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November 1, 2024

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NIA: Cost, Risk Sharing Needed to Grow Advanced Nuclear Pipeline

Speaking in Waynesboro, Ga., on May 31, Energy Secretary Jennifer Granholm celebrated the completion of Units 3 and 4 at the Vogtle nuclear power plant with a call for the United States to “draw up some more battle plans for more reactors” and triple its nuclear capacity by 2050. 

But according to a new report from the Nuclear Innovation Alliance (NIA), significant barriers remain for moving beyond first-of-a-kind (FOAK) projects like Vogtle to the nearly 200 GW of nth-of-a-kind (NOAK) advanced nuclear projects the U.S. will need to reach that 2050 goal. 

The first new reactors built in the U.S. since 2016, Vogtle’s two units have come online seven years late and $17 billion over budget, leaving subsequent projects surrounded by perceptions of risk, whether real or not, and under pressure to show they can execute on budget and on time. While the Department of Energy is funding a handful of advanced nuclear demonstration projects, “material financial commitments (i.e., signed contracts and spending on project development) to additional projects have been slow in coming,” the report says. 

These projects are generally smaller and use different, more advanced and efficient technologies than the existing 94 reactors at the 54 power plants that make up the U.S. nuclear fleet, which provides nearly 20% of the nation’s power. For example, X-energy, one of the developers receiving federal funds from DOE, is working with Dow to install four 80-MW small modular reactors (SMRs) at the company’s Seadrift, Texas, plant, where it manufactures a range of plastics and other products.  

What’s needed for a healthy pipeline of NOAKs will be a clear set of best practices, accelerated permitting, supply chain buildout and innovative approaches to cost- and risk-sharing for project developers and offtakers, the report says. 

“Faster growth and clean, firm energy is key to the growth objectives of large offtakers” and may make them more willing to accept more development risk, said Stephen Greene, a senior fellow at NIA and author of the report. 

“To accelerate commitments to advanced nuclear, energy offtakers may need to accept a greater portion of the project risks than they do through traditional offtake agreements, such as providing part of the capital commitment to address anticipated costs,” Greene said, speaking at a launch webinar for the report June 3. 

Offtakers sharing costs and risks could receive “compensation later, such as an adjustment to offtake costs or participation in project returns,” the report says. “The most impactful private-sector action would be for offtakers to make capital commitments to provide a backstop of project completion costs,” and the Department of Energy also might chip in to cover at least part of any cost overruns, the report says.  

Kreshka Young, Dow’s North America business director for energy and climate, said her company is financing the upfront development of the X-energy SMRs like any “project in our normal course of our capital planning, and it will go through our normal capital approval process.” 

Dow eventually could look for partners, as offtakers or owners, Young said, but she expects the company’s ownership and business models likely will evolve over time. “But again, at this stage, with the risk levels where they are, the perceptions of risk especially where they are, Dow is today the primary owner of the project.”  

“The real emphasis of the report is how to make projects more attractive to capital markets,” Greene said. “Additional financing either from private-sector participants or from new federal capabilities is a kind of assurance that I think capital markets are going to need, especially for initial projects to address … both the perceived and the real risk of cost overruns.” 

Other topline findings and recommendations in the report include: 

    • Due to the higher costs of FOAKs, the only way these projects pencil out is if they are developed as part of “an intended multi-project deployment plan (through which the cost of early projects can be shared among the projects).” Costs also can be shared via an “order book” of a number of projects of the same design. 
    • In the absence of ongoing, widespread nuclear construction, the U.S. must rebuild its supply chain for new plants, in particular, for the high-assay low-enriched uranium (HALEU) used in advanced and small modular reactors. 
    • Reforms are needed to streamline and speed permitting of new projects at the Nuclear Regulatory Commission (NRC). In a separate overview of potential NRC reforms, NIA noted licensing for advanced and small modular reactors “is challenging because the current licensing pathways have been tailored to conventional, large light water reactors.” 

So far, the NRC has certified the design for only one SMR, the NuScale reactor, and authorized construction of a test advanced reactor developed by Kairos Power, according to the report.  

From FOAKs to NOAKs

Throughout its construction, Vogtle’s repeated delays and cost overruns made the project a point of controversy, particularly for Georgia Power customers who will pick up $7.56 billion of the price tag for finishing the two units. A report in The Atlanta Journal-Constitution estimated that paying off that extra cost could increase utility bills by 10%.   

But with the two units completed and online, Granholm and others at DOE have hailed Vogtle as a major success.  

The expanded plant will be producing roughly 35 million MWh of power per year for the next 80 years, “so that is a multigenerational asset,” said Julie Kozeracki, director of strategy at DOE’s Loan Programs Office, which provided about $12 billion in loans for Vogtle.  

Kozeracki stressed that the lessons learned from the construction of Unit 3 resulted in lower costs and shorter timelines for Unit 4.  

“Many of the challenges faced at Vogtle were true first-of-a-kind issues,” she said. “So, for example, construction began without a complete design, without a mature supply chain, without a trained workforce. But in the course of building Vogtle, we’ve now solved these issues. … 

“Unit 4 was roughly 30% cheaper and more efficient than Unit 3,” she said, and the time needed for testing plant systems went from 94 days at Unit 3 to 42 days at Unit 4.  

