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November 1, 2024

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Dominion CEO Says Virginia Well Poised to Meet Growing Demand

MCLEAN, Va. — A growing economy driven by new data centers has demand surging in Dominion Energy’s utility territory, CEO Robert Blue said in a speech Sept. 20. 

“Demand for electricity is growing at levels not seen since the years following World War II,” Blue said. “We hit new summer demand peaks in each of the past four years. This year, we’ve had not just one peak, but a whole series of them. In fact, seven out of the 10 highest system peaks that Dominion Energy has ever seen took place in a single two-week period this summer.” 

That was in line with Dominion’s forecast, and there is no sign of it stopping anytime soon, Blue said at a luncheon hosted by bipartisan business group Virginia FREE. 

PJM expects demand in Dominion’s territory to rise by 85% over the next 15 years, which is far more than it had to deal with in the previous 15, Blue said. That is going to have impacts on reliability, affordability and the transition to cleaner energy, he said. 

The utility needs to maintain resource adequacy not just for its residential customers, but for large government and business customers in the D.C. area. 

“Some of the entities we serve include the Pentagon, the CIA, the NSA and seven FBI field offices,” Blue said. “As many of you know, around two-thirds of the world’s internet traffic passes through Northern Virginia, so it’s no exaggeration to say [that] if we don’t execute on our mission, people around the country and even around the globe can’t execute on theirs.” 

Blue said Virginia’s policies have prepared the firm to handle continued growth by allowing it to build several new natural gas plants around the state in recent years, but given how much demand is growing, it will need more supply. 

“We’re going to have to add more generation and more transmission, and we won’t be able to match rising customer needs with renewable generation alone,” Blue said. “Now understand, we’re adding renewable resources at a rapid pace … but we’re also going to need other forms of generation to step in when the weather doesn’t cooperate, as well as during periods of high demand, such as cold snaps and heat waves.” 

That includes building more natural gas plants, preserving Dominion’s existing nuclear capacity and perhaps building new nuclear resources as well. (See Dominion Issues RFP for Small Modular Reactor at North Anna.) 

The Virginia Clean Economy Act requires carbon neutrality by 2045; Blue said Dominion has already cut its emissions in half since the early 2000s, as it has replaced coal plants with natural gas. The former’s share of the company’s generation mix has plummeted from over half in 2005 to about 10%. 

“That’s had a substantial impact on our emissions profile,” Blue said. “It’s also given us the confidence to layer in more renewables, knowing that when the weather isn’t cooperating, gas-fired generation can step in and support our customers.” 

A decade ago, Dominion had no solar; now it has one of the largest portfolios of any utility. And the Coastal Virginia Offshore Wind Project is moving ahead on budget with construction on schedule, even as offshore wind in the Northeast has run into many issues. 

“One big reason we’ve succeeded where others haven’t is Virginia’s regulated utility model, which requires us to demonstrate prudency before we can move forward with the project,” Blue said. “Indeed, I would say ‘prudency’ is the defining characteristic of Virginia’s regulatory compact, and that distinguishes our state from others that have recklessly deregulated their electricity markets.” 

Blue said utility rates are higher in deregulated states, and unscrupulous retailers use deceptive and high-pressure marketing techniques on vulnerable consumers. The winter storm of February 2021 wreaked havoc in Texas — a state often held up as the model for restructuring retail power markets, he added. 

Virginia is not the only traditionally regulated state in PJM, but it is part of a minority, as states like Pennsylvania, New Jersey and Maryland have all opened up their retail markets to competition and given up some authority over generation in the process. 

In 2020, Virginia imported 18% of its power from other states in PJM, but with the surge in demand, that figure is up to 37% so far this year, Virginia Department of Energy Director Glenn Davis said in remarks later during the event. 

Davis said Virginia Gov. Glenn Youngkin (R) has endorsed an “all-of-the-above” energy policy that includes all traditional forms of energy, as well as new, cleaner ones. One of the administration’s goals is to ensure Virginia has enough power that it does not need to rely on imports from other states, he said. 

Imported power “has helped us meet our short-term demand because of our growing economy; it also gives us some serious long-term concerns,” Davis said. “Relying on imported power from PJM means that decisions made by states outside of Virginia — by the other 12 PJM states — have a direct impact on the reliability and cost of the energy supply.” 

Dominion gets several benefits from being in PJM, especially with its long-term, cost-effective regional transmission planning that helps it meet load growth, spokesperson Aaron Ruby said. PJM’s wholesale power markets also ensure the lowest-cost power is available for its customers every day. 

“With that said, we agree we don’t want to be over reliant on out-of-state power, which is why we believe in the regulated model,” Ruby said. “It gives Virginia utilities and our customers more control over our own power supply, which is the best way to ensure our power remains reliable, affordable and increasingly clean.” 

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ERCOT Technical Advisory Committee Briefs: Sept. 19, 2024

Members Endorse Ancillary Services Methodology for 2025

ERCOT stakeholders have endorsed changes to the grid operator’s ancillary services methodology as part of the annual process to determine the minimum amount of products that will be procured in 2025.

Staff’s proposed modifications, presented to the Technical Advisory Committee during its regular monthly meeting Sept. 19, include three revisions to ERCOT contingency reserve service (ECRS). ERCOT introduced ECRS last year, but it drew opposition from the Independent Market Monitor, which said the service produced “massive” inefficient market costs totaling more than $12 billion in 2023. (See ERCOT Board of Directors Briefs: Dec. 19, 2023.)

The Monitor is working with ERCOT and Texas Public Utility Commission staffs on a report for the Texas Legislature that is due by October. The IMM’s director, Jeff McDonald, said there were “limited opportunities” to add lessons learned from the study to the AS methodology process but that he was happy with staff’s recommendations.

