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June 10, 2024

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State Regulators Discuss Affordability, Utility Incentives at NEECE

MYSTIC, Conn. — Top utility commissioners from four New England states emphasized the need for regulatory innovation to preserve affordability amid the clean energy transition at the New England Energy Conference and Exposition (NEECE) on June 5. 

“Inequity is probably the most significant concern when it comes to the clean energy buildout,” said Ed McNamara, chair of the Vermont Public Utility Commission. 

As transmission and distribution costs associated with enabling electrification accelerate, protecting low-income customers will become increasingly important, McNamara said. 

“The customers with low incomes are not the ones buying [electric vehicles] or installing heat pumps,” he said. “They’re not benefiting from more stable heating and transportation prices due to electrification, but they’re still paying the cost to upgrade the distribution grid.” 

Marissa Gillett, chair of Connecticut’s Public Utilities Regulatory Authority, said regulators’ primary job is to interpret legislative directives and find “the most cost-effective way to implement the policy goals that are being articulated.” 

“I’ve been a huge proponent of utility regulators taking more of a driver’s seat position,” Gillett said. She stressed the importance of including communities that have not historically been involved in utility proceedings. “The more perspectives we have at the table the more robust our decision-making will be.” 

Gillett said one of the major challenges for regulators in the clean energy transition is the “information asymmetry that all utility regulators — and frankly stakeholders — have to grapple with.” 

“I don’t think there’s any malintent to it; it’s just a simple reality of utilities having information, and utility regulators really having to learn how to ask the right questions and be prepared with new and creative ways to interpret data,” Gillett said. 

Gillett has overseen the PURA’s implementation the legislature’s mandate for a new performance-based regulation framework and has aggressively pursued increased utility accountability. The state’s utilities have been outspoken in their criticism of the new direction, complaining in public and behind the scenes about the state’s regulatory climate and arguing that it is harming their ability to raise capital. 

Several other regulators also spoke about the need to reconsider utility incentive structures amid the clean energy transition.

“We definitely need to move [toward] stronger performance incentives that are really driving outcomes,” said Philip Bartlett, chair of the Maine Public Utilities Commission. “The key is to make sure [utility investments] are going to the places that are going to get us the biggest bang for our buck.” 

Jamie Van Nostrand, chair of the Massachusetts Department of Public Utilities, said regulators should be looking at “incentive mechanisms to align [the utilities’] interests with our interests in pursuing clean energy goals and maintaining affordability.” 

Van Nostrand specifically emphasized the need to support the deployment of virtual power plants and demand-side efforts to reduce the overall need for distribution infrastructure. 

Regarding transmission, Van Nostrand said there have been “huge technological breakthroughs over the last decade or so, whether it’s advanced reconductoring or grid-enhancing technologies, that could really potentially increase the capability of our transmission grid to carry more load.” 

“But we also know there’s a capex bias,” Van Nostrand said. “Utilities tend to want to build more stuff because they get to put it into the rate base and get a return on it. It’s our job as regulators to make sure … that utilities are considering this new technology than can potentially reduce costs.” 

Bartlett, who chairs a New England Conference of Public Utilities Commissioners working group on retail demand response, said well-designed time-of-use rates and DR programs can provide “a real opportunity” for cost-constrained customers to lower their electric bills. 

Effectively reducing demand could also “dramatically reduce the buildout of the grid” and provide cheaper solutions to preserving grid reliability during the most stressful hours of the year, he added. 

“If you can save hundreds of millions of dollars in new programs and fixes to keep things reliable, that’s huge,” Bartlett said. 

The event was the 30th annual NEECE, which is organized by the Connecticut Power and Energy Society and Northeast Energy and Commerce Association. 

Massachusetts Legislative Update

Massachusetts Rep. Jeffrey Roy, co-chair of the state legislature’s Joint Committee on Telecommunications, Utilities and Energy (TUE), gave an update on clean energy legislation currently under consideration. 

The legislature’s previous two sessions have both produced significant climate bills, but lawmakers are running out of time to pass a bill by the end of the current session, which will conclude at the end of July. (See Mass. Lawmakers Aiming for an Omnibus Climate Bill in 2024.) 

While lawmakers are considering a range of proposals related to EV charging, power purchase agreements, advanced metering infrastructure, building decarbonization and retail electricity choice, the top clean energy priority for many in state government appears to be permitting and siting reform. 

“There is nothing more important to our clean energy goals than siting and permitting reform,” Roy said. He called the current siting process in Massachusetts “slow, complicated and intricate.” 

Mary Beth Gentleman, former assistant secretary at the Massachusetts Executive Office of Energy Resources and a member of the state’s Commission on Energy Infrastructure Siting and Permitting, said the state should be permitting “at least six times the amount of clean energy infrastructure as we are currently permitting.” 

Gentleman said transmission and distribution projects typically take seven years from application to the end of the appeals process. 

“At that rate there is little chance that we will be able to comply with the state carbon mandates,” Gentleman said. “Problem No. 1 is there are too many state and local permits, and all of them can be appealed.” Consolidating all required permits into a single process could simultaneously speed up the review and make it easier for the public to participate, she said. 

Roy said he is discussing permitting reform with his TUE co-chair, Sen. Michael Barrett, and the Healey administration to “craft a bill we can all agree on.” 

“I’m confident that we’re going to get a piece of legislation done by July 31,” he said. 

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MTEP 24 up to $5.8B; Clean Energy Group Asks for Alternative to Pricey Entergy Reliability Project

MISO’s 2024 Transmission Expansion Plan (MTEP 24)’s cost increased slightly to $5.8 billion, MISO planners said at a midyear checkpoint of the annual transmission planning cycle.  