“So the worst thing we could do would be to stop after two units,” Kozeracki said. “Vogtle 3 and 4 are a downpayment for everyone to capitalize on.” 

Larger reactors, like the Westinghouse API 1000 reactors used at Vogtle, also can offer economies of scale, which may be particularly attractive to industrial and data center customers looking for large amounts of firm, clean power. 

Many existing nuclear sites have room for additional reactors, she said. Vogtle is the only site in the U.S. with four reactors. “Multi-unit nuclear sites are 30% cheaper to operate than single-unit sites, but we have currently 19 single-unit sites. We have 31 sites with two reactors, three with three reactors … so we have a lot of room to grow.” 

Still, going forward will require a rebalancing of risks, especially for utilities, Kozeracki and Greene said.  

Regulated utilities often cannot recover the high upfront costs of siting, permitting and construction of a new nuclear plant until it goes into operation and “the electricity rates they can charge to customers are not structured to incorporate that degree of risk,” the report notes. 

“Tech companies like Google, Microsoft and Amazon have so much to gain with [nuclear] assets coming online,” Kozeracki said. “And they are growth companies that are in a position to take risk, and they have the cash on hand to take some of that risk. So, I think in order to execute on an effective energy transition, utilities are going to have to learn to become more like growth companies.” 

“The objective is to get over the hump of concerns about risk and get to a point where we’re building these projects more in the regular course,” Greene said. “Then the companies that are building them will have the ability to take those risks.” 

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Senate Energy Committee Advances Biden’s FERC Nominees

The Senate Energy and Natural Resources Committee advanced all three of President Joe Biden’s nominees to FERC with broad margins in a business meeting held June 3. 

“Two of the five seats on the commission are already vacant, and a third will expire at the end of the month,” committee Chair Joe Manchin (I-W.Va.) said, referring to Commissioner Allison Clements (D). “Confirmation of these three nominations will ensure that the commission has a full complement of five commissioners continuing important work. I believe all three are well qualified and intend to vote for all three.” 

Manchin, while still caucusing with the Democrats, recently left the Democratic Party to become an independent. 

Clements’ term expires June 30; if she leaves before a replacement is approved by a floor vote in the Senate and sworn in, FERC could lack a quorum. Commissioners can stay on past their term’s expiration if a replacement has not been confirmed until Congress adjourns at the end of the year, but Clements has not said exactly when she plans to leave. 

“By one estimate, the commission regulates activities that account for 7% of our nation’s economy,” committee Ranking Member John Barrasso (R-Wyo.) said. “And for that reason, we must fulfill our responsibility to maintain a quorum on the commission.” 

FERC was left without a quorum at the beginning of President Donald Trump’s term for seven months, meaning it could not vote out any orders, and Barrasso said he does not want that situation repeated. He also supported all three nominees. 

Several committee members voted against the nominees, but none were in doubt, with both David Rosner and Lindsay See advancing by a 16-3 vote and Judy Chang by 15-4. 

FERC must have at least two members who are not in the president’s party; the current makeup is 2-1, with Commissioner Mark Christie the lone Republican. 

Rosner is a FERC staffer who was detailed to the ENR Committee and generated opposition from the left, with Sen. Bernie Sanders (I-Vt.) voting against him, despite being backed by the Democrats. 

Chang, another Democratic pick, also faced some opposition from Republicans. She is a longtime industry expert who served as undersecretary of energy and climate solutions in former Massachusetts Gov. Charlie Baker’s (R) Executive Office of Energy and Environmental Affairs. 

The Republicans put forward See, who is the solicitor general of West Virginia, having argued that state’s and others’ cases against the Obama EPA’s Clean Power Plan, which led to the “major questions” doctrine. 

Sen. Josh Hawley (R-Mo.) voted against all three nominees as a protest against the Grain Belt Express transmission line being developed by Invenergy, which could be in a National Interest Electric Transmission Corridor designated by the Department of Energy — giving FERC backstop siting authority over its path through his state. (See On the Road to NIETCs, DOE Issues Preliminary List of 10 Tx Corridors.) 

“FERC has the ability to countermand state authorities, essentially to bypass the state regulatory process and designate the land — including potentially taking it,” Hawley said. 

At their confirmation hearing, Hawley had asked all three nominees to guarantee they would take into account the interests of local farmers and residents and not “rubber stamp” DOE’s corridors. 

“I was particularly disappointed to [hear] the answer of Ms. See, who would not answer my question,” Hawley said. “And I just want to say as a Republican, I’m not going to vote for other Republican nominees who will not stand up to the power grab that is happening all across the country, and of which my state in particular has been a victim.” 

In response, Barrasso read off a written answer See had given to that question that will sound familiar to anyone who follows FERC, where its members take pains to avoid stating their opinions on specific cases that come before them to avoid having parties file recusal motions against them. 

Hawley “accurately asked” See to exercise caution when approving transmission lines, and she responded she would follow the law, Barrasso said. 

“She went on to say, ‘Sensitivity to how federal actions affect state and local communities is essential when making policy decisions,’” Barrasso said. “And she added, ‘I would consider a proposal’s consequences for local landowners important to the public interest analysis.’” 

