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December 15, 2025

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CPUC Proposal Seeks to Blend RA, Clean Energy Procurement

The California Public Utilities Commission has proposed a new framework that would take a “more programmatic approach” to load-serving entities’ resource procurement requirements compared with the agency’s recent practice of issuing procurement orders as needed. 

CPUC released the proposal, called the Reliable and Clean Power Procurement Program (RCPPP), in late April. It is intended to cover procurement to meet both reliability needs and greenhouse gas emissions-reduction targets. 

“The goals … are to build on prior procurement experience and to establish a clear and predictable set of long-term procurement requirements that will allow LSEs to better plan and implement their procurement of reliable and clean electric resources,” the CPUC proposal stated. 

CPUC staff held a workshop on the proposal May 16. RCPPP also was a topic of discussion during the California Energy Transition Summit in Sacramento on May 6-7. 

During the conference, Molly Sterkel, CPUC’s electric market program manager, described RCPPP as a bridge between CPUC’s resource adequacy program, which is focused on the availability of resources in CAISO markets, and the 10- to 15-year planning time frame of utilities’ integrated resource plans. 

She recalled CPUC’s first procurement order to all LSEs, including investor-owned utilities, community choice aggregators and electric service providers, in 2019. That order, for 3.33 GW, was followed by a 2021 decision ordering a record-breaking 11.5 GW and a 2023 order for 4 GW. (See California PUC Orders 4 GW of New Resources for Reliability.) 

“We were kind of tired of doing all those orders,” Sterkel said. “We knew we needed to have a more durable approach.” 

CPUC staff issued proposals for a procurement framework in 2020 and 2022. The release of the current proposal was accompanied by a summary of comments on staff’s 2022 options paper. 

The CPUC is accepting opening comments on the proposal through June 5. Reply comments will be due June 26. Commissioners are expected to consider the proposal later in 2025. 

RCPPP Requirements

RCPPP would apply to all LSEs under CPUC jurisdiction, including IOUs, CCAs and ESPs, but not publicly owned utilities. The reliability portion of the RCPPP framework has four components: a determination of how many resources will be needed over a specified period, how much of the needed resources will be allocated to each LSE, reporting requirements and enforcement provisions. 

The CPUC has proposed two options for reliability procurement. Under both options, the Reliability Procurement Need (RPN) would be calculated based on the accredited capacity to meet the 0.1 loss-of-load expectation using marginal effective load-carrying capability, plus a 2.5% buffer. 

In Option I, the scope of the need determination would include both new and existing resources. 

Option II would adopt a rolling 10-year “new” resource vintage, defined as resources that came online or will come online no more than 10 years before the compliance year. This would give LSEs credit for proactive and early procurement, the proposal stated. 

For need allocation, both options would allocate RPN to each LSE using LSE-specific hourly load forecasts and each entity’s pro rata share of load during critical hours. 

On the GHG reduction side of the framework, CPUC staff have proposed a clean energy standard, which would be a percentage calculated to meet the electric sector GHG target. An LSE’s allocated need then would be its retail sales forecast multiplied by the annual CES percentage. 

California Senate Bill 100 of 2018 requires all electric retail sales to come from renewable energy and zero-carbon resources by 2045. 

“How do you get to that 100% clean energy goal?” Sterkel said. “You can’t just keep putting more and more clean capacity in the system. You also have to make sure that the energy mix of each of the entities gets us from here to the 100% clean energy goal.” 

Even with a new framework, procurement orders still may be needed to meet SB 100 objectives, according to a presentation during the CPUC workshop. 

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U.S. Hydropower Projected to Bounce Back from 2024 Slump

Federal analysts expect U.S. hydropower generation to increase 7.5% over 2024 totals, which were the lowest in at least 14 years.

The U.S. Energy Information Administration said in its May Short-Term Energy Outlook that the 259.1 billion kWh projected this year still would be 2.4% below the 10-year average and would constitute 6% of the nation’s power generation.

The projections are strongly influenced by conditions in the West Coast states, as roughly half the nation’s hydroelectric generating capacity is in Washington, Oregon and California.

Precipitation conditions have been mixed there and in the Rocky Mountain region.

More precipitation than normal was recorded since October in northern California and eastern Washington, and some areas of Oregon saw record levels of precipitation. But Montana, Idaho and other parts of Washington and California saw below-normal precipitation from October through April.

2025 hydropower output in the Northwest and Rocky Mountain region is projected at 125.1 BkWh — 17% more than 2024 but 4% less than the 10-year average.