The preliminary MTEP 24 clocks in at 471 projects, stakeholders learned during a series of subregional planning meetings June 3-7. An earlier estimate pinned the MTEP 24 package at $5.5 billion. MISO has said this year’s MTEP marks a return to normal levels of investment following last year’s record-breaking $9 billion package. (See Early MTEP 24 Designates $5.5B in Transmission Spending.)  

MTEP 24 includes $688 million in generator interconnection projects and $952 million in baseline reliability projects. Everything else is designated by MISO as “other” and includes projects to address age and condition of facilities, accommodate load growth or meet transmission owners’ self-imposed reliability criteria.  

During a June 6 East Subregional Planning teleconference, MISO’s Amanda Schiro said the bulk of MTEP 24’s other project proposals are motivated by load growth and the age and condition of infrastructure.  

Schiro said MISO will continue to test projects for alternatives through the summer and share a preview and draft report of MTEP in September. She told stakeholders MISO is no longer accepting ideas for alternative projects.  

SREA Asks for Look at Former MISO South Project to Replace Entergy Proposal

Again this year, MISO South contains a big-ticket baseline reliability project that has a clean energy group requesting an analysis of alternatives. 

Entergy Texas proposed a new 35-mile, 500-kV line and substation in East Texas at $409 million. The utility said the line would help prevent potential thermal overloading of “many” 230-kV lines that supply the Port Arthur area. MISO said Texas accounts for 42% of MISO South costs for MTEP 24 because of the large project.  

Last year, Entergy Louisiana proposed almost $2 billion alone in a baseline reliability project to alleviate its Amite South load pocket; MISO ended up recommending an alternate solution to portions of the project.  

The Southern Renewable Energy Association (SREA) has asked that MISO explore resurrecting its $134 million, 500-kV Hartburg-Sabine Junction project in East Texas in place of Entergy Texas’ reliability project.  

MISO canceled the development of its Hartburg-Sabine market efficiency project in 2022 after Texas enacted a right of first refusal law that delayed construction and Entergy built gas-fired plants in the area that made the line less beneficial. Attempts by transmission developers and clean energy groups to save the project have thus far failed. (See FERC Rejects Last-ditch Effort to Save Tx Project.) 

SREA said that because Hartburg-Sabine was proposed to connect to some of the same infrastructure as the new reliability project, it may be able to pull double duty to alleviate reliability problems in East Texas while providing economic value. However, SREA doesn’t know if the market efficiency project can solve the same contingencies.  

At the June 7 South Subregional Planning meeting, MISO South Expansion Planning Manager Trevor Armstrong said MISO will study the potential for Hartburg-Sabine and present results of its analysis in September.  

Entergy Texas did not respond to RTO Insider’s request for comment on whether it thinks Hartburg-Sabine might be a suitable substitution.  

Additionally, Entergy Texas last week announced it is seeking permission with the Public Utility Commission of Texas to spend more than $2.2 billion to build two new gas-fired power plants near Entergy’s line proposal — one in Port Arthur and another about 45 miles north of Houston. The utility said both plants would feature hydrogen-capable combustion turbines and one could be equipped for carbon capture.  

Entergy said it needs the plants online sometime in 2028 to accommodate “extraordinary economic and population growth.

SREA Transmission Director Andy Kowalczyk said the association believes Entergy Texas must pursue the new plants because it hasn’t addressed its load pockets with meaningful transmission.   

“Our general stance is that we believe these sorts of procurements will continue to happen until Entergy addresses the load pockets with increased import capability that provides access to more capacity and market options,” he said in a statement to RTO Insider. 

He said MISO South load pockets such as the East Texas Load Pocket, West of the Atchafalaya Basin Load Pocket, Amite South and Downstream of Gypsy Load Pocket have been identified as issues by Entergy as far back as 2005. He said while Entergy companies focused on the Amite South and Downstream of Gypsy load pockets with transmission projects in MTEP last year, that focus on alleviating load pockets doesn’t yet appear to extend to Entergy Texas territory.  

How MISO can plan for load growth has become a point of focus for some stakeholders.  

At the May 29 Planning Advisory Committee, MISO’s Environmental Sector requested that MISO modify its annual transmission expansion planning and generator interconnection study procedures “to accommodate new, large lumpy loads like data centers and manufacturing.”  

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SPP Files to Incorporate Western Entities into RTO

SPP reached a major milestone June 4 in its efforts to expand into the Western Interconnection when it filed bylaw amendments at FERC to place seven Western entities under its tariff (ER24-2184). 

The revisions would make the RTO the first grid operator with markets in both major interconnections. 

SPP said its expansion will create economic and reliability benefits for all its member companies through access to a larger generation fleet, greater geographic diversity and increased efficiencies in SPP’s energy markets. 

The efficiencies would come by using a single market “optimized solution” across the DC ties that connect the Western and Eastern Interconnections. SPP said that will increase resilience by “leveraging” diverse resources through 510 MW of bidirectional capability, bringing price convergence across the ties. 

“Years of collaboration among SPP staff, existing RTO members and Western entities has resulted in a revised tariff that meets the unique needs of all the entities we serve, and I couldn’t be more thrilled,” SPP CEO Barbara Sugg said in a statement. 

The grid operator said its newest members can expect to see more than $200 million in annual benefits. It said the Integrated Marketplace saved Eastern Interconnection members $3.6 billion last year. 

SPP’s RTO West is scheduled to go live in April 2026. 