“I think we’ve learned some things about procurement targets and some potential recommendations for how the procurement process can be adjusted to result in a lower cost without compromising reliability,” McDonald told TAC. “We do note that that we’re seeing a more targeted procurement through this process, resulting in a reduction in both the ECRS and [non-spinning reserve service] levels procured. We’re happy to see that. … We will have some recommendations that come out of the AS study that we feel will be very important to be taken up and discussed in the 2026 methodology process.”

Staff proposals for ECRS include removing the adjustment for risk coverage during sunset hours to at least the 90th percentile; adjusting the frequency recovery portion to cover 70% of historic net load and inertia conditions; and computing the minimum ECRS requirements as the larger of the capacity needed to recover frequency and capacity needed to support net load forecast.

Since ECRS first was deployed in June 2023, staff said there have been “very few situations” when ECRS had to be released for net load forecast issues and frequency recovery needs. The changes will result in setting ECRS quantities based on needs of the dominant operational risk in every hour, they said.

Staff also proposed minor changes to non-spin, regulation service and responsive reserve service (RRS):

    • Non-spin would be revised so the methodology computing its quantities between 10 p.m. and 6 a.m. uses a four-hour-ahead net load forecast error.
    • Regulation quantities would be computed using the historic error in security-constrained economic dispatch’s forecasted net load.
    • The minimum RRS-primary frequency response (PFR) limit would change to 1,365 MW.

NRG Energy’s Bill Barnes, who represents Reliant Energy Retail Services, asked whether the transition to real-time co-optimization (RTC) next year will affect the math used to calculate “some amount” of AS to be procured throughout the year. ERCOT has set a December 2025 go-live date for RTC, which will procure energy and AS every five minutes. (See ERCOT Sets Go-live Date for RTC, ESR Project.)

“We implement RTC and that all goes away, right?” he asked. “Because how much ancillary services you actually procure is all dependent on price. At that point, the quantities will vary significantly. So I’m wondering, how do we bridge that gap, right?”

“From our perspective, RTC does not change the quantity of ancillary services that we need because the quantities are based on the fundamental operational risks,” said Jeff Billo, ERCOT’s director of operations planning. “So it’s how much RRS do you need to arrest the frequency? How much ECRS do you need to recover frequency? But those fundamentally are physics-based questions that RTC is not changing.”

Billo said ERCOT will propose a methodology similar to the current one as the grid operator goes into 2026. He said he took note of stakeholder feedback from a recent AS workshop about procuring the services closer to real time or the operating day, as opposed to calculating it annually.

“I think that could change the quantities, but we think that doing that at the same time as RTC may not be preferable, and so we want to kind of put that off to 2027,” he said.

The measure cleared TAC, 26-1, with a couple of abstentions. Calpine’s Bryan Sams cast the lone dissenting vote against the changes, saying his organization believes there’s additional risk with the reduction of regulation in the morning and during the winter.

“The second reason is we still believe that ECRS sends, or has sent, an investment signal for new generation development and the reductions in ECRS, I think, are harming that signal,” Sams said.

ERCOT’s protocols require staff to provide at least annually the methodology for determining the procured quantity of each AS needed for reliability. The grid operator’s Board of Directors and the Texas PUC will review the recommendations before making their decisions.

Members Discuss Stakeholder Process

TAC devoted the first two hours of the meeting to a discussion with staff of the stakeholder process and communications. Two hours and 25 minutes later, the membership agreed to reserve time at the next meeting to pick up the conversation.

Members discussed how decisions are made at TAC, how the decision-making process is presented to the board and how the reasoning behind opposing votes is shared with the board.

The discussion was prompted after the PUC’s chair, Thomas Gleeson, said the interaction between the board and TAC “did not work” for him during a July open meeting. (See Texas Commission Rejects ECRS Rule Change.)

The PUC’s Barksdale English, a TAC member when he was with Austin Energy, said commission staff are working on a rulemaking related to the appeal of board decisions to the PUC and “should be coming soon.”

“We talked a lot about what your role is here and how Barksdale English would love for TAC members to view your responsibility here,” English said. “I guess it almost seems like there’s another conversation that needs to be had around how do you codify TAC’s role in receiving recommendations from your subcommittees and how do you codify what you’re communicating up to the board. At the end of the day, it will be the board members’ decisions on how to receive those requests.”

‘Cookies and Laughter’

After committee Chair Caitlin Smith, of Jupiter Power, said during TAC’s August meeting that she was open to lightening the atmosphere for members following comments that “unlike SPP, we don’t have ‘cookies and laughter,’” stakeholders were greeted with a virtual cornucopia of tasty treats. (See “Lightening the Mood,” ERCOT Technical Advisory Committee Briefs: Aug. 28, 2024.)

A large chocolate chip cookie that seemed to have been sent from SPP’s Markets and Operations Policy Committee included a greeting that read, “SPP Cookie Power: From our stakeholder group to yours, we heard y’all need some cookies.” Another container of cookies were iced with “SPP.”

“I had an oatmeal raisin. It was delicious,” one member said.

Two other boxes of cookies were decorated with images of ERCOT CEO Pablo Vegas, a laughing emoji and the words “TAC IS FUN.”

The levity was provided by CIM View Consulting’s Steve Reedy, who reminded TAC that it was “Talk Like a Pirate Day.”

“How many letters does the pirate alphabet have?” he asked, before providing the answer. “I, I, R and the seven Cs.”

Change to CLRs Dispatch

TAC unanimously endorsed a Nodal Protocol revision request and its accompanying Other Binding Document request (NPRR1188, OBDR046) after late comments were filed.