By contrast, 28.5 BkWh of hydropower generation is projected in California, 6% less than last year but 15% more than the 10-year average.

As of April 1, most major reservoirs in California were above the historical average for that date — two of the largest, Shasta and Oroville, stood at 113% and 121%, respectively.

Snowpack conditions were above normal in the northern Sierra Nevada region and below normal in the central and southern Sierra regions as of April 1. Higher-than-average temperatures brought the snowpack to well-below-average levels for all three regions by May 1.

Other Generation

More broadly, the EIA’s May Short-Term Energy Outlook forecasts that U.S. electrical power generation will be 2% higher in 2025 than in 2024, and then 1% higher in 2026.

EIA predicts that natural gas will remain the largest single fuel for electrical generation. But it expects 2025 output from gas-fired plants to decline 3% year over year due to gas prices, which are forecast to be 63% higher on average than in 2024.

This — combined with recently relaxed emissions regulations on coal-fired plants — will lead to a 6% increase in generation from coal, EIA predicted.

EIA said about 5% of U.S. coal-fired generation facilities had been slated for retirement in 2025, most of them at the end of the year, which could reduce generation from coal by 9% in 2026. However, the agency also said President Donald Trump’s policy changes in favor of coal could alter these retirement strategies, adding a degree of uncertainty to the forecast.

Utility-scale solar generation is expected to jump 34% in 2025 and 18% in 2026, EIA said, bringing total installed capacity to 180 GW by the end of next year and providing another limiting factor on natural gas-fired generation.

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Turlock Irrigation District to Join EDAM in 2027

California publicly owned utility Turlock Irrigation District has agreed to join CAISO’s Extended Day-Ahead Market in 2027, the ISO said May 19. 

Turlock’s board of directors voted May 13 to allow the district to join EDAM in 2027, with the implementation agreement signed the following weekend. Turlock is a member of CAISO’s Western Energy Imbalance Market (WEIM) and has saved $28 million since joining WEIM in 2021, CAISO stated. 

Turlock provides irrigation water and electricity to more than a quarter million customers in California’s Central Valley, according to the news release. 

“[Turlock] has had tremendous success in the Western Energy Imbalance Market, and we are excited to build on this partnership and leverage the increased economic, reliability and environmental benefits of the Extended Day-Ahead Market,” Brad Koehn, Turlock’s general manager, said in a statement. “[Turlock]’s continued alliance with the California Independent System Operator will enable the district to continue our stellar track record of providing reliable, affordable power to its customers.” 

The announcement comes as the race for participants between SPP and CAISO is both heating up and winding down as the two entities prepare to launch their respective Western day-ahead markets. 

SPP got a major win May 9 when the Bonneville Power Administration issued its long-awaited decision in favor of SPP’s Markets+. Puget Sound Energy followed suit shortly after. (See BPA Chooses Markets+ over EDAM and Puget Sound Energy Inks Agreement to Join Markets+.) 

Entities such as Xcel Energy subsidiary Public Service Company of Colorado, El Paso Electric and Tacoma Power also have committed to joining SPP’s day-ahead market. 

Meanwhile, PacifiCorp and Portland General Electric have agreed to begin participating in EDAM in 2026, with the Los Angeles Department of Water and Power and the Balancing Authority of Northern California set to join in 2027. (See LADWP Gets Board’s OK to Join CAISO’s EDAM.) 

BHE Montana, PNM, NV Energy, Idaho Power and Arizona G&T Cooperatives have indicated they’re leaning toward EDAM as their preferred day-ahead market choice.

In CAISO’s May 19 news release, the ISO said EDAM is built “on the proven track record of the WEIM.” 

“The Turlock Irrigation District has been a valued partner in the Western Energy Imbalance Market since 2021, and its decision to join the Extended Day-Ahead Market reflects the growing recognition of the markets’ significant economic, reliability and environmental benefits,” CAISO CEO Elliot Mainzer told RTO Insider in a statement. “As Turlock joins the community of EDAM entities, we are pleased with the continued expansion of the EDAM footprint and remain laser focused on achieving market go-live with PacifiCorp and Portland General in 2026.” 

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TVA First U.S. Utility to Request SMR Construction Permit

The Tennessee Valley Authority crossed a milestone May 20, becoming the first U.S. utility to request a construction permit for a small modular nuclear reactor. 