The bylaw amendments were approved during the May 7 meeting of the Board of Directors and Members Committee. The board also approved a package of 16 tariff revisions that include establishing a Western balancing authority area and managing transactions across the DC ties. 

Settlements will be based on transmission service reservations during the market’s first four years. After that, they will be based on transmission congestion rights. (See “Bylaw Changes for RTO West,” SPP Board of Directors/MC Briefs: May 7, 2024.) 

SPP has been quietly working with parties interested in evaluating the benefits and requirements of RTO membership since October 2020. Initial RTO expansion terms and conditions were approved in July 2021, and the DC tie terms and conditions in July 2022. 

The entities pursuing RTO membership are: 

    • Basin Electric Power Cooperative; 
    • Colorado Springs Utilities; 
    • Deseret Power Electric Cooperative; 
    • Municipal Energy Agency of Nebraska; 
    • Platte River Power Authority; 
    • Tri-State Generation and Transmission Association; and 
    • the Western Area Power Administration’s Colorado River Storage Project Management Center, Rocky Mountain and Upper Great Plains regions. 
  • The expansion would add Arizona, Colorado and Utah to SPP’s current 14-state footprint and increase the size of its service territory in Wyoming. SPP’s Regional State Committee, composed of regulators from the RTO’s states, would add four new seats to accommodate the new members. 

Representatives from the seven entities would serve on the Members Committee and SPP’s key stakeholder group, the Markets and Operations Policy Committee. Also, several Western-specific working groups would be formed to focus on issues affecting the new members. 

Tri-State CEO Duane Highley, who led SPP member Arkansas Electric Cooperative Corp., said his organization is “enthusiastically” looking forward to participating in RTO West as it looks to advance its energy transition. 

“The full benefits of the RTO, including a day-ahead market, an ancillary services market, efficient regional transmission planning, common transmission tariff and participatory governance model, help us to further reduce costs for our cooperative members across the West,” he said. 

“The RTO offers unprecedented access to regional transmission and generation resources that will help us reach our emission-reduction goals, add more renewable energy, manage customer costs and ensure the reliability of our electric grid,” Colorado Springs CEO Travas Deal said. 

JTIQ

MOPC on June 7 approved a tariff revision request that establishes a cost-allocation framework for projects in the Joint Targeted Interconnection Queue (JTIQ) with MISO. 

The change (RR620) addresses chronic transmission issues along the seam with MISO related to generator interconnection requests and implements cost-allocation policies already approved by SPP’s state regulators. It also memorializes and defines how the JTIQ process will be implemented and applied once executed. 

SPP and MISO have been working since 2020 to identify projects along their seam that can help unlock new generation and resolve congestion issues in the absence of interregional projects. They have agreed on a direct billing approach that assigns 90% of the JTIQ portfolio’s $1.06 billion in costs for its five projects to generation. Load will cover the remaining 10%. (See MISO, SPP Propose 90-10 Cost Split for JTIQ Projects.) 

“The revision request determines how we’ll treat costs, security requirements and congestion-hedging mechanisms,” SPP’s Aaron Shipley told MOPC members. “We feel the benefits help provide some longer-term solutions and a different way to think about chronic issues … hopefully bringing added capacity to that area and helping those issues.” 

The measure passed with 89% approval over opposition from renewable interests. While recognizing the need to facilitate more generation in areas that have been “struggling,” they said the framework risks the JTIQ’s success. 

“The reason we are where we are today is in part because of the failure of our interregional planning processes to produce anything meaningful,” the Advanced Power Alliance’s Steve Gaw said. “This is the first time that projects are even at a point where there could be some projects that come out of this. The only reason it’s moving forward is because the costs are being assigned to generators, and that should not be the way we look at how we do regional planning. We should be looking at how this potentially gets us to a point where we have [a] significant look at who’s benefiting and how those benefits flow.” 

The RSC (June 10), and the board and the MC (June 12), will take up RR620 in similar special meetings. SPP will coordinate the FERC filing with MISO, which also has several special meetings set up in June. The RTOs are targeting a filing by August. 

SPP will seek board approval of the JTIQ portfolio if FERC accepts the tariff revisions and updates to its joint operating agreement with MISO. 

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FERC Sets Dynegy’s MISO Market Manipulation Case for Hearing

Nearly a decade after the MISO capacity auction in which Dynegy was found to have manipulated clearing prices, FERC has directed hearing and settlement procedures in the case (EL15-70, et al.).

The commission’s June 6 order initiated a hearing to resolve the issue while denying Dynegy’s request for oral argument before FERC. The commission had been considering briefs from Dynegy and complainants Public Citizen and the Illinois Office of the Attorney General on whether Dynegy should refund $429 million to Illinois ratepayers.

Two years ago, FERC concluded that Dynegy knowingly manipulated the 2015/16 Planning Resource Auction to produce Southern Illinois’ Zone 4 clearing price of $150/MW-day. FERC’s arrival at that conclusion followed a twisty course, including an abruptly closed nonpublic investigation, an initial finding that cleared Dynegy with little explanation, a remand from the D.C. Circuit Court of Appeals and an announcement that the commission would revisit its decision. (See FERC Staff Finds Dynegy Manipulated 2015 MISO Capacity Auction.)

In its briefs, Dynegy maintained the process unfurled unjustly, saying FERC’s order on remand “reflects bad policy, is fundamentally unfair and is inconsistent with existing norms.” It said the commission improperly raised questions about the “finality” of its decision to close the investigation while “importing” nonpublic information gathered in an investigation under Federal Power Act Section 222 into a public proceeding under Section 206.

