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November 19, 2024

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In West, Proposals for Tx Planning Proliferate Faster than New Lines

SEATTLE — The state-led Committee on Regional Electric Power Cooperation (CREPC) should spearhead an effort to boost development of new transmission in the West, according to the findings of an initiative that included contributions from former FERC Chair Richard Glick.

The findings were the product of the Western States Transmission Initiative (WSTI), a partnership between CREPC and decarbonization nonprofit Gridworks formed to gather input from electricity sector stakeholders on what actions the committee can take to help give Western transmission planning a more interconnection-wide perspective.

The WSTI proposals came just two days after the Western Power Pool (WPP) floated a plan to create a new group intended to spur the kind of interregional transmission development envisioned in the WSTI effort. (See Plan Seeks to Boost Prospects for New Transmission in the West.)

Key among the WSTI recommendations: CREPC should create a Transmission Working Group that would seek federal funding to hire staff and consultants to examine the state of the Western grid with an eye to fostering a shift from the region’s current “bottoms-up” approach to transmission planning, which favors smaller projects that satisfy local needs, to a process that prioritizes meeting the needs of the wider West with larger-scale projects.

The group also would be tasked with identifying specific interregional projects and possibly could seek National Interest Electric Transmission Corridor (NIETC) designations for some of those projects. That would allow them to reduce investment risk by tapping federal funding, Glick pointed out during an Oct. 4 discussion of the WSTI recommendations at the fall joint meeting of CREPC and the Western Interconnection Regional Advisory Body (WIRAB) on Seattle’s waterfront.

“There’s also one other element to it that people may not agree with, especially state regulators: It would also give FERC backstop siting authority for those particular routes that were essentially rejected by one or more states,” Glick said.

The Transmission Working Group also would focus on potential approaches to allocating costs for interregional projects and seek to coordinate approaches among Western states.

The WSTI also recommended the group host a Western transmission conference that would include multiple stakeholders, including officials from U.S. states and Canadian provinces.

“I think the idea of hosting a conference is to get input from … various stakeholders,” Glick said. “Not just utilities and [independent power producers] and transmission developers, but also other entities as well — voices that are normally not heard, whether it be communities, consumer groups, the business community [and] big industrial customers.”

The Transmission Working Group’s other “potential actions” could include encouraging “independent” planning processes; promoting “forward-looking and inclusive” planning; monitoring and participating in FERC transmission planning and cost allocation rulemaking and compliance proceedings; and participating in other regional transmission planning efforts.

‘Meaningful’ Planning

Sharing the dais with Glick at the CREPC-WIRAB meeting, Gridworks Director Kate Griffith said the WSTI recommendations were the product of a six-month project that included interviews with 40 organizations, which included state agencies, non-governmental organizations, utilities, tribes and other stakeholder groups from across the West.

Key themes emerging from those interviews included the “insufficient” pace of transmission development in the West, the lack of “meaningful” interregional and interconnection-wide transmission planning, and the impediment to development caused by the lack of agreement over cost allocation.

Interviewees also said most utilities lack the resources to build major projects on their own and that state/provincial coordination could play a key role in transmission development but would need more resources.

Oregon PUC Chair Megan Decker | © RTO Insider LLC

“Today’s presentation and discussion really just starts a conversation at CREPC,” Griffith told the audience at the Seattle conference. “After today’s conversation, CREPC co-chairs will be encouraging you all to share your feedback with them, and we’ll be scheduling a follow-up conversation about whether or not to pursue these recommendations.”

If CREPC decides to advance on the recommendations, Griffith said, Gridworks plans to announce the formation of the Transmission Working Group by the end of October and begin efforts to identify transmission corridors and seek consultants to engage in the effort.

State officials attending the conference largely seemed to support a larger role for CREPC in transmission planning.

Washington Utilities and Transportation Commissioner Ann Rendahl said it is “critical” to bring the states together to participate in the process. Rendahl described her experience with NorthernGrid, the Northwest’s planning entity, as one in which the group tells regulators, “‘We’ll check in with you and see if you have any thoughts’ — and that doesn’t really feel like being included in the process and having a perspective.

“With changes in state policies across the board in the West, it’s important to … get everybody’s views as to what’s important and what’s needed for the states to accomplish” their goals, Rendahl said.

“What happens next depends on the feedback we get from all of you today and over the course of the rest of the conference … and the follow-up conversation that we have,” Megan Decker, CREPC co-chair and chair of the Oregon Public Utility Commission, told meeting participants.