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ACEG Report Lays out the Case for Proactive Planning in PJM

PJM should adopt a more proactive transmission planning process to deal with the changing resource mix and growing demand on its system in the coming 15 years, according to a report released June 4 by Americans for a Clean Energy Grid (ACEG). 

“Transmission Planning for PJM’s Future Load and Generation” was written by Grid Strategies and David Gardiner and Associates. 

“This report takes a deep dive into some of the inputs that PJM needs to take a closer look at in conducting more holistic scenario planning,” ACEG Executive Director Christina Hayes said in an interview June 3. “PJM has been making progress in evolving its transmission planning in recent months, and we’re excited about those efforts. We know that more will be required in implementing Order No. 1920, and we believe this report provides a road map to doing so.” 

Skeptics of proactive planning argue that transmission plans are full of uncertainty and speculation, but ignoring the massive changes impacting the energy industry and continuing to plan reactively will not address those concerns, the report says. Uncertainty is best addressed by incorporating the best data on the future resource mix and running different scenarios to determine the optimum set of solutions, as Order 1920 requires. 

The report forecasts demand will be higher than the forecast PJM released early this year by about 8% in its “Expected” scenario and 18% for a high-growth scenario. Even those scenarios might be conservative given the continual announcements of new manufacturing facilities and data centers. 

“We find PJM will need an additional 623 TWh of annual energy generation by 2040 to meet this resource gap under our Expected scenario — equivalent to 76% of PJM’s 2023 generation,” the report says. “Under the High scenario, PJM faces a larger resource gap in 2040 and will need to nearly double current energy generation by adding 798 TWh. The increase is driven by higher electrification estimates leading to larger load growth and higher amounts of generation retirements due to shorter plant lifespan assumptions.” 

The biggest difference between PJM’s load forecast and the two scenarios in the report is the latter assume higher demand from electrification and higher generation retirements. The electrification estimates in the report are based on projections from the National Renewable Energy Laboratory, while the report says PJM’s Independent Market Monitor has estimated higher retirements than the RTO itself. 

“I think the one thing we can be certain of with every single demand forecast we have seen recently is that they will all be wrong. Right?” Hayes said. “Nobody is going to forecast the future with 100% certainty.” 

But one thing that is certain is that several factors are leading to higher demand, and it makes sense to ensure transmission is ready to meet that on time, she added. 

“We do need to be thoughtful and measured in how we plan for it,” Hayes said. “But in doing so, we need to take the long view because if we wait until it’s upon us, we’re either going to have outages, or resources that we want to keep in the United States are going to end up being located outside the United States, which is a national security problem. Or we’re going to develop the grid in a more expensive way.” 

The Regional Transmission Expansion Process in place now includes a short-term reliability process looking out five years and another reliability planning process that looks out 15 years, both using base cases based on power flow models that includes capacity cleared in the market and only announced retirements. Retirements require only 90 days’ advance notice. 

Better anticipating retirements can help significantly, as seen recently with the Brandon Shores coal plant in Baltimore. PJM found the grid would need $785 million in transmission upgrades for it to retire reliably; those will take until 2028 to complete, 3.5 years from the plant’s desired retirement, the report says. A reliability-must-run deal for the plant might cost consumers an additional $250 million a year, which could have been avoided or lowered with proactive planning. 

“In Order 1920, FERC did a good job of identifying the various factors, looking at fuel costs and market impacts and likely resource retirements, and doing a deep dive on what the generation resource mix is likely to be in five to 10 to 20 years, and rolling those factors into multivalue, holistic planning,” Hayes said. 

Another issue in PJM is a growing share of renewables as state and federal policies, lower costs and consumer demand push more and more onto the grid. While some states have policies driving that transition, others are not interested in it at all. Hayes argued that holistically planning the entire grid would even benefit the latter. 

“There’s a lot of flexibility in FERC’s rule to allow states with additional goals to assume part of the costs and ensure that states that also partake in the economic/reliability benefits contribute as well,” Hayes said. “It’s the idea of a region being seen as a region rather than a loose collection of states; it is just more cost effective for the region to plan transmission together and then allocate the costs.” 

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Pathways Backers Advance WEIM/EDAM Governance Proposal

Backers of the West-Wide Governance Pathways Initiative will move quickly on a proposal to alter the governance of CAISO’s Western Energy Imbalance Market (WEIM) and Extended Day-Ahead Market (EDAM) after voting to approve the plan May 31. 

The initiative’s Launch Committee unanimously endorsed step 1 of the “stepwise” proposal the group issued in April. The proposal calls for CAISO to revise the WEIM charter to elevate the oversight position of the market’s Governing Body over WEIM/EDAM matters to “primary” authority, rather than the “joint” authority it currently shares with the ISO’s Board of Governors. (See Western RTO Group Floats Independence Plan for EDAM, WEIM.) 

“We’re thrilled to be able to move forward with step 1 and start to engage with … CAISO in a different way,” committee Co-Chair Kathleen Staks, executive director of Western Freedom, said after the vote. 

The Launch Committee now will submit step 1 of the proposal to CAISO Board Chair Jan Schori and WEIM Governing Body Chair Andrew Campbell to kick off a stakeholder process at the ISO this month. 

