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April 24, 2025

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Load Growth Dominates Discussions at GCPA’s Spring Conference

HOUSTON — Texas has shown itself as capable as any state of building big things. And ERCOT is the one organized market that saw demand growth over the past two decades as it benefited from population shifts to the Sun Belt and booming industry.

The latest forecasts are so large, however, that meeting whatever fraction comes to fruition is daunting. That issue dominated discussions at the Gulf Coast Power Association’s recent Spring Conference. (See GCPA Hears Different Tales on Texas Load Growth from 2 CEOs.)

The market’s all-time peak is about 85 GW, and forecasts claim that could triple by the end of the decade due largely to new large loads from data centers, cryptocurrency mining, reshoring of industry and hydrogen production.

“I think that’s driven by the opportunities that are created by the Texas market, plus, you know, just the natural resources that Texas has,” said Goff Policy President Eric Goff. “So, it probably won’t be as big as the number ERCOT publishes, in part because they’re required to follow a particular methodology established in state law. But, also, it’s going to be big.”

The industry should take the eye-popping numbers in ERCOT’s forecasts with a grain of salt as it does similar figures on the supply side, said American Clean Power Association Senior Director Charlie Hemmeline. ERCOT’s queue similarly has eye-popping numbers in terms of nameplate capacity.

“There’s a lot of plans,” Hemmeline said. “Many of those plans work out, and many don’t. And so just being smart about what the future holds.”

Texas is trying to get more dispatchable generation onto the grid through the Texas Energy Fund (TEF), which has seen projects drop out recently. (See 2 More Projects Fall out of TEF Loan Program.)

Calpine has one project competing for state money. Its Vice President of Government and Regulatory Affairs Bryan Sams wondered how generous the Legislature will be, with different amounts allocated in the House and Senate this session.

“I think market design really is the answer for what needs to happen to build plants, but it helps at the margins,” Sams said.

The TEF gives the Public Utility Commission a new role, acting like a bank, and it is learning that job on the fly, he added. The program also comes with restrictions that could cause more projects to drop out, such as being required to sell 50% of capacity to the grid. Sams said firms could find a better deal co-locating with a data center and might leave the fund for that option.

“One of the things that I’m watching out of the TEF over the next few years is, do we see more natural gas turbines installed outside of TEF than inside TEF, and if so, what does that say to the health of our market and our market design?” Goff said.

ERCOT is working on new rules to deal with large loads seeking to connect to the grid. Those loads are defined as anything with a demand of 75 MW or above, said Large Load Integration Team Supervisor Julie Snitman. It has some interim rules to catch new sources of demand while more permanent fixes are worked out.

“This era of large loads is forcing us and the entire industry, really, to have to think about planning a whole new way,” Snitman said. “I think it’s really challenging a lot of our existing and preconceived notions about how to plan, particularly when the assumptions you’re making in these planning cases are shifting under you — often quite dramatically and quite quickly.”

The customer behind a request can change while it’s pending in ERCOT’s process, which can change how that load will affect the grid, she added. Some customers have flexible requirements, but others require 24/7 power, and that can change at specific sites while ERCOT examines their impact.

The interim process requires loads looking to interconnect within two years to register with ERCOT. But more customers planning large facilities are getting into the process with longer-term plans than that. Rules for longer lead times begin in May, so some are getting ahead of that.

“Also, I think increasingly there’s less and less space available in the near-term system, and a lot of clients are starting to recognize that, and so they’re pushing out those interconnect requests a little bit further than that two-year mark in the queue,” Snitman said.

Supply chain issues have been well documented on the supply side, but Brad Richter, senior vice president of Hut 8, said his firm, which develops Bitcoin mines and other data centers along with their required energy infrastructure, has seen large loads running into the same issue.

“These 345 breakers, there are two manufacturers of these worldwide,” Richter said. “And the interconnection queue on that side of things is also long, and whether you’re stepping up or stepping down, you need that equipment.”

Other jurisdictions have asked to stop large load development altogether as they’ve been swamped. At some point, ERCOT might need to weed out unrealistic projects to avoid that situation, he added.

Prospects for Another Round of Transmission Expansion

Large loads are a huge issue facing planners. They are harder to deal with than renewables because they come online faster and ERCOT cannot curtail customer demand like it can with power plants’ excess generation, said Zero Emission Grid President Mike Tabrizi. One area they have in common with renewables is the need for transmission.

“I think the main issue is not supply,” Tabrizi said. “The main issue is the transmission. You can have a single line. You can have an unlimited amount of generation on one side of this line. But it doesn’t mean that we can transfer all this out to the line, right? So, I think the main fundamental right now is that transmission is not being developed.”

Transmission expansion is important to former PUC Commissioner Will McAdams, who runs the McAdams Energy Group. Regulators will decide soon on whether to build 765-kV lines to help to serve Permian Basin oil production in West Texas. If they do, it follows that 765-kV lines will be built in the east of the state to support load growth around its major cities and from large customers.

“It’s a no-brainer to me, because that’s the one thing that we can guarantee the immediacy, or have more control over the immediacy, of integration and interconnectivity across the system,” McAdams said.

The Legislature has indicated it wants to keep ERCOT mostly isolated from the rest of North America’s grid. That will require more transmission within Texas to manage the new demand and supply.

“Then we need an extremely integrated system within that island in order to support ourselves,” McAdams said.

While ERCOT is likely to keep its jurisdictional status, one line that could increase its exposure to the Eastern Interconnection is Pattern Energy’s Southern Spirit line. It would connect to MISO South with full construction scheduled to start in 2029. Pattern Vice President of Origination Holly Adams noted that her firm has another HVDC merchant project linking New Mexico and California, while Grid United plans one to connect ERCOT and SPP.

“Our opinion is all the projects on this list should actually get built out,” Adams said. “There’s a lot of need for it. But I do think the ERCOT to MISO South, just in proximity for the Texas triangle, the big load growth — I think it’s really important to get that project built out.”

NERC’s studies on interregional transfer capability have shown that connecting ERCOT to MISO South and SPP would bring reliability benefits, she added. (See NERC Files ITCS to FERC, Meeting Congress’ Deadline.)