Dare to Dream

“I know how much CREPC enjoys an October surprise,” WPP CEO Sarah Edmonds joked during an Oct. 5 panel at the conference as she described why she released WPP’s “concept paper” for the Western Transmission Expansion Coalition (WTEC) two days ahead of the Seattle meeting.

“I posted that for all of you on [Oct. 3] knowing that we could really leverage this opportunity to be together knowing what the Gridworks recommendations were going to be and what we’re trying to do as well, where I see a lot of potential overlap,” Edmonds said.

Edmonds explained that the WTEC concept took shape after Bonneville Power Administration CEO John Hairston told her he saw a need for BPA to be a strong leader for transmission development in the Northwest but thought the conversation should be held in a forum bigger than what the agency offered.

Sarah Edmonds, Western Power Pool | © RTO Insider LLC

“I said to him I was interested in it as long as it was a West-wide, inclusive activity,” said Edmonds, whose organization operates the Western Resource Adequacy Program (WRAP) and facilitates the functions of NorthernGrid.

WTEC would intend to take a “top-down” approach to Western transmission planning, one that would include the Southwest transmission planning entity WestConnect, CAISO, BPA and the Western Area Power Administration, and not seek to upend the region’s transmission planning groups, Edmonds said.

“This is not a proposal that fits under FERC-jurisdictional activities,” she said, calling it “an exploratory effort” to engage in a new approach to planning, with FERC-related processes possibly addressed further in the future.

Edmonds also sees the potential for partnership between the WTEC and the WSTI. She said engagement between the two efforts could identify “a range of things we could shoot for” while avoiding coming into conflict or harming each other.

“We might dare to dream of harmonizing, but what about synchronizing?” Edmonds said. “I’m really open for discussion on all those points because I know, and I also would say because BPA … knows, how important the state partnership is on these decisions. The entities that will build transmission and seek cost recovery also understand that critical part of the relationship. It would be new and different to think of a partnership like this, and I know the devil is in the details.”

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Wash. Weighs Joining California-Quebec Cap-and-trade Program

Washington state officials expect to soon decide whether to join the California-Quebec cap-and-trade program.

The decision could come later this month or in early November, Joel Creswell, climate pollution reduction program manager at the Washington Department of Ecology, told the state’s House Environment and Energy Committee Monday. 

Washington’s decision to join the program would require approval by California and Quebec, setting the stage for a final contract to be signed in 2025.

Creswell said joining the bigger program would likely reduce Washington carbon allowance prices from the high levels seen in this year’s quarterly auctions. Critics of Washington’s cap-and -invest program blame it for the state having the highest gasoline prices in the U.S this past summer.

Carbon prices in the Washington auctions have climbed steadily in the first year of the program, clearing at $48.50 in the first quarter, $56.01 in the second quarter and $63.03 in the third. Republican critics of the program believe the increases have driven up prices at the pump. 

The Oil Price Information Service has estimated that a $50 allowance price would translate into a 40- to 50-cent increase in gasoline prices. The state’s oil sector has acknowledged it has passed the price of allowances to consumers to account for its extra costs. 

However, the gas price tracking service GasBuddy showed that prices in Washington and Oregon (which does not have a cap-and-trade program) had been roughly the same from 2014 to 2022. On Jan. 1, 2023, about two months before the first cap-and-trade auction, Washington’s average price was 10 cents higher than Oregon’s, with the gap expanding to 36 cents by Sept. 27. That 26-cent increase could be theoretically linked to cap-and-invest, Ecology Department spokesperson Andrew Wineke said. 

On Monday, state Sen. Liz Lovelett (D) asked: “Why would California want to link with us?”

Creswell said that Washington joining with California and Quebec would boost the manufacture and sales of green technologies in all three areas as industries seek to trim their carbon emissions.

California conducted its first cap-and-trade auction in November 2012, with prices clearing at $10 per allowance. Prices hit $14 by the third quarterly auction before declining.

In 2014, Quebec joined California to create a cap-and-trade market that is six times the size of Washington’s. California-Quebec prices increased from $19 in 2021 to $36.14 this summer, according to data from the California Air Resources Board.

One reason Washington’s carbon prices have exceeded those in California is the comparatively steeper rate of carbon reductions in the Evergreen State, said Jessica Spiegel, Northwest Region senior director at the Western States Petroleum Association, to NetZero Insider.

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EIA, DNV Lay out Progress, Headwinds in Energy Transition

Two new reports released Wednesday document the progress and challenges in the global effort to reduce greenhouse gas emissions.

DNV issued the 2023 edition of its Energy Transition Outlook, concluding that the transition is still at the starting line, with new renewable generating capacity growing at the same rate as demand.

