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November 5, 2024

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BPA Staff Recommends Markets+ over EDAM

The Bonneville Power Administration on April 4 released a much anticipated staff report that tentatively recommends the agency choose SPP’s Markets+ over CAISO’s Extended Day-Ahead Market (EDAM). 

“We stuck to our evaluation principles and are confident in the analysis and public process that led to the recommendation,” Russ Mantifel, BPA director of market initiatives, said in a statement. “Both markets we are considering honor those principles; however, ongoing concerns with governance and some superior features related to greenhouse gas accounting and resource adequacy, among others, led to staff’s preference for Markets+.” 

The staff recommendation, the product of a public process the federal power agency kicked off last July, should come as little surprise to electricity sector stakeholders who have closely followed the growing competition between Markets+ and EDAM to bring a more organized electricity market to the West. BPA was an important contributor to the development of EDAM, but it has been a central participant in the intensive — and expedited — stakeholder process to design Markets+, including the market’s governance structure. 

But the staff report, and an accompanying letter by BPA Administrator John Hairston, also made clear the recommendation is not etched in stone. 

“This is not a final decision, nor is it an endorsement of one market option over another. Rather, it is intended to provide greater insight into the analysis of Bonneville staff and their recommendations based on information gathered to date,” Hairston said in the letter. 

Along with the market recommendation, BPA also released a “preliminary legal assessment” describing the agency’s authority under federal law to join a day-ahead market. The assessment considered multiple factors, including the business case for participation, the agency’s obligations to preference customers, and its environmental responsibilities with respect to operation of its dams. 

The legal assessment notes that the Energy Policy Act of 2005 grants federal utilities the right to join transmission organizations, including RTOs. The assessment points out that Markets+ and EDAM would be “less restrictive” than an RTO because BPA “would retain substantial control over its transmission assets, and its balancing authority area responsibilities would be preserved.” 

“While the development of a day-ahead market is not an RTO, it is reasonable to conclude that Congress contemplated federal utilities would be authorized to participate in subcomponents of an RTO like a day-ahead market as part and parcel of that express authority,” the assessment found. 

‘Important Differences’

In developing the market recommendation, BPA staff considered eight evaluation principles, including: statutory, regulatory and contractual obligations; service reliability for BPA customers; resource adequacy frameworks to maintain system reliability; business rationale; consistency with BPA’s 2024-2028 strategic plan; governance; commercial and operational impact of day-ahead market participation on customers; and handling of greenhouse gas emissions. 

Governance has been a top concern for BPA as it contemplates joining a day-ahead market that could eventually evolve into an RTO. For the agency, CAISO’s governance, which is subject to oversight by California state officials, has been a significant hurdle for joining EDAM and a point that heavily favors Markets+. 

“Paramount to Bonneville’s participation in any day-ahead market is the requirement for independent market governance that is not obligated to any single state, entity or trade association,” the staff recommendation said. “Bonneville staff believes that independent governance will ensure that decisions affecting the market are made with consideration of the interests of all market participants.” 

Staff said it saw “important differences” between Markets+ and EDAM in this area, pointing to differing approaches to stakeholder processes as well as governance. 

“Bonneville staff believes that Markets+ has developed a structure and process that is more likely to result in equitable market outcomes and fair consideration of Bonneville’s interest,” the report said. “The structure of the Markets+ Participants Executive Committee (MPEC), work groups and task forces that developed the market design and initial tariff provided all participants an equal opportunity to weigh in on decisions.” 

The BPA report said the Markets+ governance and processes “supported collaboration and negotiation” to help achieve consensus on issues, allowing the agency “to propose and obtain consideration of its statutory and contractual obligations” during development of the tariff. 

BPA staff complimented the Markets+ work group processes for being “publicly accessible” and for considering views of utilities, states and independent organizations. 

They also noted that SPP’s staff have offered technical support and other facilitations “while respecting the decision-making roles of market participants.” 

“As Markets+ transitions from phase 1 to phase 2 and ultimately to an operational market, Bonneville staff expects the MPEC, work groups and task forces to maintain the same level of decision-making and collaboration that crafted the tariff,” the BPA report said. 

BPA staff contrasted SPP’s approach with what they called CAISO’s “staff-driven model.” 

“Bonneville staff acknowledge the CAISO’s efforts to develop a more participatory stakeholder engagement process. Bonneville appreciates and respects the professionalism and expertise that CAISO staff routinely display in their stakeholder process, but Bonneville staff believes the process is still lacking in stakeholder leadership and engagement in policy and implementation development, evaluation and decision processes,” the report said. 

On governance, BPA staff said CAISO’s model “has presented challenges in resolving contentious regional issues” and that the agency has observed “that EDAM governance presents real problems for Bonneville’s participation in a day-ahead market and could result in unbalanced outcomes, as it continues to operate under provision of California law. 

The report notes that CAISO’s Board of Governors is appointed by California’s governor “with obligations to California ratepayers embedded in California laws and policies.” The ISO’s “dual responsibilities” of serving California load and operating day-ahead and real-time markets “has resulted in Bonneville, and consequently its customers in the Pacific Northwest Region, being at a competitive and governance disadvantage,” the report contends. 

BPA staff acknowledged the efforts of the West-Wide Governance Pathways Initiative to create a more independent governance structure for a single Western market that would expressly include California and rest on the platform of EDAM and CAISO’s Western Energy Imbalance Market. 

“Bonneville’s view is that achieving the objective of Pathways likely requires modification of California legislation, which has not gained traction in the past,” the report said. “Bonneville is tracking the effort’s legal analysis for indicators regarding the viability and potential timeline for governance updates. Throughout its decision-making process, Bonneville will continue to consider the progress of Pathways.” 

“I don’t anticipate, at this point in time, that we’ll get more involved [in Pathways] than we are right now,” BPA’s Mantifel said during an April 4 press briefing. “We will be evaluating anything that comes out of the Pathways Initiative as part of our ultimate decision, so when we do make the decision later this year, we will take into account any governance changes that have either been realized or proposed as a result of the Pathways Initiative.” 

SPP Wins on RA, GHGs

Markets+ also won favor with BPA staff on the issue of resource adequacy based on the market’s requirement that eligible participants also join the Western Power Pool’s Western Resource Adequacy Program (WRAP), which is operated by SPP. 

“WRAP has become the dominant resource adequacy program outside of California,” the BPA report said. “The EDAM proposal does not propose a uniform adequacy metric or require EDAM entities to participate in a resource adequacy program. Bonneville staff supports and prefers the clear and consistent requirement that all Markets+ [load-responsible entities] must participate in WRAP, which better supports regional reliability.” 

While California utilities are subject to a state-mandated RA requirement, other EDAM participants outside California can participate in the WRAP but are not required to join an RA program, BPA staff noted. 

“The EDAM proposal’s lack of a common resource adequacy metric makes it difficult to assess whether the footprint as a whole will be resource adequate in the planning horizon. Further, failure to adequately plan in advance to meet demand by the day-ahead time frame could undermine the ability of the market to find adequate supply to serve load in the short day-ahead time frame,” the report said. 