NERC studies have shown interregional HVDC lines that are long enough to get into a different weather pattern can improve the reliability of the grid, said Lasher Energy Consulting’s Warren Lasher. But the connection to vastly different market regimes would lead to less generation in Texas over time as the resources on the other side do not face the same competitive pressures that come with ERCOT’s unique market.

“It reminds me of the canals around Chicago, where they’re concerned about invasive fish getting into the Great Lakes,” Lasher said. “You’ve just got to be careful about where you build a connection from one point to another because of the long-term impacts.”

Where Will Needed New Generation Come from?

While transmission is key to serving new load, it cannot accomplish that without enough electrons. That means new generation to meet rising demand.

Vistra Energy develops solar, batteries and natural gas units, but it needs offtake agreements with customers to make renewable projects profitable enough to build. The revenues required for new gas plants increasingly are requiring that too, said Stacey Doré, its chief strategy and sustainability officer.

“We often say in rooms like this, if there are any corporate offtakers for gas plants that want to sign up for a PPA, come and talk to us,” Doré said. “And we typically don’t have a line out the door waiting for that.”

Gas plants need market signals to get built. While Vistra is developing new peaker plants in West Texas that are up for the Texas Energy Fund, it is hedging its bets and could back out of those plans if prices are not enough to justify the final investment, Doré added.

“In ERCOT in particular, where there’s no capacity market, customer choices are driving what gets built, and the customers are demanding renewables, even while our policymakers are saying we need more dispatchable generation,” Doré said. “So I think that’s a disconnect that we still haven’t quite solved in ERCOT yet.”

The existing thermal fleet ran only at 50% capacity factor last year, which means there still is headroom in current generation, she added.

The use of batteries has increased dramatically in ERCOT, with more than 10 GW today, said Jupiter Power CEO Andy Bowman, whose firm develops energy storage projects.

“I think with batteries, they come along so quickly that the market opportunity is still coming together and being articulated in state policy and in ISO policies,” Bowman said. “The opportunity here in ERCOT is very different. The first six projects that we built were built on balance sheet. These were projects that just operated in the market. They operated largely as a natural gas power plant would.”

Jupiter is developing more batteries that are contracted with PPAs, instead of just earning in the wholesale markets, he added. ERCOT will keep building solar and batteries, along with some wind and natural gas, and that will lead to more ramping needs and volatility.

“There’s a pretty good stripe of opportunity that a lot of outside forecasters, which we rely on in our finances and so on, are seeing a really solid revenue opportunity for batteries fitting into ERCOT extending through 2040,” Bowman said.

With a demand super cycle driving investment, there’s no shortage of capital to support new supply. But NRG Energy and other generators have to make enough money to justify investing it, said its Executive Vice President Robert Gaudette.

“Thermal shares a lot of the same question marks as far as, OK, well, ‘who’s wearing a risk on tariffs, or who’s wearing a risk on XYZ and all that,’ but there’s no shortage of capital,” Gaudette said.

A lot of that capital is being deployed into existing assets through merger and acquisition activity, said Vistra’s Doré.

“You can buy those plants for cheaper than you can build new plants,” Doré said. “And as long as that’s the case, capital is going to flow to those assets, because obviously they’re going to have a better return. So, then you have to ask yourself, what does the market need to do to incentivize new generation if we need new generation and how much of it do we need?”

PJM has built three times the amount of natural gas as ERCOT has in the past decade, but it has a capacity market. While that construct is not likely to be added to the Texas grid, Doré argued that something has to change.

“You’ve got to come up with some market mechanism that rewards reliability, because the fact of the matter is we have plenty of energy,” Doré said. “I mean, on your average day in ERCOT, we have a lot of excess energy. We have plenty of energy. What we don’t have quite enough of is the capacity that’s needed to fill in the gaps on the peak days when perhaps renewables, for example, are not performing as expected.”

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Texas RE Endorses 6.4% Budget Increase for 2026

The Texas Reliability Entity’s Member Representatives Committee has unanimously approved the entity’s 2026 business plan and budget, which is within 1% of projections. 

The proposed $21.598 million budget is a $1.3 million increase (6.4%) over the 2025 budget. It adds three staffers to help handle the organization’s increasing workload and a 4% merit increase for personnel. 

“We’re looking at the challenges that we’re seeing with significant growth and the complexity of the work that we’re having to do, and the changing landscape with the resource mix,” Texas RE CEO Jim Albright told the MRC during the April 17 call. 

Albright said Texas RE has the lowest number of statutory full-time equivalents (72) in the ERO Enterprise but the second-highest number of registered entities (389). It has the lowest NERC ERO Enterprise Program funding per registered entity, he said. 

At the same time, the increase and types of registered entities are increasing compliance-oversight engagements. New standards or requirements in compliance areas and increased expectations from NERC and FERC for new entity outreach and engagements also are taxing Texas RE’s staff, COO Joseph Younger said. 

Looking ahead, Texas RE is projecting a 7.8% budget increase in 2027 from 2026 and a 5.5% increase in 2028 from 2027. 

Texas RE will post the budget for members’ comments. The complete plan and budget will be presented to the board May 14 for its approval. 

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PUC Staff Urges Approval of 765-kV Lines to West Texas

The Texas Public Utility Commission’s staff has recommended that the commission approve construction of three 765-kV transmission lines, rather than 345-kV lines, into the petroleum-rich Permian Basin to improve the region’s reliability (55718). 

Staff said in an April 17 memo that after “careful deliberation,” they found the 765-kV import paths’ long-term benefits justify an additional 22% increase in estimated capital costs.  

Based on confidential cost filings from transmission providers and updated estimates from ERCOT, staff said the 765-kV option’s expenses have increased from $9.06 billion to $10.11 billion. In comparison, the 345-kV option has increased from $7.69 billion to $8.28 billion. 

“Staff is convinced that the commission has a unique opportunity to timely address ERCOT’s current and expected rapid load growth by deploying an extra-high-voltage transmission network at a reasonable economic cost,” they wrote. “This decision balances forecast uncertainty, cost and reliability with establishing a forward-thinking policy decision that ably prepares the ERCOT region for the future.” 

The PUC is expected to discuss the recommendation at its April 24 meeting. The commissioners have promised a decision by May. 

