FERC on July 19 approved granting voting rights to a member of American Electric Power’s board of directors who was appointed by investment firm Icahn Group (EC24-60).
The commission is required by Federal Power Act Section 203 to approve appointments of investment company officers to public utilities’ boards. AEP told FERC it had agreed in February to add Hunter Gary, Icahn senior managing director, to its board, but he was unable to vote until the commission gave its approval. Icahn, founded and controlled by investor Carl Icahn, also was able to appoint a new independent director and a non-voting observer to the board under the deal.
The commission found the arrangement met its rules around mergers; would not have any impact on competition, rates or regulation; and would not result in cross-subsidization.
Public Citizen filed a protest against the deal, arguing the non-voting board members already had forced a change of control at AEP with their role in the “involuntary termination” of former CEO and board Chair Julie Sloat. (See Interim CEO Fowke Explains AEP Leadership Change.) The consumer group argued FERC should find that the deal and subsequent firing of Sloat violated Section 203, which also requires public utilities to seek commission approval before any attempted change in control.
AEP argued it met FERC’s public interest requirements, and that Public Citizen’s “inflammatory and unsupported allegations” should be dismissed. Icahn Group itself did not execute the removal of Sloat, which was in compliance with the law and the company’s bylaws, AEP said.
FERC agreed with AEP, saying the issues Public Citizen raised “do not impact the factors addressed by the commission in evaluating” such deals. “Public Citizen does not present other evidence that the proposed transaction fails to satisfy our public interest criteria,” it said.
But the commission did chide AEP for its late request, filed March 15, after Gary already had been appointed.
“Contrary to the requirements of FPA Section 203, AEP failed to file a timely request for approval of the appointment of the Icahn Group designee to the AEP board,” FERC said. “AEP is reminded that it must submit required filings on a timely basis or face possible sanctions by the commission.”
The order drew a concurrence from Commissioner Mark Christie, who agreed the application met FERC’s policies and regulations, but that investors’ impact on public utilities is a growing area of concern that might warrant some changes in those rules.
Christie has said in other proceedings that utilities are not typical for-profit, shareholder-owned companies, and it is essential for regulators to ensure investors’ interests do not conflict with utilities’ public service obligations.
“Where there is the potential for a conflict — and there always is — it is the commission’s responsibility, under Section 203, to ensure that transactions are consistent with the public interest,” Christie said. “In my view, this must involve balancing consumer protection and potential impacts to reliability with the interests of investors in addition to evaluating traditional market power concerns.”
Christie argued that the only reason investors seek board seats on public companies is to exert influence on their decision-making and actions. Even directors “independent” of firms like Icahn take actions to benefit utility shareholders, including those who got them the position, he said.
“Investor influence on public utilities and public utility holding companies continues to grow, and in ways that may conflict with public utility service obligations. It is incumbent on the commission to account for and address this influence,” Christie said. “These issues are ripe for action, and I look forward to continued consideration of them with my colleagues.”
Commissioners Lindsay See and Judy Chang, who recently joined FERC, did not participate in the order.
The California Public Utilities Commission proposes to authorize procurement of emerging clean energy technologies with a combined nameplate capacity of up to 10.6 GW.
The decision focuses on long lead-time resources — emerging technologies that have yet to achieve economies of scale and presently are not being procured by individual load-serving entities (LSEs) in amounts sufficient to achieve cost reductions.
It would authorize procurement starting in 2026 of up to 1 GW of multiday long-duration energy storage (LDES) and up to 1 GW of 12-hour LDES to come online in 2031-2037; procurement starting in 2027 of up to 1 GW of enhanced geothermal systems to come online in 2031-2037; and procurement of up to 7.6 GW of offshore wind to come online in 2035-2037.
Lithium-ion batteries and pumped storage hydropower would not qualify for either category of LDES.
The proposal stems from Assembly Bill 1373, which was signed into law in 2023 and seeks to make it easier to procure emerging technology energy resources through centralized procurement. The Division of Water Resources would lead the procurement process.
Increasing clean energy supplies would help the state reduce greenhouse gas emissions and maintain a reliable power supply, a CPUC fact sheet states.
Other details:
Future central procurements would be assessed regularly within the integrated resource planning (IRP) process, and may consider other technologies, as well.
The 10.6 GW is a ceiling; the CPUC could follow through with smaller procurements or none, if costs are too high.
To support these efforts, the proposal suggests exploring funding streams other than customers’ electricity bills.
The longer time frame allows the opportunity to achieve cost reductions through scaling of these new technologies; while they may cost more than the dominant commercial resources that LSEs procure today, these newer technologies frequently are part of the state’s least-cost planning analysis.
The cost and risks of these centralized procurements would be spread among all LSEs — they would not be permitted to opt out.
Publicly operated utilities (POUs) may opt in, however, and the CPUC hopes they would, because they serve roughly 25% of customers in California and it is “inherently discriminatory and unfair” for them to benefit from the investments paid for by other Californians but not contribute themselves.
The CPUC said in its proposal it’s attempting to spur a market transformation, in the same manner that early investor-owned utility ratepayer investments in solar, onshore wind and battery storage in California helped bring down the cost of those technologies.
“Herein,” they write, “we are explicitly asking LSE ratepayers, through the central procurement mechanism, again to take on the responsibility for making an initial investment in several promising emerging technologies that may prove to be important for achieving [Senate Bill 100 greenhouse gas emission] reduction goals in the electricity sector, as public goods on behalf of all ratepayers under our IRP purview, regardless of their specific LSE.”
They add: “But right now, the resources we are selecting are inherently more expensive and would be unlikely to be selected in volumes high enough to lead to market transformation by an individual LSE in a least-cost procurement solicitation.”