“According to Dynegy, this departure from policy, this departure from policy ‘threatens public confidence in the integrity of [FERC’s] enforcement process’ and ‘negatively affect[s] the perceived fairness of commission investigations,’” the commission said.

Dynegy also argued its due process was violated because the commission’s Office of Enforcement had to file a remand report outlining allegations in a Section 206 proceeding using evidence from its closed, nonpublic investigation. Because of the nonpublic nature of the investigation, Dynegy said it couldn’t participate in discovery or cross-examination.

It claimed the remand order exceeded FERC’s authority because, according to the commission itself, a Section 206 filing isn’t the “proper vehicle to prosecute claims of market manipulation.”

The Illinois AG and Public Citizen fired back that “Dynegy cannot now claim, at this late stage of the proceeding, and at the risk of further delay, that its procedural rights have been violated due to the absence of an evidentiary hearing that it never requested.”

FERC said its actions were “an appropriate response” to the D.C. Circuit’s findings, were consistent with its precedent and do not rise to violations of due process.

“We acknowledge that this case, and the issues that the commission must address on remand, present complicated questions regarding the interplay of the closed FPA Section 222 investigation and resolution of the still-pending FPA Section 206 complaints,” FERC said. It added that it takes seriously its decisions to disclose nonpublic information from its investigations and doesn’t foresee itself regularly releasing such information in the future.

“However, we continue to conclude that submission of the remand report and the opportunity for parties to submit initial and reply briefs was an appropriate response,” the commission said.

FERC also pointed out that it’s allowed to release nonpublic information from an investigation and that it’s common practice for it to initiate further briefings following a remand, “particularly where an appellate court rules that the commission failed to adequately explain its decision.”

Dynegy also argued that it wasn’t made aware via Enforcement staff that its behavior leading up to and during the 2015/16 auction could constitute market manipulation. It said it didn’t have a legal or regulatory requirement to sell capacity, nor was it “on notice” that FERC expected it to do so.

The commission didn’t buy the second argument from Dynegy and ruled the company had “adequate notice that its behavior could constitute market manipulation under relevant commission regulations and precedent.”

FERC pointed out that Enforcement staff said their in briefs that Dynegy took pains ahead of the auction to increase the chance an offer from it would set the clearing price in Zone 4. Staff said Dynegy “engaged in a scheme to amass and hoard megawatts that might otherwise have been offered into the 2015/16 auction at a zero price, thereby increasing the likelihood that a non-zero-priced Dynegy resource would be the marginal resource and set the Zone 4 clearing price.”

The division said evidence pointed to Dynegy expecting that the 2015/16 auction would clear below its lowest non-zero offer of $108/MW-day. Rather than submit all its supply at the cost-based $108 price, Dynegy engaged in pre-auction sales at approximately $66/MW-day until it offloaded enough supply to create a specific gap and therefore ensure its own resource would set the clearing price in the zone.

Staff said Dynegy then took steps to maintain the gap by increasing the price of the capacity component of its retail sales offers from $66/MW-day to $164/MW-day, resulting in 125.4 MW of unsold capacity, and refusing to offer a price to two customers for 385 MW of capacity.

“Dynegy also sought to increase the ‘gap’ by purchasing 50 MW of capacity for $61/MW-day — an act that made no economic sense given that it already held thousands of megawatts of unsold capacity,” Enforcement staff wrote.

The company claims its actions were “motivated by a legitimate intent to recover its costs,” not to commit fraud. It said after it lost money in the 2013/14 auction, it devised a strategy to recover its costs by offering capacity both prior to and in auctions. Dynegy said its attempts to receive price signals that could help it make decisions, including resource retirement, were “not only economically rational, but the only way for an independent power producer, reliant on market revenues, to stay in business.”

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FERC Allows Berkshire Utilities to Earn Market-based Rates in WRAP

FERC on June 7 approved tariff revisions by Berkshire Hathaway Energy subsidiaries PacifiCorp, Nevada Power and Sierra Pacific Power that will enable the utilities to earn market-based rates when participating in the Western Resource Adequacy Program (WRAP). 

As noted in the commission’s order (ER24-851), the Western Power Pool’s (WPP) WRAP does not intend to be a centralized market for capacity or energy, but rather a voluntary planning and compliance framework for resource adequacy that facilitates the ability of participants to meet capacity shortfalls through bilateral transactions. 

“As proposed, transactions in the [WRAP’s] Operations Program (notably the energy deployment and its associated total settlement price) would be market-based rate transactions conducted under existing authorities and frameworks on a bilateral basis between participants,” the commission wrote. 

The WPP’s initial plan was to avoid requiring WRAP participants to file individual market-based rate filings and instead rely on a structure of indexed-based prices to settle the bilateral transactions, contending that the system would prevent the exercise of market power among participants. 

Despite that measure, FERC was concerned that some participants would still be transacting in balancing authority areas (BAAs) in which they had been found to exercise market power, and that existing market-based rate requirements imposed on individual participants would still apply. 

“With regard to the price index component of WRAP’s structure, the commission found that the Western Power Pool’s proposal was ‘not sufficient to demonstrate that a price index may be used by specific participants that lack market-based rate authority or are subject to market-based rate mitigation,’ as it failed to address whether the proposed index-based price was a just and reasonable rate for such participants,” FERC noted. 

But recognizing that existing restrictions on market-based rate authority (MBRA) could impede a participant’s ability to transact at WRAP tariff-specified rates, the commission said such a participant could submit a Federal Power Act Section 205 filing “to seek new market-based rate authorization with appropriate mitigation or propose to amend its current market-based rate tariff to include tailored mitigation for the commission to consider.” 