Staff said 765-kV lines’ lower impedance than that of 345-kV lines increases power flows. They said ERCOT indicates the 345-kV plan has an incremental transfer capability of 1,340 MW while the 765-kV plan can transfer 2,105 MW. 

“The higher value for the 765-kV transfer indicates it can carry more power, and therefore serve additional load in the Permian,” staff said, noting the “uncertainty inherent in forecasting load out as far as 2038.” 

“The ability to serve more load could offer a buffer for the 2038 load forecast and may avoid or delay the need to build additional transfer paths in the near future,” they said. “Therefore, the increased capital cost of installing 765-kV infrastructure could function as a present investment that may save additional infrastructure costs in the future.” 

Staff also said the 765-kV option’s transfer capability will help ERCOT better manage the “uncertainty surrounding load and generation siting decisions” and the flexibility for power flows to shift due to changes in location and the nature of future load and generation. 

Because the 765-kV plan allows greater transfer capability, ERCOT designed the 765-kV plan using only three paths totaling about 1,255 miles of right-of-way, staff said. The 345-kV plan, with five paths, would require about 1,676 miles of ROW. 

The lines, if built, could be Texas’ first. SPP in December approved a transmission plan that included its first 765-kV project in Southwestern Public Service Co.’s West Texas and New Mexico region. (See SPP Board Approves $7.65B ITP, Delays Contentious Issue.) 

“765-kV technology may be new to Texas, but it is not a new technology,” staff said, pointing to American Electric Power’s “decades of experience” with EHV lines. AEP has offered other transmission providers access to its 765-kV standards and guidance, they said. 

ERCOT, at the PUC’s direction, filed its reliability plan for the Permian Basin in July 2024. The plan included the 345-kV and 765-kV import paths and a 2038 need date. The commission approved the plan in October 2024 but reserved a decision on the voltage level by May 2025. (See Texas PUC Approves Permian Reliability Plan.) 

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FERC, NERC Say Grid Winter Recommendations Working

The U.S. electric grid and natural gas system performed well during the cold weather events of January despite record cold temperatures across much of the Southeast, FERC and NERC staff said at the commission’s open meeting on April 17.

Low temperatures blanketed the South in waves from Jan. 3-24, separated into discrete events later dubbed winter storms Blair, Cora, Demi and Enzo. Cities as far south as Louisiana reported extreme low temperatures, with New Orleans hitting 26 degrees F on Jan. 22, while cities across the South also broke snowfall records.

Despite the severe cold, NERC and FERC reported in February that no “major [grid] incidents” occurred, and the grid also was free of “major fuel system disruptions.” The commission and the ERO announced a joint review of the grid’s performance to determine the impact of the electric and gas industries’ winter preparation activities, including changes since the winter storms of 2021 and 2022, and “additional opportunities to enhance winter operations.” (See FERC, NERC Praise Grid Performance in Cold Snap.)

Presenting the results of that review, NERC Manager of Event Analysis Matt Lewis said the U.S. “set winter records in electric demand and natural gas consumption” from Jan. 19-24, with 678 GW generated at the peak hour of 8-9 a.m. EST Jan. 22. PJM, MISO South, VACAR South (a subregion of SERC comprising parts of North and South Carolina) and the Tennessee Valley Authority all set winter peak demand records as well.

Natural gas accounted for the largest share of electric generation during this period, with 291 GW generated during the peak hour. This amounted to 43% of all generation, more than the 19% from coal and 14% from nuclear combined, and contributed to gas consumption reaching 150 Bcf/day from Jan. 21-22. Gas took the same share of generation in the other two 2025 winter events.

Jan. 22 also saw the number of coincident incremental unplanned generator outages across the Texas and Eastern Interconnections peak at 71,022 MW. The largest share of unplanned outages at this time occurred in MISO, with more than 17,000 MW out of service, which also was the highest number of unplanned outages for any electric entity across the two interconnections.

Lewis observed that both interconnections have experienced higher amounts of unplanned generator outages before: The Eastern Interconnection lost 90,500 MW of generation during Winter Storm Elliott of 2022 and Texas lost 34,290 MW during 2021’s Winter Storm Uri. No manual load shed was required as a result of the generator outages.

Cumulative incremental unplanned generator outages in the Eastern and Texas Interconnections from Jan. 3-24. | FERC

Electric entities “reported better internal and external communication compared to prior winter storms” during the 2025 events, the joint report said. Calls between reliability coordinators (RCs) also “played a crucial role in preparing for extreme weather” before the storms.

“The Southeastern RC began such calls … five days prior to each of the January 2025 arctic events,” FERC and NERC said in the report. “In the SERC footprint, calls occurred daily to provide heightened situational awareness … as a direct result of lessons learned from Winter Storm Elliott. SPP noted that enhanced coordination calls with neighboring reliability coordinators provided critical insights into how the … arctic events were impacting the grid, addressed anticipated resource constraints and identified tight operational periods.”

‘We Had No Load Sheds’

Preparations before the storms were extensive, with multiple entities “declaring conservative operations earlier than in past events to defer, recall or cancel planned transmission outages to reduce grid congestion and enhance transfer capability.” Such actions included TVA and MISO returning key transmission lines to service.

Coordination between the gas and electric industries also improved from previous winter events. FERC and NERC noted that natural gas pipelines “regularly hold customer and stakeholder meetings entering the winter seasons,” and in some cases increase the frequency of their coordination phone calls ahead of storms. The report said MISO, TVA and PJM have worked to build relationships with gas pipelines. TVA credited such relations for enabling it to procure gas needed during the Martin Luther King, Jr. holiday weekend.

Staff credited electric and gas operators with implementing many of the recommendations made after previous extreme winter events for improvements in areas such as generator weatherization, communication and coordination, operations staffing and resource availability risk assessments. Robert Clark of FERC’s Office of Electric Reliability noted that electric generators have shared their burn profiles with gas pipelines, which allows the gas providers to prepare for “the influx of gas that’s going to be needed to meet that demand.”

The report’s authors urged the electric and gas industries to continue implementing the recommendations made in previous winter storm reports, noting that mechanical and electrical generator outages remain “a critical and persistent gap,” accounting for more than half of generator outages with a reported outage cause in the January events. They warned that this trend could point to a “systemic vulnerability … that has yet to be fully addressed.”