The facility would be built around a GE Hitachi BWRX-300 near Oak Ridge, Tenn., at TVA’s Clinch River site, where plans to build a breeder reactor were pursued and then abandoned 40 years ago. 

In its announcement, TVA said its plan has the best path to success because the site holds the first — and still only — early site permit issued by the Nuclear Regulatory Commission for an SMR.  

But there are many competing plans. The SMR field is crowded with technology developers, site developers and would-be off-takers eager for the non-intermittent, emissions-free electricity this next class of nuclear reactors is expected to provide. 

If the technology evolves as hoped, and if it is widely deployed, permitting and construction could be streamlined and standardized to the point that SMRs come online much more quickly and at markedly lower cost than their large-scale forebears.

TVA’s milestone comes amid a series of firsts in the SMR sector: 

    • The NRC on May 13 accepted a construction permit application for X-energy’s first SMR, which would power Dow Chemical’s manufacturing facility in Seadrift, Texas, and be the first advanced nuclear reactor at an industrial site in the U.S. 
    • Ontario Power Generation on May 8 received provincial approval to build what is expected to be the first SMR to come online in North America, also a BWRX-300. (See Ontario Greenlights OPG to Build Small Modular Reactor.) 
    • In March 2024, TerraPower submitted the first application for permission to construct a commercial advanced reactor, its Natrium demonstration project in Wyoming. NRC’s draft safety evaluation is underway. 
  • 2024 and 2025 have seen many other SMR announcements. Most were not milestones, yet they carried a tone of confident certainty. But at least some amount of revision, delay or failure seems likely for these proposals, given all the financial, regulatory and technological hurdles standing between the announcements and start of commercial operation. 

If nothing else, a key value prospect of SMRs — serial production of identical facilities — would be diluted if 10 technology developers all bring their assorted designs to market. 

The Clinch River SMR project joins TVA — the country’s largest public power supplier and a nuclear operator — with GE Hitachi Nuclear Energy, which has a decadeslong legacy of dozens of completed reactor projects worldwide. 

TVA is leading an industry coalition in an application for up to $800 million in grant funding from the U.S. Department of Energy’s Generation III+ Small Modular Reactor Program, designed to bridge the gap between the existing U.S. reactor fleet and more advanced designs. 

TVA CEO Don Moul highlighted this in the official announcement. “This is a significant milestone for TVA, our region and our nation because we are accelerating the development of new nuclear technology, its supply chain and delivery model to unleash American energy,” he said. “TVA has put in the work to advance the design and develop the first application for the BWRX-300 technology, creating a path for other utilities who choose to build the same technology.” 

TVA said preliminary site preparation for the SMR could begin as soon as 2026. 

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ICF Report Predicts the Pace of Demand Growth to Speed up

ICF International is projecting another rise in the rate of demand growth as more data centers seek to plug into the grid in the coming years, with a 25% increase from 2023 levels by 2030 and 78% by 2050. 

“The growth trend is rapidly accelerating, potentially leading to the greatest era of load growth since post-World War II nationwide electrification,” according to ICF’s report, “Rising Current: America’s Growing Electricity Demand,” released May 20. 

Two years ago, national forecasts predicted 1.3% annual electricity demand growth through 2030. ICF’s report predicts 3.2% annual growth for the same period. 

ICF’s numbers are higher than other recent forecasts, such as the U.S. Energy Information Administration calling for 12% demand growth by 2030 and 60% by 2050. That forecast does not include the latest projections from PJM, ERCOT, MISO or SERC-Southeast. 

“The difference between the Energy Information [Administration] forecast and the forecast in this report further illustrates just how quickly demand growth forecasts are changing,” the report says. 

The report predicts peak demand will grow 14% by 2030 and 54% by 2050. It also predicts higher bills, as the industry will need to add about 80 GW of capacity per year between 2025 and 2045, up from an average of 40 GW over the past five years. ICF forecasts that residential rates will go up between 15 and 40% by 2030, depending on the region, and could double by 2050. 

“Peak demand is crucial because utilities must ensure they have the infrastructure to deliver enough electricity at times when it is needed most, even if that level of electricity is only needed for a few hours on a few days per year,” the report says. 

Historically, most of the grid has peaked during the summer, but growing electrification across the U.S. could shift those peaks, so it is essential for utilities and other stakeholders to adapt to new patterns of electricity use, the report says. 

Overall demand is growing at a faster rate because many of the data centers and manufacturing facilities coming online run around the clock, which will require more baseload generating capacity and demand-side management. 