Pathways backers anticipate CAISO will hold an initial public stakeholder call — with the Launch Committee presenting — in mid-June. That would be followed by a three-week comment period, a committee response period and a public meeting for a joint decision by the board and Governing Body in late July or early August. 

“Let me start by really thanking the Launch Committee for taking up the concept that the regulators had put forward last summer, fleshing it out and producing such an astonishing work product,” Oregon Public Utility Commissioner Letha Tawney said. 

Tawney was among the group of Western state energy officials who launched the Pathways Initiative last July to increase the potential for creating a single day-ahead electricity market for the region that expressly includes California and leans on the technical capabilities of CAISO. 

Arizona Corporation Commissioner Kevin Thompson, another initial supporter, commended the Launch Committee’s progress despite conflicts that arose at a previous private meeting of the committee in Phoenix. 

“There was some tension there in the room a little bit here and there,” Thompson said, “but to see where the stakeholders have moved the conversation to get us toward independent governance, and giving prior primary authority to the EIM as the governing board, is a step in the right direction that gets us away from the joint authority and starts moving us really closer towards independent governance.” 

The Pathways Initiative’s final proposal included a handful of changes from the original version, including expanding the responsibility of the Governing Body to respect both state and “local” policies in its decisions and highlighting the existing right of the body to institute a governance review process with the ISO board in the event of a mass withdrawal of EDAM entities from the market. 

The proposal also clarified the workings of the dual filing — or “jump ball” — process that would occur in the event the CAISO board disagrees with a tariff filing approved by the Governing Body and decides to submit a parallel filing with FERC.

Next Steps and Phases

The Launch Committee also voted to continue developing step 2 of the proposal, which will seek to transfer governance of the WEIM — and its associated future EDAM — to an independent “regional organization” (RO) that the Pathways group expects to establish next year. 

Step 2 poses greater challenges than the first step because it requires convincing the California legislature to pass a bill authorizing CAISO to transfer its authority over a large part of its market to the RO. While the Launch Committee itself will not be participating in those efforts, many of its members will be in their capacities as individual organizations with interests in the change. 

Launch Committee member Spencer Gray, executive director of the Northwest & Intermountain Power Producers Coalition, said step 2 also must address the “core tension” between the two options being considered for the structure of the RO, which relates to “the degree of institutional independence of the regional organization and the financial liability and responsibility that comes along with institutional independence.” 

Gray pointed to the series of “work streams” the Launch Committee has identified for its Phase II work plan, which focuses largely on issues embedded in step 2. The committee has appointed two leads to deal with each stream, which include:  

    • exploring the stakeholder process for the RO, including examining sector-based approaches and how to frame policies; 
    • dealing with CAISO-related issues; 
    • analyzing the existing CAISO tariff, which could entail identifying the functions of a balancing authority under a new market arrangement; 
    • addressing public interest issues, including considering the evolution of the WEIM’s Body of State Regulators; and 
    • addressing RO formation and governance, which would range from incorporation to board nomination to securing funding sources. 

Committee member Lisa Tormoen Hickey, a senior regulatory attorney with Interwest Energy Alliance, told meeting participants the Pathways Initiative will need to secure about $450,000 in funding for its Phase II activities through the end of the year. Those activities will include additional legal review for RO options, proposing an RO stakeholder process, making a final step 2 recommendation, and gathering and publishing stakeholder feedback on the recommendation. 

She said the committee estimates an additional $636,000 will be needed to complete Phase III activities, which will include establishing an RO “formation” committee, developing tariff amendments and bylaws, retaining a placement firm for selecting a board and management team, and monitoring California legislative and CAISO actions. 

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SERC Reports Sufficient Resources in Summer Assessment

The SERC Reliability region is positioned to meet peak demand under normal conditions this summer, although extreme heat and a busy hurricane season could cause concerns for grid operators, the organization said in its 2024 Summer Reliability Assessment released May 30.

SERC produces its summer assessment each year as a complement to NERC’s annual SRA, which the ERO released last month. (See NERC Summer Assessment Sees Some Risk in Extreme Heat Waves.) The report focuses on four key areas relevant to SERC and its subregions — demand, capacity resource adequacy, reserve margins and transmission adequacy — but “does not predict events or weather conditions” during the summer months.

In addition, SERC’s report “focuses on normal summer conditions,” or conditions with a 50% likelihood of coming to pass, while NERC’s assessment also considers an extreme “90/10” scenario (indicating a situation the ERO expects has only a 10% chance of happening). SERC’s assessment does include its summer transmission reliability study, which examines both 50/50 and 90/10 load projections.

In its assessment, the regional entity observed that its “footprint is susceptible to extreme heat, droughts, floods, tornadoes and hurricanes during the summer months.” The region has experienced an average of six heat waves per year over the past decade, compared to two per year in the 1960s. According to the National Oceanic and Atmospheric Administration’s weather forecast for June through August, the 16 states covered by SERC have a 43 to 50% chance of experiencing above-normal temperatures this summer.