The higher figure for offshore wind — up to 7.6 GW, all of it the more complex and expensive floating-turbine variant — is intended to show the CPUC’s interest in building a still-developing technology and nonexistent U.S. industry as a resource for California. Also, 7.6 GW is the maximum transmission capacity for the Morro Bay and Humboldt offshore wind buildout.
The D.C. Circuit Court of Appeals on July 19 rejected a wind farm’s challenge of FERC’s decision to allow SPP to charge more than $100 million for upgrades needed to connect the facility to the grid operator’s system.
In a unanimous ruling, the court found the commission’s decision to assign mitigation costs to Tenaska Clear Creek Wind to be reasonable because the project caused operational issues for SPP that would not have existed but for the facility itself (22-1059).
Clear Creek’s appeal stems from a September 2022 order in which FERC ruled that SPP correctly assigned the facility about $66 million in network upgrade costs during a restudy of a Missouri wind project. The commission denied in part a rehearing request in December 2022, although it directed the RTO to restudy the project with different planning models. (See “Split Decision for Tenaska in SPP Complaint,” FERC Rules in Three SPP Disputes.)
The network upgrade costs eventually were set at $102 million.
The appeals court said it was “unpersuaded” by Clear Creek’s challenges in its review request. The wind farm argued that FERC’s order violated its cost-causation principle; that SPP’s cost allocation was inconsistent with the commission’s “but for” policy; and that FERC ignored the RTO’s interconnection study and allocation practices used firm service when the facility was not taking service or seeking deliverability.
The D.C. Circuit said FERC was able to show its finding “comports with its precedent and the cost-causation principle,” thus proving the order was based on reasoned decision-making. It said the commission’s reasoning was “simply that the project caused operational issues for SPP that did not arise prior to its operation, so it is reasonable to assign the costs of mitigation to Clear Creek.”
The court also concluded SPP’s methodology aligns with the “but for” principle and the commission’s determination was consistent with “reasoned decision-making.”
“Substantial evidence supports the commission’s determination here that the disputed upgrades were not intended to address regional transmission planning, as opposed to interconnection, needs,” the appeals court wrote.
Finally, the court said FERC “reasonably” explained why Clear Creek couldn’t meet the burden of demonstrating that SPP’s use of firm service, or network resource interconnection service (NRIS), was unjust, unreasonable, unduly discriminatory or preferential. It said the commissioned identified precedent that was just and reasonable and that it “expertly pointed out” how Clear Creek’s NRIS request supported SPP’s justification for conducting its interconnection study at the NRIS level.
Clear Creek is a 242-MW facility that is interconnected to SPP neighbor Associated Electric Cooperative Inc.’s transmission system. The upgrade costs were assigned as part of an affected system study.
NYISO’s Business Issues and Operating committees met last week to discuss and vote on updates to the ISO’s Ancillary Services manual. Both committees approved the proposed revisions unanimously.
The revisions consist of changes to the Voltage Support Service section of the manual. “Qualification Package” was given its own subsection with clarifying language under Section 3.2, and “Identical Treatment Units,” “Testing Periods” and “Testing Coordination” were broken out into their own subsections under Section 3.6.
SIS for Cryptomining Expansion
The committee also unanimously approved the system impact study scope of a project to expand Digihost Technology’s cryptocurrency mining facility in North Tonawanda.
The facility has drawn fire from local residents for noise and air pollution. On July 16, two days before the OC’s meeting, the city’s Common Council approved a two-year moratorium on new data center operations and the expansion of existing facilities.
The controversy did not come up during the committee’s meeting. Digihost has proposed an in-service date in December, according to the scope.
The OC also approved five interconnection study reports, most of which were for solar and wind projects.
Market Reports for June
Rana Mukerji, NYISO senior vice president of market structures, presented the BIC with the monthly market performance report for June.
The average locational-based marginal price was $39.68/MWh, exceeding both May’s $28.36/MWh and the $29.85/MWh for June 2023. Day-ahead and real-time load-weighted LBMPs were higher compared to the previous month. The average daily send-out of 455 GWh/day also is up from last month and the year before. And the average year-to-date monthly cost of $40.78/MWh is 4% higher than last year’s.
Aaron Markham, NYISO vice president of grid operations, presented the OC with the monthly operations report. He said high temperatures in June resulted in higher-than-average demand for the month.
“Peak load was mitigated by demand response activations,” Markham said. “The heat moved through the state. It was hotter upstate early in the period, and then the heat moved downstate. Not having simultaneous high temperatures across the state mitigated the peak load.”
Peak load for the month occurred June 21 at 28,245 MW, about 90% of the baseline forecast, Markham said.
Batteries may be receiving excessive or inefficient bid cost recovery (BCR) payments in CAISO, an issue that could be exacerbated by the ISO’s recent move to increase its soft offer cap to allow for higher bids by storage resources.
The issue was highlighted by CAISO’s Department of Market Monitoring and Market Surveillance Committee on July 8 during the first workshop of a new Storage Bid Cost Recovery and Default Energy Bids initiative.
CAISO staff launched the effort to address concerns related to a rule change pending before FERC that would alter ISO rules related to FERC Order 831 by raising the soft offer cap from $1,000/MWh to $2,000/MWh, in part to accommodate opportunity costs and bidding strategies for storage resources. (See CAISO, WEIM Boards Approve Proposal to Raise Offer Cap.)
“BCR, as [with] many other elements of the CAISO tariff and the market, was initially designed with a thinking of conventional assets,” Sergio Dueñas Melendez, storage sector manager at CAISO, said during the workshop. “This was something that was not developed in a manner or outlined with potential new technologies that could be integrated into the CAISO market en masse, particularly with storage.”