The growth rate is not being felt the same everywhere, with the report saying that in the near term, the Dominion zone in PJM, Southern Co.’s service territory and ERCOT’s West Zone will have the highest increases in demand. Those areas are averaging 7.1% overall annual demand growth through 2035, while peak demand is expected to grow by 5.6% annually over the same period. 

Demand growth has significant implications for reliability, with the report showing that much of the country could see reserve margins slip below their targets by 2030. That issue could be exacerbated by supply chain hurdles.  

“To be clear, the U.S. is unlikely to run out of electricity,” the report says. “New generation capacity will be built in the coming years, with ISOs like PJM and MISO already working to fast-track new resources that make reliability contributions. Ultimately, if grid stakeholders can’t ensure enough new capacity is coming online, interconnection requests from new load sources could be denied to reduce the risk of reliability issues.” 

New generation is going to require upgrades to the transmission and distribution systems, which also take time. The near-term demand growth could prove most challenging, as load could come online more quickly than new generation can be added or the grid expanded. 

“Maintaining strong reserves will require reviewing new generation projects in the queue, increasing output of existing generation, and extending the life of existing power generation,” the report says. 

The industry could use virtual power plants and demand response to help deal with the supply issues and wring more out of the grid with technologies such as dynamic line ratings that can increase capacity under most conditions, the report says. 

All projections come with uncertainty, and ICF said several major factors could impact its predictions, including artificial intelligence becoming more efficient and an increase in fossil fuel production making traditional generation more economic. President Donald Trump’s tariffs could curtail economic growth, or firms might relocate manufacturing here to avoid them. Another major issue is the fate of federal tax credits for generation and efficiency. 

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Counterflow: The SMR Fission Vision in Ontario

The problem: meeting inflexible electric demand with a generation mix that is increasingly intermittent. 

The increasing intermittency is driven by the replacement of dispatchable fossil fuels (coal, gas and oil) with non-dispatchable renewables (wind and solar). 

The problem is well understood. The solutions, not so much. 

Prior columns have discussed why nuclear fusion is no answer, why long-duration battery storage is prohibitively expensive, why offshore wind makes no economic sense, and why green hydrogen electricity actually is harmful. 

I’ve discussed why the most economic path to net zero involves retaining gas generation in essentially a back-up role and offsetting the occasional carbon emissions with carbon offset credits and/or carbon capture, and I’ve had some other suggestions along the way, including Plan B, solar geoengineering. 

Talking Fission

ontario

Steve Huntoon

Today, let’s talk about nuclear fission. We need to distinguish new fission from existing fission. Diablo Canyon is a poster child for the latter, and it is fortunate that its premature closure was averted, as I urged many years ago. 

But new fission? In the wake of the Vogtle experience in Georgia (more than seven years late and $17 billion over budget), attention has shifted to small modular reactors (SMRs) of around 300 MW (about a fourth of the typical large unit like Vogtle). 

As the term “modular” suggests, the basic pitch is that SMRs could be “factory built,” with a lower per-MW cost. Many uncertainties exist about that, and a scorching critique of SMRs from the University of Pennsylvania is here. 

The SMR vision persists despite the collapse of the Utah NuScale SMR project in the wake of dramatic cost increases (and despite the $30/MWh federal subsidy). But it’s been suggested that NuScale’s failure was an anomaly.  

New Data Point from Ontario

So, which is it? We’ve just received a new data point from Ontario. The project there involves four 300-MW SMRs. It’s been estimated to cost $15 billion. The government’s press release says, no irony intended, that it’s part of “Ontario’s Affordable Energy Future.”  

If we do the math, $15 billion for 1,200 MW is $12.5 million/MW. If we plug this capital cost into the Lazard capital cost range, it interpolates to $195/MWh in the levelized cost of energy (LCOE) range. (See Page 38.) 

For perspective, this $195/MWh is five times the $38/MWh average cost of generation in PJM. (See Figure 3 net of transmission costs.) Yes, five times! 

It’s also five times what GE Hitachi told the Nuclear Regulatory Commission in 2019 this SMR would cost, specifically that it would cost less than $2.25 million/MW. (See Slide 6.) GE Hitachi also said: “Nuclear could become a major source of U.S. power generation at $2,000/kW [$2 million/MW].” (Slide 5.) “Yes,” at that cost, and “No,” at six times that cost. 