The protocol change would modify the dispatch and pricing of controllable load resources (CLRs) in response to the PUC’s directive to increase the “utilization of load resources for grid reliability.” It revises the market-participation model of CLRs that are not aggregate load resources so that they are dispatched at a nodal shift factor and settled for their energy consumption at a nodal price.

The committee also endorsed a combo ballot that included three NPRRs, one revision to the Nodal Operating Guide (NOGRR) and the annual under-frequency load shedding survey of transmission owners, which found they met requirements for all five thresholds.

The protocol and guide changes, if approved by the ERCOT board, will:

    • NPRR1215: clarify that the day-ahead market’s energy-only offer credit exposure calculation zeros out negative values, with any zeroed-out values being included in the calculation of the dpth percentile difference.
    • NPRR1237: document the scenarios in which market participants are required to successfully complete retail qualification testing, regardless of whether the market participant previously received a qualification letter from ERCOT from prior retail flight testing.
    • NPRR1244: align eligibility provisions for CLRs not providing PFR to provide ECRS. It would also include in physical responsive capability’s calculation only the capacity of CLRs when they are qualified to provide regulation service and/or RRS that requires the CLR to be capable of providing PFR.
    • NOGRR263: clarify that a CLR is only required to provide PFR when it is providing an AS that requires that resource to be able to provide PFR.
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CAISO, Stakeholders Consider GHG Attribution for Non-priced States

CAISO is recommending it implement a Western Power Trading Forum (WPTF) proposal that could help the Extended Day-Ahead Market track and account for greenhouse gas emissions in a way that considers the variety of carbon pricing programs across the West.  

Central to the proposal, first presented by WPTF in March, is use of residual market supply — energy not committed to market participants or attributed to GHG regulation areas.  

The proposal assumes that if the market can ensure entities are able to claim and procure their own resources to meet load, what is left is a relatively small increment of energy, which is the residual supply, Clare Breidenich, WPTF assistant executive director, explained at a March meeting of the ISO’s Greenhouse Gas Coordination Working Group.  

The residual supply helps determine a residual emissions rate, which represents a dispatch-weighted average emission rate of the market supply. Under this framework, leftover energy in the market would go into the residual supply. (See CAISO, Stakeholders Consider 2 GHG Mechanisms for EDAM.) 

“This conversation around a residual rate is going to be robust in terms of how we calculate that,” Anja Gilbert, a lead policy developer at CAISO, said in a Sept. 19 meeting of the GHG group. “There’s questions on how we think about a residual rate for price-based states, for states with climate policies not based on a price, and then for states that do not have climate policies.”  

Portland General Electric Weighs in

Pam Sporborg, director of transmission and market services at Portland General Electric (PGE), weighed in on how states like Oregon that don’t price carbon but do have climate policies could incorporate the proposal.  

While Oregon doesn’t put a price on GHGs, the state requires utilities such as PGE to reduce emissions every year until the utility is “under the 2030 hard cap for emissions that is based on an 80% reduction from a reference level.”  

“While that doesn’t necessarily entail a price on those emissions, we do see it as a hard limit, which can indicate that we have a significant willingness to pay for those emissions,” Sporborg said. “While we really like the structure and framework in this proposal, we want to open up some questions around how we can also ensure that capped states are having an equitable allocation or equitable access to the excess emissions framework consistent with or alongside of the GHG pricing zone states.”

Connie Horng, PGE’s principal greenhouse gas policy analyst, presented an alteration to the proposal, suggesting that if an LSE inside the GHG pricing area has excess designated energy, those megawatt hours and associated GHGs would be assigned to another LSE inside the pricing zone before being allocated to the residual market supply. Within this framework, PGE proposed looking beyond just a GHG pricing zone adjustment and incorporating a methodology that would be able to reflect all GHG regulated zones — including non-priced ones.  

“How do we expand from just the pricing zones that impact Washington and California to include the regulation that applies to Oregon and potentially other states who have these strong caps and a compliance framework associated with GHG?” Horng said. “Our goal here is to allow all of the GHG-regulated states with the clean energy portfolio requirements that we are bringing to the market to solve for each other’s excesses and shortfalls first, before we get that residual market calculation.”  

Gilbert questioned how the ISO might modify the approach to account for PGE’s suggestion.  

“Are we looking to modify the WPTF approach for price-based regions to include states like Oregon? Or is a separate residual rate for Oregon that is applied to Oregon LSEs or BAAs required?”  

Sporborg said PGE was open to both solutions, but thinks they need to be explored more thoroughly.  

“Our goal is to really maximize the diversity benefits from the states,” Sporborg said. “Even though we don’t have the pricing component to our regulation, we will still be making investments in a diverse portfolio of clean energy supply to meet our 2030 goal. … If we can find an opportunity that allows us to participate in the broadest regional diversity and to also benefit from the greening of the portfolios that will create this residual excess, I think that is the solution that we would want to get to optimally.”  

The ISO is seeing feedback on PGEs proposal in written comments and will continue to discuss it in later working groups.  

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Texas RE Endorses ERO Enterprise Strategy

The Texas Reliability Entity’s Board of Directors has unanimously endorsed the ERO Enterprise’s long-term strategic plan that will guide NERC and its regional entities in their collective priorities and activities. 

The strategic plan identifies focus areas to help guide the ERO Enterprise over a longer-term planning horizon and annual work plan priorities that identify performance goals and key accomplishments. It has not been updated since it was created in 2019. NERC hopes to present it to its Board of Trustees in October for approval. 

“[NERC is] looking for each region to indicate their support for this approach, so that all six regions have expressed this is a framework that we can collectively operate under,” Texas RE COO Joseph Younger said during the board’s Sept. 18 meeting. He said at least three other REs have endorsed the plan. 