FERC Chair Mark Christie thanked FERC and NERC staff for their work on the report, which he said shows the value of the commission and ERO’s work.

“I think it really illustrates … not [in] theory, but real life, the critical role that FERC plays and NERC plays in making the grid more reliable,” Christie said. “Because here is the proof: We had no load sheds. Think about that — we had no load sheds last winter in these storms, and then compare the load sheds that we had in Uri. … It shows you that we can make the grid more reliable.”

In a statement, NERC CEO Jim Robb agreed the report shows progress but that more work remains to be done.

“It’s great to see both electric and gas industries find ways to lean into extreme events like we saw with these winter storms,” Robb said. “As these kinds of events become more frequent, it’s important to codify what works and include that information into performance expectations for both sectors.”

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GCPA Hears Different Tales on Texas Load Growth from 2 CEOs

HOUSTON — Two power industry CEOs at the Gulf Coast Power Association’s spring conference offered two different takes on ERCOT load growth over the rest of the decade — and how the sector should deal with a potential doubling of peak demand by 2031. (See ERCOT: 60 GW in Additional Demand by 2031.) 

“Everything’s bigger in Texas — but is it really that big?” Calpine CEO Andrew Novotny said at the event April 16. “Just a couple weeks ago, we were dealing with a pretty large ERCOT load forecast that was calling for more than 60,000 MW of growth. As of … really just last week … that 60,000 MW was turned into more than 100,000 MW of forecasted demand between now and 2030.” 

Those numbers are creating a lot of angst in an industry that has dealt with steady load growth for decades, but not a more than doubling of demand in five years, he added. 

Part of that forecast is 13 GW of hydrogen electrolyzers, which already were running into major cost issues before the election scrambled federal support for clean fuel solutions, Novotny said. An additional 9 GW was for cryptocurrency mining facilities, which, like hydrogen electrolyzers, would represent price-responsive demand and not have major impacts on the market’s peak. 

“We need to get more transparency in certain data, but they’re all curtailing anytime the price takes over $200,” Novotny said. “Bitcoin is soaking up the cheap wind and solar that exists and curtailing, providing their power back to the grid anytime the grid needs it.”

The biggest chunk of the forecast is 70 GW of new data centers, compared with fewer than 3 GW of data centers in Texas today. That would lead to $2 trillion of investment in the state over five years. 

“I think it’s impossible because it’s more than two times the amount of chips that Nvidia is expected to make over the next three years,” Novotny said. 

The Nvidia GB 200 chips cost $70,000 apiece and are needed for the artificial intelligence applications driving the data center boom. One of those chips uses the same amount of power as two-and-a-half average Texas homes, Novotny said. 

If Nvidia can double its growth rate, it will sell enough chips in the next three years that, with associated cooling demand, they will require 34 GW to operate. That could increase to 49 GW by 2030, which would be short of the 70 GW projected for Texas — an outlook that doesn’t consider other data center markets that also are projecting huge growth. 

To be included in the forecasts, many of the planned data centers need little more than certification from a corporate officer at the company constructing them, which requires a deposit of several million dollars — a drop in the bucket, given that the industry could spend $300 billion. 

“If we go after this hard as Texas, we can probably get somewhere between [5,000] and 10,000 megs of these things by 2030,” Novotny said. “So a number like 7,000 MW seems like a good midpoint guess to make. But I mean, aren’t we scared to even get that? I mean, how much resource adequacy challenge will we have?” 

Markets That Work

AlphaGen Chair Curt Morgan, who once was CEO of Texas’ largest generator, Vistra Energy, later that day offered a more cautionary — but bullish — view, colored by a fear of the industry missing out. Morgan came out of retirement because he wanted to participate as the industry dealt with national-scale load growth for the first time in decades. 

“This is the first time in my career I’ve seen a demand-led cycle,” Morgan said. “Usually, it’s an overbuild on the supply side. But my biggest concern right now is that if we get this wrong, then the [data center- and manufacturing-led] growth coming to this country is going to find a home somewhere else.” 

The power sector can meet the challenge, Morgan said, but worried it will not unless competitive markets send the right price signals. 

“We need markets that work, and we need the courage of our elected officials and our regulators to put a market system in place and let it work,” he added. 

The evidence from the Texas Energy Fund does not bode well for new builds, as the repeated exits from that program — which offers government subsidies for dispatchable power plants — show that many do not see enough revenues from ERCOT’s market to support the buildout. (See 2 More Projects Fall out of TEF Loan Program.)  

That kind of buildout has been done before, given that the construction of the entire power grid was supported by the balance sheet of large industrial customers who were its largest users. 

“Now we’re talking about data center growth, and the people who are going to benefit from data centers have to put their balance sheet out there to support power growth,” Morgan said. “They can’t sit it out.” 

Calpine CEO Andrew Novotny addresses GCPA on April 16. | © RTO Insider 

Morgan said he tells people he gets paid to be paranoid and right now he is worried the industry is going to miss the huge opportunity in front of it. 

“I’m really concerned because not everybody’s on the same page and there are politics being played,” Morgan said. “And I understand it, you know; it’s just going to be an expensive buildout.” 

The big tech firms that are driving the data center boom need to help because the cost shifts to other consumers otherwise would become politically infeasible, meaning the country misses out on the economic opportunity, he added. 

Markets have overseen huge resource expansions in the past, including the combined cycle boom at the dawn of electricity sector restructuring, which quickly turned into a bust and a wave of independent power producer (IPP) bankruptcies. 

“Every single publicly traded IPP in this country went in and out of bankruptcy,” Morgan said. “Not one penny of those bankruptcy costs was ever borne by a captive ratepayer. The shareholders paid for that. To me, that is the essence of competition.” 

‘Shark-infested Waters’

Some want to get away from that model and are using prospective demand growth as a reason to push for utility-owned generation in states that have banned it for decades, Morgan said.  

Utilities often still can set up competitive subsidiaries that sell generation in the states where they operate, but they would rather put the risk of new power plants on the backs of consumers a in rate base, he said. (See Utilities Pushing for Return to Owning Generation in Pennsylvania.) 