Before Cost Overruns

And even this is optimistic because it assumes the Ontario project will come in as budgeted. Experience with SMRs (like other nuclear) is for massive cost overruns. J.P. Morgan reports: “There are three operating SMRs in the world (two in Russia and one in China), and another under construction in Argentina. The cost overrun on the China SMR was 300%, on Russian SMRs 400% and on the Argentina SMR (so far) 700%. Their construction time frames were also nowhere near the projected 3-4 years; they all took 12-13 years instead to complete.” (By the way, this J.P. Morgan paper is an impressive overview of energy and the environment.) 

Who is on the hook for the cost overruns? The Ontario project’s lead contractor says it has been pursuing “collaborative alternative procurement and contracting models with the goal to reduce risk during construction,” specifically including the Ontario SMR project. Doesn’t sound like it’s taking cost overrun risk. 

That leaves the utility’s customers and the utility’s shareholder(s) to bear the risk. The utility is owned by the Ontario government, so that means the customers and the taxpayers. Uh oh. 

Good luck Ontarians! I think you’re going to need it. 

Columnist Steve Huntoon, a former president of the Energy Bar Association, practiced energy law for more than 30 years. 

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$5B Authorized for N.Y. Energy Efficiency, Building Electrification

New York’s major utilities and its energy development entity have been cleared to administer $5 billion for energy efficiency and building electrification through 2030.

The state Public Service Commission authorized the spending at its May 15 meeting (Case 14-M-0094).

The $1 billion in annual funding will be administered over the next five years by the New York State Energy Research and Development Authority and nine utilities. It will be recovered through ratepayer surcharges.

The PSC said this latest effort will complement the New Efficiency: New York and Clean Energy Fund programs. It expects the resulting changes to achieve the equivalent of 615 trillion Btu in lifetime energy savings.

The PSC’s official announcement painted this in direct contrast to the Trump administration’s elimination of energy-efficiency initiatives.

The announcement also emphasized the benefits that low- to moderate-income New Yorkers would receive from the initiative.

However, advocates for LMI New Yorkers called out the PSC for earmarking only 30% of the funding for LMI households, rather than 50%, as some activists had urged.

“While the PSC is clearly committed to energy efficiency as a pathway to reduce costs and pollution, we feel the commission has missed the mark by not revising the LMI budgets that were set in 2023 to address today’s affordability crisis,” Eric Walker of WE ACT for Environmental Justice said in a joint statement several groups issued a day after the PSC order.

But they also found much to like in the order, saying it will better align the state’s energy efficiency/building electrification efforts with its broader climate policies, such as by ending most funding for gas-burning equipment, authorizing more spending on pre-weatherization measures and working to increase participation in the New York City area, where it has been lagging.

The point of contention was that only 30% of the funding is committed to the 40% of New York households that are classified as LMI and are least able to afford New York’s high utility costs.

“WE ACT and our allies will continue to fight for families who have the most to gain from the EE/BE programs because there’s lots of work to be done,” Walker said.

The utilities covered by the order are Central Hudson Gas & Electric; Consolidated Edison and its subsidiary Orange & Rockland Utilities; National Fuel Gas; Avangrid’s NYSEG and Rochester Gas & Electric; and National Grid’s KEDLI, KEDNY and Niagara Mohawk businesses.

The nine utilities’ latest monthly collection reports show a combined 1.15 million residential customers more than 60 days in arrears on a total of $1.78 billion in charges. This is near the pandemic-era highs seen in 2021 and comes despite hundreds of millions of dollars in taxpayer and ratepayer subsidies to pay down some of the arrears.

Additionally, more than 100,000 nonresidential customers were in arrears to the tune of more than $600 million as of April.

PSC Chair Rory Christian said during the meeting that as he was researching this order, he came upon a 1980 state energy master plan touting conservation and efficiency, and found the problems described 45 years eerily similar to those today.

Efficiency reaps dividends on two levels, he said: The individual consumer whose home is made more efficient spends less to heat and power it, and these more-efficient homes or businesses collectively reduce the need for costly upgrades that all ratepayers must bear to increase utility infrastructure capacity.

“Each person’s contribution helps lessen and avoid the strain on the electric system,” Christian said, “allowing us to avoid or eliminate certain investments. That’s a big deal.”

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Consumer Advocates, Environmentalists Lay out Priorities to PJM

LANDSDOWNE, Va. — PJM’s Public Interest and Environmental Organization User Group voiced mixed views on the RTO’s policy trajectory, praising advances in generation interconnection over the past year while raising concerns about rising costs and transparency.