The plan’s four focus areas are: 

    • using data, tools and approaches to help stakeholders and policymakers address existing risks to the bulk power system and proactively identifying and preparing for emerging and unknown risks. 
    • maintaining cyber and physical security programs that are risk-based, efficient and coordinated and that effectively advance the industry’s security posture. 
    • ensuring that stakeholders and policymakers find value in engagements with the ERO Enterprise and seek its expertise. 
    • performing as an effective and efficient team acting in coordination and ensuring its programs and efforts deliver value for stakeholders and policymakers. 

“It’s a broad umbrella. Honestly, things are changing all the time, but those four categories kind of encompass … all the things that we’re working on,” Younger said. “We hope that it can stand the test of time for a few years.” 

In other actions, the board’s Nominating Committee said it has nominated Milton Lee for a third and final three-year term, effective Jan. 1, 2025. 

“I’m getting so old I wonder if I can actually get up in the morning,” Lee said. “I didn’t think I would make it this far, but I plan to be here for the next three years.” 

Texas RE staff said it had 630 registrants and 495 attendees for its Cyber and Physical Security Workshop, held Aug. 28 in San Antonio. Panels focused on critical infrastructure, threat assessments, current and future grid technologies, and security posture.

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WestTEC Seeks to Close $2.1M Funding Gap Despite DOE Boost

The Western Transmission Expansion Coalition’s (WestTEC) transmission planning study is getting a boost from a $1.75 million Department of Energy grant even as the cost of the project has grown to $6.1 million. 

When the grant application was submitted in January, the preliminary project cost was $4.8 million. DOE is funding 37% of that, or $1.75 million. Western Power Pool (WPP), which is facilitating WestTEC, is expected to provide about $3 million in matching funds. 

Additional funding of $2.2 million is coming from WECC, which is partnering with WPP on the project. 

With the new cost estimate of $6.1 million, WPP is working to close a funding gap of about $2.1 million. Funds will come from sources including WPP members, WestTEC participants and other regional partners that support WestTEC, WPP CEO Sarah Edmonds said in an email. 

During the WECC Board of Directors meeting Sept. 17, CEO Melanie Frye said a three-party contract for the WestTEC project has been drafted among WPP, WECC and Energy Strategies, an energy consulting firm that will do most of the analytical work. 

Frye said WECC is making sure the project qualifies as reliability work under Section 215 of the Energy Policy Act. 

“As of yet, we’ve not expended any funds,” Frye said. “We are wanting to make sure that we have the contract in place and that we’re very clear on what it’s funding so that it’s not falling outside the bounds of the Section 215.” 

The WestTEC study will address long-term interregional transmission needs across the Western Interconnection. The WestTEC Steering Committee recently unanimously approved the project’s study plan. (See WestTEC Committee OKs Plan for ‘Actionable’ Tx Study.) 

The study is expected to take place over the next two years. The goal is to produce transmission portfolios for 10- and 20-year planning horizons. In addition to enhancing Western reliability, the portfolios will also factor in economic efficiencies and state policy goals. 

The grant funding for the study is from the Wholesale Electricity Market Studies and Engagement Program in the DOE’s Grid Deployment Office. The program provides funding to states and regions related to developing, expanding or improving wholesale electricity markets. 

When U.S. wholesale markets were designed three decades ago, the nation’s electric grid “looked much different,” GDO Director Maria Robinson said in a statement regarding the grant program. 

“With the widespread deployment of new clean energy resources and advanced grid and transmission technologies, creating effective wholesale electricity markets is critical,” Robinson said. 

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ITC President Krista Tanner Pushes for Permitting Legislation

WASHINGTON — Transmission policy has made progress lately, but ITC President Krista Tanner came to Capitol Hill to get one more item over the finish line: the permitting bill. 

A bill cleared the Senate Energy and Natural Resources Committee with a bipartisan, 15-4, vote over the summer, and Tanner said she hopes it can become law. (See Manchin-Barrasso Permitting Bill Easily Clears Committee.) 

“There’s widespread recognition that permitting reform is needed, and it’s coming from all corners,” Tanner said in an interview. “So, certainly, proponents of the IRA want to see this, because we’re not going to see the benefits of the IRA or achieve our climate goals if we don’t have the permitting. I mean, this is the last step that we need. Even if that’s not your perspective, we’re seeing energy demand growth in this country for the first time in 50 years. And so, we know that we need a resilient grid to connect new generation to serve new load.” 

ITC Holdings is a transmission-only firm that owns most of the power grid in Michigan and Iowa and does business in five other states: Minnesota, Illinois, Missouri, Kansas and Oklahoma. While it can get through many of the more local projects in its service territories without issue, ITC’s joint Cardinal-Hickory Creek project with ATC and Dairyland Power Cooperative crossed the Mississippi River between Iowa and Wisconsin, cutting through a federal wildlife refuge in the process. 

Nothing in the permitting bill passed by committee “guts” the National Environmental Policy Act and its requirements, but it would limit the amount of litigation involved in building transmission, Tanner said. 

“On Cardinal-Hickory Creek, we had five different lawsuits, five different injunctions. We ultimately prevailed and found that we did, in fact, comply with NEPA and follow the appropriate process,” she added. “And so, it’s really the litigation and the injunctions that created a lot of delays on this project. And those delays aren’t inexpensive. Anytime we start and stop a project, that adds cost to the project.” 

The line is poised to go into service as soon as this week, as the section crossing the river and the refuge has finally been built. The 102-mile line needed permits from Iowa, Wisconsin and several federal agencies that all had different processes, opening it up to multiple avenues for litigation. 

While it did cross a refuge, ITC and the other backers tried to avoid affecting land in other areas, favoring existing rights of way. But it had to cross the Mississippi River at some point, and that section drew significant opposition. While the line did bring up land use issues, it will help connect significant amounts of clean energy to the grid. 