No Market Power

In their Section 205 filings, the utilities pointed out they lack MBRA in their own BAAs, as well as in some first-tier — or interconnected — BAAs. 

“They note, however, that the WRAP tariff obliges them to deliver physical power to a neighbor in need, which could be to a balancing authority area where their market-based rate authority is mitigated. They assert that complying with the WRAP tariff could cause them to exceed the authority in their market-based rate tariffs,” the commission wrote. 

The three utilities proposed to rely on the liquid hubs specified by the WRAP: Mid-C in Washington and Palo Verde in Arizona. The utilities contended they would not set the market price for any transactions in the WRAP and would be price takers, with all sales settled at the price index for each region. 

“Applicants argue that allowing them to amend their market-based rate tariffs to use index prices when selling to counter-parties under the WRAP tariff would be just and reasonable under Order No. 697, where the commission stated it would allow mitigated sellers to use an index or locational marginal price proxy ‘on a case-by-case basis based on their individual circumstances’ rather than defaulting to cost-based rates,” FERC wrote. 

The utilities also argued that Mid-C and Palo Verde meet the commission’s liquidity requirements for use in jurisdictional tariffs. 

“PacifiCorp states that it routinely makes sales at both the Mid-C and Palo Verde hubs and has engaged in sales of millions of megawatt-hours at both the Mid-C and Palo Verde hubs since 2019. Nevada Power and Sierra Pacific did not make any representations about their sales at either the Mid-C or Palo Verde hubs,” but they did note they trade more frequently at the Mead hub in Nevada, FERC said. 

PacifiCorp said it trades only lightly at Palo Verde and, while trading more heavily at Mid-C, it does not report its transactions at either hub to price indexers and therefore could not influence the WRAP settlement price at either hub. 

The commission clarified that its acceptance of the changes to the market-based rate tariffs for the utilities is limited to WRAP transactions and predicated on program provisions that restrict the potential for the exercise of market power. 

“As applicants note, under the WRAP design, when load-responsible entities choose to join WRAP, once committed under the Operations Program, they are obligated to comply with its requirements, including requirements to make non-discretionary sales, or face charges for noncompliance,” the commission wrote. As such, the applicants and other participants in WRAP will have no discretion as to: whether to make a sale; the quantity of any sale; or the price of any sale. For any such sale, the applicants will act as a price taker and, therefore, will not know the WRAP settlement price until after the markets close.” 

But the commission also required the utilities to include in their triennial market power updates to details about their “transactions at or near the Palo Verde and Mid-C hubs, relative to the total volume of transactions at the Palo Verde and Mid-C hubs, respectively, to allow the commission to evaluate the applicants’ sales contribution to index formation.” 

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FERC Chair: States not Benefiting from Grid Projects Won’t Pay — Period

OXON HILL, Md. — FERC Chair Willie Phillips did not expect his audience at the Exelon Innovation Expo to have read every word of the commission’s 1,363-page Order 1920, which sets out to transform transmission planning in the U.S. 

But in his June 5 keynote at the daylong event, he did pick out a few key provisions of the order and made a promise.  

“State regulators must be and will be at the table when we decide what projects to select and how we will pay for them,” Phillips said, speaking to a packed room of about 1,000 attendees at the MGM National Harbor Hotel & Casino. “And I’ll tell you this right now: If you do not benefit from a project, you will not have to pay for it, period.” 

He also stressed the innovative elements of the order’s approach to long-term planning for regional transmission, with a focus on reliability, affordability and sustainability.  

“It makes sure that we look out over the long-term, 20-year horizon to make sure that we plan for the reality … on the horizon; that we consider a broad set of benefits when we do this planning, including grid-enhancing technologies,” he said.

Similarly, Phillips described Order 1977, issued with 1920 on May 13, as a “breakthrough when it comes to how we engage with landowners and environmental justice communities” as part of FERC’s backstop permitting authority for projects in federally designated National Interest Electric Transmission Corridors. (See FERC Issues Transmission Rule Without ROFR Changes, Christie’s Vote.) 

The order’s Landowner Bill of Rights and requirements for project developers to submit Tribal Resource and Environmental Justice Public Engagement plans are intended to “make sure that these vulnerable communities are a part of planning for the new infrastructure that will power the American economy.” 

Speaking on the event’s main theme ― the role of innovation in the U.S. energy transition ― both Phillips and former Energy Secretary Ernest Moniz covered by-now-predictable ground ― the exponential growth in U.S. energy demand driven by data centers and artificial intelligence ― and provided some individual and at times provocative insights. 

Former Energy Secretary Ernest Moniz | © RTO Insider LLC

Now CEO of the nonprofit Energy Futures Initiative, Moniz said current data center load growth signals “we’re just in the early stages of reindustrialization of the United States.”  

Phillips agreed, saying “the technology revolution is an energy revolution … pushing the way we consume, the way we produce and the way we distribute our energy across the country.” 

Chip, battery and EV factories, and heat pumps are all in the mix, Moniz said, “and then we have wild cards that we still don’t know how they’re going to play out fully.” For example, converting the country’s current hydrogen production from natural gas to green hydrogen produced with electrolyzers could require about one-eighth of total U.S. electricity production, he said.  

Moniz agrees with utilities calling for new natural gas generation to meet growing demand.  

“I believe that is a reality,” he said. “However, rather than treating this as a conflict, what I think we need to do is to take a more rational view of the clean energy transition. The word ‘transition’ there has meaning; it means we should not be looking at points in time, but a transition. 