BCR is intended to eliminate the incentive for resources to add a risk premium to their offers, which drives up bids, leading to higher overall energy costs and inefficient market outcomes. But the DMM noted that BCR payments to storage resources have materialized — specifically related to the buy- and sellback of day-ahead schedules — despite not being aligned with the intent.
“Assets might be incented to bid and operate in the [real-time] market in a manner that would trigger buy- or sellbacks of their [day-ahead] energy schedules in order to capture outsized BCR payments,” Dueñas Melendez said.
Generating units can receive BCR payments if total market revenues earned throughout the day don’t cover the sum of the unit’s acceptable bids, which includes bids for startup, minimum load, ancillary services, residual unit commitment availability, day-ahead energy and real-time energy. Because batteries don’t have startup, shutdown, minimum load or transition costs, they “lack the traditional drivers of BCR,” according to a DMM report on battery storage from July 2023.
Batteries, however, can be subject to BCR because of their opportunity costs, incurred when a battery discharges during a particular time of the day, usually from weather-related grid conditions. Discharging energy during low-demand hours, for example, could preclude discharging during hours of high demand, and the difference in market prices between low and high demand hours represents the opportunity cost of discharging in lower-priced hours.
“In the past, battery energy storage has received disproportionate amounts of BCR,” Dueñas Melendez said. “In their comments, throughout the Order 831 process of bidding above the soft offer energy bid cap, DMM highlighted once more that those changes could exacerbate the challenges that they’ve identified regarding BCR. This perspective was also echoed by the Market Surveillance Committee, who recommended that ISO staff engage with stakeholders to review and restructure current BCR provisions for batteries, particularly given the changes around Order 831.”
The July 2023 report highlighted that in 2022, batteries received nearly $30.5 million in payments, primarily in the real-time market, despite making up only 5% of CAISO’s capacity.
‘Aggressive Timeline’
Stakeholders expressed confusion about the root of the problem, specifically related to why batteries, in some cases, don’t have the state-of-charge to fulfill a schedule.
“What caused the real-time state-of-charge to put us in the position of a buyback or a sellback? Was it the result of price or modeling issues? Was it the result of not co-optimizing in real-time ancillary services? Was it because of bidding behavior, and are there rules that need to be put around that?” asked Don Tretheway, managing director of EES Consulting and representing the California Energy Storage Alliance. “I don’t think making these high-level statements helps anybody in terms of trying to understand where the solution is, especially given the speed at which you plan to make these changes.”
Stakeholders also expressed concern about the “aggressive timeline” of the initiative, which Dueñas Melendez said is on an expedited schedule because of its “sensitive nature.” Track 1, dedicated to refining BCR provisions for storage, initially gave stakeholders only three days to submit comments, but after significant pushback, the ISO extended the deadline to July 18.
“The fact that CAISO committed to working on this stuff in 2022 and didn’t do anything for two years, and now we’re going to do this in two months, it seems a little inconsistent with comments made to FERC about taking this as a priority,” Tretheway said.
Alva Svoboda, principal of market design integration at Pacific Gas and Electric, echoed the concerns.
“This is obviously a very aggressive timeline, and in my mind, it implies only one kind of solution feasible for CAISO … which is to essentially trigger periods in which batteries are not eligible for BCR and hence are completely unhedged against any price outcome in the market.”
Rather than meeting to discuss the straw proposal scheduled for publication July 17, the ISO added an additional workshop July 22 to continue working through the issue with stakeholders.
WEST PALM BEACH, Fla. — The return to demand growth in the electric power industry has been a major theme this year, and it dominated the discussion at the National Association of Regulatory Utility Commissioners’ Summer Policy Summit last week.
“We’re hearing more and more about the increase of load and demand on our system every day,” FERC Chair Willie Phillips said. “Not just regular run-of-the-mill increases. … We’re talking about sharp, material increases on our system.”
The issue varies regionally, with some areas already feeling a tighter supply-and-demand balance because of the growth in data centers, reshoring of manufacturing, electrification of home heating and transportation, and increasingly extreme weather, Phillips said.
Thousands of Houston-area customers were without power for a week at the peak of summer after Hurricane Beryl, while other parts of the country were facing major heat waves, with D.C. seeing triple-digit temperatures as NARUC was meeting.
Conservative estimates have demand growing nationally about 1%/year, which over the next five years could add up to 5,000 TWh of new demand. FERC has issued a series of major rules, including Order 2023 on interconnection and Order 1920 on transmission planning and cost allocation, that Phillips said would help the situation. Order 1920 will help expand transmission to deal with those new drivers of demand while maintaining reliability and affordability, he said.
“I know that not every commissioner in this room has embraced Order No. 1920, or 1977,” Phillips said. “Not every commissioner on FERC has embraced No. 1920.”
But the industry needs to start moving forward on planning for the future, as demand is growing, and Phillips said the order’s focus on long-term planning with a broad set of benefits will get much-needed steel in the ground.
“We have to consider grid-enhancing technologies as well,” Phillips said. “So, there is a requirement both in Order Nos. 2023 and 1920 to consider grid-enhancing technologies as we build out our system.”
Order 1920 was the subject of dissent from FERC Commissioner Mark Christie, whom Phillips called his friend from before their time as federal regulators. Phillips was on the D.C. Public Service Commission when Christie was on the Virginia State Corporation Commission, and the two neighboring state regulators regularly worked together at NARUC and the regional Mid-Atlantic Conference of Regulatory Utilities Commissioners.