“We have 160 renewable projects waiting to come online for this project, and they represent over 24 gigawatts of clean energy,” Tanner said. “We’re not going to achieve our clean energy goals if we don’t have the transmission to bring the clean energy onto the grid.” 

One way to avoid such delays is to work with affected landowners and communities on the front end to address their concerns. 

“Landowners and communities bear the burden of these lines on behalf of everyone, right?” Tanner said. “And so, it’s really important that you bring them in from the beginning. You talk to them about the need of the line, how it helps their community, not just the region, but their community.” 

ITC will show communities what a proposed substation would look like and what facilities it would serve to indicate how it could provide local benefits. The firm works with landowners on where exactly transmission poles should be placed, and Tanner said it once even leased some other land for an affected landowner to hunt on because transmission line construction stopped them from using their own property. 

FERC Order 1920 has a lot of commonsense transmission planning rules and is in line with what ITC has advocated for some time, Tanner said. MISO transmission practices also line up with the rules, which should solidify how things are done there, she added. 

“I think it will quell the debate because, you know, cost allocation, all of these things remain contentious, and it seems like nothing is ever fully decided,” Tanner said. Having Order 1920 in place “just solidifies that this is the way we do planning in this RTO. We’re not going to keep revisiting these things.” 

Some have argued that the forward planning MISO is engaged in, and FERC has backed in 1920, could lead to transmission overbuild. Tanner said she doubts that, especially based on what happened when MISO completed the Multi-Value Project lines.

“They were at capacity the minute they were built, because we thought too small,” Tanner said. “And so, I think we have to stop thinking small as a country and start betting on our economy and our manufacturers.” 

While 1920 was an important step, FERC could add more “regulatory certainty” around returns on equity to help get transmission built, Tanner said. FERC has had an open proceeding in RM20-10 on incentives for several years and Commissioner Mark Christie has called for reforms in numerous dissents to orders approving them for specific projects. 

Those unresolved ROE cases create uncertainty, Tanner said. “And given the need for investment, this is not the time to create uncertainty.” 

Tanner also said she would like to see FERC further curtail competition in transmission planning and development. The system under Order 1000 has failed largely because independent developers lack the local knowledge of a firm like ITC, she said, which is transmission only but operates in specific communities. 

“The only thing that Order 1000 has succeeded in is causing at least a year’s delay in projects, but it has not reduced the cost,” she added. 

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4 Utilities Nearly Compliant on Order 2023 Rule Changes

FERC has largely approved Order 2023 compliance filings for four utilities in the West and Texas, directing them to submit further compliance filings within 60 days. 

The utilities include Idaho Power (ER24-10), Puget Sound Energy (ER24-1559), Black Hills Colorado Electric (ER24-2023) and Golden Spread Electric Cooperative (ER24-2027).  

FERC approved Order 2023 in July 2023 to revise its pro forma generator interconnection rules to speed up processes in backlogged interconnection queues throughout the U.S. (See FERC Updates Interconnection Queue Process with Order 2023.)  

The order changed the commission’s pro forma interconnection rules to require transmission service providers to shift their approach to interconnection from a first-come, first-served serial process to a first-ready, first-served cluster process; increase the speed of queue processing; and incorporate technological advancements such as grid-enhancing technologies into the process. 

FERC in March partly approved Idaho Power’s initial Order 2023 filing, asking the utility to align its interconnect procedures with the order’s requirements related to the cluster study process, the allocation of cluster network upgrade costs and site control. (See FERC Upholds, Clarifies Generator Interconnection Rule.) 

The commission also had asked the utility “to either justify unexplained variations as consistent with or superior to the commission’s pro forma procedures and agreements or adopt without modification the commission’s pro forma procedures and agreements” and to remove proposed tariff revisions that exceeded the scope of the order. 

In its Sept. 19 ruling, FERC approved revisions to Idaho Power’s initial filing related to the cluster study process, allocation of upgrade study costs and site control, noting the utility largely adopted the commission’s pro forma rules except for “minor variations.” The commission made a similar finding on the utility’s rules around site control and the transition to the “first-ready, first-served” cluster process and affected system study process.  

FERC additionally said Idaho Power had satisfied the commission’s request that it rescind previously proposed revisions to the utility’s surplus interconnection service rules that were determined to be outside the scope of Order 2023 but directed the utility to delete a section of the tariff related to those rules within 60 days. 

The commission issued similar rulings for the other three utilities, finding their proposed tariff revisions largely compliant with Order 2023 but requiring each to submit additional compliance filings within 60 days to account for minor shortcomings in their previous filings. 

The sticking points for Puget Sound Energy’s filing centered around “unexplained” deviations from the pro forma language in the utility’s revisions related to its cluster network upgrade cost rules and affected system agreements. 

In its order on the Black Hills Colorado filing, FERC approved the utility’s deviations from pro forma rules related to operating assumptions for interconnection studies, specifically its practice of not determining the network upgrades required for a charging electric storage resource in its interconnection study process because, when charging, a storage resource “looks and acts more like load than an injecting generator.” Black Hills said instead it would determine the impact of those resources through the transmission service request process. 

The commission’s partial approval of Golden Spread’s filing included a rejection of the co-op’s removal of pro forma language saying that, for transmission providers that employ fuel-based dispatch assumptions, “a request to add a generating facility of a different fuel type to an existing interconnection request would always constitute a modification that would require study.” Golden Spread omitted that language, saying it doesn’t use fuel-based dispatch assumptions, but the commission directed it to restore the language in an additional compliance filing. 