“We have opportunities to design systems in which, if we have a little more carbon now to meet the load, we have to have a catch-up period during the transition in terms of the overall forcing of global warming. We can do that, but the discussion has to evolve around transition.” Moniz did not elaborate on the impacts of such an approach, such as whether building new gas plants in the near-term would increase the likelihood of future stranded assets to be paid for by utility customers, and was not available to respond to a NetZero Insider question on this point.  

However, during his speech, he did say other options for reducing emissions, such as carbon capture and sequestration and advanced or small modular nuclear reactors, “are clearly at least 10 years on the horizon, and that means you don’t wait eight years to start planning it. That means you start last year to start planning it.” 

‘Utilities Didn’t Make the Cut’

Phillips also spoke about the connection between innovation and diversity. 

“Most successful companies value innovation, and for those companies that value innovation, they also value something else; that’s diversity, diversity of experience and diversity of thought,” he said. 

Phillips’ efforts to bring that kind of diverse thinking to FERC are rooted in his own experience, he said, growing up in a single-parent household in Alabama, where he watched his mother spread out bills on the kitchen table to decide which to pay. 

“Sometimes, utilities just didn’t make the cut,” he said. “So, it’s never far from my mind, as I do this work, what real, everyday people — ratepayers, what they’re thinking about, what they’re struggling with to make their ends meet,” he said.  

Phillips sees the coming spikes in energy demand from a similar perspective. While demand is growing, the fact that “70% of our grid was built in the 1950s and 1960s” translates into an aging system where some regions are facing potential power shortages in the near term, he said. “For regulators like us, [the] question is, what do people do when they don’t have the power they need? What do you do when the lights go out?” 

Orders 1920 and 1977 are at least part of the answers to those challenges, he said.  

Moniz called Order 1920 the “biggest step by FERC on transmission, probably in more than a decade.” Planning for the clean energy transition, energy security and social equity should be “one conversation in the policy world,” Moniz said. “It may be treated like three conversations, but it’s not. It’s one conversation, and that is the basis of long-term planning.” 

But more work needs to be done. Moniz sees demand aggregation and risk sharing as a critical part of long-term planning, pointing to a recent agreement by Google, Microsoft and steel producer Nucor to aggregate their demand and fund clean energy projects that can provide carbon-free power.  

“Aggregating demand will again be part of the 20-year planning horizon and a way of sharing risk that the private sector can take on, and the public sector can work with the private sector on,” he said. “There’s no way we can accelerate the way we need to, I think, without all of that.” 

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NPCC Predicts Adequate Electricity Supply this Summer

The Northeast Power Coordinating Council’s 2024 Summer Reliability Assessment, released last week, shows the region “will have an adequate supply of electricity this summer” under most conditions, with a forecast peak demand about 200 MW lower than last summer. 

The regional entity’s predicted peak week begins Aug. 11, though this represents an overall high for the territory. Subregions have a range of peak-week starts ranging from June 2 for New England to Sept. 22 for the Maritimes. 

NPCC said coincident demand in its footprint — which includes the six New England states, New York, Québec, Ontario, New Brunswick and Nova Scotia — should peak at 105,014 MW in its 50/50 forecast, which represents a prediction with a 50% chance of being exceeded. This compares to the 105,200-MW peak in the RE’s summer assessment last year, for the week beginning Aug. 20. (See NPCC Warns of Tight Summer Margins in Ontario.) 

Under the 90/10 forecast — indicating a 10% chance of being exceeded — coincident demand would peak at 112,011 MW, while the RE’s extreme case predicts demand of 117,598 MW for a peak week beginning July 21. Total capacity for the 50/50 and 90/10 scenarios is 162,006 MW, dropping to 161,973 MW in the extreme forecast. Predicted net margins are 12,382 MW for 50/50 and 5,385 MW for 90/10, and a 5,923-MW deficit in the extreme, indicating that energy imports and operating procedures would be necessary to maintain reliability. 

According to the assessment, the “single most important variable” impacting demand in NPCC’s footprint — which is winter-peaking — is ambient weather conditions. This means subregions can experience widely different patterns of demand, reflected in the range of peak week dates and conditions predicted by each reliability coordinator.  

As a result, the RE suggested it is unlikely multiple subregions will experience tight margins at the same time, meaning neighbors will likely be able to help each other out when needed. Québec in particular should “be able to provide assistance to other areas if needed, up to the transfer capability available,” NPCC said. 

While expected demand is lower than last year, NPCC acknowledged that the predicted capacity has also declined slightly, from 163,338 MW in last year’s assessment. The RE noted several resource retirements, the largest of which is the Mystic Generating Station combined cycle Units 8 and 9, representing a total nameplate capacity of 1,515 MW, which went offline May 31. The Mystic retirement “accounts for nearly a 5% reduction in New England’s installed capacity compared to” the 2023 assessment, NPCC said. 

Hydro and tidal power continues to account for the majority of generation in peak weeks, although NPCC noted this figure is skewed by Québec, where this resource makes up 89% of generation. In other subregions, hydro and tidal make up no more than 23% of generation (Ontario), to as low as 11% (New England).  

Dual-fuel generation is projected to be the second most common in the region, though this total is also affected by New York, where dual-fuel makes up 50% of the generation mix, and New England, where it makes up 30%. It also makes up the biggest share of generation in both subregions. 

The Maritimes subregion has the greatest diversity of resource types in the assessment, with coal taking the largest share at 22%, and wind, oil and hydro each accounting for at least 10%. In Ontario, nuclear power leads all other resource types with 34% of generation capacity. 