Christie spoke at the conference after Phillips, and he basically agreed on the dominant theme of the event, though he framed it as reliability and said it was the states — much more so than FERC, or the ISOs and RTOs — that had the power to ensure it going forward. FERC does oversee reliability standards for the bulk power system, but it has limited authority when it comes to actually building needed infrastructure.
Section 215 of the Federal Power Act says FERC has no authority to order the construction of any utility asset, whether generation or transmission, Christie said.
“That’s the states; you are the IRP [integrated resource plan] planners,” he added. “When it comes to resource adequacy … that’s under state jurisdiction. You’re the ones who decide what generator units are going to get built. You’re the ones who decide what generator units are ultimately going to be retired.”
RTOs’ primary role is to run the system and to make sure they can balance the grid, which is important. The organized markets will say when they see trouble brewing on the reliability front; Christie said many of their communications on those lines in recent years showed a brewing crisis for the grid.
“Yesterday at 4:30, PJM peaked on this hot day; PJM peaked at about 153 GW of load. … They had 9 GW in reserve. That’s 6%,” Christie said July 16.
July 15 was one of the hottest days of the year, and despite PJM using almost all its generation to meet the day’s demand, the RTO is expecting to lose up to 50 GW in the coming years, Christie said. “That arithmetic does not work.”
Other RTOs are also forecasting retirements and seeing thinner reserve margins, which Christie said is a recent phenomenon. For most of his tenure on the SCC, Virginia’s utilities would come in with load growth projections that nobody believed because they were always flat from the previous data, and the numbers were coming at a time when PJM was very long on capacity.
That changed toward the end of Christie’s tenure at the SCC and has continued during his tenure on FERC. Virginia has been home to “Data Center Alley” for decades, and while that used to be focused around the D.C. area, it has stretched down I-95 to Richmond in recent years, Christie said.
“When you are doing load forecasts now, you’ve got to really get those things right,” Christie said. “And then you’ve got to take seriously what they are showing.”
The five-year load growth forecast doubled in one year, Gramlich said, with some regions like Dominion Virginia Power and ERCOT seeing higher load growth than the average. The new load is coming from reshoring manufacturing, data centers and electrification. Data centers alone may contribute 1% demand growth annually.
Addressing that demand growth will require enhancing the distribution and transmission systems, as well as ensuring the grid has enough energy around the clock and important reliability services like inertia and ramping, Gramlich said.
While 1% load growth does not sound like that much, it is double what had been the norm in recent years, and over time, it can really add up, said former FERC Commissioner Tony Clark, senior adviser at Wilkinson Barker Knauer. The numbers also vary significantly by region.
“This is a paradigm shift that is probably perhaps not unlike the paradigm shift we saw with fracking and availability of natural gas in terms of impact on the industry itself,” Clark said. “So, it’s a big deal.”
The new demand growth is coming at a time of traditional generators retiring, and the replacements tend to be renewables, which offer plenty of energy, but not nearly the same amount of capacity as traditional power plants, Christie said.
Clark brought up the same issues about replacing retiring generation, and he argued that no “silver bullet” exists to deal with the projected gap as demand grows.
“In all probability, to me, it looks like probably some sort of mix of natural gas and renewables in the near-term future because that’s what we have available today,” Clark said.
Other options, like long-term storage, small modular reactors or other kinds of advanced nuclear, are not immediately available, so serving the demand reliably is going to be a real challenge, he added.
The Impact of Vehicle Electrification
While forecasts always carry uncertainty, some of the load growth is already baked in, with Alliance for Automotive Innovation CEO John Bozzella saying California’s rules on vehicle mileage, which have been adopted by states representing 40% of the market, will require 35% of their vehicles be electric in the coming years.
But many consumers have started to sour on electric cars because charging infrastructure has not kept up with demand. According to AAI’s latest report, as of the first quarter this year, the U.S. had 167,213 chargers for 4.7 million electric vehicles, for a ratio of 28 to 1, while 1 million are needed by 2030 to meet projected demand.
McKinsey & Co. has found that 46% of current owners are likely to switch back to gas-powered vehicles (compared to 29% globally), and the biggest reason is the lack of public chargers, Bozzella said.
The impact on the grid of electrifying medium- to heavy-duty vehicles represents much bigger loads. Environmental Defense Fund Attorney Cole Jermyn said fleet managers are planning to transition a year or two ahead of time, which is shorter than most utility planning cycles.
“If they’re a large fleet, that’s a multi-megawatt load that, depending on the grid infrastructure, can take several years — well longer than the fleet actually knows their plan — to complete the substation, the feeder or transformers, or whatever it is that they need to actually bring their chargers online,” Jermyn said. “So, … the pace of the electrification is creating this disconnect that requires proactive efforts to prepare for.”
It is possible for utilities to proactively plan for major fleet electrification because they are in specific neighborhoods, whereas light-duty vehicles are spread around utility territories, he added.
While estimates vary for how quickly both consumers and businesses will electrify their vehicles, even the low-end predictions represent significant new loads, said Ben Shapiro, manager of RMI’s Carbon-Free Transportation team.
“Utilities understandably want to be sure, to the extent possible, that they’re going to get cost recovery,” Shapiro said. “And they don’t have a ton of incentive to be more proactive in this space under the existing paradigm.”
That requires reducing the uncertainty to improve decision-making, shifting to a more targeted approach to addressing future load growth, and finding new ways to mitigate and share risk across parties, he added.
One area that can help improve load forecasting is “vehicle telematics” that show utilities where fleets are driving and parking now to inform future charging needs, Shapiro said. Another policy that would help is ensuring that the existing infrastructure is used efficiently to help avoid overbuilding distribution system upgrades.
