a winter day.