“That’s a chicken-you-know-what,” Morgan said, avoiding the expletive. “Come in here, into the shark-infested waters, and figure out how to make it work just like we are. And I’ll tell you, if we get into a situation where we start to bifurcate markets, it’ll never win. I’ll tell you why, because you’ll have retirements that will always outstrip new build, and you’ll just make a bad situation worse.” 

When it comes to Texas, Morgan said the ERCOT market needs to send price signals that support more dispatchable generation that will be needed to meet the growing demand. Capacity markets are a third rail in Texas, but some kind of price signal through ancillary services could work. 

“Markets will overbuild themselves if they believe that there’s a reasonable chance of getting return on investment and they can trust that the market scheme is going to stay the same year after year,” Morgan said. “If they think it’s going to change on them, then markets will not invest.” 

After Winter Storm Uri, the PUC cut ERCOT’s price cap down to $5,000/MWh but ordered more frequent triggering of scarcity pricing and implementation of real-time co-optimization of energy and ancillary services. Those efforts have not worked, especially with the looming need to meet data center demand, Morgan said. 

“I think we need to have something that provides the chance for people to get a return of and on their investment,” Morgan said. “We need to leave it in place. We have to have the courage to trust that it’s going to happen. If we do that, there is a ton of capital out there right now that would love to find a home and support this demand buildout.” 

Another needed regulatory fix involves the natural gas industry, which is going to become more important going forward. Morgan said. 

“I don’t think there’s a regulatory body that really holds anybody’s feet to the fire on the gas side of the business,” he said. 

The Texas gas industry suffered outages during Uri and, like the power industry, does not want to see a repeat, but regulation of its interstate pipelines is very light, he noted.  

Regulators, including FERC, have taken a more laissez faire approach to that industry, and that has its advantages, but in Texas, it is less regulation and more “advocacy,” he said 

“Nobody even batted an eye when we went from less than $3 to $300 gas during Uri,” Morgan said. “‘Ah, that’s just how that market works.’ I mean, that excuse was $8 billion of money that was basically sent through the [local delivery companies] for gas charges that occurred during Uri … and they securitized it and are paying it off over a 20-year period.” 

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Christie Blasts PJM Pursuit of Transource Market Efficiency Project

FERC Chair Mark Christie on April 17 criticized PJM for continuing to consider proceeding with Transource Energy’s Independence Energy Connection (IEC) transmission project years after Pennsylvania regulators denied it a certificate of public convenience and need (CPCN).

Christie’s comments came in his concurrence with a commission order dismissing as moot a PJM request to waive its deadline to complete an annual reevaluation of the project (ER25-612).

Should Transource “and PJM succeed in persuading a federal court that the mere selection of a transmission project planned by PJM acts to preempt the states’ CPCN laws — a position vigorously opposed by all the states as expressed by the National Association of Regulatory Utility Commissioners — such a ruling will likely be a Pyrrhic victory of monumental proportions,” Christie wrote.

“Such an outcome will tell the states, which retain the authority under their inherent police powers to decide whether to allow their utilities to join, not join or leave RTOs, that the rules of the game have been changed radically after the fact — without the states’ agreement and, as the history recounted herein shows, contrary to earlier pledges to respect state laws. So perhaps state perspectives on RTO membership for their utilities should be reconsidered.”

PJM filed the waiver request in November 2024 to ask the commission to allow it to complete its annual reevaluation of the project in the third quarter of 2025, stating that its market efficiency modeling could not be complete until reliability violations had been resolved in the 2024 Regional Transmission Expansion Plan (RTEP).

In December 2023, a federal court ruled the Pennsylvania Public Utility Commission had violated the U.S. Constitution, finding the denial was based on economic protectionism rather than siting. The court said PJM must complete a new cost-benefit analysis before the project can proceed. (See Federal Court Rules in Favor of Transource Congestion Project in PJM.)

In the absence of a FERC order by Dec. 20, 2024 — PJM’s requested effective date for the waiver request — the RTO proceeded with completing the reevaluation with the same modeling used in the 2023 evaluation, resulting in the same benefit-to-cost ratio of 0.81 as the earlier analysis. That ratio was 1.09 when sunk costs were excluded. In a presentation to the Transmission Expansion Advisory Committee in January, PJM said using older data could mask impacts affecting the project.

“Significant impacts may be presently and temporarily masked by reliability and other issues which are being addressed by RTEP projects that are expected to be approved in first quarter of 2025,” PJM said.

Comments opposing the waiver request contested the benefits of the project and argued that PJM had not followed its tariff requirements. They argued PJM staff should have recommended its Board of Managers cancel the project or have considered it canceled when the PUC denied the CPCN for construction.

The commission ruled that PJM’s completion of the reevaluation with “the presently available model” rendered the request moot.

First approved by the PJM board in August 2016, the project includes two 230-kV lines across the border between Pennsylvania and Maryland. It has been suspended since September 2021 after the PUC’s denial. The Maryland Public Service Commission approved the segments of the project running through its state in June 2020 and has issued repeated extensions on deadlines for construction to start as the litigation proceeded.

Christie Argues Ignoring CPCN Denial Would Undermine State Authority

In his concurrence, Christie wrote that it is “remarkable” the issue was brought before the commission four years after the PUC denied the CPCN for the project.

The idea that PJM planning supersedes state siting authority could undermine states’ ability to require utilities to obtain CPCNs for any projects if they remain RTO members, Christie argued.

“The claim that, because PJM and other RTOs are federally regulated, the inclusion of a PJM-planned transmission project in PJM’s RTEP effectively preempts a state’s inherent police power authority to approve that and other utility projects within its borders is, frankly, outrageous. FERC Order No. 1000, which set up the entire regional planning regime under which PJM and other RTOs now operate, said the opposite,” he wrote.

He linked the possible impact to state jurisdiction to his longstanding opposition to incentives awarded to utilities that join RTOs, saying that awarding developers construction work in progress incentives for projects included in PJM’s RTEP, but which are suspended or have been denied CPCNs, inflates consumer rates. He compared the continuation of the IEC project to PJM’s abandoned Potomac-Appalachian Transmission Highline project, which he said cost consumers a quarter of a billion dollars with no construction ever beginning. (See Christie Blasts FERC Transmission Incentives in PATH, Brandon Shores Orders.)