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Cautious Optimism at Alliance for Clean Energy NY Conference

A city bus trundled to a halt on a dusty gravel road just south of Albany at the Port of Albany’s offshore wind expansion project. The passengers, various representatives from labor, the energy industry and the Alliance for Clean Energy New York, shielded their eyes from the late afternoon sun, staring across several acres of flat, riverside land.  

“If you look out to the east side, you’ll see a line of trees that stretches about eight acres,” said Richard Hendrick, CEO of the Port of Albany. “We engaged early on with the First Nations people who have sacred land on the east side of the Hudson River. … They suggested if we just keep that buffer of trees, none of what we’re doing here will impact their view.”  

Hendrick and his staff proudly showed off the newly created, fully permitted site they hope will be the center of offshore wind tower manufacturing for New York’s emerging market. Hendrick’s team had removed 30,000 tons of contaminated coal ash from roughly 100 acres of land and capped off the rest of the soil. Construction is entering final stages on a 400-foot steel bridge to connect the site to the rest of the port over a nearby creek.  

Construction on a 500-foot wharf and dedicated substation are due to begin in early 2025.  

Optimistic Outlook

The tour, forward looking and full of hope, put a period on the general theme of the Alliance for Clean Energy NY’s fall conference. Industry players, regulators and elected officials generally were positive about the direction of New York’s energy future despite recent reporting that the state would fall short of its 2030 climate goals.  

“Our pipeline continues to grow,” said Doreen Harris, president of NYSERDA, in her breakfast keynote address. “We have over 100 large-scale renewable projects in the interconnection queue. … These projects are getting built! Some of you may know that I’ve coined that summer of 2024 is the ‘Summer of Shovels,’ and you have kept me very busy celebrating.” 

Harris said that just 10 years ago, the renewable picture wasn’t nearly as robust. She pointed to 1 GW of distributed solar installed last year and compared it to the roughly 50 MW the state was installing a decade ago.  

“If you take nothing else from these remarks, I want you to know that the renewable energy pie will continue to grow here in New York in the coming decades,” Harris said. She said her goal is to accelerate the progress on renewables, and she encouraged industry representatives to participate in developing the new Clean Energy Standard. 

“The phoenix has risen from the ashes here in New York, and we have collectively emerged stronger, smarter, wiser and more powerful,” she said. “Make no mistake: This was a Herculean effort. But here in New York, we deliver on our promises.” 

Speeding up progress on siting, permitting and interconnection was the major theme of the morning’s panel discussions. Department of Environmental Conservation interim Commissioner Sean Mahar told attendees he didn’t want the DEC to be a barrier to renewable development.  

“What we think we’re doing right now is creating a more workable program,” Mahar said, referencing wetland regulations. “We are structuring this program in the right way so as not to be a barrier to development, but to make sure development is happening in the right places.”  

In later comments, Mahar said DEC is working on ways to permit renewable energy development on brownfields and Superfund sites, to streamline the permitting process and to streamline mitigation efforts in places where renewables harm the environment.

Zach Smith, vice president of system and resource planning for NYISO, said the ISO implemented a new interconnection process to speed up the expansion of transmission and renewables.  

“Our projection is that roughly three times the amount of generating capacity is needed in the next 20 years relative to today’s system. Opportunities abound,” Smith said. “What that capacity looks like, that’s kind of a big question mark. There is not a single formula to this.” 

Smith said the upcoming Reliability Needs Assessment was conservative in its estimate of how much generation capacity would be interconnected. Some projects in the interconnection queue weren’t considered as part of the assessment because they weren’t far enough along. He said a finding of a reliability need wasn’t necessarily “pulling the fire alarm.”  

“Rather, it’s to flag the need for continued progress on resources in New York State, and we have had many,” Smith said. “It’s an opportunity for further resource development.” 

Endorsements for New York’s Renewable Market and Kamala Harris

A lunch panel of renewable energy industry leaders said they were broadly optimistic about building new energy resources in New York. 

“The main point here is that you have a very strong market signal about demand in New York, which makes it an attractive place to really think about a multiyearlong investment program,” said Ben Koffel, chief commercial officer of Vineyard Offshore. He pointed to the high forecast load growth for the state. “If you were at this kind of conference a decade ago, people weren’t talking about that. Everyone was talking about energy efficiency.”  

He said load growth in New York, combined with the state’s willingness to “put its neck out there and be a leader,” made the state attractive to energy investors.  

“We don’t see a tremendous amount of opportunity cost because New York is such a leader, particularly in the offshore space,” Koffel said. “This is a marquee market globally. That’s what we hear from our peers in Europe.” 

Mark Richardson, CEO of US Light Energy, a distributed solar energy company, was less enthusiastic about the near term for his industry segment in the state.  

“Where the rubber hits the road in terms of deployment, distributed generation has been incredibly successful over the past several years,” Richardson said. “From our perspective, the opportunity in that segment has slowed down dramatically, and it’s a combination of infrastructure capacity, interconnection capacity, interconnection queues … combined with a local stranglehold on the permitting process for smaller projects.” 

Richardson said New York, so far, has done a good job, but the distributed generation segment needs more help from the state to deal with local siting and permitting issues.  

Clint Plummer, CEO of Rise Light and Power, said the industry had to find ways to get as much community support as it could while also designing projects that would be minimally impactful.  

“People don’t want big things in their backyards,” Plummer said. “As a resident, I like that my voice has some impact on what can be built in my community where I live, and as a developer, it’s a major source of annoyance. But it’s a necessity.” 

Plummer said this meant going to public meetings and being willing to take the “endless barrage of criticism” that they bring, then adapting plans to mitigate, or avoid, impacts.  

“You’re never going to win everybody, but people will respect you for being a trustworthy partner,” Plummer said.  

