The potential benefits of a single West-wide market footprint must be viewed with “significant skepticism,” the Bonneville Power Administration’s top official told Seattle City Light in a letter reemphasizing the agency’s view that SPP’s Markets+ is preferable to CAISO’s Extended Day-ahead Market (EDAM).
The letter from BPA Administrator John Hairston, posted by the agency Dec. 17, came in response to a Nov. 14 letter from City Light CEO Dawn Lindell that argued BPA is risking millions of dollars in economic benefits by favoring Markets+ over EDAM.
Specifically, Lindell pointed to a BPA-commissioned study by Energy and Environmental Economics (E3) showing the agency could gain between $69 million and $221 million per year in economic benefits if it joined CAISO’s EDAM over Markets+.
In his response, Hairston contended that City Light’s numbers are only accurate under a scenario in which there is only a single West-wide market rather than the more likely scenario that there will be multiple markets in the future.
“The Western Interconnection appears certain to have multiple day-ahead markets as entities have signed implementation agreements and issued declarations (or intent) for specific day-ahead markets,” the letter stated. “The expected materialization of benefits under a single West-wide market footprint should be viewed with significant skepticism.”
Hairston similarly shot down City Light’s contention that remaining in the Western Energy Imbalance Market (WEIM) and joining no day-ahead would produce greater benefits than joining Markets+.
Many WEIM participants have already signed agreements to participate in either Markets+ or EDAM, meaning the benefits of WEIM will likely erode, according to Hairston.
“As EIM entities move to the [EDAM] proposed by … [CAISO], there is no guarantee WEIM will continue to be offered as a standalone program, which is a risk to the potential benefits and long-term viability of a WEIM-only scenario for Bonneville,” the letter stated.
The BPA administrator also touted the Markets+ requirement that its members participate in the Western Resource Adequacy Program (WRAP) to ensure system reliability. By contrast, EDAM’s proposal lacks a “common resource adequacy metric,” according to Hairston.
“Without a market wide mandate for resource adequacy program participation, EDAM does not provide the same assurance for long term benefits of a resource adequacy program that is provided by Markets+,” the letter stated.
Pathways Skepticism
However, BPA has repeatedly highlighted the governance issue as the main reason it favors SPP’s markets+. While Hairston noted the West-Wide Governance Pathways Initiative has made important strides toward improving EDAM’s governance structure, he argued that more work must be done to ensure that the market is independent of CAISO — and California — influence.
Hairston singled out three areas of concern: the shared tariff under which EDAM and CAISO would operate, the CAISO board’s authority over market operations and other functions, and that CAISO would remain the counterparty in contracts with market participants, according to the letter.
Additionally, it’s uncertain whether California lawmakers will provide the legislative support required to establish a “regional organization” and grant it power to set market policy for EDAM, Hairston wrote.
“We appreciate Pathways Launch Committee’s optimism for a positive legislative outcome, but such efforts have repeatedly failed to secure the California Legislature’s approval,” Hairston wrote. “It also remains to be determined what legislative conditions and constraints may be introduced that would impede an independent governance structure.”
Pathways supporters have said they foresee few challenges in passing the needed legislation during the 2025 session, given that the bill will be sponsored by the staunchest opponents of previous efforts to “regionalize” CAISO.
In an email to RTO Insider, Seattle City Light — which operates its own balancing authority area and has signaled its intent to join EDAM despite BPA’s leaning — noted that in addition to the E3 study, a report by the Brattle Group showed the agency would realize $65 million in annual benefits in EDAM versus $83 million in losses in Markets+.
“A two-market solution in the Pacific Northwest is simply not efficient,” City Light wrote. “Both the recent BPA E3 and PNCG/NIPPC/RNW Brattle studies confirm this assertion.
City Light added that it agreed with concerns U.S. senators from Oregon and Washington expressed in a Dec. 13 letter to BPA asking the agency for more details justifying its leaning in favor of Markets+ and its decision to pay its $25 million share of the cost to fund the Phase 2 implementation stage of the market.
The utility said “BPA’s continued leaning towards an inferior economic option is worrisome especially in light of their proposed 10% increase in power rates and nearly 30% rate increase in point-to-point transmission rates. According to the Brattle study, the impact of this decision will leave upwards of $430 million a year in benefits behind.”
“We look forward to seeing a detailed and thorough response from BPA,” City Light said.
THE WOODLANDS, Texas — MISO will examine one of the long-range transmission projects from its first portfolio following a cost increase of more than two and a half.
MISO announced that it will conduct a variance analysis on the planned 345-kV Morrison Ditch-Reynolds-Burr Oak-Leesburg-Hiple line in Illinois and Indiana, which has climbed from an estimated $261 million to $675 million. The project was approved in 2022 under MISO’s first long-range transmission plan (LRTP) portfolio.