NOAA also has predicted an above-normal 2024 Atlantic hurricane season, with 17 to 25 total named storms with winds of at least 39 mph, including up to 13 hurricanes (with winds of at least 74 mph). By comparison, 20 named storms occurred in the 2023 hurricane season, including seven hurricanes. In an average hurricane season, 14 named storms develop, and seven of these become hurricanes. SERC’s report noted the “risk of physical damage and disruption” to power facilities from hurricanes and other extreme weather events.

Along with these risks, the report also highlighted above-normal precipitation predicted across much of SERC’s footprint this summer. The RE warned that heavy rainfall can result in rapid vegetation growth, potentially interfering with transmission lines.

Despite these challenges, SERC emphasized that all its subregions have reported sufficient reserves to meet demand under normal circumstances.

Across the region, total internal peak demand — defined as the projected sum of metered generator outputs and metered line flows into the system, minus metered line flows out of the system — is projected at 262 GW. Total net internal demand — the total internal demand less controllable and dispatchable demand response — is predicted to be 252 GW. By contrast, last year’s actual system peak was 262 GW, against a forecast of 249 GW.

To meet this demand, SERC’s regionwide anticipated resources, including power transfers, stand at 328 GW, with all seven subregions also reporting sufficient internal resources to meet their expected loads. The smallest margin between resources and demand is found in MISO-Central — comprising parts of Illinois, Iowa, Kentucky and Missouri — where 20 GW of resources are available to meet 17 GW of net internal demand.

The region’s generation mix is varied, but SERC expects natural gas to account for just under 50% of generation capacity this summer with 161.4 GW. Coal is next with 64.2 GW at 19.9% of capacity, followed by nuclear energy — including the recently completed third and fourth units at Plant Vogtle in Georgia — at 42.7 GW and 13.2%. (See Southern Credits Strong Southeast Economy for Earnings Growth.)

The RE said fuel availability for gas and coal plants within the region constitutes a potential reliability risk for utilities in the region. SERC also noted severe weather poses a moderate risk of transmission impacts, though it also said its transmission reliability study projected only “localized thermal overloads and no voltage constraints in the SERC region” for both the 50/50 and 90/10 forecasts.

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Monitor Alleges EE Resources Ineligible to Participate in PJM Capacity Market

The Independent Market Monitor filed a complaint May 31 asking FERC to reject all energy efficiency (EE) offers into PJM’s capacity market, alleging that none of them meet the Base Residual Auction (BRA) participation requirements (EL24-113). 

The complaint argues that EE programs that seek to help consumers buy more efficient appliances by entering into agreements with distributors and retailers — known as mid- and upstream programs — are not obtaining consumer-level data or entering into contracts with individual end users. It took aim at the measurement and verification reports of a dozen EE providers, stating they had not included information to demonstrate that installations of more efficient products occurred in a manner that would allow PJM and the Monitor to conduct audits. 

“The reports fail to provide adequate evidence to demonstrate that the included EE measures meet the requirements to be approved and to receive payment. It is unjust and unreasonable to require PJM customers to pay a total of $128 million in the BRA alone for EE MW that have not been demonstrated to meet the requirements to be paid,” the Monitor wrote. 

The complaint asks the commission to either bar the EE providers from receiving capacity market revenues in the 2024/25 delivery year or order PJM and the Monitor to open an investigation to determine eligibility. 

Following the filing, PJM emailed EE market participants that it plans to delay signing off on all post-installation measurement and verification (PIMV) reports supporting EE offers until after the complaint is resolved, which also holds up capacity market payments to EE resources. 

“Delay of PJM action on the PIMV reports provides FERC the opportunity to consider the merits of the IMM complaint,” the email said. “As a result, no payments, deficiency charges and nonperformance charges associated with energy efficiency resources for the 24/25 delivery year will be invoiced to energy efficiency providers until FERC has ruled on the merits of the IMM complaint and PJM approves or rejects the PIMV reports. All replacement transactions associated with energy efficiency providers will be terminated and may be reentered depending on the outcome of this matter at FERC.” 

PJM spokesperson Jeff Shields said the delay affects all EE offers, including components not related to midstream and upstream programs. 

A representative of one of the entities named in the Monitor’s complaint, who spoke on the condition of anonymity, said it’s alarming that PJM opted to withhold capacity market revenues with less than a day’s notice before the start of the delivery year because of a complaint still pending before the commission. 

“From our vantage point, it is hard to see this as anything other than the IMM unilaterally suspending energy efficiency and, for reasons kind of unknown, PJM going along with that and supporting that,” they said. 

They said it fits squarely in the Monitor’s role to scrutinize a particular market participant; however, the complaint appears to target an entire class of resources and enact a policy change through a FERC complaint. They noted that there’s an ongoing stakeholder process focused on the rules around EE measurement and verification that the complaint seeks to sidestep. (See “Stakeholders Regroup on Energy Efficiency Rules After MRC Rejection of Proposals,” PJM MIC Briefs: May 1, 2024.) 

“It’s entirely reasonable and within the IMM’s discretion to take as close a look as he wants at any capacity resources … but to approach it in this fashion, especially in the midst of an ongoing stakeholder dialogue on how to make the rules better — it seems entirely inappropriate,” they said. 