The federal Joint Office of Energy and Transportation, which combines the efforts of both departments on the transition to EVs, has a plan to start working on expanding electrification around the country, said Jean Chu, an analyst for the office.
“Our intention is to capitalize public and private investment to accelerate the industry activity and to signal the utility and electric utility and hydrogen market to plan and deploy the necessary generation, transmission and distribution projects,” Chu said.
The plan would prioritize areas likely to be early adopters of medium- and heavy-duty vehicle electrification first, and then link those regions together along the existing highway network. Once the biggest areas are connected in the next decade, the departments would shift their focus to electrifying the rest of the country, Chu said.
Data Center Expansion
Constellation Energy has the largest competitive retail business serving the commercial-and-industrial sector, but Chief Strategy Officer Kathleen Barrón said they do not have any better idea of what future demand will be than others presenting at NARUC.
Hydrogen was supposed to be a major driver of load growth, but issues around tax credits have at least delayed that, and the shift toward electrification has also waned in recent years. Now the latest issue is data centers scaling up as new technologies require more capacity from them. The Electric Power Research Institute released a report on data centers recently, and its forecasts vary widely, Barrón said. (See EPRI: Clean Energy, Efficiency Can Meet AI, Data Center Power Demand.)
“Some of the developers are looking at different sites for the same project, so I think that they contribute to a little bit of double counting,” Barrón said.
Data center developers are taking a page from the renewable industry, where they propose multiple projects to find out where it is cheapest to plug into the grid, with more expensive alternatives never coming to fruition.
“But in general, of course, we do see greater load growth moving forward than we have historically,” Barrón said. “So the question is, how do customers plan to meet that demand? What we’re seeing is an increasing number of them looking to power their operations with zero-carbon electricity.”
Policies are pushing the industry cleaner, but many large data center customers want to go even further and power their operations with 24/7 clean electricity, she added. Constellation can meet their demands in a variety of ways, including linking multiple large customers as off-takers under power purchase agreements with new renewables, and it also owns and operates the largest domestic fleet of nuclear reactors.
The demand for data centers needs to be met with states offering incentives to site them in their jurisdictions and the federal government seeing the issue of artificial intelligence technology as a key national security issue, Barrón said.
While AI technology is more energy intensive than traditional internet use, Briana Kobor, Google’s head of energy market innovation, noted that data centers are used every time customers surf the internet on their smartphones and are involved in huge parts of the economy generally.
“In 2020, the digital economy accounted for over 10% of U.S. GDP and [employed] nearly 8 million people,” she added.
AI might currently be dominated by chat bots and the production of “funny pictures,” but the technology could revolutionize how humanity deals with some of its biggest problems, Kobor said.
About 4% of PJM’s overall load goes to serve data centers, as it is home to a large share of the 2,700 facilities around the country, with many of them in Northern Virginia, but also other areas the grid operator serves, such as Columbus, Ohio, said Jason Stanek, the RTO’s executive director of government services.
While some of the projections could be influenced by speculative data centers, load is growing in ways that were unexpected just a few years ago. PJM is increasingly focused on figuring out exactly where the new data centers are actually going to plug into the grid, and it has surveyed the local delivery companies in its footprint to get better data in its load forecasts.
“We ask our utilities within PJM to report back whether or not we need revisions to reflect large customers coming on board,” Stanek said. “The question is whether or not these data centers are shopping around; we’ll see multiple data centers show up.”
The data PJM gets back from its member utilities will be included in a new forecast that is released in January 2025, he added.
Google agrees that there is likely some duplication in the amount of data center demand being projected, and it is important to get the numbers right; as a customer it wants to avoid overbuilding the system, Kobor said.
“We have a shared interest in making sure that we do not end up with an overbuilt system and get stranded costs at the end of this, just like any other ratepayer,” she added. “So I encourage folks to continue that conversation with us as we continue down this journey. And I think we are likely in a point of greatest uncertainty, and we’re going to start to see greater clarification as we move forward.”
Getting that clean supply from the grid can be complicated for data centers, which have a shorter development time than it takes to build new generators, interconnect them to the grid and expand transmission to deliver new power to load, Barrón said. That has driven interest in data centers and other large customers to link up directly to nuclear plants and avoid using the grid altogether.
The issue of data centers connecting directly at nuclear plants is pending in a case at FERC, in which Constellation has intervened to argue that the commission should let such deals happen — though others have said it could bring up issues around cost shifting and eventually even reliability. (See Talen Energy Deal with Data Center Leads to Cost Shifting Debate at FERC.)
Locating at nuclear plants also avoids “NIMBYism” because they are always built on large swaths of land. Such deals also avoid building out the transmission and distribution systems to accommodate major new loads, avoiding socializing those costs to other customers.
Nuclear plants benefit from a tax credit that has prevented more retirements, but that is going to sunset in eight years, and forecasters expect nuclear retirements will resume when it does, Barrón said.
“If you have a customer that was willing to commit to long term, you wouldn’t have to be concerned about that,” she added.
The Bonneville Power Administration is ramping up its engagement with the West-Wide Governance Pathways Initiative, an executive with the federal power agency said July 18.
That means BPA will shift from a previous stance of mostly monitoring developments in the Pathways Initiative to fully participating in its looming efforts to change California law to relax some provisions of CAISO’s state-run governance and shape a new “regional organization” (RO) to oversee a Western electricity market based on the ISO’s Western Energy Imbalance Market (WEIM) and Extended Day-Ahead Market (EDAM).