The outlook is not sunny — the report projects global warming well beyond the 2100 target of 1.5 degrees Celsius — but there are some points of optimism: It predicts slight reductions of emissions starting as soon as next year and dropping 4% lower by 2030. It predicts a 46% reduction in emissions by 2050, when it expects non-fossil energy to supply 52% of world demand.

The Energy Information Administration covers some of the same ground in its annual International Energy Outlook.

The two reports are not directly comparable, as EIA extrapolates future models from an unchanging 2023 policy baseline. It projects global fossil fuel consumption and carbon dioxide emissions would rise through 2050 without major policy adjustments to the current trajectory.

DNV Outlook

An introductory message from DNV Group President Remi Eriksen begins with a simple assessment: “If ‘energy transition’ means clean energy replaces fossil fuel in absolute terms, then the transition has not truly started.”

High prices have had opposite effects on energy industry sectors, making oil and gas exploration more lucrative and complicating the buildout of renewables, he said.

But DNV projects that emissions from oil will peak in 2025 and from natural gas in 2027.

Policy changes already are showing results in the US and EU, where per-capita greenhouse gas emissions are among the highest in the world, it said. However, in the next decade, transmission constraints and supply chain shortfalls pose a threat to progress.

Another trend playing out now is the rise of oil and natural gas prices, which tarnished the status of gas as a bridge fuel during the transition and prompted an increase in coal-fired generation in several countries. But increased fossil use in lower-income countries is gradually balanced over the next decade by increased renewables in wealthier countries, DNV projects.

Advanced economies will drive development of the technologies that will help to enable the transition, but that will not bring as much benefit to medium- and low-income regions, which need de-risked funding to accelerate the transition.

Overall, the energy mix is projected to transition from 80%/20% fossil-renewable in 2023 to 48/52 renewable by 2050, with a 10-fold increase in wind generation and 17-fold increase in solar power.

Energy security has become a motivating factor since Russia invaded Ukraine, disrupting energy supplies and prices. Local energy production is now a priority in many countries, whether it be renewable, nuclear or coal.

So while progress is being made, DNV concludes, it is not being made fast enough. Global emissions would need to be cut 50% by 2030 to achieve a net-zero energy system by 2050, but the report does not project a 50% emission reduction even by 2050.

The global target held out by some activists and scientists — keep the planet from warming more than 1.5 C by 2100 — keeps getting harder to reach, DNV said. It calculates a 2.2-degree increase through 2100 under the emissions forecast in the outlook.

EIA Outlook

EIA said its projections in the IEA conclude that while zero-carbon technology such as renewables and nuclear would meet the bulk of new demand through 2050, that is not enough to counter the increase in other sources of CO2 emissions. These include global population growth, increased regional manufacturing and the push for higher standards of living.

The projections are not forecasts, nor are they even likely scenarios; they assume the policies in place as of late 2022/early 2023 will remain unchanged for the next 27 years. (In fact, the authors note, some policy changes already have occurred as of late 2023.) Rather, the projections are a policy-neutral baseline against which future policy decisions can be considered, the report says.

EIA highlighted three main takeaways from the report.

All cases modeled show global energy consumption rising, with the fastest growth coming in the residential and industrial sectors and the greatest increase in use of liquid fuels coming in industrial applications. As more electric vehicles hit the road, applications such as chemical production account for a greater share of the liquid fuels used.

Global electric generation capacity grows anywhere from 55 to 108% from 2022 to 2050, depending on the case modeled, and actual electricity generated rises 30 to 76%. Renewables, nuclear and battery storage account for most of the increase in both metrics, but renewables grow fastest in cases that assume high economic growth and greater electricity demand.

Energy security is a driving concern in both directions: It hastens the transition away from fossil fuels in some countries and prompts increased fossil consumption in others.

“IEO2023 fills an important niche among global outlooks by focusing on a plausible but sober assessment of global energy trends through the first half of the century,” EIA Administrator Joe DeCarolis said in a news release. “There is considerable uncertainty in the energy landscape over the next 30 years, and the IEO provides a set of policy-neutral baselines that will help guide sound decision-making.”

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IMM Presses MISO for New Rules After DR Market Gaming

MISO’s Independent Market Monitor is angling for demand response offer floors and attestations of expected levels of energy consumption in the wake of an Arkansas steel mill’s gaming of the MISO demand response market.

Meanwhile, a second demand response resource in MISO might be under fire for promising load reductions and not delivering them.

In late August, FERC accepted a $35 million total settlement between Big River Steel in Osceola, Ark., Entergy Arkansas and FERC’s Office of Enforcement, of which $21 million will be returned to MISO customers. The steel mill for years collected payments from MISO for demand response while not actually reducing electricity use. (See FERC OKs $21M Settlement in Arkansas Steel Mill’s DR Scheme in MISO.)