Monitor Joseph Bowring told RTO Insider the complaint addresses a longstanding issue with EE participation in PJM’s capacity market and is meant to ensure consumers are not overpaying for EE under the current rules. He said the complaint is unrelated to stakeholder discussions looking at how the capacity contribution of EE resources is measured and verified. On the approach PJM and stakeholders should take in that forum, Bowring said he believes the tariff does not support the resource class being a part of the capacity market.  

“EE does not belong in the capacity construct at all,” he said. 

Many of the Monitor’s arguments in the complaint echoed those made by PJM as it drafted a proposal to tighten the measurement and verification requirements for EE. During the May 1 Market Implementation Committee meeting, PJM’s Pete Langbein argued it has not been demonstrated that capacity market revenues flowing to EE participants is incentivizing consumers to buy more efficient devices they otherwise would not have. 

“They shouldn’t be able to claim things that are naturally going to occur. … If I’m making a decision to purchase a high-efficiency air conditioner, an EE provider shouldn’t be able to claim that unless they can prove” they incentivized the purchasing of that unit over a less efficient product,” Langbein said in May. 

Stakeholders representing EE providers pushed back, stating that the resource class efficiently provides a guaranteed reduction in consumption over PJM’s load forecast. 

The complaint argues that the party seeking to enter energy savings into the capacity market either must directly control the load reduction or hold a contract with the consumer granting rights to the capacity associated with the energy savings. Without contracts between EE providers and the consumers buying efficient devices, the Monitor also raised the possibility that multiple EE market participants could attempt to include the same load reduction in their capacity offers. 

“There is no evidence that Indicated Energy Efficiency Sellers through midstream and upstream programs provided legally required consideration to any end users for the rights to their projects or products. The Indicated Energy Efficiency Sellers therefore are not the owners of the requisite contractual rights required by the PJM tariff to be eligible to receive revenues from the PJM capacity market,” the Monitor said. 

The Monitor also argued that EE programs that contract with retailers and distributors may not lead to lower costs for consumers buying more efficient devices and that no change in consumer behavior has been demonstrated. 

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$1B Committed so far to Floating Offshore Wind Shot

The U.S. Department of Energy has issued an update on federal efforts to speed up development and deployment of floating wind turbines. 

The DOE progress and priorities report lays out more than 50 milestones reached since the Floating Offshore Wind Shot was launched in September 2022. 

The initiative is part of the Biden administration’s Energy Earthshot program. The departments of Commerce, Energy, Interior and Transportation are collaborating in the hopes of reducing the cost of floating turbines by 70% and installing 15 GW of total floating wind capacity by 2035. 

Floating wind turbine technology is more expensive and complex than the widely used fixed-bottom turbine designs. Also, the first large-scale floating wind projects are in planning stages in other countries. There is no operational history at scale in U.S. waters, nor is there the specialized infrastructure to build it.  

Most of the 50-plus milestones listed in the report are research and/or funding initiatives intended to change this.  

With large swaths of U.S. coastal waters too deep to affix turbine foundations to the seabed, the Floating Offshore Wind Shot is designed to allow fuller use of this emissions-free power source. DOE reports that more than $950 million has been devoted to the initiative in the past 20 months. 

Near-term priorities summarized in the report include: 

    • cost reduction — by researching resource assessment, design, modeling, manufacturing, operations and maintenance; 
    • supply chain development — by identifying gaps and solutions to inform decision-making, and mobilizing investment through federal programs and lease bidding credits; 
    • expanding just and sustainable development — by increasing the involvement of tribal leaders, fishers and communities while increasing workforce development; 
    • transmission development — with in-depth offshore wind transmission studies, improved planning tools and advancing critical components; and 
    • developing co-generation opportunities — with analyses of hydrogen generation and energy storage options, and effective designs and demonstrations. 

Featured accomplishments include: 

    • DOE announced $38 million for six projects to develop floating offshore wind designs through the Aerodynamic Turbines Higher and Afloat with Nautical Technologies and Integrated Servo-control (ATLANTIS) Program. 
    • DOE launched the $6.9 million Floating Offshore Wind ReadINess (FLOWIN) prize to develop the domestic supply chain. 
    • DOE provided more than $18 million to support research and development of HVDC voltage source converter systems and standards, controls and curricula. 
    • DOT awarded $427 million to establish the first West Coast offshore wind terminal, through the Humboldt Bay Offshore Wind Project. 
    • DOE funded research to model and analyze the levelized cost of hydrogen for de-centralized offshore-wind-to-hydrogen systems. 
    • DOI held the first floating offshore wind lease auction off the coast of California in 2022 and designated wind energy area lease auctions off the Maine and Oregon coasts in 2024. 
    • DOI and DOC expanded the Sea Grant Offshore Wind Liaison Program to the West Coast to ensure continued engagement with the communities there. 
    • DOE completed a study on the impacts of developing a floating offshore port network on the West Coast that will inform future collaboration efforts. 
    • DOE convened local stakeholders to discuss key transmission needs on the West Coast. 
    • DOE-funded projects along the Pacific Coast began collecting data to support monitoring the presence of birds, bats and marine mammals in areas where wind turbines may be sited, and to develop autonomous monitoring for marine organisms and the seabed. 

DOE concluded its report by saying much more is needed if floating wind goals are to be met and said continued collaboration by stakeholders is important. It said regular summits are planned, along with periodic updates as needed to the summary report. 