“As transmission costs rise rapidly in PJM, as well as in all other RTOs, it is past time for this commission to fulfill its duty to ensure ‘just and reasonable rates’ under the Federal Power Act by protecting consumers from the costs of FERC’s own policies that are inflating those rapidly rising transmission costs,” Christie wrote. “And to be more specific, as the debate continues over whether to give transmission developers/owners a perpetual [return on equity] adder for joining an RTO, the history recited herein is extremely relevant. History matters.”

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SunZia Gets Mixed Decision on Tariff

FERC on April 17 approved the non-rate terms of SunZia Transmission’s proposed transmission owner tariff but sent the tariff’s non-subscriber usage rate to a settlement process and potential hearing (ER25-170). 

Pattern Energy is developing the SunZia transmission line, a 552-mile, 500-kV DC line that will carry wind power from New Mexico into Arizona. The SunZia line, with a planned capacity of 3,021 MW, is expected to begin operations in 2026. 

SunZia plans to join CAISO’s balancing authority area as a subscriber participating transmission owner (PTO). The subscriber PTO model allows transmission developers to join CAISO without the transmission project being selected through CAISO’s transmission planning process.  

Developers of subscriber PTO projects are responsible for funding the transmission project, rather than recovering their transmission revenue requirement through CAISO’s transmission access charge (TAC). FERC approved the subscriber PTO model in March 2024. (See CAISO Wins FERC Approval for Subscriber-funded Tx Plan.) 

In the case of SunZia, the transmission system’s existing capacity has been committed to Pattern subsidiary SunZia Wind, which has entitlements with Salt River Project, Western Area Power Administration and Tucson Electric Power to send its wind power beyond SunZia Transmission’s Pinal Central terminus to Palo Verde, which connects with the CAISO system. 

In the subscriber PTO model, transmission capacity not used by subscribers is available to CAISO market participants. CAISO will pay the subscriber PTO for that usage based on a non-subscriber usage rate (NSUR). 

The NSUR in SunZia’s proposed tariff drew protests from a group of utilities — Pacific Gas and Electric, Southern California Edison, and San Diego Gas & Electric — as well as from a group of six California cities.  

One complaint about SunZia’s proposed NSUR was that it was developed using the Appalachian methodology, which came from a 1987 FERC case involving Appalachian Power Co. As described by FERC, the methodology is “premised on the assumption that a customer using the transmission system for the 16 peak hours of the day should pay the same contribution to fixed costs as a customer who has reserved capacity on a daily basis.” 

The protesters also said SunZia hadn’t provided support for an annual escalation factor of 0.5%. 

While FERC found the escalation factor to be just and reasonable, it shared the protesters’ concerns about use of the Appalachian methodology in calculating the NSUR. 

Under FERC’s order, the chief judge will appoint a settlement judge within 45 days and a settlement conference will be held to try to resolve the NSUR matter. If a settlement can’t be reached, the issue will go to an evidentiary hearing. 

Expedited Action Requested

SunZia initially filed the proposed transmission owner tariff Oct. 21, 2024, and a month later asked for a decision by Dec. 21. 

Citing its obligation to investors, lenders and customers, SunZia Transmission filed a renewed request for expedited treatment March 14, asking FERC to issue an order by April 30. 

“If the commission does not provide expedited action, SunZia Transmission will be forced to divert its resources to an alternative plan that would require it to form its own balancing authority area (“BAA”) rather than joining CAISO’s BAA,” SunZia said in the filing. 

Forming its own BAA would take several months and require “a significant commitment of resources” from SunZia, NERC and WECC, the filing said. 

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CAISO Issues ‘Expedited’ Plan for Allocating EDAM Congestion Revenues

CAISO on April 17 released a draft final proposal detailing how its Extended Day-Ahead Market (EDAM) will allocate congestion revenues in circumstances when a transmission constraint in one balancing authority area produces “parallel” flows — with resulting transmission congestion — in a neighboring BAA also participating in the market. 

The draft proposal is the product of an “expedited” stakeholder process the ISO kicked off in March to address concerns among some Western electricity market participants that EDAM would leave some non-CAISO participants exposed to congestion charges for constraints occurring outside their systems, while not providing them the ability to adequately recover or hedge against the charges. (See Fast-paced Effort will Address EDAM Congestion Revenue Issue.) 

“This proposal for parallel flow congestion revenue allocation is an initial step toward continued evolution of the overall congestion revenue allocation design informed by market operational experience and stakeholder input,” CAISO said in the proposal. 

Vancouver, British Columbia-based electricity trader Powerex first called attention to the issue in a February paper contending that EDAM’s handling of congestion revenues represented a “design flaw,” which the company identified after reviewing PacifiCorp’s proposed revisions to its open access transmission tariff intended to accommodate its participation in the market, scheduled to begin in 2026. (See Powerex Paper Sparks Dispute over EDAM ‘Design Flaw’.) 

Powerex is a firm OATT rights holder in PacifiCorp’s system, and it argued that any such transmission customer stands to lose value in its contracts under the arrangement. 

Seeking Balance

CAISO said its draft proposal seeks to strike a balance between EDAM’s existing FERC-approved rules related to congestion revenues and the alternative scheme it floated in the issue paper kicking off its expedited stakeholder initiative. 

Under EDAM’s existing rules, congestion revenues are allocated to the BAA containing a constraint, with the operator of that BAA allowed to sub-allocate any revenue it receives from the ISO to transmission customers according to the procedure outlined in that BAA’s OATT. 

“This congestion allocation method recognizes that the balancing area where the internal transmission constraint is located bears the effects of that congestion and the reliability impacts associated with the constraint, and thus congestion revenues accruing across the interconnected EDAM footprint associated are allocated fully to the EDAM balancing area where the constraint is located,” CAISO notes in its proposal. 

The ISO said many stakeholders “saw merit” in the existing design but “also recognized the concerns expressed with parallel flow congestion revenue allocation” and the need to develop a new “transitional” approach for allocating revenues “to support the ability to more readily protect or manage congestion cost exposure for OATT transmission rights holders.” 