Carrie Milton, of the Independent Market Monitor’s team, said the IMM is advising MISO to reinforce its rules for demand response resources (DRRs) “to prevent similar gaming in the future.”

“After seeing this kind of conduct, we have recommended [that] MISO establish an offer floor for DRRs and that DRRs indicate their forecasted, pre-curtailment expected consumption,” Milton said during an Oct. 5 Market Subcommittee meeting.

Milton said IMM staff recently referred another MISO DRR to the Office of Enforcement for offering “phantom load reductions” similar to Big River Steel. In this case, the unnamed company collected more than $35 million in payments from MISO.

Neither MISO nor the IMM revealed the name of the company involved with the possible new investigation. MISO said the IMM’s screening first uncovered the “information that led to FERC’s investigation” of Big River Steel.

Milton said the IMM team is working with MISO to gain support for the DRR rule changes.

MISO did not say whether it agrees with the IMM’s proposal but said it is open to exploring with stakeholders what improvements might be necessary.

“Following any situation like this, MISO is closely collaborating with the IMM and FERC to evaluate potential enhancements to help prevent similar conduct in the future, which will be vetted through MISO stakeholder process in an open and timely fashion,” spokesperson Brandon Morris said in an emailed statement to RTO Insider.

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Michigan Energy Siting Bills Set off Opponents and Backers

LANSING, Mich. — Michigan’s Public Service Commission would oversee siting of major renewable energy projects under a package of legislation introduced in the state’s House of Representatives, which immediately drew praise from supporters and outrage from opponents.

The bills were introduced Oct. 10 after weeks of anticipation and referred to the House Energy, Communications and Technology Committee. (See Mich. Senate Passes First Renewable Bill; Talks on Package Continue.)

HB 5120 and companion bill HB 5121 would preempt local zoning and give the PSC authority for siting of wind, solar and energy storage facilities of 100 MW or more. HB 5122 and HB 5123 are identical except that they would apply to solar energy storage facilities between 50 and 100 MW. No hearing has been set on the legislation at this time.

An official with the Michigan Townships Association (MTA) immediately blasted the legislation as an “authoritarian” attempt to force small, rural areas to accept large energy facilities and bar local voter referendums on the projects.

“Yes, renewable energy facilities can be contentious in some communities. But the answer is not — and is never — to silence the voices of the impacted residents and communities,” said Neil Sheridan, executive director of the association.

Also opposing the package is the Michigan Farm Bureau, which has said the legislation could harm Michigan’s agriculture industry, as well as the Michigan Association of Planning and the Southeast Michigan Council of Governments (SEMCOG). SEMCOG represents all the city and county governments in Michigan’s largest population area, including Detroit and Wayne, Oakland and Macomb Counties (though those entities also have their own lobbyists).

Not taking a position on the bills thus far are two other significant local government interest groups: the Michigan Association of Counties and the Michigan Municipal League. The Municipal League represents the state’s cities and villages, including Grand Rapids and Ann Arbor (the second- and fifth-largest cities in Michigan, respectively), two communities that have been more aggressive in dealing with climate change issues.

The Municipal League also recently supported HB 5028, which would prohibit homeowners’ associations from barring solar panels on houses.

The MTA represents the more than 1,200 townships in the state — ranging from Canton Township in Wayne County, with a population of greater than 90,000, to Pointe Aux Barques Township in Huron County, population 15 — where most of the major disputes about building renewable energy projects have taken place.

Backing the bills is a coalition of industrial groups that work on and for renewable energy, including the Michigan Energy Innovation Business Council and the American Clean Power Association. Erika Kowall, director of Midwestern Affairs for the ACP, said the legislation showed Michigan was “taking a meaningful step to help counter project delays and ensuring that a clean energy future will unlock economic investment and jobs across the state while protecting the environment.”

Peder Mewis with the Clean Grid Alliance said Minnesota and Wisconsin have systems similar to what Michigan is proposing that maintain local oversight on smaller projects while having state oversight on larger projects.

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MISO: Possibility of Winter Emergency in January

In keeping with its winter estimates from previous years, MISO said it could run into trouble in January should it experience high load or high outages.

In a winter outlook published last week, MISO said it should fare well over the season under typical demand and generation outages. However, the RTO said it may need to declare an emergency in January if a deep freeze spurs either unusual generation outages or elevated demand.

Otherwise, MISO said it should have sufficient firm resources to cover winter peak load forecasts.