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ISO-NE Expects to Have Sufficient Resources for the Summer

ISO-NE expects to have adequate resources to meet its projected 24,553-MW peak load this summer, the RTO announced as part of its summer outlook, released June 3.  

The ultimate outcome will be highly dependent on weather, ISO-NE said, estimating there is a 10% chance the peak load exceeds 26,383 MW. The RTO anticipates having about 30,000 MW of capacity available.  

“While the ISO expects the region to have adequate supplies of electricity this summer, abnormal conditions could force system operators to take action to maintain system reliability,” ISO-NE wrote in a press release. “Climate change has caused weather to become more volatile and less predictable, increasing the potential for system operators to resort to these actions.” 

Weather is the region’s “largest driver of energy use,” ISO-NE noted, adding that hot and humid conditions coupled with unexpected generator outages would be especially difficult to manage. 

ISO-NE’s demand forecasts are based on weather data from the prior 30 years, but they do not consider climate forecasts or more granular climate trends.  

Data from the National Oceanic and Atmospheric Administration indicate average and maximum summer temperatures have been trending up in the Northeast over the past 30 years. Average temperatures for summer months have increased by about 0.4 degrees per decade since 1993, while maximum temperatures have increased by about 0.3 degrees per decade. 

Average summer temperatures in the Northeast, 1993-2023 | NOAA

“Just a 1-degree change in temperature can impact the load and demand in New England significantly — by half a gigawatt or more,” Mike Fontaine, supervisor of operations forecasting for ISO-NE, said in a video released in May. 

ISO-NE has indicated it plans to incorporate climate modeling into demand projections starting in 2025. (See ISO-NE Decreases Its 10-year Peak Load Forecast.) 

The RTO also highlighted the role behind-the-meter (BTM) solar has played in reducing peak demand, noting that it is responsible for approximately a 1,000-MW reduction in the summer peak. The roughly 7,000 MW of BTM solar capacity in the region has pushed the timing of the peak from midafternoon to early evening, ISO-NE added.  

The forecast also includes just over 2,000 MW of energy efficiency, ISO-NE said, while dispatchable active demand response is counted as a supply-side capacity resource.  

This summer will be the first following the retirement of the Mystic Generating Station, which was once New England’s largest fossil power plant. ISO-NE said it is “not projecting any capacity issues during the summer based on this retirement.”

The 24,553-MW peak projection would be an increase over the 2023 peak load of 24,043 MW, which occurred Sept. 7.  

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FERC Approves SPP’s Cost-allocation Revisions

FERC on May 31 accepted SPP tariff revisions that will allow certain transmission facilities’ costs to be entirely allocated on a regional postage-stamp and cost-by-cost basis, effective June 1, 2024 (ER24-1583). 

The commission found SPP’s capacity, flow and benefit analyses of the Sunflower Electric Power transmission facilities at the center of the proceeding provided benefits to the region as a whole. It said the grid operator demonstrated that its proposal will allocate the facilities’ costs in a manner “at least roughly commensurate with estimated benefits, consistent with the cost-causation principle.”  

SPP’s analysis demonstrated that Sunflower’s “wind-rich” transmission zone had generation capacity that greatly exceeded its load. Flow analyses demonstrate that more than 70% of the power flows over the utility’s byway facilities are from generation unaffiliated with the zone’s load. 

“We find that SPP’s capacity and flow analyses demonstrate that electricity generated from resources inside the Sunflower zone is being used by load outside of the Sunflower zone and that the Sunflower byway facilities are being used to deliver this electricity,” FERC said.  

“The entire SPP region benefits economically,” from Sunflower’s facilities, the commission said. “We find that the proposed 100% regional, postage-stamp cost allocation will allocate the remaining costs of the transmission facilities in a manner that is at least roughly commensurate with benefits received and, therefore, is just and reasonable.” 

SPP allocates one-third of the cost of byway projects — on lines rated at 100 to 300 kV — to the RTO’s full footprint, with customers in the transmission pricing zone where the project is built being allocated the rest. “Highway” projects — those larger than 300 kV — are allocated RTO-wide. 

FERC rejected protests that the proposed allocation for the byway facilities’ remaining costs is inappropriate because those facilities were built to address zonal reliability issues or forecast load growth that never was realized, rather than regional needs. It said other arguments were that SPP’s analysis was “insufficiently granular” to determine whether the entire region would receive benefits at least roughly commensurate with costs. 

“We emphasize that cost-allocation precedent does not require such ‘exacting precision’ in the commission’s cost-allocation decisions,” FERC said. “We find that a granular zone-by-zone benefits analysis is not necessary to find that SPP’s proposal to allocate the remaining costs of the Sunflower byway facilities on a 100% regional, postage-stamp basis is just and reasonable.” 

The commission rejected SPP’s initial 2021 proposal to establish a process allowing entities to petition the RTO’s Board of Directors for exceptions from the highway-byway cost-allocation methodology. FERC accepted a revised proposal in 2022 in a 3-2 decision, only to reverse course in 2023 after several rehearing requests. (See FERC Reverse Course on SPP Byway Cost Plan.) 