Later, during a “lightning round” question, the topic of the election was brought up to the panel.  

“I hope a year from now, Doreen is not the only President Harris that we know,” Plummer said. “But practically speaking, this underscores why New York is a good place to be investing.”  

Plummer explained that a Harris presidency probably would be more pro-renewable than a second Trump administration. But if Trump were elected, New York’s position of pushing for more renewable generation for the state still would make it an attractive spot to develop.  

Koffel said that even if Trump wins, New York has a strong economic case for renewables now that the industry had gotten to its current size.  

“Renewables is a big tent, and the industry touches a lot of people,” Koffel said. “In the event that Trump is the president again, that tent will mobilize to talk about the benefits it’s bringing to the region, the billions and billions of dollars of investment.” 

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Constellation to Reopen, Rename Three Mile Island Unit 1

Constellation Energy plans to reopen Three Mile Island Unit 1 under a power purchase agreement with Microsoft to sell about 835 MW to serve the company’s data centers.

Constellation announced the reopening in a press release Sept. 20, exactly five years after it took the nuclear generator offline for economic reasons. In its new life, the generator has been renamed the Crane Clean Energy Center (CCEC) in memory of Exelon CEO Chris Crane, who died in April 2024. (See Exelon to Close Three Mile Island.)

“Powering industries critical to our nation’s global economic and technological competitiveness, including data centers, requires an abundance of energy that is carbon-free and reliable every hour of every day, and nuclear plants are the only energy sources that can consistently deliver on that promise,” Constellation CEO Joe Dominguez said in the announcement. “Before it was prematurely shuttered due to poor economics, this plant was among the safest and most reliable nuclear plants on the grid, and we look forward to bringing it back with a new name and a renewed mission to serve as an economic engine for Pennsylvania.”

Constellation aims to bring the unit back online in 2028 and will seek a license renewal from the Nuclear Regulatory Commission to continue operating the generator through at least 2054. Restarting the unit will require a $1.6 billion investment, including upgrades to the turbine, generator and transformer. Safety and environmental reviews will be required from the NRC, as well as local and state permits. The adjacent TMI Unit 2, which partially melted down in 1979, is owned by Energy Solutions and is in the process of being decommissioned.

Microsoft Vice President of Energy Bobby Hollis said the carbon-free energy provided by CCEC will help the company meet its clean energy targets. The PPA will be effective for 20 years.

“This agreement is a major milestone in Microsoft’s efforts to help decarbonize the grid in support of our commitment to become carbon negative. Microsoft continues to collaborate with energy providers to develop carbon-free energy sources to help meet the grid’s capacity and reliability needs,” he said.

Data center load has been a significant driver of rapidly increasing load forecasts in PJM and has been highlighted as one factor behind a spike in capacity prices in the 2025/26 capacity auction. (See “PJM Discusses 2025/26 Auction Results,” PJM MRC/MC Briefs: Aug. 21, 2024.)

The RTO’s 2024 load forecast, which is based on historic economic trends, includes large load additions in the AEP, APS, Dominion and PS zones, reflecting changes in consumption that utilities identified. Dominion estimated 2,666 MW of additional load in 2025, which it estimates will balloon to 21,563 MW in 2039. American Electric Power estimates 1,738 MW in 2025, growing to 3,624 MW in 2039.

Data centers have sought to co-locate with nuclear power plants, which would pull capacity out of PJM’s market over the objections of utilities and state regulators. Talen Energy and Amazon Web Services reached an agreement earlier this year to sell a data center Talen built adjacent to its Susquehanna Nuclear Plant and supply it with behind-the-meter energy.

PJM has asked FERC to approve an amendment to the generator’s interconnection service agreement to reduce the maximum output, and capacity, the generator offers into PJM. Exelon and AEP filed a joint protest arguing that co-located load benefits from the wider transmission grid and should be subject to relevant fees. They also argued there are unresolved questions about how a novel configuration could affect the grid. The Pennsylvania Public Utility Commission filed in support of the utilities’ protest (ER24-2172). (See Talen Energy Deal with Data Center Leads to Cost Shifting Debate at FERC.)

Pennsylvania Politicians, Nuclear Experts Support Reopening

Pennsylvania Gov. Josh Shapiro (D) gave the reopening his support in a statement provided through Constellation’s announcement, saying the state’s nuclear industry provides “safe, reliable, carbon-free electricity.”

“Under the careful watch of state and federal authorities, the Crane Clean Energy Center will safely utilize existing infrastructure to sustain and expand nuclear power in the commonwealth while creating thousands of energy jobs and strengthening Pennsylvania’s legacy as a national energy leader.”

That support was echoed by state Rep. Tom Mehaffie (R), U.S. Rep. Scott Perry (R) and Bart Shellenhamer, chair of the Board of Supervisors for Londonderry Township, where the CCEC is located.

“This unit was a good neighbor to Londonderry Township and our surrounding region for 45 years, with a workforce dedicated to contributing to area nonprofits and supporting the local economy,” Shellenhamer said. “The Crane Clean Energy Center will bring billions in new infrastructure investment and help support area businesses, schools and public services that improve quality of life for the whole region.”

Michael Goff, acting assistant secretary of the U.S. Department of Energy’s Office of Nuclear Energy, said the reopening is a milestone for Pennsylvania and the country. “Always-on, carbon-free nuclear energy plays an important role in the fight against climate change and meeting the country’s growing energy demands,” he said.

Constellation purchased TMI 1 in 1999 and operated the unit through 2019, when it opted to deactivate the generator rather than buy more fuel. The company asked the Pennsylvania General Assembly to pass subsidies for the plant’s continued operation years ahead of the retirement. While both chambers had bills on their dockets, their prospects were unclear. (See Pa. Lawmaker Contends TMI Rescue Unlikely.)