BPA staff also favor the way Markets+ will handle the tracking and accounting of greenhouse gas emissions, an issue of specific concern for agency customers in Washington state, which last year adopted a cap-and-trade system to price carbon. While both Markets+ and EDAM are designed to attribute specific resources to states with GHG pricing, BPA staff said SPP’s design offers more assurance that energy from the federal hydro system will be attributed to BPA’s Washington customers who have contracted for that power. 

“In contrast, CAISO’s design would attribute the federal system to Washington only when it is the most economical solution for the entire market footprint,” BPA staff said. “This outcome of CAISO’s design would adversely impact Bonneville because, at times when the system is not attributed to Washington, Bonneville may not be able to recover the difference between the price it receives for system resources and the cost it pays for load in the GHG area.” 

BPA staff also preferred the Markets+ approach to transmission congestion rent, saying it “better models physical congestion in Bonneville’s transmission system, allocates congestion rents according to constraint-level congestion and allocates congestion rents directly to long-term transmission right holders, which provides consistency for transmission customers across the entire footprint.” 

BPA plans to issue a draft decision on its market choice in August, followed by a final decision late in the year, likely in November. In the meantime, it will hold additional workshops on the issue this summer. 

Reactions

Stakeholder reactions to the BPA recommendation were mixed, if predictable. 

“SPP is very pleased to hear of BPA’s staff recommendation to join Markets+,” RTO spokesperson Meghan Sever said in an email to RTO Insider. “BPA has been an active participant in Markets+ development, and we look forward to continued collaboration as we work to build a Western energy market that provides environmental and financial benefits and enhances electric reliability in the Western Interconnection.” 

“We respect BPA’s public process and appreciate our continuing collaborative relationship on the broad set of Western electricity issues, as well as BPA’s partnership and successful participation in the Western Energy Imbalance Market,” CAISO said. 

Opponents of BPA’s “leaning” in favor of Markets+ offered stronger words. 

The Northwest Energy Coalition (NWEC), which has strongly advocated for a single Western market, once again advised BPA to ease up on its timeline for selecting a market. 

“NW Energy Coalition and our allies urge BPA to keep an open mind and continue to do comprehensive analysis before making a decision,” NWEC said in a statement, noting that EDAM, which has already been approved by FERC, builds on the WEIM, a market in which BPA already participates. 

“The WEIM already covers more than 80% of the Western region and has provided more than $5 billion in customer benefits. It is no exaggeration to say the WEIM has provided a crucial contribution to keeping the lights on during extreme weather events, including the mid-January freeze in the Northwest,” NWEC said. 

“This decision makes clear that the Bonneville Power Administration cares more about political control than its customers, residents of the Northwest, or endangered salmon and steelhead,” Mitch Cutter, salmon and energy strategist at the Idaho Conservation League, said in a statement. “A single regional market could help save ratepayers money, decarbonize the grid and reduce the Northwest’s dependence on salmon-killing hydropower. Instead of heeding its mission and statutory obligations, BPA seems hellbent on joining Markets+ and fragmenting the West when unity is most needed.” 

Advanced Energy United Executive Director Leah Rubin Shen said it was “exciting” that BPA staff determined it would be legal and beneficial for the agency to join a day-ahead market, but she said joined “energy industry and policy leaders throughout the region — including the governors of Washington and Oregon — in finding the recommendation about which market to join premature.” 

“This is a very dynamic landscape that is rapidly changing. BPA’s own modeling shows their customers and partners will benefit most from being in the same market as California, and there is a robust effort underway — the West-Wide Governance Pathways Initiative — to resolve BPA’s primary objection regarding independent governance,” she said. 

‘Absolutely Critical’

BPA’s final decision will carry significant weight in the Northwest, where it operates 15,000 circuit miles of transmission — or 70% of the regional system — and is the largest power provider, controlling 17,500 MW of generating capacity. 

But a final decision in favor of Markets+ could leave the agency at risk of hemming itself into a relatively small market with limited links to other potential participants, depending on the choices of neighboring balancing authorities. 

On that front, EDAM has already won commitments from significant players in the Northwest, including PacifiCorp, whose six-state territory extends into the Intermountain region, and Portland General Electric, Oregon’s largest utility by customer base. Publicly owned Seattle City Light, which has been deeply involved in the Pathways Initiative and is listed among its top funders, is expected to follow suit. (See CAISO’s EDAM Scores Key Wins in Contested Northwest.) 

Sources have told RTO Insider that decisions by Idaho Power and NV Energy will be vital for determining how markets take shape in West but especially important for the functioning of Markets+, which has its strongest support in the Pacific Northwest and Arizona — areas separated by more than a thousand miles and a lack of transmission links. 

Signs point to both joining EDAM, although that’s still uncertain. 

Idaho Power offered the clearest signal last month in a letter to CAISO saying it is leaning toward joining EDAM after determining that the market offers the greatest value for its customers. The Boise-based utility has also recently partnered with the ISO to fund a Nevada transmission line designed to increase transfers of renewable energy between Idaho and points to the south, opening up the potential for more energy sales into the Southwest. 

And while NV Energy has been more guarded about its direction, a recent Brattle Group study found the utility would realize significantly greater financial benefit from participating in EDAM than Markets+. The Nevada utility’s choice will be pivotal for either market, given the central location of its transmission network and its role in facilitating transfers among WEIM participants. (See NV Energy to Reap More from EDAM than Markets+, Report Shows.) 

“Where it looks like we’re going to go right now — if Markets+ succeeds in moving forward with a lot of support across the West — is a Northwest zone and a Southwest zone with no direct connection from transmission,” Fred Heutte, senior policy associate at NWEC, said in an interview in February. “It’ll have to transfer power across the grid of other entities that are not in Markets+.” 

Asked during BPA’s press briefing about the weight of such geographical factors in its final decision, Mantifel called them a “major factor,” but he also noted that while the agency’s financial benefits would be “sensitive” to the market footprint, it has not identified any “bright line at this point in time that would automatically shift our decision.” 

Asked whether the governance issue would outweigh financial benefits, Mantifel said: “I would say governance occupies a pretty equal spot in our evaluation. Yeah, governance is an absolutely critical issue for Bonneville in making this decision.” 

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Robb, Cancel Review Reliability Landscape

In their annual media call April 4, NERC CEO Jim Robb and Electricity Information Sharing and Analysis Center (E-ISAC) CEO Manny Cancel said that while the reliability landscape continues to grow more complex, the ERO Enterprise is focused on grappling with any problems that might emerge. 

The call covered a wide range of topics, including the in-progress Interregional Transfer Capability Study (ITCS) and last year’s GridEx VII security exercise, the report for which NERC also released this week. (See NERC Flags Communication, Coordination in GridEx VII Report.) 

In his opening remarks, Robb said the ERO is “about halfway through” its three-year plan for 2023-2025 and that he feels “very good about where we are” and what it has accomplished so far. Nevertheless, he also acknowledged that NERC’s agenda has become full over the last year, with orders from FERC on inverter-based resources and cold weather standards and Congress’ mandate for the ITCS, which must be submitted to FERC by December. 

Because of the new assignments, particularly the ITCS, NERC has had to reconsider its work plan priorities, and some of the activities that were planned for 2023 and 2024 could not be completed in the original time frame, Robb said. In addition, some of the new hires who were intended to work on the ERO’s work plan priorities were shifted to the ITCS. 