Sunflower has advocated for relief from the highway/byway process since 2017. Transmission owners largely have opposed the proposal as it wound its way through the stakeholder process, saying it would shift byway cost responsibility from wind-rich areas to others. 

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Extreme Weather Workshop Hit by Extreme Weather

DALLAS — Attendees at a recent NERC and EPRI workshop on a draft standard addressing extreme weather’s effects on transmission planning now have a more personal understanding of those impacts. 

Violent thunderstorms ravaged North Texas on May 28, the day before the workshop began, knocking out power to about 1 million Texans and leaving destruction in its wake. Several speakers and attendees were unable to fly into the Dallas area’s two airports after numerous flights were canceled. Those who did arrive found restaurants and entertainment options closed, thanks to the outages. 

It didn’t get any better as the workshop adjourned May 30: Another line of storms rolled through the DFW Metroplex, forcing the cancellation or delay of flights out of the airports. 

“It’s very ominous to begin a workshop focused on extreme weather with extreme weather,” Eknath Vittal, a senior principal technical leader in EPRI’s transmission operations and planning department and the workshop’s moderator, said May 29 in opening the workshop. 

Vittal guided the diverse group of climate experts from national labs, research and development organizations, and other entities through a discussion of extreme weather and its implications for FERC Order 896 and NERC’s upcoming TPL-008 draft standard regarding extreme weather’s effect on transmission planning.  

The commission’s 2023 order directed NERC to update TPL-001-5.1 (transmission system planning performance requirements) or draft a new standard by December 2024 that addresses a lack of long-term planning requirement for extreme weather events. (See FERC Approves More Extreme Weather Rules.) 

FERC’s requirements included: 

    • developing benchmark planning cases based on major prior extreme weather events and/or meteorological projections. 
    • planning for extreme weather events using steady state and transient stability analyses expanded to cover a range of extreme weather scenarios, including the expected resource mix’s availability during extreme conditions. 
    • using corrective action plans that mitigate any instances where performance requirements are not met. 

The NERC drafting team’s initial work product “failed miserably,” as PJM team member Michael Herman said, on its first ballot. The team is reviewing the comments it received before determining next steps, he said. 

“We’ve been reading the comments that everyone has submitted about this,” Herman told his audience. “We’re taking that information and we’re working internally to process that information, and to determine what changes we need to make to the standard in order to address the concerns that all of you brought up.” 

Herman says the drafting team will work to improve the standard’s language to better consider wide-area — entire reliability coordinator areas and critical flow and status information from adjacent RC areas — impacts and setting study area boundaries based on the benchmark events’ planning coordinator or planning coordinator requirements.  

“In general, we see a lot of need here to bring online nuances to these studies, not just with respect to the defining the benchmark events, but actually the assumptions that go into the analysis itself,” he said. 

A second draft is expected to be released for a second ballot in July. The drafting team will consider the need to define wide-area studies, bounding coordination requirements within a single interconnection and whether additional details are needed to specify addressing impacts on/from adjacent systems. 

Vittal said the TPL-008 process won’t take as long as the original standard, which took five years to approve.  

“Well, there’s the FERC directive behind it, so that kind of dictates the timeline in a way that might not apply to other standard-development processes,” he said. “That’s driving things at a little more pace.” 

“This conference raises a lot of questions about how much data and how much analysis should be put into [the standard] because there’s a lot of assumptions and a lot of uncertainties that still require a lot of engineering and regulatory judgment,” said SPP’s Charles Yeung, executive director of interregional affairs.  

He said the standard still will need a lot of work but that the workshop laid out a set of questions that will be tackled in the development process.  

“I think it’s very valuable to do that upfront, rather than having to go through this iteration of postings and Q&A,” Yeung said. “This is definitely helpful because this is clearly something that’s not done in the planning horizon. So how do you translate all that analysis into a planning horizon? That’s going to be the challenge because the conditions and risks are very different going out far in the future than they are a week in the future.” 

SPP’s Jonathan Hayes asks a question during a workshop on an extreme weather standard as EPRI’s Eknath Vittal listens. | © RTO Insider LLC

Creating the benchmark planning cases will require exchanging information on who develops the case, the weather variables that will affect inputs and assumptions, and how planning coordinators will coordinate case development with other PCs.  

The standard drafting team envisions coordination among adjacent affected PCs to include sharing all applicable modeling and contingency data and understanding the benchmark event being studied by adjacent impacted PCs.  

“Every time I talk to anyone in industry about what we’re trying to do … they’re so impressed because we’re trying to take on something that has not been done before,” said Soo Jin Kim, NERC’s vice president of engineering and standards. “When NERC first came into existence … it was in whether or not we had enough capacity on the system. That’s no longer the case anymore. Now with our changing resources, with almost all of the generation projects coming into the interconnection queues being renewable resources, we have to run our system very differently.” 

Kim said other planning projects are on the horizon once TPL-008 is completed. She acknowledged the industry is “a little tired” of all the standards projects in play and asked for patience as NERC works to address severe weather effects. 

“We do think it’s important that we continue to grow, and we continue to make sure that the momentum moves forward,” she said. “We’re now at a point where we have to keep up. I think it’s very important that we get ahead of the issue, and then we’re not playing catch-up for the next two years.”