The grid operator predicts a 96.4-GW peak in December under typical circumstances or 101.5 GW in a high-load scenario. It said it should have nearly 115 GW of firm resources to cover peak, though that could be downgraded to 110.7 if generation outages creep up.

MISO said its system most likely will realize a nearly 102-GW peak in January under typical demand or up to 107 GW in an amplified demand situation. It said it should have as much as 121.8 GW or as little as 100.7 GW of firm resources available in its fleet, all but guaranteeing the need for emergency procedures and resources.

System strain will ease in February, MISO said, with a 97.6-GW peak or a less likely 102.4-GW peak. In either case, the RTO said it should be able to handle demand without an emergency, having anywhere from 121.6 GW to 111 GW available in firm resources.

MISO anticipates it will have access to about 10 GW worth of load-modifying resources and other operating reserves this winter if it orders emergency procedures.

MISO declared one maximum generation event last winter during a Dec. 23 arctic blast, a product of high load and high generation outages. (See MISO Winter Recap Centers on December Emergency.)

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FERC Denies Rehearing over SPP IC Costs

FERC on Friday rejected a rehearing request by a solar developer of the commission’s denial of its complaint and a tariff waiver over SPP’s interconnection studies for the planned facility (EL22-89).

The commission, citing Allegheny Defense Project v. FERC, denied the rehearing request by “operation of law.” FERC modified the discussion in its previous order but arrived at the same conclusion.

The D.C. Circuit Court of Appeals’ 2020 ruling in Allegheny found the commission no longer could grant rehearing requests “for the limited purpose of further consideration.”

The developer behind Cage Ranch Solar and Cage Ranch Solar II, a 900-MW project in West Texas, sought to reverse the commission’s May decision that found Cage Ranch had not met its burden to show that SPP violated its tariff or conducted its studies in an unjust and unreasonable manner. FERC said the solar facility did not demonstrate the study models underlying the cluster study were defective. (See FERC Sides with SPP Over Interconnection Study Complaint.)

Cage Ranch argued FERC erred by finding its interconnection was the “but for” cause of network upgrades, failing to address the developer’s cost-causation arguments; and that its waiver request did not address a concrete problem.

The commission said it was unpersuaded by the rehearing arguments and continued to find that Cage Ranch had not met its burden under the Federal Power Act to show SPP violated its tariff or that its allocation of costs was otherwise unjust and unreasonable.

“Nothing in the rehearing request demonstrates that the [SPP] study models underlying [SPP’s study] are defective,” FERC said. “Accordingly, we continue to find that Cage Ranch has failed to demonstrate that the network upgrades assigned to Cage Ranch … and the associated [study] payment amount that Cage Ranch was required to post, are unjust and unreasonable and unduly discriminatory or preferential. … None of the issues raised in the rehearing request persuade us that the commission’s conclusions were in error.”

Cage Ranch had said the SPP study in question should not have been used to determine interconnection costs for the solar farm and other customers in the study group because SPP failed to resolve alleged nonconvergence issues. FERC pointed out that the grid operator assigned Cage Ranch network upgrade costs using a modeling approach it applies to all interconnection customers.

Cage Ranch Solar also filed a challenge of FERC’s earlier ruling in August with the D.C. Circuit. It said the orders violate the Federal Power Act and the Administrative Procedure Act and are arbitrary, capricious and an abuse of discretion (23-01227).

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FERC Rules Against Additional Mystic Agreement Disclosures

Independent entities cannot review and challenge tank congestion charges and revenue credits in the annual true-up process for the cost-of-service agreement between ISO-NE and the Mystic Generating Station, FERC ruled Friday (ER18-1639).

The commission also ruled against a request by a group of municipally owned utilities for additional audit disclosures related to the agreement, saying that ISO-NE’s existing audit procedures and disclosures are adequate.

The ruling responded to both the municipal utilities’ request for additional information and a request for rehearing by Constellation Mystic Power, which argued against FERC’s determination that “interested parties” can review and challenge the true-up. That “could be read to allow interested parties to obtain information that is commercially sensitive, and that poses a security risk,” the company said.

In contrast, the utilities argued that the significant costs of the agreement — which they estimated to be more than $400 million over the first 10 months — necessitated the disclosure of additional information to allow interested parties to challenge the credits and charges. (See Public Power Groups Seek Information on Mystic Agreement.)

Credits account for revenues that Mystic earns from sources other than the agreement, while tank congestion charges refer to any costs associated with the increased need for uneconomic self-scheduling or short-term vaporization LNG.