“We did go back through our priorities and talked with the board and pushed a few of them off to this year and beyond,” Robb said. “One of the major ones we wanted to do was a comprehensive assessment of market rules and how they do — or in some cases, don’t necessarily — support reliability going forward. We decided that was something that was important to be done, but not as urgent as some other things.” 

Robb emphasized that NERC has focused on making sure its added responsibilities, like the ITCS, don’t result in unexpected financial burdens for the registered entities that ultimately fund the ERO through its assessments. The added expenses for 2023 and 2024 were largely met by using the organization’s financial reserves, and the CEO added that “a few things have broken our way” concerning the ERO’s investments that have allowed it to “absorb the work.” 

Robb also said that as the ERO works on next year’s budget, it has made a commitment not to “surprise [stakeholders] with anything next year” in terms of major financial deviations from the three-year plan. 

E-ISAC Monitoring Active Threats

Cancel noted that the E-ISAC — which celebrates its 25th anniversary this year — has seen “significant ramifications” from global geopolitical issues such as Russia’s invasion of Ukraine and Israel’s military actions in Gaza, along with the ongoing tensions between Taiwan and China. These have manifested in a “dramatic increase in malicious cyber activity.” 

The E-ISAC continues to view China as a “top cyber threat,” Cancel said, citing the Volt Typhoon hacking group that CISA said this year had been actively infiltrating U.S. infrastructure operators for at least five years. (See CISA Highlights China Threat in 2024 Priorities Report.) However, Russia, Iran and North Korea also “continue to demonstrate advanced capabilities” to undermine U.S. infrastructure through vulnerabilities on electronic networks. Cancel said these threats demonstrate the need for vigilance and effective internal network monitoring. 

Physical security threats remain a top concern for the E-ISAC as well, with Cancel noting the organization reviewed more than 2,800 physical security events in 2023. He added that this number did not represent a “substantial increase beyond the elevated threat that started [in] 2022.” Cancel also observed that about 3% of the physical security incidents in 2023 affected the grid, but none led to cascading outages. The most serious incidents involved ballistic damage, theft, intrusion, tampering and vandalism. 

Cyber and physical attacks were both part of the plan for GridEx VII, which Cancel noted involved 15,000 individual participants from 252 registered organizations in the two-day distributed play portion and 230 individuals in the executive tabletop. Cancel attributed the drop in participating organizations — with last year marking the smallest number of groups since GridEx II — to changes in “the way we count the participants,” but he said the number of individual attendees represented a significant achievement for the event. 

“Fifteen thousand people across the U.S. and Canada … spent two full days participating. That’s quite a compelling statistic,” Cancel said. “And on the executive tabletop, we’ve seen no decrease there. We continue to get the CEO participation across the electricity sector in the United States and Canada, and I’m also very pleased that we get the appropriate leadership from the federal governments there as well.”

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DOE’s Final Transformer Efficiency Rules Seek to Ensure Stable Supply Chain

The U.S. Department of Energy on April 4 finalized energy efficiency standards for distribution transformers to increase grid efficiency and save $824 million annually. 

The congressionally mandated final standards give the industry an extra five years to comply. DOE said it adjusted them based on significant feedback from the industry and others after issuing its proposal last year. The longer time frame will give the industry time to ramp up production of grain-oriented electrical steel (GOES). 

“The regulatory process can work, and this final rule shows just that by reflecting feedback from a broad spectrum of stakeholders,” Energy Secretary Jennifer Granholm said in a statement. “Ultimately, it will be a piece of the solution, rather than a barrier, to help resolve the ongoing distribution transformer shortage and keep America’s businesses and workers competitive.” 

The final standards can primarily be met with GOES, most of which will be manufactured in the U.S., according to the department. Another small subset of new transformers can be manufactured with amorphous alloy, also expected to be manufactured domestically. 

There are more than 60 million distribution transformers around the country, DOE said. 

Efficiency improvements for transformers will cut wasted energy, saving $14 billion and cutting 85 million metric tons of CO2 emissions over 30 years, DOE estimates. The 30-year energy savings total 4.6 quadrillion BTUs, a savings of 10% compared to current products. 

The initial proposal was going to shift the market to 95% of transformers being made from amorphous alloy, but the final standard can be met if 75% of transformers are made with GOES. The final rule also extends the compliance deadline from three to five years. 

The standards are expected to protect the domestic supply of core materials used to build the transformers, increasing supply-chain resilience and preserving manufacturing jobs in Pennsylvania and Ohio, according to the department. 

“I engaged directly with Secretary Granholm and the Biden administration to ensure Pennsylvanians’ concerns about the proposed rules were heard, and I want to thank them for making sure the final rule will allow for Butler Works to continue its existing line of steel production in Western Pennsylvania, while supporting upgrades that will help spur innovation, protect jobs and reduce carbon emissions from the plant,” Pennsylvania Gov. Josh Shapiro (D) said in a DOE statement. 

The standards will significantly cut energy use by transformers, but they miss the chance for much larger savings, said the American Council for an Energy Efficient Economy. The final standards will save only one-third as much energy as the proposed standards would have. 

“These standards significantly reduce energy waste, but they leave much bigger savings on the table,” Andrew deLaski, executive director of ACEEE’s Appliance Standards Awareness Project, said in a statement. “Passing up the savings that could have been achieved has a real cost for consumers, businesses and the climate.” 

The GridWise Alliance said it was still reviewing the final rule, but it said the new framework will ensure that utilities can continue to make investments essential to maintaining the security and reliability of the grid. 

The country is still experiencing a critical shortage of distribution transformers, with the lead time for procuring some types close to two years, GridWise said. The original standard could have exacerbated that shortage, but DOE recognized the industry’s concerns. 

“I want to thank DOE for considering the challenges facing the grid industry and for listening to stakeholders in adapting the final rule to provide more certainty to the market for distribution transformers,” GridWise CEO Karen Wayland said. “Our GridWise members look forward to working with DOE to address the transformer shortage in the short term and in continually improving the efficiency of the electric grid over the long term.” 

Louis Finkel, the National Rural Electric Cooperative Association’s senior vice president of government relations, agreed that the final rule is much improved over the proposal. 

“The final rule provides stability for most of the market while affording a more gradual shift toward tighter efficiency standards for transformers used to meet larger commercial and certain electrification loads,” Finkel said. “We will work closely with our members, manufacturers and suppliers to ensure implementation does not further disrupt an already strained supply chain.” 

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Court: Ameren Still Without Remedy for Years of Rush Island Air Pollution

After more than two years, Ameren Missouri has not delivered suitable redress for more than a decade’s worth of Clean Air Act violations via its Rush Island coal plant.  

Lawyers for Ameren and the U.S. Department of Justice met again in U.S. District Court for the Eastern District of Missouri last week, where Senior District Judge Rodney Sippel appeared exasperated with Ameren’s proposed legal remedy for its excess pollution, which involves purchasing 20 electric school buses and 40 charging stations for the St. Louis area (4:11 CV 77 RWS). 

Sippel said Ameren’s proposal remains inadequate for the scale of pollution and entreated the utility to offer concrete ideas for “what we can do, not just what we can’t do,” according to the St. Louis Post-Dispatch. Sippel also warned that “stopping violating the law is not a solution to the harm done,” referring to Rush Island’s closure later this year. 