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Market Footprint Critical for EDAM Decision, NV Energy Says

The growing footprint of CAISO’s Extended Day-Ahead Market (EDAM) was a critical factor in NV Energy’s recently announced decision to join it rather than the competing Markets+ offering from SPP, the utility said in a regulatory filing.

PacifiCorp, the Balancing Authority of Northern California, Los Angeles Department of Water and Power, and Portland General Electric, as well as CAISO, all are expected to participate in EDAM. In addition, Idaho Power has said it is leaning toward EDAM as its day-ahead market choice.

The expected EDAM lineup “provides a significant degree of interconnectivity and supports a diversity of resources,” said Ryan Atkins, NV Energy’s vice president of resource optimization and resource planning.

Atkins’ comments are from written testimony included in the company’s 2025/27 integrated resource plan, filed with the Public Utilities Commission of Nevada on May 31. The commission made the filings public June 5.

CAISO’s recent approval of the Southwest Intertie Project-North (SWIP-North) was another key factor in NV Energy’s decision, Atkins said. A joint project by NV Energy and LS Power, SWIP-North will be a 285-mile, 500-kV line to send Idaho wind energy to markets to the south. It will connect to the One Nevada (ON) Line at Robinson Summit, a site that eventually will be one corner of a transmission triangle across Nevada when NV Energy’s Greenlink North and Greenlink West lines are completed. (See CAISO Board Approves Nevada Transmission Line to Access Idaho Wind.)

SWIP-North “will only enhance the transfer capability of the existing ON Line transmission line in Nevada, bringing even greater benefits to all EDAM participants,” Atkins said.

Atkins also noted the “significant economic, reliability and environmental benefits” that NV Energy has gained through participation in CAISO’s Western Energy Imbalance Market (WEIM). Since joining the WEIM in December 2015, the utility has reaped $488 million in benefits.

Although NV Energy stated in its IRP that it plans to join EDAM, the utility will file a separate, formal proposal later this year seeking PUC approval to join the day-ahead market.

In a June 6 release, CAISO called NV Energy’s intent to join EDAM “a substantial milestone in advancing the efficient coordination of the electric needs for growing loads and a changing resource mix across the West.”

‘Least-cost, Least-regrets’ Decision

NV Energy’s announcement of its EDAM choice may be a central piece in the day-ahead market puzzle in the West.

As competition for day-ahead market participants has been heating up between CAISO and SPP, many potential participants have indicated they are waiting to see who will join each market before making their own decision.

Entities that have shown the most interest in joining Markets+ include the Bonneville Power Administration and Puget Sound Energy in the Northwest, and Arizona Public Service, Salt River Project and Tucson Electric Power in the Desert Southwest. NV Energy’s balancing authority area sits between those two areas.

The comments in the IRP are the latest confirmation of NV Energy’s intent to join EDAM.

David Rubin, NV Energy’s federal energy policy director, confirmed the utility’s decision May 31 during a meeting of the Launch Committee for the West-Wide Governance Pathways Initiative. (See NV Energy Confirms Intent to Join CAISO’s EDAM.)

Before that, NV Energy had disclosed its decision to join EDAM during private meetings, multiple sources previously told RTO Insider.

In his testimony, Atkins also addressed the question of how NV Energy plans to meet a Nevada requirement to join an RTO by 2030.

“Events in the West are still too fluid, and the requirement dates still far enough out, to make any judgments about [NV Energy’s] ability to meet the Jan. 1, 2030, requirement,” he said.

Atkins described the decision to join EDAM as an incremental step to capture “substantial customer benefits on a least-cost, least-regrets basis.”

Last year, the PUC opened a docket to explore ways to evaluate a utility’s request to join a regional market or RTO. (See Nevada RTO Proceeding Examines EDAM, Markets+ Design.)

In a May 20 procedural order, Commissioner Tammy Cordova laid out 18 topics that NV Energy should address in an application to join a day-ahead market.

Those include governance, cost of participation, greenhouse gas tracking, impacts on non-jurisdictional transmission customers and pathways to joining an RTO.

Another topic for consideration is any investment in generation and transmission that would be needed to participate in the market or maximize its benefits.

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BOEM Clears Way for Central Atlantic Wind Lease Auction

The Bureau of Ocean Energy Management has determined its planned lease of Central Atlantic wind energy areas would have no significant impact on the ocean, the creatures that live there or the people who use it for other purposes. 

The final environmental assessment, announced June 6 sets the stage for the BOEM to auction lease areas along the Delaware, Maryland and Virginia coasts this year. The target date is Aug. 14. 

The analysis does not examine the impacts of construction and operation of wind turbines and the associated infrastructure. It analyzes only the research that would determine the area’s suitability for future wind farms and underwater transmission. 

This research includes site assessment and site characterization efforts such as placement of meteorological buoys and oceanographic devices, as well as geophysical, geotechnical, archaeological and biological surveys. 

The three wind energy areas — designated A-2, B-1 and C-1 — total 356,545 acres and stand as little as 19 nautical miles from shore. BOEM expects the four lease areas would average 80,000 acres each. 

B-1 will not be offered in this year’s auction because of the potential conflicts there between offshore wind turbines and nearby military and space flight activities. BOEM concluded the scope of constraints and cost of mitigation measures needed for construction were too great.  

However, B-1 was included in the environmental assessment because it may be included in a later lease sale after NASA and the Department of Defense complete an in-depth review of what activities could co-exist there, and under what conditions. 