Speaking at PJM’s Annual Meeting on May 14, representatives of the consumer advocate wing of the group largely focused on how rising capacity and transmission costs are affecting ratepayers and long-term reliability, while raising questions about whether the RTO is overly influenced by large transmission and generation owners.

Environmentalists worried that improvements to the interconnection study process, which could speed renewable development, could be outweighed by decisions to allow more resources into the queue and the effects of PJM’s long-term transmission planning proposal under FERC Order 1920.

Brian Lipman, director of the New Jersey Division of Rate Counsel, said consumer advocates for the first time are growing concerned about how the PJM capacity market can manage both sides of the objective of delivering reliability at the least cost. While advocates have long focused on impacts to consumers’ rates, reliability has become a growing issue as industry participants discuss the increasing risks of brownouts and rolling blackouts.

Lipman used the concept of a Venn diagram to describe the decreasing overlap between the prices consumers are willing to pay and the revenues generation owners report they need to earn to maintain and develop resources. Legislators, governors and voters trying to understand how PJM decisions will affect rates and should impact policy also are frustrated by the lack of cost-impact analysis around the RTO’s proposals and market outcomes, he said.

“The anger at PJM outside this room is probably at an all-time high … I think you saw that over the last few days,” Lipman said, referring to a May 12 Members Committee (MC) vote to oust two members of the RTO’s Board of Managers who were up for reelection. (See related story, PJM Stakeholders Reaffirm Board Election Results.)

Lipman expressed surprise that PJM didn’t anticipate the outcome, given the amount of dissatisfaction that some stakeholders have expressed to the RTO.

He argued that PJM should conduct more outreach to understand where member states stand and to establish more avenues for them to learn about changes being contemplated by the RTO or its members. Too often, he said, key decisions already have been made when proposals are brought to stakeholders. He pointed to the proposal to shift filing rights over the Regional Transmission Expansion Plan from the RTO membership to the Board of Managers, which was filed at FERC after stakeholders voted in opposition, as well as the settlement with Pennsylvania Gov. Josh Shapiro to set a minimum capacity price and lower the maximum, which was not voted on by the membership.

“PJM must work on its transparency; much of its work is shrouded in secrecy,” Lipman said.

Maryland People’s Counsel David Lapp said PJM has argued that the considerable increase in clearing prices seen in the 2025/26 Base Residual Auction (BRA) was the result of tightening supply and demand, which he said misses the impact of RTO market design decisions that have limited supply.

Lapp noted that, while some of those have been changed for subsequent auctions, such as modeling the output of generation operating on reliability-must-run agreements as capacity, leaving them in place for the 2025/26 auction will cost consumers more than $5 billion. (See Maryland Report Details PJM Cost Increases for Ratepayers.)

Lapp also said that including intermittent and storage resources in the requirement that resources holding capacity interconnection rights (CIRs) must offer into BRAs was another step forward, but an exception remains for demand response resources.

“There’s a lot PJM can do to move those circles together if not overlap; those are the assumptions and parameters that PJM controls,” Lapp said, referring to Lipman’s Venn diagram concept.

Lipman said PJM market design decisions often undermine states’ clean energy policies and efforts to build offshore wind in the footprint. That has created an impression the RTO is more political than previously realized.

PJM CEO Manu Asthana strongly pushed back on that assertion, saying one of his proudest efforts was the use of the State Agreement Approach to facilitate the transmission planning necessary for meeting New Jersey’s offshore wind targets. He noted that other projects are proceeding in Virginia and said the high accreditation offshore wind carries makes it an ideal resource for meeting PJM’s capacity needs.

“It’s not fair to come to us and say, ‘PJM, you’re against offshore wind.’ We did everything we could to get it, and we need it now,” Asthana said. “I can’t be accountable for a supplier in Denmark who walked away.”

Asthana said one of his core goals before stepping down from his role at the end of the year is to rebuild the bridge with consumer advocates, who have an important voice in the stakeholder process. He said consumers ultimately must pay these costs, and he is sensitive to that hardship, so PJM and advocates will have to work together to figure out how to serve consumers at a price they can afford. (See PJM CEO Manu Asthana Announces Year-end Resignation.)

Asthana said each of the major capacity market changes the RTO has filed at FERC since December is expected to reduce clearing prices. While prices in the last auction were very high, he disagreed with the position that they were unreasonably high from an economics perspective. He said several different principles are conflicting with each other around sending price signals that attract needed generation while remaining cost-effective. PJM’s modeling shows more generation is needed, Asthana said, and much of the generation that can be built in the region comes out to about $650 MW/day to build.