Following the session, the court ordered Ameren, DOJ and the Sierra Club to submit simultaneous proposed mitigation orders no later than May 1.

Rush Island has been at the center of a yearslong legal battle over its emissions. In 2007 and again in 2010, Ameren upped output at the plant by replacing boiler components; however, it didn’t install pollution controls as required for overhauled units under the Clean Air Act. Those violations triggered a 2011 lawsuit from DOJ on behalf of EPA, and another lawsuit in 2014 from the Sierra Club that named two other Ameren Missouri coal plants in addition to Rush Island. The litigation culminated in a court order last year for Ameren to either spend hundreds of millions of dollars installing pollution controls at Rush Island or shut it down. (See Hearing May Settle Ameren, DOJ Clash over Coal Plant.)  

Ameren confirmed this week that Rush Island will close by mid-October 2024, per the court order. 

“Ameren intends to comply with the court’s order, which requires a filing regarding mitigation by May 1, 2024. Our prior legal filing sets forth our position regarding the scope of mitigation,” an Ameren spokesperson said in an emailed statement to RTO Insider. 

Ameren did not elaborate on whether Sippel’s view that it needs to do more will influence its final mitigation plan. 

The utility has blasted DOJ and the Sierra Club’s recommended mitigation plan that includes Ameren purchasing 150,000 indoor air filters for the metro St. Louis area and building a renewable energy facility including at least 300 MW of wind or solar generation paired with at least 200 MW of battery storage somewhere in Ameren’s Midwest service territory. The facility should be built within five years, the two said, to “reduce regional reliance on [sulfur dioxide]-emitting generation infrastructure.” 

In a recent court filing, Ameren argued it should not have to mount a “massive, multiyear construction project that would involve and require input and regulatory approvals from numerous stakeholders.” It also argued that a renewable energy and storage project is extraneous since it already “carefully” plans its resource mix under an integrated resource plan (IRP) process.  

Ameren added that DOJ and Sierra Club’s ask ignores that after the court’s rulings on its liability and remedy, it “has substantially redirected its resource planning into renewable energy generation with enormous investments in wind, solar and battery facilities already planned for the coming years.”  

“What plaintiffs seek — and what their proposal amounts to — is a penalty,” Ameren said. 

In its legal filings, Ameren has touted an anticipated $28 billion in social benefits for retiring the plant early, instead of in 2039 as estimated in previous IRPs. 

Rush Island operates sparingly under a MISO-designated system support resource (SSR) agreement, used to keep generation operating past planned retirement dates for the sake of system reliability. The SSR has been in place since 2022 and has been reupped annually, this time set to expire on Sept. 1. MISO has said its SSR cannot override a federal court order to cease operations, and the coal plant will go dark in October despite MISO previously saying it could require a Rush Island SSR into 2025.  

The Sierra Club declined to comment on how a suitable remedy for Ameren should look but emphasized its joint filing with DOJ last month asserting that an early retirement of Rush Island does not mitigate the harm caused or atone for belated compliance. 

“Ameren has … suggested Rush Island’s recent period of limited operations, coupled with its impending 2024 retirement, obviates the need for further relief. But Ameren’s emissions accounting is skewed, and the company’s description of its retirement decision touts Rush Island’s ‘early’ retirement while ignoring its belated compliance,” DOJ and Sierra Club wrote.  

The two cited Joel Schwartz, a scientist with Harvard’s School of Public Health and an expert witness for DOJ in the case, who has said the social cost of Rush Island’s excess sulfur dioxide pollution is around $23,500 per ton. At 17,000 tons of excess emissions per year, Schwartz estimated that a single year of delay in installing scrubbers or shuttering Rush Island causes $300 million in societal harm to downwind communities. 

Under Rush Island’s limited operating status as an SSR, DOJ and Sierra Club said that Ameren has “still has not begun to pay back the debt owed to the public health and welfare; it has merely slowed the rate at which it borrows from the health of downwind communities.”  

The two further argued that Rush Island Units 1 and 2, which began operating in 1976 and 1977, were designed for approximate 30-year life spans and should have been fitted with pollution controls or retired 15 years ago to comply with the Clean Air Act.  

“Ameren suggests this court should forgive its mitigation obligations entirely, and that it should get full credit for what amounts to a belated selection of an obvious compliance plan that the company should have begun years ago,” they wrote.  

Meanwhile, Ameren is proceeding with a bid before the Missouri Public Service Commission to recoup the costs of retiring Rush Island from its customers (EF-2024-0021). (See Ameren Files to Recoup Rush Island Closure Costs from Customers.)  

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EPA Awards $20B from Greenhouse Gas Reduction Fund

A heat-pump water heater for a low-income homeowner in DeSoto, Ga. A National Guard Armory renovated with high-efficiency, all-electric heating as a small-business and nonprofit incubator in Owosso, Mich. Solar panels, window and roof upgrades, and aging-in-place upgrades for an affordable senior housing project in Miami.

These projects and thousands more like them, funded through community lending institutions, received a $20 billion boost April 4, as EPA announced the eight organizations it has selected to receive grants from its Greenhouse Gas Reduction Fund (GGRF). Grant amounts range from $400 million to $6.97 billion.

Created by the Inflation Reduction Act, the GGRF aims to “create a national clean financing network for clean energy and climate solutions across sectors, ensuring communities have access to the capital they need to participate and benefit from a cleaner, more sustainable economy,” EPA said. The awards represent “the single largest non-tax investment within the [IRA] to build a clean economy while benefiting communities historically left behind.”

The awardees have committed to use the money for projects that collectively will reduce or avoid 40 million metric tons of greenhouse gas emissions per year, while drawing in nearly $7 in private investment for every $1 of federal funds they receive over the next seven years, according to the announcement. In addition, more than 70% of the GGRF funds will go to low-income and disadvantaged communities, including more than $4 billion for rural communities and nearly $1.5 billion for tribal communities.

The Climate United Fund, which was selected to receive the largest GGRF award, plans to use its $6.97 billion to help finance 1 billion square feet of net-zero building space across residential and commercial sectors, including 188,000 units of multifamily housing. Other targets include deploying 150,000 zero-emission vehicles and more than 11 GW of renewable energy.

The group is a partnership between impact investor Calvert Impact, the Community Preservation Corporation — which invests in affordable housing in low-income neighborhoods — and the Self-Help Credit Union, located in Durham, N.C. The fund plans to invest both in community lending institutions and in specific projects.

“We are not aiming to just deploy more clean energy and green buildings in underserved places; we’re building up local lenders and local businesses that can support enduring, thriving, and equitable clean energy markets and communities,” according to a Climate United fact sheet.

Speaking at a rollout event for the GGRF in Charlotte, N.C., on April 4, Vice President Kamala Harris said the grants will address a key issue in building out a clean energy economy: limited access to capital in low-income and disadvantaged communities.

“In every community in our nation, there are, of course, extraordinary people with talent, ingenuity and the ability to help us take on the climate crisis,” Harris said. “In too many places, too many people with all that talent have still had limited access to capital to do the work they want to do, to start and grow a clean energy business.”

The GGRF awards mark “the first time in history we are providing tens of billions of dollars directly to community lenders to finance local climate projects,” she said. “We have taken this approach because we know we have the capacity … to empower communities to decide what projects they want, that will have the greatest impact from their perspective in the place they call home; and then we can invest in those projects in a way that will actually have value for the people who live there.”