Northern Indiana Public Service Co. is handling the upgrade of existing 138-kV lines with about 37 miles of 345-kV lines.
During MISO Board Week on Dec. 10, Executive Director of Transmission Planning Laura Rauch confirmed the cost increase triggered the study process. She said MISO will share more details once it finishes the analysis.
MISO performs variance analyses on transmission projects when they encounter schedule overruns or significant design changes or experience a cost increase of at least 25% from original estimates. After completing the analysis, MISO can either let projects stand, cancel them or assign them to different developers, if possible.
Rauch said other projects from the first LRTP portfolio remain on budget, with overall portfolio costs holding steady around the originally estimated $10.3 billion.
MISO’s End-Use Customer sector has requested that the RTO and stakeholders discuss transmission cost-containment measures in planning meetings over 2025.
Data centers are already a major source of demand in Virginia, but their growth in the coming 15 years is the main reason Dominion Energy expects its load to grow by 64%.
The State Corporation Commission held a technical conference looking into the issue Dec. 16. Data center load growth accounts for 87% of the utility’s load growth and that does not even count the fact that 60% of data center load growth is in the territory of rural electric cooperatives, Trailhead Energy Consulting’s Marc Chupka, on behalf of Clean Virginia, told the commission.
“Other forecasts are actually closely clustered to the Dominion forecast — the JLARC report, PJM’s and others — but consensus does not imply accuracy,” Chupka said. “Often, forecasts of this nature are clustered, not because everyone is in agreement about how the future is going to unfold, but rather, they’re working from the same data, or very similar data, using very similar methodologies.”
Those assumptions could be off significantly, Chupka said, noting that Google just announced its quantum-based Willow chip. That advance and others could lead to much more efficient hardware in data centers, or artificial intelligence software could get more efficient, either of which would mean much lower demand from the sector going forward.
The industry is growing because consumers are more online than ever, with an average of 21 connected devices in every home, said Aaron Tinjum, the Data Center Coalition’s director of energy policy and regulatory affairs.
“Consumers and businesses will generate twice as much data in the next five years as they did in the past decade, so twice the amount of data in half the time,” Tinjum said. “This growth is driven by the widespread adoption of cloud services, the proliferation of connected devices and the rapid scaling of advanced technologies like generative AI, which alone could create between $2.6 trillion and $4.4 trillion in economic value globally by 2030.”
In the electric industry generally, 20-year forecasts can be directionally helpful, but beyond that, their value is questionable, Google’s Brian George said.
“I do think as we start to inch back towards that sort of 12-, 10-, eight-year mark, we need to start ratcheting up the confidence we have, and that is simply because of the long lead times it requires to build new infrastructure,” said George, the U.S. federal lead for Google’s Global Energy Market Development and Policy program. “But … we actually think there’s a lot of room right now for PJM to be more aggressive in addressing the load forecast adjustments that come up from its” transmission owners.
Dominion does a good job on the forecasts that it feeds to PJM that are then turned into regional forecasts, but that is not the case with all of the region’s TOs, he added. Google works to have the most efficient data centers in the world, and it has a financial incentive to continue that because energy is one of the biggest costs they incur, George said.
Data centers are focused on the state’s electric co-ops, especially around Data Center Alley in Northern Virginia, because they offer ample land that is also near transmission corridors, Rappahannock Electric Cooperative (REC) CEO John Hewa said.
“We’ve engaged with a wave of new data center members and emerging direct-serve projects with an inbound load ramp projection that climbs in excess of 16,700 MW by the year 2040,” Hewa said. “Commissioners, what I’m characterizing here is that a once-quiet and still-rural electric cooperative has an inbound load ramp that exceeds the summer peak of the New York City power control zone, actually substantially. In REC’s case, much of this load ramp is scheduled to mature quickly within the next five years.”
The co-op has set up an affiliate to serve the major group of new customers separately from the homes and smaller businesses that make up the rest of its customer base, with the affiliate serving them with market-based rates under FERC’s regulation, he added. That helps insulate other customers from any potential billing disputes, which can quickly add up to millions of dollars with hyperscale data centers, especially if the wholesale markets are impacted by an event like Winter Storm Elliott.
“I simply do not think it is right for the other members, such as residential, to have to backstop the scenario for a Virginia-based data center operating with global reach,” Hewa said. “These large-use members must provide the financial liquidity, not only for their own great infrastructure and operations, but also for backing their presence in the wholesale market and the wholesale market purchases that go with that.”
When done right, using market-based rates would protect other member consumers from subsidizing the energy demands of data centers, he added.
