CARMEL, Ind. — MISO said it will finalize an availability-based accreditation for nearly 12 GW of load-modifying resources (LMRs) over the first quarter of 2025 ahead of a filing with FERC.
Some stakeholders remain skeptical of MISO’s plans to rely on past performance levels to accredit LMRs by the 2028/29 planning year.
During a special Dec. 17 Resource Adequacy Subcommittee teleconference, MISO reiterated that it plans to split LMRs into two categories — those that can respond in 30 minutes or less and those that can’t — and accredit them correspondingly.
The RTO said its faster category would have a maximum response time of 30 minutes and presumed availability for all maximum generation emergency step two events.
On the other hand, the class of LMRs with slower response times would carry a maximum response time of six hours and would be readied earlier under tight conditions, when MISO declares a maximum generation warning. The RTO has long said it needs to be able to access LMRs before emergencies materialize.
MISO said the accreditation will extend to demand response resources participating in the capacity auction. Like the slower LMRs, demand response capacity resources would have a six-hour response requirement and must respond to at least one deployment per season if MISO issues instructions, with reduced accreditation for non-response.
Joshua Schabla, a MISO market design economist, said the RTO doesn’t expect to make major changes to the proposal in the coming months.
“The design is in a good spot. That’s not to mean it’s locked in, or we don’t expect a back and forth,” Schabla said. He added that MISO’s existing LMR accreditation is more than 15 years old and doesn’t reflect performance.
MISO said it will use backward-looking meter data from hours when capacity advisory declarations are in place to gauge availability and accredit resources.
The RTO plans to draw on data from a minimum of 65 historical hours per season over the past year, giving equal weighting to performance during low-margin hours and in hours where capacity advisories escalated into maximum generation events, alerts or warnings. That’s a change from fall, when MISO said it would apply a 20% weighting to low-margin hours and an 80% weighting to capacity advisories and above.
“It’s a very broad framework to capture a very broad set of resources,” Schabla said.
Multiple stakeholders said the accreditation plan still seems too complex and destined to produce unintended consequences.
“We’re seeing accreditation not aligned with what these resources are capable of,” Schabla said. “The stack of resources we can rely on is shrinking.”
Schabla said emergency resources can currently clear the capacity auction “without making themselves available.” MISO said real-time availability data indicates anywhere from 6 to 7 GW of capability from an estimated 9.5 GW participation level, which is “far less” than the auction’s cleared quantity of 12 GW of LMRs.
Schabla said the new accreditation will link availability with accreditation and will motivate demand response operators to give MISO accurate availability data.
MISO said it would also halt its practice of accepting LMRs’ self-conducted testing to verify performance.
Schabla said it’s clear that LMRs’ self-testing is not providing a “good indication” of what the resources can do. He said rolling out MISO-initiated testing will keep cheaper resources that cannot perform from crowding out genuine demand response in the capacity auction.
MISO said its members must add an “unprecedented” 17 GW in new resources annually over the next two decades to reliably meet demand and decarbonization goals.
That’s according to the RTO’s finalized Regional Resource Assessment for 2024, which draws on its members’ resource plans to quantify resource expansion needs on a 20-year outlook.
MISO’s Armando Figueroa Acevedo said a 17 GW/year rate would require members to add more than three times their recent average additions of 4.7 GW/year. If members can achieve the more than 340 GW in additions, MISO would boast 515 GW in total installed capacity by 2042.
“Achieving this pace will require several factors, including overcoming supply chain, permitting, labor and interconnection queue delays,” Figueroa Acevedo told stakeholders at a Dec. 18 teleconference to discuss results.
Members so far have planned to add 163 GW in installed capacity by 2043, less than half of what MISO says is necessary. The RTO filled in a simulated 180 GW of wind, solar and battery storage in its assessment to meet states’ and members’ pollution-cutting goals.
Despite record influxes of renewable energy, Figueroa Acevedo said MISO’s thermal resources are still poised to contribute “the bulk” of accredited capacity by 2043. At that time, MISO expects its lower-accredited wind and solar to account for 62% of installed capacity and have the potential to reach 87% of annual energy.
Between 2029 and 2043, MISO expects 27 GW in thermal retirements and 11 GW in thermal additions, leading to a net loss of 16 GW.
Figueroa Acevedo said MISO’s emerging reliance on solar power is pushing ramping needs from the morning to the evening and will double or triple its average one-hour ramping requirements by the early 2030s.
“A lot of the accredited capacity we see on the system is retained thermal generation and battery storage” entering the system, MISO Director of Strategic Initiatives and Assessments Jordan Bakke said.
WPPI Energy’s Steve Leovy said MISO should consider adding some long-duration energy storage in its modeling. Other stakeholders said the RTO seemed to underestimate how much storage can help improve reliability.
Bakke said the long-term assessment is meant to reflect members’ planning and said next year’s results could change depending on how many new resources members can scale over the next few years. He said the assessment is meant to “highlight the challenges of what we’re collectively trying to do across the footprint.”
MISO’s resource projections in the assessment began with 2029, skipping the next few years, where the RTO has said it could come up short on capacity.
America’s Power CEO Michelle Bloodworth said MISO should be focusing in particular on the next five years, given the heightened danger to reliability. Staff said the Regional Resource Assessment is intended to examine long-term needs while the annual resource adequacy survey conducted by MISO and the Organization of MISO States concentrates on near-term capacity sufficiency.