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SPP Pushes Back on Western Market Delays

The three independent SPP board members providing oversight of the RTO’s Markets+ development in the West have called for policy- and decision-makers to allow the process to “follow its natural course.” 

In an open letter released Sept. 19 and addressed to the Pacific Northwest congressional delegation, Western state regulators and the stakeholder-led Markets+ Participant Executive Committee (MPEC), the directors said delaying decisions to allow other market options to more fully develop will lead to uncertainty and prevent some interested participants from benefiting. 

“Extended delays could lead to market participant uncertainty about their market choices and, due to the need for adequate market footprint for Markets+ to succeed, deny interested parties the possibility of becoming beneficiaries of its unique design,” wrote Director Steve Wright, chair of the Interim Markets+ Independent Panel (IMIP), fellow SPP Director Elizabeth Moore and board Chair John Cupparo. 

“This independent panel understands some parties’ wishes to delay decisions while other market options more fully develop. Making Markets+ a reality requires continued funding, though, and funding requires that Western entities be allowed to negotiate and execute agreements on the defined timeline,” the IMIP said. Western market participants “were clear that anything other than accelerated market development” would undermine the day-ahead market’s viability and would “hence not be worth their time or money.” 

“It is our belief that the accelerated formation of the Markets+ option has already provided benefit to Western consumers,” the IMIP said. “There are many examples of competition improving market design and governance of several market alternatives that will be available to the West. 

“SPP and participants in Markets+ development anticipated short delays for steps like FERC tariff approval, but longer delays could disrupt healthy competition, threaten an as-soon-as-possible go-live date for Markets+ and ultimately deny the West a solution to many of the challenges it faces,” the directors added. 

The RTO has been involved with several service offerings in the Western Interconnection, some that predate the COVID-19 pandemic. It was approached in 2021 by Western entities interested in designing a market. Work with 37 stakeholders began the next year and has resulted in a governance structure that has produced a tariff and market protocols. 

SPP filed the proposed Markets+ tariff with FERC in March. However, the commission issued a deficiency letter in July asking the RTO to respond to 16 issues it found lacking in the design (ER24-1658). (See FERC Finds SPP Markets+ Tariff ‘Deficient’ in Several Areas.) 

As if to emphasize the need for speed, SPP filed a response to FERC’s deficiency letter Sept. 20, more than a week ahead of the due date. The RTO said the deficiency letter is part of a “routine process” it has been participating in for years. It said none of the commission’s questions indicate a “serious risk.” (See SPP Dispels Concerns over Markets+ Deficiency Letter.) 

The grid operator used 33 pages to answer the 16 questions, which dealt largely with transmission issues. It asked FERC for an order by Nov. 20. 

The IMIP said the deficiency letter was “consistent with our expectations” for the market’s approval and that SPP’s response to FERC “falls within its previously adopted schedule.” 

The panel’s comments come as efforts to build two day-ahead markets in the West continue to ratchet up. 

In recent months, the four U.S. senators from Washington and Oregon have urged the Bonneville Power Administration, one of the key Market+ players, to “act carefully and deliberately” before choosing a market. The agency has responded by reiterating its resistance to the CAISO Extended Day-Ahead Market’s (EDAM) California-centric governance model and expressed support for SPP’s market. BPA has delayed a decision until 2025, but it also plans to continue its funding in the second phase of the market’s development. (See ‘Leaning’ Evident in BPA Response to NW Senators and BPA to Fund Phase 2 of Markets+, Agency Exec Says.) 

CAISO in June kicked off a West-wide Governance Pathways Initiative designed to shift the ISO’s governance structure to an independent entity within the EDAM. Four workshops have highlighted the difficulty of designing a new Western “regional organization.” (See related story, Comments on Western RO Stakeholder Plan Show Complexity of Effort.) 

While potential participants consider which market to join, some have already made that choice. NV Energy announced its intention to join EDAM, and two Black Hills Energy subsidiaries said they will leave SPP’s Western Energy Imbalance Service for CAISO’s Western Energy Imbalance Market. Black Hills participated in Markets+’s first phase and said it will pursue markets that “provide additional value.” 

For its part, SPP has increased its public outreach, stressing its ability to build and manage markets and transact energy over seams. It has also created a spiffy website dedicated to Markets+. (See SPP’s Experience with Seams Could Help Markets+.) 

“Organizations spanning the Pacific Northwest, Desert Southwest and Mountain West regions will weigh many factors in making decisions about participating in a regional electricity market,” the IMIP said. “We trust they’ll each make the ultimate choice that’s best for their respective stakeholders.” 

The directors said SPP has approved a $150 million budget for the market’s remaining development, “a fraction of a percent of the $25 billion in transactions that occur annually in Western wholesale trading markets today.” They said Markets+’s governance and market design will offset upfront costs, with the RTO’s experience operating other markets suggesting that Markets+ services will have a lower lifecycle cost than other alternatives. 

According to SPP, BPA will be responsible for at least 17.4% of Phase 2 funding, second only to Powerex at 23.2%. Those percentages could increase should the Black Hills subsidiaries withdraw from further Markets+ development efforts. 

MSC, IMIP Strengthen Relationship

The Markets+ State Committee, comprising Western regulators and one of the recipients of the IMIP’s letter, has endorsed a resolution that provides greater cooperation between the commissioners and the IMIP. 

The two bodies have agreed to participate in each other’s meetings with allocated time on their corresponding agendas. They also agreed to host joint in-person or virtual meetings to address any issues during the market’s development and operation. 

Director Wright has indicated to the MSC that the IMIP will support the resolution. 

The MSC meets monthly, while the IMIP generally meets during MPEC meetings.