In Dominion’s territory, the recent growth in data center-led demand has actually contributed to lower transmission and distribution costs for residential customers, who paid 59% of the overall costs in 2020 and now pay 10% less, said Vice President of Regulatory Affairs Scott Gaskill.
“The growth in the GS3 and GS4 load classes, or rate classes, has increased over that time, which just naturally is going to reallocate costs to that load class, and you see a residential decline and that class go up,” he said, referring to Dominion’s rate schedules for business customers with a peak demand of at least 500 kW.
But past performance is no guarantee of future results, and the large infrastructure investments needed to meet growing demand from data centers, some of which is already inevitable, will lead to higher costs as seen in PJM’s capacity market already.
“I view that as probably the single largest driver to rate increases, say over the next three to five years,” Gaskill said. “Again, from the infrastructure build perspective, I think our current cost allocation methodology largely [takes] care of that, and the fact that the GS3 [and] GS4 classes are going to continue to be allocated more and more of those costs. But when we talk about the impact of energy prices — just the supply and demand in the whole PJM region — that’s going to be socialized across our system.”
The other members of the GS3 and GS4 rate classes are often the Virginia Manufacturing Association’s members, which include 4,511 factories that were historically the largest electricity customers, attorney Cliona Robb said on behalf of the group.
“It is the GS3 and GS4 rate classes that are being assigned a greater proportion of costs related to generation and transmission associated with meeting data center load,” she said.
VMA does not believe any drastic changes are needed to the way rates are handled now, Robb said. While its members are facing a greater share of costs from new load, that is just how the system works, and all customers benefit from building more generators and expanding the transmission system.
Demand from data centers is already driving most of the growth in demand, and eventually, it could get to the point where it threatens to make other large business less affordable in Virginia, which could have a bigger impact on the economy, Wilson Energy Economics Principal James Wilson said.
“We’ve heard that data centers represent economic development, but when you look on it on a per-megawatt basis, the amount of economic development from, say, an electrified manufacturing facility is much, much higher than a data center,” Wilson said.
Data centers can move to another part of the country easily, and that would have a much smaller economic impact than losing a manufacturing operation, he added.
“So, you might push the data centers around a little bit, but you probably wouldn’t want to do that to the manufacturing,” Wilson said.
So far, though, the way costs are allocated has worked, and the addition of new infrastructure has benefited the entire system, Google’s George said.
“We have never tied the provision of retail electric service to jobs-per-megawatt created,” George said. “And so again, it’s unclear what benefit that adds.”
The four U.S. senators representing Oregon and Washington said the Bonneville Power Administration has so far failed to make a financial case for joining SPP’s Markets+, a condition they contend should be the key driver of the agency’s decision to participate in a Western day-ahead market.
Democratic Sens. Jeff Merkley (Ore.), Ron Wyden (Ore.), Maria Cantwell (Wash.) and Patty Murray (Wash.) offered that assessment in a Dec. 13 letter addressed to BPA Administrator John Hairston. It was the second such letter from the delegation since July cautioning Hairston to “act carefully and deliberately” as the federal power marketing administration weighs its choice between Markets+ and CAISO’s Extended Day-Ahead Market (EDAM).
“Any market choice must be driven by a strong business case; thus far, BPA has not been able to make this case for Markets+,” the senators wrote. “This is particularly worrisome during a time of steep growth in rates, both for public and investor-owned utilities, across the Northwest.”
In their July 25 letter, the senators urged BPA to delay its final decision on a market beyond its November deadline. That was followed a month later by the agency’s announcement that it would postpone its draft decision until March 2025 and issue its final decision in late spring. (See BPA Postpones Day-ahead Market Decision Until 2025.)
It’s unclear what will be the impact of the most recent letter, which comes six weeks after BPA staff said they had “not shifted” their preference for Markets+ despite the release of a much-anticipated BPA-commissioned study by consulting firm Environmental and Energy Economics (E3). (See BPA Sticks to Markets+ Leaning Despite Study Showing EDAM Benefits.)
That study, which relied on production cost analyses, found BPA would realize the most significant net economic benefits — $251 million in 2026 declining to $147 million in 2035 — in a “Westwide Market” scenario that includes California.
E3 found BPA’s worst outcomes would occur in a scenario in which the EDAM includes California, NV Energy, PacifiCorp, Portland General Electric, Seattle City Light and Idaho Power, where the agency could be expected to see $30 million in benefits in 2026, but then incur $23 million and $28 million in net costs, respectively, by 2030 and 2035.