The funds also will be used to provide technical assistance and build capacity among community lenders, to “drive deployment of tens of thousands clean energy projects,” said EPA Administrator Michael Regan, who accompanied Harris to Charlotte. “And the good news is we’re not starting from scratch, because these [awardees] are not new to this work. These experts have already provided capital to families and small businesses across the country.”

EPA Administrator Michael Regan in North Carolina | The White House

Self-Help, for example, has spent several years working with a range of community groups to build 49 energy-efficient homes in Grier Heights, one of Charlotte’s historically black neighborhoods, said Donnetta Collier, financial capabilities manager.

“Our work guarantees that the homes’ heating and cooling bills will be under $48/month,” and all the homes were sold to residents with incomes below 80% of area median income, Collier said.

As part of Climate United, Self-Help hopes to scale its model to build more homes “by infusing billions into community lenders across the country,” she said.

The Awardees

The idea behind the GGRF dates back more than decade, when Sen. Ed Markey (D-Mass.) and then-Rep. Chris Van Hollen (D-Md.) first introduced legislation to create a national climate bank. Markey and Sen. Van Hollen continued to work on the legislation, which was finally incorporated into the IRA as the GGRF.

Quoted in the EPA announcement, Van Hollen hailed the awards as “a pivotal moment in America’s fight to confront the climate crisis while driving inclusive economic growth.”

The IRA provides $27 billion for the fund, divided between three programs, two of which will be funded by the $20 billion announced April 4.

The National Clean Investment Fund (NCIF) will award $14 million to three nonprofit groups, to establish “national clean financing institutions that will deliver accessible, affordable financing for clean technology projects nationwide,” with a particular focus on public-private investing and low-income and disadvantaged communities.

Climate United is one of the NCIF awardees, along with the Coalition for Green Capital ($5 billion) and Power Forward ($2 billion). All three have decades-long experience in funding community-level projects, according to EPA

The Clean Communities Investment Accelerator (CCIA) is investing $6 billion in five nonprofit community development financial institutions (CDFIs) to “establish hubs that provide funding and technical assistance to community lenders working in low-income and disadvantaged communities.”

The CCIA awardees are the Opportunity Finance Network ($2.29 billion), Inclusiv ($1.87 billion), Justice Climate Fund ($940 million), Appalachian Community Capital ($500 million) and Native CDFI Network ($400 million).

CDFIs are specialized lenders that focus on providing basic financial services to low-income and disadvantaged communities that may not have access to mainstream financial institutions, according to the U.S. Treasury Department, which certifies CDFIs.

The U.S. has more than 1,300 CDFIs, which together manage more than $222 billion in funds, according to the  Opportunity Finance Network.

The Native CDFI will use its $400 million grant to help 63 community lenders across tribal lands “to fund renewable energy, energy-efficient upgrades and sustainability projects that will enhance well-being and create employment opportunities for native people,” according to the organization’s website.

Republican Rollback Efforts

GGRF’s third program, the $7 billion Solar for All initiative, will “finance clean technology deployment … in low-income and disadvantaged communities,” according to EPA, which said it will be announcing more information on the program later in the spring.

The current awardees were selected through a review process that included “dozens of federal employees — all screened through ethics and conflict-of-interest checks, as well as trained on the program requirements and evaluation criteria,” EPA said.

Following the announcement, the agency will negotiate award agreements with each of the selected organizations, which will set out performance metrics for emission reductions and other goals, according to a senior administration official speaking on background.

Under the IRA, EPA must complete negotiations and finalize agreements to award the funding by Sept. 30, at which point the federal dollars will be officially “obligated” and available to the grantees, the official said.

The House of Representatives on March 22 passed a bill, the Cutting Green Corruption and Taxes Act (H.R. 1023), that would roll back the GGRF. Three days before the 209-204 vote, President Joe Biden issued a statement saying he would veto the bill if it is passed by the Senate.

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DC Budget Woes Threaten District’s Home Electrification Program

The D.C. Council has approved a bill aimed at electrifying 30,000 low-income homes across the district by 2040, but a fight is brewing over funding for the program, which Mayor Muriel Bowser is looking to redirect as part of her efforts to plug holes in her proposed 2025 budget. 

Introduced by Councilmember Charles Allen in February 2023, the Healthy Homes and Residential Electrification Act (B25-119) passed its first reading unanimously during the council’s April 2 meeting. A second reading and final passage could occur at the council’s next regular meeting May 7. 

The bill would establish a “Breathe Easy” program combining district and federal funding to cover all costs for home electrification retrofits for low-income homeowners and for apartment dwellers in buildings with a majority of low-income residents. Partial payments for retrofits also could be provided for moderate-income homeowners on an income-based sliding scale. 

The bill defines home electrification retrofits as “replacement of all appliances or other systems, such as oven, water heater or heating system, that combust fossil fuels on site with appliances and other systems that perform the same function and that are powered exclusively by electricity.” 

Funding for programs to train local contractors in installing and maintaining electric appliances and systems also is included in the bill.

Allen’s original bill set ambitious targets for the program, calling for 5,000 retrofits by the end of 2025, 10,000 by the end of 2030 and 20,000 by the end of 2035. 

However, at a March hearing, the council’s Committee on Transportation and the Environment amended the bill to allow a more gradual ramp-up of the program. The revised goals are to complete 2,500 retrofits by the end of 2027, 10,000 by 2032, 20,000 by 2037 and 30,000 by 2040. 

The committee also stripped the original bill’s provision adding a surcharge to permits for the installation of appliances and systems that burn fossil fuels in both new construction and renovations. 

The council previously authorized full funding for the program last year ― an estimated $25 million ― from the city’s Sustainable Energy Trust Fund (SETF), which is funded from fees residents pay on monthly electric and gas bills. 

But that funding could be slashed according to the proposed 2025 budget Bowser presented to the council April 3. The district is facing a $700 million deficit in 2025 because of a combination of rising costs, slow post-pandemic revenue growth and the expiration of one-time federal funds received from the American Rescue Plan, Bowser said. 

By 2028, the gap could grow to an estimated $1.2 billion, according to city estimates. 

The mayor’s presentation for the council did not mention the Healthy Homes Act or Breathe Easy, but called for $1 billion in program reductions, on top of $493 million in “efficiencies and reductions.” 

In a letter to the council, Bowser also said she would “resist starting new programs that would only add to our longer-term financial pressures.” 

Council staff and clean energy advocates still are combing through the budget’s details, but based on their initial analyses, the mayor intends to use $17.3 million from the SETF to pay utility bills for government facilities, rather than the low-income bill assistance, clean energy and energy efficiency programs it was created to fund. 

Questioned by Allen on April 3, Jenny Reed, director of the Office of Budget and Performance Management, said the need to shift the funds from the SETF was due to D.C.’s own renewable portfolio standard, which requires the district’s utilities to provide 100% clean power by 2032. The district also is working toward a 60% cut in greenhouse gas emissions by 2030 and net-zero by 2040. 

The problem, Reed said, is that the city’s energy demands are decreasing, while its energy bills are increasing as utilities buy renewable power and renewable energy credits to meet mandated levels of clean power. 