But stakeholders also expressed concerns about the potential alternative outlined in the issue paper, which proposed to allocate congestion revenues only to the BAA in which the revenues accrued, not to the neighboring area where the constraint was located. Some commenters thought the alternative went too far in reallocating the revenues, while others worried the approach could increase incentives for some transmission users to self-schedule generation to gain a more complete hedge, which would reduce the efficiency of market operations. 

CAISO said its proposed design instead “leverages elements of the transitional alternative introduced in the issue paper and retains aspects of the current, FERC-approved, design to congestion revenue allocation; i.e., it is incremental to the underlying congestion revenue allocation methodology.” 

Under the draft final proposal, parallel flow congestion revenues collected in an EDAM BAA that result from a binding constraint in a neighboring area will first be allocated to the BAA in which the overflow congestion occurs — and the revenues are collected. That will enable that BAA to distribute funds to firm OATT transmission rights holders who possess long-term and monthly point-to-point (PTP) and network integration transmission service (NITS) rights and have submitted “day-ahead balanced source/sink schedules.” 

“Consistent with the existing EDAM design, transmission customers will register their firm PTP and NITS transmission rights, with the market operator identifying the nature of the rights from source to sink. These registered transmission rights will be associated with a contract reference number, which, when included in the bid submission, associates that bid with existing OATT transmission rights,” the proposal states. 

The plan also stipulates that any remaining congestion revenues associated with the parallel flows would be allocated to the EDAM BAA in which the constraint occurred. 

“This aspect of the design mitigates the concerns expressed by stakeholders that, under the transitional alternative described in the issue paper, balancing areas may be exposed to congestion costs (negative congestion revenues) associated with parallel flow effects when generation in the balancing area provides counter flow benefit to the direction of the transmission constraint located in a neighboring balancing area,” according to the proposal. 

Additionally, EDAM would continue to allocate any congestion revenues that accrue within the BAA containing the constraint to that BAA, “consistent with the FERC-approved EDAM framework.” 

Acknowledging “the complexity of the overall topic of congestion revenue accrual and allocation,” the proposal provides multiple illustrated examples of how the plan would work in practice. 

‘Guns Blazing’

CAISO is moving quickly to wrap up the congestion revenue allocation proposal in time for a vote next month by its Board of Governors and the Western Energy Markets (WEM) Governing Body. 

WEM stakeholders appear to be largely on board with the ISO’s sense of urgency. 

During an April 9 meeting of the WEM Regional Issues Forum (RIF) in Portland, Ore., representatives from most RIF sectors cited congestion revenue allocation as CAISO’s top priority right now, at the forefront of other issues the ISO will need to address to ensure a smooth launch of EDAM in 2026. 

“We support moving quickly in the congestion revenue allocation initiative,” Vijay Singh, senior organized markets analyst at PacifiCorp, said on behalf of the RIF’s EDAM sector. PacifiCorp will be the first utility to begin participating in the EDAM next spring. 

“We were really ready to come in guns blazing and go after the ISO for not doing more on congestion, but we really got to commend the ISO for kicking off the process and looking to go to the Board of Governors by May,” Avangrid’s Scott Olson said for the Independent Power Producers and Marketers sector. 

The Bonneville Power Administration’s Allie Mace, RIF liaison for the Power Marketing Administration sector, also commended CAISO for moving on the issue, but she noted the “transitional” nature of the proposed solution and encouraged the ISO to include an initiative for longer-term solutions in its policy initiative road map. 

CAISO will hold a stakeholder meeting to discuss the draft final proposal April 23. 

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ISO-NE Prepares Expedited Filing After Ruling on Order 2023 Compliance

The NEPOOL Transmission and Markets Committees voted April 17 to support an ISO-NE proposal to adjust several key dates and deadlines in its compliance proposal for FERC Order 2023, which the commission approved April 4. The committees also voted to support an amendment by RENEW Northeast to extend the deadline for late-stage projects to complete their system impact studies (SISs).

FERC’s ruling accepting ISO-NE’s Order 2023 compliance filing did not alter the RTO’s proposed timeline for its transition process, which includes dates and deadlines that have passed and no longer are viable. (See FERC Approves ISO-NE Order 2023 Interconnection Proposal.) To amend these issues, ISO-NE plans to file “narrowly tailored tariff revisions to only adjust transition related dates in the compliance proposal by approximately one year.”

These changes would allow the RTO to align its transitional capacity network resource (CNR) group study with the 2025 Interim Reconfiguration Auction Qualification Process — a necessary step to run the CNR study in 2025 — and start the transitional cluster study (TCS) in October.

The transitional CNR study is intended to enable interconnection customers with complete SISs to achieve capacity interconnection rights, while the TCS will be open to all other projects with valid interconnection requests. ISO-NE will use the results of the CNR study as an input to the TCS.

The RTO plans to make a Section 205 filing with the timeline changes “immediately following the May 2025 Participants Committee meeting, and request a next day effective date for the revisions to adjust the dates,” said Alex Rost, director of transmission services at ISO-NE.

Rost said ISO-NE has closed the queue again after opening it briefly on April 1 and noted that only resources with valid interconnection requests as of June 13, 2024, will be eligible to enter the TCS. The next opportunity for resources to enter the interconnection queue will be the initial cluster request window, which will open after ISO-NE completes the TCS. If the TCS begins in October 2025, the queue would be slated to reopen in late 2026.

Because the new interconnection rules already are in place — and technically took effect Aug. 12, 2024, despite FERC not ruling until April 4, 2025 — ISO-NE has stopped work on all ongoing interconnection studies under the prior rules, Rost said. He noted that “any on-hand deposits associated with an [interconnection request] that is eligible for the transition can be applied to transition studies.”

He said ISO-NE will honor any SISs completed between the official effective date and the date ISO-NE received the ruling, as these studies were completed under the rules that were in place at the time.

Abigail Krich of Boreas Renewables, speaking on behalf of RENEW Northeast, proposed to amend the expedited filing to allow late-stage requests to continue their SISs until Aug. 29, 2025.

“The only component of the ISO’s originally proposed transition that they do not propose to shift forward by [about] one year is the late-stage SIS completion deadline,” Krich wrote in a memo prior to the meeting. She noted that ISO-NE initially proposed to continue working on late-stage SISs through Aug. 30, 2024.