But BPA staff played down those findings — and those of an earlier Brattle Group study showing the agency would realize $65 million in annual benefits in EDAM versus $83 million in losses in Markets+ — contending that the production cost models did not capture the complete economic picture. Staff also continued to emphasize the importance of the independent governance and market design of Markets+. (See BPA Execs Lay out Markets+ Benefits, Risks, Reasons.)
BPA’s position rankled Northwest electricity sector stakeholders who have advocated for EDAM, some of whom evidently have the ears of the region’s politicians.
In their letter, the senators wrote that the recent studies “have provided important modeling to help shape BPA’s decision-making” and added that “there is no scenario that E3 evaluated that demonstrated net financial benefits by joining Markets+,” while also pointing to the Brattle findings.
And while the senators acknowledge the importance of independent governance and the potential benefits of a market design stemming from that arrangement, they also argue that “those advantages cannot come at a steep financial cost to ratepayers.”
“The purpose of organized markets is to improve transmission and generation efficiencies across the market, reducing costs and increasing reliability, while maintaining the integrity of greenhouse gas accounting for participating states,” the senators wrote.
They echoed another criticism recently made by the region’s EDAM supporters: that BPA appears willing to foot its $25 million share to fund the Phase 2 implementation activities for Markets+ while declining to contribute to the West-Wide Governance Pathways Initiative’s effort to bring independent governance to CAISO’s markets.
“While BPA has said that this funding decision is not a commitment to join Markets+, SPP has characterized it otherwise, stating that ‘[implementation] activities cannot begin until prospective market participants execute Phase 2 funding agreements, essentially committing to join Markets+,’” the senators wrote.
“This, coupled with BPA’s decision not to invest a significantly smaller contribution to developing the West-Wide Governance Pathways Initiative, has created the impression among many stakeholders that BPA has already chartered a course despite data from these studies showing that joining Markets+ will increase costs to ratepayers,” they said.
The letter concludes with the senators asking BPA to respond to seven questions by the end of the year, including:
How will the agency ensure that its obligations under its guiding statutes will not be compromised by joining a day-ahead market?
At what point might BPA determine that the financial cost outweighs any other net benefits from joining either market, and might the agency consider not joining a market as a “viable solution” in the short or long term?
Is BPA’s $25 million funding decision for Phase 2 of Markets+ “essentially a market decision,” as characterized by SPP, and why has the agency declined to invest $25,000 in the Pathways Initiative?
The senators also asked if BPA plans to perform any additional economic analysis and what process it has developed to engage with the region’s tribes.
‘Careful Scrutiny’
When reached for comment, BPA told RTO Insider it would not discuss the letter before providing its formal response, but the agency’s website already hosted a Dec. 16 response from the Portland, Ore.-based Public Power Council (PPC), which represents BPA’s “preference” customer base of publicly owned utilities, most of whom strongly support Markets+. (See Public Utilities Urge DOE to Respect BPA’s Day-ahead Decision Process.)
In its letter, the PPC argued that the cost increases found in the E3 and Brattle studies “merit careful scrutiny” and noted that the group had recently met with the senators and their staff to share that the study models “do not fully account for the qualitative and quantitative benefits that Markets+ provides, particularly for BPA, Northwest utilities and many utilities in the Southwest.”
“In fact, the analytical assumptions underpinning these modeled approaches omit many real-world differences between Markets+ and EDAM that have significant reliability and economic consequences to Northwest ratepayers that far exceed any estimates produced by E3 and the Brattle Group,” the PPC wrote. “Beyond the limited scope of the analysis, the underlying assumptions can drastically change the results.”
The PPC noted also that BPA “sensitivity” cases based on E3’s analysis (appearing on slide 45 in a Nov. 4 presentation) showed “more accurately reflect the actual cost of potential market seams” between Markets+ and the EDAM, “and those results increased BPA Markets+ benefits by over $150 million — to levels on par with those stemming from BPA’s participation in EDAM.”
PPC additionally contended the studies overstated the benefits of BPA’s participation in CAISO’s Western Energy Imbalance Market while downplaying the benefits from the price transparency, congestion management and ability to optimize the use of the agency’s transmission network, among other things, from Markets+.
In an email to RTO Insider, City Light — which operates its own balancing authority area and has signaled its intent to join EDAM despite BPA’s leaning — said it “values the delegation’s leadership in helping to focus the BPA market decision on reliability, affordability and reduction in carbon emissions.”
“We appreciate the emphasis on the purpose of organized markets — that being instituting efficiencies, both economic and physical, in the operation of the region’s transmission system and generation fleet,” City Light wrote. “We agree that BPA’s continued leaning towards an inferior economic option is worrisome especially in light of their proposed 10% increase in power rates and nearly 30% rate increase in point-to-point transmission rates.”
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.