FERC sided with Constellation, reversing its previous determination and also agreeing that shared revenue from third-party natural gas vapor sales should not be included in the true-up process. The commission said these contested issues are inconsistent with the Mystic agreement’s true up process because “none of them are projected in advance, but rather they are each settled and audited on a monthly basis.”

The commission also denied the municipal utilities’ request for additional audit information, which is “not supported by the Mystic agreement and unnecessary, given the attention that ISO-NE, its auditors and the Market Monitor give these items on a regular basis.” The request “goes beyond the terms of the Mystic agreement, which vests ISO-NE with audit rights and requires ISO-NE to maintain the confidentiality of audit-related information.”

“Allowing all interested parties to review Mystic’s revenues and revenue credit could require disclosure of proprietary information about Mystic’s actual fuel costs,” FERC wrote. “We recognize the potential competitive harm to Mystic, Constellation LNG and the market that could ensue from the disclosure of unmasked, offer-specific, commercially sensitive information to third parties.”

FERC wrote that it is “sympathetic” to the concerns about the high costs of the Mystic agreement, but “there is no record evidence that the Mystic agreement formula rate is being improperly executed.”

“The existing cost review and audit processes, which are facilitated by ISO-NE, its auditors and the Internal Market Monitor … are sufficient to ensure that Mystic adheres to its filed rate,” FERC added.

FERC also accepted a proposal ISO-NE had filed as an intermediate solution, which stopped short of the broad disclosures requested by the public power groups but allows for releasing redacted audit reports, providing summaries of its discussions with Constellation about fuel supply decisions, and making a member of Levitan & Associates’ tank congestion audit team available for questions at several points throughout the agreement.

“We are pleased that the commission has recognized the significant information the ISO has made available regarding the ongoing auditing of Constellation’s fuel supply decision,” an ISO-NE spokesperson told RTO Insider via email. “We will continue to work with Constellation and our stakeholders on ways to provide additional information while protecting confidentiality.”

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Green Mountain Power Seeks to Equip Some Homes with Batteries

Hit by one storm after another, Vermont’s largest electric utility is proposing to install battery systems in certain customers’ homes as a resilience measure.

The plan is one piece of Green Mountain Power’s 2030 Zero Outages Initiative, which it calls a first-in-the-nation combination of hardening power lines, creating community microgrids and placing distributed storage assets strategically across its service area — then crunching external data to find the best strategy against power outages on each of 300 circuits.

GMP has been promoting in-home storage units for eight years, and its residential customers now have 5,000 battery units in their homes. The customer waitlist stood at 1,200 when the Vermont Public Utility Commission in August lifted the enrollment cap on two GMP programs to promote in-home storage.

Under one program, GMP leases Tesla Powerwall batteries to customers for 10 years at a discount; under the other, GMP provides an up to $10,500 incentive to ratepayers who buy a system on their own.

In a petition to the PUC Monday, GMP proposes to spend $280 million to increase storm resilience (Case No. 23-3501-PET). Some $250 million would be used to harden 8 to 10% of GMP’s 10,000 miles of overhead lines — either by moving them underground or by protecting them with spacer cables or other devices.

The other $30 million would place battery units in some homes in what GMP calls Zone 4 — areas served by single-phase “last-mile” power lines in rural areas. Some parts of the mountainous state have sufficiently few customers per mile that moving power lines underground or even just hardening them would be less economical than installing batteries.

The utility would cover the cost of the batteries so individual homeowners who couldn’t afford the upfront cost of a battery wouldn’t be left behind.

Ratepayers would pick up the tab, although GMP plans to pursue federal funding.

Other pieces of the puzzle include trailer-mounted energy storage, demand-response-enabled EV chargers and electric school buses with V2G capability.

GMP said the unique aspect of the 2030 Zero Outages Initiative is that it takes all these pieces and overlays them with federal community vulnerability data, topography and other metrics to calculate the best resiliency strategy for each circuit.

Utilities and grid operators nationwide are wrestling with the long-term implications of the clean energy transition and the immediate impact of extreme weather blamed on climate change.

In Vermont, the storms have been coming fast and furious. GMP has spent $115 million on repairs from major storms in the past decade, $45 million of it in just the past year. The three storms with the highest number of outages in GMP history have all hit in the past 12 months.

That is unsustainable, GMP said. It needs to accelerate resiliency efforts so future storms cause less damage and fewer outages.

GMP President Mari McClure said in a news release Tuesday: “We all see the severe impacts from storms, we know the impact outages have on your lives, and the status quo is no longer enough. We are motivated to do all we can to combat climate change and create a Vermont that is sustainable and affordable, but we must move faster. Together with our customers, regulators, our communities and that Vermont spirit that manages to innovate despite all odds, we have all we need to revolutionize the energy system and ensure a stronger, more affordable Vermont.”