Krich said late-stage projects already could have spent “on the order of $250,000” on interconnection studies, which would be invalidated if the studies are not completed prior to the TCS. She said there appears to be 10 or fewer projects that could be eligible for this late-stage treatment.

“These [interconnection requests] remain eligible to enter the TCS this fall, but doing so will cost them more money, delay their interconnection and put them at risk of larger withdrawal penalties,” Krich said. She added that completing the system impact studies for as many projects as possible prior to the TCS would reduce the size, complexity and withdrawal risks of the study.

“Continuing work on the few interconnection requests that would potentially be identified as ‘late-stage’ would be a relatively small amount of work for the ISO’s interconnection team and should not take away from the ability to implement the remainder of the Order 2023 transition,” Krich added.

Developers with late-stage interconnection requests have expressed a strong interest in continuing their studies and argued it is in the region’s best interest to complete these studies to help bring new resources online as quickly as possible.

ISO-NE expressed concern about potential issues associated with reintroducing the old interconnection rules for late-stage requests, and that incorporating RENEW’s proposal into its filing could complicate the approval of its proposed timing changes.

The committee voted to support both RENEW’s amendment and ISO-NE’s proposal without the amendment. ISO-NE said it will consider its options before bringing the proposal to the NEPOOL Participants Committee on May 1.

ISO-NE also plans to work with stakeholders to make a second filing to address the series of relatively minor issues that FERC identified with its Order 2023 compliance proposal. This filing is due in early June.

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N.J. Gov. Urges FERC to Investigate PJM; Christie and Phillips Defend PJM

New Jersey Gov. Phil Murphy (D) is asking FERC to investigate “potential market manipulations” in the PJM Base Residual Auction (BRA) in July 2024 that state officials say contributed to a 20% hike in electricity rates in New Jersey. 

Murphy, in a letter to FERC commissioners, said he had “deep concerns about the PJM cost crisis.” He said he believes the “exorbitant price increases” in PJM’s July auction “may have been subject to market manipulation.” 

FERC Chairman Mark Christie defended PJM staff in comments at the monthly FERC meeting April 17. 

“A lot of this criticism that I’ve been seeing in the media, directed at PJM and its management, and blaming them for everything that is wrong with the PJM capacity market, is in many ways misplaced,” he said. “And a lot of it is because of state policies that have sort of come to a head just recently.” 

Christie particularly cited the work of outgoing PJM CEO Manu Asthana and other PJM executives. (See PJM CEO Manu Asthana Announces Year-end Resignation.)  

“Manu had the unlucky job of coming in when a lot of factors that were put in play 20 years ago sort of started to come to a head,” Christie said. “These factors, such as the big increase in load that we’ve been seeing in the last few years, the loss of resources has been ongoing for years, and all this sort of came to a head. But he has done, I think, an outstanding job. I’ve always found him to be very, very straightforward and open in dealing with me.” 

Commissioner Willie Phillips agreed with Christie. “I want to echo the comments you made about Manu and PJM leadership. I think what you said was spot on and very well said.” 

Asked whether FERC would launch an investigation, Christie said he had to be careful about commenting because the commission has pending cases dealing with the high prices from the last capacity auction. But he noted he has been a skeptic/critic of the capacity market construct since it first was launched. 

“I think that a lot of the problems that PJM is facing today are the result of trends that have been going on for 21 years,” Christie said. “And again, I’m a fact-witness to that. I’ve been there, and I think a lot of decisions were made years ago that are now showing up and causing problems for a lot of the states that are complaining the most. One of the biggest problems, I think, was 20 some years ago. They made a decision to use the PJM capacity market as their mandatory sole source of resource adequacy, and so that put them at the mercy of the PJM capacity market.” 

Many of the member states have pointed the finger solely at PJM for those problems, but Christie argued some of their state policies are to blame as well. FERC is holding a two-day technical conference in June to look at resource adequacy, where the issues will be discussed. 

Gov. Murphy’s letter urged FERC to “determine the extent to which any such manipulation may have resulted in higher capacity auction prices that are being passed on to retail electricity customers in the PJM market, particularly in New Jersey.”  

“I believe that billions of dollars in excessive costs for [consumers] are the direct result of fundamental flaws in PJM’s capacity market and were foreseeable and preventable,” the letter said. 

In response, PJM released a statement that said the organization “has not seen evidence that supports a finding of market manipulation in the 2025/26 capacity auction, but we take such allegations very seriously.” FERC’s Office of Enforcement “is the right place to address such a concern, and PJM will follow any directives we receive from FERC,” the statement said. 

“New Jersey has insufficient generation in-state to meet its needs, and has to make up this difference through imports,” said the statement, released by spokesman Jeffrey Shields. “A seven-year-long effort by New Jersey to fill this gap with offshore wind has failed to deliver any results whatsoever, and consumers are now paying the price for this failure.” 

Murphy’s statement marks a new stage in the friction between PJM and New Jersey and other states over the rapidly increasing cost of electricity and the region’s ability to generate enough power in the future. 

New Jersey and Maryland officials on April 16 attended a press conference for the release of a report by Evergreen Collaborative, a national environmental group that promotes solutions to climate change. The report predicted a 60% hike in electricity rates unless PJM takes steps to reform the process by which new clean energy sources are added. (See NJ, Md. Officials Target PJM After Critical Report.)  

Pennsylvania in January filed a complaint with FERC about PJM, which resulted in the RTO’s agreement to cap future auctions’ capacity prices. (See PJM, Shapiro Reach Agreement on Capacity Price Cap and Floor.) 

New Jersey’s draft master plan, released March 13, predicts demand for electricity will increase by 66% by 2050, and state officials are concerned about how they will meet that need. (See NJ Releases Electrification-focused Energy Master Plan.) 

PJM says the expected shortfall in power is in part due to the slow pace of new energy sources coming online compared to the far faster pace at which older generating sources — mainly fossil-fueled sources — are going offline, often in line with state policies. In addition, PJM says the region can expect an influx of high-energy-using entities, especially artificial intelligence data centers. 

New Jersey, and other states, say PJM has failed to plan for the surge and the problem is exacerbated by the slow pace at which the agency approves new energy sources, especially renewable energy sources.