However, the stepped-up involvement in Pathways doesn’t signal a change in BPA staff’s “leaning,” issued in April, recommending that the agency choose SPP’s Markets+ over EDAM when it opts to join a day-ahead market, according to Doug Marker, an intergovernmental affairs strategist at BPA. (See BPA Staff Recommends Markets+ over EDAM.)
“This does not represent a change in our staff recommendation, nor an endorsement of EDAM or the Pathways conclusions, but we feel it’s important to be involved to understand the issues that are shaping the structure of Pathways,” Marker said during a BPA day-ahead markets workshop.
“At the end of the day, should this be successful — and obviously we share the objective for bringing independence to CAISO market governance — we will have customers who are served through the markets that are governed through this process, and we will at least be a neighboring entity for the market,” he said.
Marker said BPA declined to participate in Step 1 of the Pathways effort, which crafted a plan to elevate the authority of the WEIM’s Governing Body to the greatest extent possible without altering California law, because it was heavily involved in drafting a tariff for Markets+. SPP filed the proposed tariff with FERC in late March. (See SPP Files Proposed Markets+ Tariff at FERC.)
BPA is expanding its engagement just as Pathways begins to pursue parallel “work streams” in Step 2 of its effort. (See Busy Summer Ahead for Pathways Initiative.) Marker said the agency assigned staff to four of the initiative’s six newly created workgroups, including those dealing with CAISO tariff analysis, stakeholder processes, RO governance and public interest issues, “which is really talking about the role of a states committee and possibly consumer advocates in the governance structure for the RO.”
“We’ve said we want two viable options, and so we are participating from the perspective of improving the viability of the EDAM alternative,” he said.
‘Material Difference’
Marker said it’s important to BPA that Pathways’ discussions “be done as transparently as possible,” echoing a criticism that some stakeholders have shared with RTO Insider: that much of the effort has been developed in closed-door meetings, punctuated by monthly public progress reports. (Pathways participants have pointed out that all votes by the group will be held publicly.)
“So, we urge the Pathways’ Launch Committee to make the workgroup meetings open. It was a decision for us to participate even if the meetings are not open, but we think that the open meetings improve the transparency and the ultimate strength of the proposals that emerge from it,” Marker said.
That last comment prompted a sharp response from Launch Committee Co-Chair Pam Sporborg, director of transmission and market services at Portland General Electric.
“I’ll note that Pathways is not a decision-making body,” Sporborg said. “We’re a temporary volunteer group that is coming together to suggest ideas and concepts to formal decision makers across the west, to the CAISO board, California elected officials and to the broader West. We’re not drafting a tariff like Markets+. We’re not a formal stakeholder process. We have turned over our recommendations to that formal [CAISO] stakeholder process, which is ongoing, as you noted.”
Sporborg pointed out that BPA has participated in efforts with a similar process of public and non-public meetings, such as the Western Power Pool’s Western Resource Adequacy Program (WRAP) and Western Transmission Expansion Coalition (WestTEC).
“It seems interesting to call out Pathways uniquely, given that Bonneville’s participation in those other structures that really have a steering committee focus and do hold those kinds of private coordinating meetings with separate and intentional opportunities for public engagement,” she said.
BPA Director of Market Initiatives Russ Mantifel, who’s been leading the agency’s day-ahead markets process, countered that he thinks the process for developing Markets+ was transparent from the beginning, with publicly noticed meetings and open invitations to any concerned parties.
“In terms of WRAP and WestTEC, I don’t think it’s Bonneville that is asking for those things not to be public. In addition to [the Western Markets Exploratory Group], as well, we were open to everything being open,” Mantifel said, adding that Bonneville is required to be transparent and that “raising the bar” on transparency “is what we should be doing.”
“I also think that the Pathways Initiative is explicitly trying to develop a market that will set the prices for every consumer in the Western Interconnection,” he continued. “At least that’s what we’ve heard: that the goal is to create a single market and the benefits are assuming a single market that’s serving load to every retail load in the West. So, I think that that is a material difference.”
CARMEL, Ind. — MISO’s $25 billion, mostly 765-kV long-range transmission package for the Midwest region is nearing finalization, while the Independent Market Monitor continues to doubt the necessity of the projects.
The Monitor is penning a memo spelling out his concerns with MISO’s assumptions behind its long-range transmission planning.
Despite that, the lines are advancing to MISO’s business case testing, where they will be analyzed against its nine benefit metrics. MISO will release the business case for the portfolio in September.
“The benefits metrics process has been well reviewed,” Executive Director of Transmission Planning Laura Rauch told the Organization of MISO States’ board of directors July 16. She said MISO solicited extensive stakeholder feedback and is “fairly comfortable” with the metrics it is advancing.
Rauch said MISO will hold multiple workshops with stakeholders to go over the business case for the new batch of LRTP lines.
“We’re at the stage, using an airplane analogy, where we’ve landed and we’re on the tarmac,” Director of Economic and Policy Planning Christina Drake told stakeholders on a July 17 teleconference.
MISO has yet to factor in the cost of underbuild projects into the second LRTP portfolio.
Drake said MISO’s first, $10 billion LRTP portfolio in MISO Midwest minimized the need for underbuild projects to support the second portfolio. MISO uses the term “underbuild” for the secondary, lower-voltage transmission upgrades necessary to support a 765-kV network in the Midwest region without worsening existing constraints.
This month, IMM David Patton said he scheduled meetings with MISO planners to outline his concerns with the metrics, though he acknowledged little progress on a compromise.
“I don’t think the MISO board understands how serious these concerns are,” Patton told the Board of Directors’ Markets Committee on July 11. “We haven’t seen a lot of movement to address either the concerns on the [second transmission future] — which we view as very unrealistic — or MISO’s benefits process.”