If the PUC approves, the $280 million would be spent over the next two years. GMP said it expects the improvements to start yielding savings on storm recovery costs by 2026 and will submit a request for an expanded second phase of improvements to be made through 2030.

In a promising sign, the first 50 miles of power lines relocated underground came through the recent series of major storms undamaged and trees that fell on new spacer cables caused no outages.

GMP serves more than 270,000 homes and businesses in Vermont. It is by far the largest electric utility in the state, and the only one owned by investors.

A spokesperson told NetZero Insider Tuesday that GMP is confident it can secure enough storage units, even amid surging demand for batteries. It already has been working with suppliers.

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Renewable Thermal Storage Could Zero out Industrial Heat Emissions

Thermal energy storage (TES) powered by renewables could be a flexible, cost-effective way to decarbonize heavy industry in the United States, if such projects could access wholesale power prices and rate structures based on cost causation, says a new report from the Renewable Thermal Collaborative and Center for Climate and Energy Solutions.

The technology essentially is a two-fer, capable of providing the high-temperature heat needed for a range of so-called “hard-to-abate” industrial processes, as well as vital grid-support services to ensure power system reliability, according to the report, authored by industry consultants The Brattle Group. Like other storage technologies, it also can be used as a hedge against volatile fossil fuel prices, acting as a sponge to absorb excess renewable power during times of high production and low costs, and discharging during periods of peak demand.

“If widely deployed to their maximum potential, renewable-powered thermal batteries could displace the entirety of the emissions associated with industrial heating demand, amounting to 779 million metric tonnes (MMT, also equivalent to 1 Megatonne) of carbon dioxide equivalent (CO2e) emissions per year in the United States, or approximately 12% of total economy-wide GHG emissions.” the report says.

Globally, renewable TES could slash industrial CO2 emissions by 6,000 MMT per year, or 14.5% of all energy-related emissions, the report says.

A first step for scaling the technology is simply getting it on the radars of critical stakeholders, from potential industrial users to utilities and state and federal regulators, the report says. For example, policymakers and regulators should classify renewable TES as a “qualified technology solution that can be considered equally alongside other alternatives in” state and federal studies examining economy‐wide and grid decarbonization pathways, the report says.

Similarly, the report calls on grid operators to recognize the attributes of renewable TES as a technology that can ramp within minutes or even seconds and operate as either a dispatchable or flexible resource.

Speaking during a recent webinar on the report, Phillip Stephenson, vice president of business development for startup Electrified Thermal Solutions, praised the study for “finally laying out what I think is a great secret we want people to know. … We actually just need to change the rules a bit to match costs and benefits to make this work.

“We are not asking for dumping subsidies on us to unleash a lot of decarbonization and [show] how real these benefits are and how widespread the benefits can be in terms of the grid, which means really [for] the energy transition and society,” he said.

‘The Right Thing to Do’

Thermal energy storage is based on the same basic technology as a toaster or electric stove. Electric power is run through a “resistive material” ― for example, some form of carbon or graphite that impedes power flow, creating heat that can be stored.

The technology has long been used in space and water heating applications, especially in district heating or combined heat and power systems, to capture waste heat for heating and cooling. Such systems often store heat in vats or other large containers of water.

But the high temperatures needed for heavy industry — such as glass, paper and chemical production — typically have required the combustion of fossil fuels. Many companies in these sectors anticipate decarbonizing their factories either by switching from fossil fuels to green hydrogen or cutting their fossil fuel emissions with carbon capture and storage. (See Summit Showcases New Technologies to Accelerate Industrial Decarb.)

Instead, startup companies like Electrified Thermal and Antora Energy have developed technologies that can turn renewable power into high-temperature heat that is stored in special bricks or carbon blocks and released as needed. At present, these and other renewable thermal storage companies can provide heat of up to 750 degrees Celsius, or 1,382 degrees Fahrenheit, high enough to cover 75% of all industrial heat demand, the report says.

Antora, a startup with funding from Bill Gates’ Breakthrough Energy Ventures, recently announced a pilot project in California where the company’s system produced heat at 1,800 degrees Celsius, or more than 3,200 degrees Fahrenheit, high enough to cover almost any industrial process.

Greg Wellman, technology manager of decarbonization for Eastman Chemical Company, talked about the commercial benefits of renewable TES for his firm, a Fortune 500 company producing a range of “specialty materials,” such as bird-friendly glass for building facades.

Spun out of Eastman Kodak in the 1990s, the company is looking at thermal storage because it fits well with its existing natural gas-based infrastructure, and the new systems are modular, meaning they can be sized to try out on a single process or to produce industrial heat for a whole factory, he said.