Site assessment and site characterization were projected to have a negligible or negligible-to-minor impact on each of the resources evaluated, which ranged from air quality to fishing to military operations to sea turtles. 

BOEM’s Central Atlantic region stretches from Delaware Bay to Cape Hatteras.  

The world’s largest naval base, multiple fighter wings, a bombing and gunnery range and a space launch facility all are sited close to water’s edge, and the Department of Defense has raised concerns about incompatibility with wind turbines. (See Potential Military/NASA Conflict with OSW Seen in Wind Energy Area.) 

Some interagency friction was reported as BOEM attempted to prepare the region for offshore wind development, but by the time Central Atlantic wind energy auction plans were announced in late 2023, the Department of Defense and NASA offered supportive statements. (See BOEM to Auction Wind Energy Areas in Central Atlantic.) 

The concerns about building wind turbines in area B-1 apparently do not extend to doing research work there, or in A-2 or C-1.  

The environmental assessment predicts 201 to 377 round trips from port by an array of research vessels, and states that is not a large number when spread across the anticipated five- to seven-year research window or when compared with the heavy marine traffic already seen in the area. 

Potential conflicts with the military would be averted through effective coordination with military commanders and the U.S. Coast Guard, the report concludes, although site-specific stipulations may be needed. 

In a June 6 news release, BOEM Director Elizabeth Klein said development would move forward collaboratively: “We will continue to work closely with Tribes, our other government partners, ocean users, and the public to ensure that any development in the region is done in a way that avoids, reduces or mitigates potential impacts to ocean users and the marine environment.” 

BOEM also plans offshore wind energy auctions in 2024 in the Gulf of Maine, the Gulf of Mexico and Oregon. 

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Chicago Law Prof Takes ISO-NE to Task at Consumer Liaison Group

HOLYOKE, Mass. — Governance structures and market rules at ISO-NE that favor incumbent interests have contributed to pushing the region into costly and carbon-intensive reliability solutions, University of Chicago Law School professor Joshua Macey told the RTO’s Consumer Liaison Group (CLG) on June 4. 

Speaking to NEPOOL members, ISO-NE officials and members of the public at Holyoke Community College, Macey said the voting power of incumbents within NEPOOL has led to a bias toward capital-intensive solutions to reliability concerns. 

“Reliability regulations are increasingly coming into tensions with clean energy policies,” Macey said, pointing to the reliability-must-run agreement for the Mystic Generating station and ISO-NE’s inventoried energy program, which compensates resources for keeping stored fuel on hand in the winter. The program is set to expire at the end of February. 

“This is the type of intervention that essentially renders any type of clean energy policy irrelevant,” he said, arguing that out-of-market fuel security interventions constitute an admission that the capacity market is not adequately serving its reliability function. 

He argued that ISO-NE’s capacity market has had small penalties for generators that can’t run when called upon. In 2014, “a resource could have met none of its obligations and still made a profit in the capacity market,” he said.  

Although penalties have increased in recent years, that must be coupled with “some way to guarantee that the generator can pay,” Macey said. 

ISO-NE is in the middle of a multiyear process of revising its capacity market rules to better align procurements with tangible reliability benefits. The RTO also has an ongoing project “to reduce collateral shortfalls for Pay-for-Performance penalties that generators are assessed if they fail to operate or underperform during long-duration capacity-scarcity conditions.” 

Regarding transmission, Macey argued that a lack of oversight over line upgrades has led to high-cost projects that do not address the looming needs associated with the clean energy transition. 

Asset-condition project costs have increased dramatically over the past 10 years, prompting states to push for changes. In response, transmission owners have rolled out some changes to the asset-condition review process, including a new database, process guide and opportunities for stakeholders to provide comment on projects in the planning stages. (See “Asset Condition Project Updates,” ISO-NE PAC Briefs: Dec. 20, 2023.) 

However, asset-condition costs have continued to accumulate. In mid-May, National Grid proposed an approximately $500 million project to replace degrading wooden structures with steel poles on a line that was previously refurbished in 2008. (See ISO-NE Planning Advisory Committee Briefs: May 15, 2024.) 

Since the financial risk of these transmission investments falls on ratepayers, TOs face minimal consequences for ineffective or poorly planned upgrades, Macey said. 

One NEPOOL officer took exception to Macey’s characterizations of market and governance bias. 

“When you look at NEPOOL, all the voting is transparent,” said Dave Cavanaugh, vice chair of the organization’s Participants Committee, whose meetings are closed to the press and public. NEPOOL’s primary role as a purely advisory body limits the power of individual companies or sectors, he argued. 

Regarding Macey’s criticism of the capacity market, Cavanaugh said ISO-NE is working to address some of the issues the professor talked about, including increasing penalties. “There’s a message in the marketplace that you need to perform.” 

Demand Response

Henry Yoshimura, director of demand resource strategy at ISO-NE, outlined the role of demand response in the clean energy transition. 

As intermittent renewable resources increase, the grid will face “big periods of under-generation and big periods of over-generation,” Yoshimura said. These swings will lead to energy prices that increasingly “bounce around.” 

This variability of supply, combined with rapidly increasing peak loads, will make DR a key resource in the coming years, Yoshimura said. 

“I do think that retail rate reform is needed in order to encourage demand flexibility,” Yoshimura said, adding that time-of-use rates could incentivize end users to better align their consumption with wholesale prices. 

Yoshimura noted that the proposed shift to a prompt and seasonal capacity auction could boost DR resources, which can be relatively quick to develop and could be used to fill capacity deficiencies on a shorter notice than many traditional transmission or generation solutions.