To balance the budget, “we looked at areas where programs had not yet started, and where there may be federal funding to offset some of those costs that we were now going to use for other purposes,” she said. 

Getting Creative

Breathe Easy fits that description all too well. 

The district’s Department of Energy and Environment (DOEE) is set to receive $59.4 million from the Inflation Reduction Act to be used for consumer rebates for “whole home” energy upgrades or for individual new electric appliances, such as heat pumps or electric stoves. 

The IRA provides $8.5 billion for home energy upgrades and rebates, with rebate programs being administered by state energy departments and the funding split just about evenly between rebates for whole-home and individual appliance upgrades. 

The rebates were supposed to be available as of Jan. 1, 2023, but the U.S. Department of Energy did not release guidelines for states to apply for the funds until July, and DOEE just now is completing its first applications. (See DOE Opens Applications for $8.5B in IRA Home Efficiency Funds.)

Getting the money is a two-step process, according to Nick Burger, deputy director of DOEE’s Energy Administration. 

“We submit an application to the Department of Energy. They do some initial review,” he said. “They tell us to proceed, and then we have to submit sort of a supplement called the implementation blueprint. That’s got a bit more detail on our program design, and once that piece is approved, then they release the money to us.” 

DOEE is “very close” to submitting its first application, and Burger is hopeful to get it through the Energy Department process by fall, with at least some IRA dollars “flowing to residents … sometime by the end of 2024.” 

But both Burger and Allen said the SETF funds for Breathe Easy are a critical catalyst to maximize the impact of the federal dollars. 

If Breathe Easy is defunded, “the federal infrastructure funding we’re pairing with this local funding will become next to useless,” Allen said at the April 2 council meeting. “There is a cap on how much you can spend on gas-to-electric home renovation under it, and it’s about half of what the actual renovations cost. 

“If [the mayor’s] budget were allowed to pass, it means that we’re not only going to harm lower-income households in our city, but we’re also just going to walk away from federal money on the table. It would be a wasted opportunity,” he said. 

Burger agreed, noting the IRA sets a $14,000 cap for the total rebates a household can receive for appliance upgrades and pays up to 80% of the costs for whole-home efficiency upgrades. “That’s where D.C. money can be used to unlock federal funding … to cover the full cost for income-qualified households,” he said. 

Allen has estimated a full-home electrification, including heat pumps and other appliances, can run up to $30,000 or more per home. 

D.C. already has ambitious clean energy programs, such as its Solar for All initiative, which has a mandate to install rooftop and community solar projects across the city, with the goal of halving utility bills for 100,000 of the district’s low-income residents by 2032. 

To prepare for the federal funds and Breathe Easy, the council last year appropriated $2 million for DOEE to run a pilot program using Solar for All and other existing energy-efficiency programs to install solar and electric appliances in low-income homes. Burger said 48 homes have been upgraded, primarily in two of the district’s African American neighborhoods, River Terrace and Deanwood. 

DOEE also is sponsoring a Healthy Homes Fair on April 6, to “help equip D.C. residents with the knowledge they need” to plan home efficiency and electrification upgrades, Burger said. “While we would be thrilled to be able to show up … with rebates in hand, we also know that residents are planning their electrification journey,” he said, and the fair is aimed at informing them about the available technologies and, eventually, the federal funding opportunities.

Still, without more local funding, the challenge for DOEE will be “how do we get these benefits, the federal rebates, most effectively, most easily into the hands of low-income households,” which may include both single-family homes and multiunit buildings, he said. The IRA provisions for multiunit buildings are more flexible and could be used to cover the full costs of unit upgrades; so, DOEE may prioritize channeling funding toward such buildings, he said.  

But Burger noted that the council and mayor will be negotiating the budget over the coming weeks, so DOEE will not know what its final budget will be until then. If the Breathe Easy funds are cut, DOEE will start exploring how it can stretch the federal funds, especially for the individual appliance rebates. 

“That’s where we’re going to have to kind of continue to look and get creative,” he said. 

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CISA Seeks Comment on Proposed Cyber Reporting Rules

The Department of Homeland Security’s Cybersecurity and Infrastructure Security Agency (CISA) took another step toward fulfilling an obligation imposed by Congress in 2022 with the release of a notice of proposed rulemaking (NPRM) outlining requirements for critical infrastructure operators to report cyber incidents to the agency. 

CISA’s proposal stems from the Cyber Incident Reporting for Critical Infrastructure Act (CIRCIA), which Congress passed in 2022 as part of an omnibus spending bill. The law requires entities in 16 critical infrastructure sectors defined in Presidential Policy Directive 21, including energy, to report relevant cyber incidents to CISA within 72 hours of occurrence, as well as when they make a ransom payment to the perpetrators of a ransomware attack. (See Budget Mandates Cyber Reporting for Critical Infrastructure.) 

Authority for defining which incidents would be subject to reporting and which additional sectors, if any, the requirements would cover was left to CISA, which solicited input from industry with a request for information in 2022. Respondents to the RFI included NERC and the regional entities, which raised concerns about possible conflict between CISA’s potential final rule and the ERO’s Critical Infrastructure Protection (CIP) standards. (See NERC Calls for Flexibility in CISA Cyber Reporting Rules.) 

CISA acknowledged these concerns in its NPRM, along with similar sentiments expressed by groups with their own reporting requirements, such as the Nuclear Regulatory Commission, Department of Energy and Federal Communications Commission. The agency said it doesn’t intend to use the authority granted by CIRCIA to replace existing regulations but “to fill … key gaps in the current cyber incident reporting landscape” created by the lack of a “comprehensive and coordinated approach” to cyber reporting in critical infrastructure.  

The NPRM includes definitions of key terms such as: 

    • Cyber incident — “an occurrence that actually jeopardizes, without lawful authority, the integrity, confidentiality or availability of information on an information system, or actually jeopardizes, without lawful authority, an information system.” 
    • Covered cyber incident — “a substantial cyber incident experienced by a covered entity.” 
    • CIRCIA report — a report of a covered cyber incident, ransom payment or both; or a supplemental report. 
    • Information system — a “set of information resources organized for the collection, processing, maintenance, use, sharing, dissemination or disposition of information.” This definition is borrowed from the Paperwork Reduction Act of 1980. CISA added that operational technology resources also are explicitly included in the definition. 

More general terms such as “cloud service provider” also are defined, while the term “covered entity” is included but not given a set definition. Instead, CISA said whether an entity is covered by the rule will depend on its size, along with sector-specific criteria. The agency also has proposed allowing third parties such as the E-ISAC or its counterparts in other sectors to submit reports on behalf of covered entities with their authorization. 

Web-based Reporting to be Standard

Regarding the manner of reporting, CISA noted CIRCIA required the agency to provide a web-based form for submission of reports. In addition, CISA said it received multiple comments suggesting such a form “is the preferred manner for submission of CIRCIA reports.” As a result, CISA proposed making a web form the “sole explicitly identified option” for submitting incident reports, though it also suggested the final rule would provide for the agency’s director to approve other forms of reporting, such as by telephone or email or in person. 

The content proposed for CIRCIA reports is, for the most part, explicitly required by the legislation and includes information such as the identity of the covered entity, the type of incident being reported, a detailed description of the incident, vulnerabilities that attackers may have exploited, the entity’s defenses and any mitigation or response measures.  