MISO fared the worst among all regions in NERC’s 2024 Long-Term Reliability Assessment, being the only region categorized as high risk, with NERC calling attention to possible shortfalls starting in 2025. MISO leadership has also raised the possibility of shortages within a few months and said it’s crucial for the grid operator to devise a fast lane in its interconnection queue for necessary generation projects. (See MISO Tells Board RA Fast Lane in Interconnection Queue is a Must.)
Backed by a new process conducted by the New England states, ISO-NE is moving forward with a request for proposals to build new transmission that would bring wind to market from Northern Maine.
The New England States Committee on Electricity presented its request at the ISO-NE Planning Advisory Committee’s meeting Dec. 18. The RTO plans to develop the RFP and release it by March.
“This is the first time that we’re using this process, and so we wanted to focus on investments that we have a high confidence in, that they’ll provide a lot of value for consumers; this concept of least-regrets transmission,” Jason Marshall, Massachusetts deputy secretary and special counsel for federal and regional energy affairs, said in an interview.
North-to-south transmission capacity in the region has been lacking, with Marshall saying it has limited the ability of generation to move to load centers to the south.
“As a result, resources have been really curtailed up there, and it’s limited our access to low-cost clean energy generation,” he added.
The RFP would also facilitate the interconnection of new wind resources, which have been held back by the lack of transmission to the resource-rich region, Marshall said.
“Strengthening the connections between northern and southern New England will enhance reliability and market efficiency by resolving known constraints on the transmission system and will also position the region to more efficiently integrate affordable resources in coming years,” NESCOE wrote in a memo to the RTO. “There is broad interest in addressing these longstanding system challenges, and strengthening the transmission system in Maine is a reasonable, measured first step toward the region’s needed transmission investment.”
The RFP targets increasing transfer capacity starting at a substation in Pittsfield, Maine — west of Bangor — and down through the southern part of the state into New Hampshire. Several parties asked in comments for the states to issue multiple RFPs based around the multiple needs for new transmission. (See ISO-NE Stakeholders Respond to Potential Long-term Transmission RFP.)
The states have been discussing the option for the multiple RFPs, and they also brought up that issue with the RTO, NESCOE’s Sheila Keane said at the PAC meeting.
“We understand that multiple RFPs could risk an unintended consequence of inefficient investment and extend the timeline for needed investment,” she added. “So, we certainly take that into mind in our final decision, and at this time, we accept that recommendation that a single, comprehensive RFP scope is the most efficient way forward.”
The tariff requires a complete solution for the needs identified, but Keane said the states are interested in maximizing competition in the process, and that could change in future RFPs.
The RFP is just one of several processes that could increase transmission from Northern Maine, where the grid is operated not by ISO-NE but by the Northern Maine Independent System Administrator and is connected to the Eastern Interconnection through New Brunswick.
The Maine Public Utilities Commission has opened a proceeding looking into better connections for the region, and Massachusetts has the authority to do out-of-state procurements for clean energy, Marshall said.
“I think we would view these activities as complementary,” he added. “They are different processes though, but again, at least for our state, we’re in an early phase.”
Vistra is extending the life of its coal-fired Baldwin Power Plant in Illinois through 2027 amid MISO delivering warnings over a supply crunch in its footprint.
The Irving, Texas-based company said Dec. 17 that it will keep the Baldwin plant running for an additional two years while still meeting EPA retirement and pond closure obligations. Vistra originally announced in 2020 that the 1,185-MW coal plant would close at the end of 2025.
The utility said the extension will buy the region some time to bring new generation online while helping to avoid a capacity shortfall.
“Vistra is committed to the responsible transition of our fleet in Illinois, and in this case, the most reasonable path forward is to continue to operate the plant as a reliable bridge to 2027, as we, and others, bring new generation assets online in the state,” CEO Jim Burke said in a press release. “As many organizations have recently raised concerns over reliability and resource adequacy in central and southern Illinois, we are taking action and delivering solutions that balance the needs of reliability, affordability and sustainability.”
The company has built a 68-MW solar farm and 2-MW/8-MWh energy storage facility at Baldwin; they began operations this month. It said its current coal-solar-storage setup at Baldwin “demonstrates the company’s commitment to evaluating how to best leverage the footprint, infrastructure and transmission connections already at the plant sites to meet the evolving electricity needs of customers.”
Vistra has planned on-site solar and storage at its other downstate coal plants as part of Illinois’ Coal to Solar and Energy Storage Initiative. It has completed a 44-MW solar and 2-MW/8-MWh storage facility at the Coffeen Power Plant and will begin construction of a 52-MW solar and 2-MW/8-MWh storage facility at the Newton Power Plant in 2025.
Vistra also noted it has begun construction on a 405-MW solar farm that will interconnect at its retired Joppa Power Plant.
MISO has said it could contend with a capacity shortfall as soon as the upcoming summer. (See OMS-MISO RA Survey: Potential 14-GW Capacity Deficit by Summer 2029.) While the RTO and the Organization of MISO States’ five-year resource adequacy survey this year did not show the potential for such an immediate shortfall in southern Illinois’ Zone 4, nearby Zone 5 in Missouri was flagged for substantial risk.
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.