Another reason Eastman is looking closely at the technology is its potential for price parity with natural gas in the near future, Wellman said. “[When] you think about what’s the long-term trajectory of natural gas pricing, what’s the long-term trajectory of electron pricing … there’s going to be a compelling case to make these changes [to renewable TES], not just because it’s the right thing to do but also because it’s a financially right thing to do,” he said.

The Brattle report notes that for companies like Eastman, renewable TES could allow fuel switching, that is, keeping fossil fuel infrastructure, and natural gas, as backup generation to respond to price fluctuations or emergency events.

Stephenson said the technology also could be an attractive option for utilities anticipating new, higher peaks in energy demand as industrial customers seek to electrify their plants and processes. With renewable TES, industries could electrify “without having those peak demand impacts,” he said.

For utilities, the benefits include improved “economics on their entire system by being able to take all that new heat load coming from the customers … but tuck it under their existing peak by using only off-peak energy,” he said.

Depending on project configuration and rate structure, renewable thermal energy storage can be cost-competitive with natural gas. | RTC

Good for All Customers

Beyond raising industry awareness of renewable TES, scaling the technology will depend on getting it to price parity with natural gas, which, in turn, may depend on a range of factors, such as the configuration of individual systems, rate structures and access to wholesale power prices.

Price parity could vary across system configurations, the report shows, specifically whether the renewable power is located off- or on-grid, whether the system can export power to provide grid-support services or whether the renewable power is coming from the grid itself.

At present, the report says, the most cost-competitive configurations for renewable TES are for projects that “self‐supply or directly contract with a renewable power supplier in an off‐grid or partially grid‐connected status.”

But project configuration often is determined by the specifics of a customer’s site, said Nick Soncrant, Antora’s head of business development.

“If a customer is space-constrained, colocated, new-build renewables will be pretty tough to implement,” Soncrant said. “If a customer is in a renewable-dense region … where the price of power is competitive with natural gas, we can look to work with utilities either under their existing tariff or partner with them to develop a new wholesale market tariff.”

Such new “modern” rate structures are vital for renewable TES to successfully compete with natural gas, the report says. Traditional rate structures, which include generation, transmission and distribution fees, presume “the customer can’t change when they use power,” said Kathleen Spees, a Brattle Group principal and lead author of the report.

For renewable TES to pencil out, Spees said, will require “very principled ratemaking structures of cost causation. … You only apply costs that are really relevant and caused by this sort of customer, which are low because you can really optimize when you would withdraw any power from the grid with a thermal battery,” she said.

“The good news about these modern rate structures, of course, is that they are good for all customers,” Spees said. “They’re good to incentivize all customers to behave in ways that actually reduce costs to the power grid. There is just much more potential and capability to shape whether and when any consumptions patterns take place.”

The report points to two electric cooperatives, the Vermont Electric Cooperative and the Victory Electric Cooperative in Kansas, that have adopted new rate structures based on cost causation. The Victory co-op, for example, has a rate for industrial customers that, the report says, is “aligned with wholesale power prices, consumption during system coincident peak demand and other (smaller) cost components, including local delivery charges.”

841 and 2222

Whether renewable TES projects will be able to access wholesale prices raises another key question: Is the technology covered under either FERC Order 841 or Order 2222, regulations that require, respectively, that energy storage and distributed energy resources be able to participate in wholesale power markets.

To date, Spees said, “that question has not been specifically asked or answered” and would require one or more affirmative rulings from FERC.

The fact that renewable TES can provide multiple value streams, both storing and discharging power, adds another layer of complexity to the issue, said Jordan Kearns, vice president of project development for Antora Energy.

“We … and other folks in the space have systems that can produce electricity back from these thermal batteries, and it’s kind of hard to argue that’s not a battery that would be covered under 841 or 2222,” Kearns said in an interview with NetZero Insider. “But then how do you treat the heat [that] goes off of it? Are you going to be punished for capturing and … putting that waste heat to good use?”

The report offers several recommendations for grid operators and FERC to ensure renewable TES can participate on a level basis in energy, capacity and ancillary markets, including:

    • Having the same size requirements for standalone batteries and renewable TES, with a minimum of 100 MW.
    • Establishing “distinct participation models” for different renewable TES configurations, such as standalone thermal batteries with controllable demand, colocated renewable electricity and thermal battery systems that can be scheduled to charge or discharge power, and TES systems that receive renewable power from the grid.
    • Allowing thermal batteries to access wholesale energy prices based on the same locational marginal price available to generation resources and electric batteries.