CISA also plans to require entities to state whether they requested assistance from other entities and any engagement they have had with law enforcement agencies related to the ransom payment or attack. The agency said it may add other data to the requirements to keep up with changes in the cybersecurity landscape. 

“CIRCIA is a game changer for the whole cybersecurity community, including everyone invested in protecting our nation’s critical infrastructure,” CISA Director Jen Easterly said in a statement. “It will allow us to better understand the threats we face, spot adversary campaigns earlier and take more coordinated action with our public and private sector partners in response to cyber threats. We look forward to additional feedback from the critical infrastructure community as we move towards developing the final rule.” 

Comments on CISA’s NPRM are due 60 days after its publication in the Federal Register on April 4. 

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Biden Admin Releases Blueprint for Building Decarbonization

The Biden administration released a plan April 2 to decarbonize the country’s building sector, which it says could reduce emissions in the sector by 65% by 2035 and 90% by 2050. 

The Department of Energy worked with the Department of Housing and Urban Development and EPA to write the plan, “Decarbonizing the U.S. Economy by 2050: A National Blueprint for the Buildings Sector.” The blueprint is the first federally developed sectorwide strategy for building decarbonization. 

“America’s building sector accounts for more than a third of the harmful emissions jeopardizing our air and health,” Energy Secretary Jennifer Granholm said. “As part of a whole-of-government approach, DOE is outlining for the first time ever a comprehensive federal plan to reduce energy in our homes, schools and workplaces — lowering utility bills and creating healthier communities while combating the climate crisis.” 

Buildings produce more than one-third of domestic climate pollution, and their owners spend $370 billion on energy annually. The blueprint projects cuts of 90% of greenhouse gas emissions from the sector, which would save consumers $100 billion in annual energy costs and avoid an additional $17 billion in annual health costs. 

The U.S. is home to 130 million buildings, with another 40 million expected to be built by 2050. Buildings account for 74% of electricity demand, while their heating and cooling drives peak demand across multiple sources. 

The blueprint focuses on four key strategies for cutting emissions from the sector: increasing energy efficiency, accelerating on-site emissions cuts, transforming how buildings interact with the grid, and cutting emissions from the materials and process of constructing buildings. It calls for on-site energy use to reach 35% by 2035 and 50% by 2050; cutting on-site emissions by 25% by 2035 and 75% by 2050; tripling demand flexibility on the power grid by 2050; and cutting embodied emissions in building materials 90% by 2050. 

“Although the strategy focuses on federal actions that can drive change, it aligns with several state-level decarbonization roadmaps and notes key opportunities for collaboration among federal, state and local agencies,” the blueprint says. 

Despite major advances in efficiency and carbon-free electricity, the scale and complexity of the building sector means that its decarbonization remains a significant challenge. The nation’s 130 million buildings all use energy differently and produce different levels of GHG pollution. 

“The long lifetimes of buildings and their components mean that today’s buildings will still comprise the majority of the U.S. building stock in 2050,” the report says. “Thus, to achieve this blueprint’s vision, it is critical to accelerate deployment of low-carbon solutions in both new construction and in existing buildings — particularly in disadvantaged communities, where building upgrades are most needed.” 

Recent years have seen advances in efficiency, low-carbon space and water heating, and distributed generation, so it is possible to retrofit existing buildings and construct new ones to be much less carbon intensive, the report says. 

New Better Buildings Initiative for Heat Pumps

DOE on April 3 also announced a new Better Buildings initiative intended to help heat pump manufacturers produce higher-efficiency and more cost-effective rooftop heat pumps for large, commercial buildings. 

“Since 2011, DOE’s Better Buildings Initiative has helped paved the way for cost-effective energy-efficiency and decarbonization solutions across America’s building sector,” Granholm said April 3. “Our new Commercial Building Heat Pump Accelerator builds on more than a decade of public-private partnerships to get cutting-edge clean technologies from lab to market, helping to slash harmful carbon emissions throughout our economy.” 

The heat pump accelerator was developed with major commercial end users including Amazon, IKEA and Target, and includes manufacturers such as AAON, Carrier Global, Lennox International and Rheem Manufacturing. Its goal is to bring affordable, next-generation rooftop heat pumps to market as soon as 2027, halving emissions and energy costs compared to natural gas-fueled heat pumps. 

Deployed at scale, the advanced heat pumps could save commercial customers about $5 billion on utility bills annually. 

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Everett LNG Contracts Face Skepticism in DPU Proceedings

Proposed gas supply agreements between Constellation Energy and Massachusetts gas utilities that would keep the Everett Marine Terminal operating through 2030 are facing significant pushback from environmental organizations and the state Attorney General’s Office in time-constrained proceedings at the Department of Public Utilities. 

Everett is an LNG import facility located just outside of Boston and is the only facility in the region that can directly import and inject LNG into the gas system. The main customer of Everett, the Mystic Generating Station, is set to retire at the end of May at the conclusion of a two-year cost-of-service agreement with ISO-NE, threatening the future of the import facility. 

The impending closure of Mystic has put a looming deadline on finalizing the Everett contracts, which initially were announced in February. (See Constellation Reaches Agreements to Keep Everett LNG Terminal Open.) The gas supply agreements would extend through winter 2030. 

Constellation, the owner of both Everett and Mystic, has said it will be unable to keep the terminal open after the plant closes without the contracts, and it can void the contracts if they are not finalized by May 1.  

This May deadline has led to expedited regulatory proceedings (DPU 24-25, 24-26, 24-27 and 24-28), in which the AGO and several environmental organizations have raised concerns about the cost and environmental impacts of the agreements. 

“Despite taking years to negotiate their gas supply contracts with Constellation, the LDCs [local distribution companies] see … fit to provide the department only two months to conduct a proceeding that would normally take about six months from filing to decision,” the Conservation Law Foundation (CLF) commented in March. 

The organization initially was granted “limited intervenor” status in the proceeding by the DPU, allowing it to examine impacts on low-income customers, the consideration of alternatives and environmental justice effects. The status also potentially enabled the organization to eventually appeal the results of the proceeding. 

However, the DPU rescinded this status April 1 following a protest from the utilities, which argued that giving CLF the ability to appeal any decision would mean “effectively vesting CLF with the ability to negate or veto a department decision approving the proposed contracts.” 

The DPU responded by downgrading CLF to “limited participant” status, which would prevent the organization from appealing the results. Environmental advocates expressed disappointment with the decision and dismissed concerns about a “dilatory appeal.” 

A CLF appeal had the potential to threaten the contracts only if the state Supreme Judicial Court (SJC) thought the issues stated in the appeal merited a hearing by the full court, said Joe LaRusso, senior advocate at the Acadia Center. “What the DPU denial of CLF’s intervenor status prevents, then, is CLF filing a meritorious appeal to the SJC and a potential direct challenge to DPU approval of the contracts.”

Cost Concerns

The contracts at issue likely will come at a hefty price for ratepayers; according to Brattle Group consultants hired by the AGO, the contracts would cost a combined $946 million, which ultimately would be passed on to ratepayers. 

Brattle estimated $375 million would go to covering Everett’s operating costs, while charges associated with procuring LNG would amount to about $489 million and a third group of charges tied to how much gas actually is delivered to the utilities would be about $81 million. 