Board of Managers member David Mills said he plans to propose adding a standing agenda item to future MC meetings stipulating that attending board members would commit to staying for the full day so they can discuss items of importance with stakeholders, including possible FERC filings the board is contemplating.

Environmental Orgs Promote Streamlining Interconnection, Planning

The explosion of data center load growth has caught PJM on the back foot as it works to transition to a new mode of studying generation interconnection requests that aims to break through its application backlog by the end of 2026, said Claire Lang-Ree, an advocate with the Natural Resources Defense Council’s Sustainable FERC Project. While the new cluster-based approach carries the potential to speed renewable development, she said other decisions PJM has made recently would undermine that progress.

In particular, she faulted the Reliability Resource Initiative (RRI), which added 51 projects to Transition Cycle 2, with the aim of allowing more generation to get built by the end of the decade to address a possible capacity deficiency PJM has identified.

Rather than advancing the development of more fossil fuel generation, which was the big winner in the RRI, PJM should focus on throwing its weight behind existing queue projects while improving queue processing timelines, Lang-Ree said. She cited PJM’s surplus interconnection service and generation replacement processes as two major improvements the RTO has made over the past year.

Lang-Ree said the RRI showed PJM is capable of moving quickly and effectively on priorities it has identified, a capability she thinks should be leveraged to position itself as a partner to states advancing their own energy policies.

Mike Jacobs, of the Union of Concerned Scientists, said one such area for collaboration is meeting the battery and renewable portfolio targets several PJM states have set. PJM has taken steps to improve the process for installing batteries at underutilized points of interconnection and transferring CIRs from deactivating generation to storage on the same site, but the market rules remain murky for combining renewable and storage resources as a hybrid seen as a single unit. He argued PJM should meet with those states to make constructive contributions to their goals and how they can be achieved.

Asthana said he was glad to see 2.3 GW of storage projects selected for expedited interconnection studies through the RRI and added that another 20 or 40 GW of batteries would make resource adequacy planning a lot easier. Studies conducted by The Brattle Group found that battery installations remain very expensive, a factor that has been overcome in other regions by the resources’ ability to arbitrage fluctuations in energy prices caused by higher intermittent penetration — a development that has yet to materialize in PJM.

Earthjustice attorney Nick Lawton said a long-term, regional planning model that complies with FERC’s Order 1920 will reduce risk and conflict for PJM. Enhancing backbone transmission can facilitate new entry, advance state clean energy policies and lower rates for consumers, while the RTO’s continued reliance on building local projects will raise interconnection costs for new generation and add up to higher rates once the multitude of smaller, inefficient projects are added up.

He argued that PJM’s proposal to comply with Order 1920 would continue to rely on supplemental and generation interconnection projects by splitting the benefits it considers when evaluating regional projects into core and additional needs. He said that would miss out on projects that would better prepare the grid for generators deactivating for economic reasons and new resources entering the market to support state renewable portfolio standards. Inserting PJM in the position of determining which state policies would be planned for would also be an inappropriate usurpation of state authority, he said.

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Panel Discusses Data Center Load Growth at PJM Annual Meeting

LANSDOWNE, Va. — Experts in the data center field discussed the challenges of meeting accelerating computational load during the PJM Annual Meeting, held in the core of Northern Virginia’s Data Center Alley. 

Panelists were united in their belief that data centers and other large load additions are likely to continue to proliferate in PJM and across the U.S., posing reliability risks and cost assignment challenges. 

PJM Executive Vice President of Market Services and Strategy Stu Bresler, who moderated the May 13 panel, said load not only is expected to increase at an unprecedented pace, but it also would act uncharacteristically compared to traditional consumption by following a novel profile. 

Brian George, Google’s head of global energy market development and policy, said data center load is sure to grow, but there is risk inherent in any predictions about the future. Ensuring that load can be served reliably without costly overbuilding will require a load forecast that weeds out duplicative projects being proposed at multiple locations. 

“I can tell you not all of it is real; if we look a few years out, that forecast is wrong,” he said.  

Dan Thompson, principal research analyst for S&P Global Market Intelligence, gave the example of two developers seeking to build a data center for the same customer at different locations within Georgia Power’s territory. That caused the projected load to appear twice in the utility’s forecast, none of which manifested after the customer backed out of the project. 

Tech Companies Adjust to New Interconnection Reality

George said the tech industry has long benefited from an overbuilt grid and has developed an assumption that power would always be available from utilities. Adjusting to a new reality where new transmission, and possibly generation, must be built before data centers can come online is a hard reality the sector will have to adjust to. 