Patton said he remains hopeful MISO is open to altering its project portfolio to assemble the “most least-regrets” collection of transmission projects.
He called MISO’s second transmission planning future “completely inconsistent” with its new, availability-based capacity accreditation and its invitation for members to develop resources with more steadfast attributes.
MISO is using its second transmission planning future as a basis for this LRTP portfolio. It assumes that by 2042, the RTO will manage 466 GW of installed capacity with a fleet that emits 96% less carbon pollution than it did in 2005 and have a 145-GW peak load that occurs in January rather than July.
Patton said MISO’s goal of least-regrets transmission planning is possible only when it uses “valid benefit metrics and explores the gamut of possible futures.”
MISO has proposed using nine benefit metrics to establish a benefit-to-cost case for the portfolio, including avoided capacity costs, capacity savings from reduced line losses, congestion and fuel savings, reduced transmission outage costs, energy savings from reduced losses, lower risks during extreme weather, mitigation of reliability issues, avoided transmission investment and decarbonization.
Patton has said it’s not appropriate for MISO to place a value on decarbonization when the government already does through tax credits. He also has said the RTO should not presume the lines will save members money on additional capacity that otherwise would have to be built.
At the workshop, MISO was adamant the second LRTP portfolio will accommodate Midwest members’ fleet transition plans and load growth.
MISO said on a 20-year horizon, the Midwest also should see $3.2 billion in adjusted production cost savings, an 8.5% (20.4 million MWh) reduction in curtailment, savings to the cost of serving load and decreased price separation. The RTO also said LRTP II resolves 60% of the Midwest’s 200-kV and above constraints that could trigger contingencies and more than 70% of thermal violations for all voltage levels.
The Louisiana Public Service Commission in session in June | Louisiana PSC
Xcel Energy’s Drew Siebenaler said his utility’s ambitions now more closely resemble MISO’s third, 20-year transmission planning future, not the second. He asked whether MISO would test the second LRTP portfolio against its most aggressive, third planning future, as rapid load growth and fleet transformation have made it appear the most probable.
Drake said MISO remains committed to testing the second portfolio against the “low-end bookend” and using the second transmission planning future. But the RTO is aware the portfolio will not enable all the generation contemplated in the future. She said that’s why MISO will pursue a companion portfolio next year, with proposed lines likely popping up in the western portion of MISO Midwest.
La. and Miss. Regulators Open Offensive Against Order 1920
Meanwhile, Louisiana and Mississippi state regulators have called on the 5th U.S. Circuit Court of Appeals to examine FERC’s recent landmark transmission planning rule.
Attorneys for the Louisiana Public Service Commission and Mississippi Public Service Commission filed a petition for review July 15 of FERC’s Order 1920 (24-60355).
Both state commissions claimed they are “aggrieved” by the order, which requires transmission providers to conduct transmission planning on 20-year horizons every five years.
Louisiana and Mississippi, both part of MISO’s South region, have not been the focus of MISO’s LRTP planning efforts yet. The RTO so far has proposed only multibillion-dollar LRTP portfolios for its Midwest region. MISO, clean energy groups, MISO South state regulators and Entergy disagree over how LRTP cost allocation should be handled in the South. (See related story, Clean Energy Orgs Push Entergy Players to Consider Broader Cost Allocation.)
Below is a summary of the agenda items scheduled to be brought to a vote at the PJM Markets and Reliability Committee and Members Committee meetings July 24. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will be covering the discussions and votes. See next week’s newsletter for a full report.
Markets and Reliability Committee
Consent Agenda (9:05-9:10)
B. Endorse proposed conforming revisions to Manual 12: Balancing Operations to implement provisions of a package to establish fuel assuredness requirements for black start resources approved by stakeholders last year. The changes would add two exemptions from penalties for fuel-assured black start resources that fall below their minimum fuel inventory due to capacity calls or storage inspections, as well as reworking the verification process. The revisions being voted on July 24 were inadvertently left out of the language approved last year despite being included in the approved package matrix. (See “Stakeholders Endorse Revisions to Manual 12 for Black Start Fuel Requirements,” PJM OC Briefs: July 11, 2024.)
C. Endorse proposed revisions to Manual 13: Emergency Operations drafted through the document’s periodic review. The changes clarify communication processes between RTO control rooms, adding language that local load shed directives do not initiate a performance assessment interval (PAI), and remove member actions stating that gas generation owners should notify PJM of whether they have or plan to procure fuel to meet day ahead reserve commitments.
Endorsements (9:10-10:50)
1. Enhanced Know Your Customer (9:10-9:30)
PJM’s Anita Patel and Eric Scherling will present more stringent “know your customer” requirements that would require some members to provide more information about key decisions makers, owners and beneficiaries. The proposal was endorsed by the Risk Management Committee on May 21. (See “First Read on Expanded ‘Know Your Customer’ Rules,” PJM MRC/MC Briefs: June 27, 2024.)
The committee will be asked to endorse the proposed solution and corresponding tariff revisions.
2. Performance Impact of the Multi-Schedule Model in the Market Clearing Engine (9:30-9:50)
Constellation Energy’s Adrien Ford is set to make a motion for the committee to endorse a joint PJM/GT Power Group proposal to establish a formula to select one offer into the energy market for each resource to be forwarded to the Market Clearing Engine (MCE). The proposal is intended to facilitate PJM’s goal of implementing multi-schedule modeling without causing a significant increase in MCE computation times. The proposal to be voted on July 24 was turned down by the MRC in December when the committee endorsed a different PJM proposal, which ultimately was rejected by FERC. (See “Stakeholders Discuss Path Forward on Multi-Schedule Modeling,” PJM MIC Briefs: June 5, 2024.)