The latter two charges are indexed and will vary over the course of the contract, but most of the costs (an estimated $864 million) must be paid regardless of how much LNG ultimately is needed. 

“The agreements result in very high prices and, therefore, will be costly to Massachusetts ratepayers,” the consultants wrote in testimony submitted by the AGO. 

The consultants specifically expressed concerns about the LNG supply costs included in the agreements, noting they “do not provide any transparency into Constellation’s upstream LNG supply costs, which means Constellation may have the ability to build in a markup above its own cost of procuring and transporting LNG cargoes to Everett.” 

“The agreements have a pricing formula with poorly explained adders and multipliers that result in significant premiums,” the consultants noted. “The LDCs claim that these adders and multipliers cover the (unknown) costs of LNG procurement and (unexplained) risks faced by Constellation that would accompany its procurement obligations, though they do not know whether this is true and have no way to verify it.” 

Climate Consequences

Throughout the proceedings, the utilities have emphasized the agreements are a temporary solution to preserve the reliability of the gas network, which is threatened by the region’s pipeline constraints. 

In a statement, an Eversource Energy spokesperson called the contracts “a temporary and necessary solution to maintain reliability during the coldest times of the year and serve as a bridge to the clean energy future.” They also noted the agreements will increase system reliability without requiring any new gas infrastructure or pipeline expansions. 

However, environmental advocates in the state are worried the agreements ultimately could function as a bridge to an expanded gas network, instead of decreased gas demand.  

National Grid and Eversource, the two largest gas utilities in the state, project natural gas demand to continue to grow in the leadup to 2030. A recent DPU order and state climate laws passed in recent years are intended to reverse this trend. (See Massachusetts Moves to Limit New Gas Infrastructure.) 

National Grid’s contract with Constellation would authorize the utility to purchase increasing quantities of gas through 2030, with the maximum seasonal quantity more than quadrupling between the winter of 2024/25 and the winter of 2029/30. 

“I would suggest these contracts are not some stopgap measure but a continuation of the gas industry’s playbook to ensure a transition off gas does not happen in our commonwealth,” Cathy Kristofferson, secretary and treasurer of the Pipe Line Awareness Network for the Northeast, said at a public hearing. 

In September, Enbridge announced a new project to significantly increase the capacity of its Algonquin Gas Transmission Pipeline network from New York to Massachusetts with an in-service date of late 2029. (See Enbridge Announces Project to Increase Northeast Pipeline Capacity.) Eversource has confirmed it offered a bid for capacity in the open season for the project, while National Grid has not responded to multiple inquiries into whether it also bid into the open season. 

“It is not lost on some of us that the six-year contract length sought in these proceedings coincides with the six-year in-service time frame forecast by Enbridge for their Project Maple” expansion, Kristofferson added. 

Enbridge submitted comments in favor of the Everett agreements, writing that “New England continues to be underserved by natural gas.” 

“The New England region requires additional natural gas infrastructure to maintain reliability, deliver energy affordability and help the region achieve its policy goals with respect to greenhouse gas emission reductions,” the company added. 

Priya Gandbhir, senior attorney at CLF, said a prolonged reliance on natural gas is “not an acceptable path forward” and echoed concerns about Enbridge’s capacity expansion proposal. 

“If these contracts are going to be approved, it needs to be on the way to our clean energy future,” Gandbhir said, adding that the proceeding underscores the need for holistic energy planning in the state. “I remain very skeptical that the intent of the LDCs is to use this as a bridge to clean energy.” 

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Stakeholder Soapbox: The Greatest Machine Needs a Tune-up

The U.S. electricity grid is often described as one of the greatest and most complex machines ever built. Hundreds of thousands of miles of wires connect our nation’s homes and businesses to our domestic energy resources, helping drive American prosperity and security over the last century. 

But like any aging machine — particularly one designed to meet 20th century needs — some of its components are no longer operating efficiently. And these inefficiencies are costing American consumers on their utility bills and threatening access to reliable electricity. 

Nora Mead Brownell |

Existing connections between grid regions are simply not utilized as well as they should be. 

The power grid is generally broken up into regions. Regional grid operators rely primarily on power plants in their service areas to generate enough electricity for homes, schools, hospitals and businesses. The supply of power must meet demand at any given time to maintain grid stability and to keep the lights on. 

There are also power lines that connect these regional networks, so a home in Cleveland may receive electricity generated by a wind farm outside Des Moines. This is especially beneficial for the Ohio homeowner if that wind farm is producing the cheapest power at that time. And this interregional connection is even more important if a winter storm forces several power plants in Ohio to stop operating. That transmission line will carry critical electricity needed to keep the heat and lights on in homes hundreds of miles away. 

The value of interregional transmission capacity was especially evident during the deadly cold snap in February 2021 that slammed the central U.S. While Texas’s isolated grid was forced to shut off power to millions of people, grid operators in the Midwest and Great Plains avoided widespread outages by importing 15 times more electricity than Texas through interregional lines. 

But the U.S. has few of these interregional power lines. And we are not using the existing capacity very efficiently. While new electricity-carrying lines are needed, they often can take up to a decade to plan and build because of complex siting and planning processes. As a result, it’s important to maximize the use of the existing system. 

Regional grid operators have a clear opportunity to optimize the existing interties they share with neighboring regions. In fact, for nearly two decades, the oversight bodies that monitor Eastern regional grid operators have recommended that they do just that. It’s now well documented that the inefficient use of these connections continues to increase system costs and reduce reliability. 

At times, despite the cost of power being significantly higher in one region than the other, electricity will flow from the more expensive market to the lower-priced market, raising system costs. In the Mid-Atlantic, this costly phenomenon occurred 48% of the time in 2022, according to the PJM Market Monitor. In the Midwest, MISO’s Monitor determined that more than 40% of transactions between its neighboring regions were “ultimately unprofitable” in 2021.

But some U.S. grid regions are using these interregional connections more efficiently. In the West, markets have optimized their interties, saving more than $4 billion since the inception of system changes almost a decade ago. 

Optimizing the use of existing or new interregional transmission capability between grid operators in the Midwest, Plains and Mid-Atlantic would provide approximately $50 million to $60 million annually for every 1,000 MW of intertie capacity, according to recent analysis by the Brattle Group. 

The failure to optimize interties means existing power infrastructure is underutilized, and the benefits of interregional transmission are not fully realized. Thus, there is less of an incentive to build the future interregional transmission lines our country desperately needs to ensure consumers can access clean, affordable power at all hours. Recent studies have shown that the U.S. needs to dramatically hasten the pace of interregional transmission line deployment to meet future electricity demand. 

There are several paths FERC can take to improve the efficiency of the existing interregional system. FERC can require intertie optimization under existing federal law or act on a request from a regional grid operator. Given the well-documented savings that improving current inefficiencies would generate, the commission is well within its authority to require grid operators to optimize their interties. 

We’re long overdue to optimize the capacity currently available. Doing so will enhance the grid today and help ensure that future investment efficiently powers America through the 21st century.   

Nora Mead Brownell served on the Federal Energy Regulatory Commission from 2001 to 2006 and now serves as a Venture Partner at Clean Energy Venture Group.