Google is pivoting to that paradigm shift by putting more skin in the game when negotiating tariffs with electric distribution companies, he said. 

“We are now in a position where we have to go back to our executives and say we are now imposing this cost on the grid,” George said. “We have to come to terms with the fact that energy is not risk free.” 

Thompson said utilities increasingly are passing interconnection costs to data centers, particularly as investors grow more willing to finance large projects. It used to be difficult to find capital to develop projects beyond 24- or 36-MW buildings, but the scale now is growing to the hundreds of megawatts. As that continues, developers will have to grow more accustomed to building to spec and accounting for substation and interconnection needs and costs. 

Data Center Characteristics Pose Reliability Challenges

Mark Lauby, NERC senior vice president and chief engineer, said properly modeling how data centers may act on the grid is critical to ensuring they do not cause the sort of voltage issues that caused 1.5 GW of load to go offline July 10, 2024.  

When the sensitive devices housed in data centers switch off suddenly, they can rock the frequency and voltage of the entire grid. (See NERC Report Highlights Data Center Load Loss Issues.) 

Thompson said data center operators in ERCOT showed they are capable of flexible operations by curtailing their load when the grid operator asked consumers to cut back while ice storms were hitting Texas. Overall, however, he said their demand response potential remains largely academic because operators typically have contractual requirements to their customers to provide a predefined degree of service to their customers, hampering their ability to throttle servers or switch them offline. 

Kevin Hughes, STACK Infrastructure senior vice president of public affairs, said installing backup generation for data centers has long been seen as an avenue for unlocking more flexibility, but regulatory and hard infrastructure constraints limit the feasibility of that approach. 

Data centers also are a capital-intensive business, with land in Data Center Alley running about $4 million/acre and the hardware costing between $500 million and $1 billion, Hughes said, adding that these are not assets operators want to leave idle. 

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CAISO Chooses Viridon to Develop Humboldt OSW Transmission Projects

CAISO has selected Viridon as the project owner to develop transmission infrastructure in Humboldt County, Calif., to support future offshore wind power in the region.

Over the next decade, Viridon will develop about 400 miles of new transmission lines for two primary projects: Collinsville and Fern Road. The projects could cost an estimated $4.1 billion.

The Collinsville project includes a new 260-mile high-voltage direct current line that initially will operate at 500 kV alternating current, along with a new substation and transformer in Humboldt. The estimated project cost is $1.9 billion to $2.7 billion, and the project is expected to be online by June 2034, CAISO wrote in its 2023-2024 transmission plan.

The Fern Road project includes a new 140-mile 500-kV line from the New Humboldt substation to the Fern Road substation for an estimated $0.98 billion to $1.4 billion. Since the line’s voltage level is more than 200 kV, Viridon will be responsible for submitting progress reports to WECC, CAISO wrote in its plan. This line also is expected to open by June 2034. Viridon will be required to submit nonconfidential cost-tracking information for CAISO’s approval during the project.

However, there is inherent uncertainty in the future of floating offshore wind off the California coast, CAISO wrote. CAISO therefore will “balance the need to engage promptly on long lead time transmission with the need to remain in step with the numerous other parallel development paths needed to enable offshore wind to develop,” the ISO wrote.

California’s North Coast has “world class” offshore wind power potential, but the location of that power is a long distance from the load centers in the state, the California Energy Commission (CEC) wrote in a 2024 transmission corridor evaluation report. The transmission system will require significant infrastructure investment to move North Coast OSW power to major urban load centers, and “large amounts of transmission upgrades will be needed in the coming decades,” the report says.

The CEC’s report includes possible transmission line paths for both the Collinsville and Fern Road projects. For the Collinsville project, the most favorable route is a southern path, which has two potential barriers: residential development in the City of Eureka and critical habitat for threatened or endangered species.

For the Collinsville project, a coastal overhead path had fewer potential difficulties than a coastal underground path. The overhead path’s primary potential barriers include traversing valuable property in wine country, while the underground path’s primary potential barriers include active fault lines and possible landslides.

CAISO’s 20-Year Transmission Outlook, published in 2022, shows 10 GW of offshore wind development in the state: 4 to 7 GW in the North Coast region and 3 to 6 GW in the Central Coast region.

Viridon currently is developing two transmission projects in the NYISO region, one planned to be online in 2026 and the other in 2033.