The committee will be asked to endorse the proposed solution and corresponding revisions to the tariff and Operating Agreement.
PJM’s Emily Barrett will present two proposals to rework how PJM determines its reserve procurement targets and how those resources are deployed. The first would replace the static 3,000-MW 30-minute reserve requirement with a formula that takes load forecasting, forced outage rates, the largest active gas contingency and the primary reserve requirement into account. It also would permit PJM to increase the 30-minute, synchronized or primary reserve requirements independently of the other two. The second proposal would send reserve deployment instructions through resources’ basepoints as the primary notification that they are being called on to provide reserves. (See “First Read on 2 PJM Proposals to Revise Reserve Markets,” PJM MRC/MC Briefs: June 27, 2024.)
The committee will be asked to endorse the proposed solutions and corresponding tariff, Operating Agreement and manual revisions.
4. Enhancements to Deactivation Rules (10:10-10:30)
Philip Sussler, of the Maryland Office of People’s Counsel, and Clara Summers, of the Illinois Citizens Utility Board, will present amendments to the Deactivation Enhancements Senior Task Force (DESTF) issue charge to expand its scope to include proposals that create more cost-effective alternatives to reliability-must-run (RMR) contracts, which are offered to generators whose requested deactivation would prompt transmission violations. The widened scope also includes education about alternative transmission technologies that could allow violations to be resolved faster and processes in use by other grid operators. (See “Consumer Advocates Seek Wider Scope for Deactivation Task Force,” PJM MRC/MC Briefs: June 27, 2024.)
The committee will be asked to approve the amended issue charge.
5. Review and Endorsement of IRM and FPR Results for 2026/27 Delivery Year (10:30-10:50)
PJM’s Josh Bruno will present revised installed reserve margin (IRM) and forecast pool requirement (FPR) values for the 2026/27 delivery year to reflect market design changes made since the 2023 Reserve Requirement Study (RRS) was completed. Drafted through the Critical Issue Fast Path (CIFP) process last year, the market changes include accrediting nearly all resources through a marginal effective load carrying capability (ELCC) approach and alterations to the IRM and FPR formulas.
The committee will be asked to endorse the IRM and FPR results upon first read at this meeting. Same day endorsement may be sought at the Members Committee. (See “Stakeholders Endorse Revised RRS Values,” PJM PC/TEAC Briefs: Feb. 6, 2024.)
Members Committee
Endorsements (2:40-3:00)
Bruno will present revised installed reserve margin (IRM) and forecast pool requirement (FPR) values for the 2026/27 delivery year.
The committee will be asked to endorse the new figures upon first read.
CARMEL, Ind. — A band of Michigan utilities wants the option to decline MISO’s affected system-style studies on distributed energy resources, arguing the RTO’s studies create an unnecessary layer of bureaucracy and hinder DER expansion.
Consumers Energy, DTE Energy, ITC Holdings and Wolverine Power approached MISO at the July 17 Planning Advisory Committee, asking for an opt-out provision on the RTO’s affected system studies for DER additions that might impact the transmission system.
Wolverine Power Vice President of Regulatory Affairs Tom King said the Michigan-based parties believe MISO’s DER affected system study process limits efforts to integrate DERs on the grid.
Last year, MISO decided it would evaluate the need for a review of DERs when they can inject 5 MW of power at the substation level during system peak load and if they can force a 1% change in line loading. Transmission owners screen for the 5-MW injection capability, while the RTO ascertains whether the DERs could influence a 1% line-loading change.
At a July 17 Planning Advisory Committee meeting, King said MISO’s DER affected system study process and fee requirements “are burdensome, duplicative of the more comprehensive existing TO studies, create unnecessary costs and have the potential to significantly limit DER deployment.” He said TOs already study the potential for DERs to worsen thermal and voltage issues that MISO tests for. He added that TOs’ studies in many cases are superior to MISO’s.
Transmission owners pay a $60,000 study deposit to MISO per substation that is required to be studied for DER impacts. MISO refunds any portion it doesn’t use for the studies.
“MISO obviously has a fee to perform these studies, which has to be coordinated with the TO and then coordinated or not coordinated with the DER,” King told stakeholders.
King said the Michigan utilities developed their opt-out recommendation with help from Michigan Public Service Commission staffers. He asked that MISO treat DERs as load-serving additions or changes, not as generation that causes third-party impacts to the MISO system. That way, King said MISO could view DER additions as end-user facilities seeking to make “qualified changes” under its facility interconnection studies process.
MISO could step aside for transmission owners to perform their more extensive thermal and voltage analyses, King said. He said TOs would continue to “carefully evaluate trickle-up impacts” on the transmission system by DERs and notify MISO of impacts when they submit a transmission upgrade as part of the RTO’s annual Transmission Expansion Plan to mitigate added stress on facilities.
King said he’d like MISO and stakeholders to prepare an opt-out provision as soon as this fall. He said there’s considerable support for DERs in Michigan, with new legislation designed to encourage more of them. He said that trend is likely to occur in other jurisdictions in the footprint.
Last year’s Michigan Clean Energy and Climate Action package contained a provision to raise utilities’ distributed generation program caps from 1% to 10% of their in-state peak load average of the last five years. King said prior to the legislation, utilities were outstripping the 1% limit.
King also noted that the EPA recently awarded Michigan $156 million to reduce the cost of community and rooftop solar projects for low-income households and that Democratic Gov. Gretchen Whitmer’s “MI Healthy Climate Plan” recommended utilities “increase options for customer-driven renewable energy, such as rooftop solar and voluntary green pricing programs.”
