Arizona Corporation Commissioner Kevin Thompson on Jan. 24 said he thinks his state’s four major utilities may have erred in committing to joining SPP’s Markets+ instead of CAISO’s Extended Day-Ahead Market (EDAM).
Thompson shared his views during a California Energy Commission workshop exploring the impacts on California of the West-Wide Governance Pathways Initiative’s effort to create an independent “regional organization” (RO) to provide governance to CAISO’s EDAM and Western Energy Imbalance Market (WEIM).
In a joint announcement issued last November, Arizona Public Service, Salt River Project, Tucson Electric Power and UniSource Energy Services said they planned to start participating in Markets+ in 2027, citing the potential to realize a combined $100 million in benefits from the market. (See 4 Arizona Utilities Commit to Joining Markets+.)
Speaking during a panel featuring four Western utility commissioners who signed the July 2023 letter launching the Pathways Initiative, Thompson said he urged his state’s utilities to delay their decisions until developments played out around the initiative’s “Step 2” plan, which include an effort this year to pass a bill in California authorizing CAISO to both hand off its oversight of market rules to the proposed RO and participate in the new entity.
“I think Arizona’s utilities jumped the ball a little bit,” Thompson said. “I think they jumped out there ahead of their skis, and I asked them if they would just allow this to work itself through and see where it ends, because this could be the next best thing since sliced bread. You won’t know if you don’t see it through.”
As a publicly owned utility, SRP is not subject to the jurisdiction of the ACC, while the state’s investor-owned utilities have a relatively free hand in deciding on a day-ahead market. APS, SRP and TEP all currently participate in the WEIM but have been firm supporters of the development of Markets+ as an alternative to the EDAM, in large part because of their concerns about CAISO’s state-controlled governance framework.
New Mexico Public Regulation Commissioner Pat O’Connell echoed Thompson’s comments, saying, “It will be interesting to see if we can overcome this governance issue” and questioned “how well those [Arizona utility] decisions will age.”
“As the economic studies suggest, not well,” O’Connell said, referring to the series of economic studies published over the last year showing most Western utilities would financially benefit more from a single electricity market that includes California than in a scenario in which the region is divided into two markets.
Among those studies was a Brattle Group analysis showing that New Mexico’s utilities would realize greater savings from EDAM even if their larger Arizona neighbors joined Markets+, a finding that prompted Public Service Company of New Mexico (PNM) to commit to the CAISO market. (See Brattle New Mexico Study Shows EDAM Benefits Outpacing Markets+ and PNM Picks CAISO’s EDAM.)
“One of the things you learn by working in the planning world is that — especially in electricity — it’s least-cost if we can share” resources, O’Connell said, referencing his past experience working for utilities, including PNM.
O’Connell pointed out that New Mexico’s potential for developing both wind and solar resources is much larger than its energy demand, which means that “it has a lot to a lot to contribute to California in terms of providing low-cost wind resources.”
“All those things were in my head when we gathered together and started talking about, ‘How can we create the broadest possible footprint for regional coordination?’ And that immediately made sense to me: that that is something worth pursuing,” he said.
None of the Arizona utilities responded to a request for comment on the commissioners’ statements.
Regardless of the direction the Arizona utilities take, Thompson said he is “committed to staying on” with Pathways, an effort he likened to the drafting of the Declaration of Independence.
While acknowledging Markets+ supporters’ concerns that CAISO could have continued outsized influence within the new RO, Thompson expressed hope that Pathways participants can address that when they embark on the effort’s “Step 3” process to refine the RO and possibly broaden its authority.
“As the states and the stakeholders continue to work through Step 2 and move to Step 3, I think you’re going to see a lot of the details work themselves out,” he said.
“This is something that was built from the ground up,” he continued. “You know, it would have been too easy to follow a PJM model or the other models in the north and the east. We’re not PJM; we’re not the east. We’re the West, and we’re unique in that.”
FERC on Jan. 24 issued an order terminating its proceeding on the consideration of greenhouse gas emissions in natural gas infrastructure project reviews (PL21-3).
“Having thoroughly reviewed that record, we are now withdrawing the draft GHG policy statement and closing that proceeding,” FERC said. “We find, based on the record that has been developed, that the issues addressed in that proceeding are, in general, better considered on a case-by-case basis, when raised by parties to those proceedings, as the commission has done following the issuance of the draft.”
The proposed policy statement dates back to former Chair Richard Glick’s tenure, and opposition to it from former Sen. Joe Manchin (I-W.Va.) helped sink his re-nomination. FERC did not move forward on the draft for the rest of President Joe Biden’s term, during which Commissioner Willie Phillips served as chair. (See Glick’s FERC Tenure in Peril as Manchin Balks at Renomination Hearing.)
FERC had issued the policy statement in February 2022, explaining it would presume projects with estimated GHG emissions of at least 100,000 metric tons of carbon dioxide equivalent per year will have a significant impact on climate change — requiring that the commission conduct an environmental impact statement — unless the developer can rebut that presumption with evidence. The policy was strongly opposed by Republican Commissioners James Danly and Mark Christie (the latter of whom became chair Jan. 20).
But a month later, FERC walked back the policy, labeling the statement as a draft and inviting comments on it, on top of the tens of thousands of comments it already received when it issued its Notice of Inquiry the year before. (See FERC Backtracks on Gas Policy Updates.) The commission simultaneously did the same thing with a separate statement that updated its 1999 policy on granting gas pipelines certificates of public convenience and necessity. That docket began with an NOI issued in 2018 and was only mentioned in last week’s brief order (PL18-1).
All three Democratic commissioners — Phillips, David Rosner and Judy Chang — wrote a joint concurrence, saying that since they have been on FERC, they have followed the law when evaluating applications for natural gas infrastructure.
“The consideration of greenhouse gas emissions in our review of natural gas infrastructure projects has been one of the most challenging issues before the commission for several years,” they said. “The extent to which the commission must account for the project’s GHG emissions and in turn the impacts on global climate change has been debated and litigated at length before the commission and the courts.”
The courts have continued to hand down rulings on cases that implicate FERC’s environmental reviews of gas infrastructure, including remanding cases in which they find its analysis lacking, the Democrats said.
While the policy statement is being dropped, the three commissioners said it has provided information that has proven useful for FERC as it developed its current, bipartisan case-by-case approaching to reviewing the climate impacts of natural gas infrastructure.
FERC’s approach to GHGs has evolved, and in complying with the National Environmental Policy Act, it estimates reasonably foreseeable emissions attributable to a proposed project; provides a qualitative discussion on potential adverse impacts from those emissions; compares them to state or national levels; and calculates monetized values, the commissioners said. FERC also expects developers to evaluate technically and economically feasible strategies to cut emissions during construction and operation.
“All of our colleagues have joined us on orders using this approach to comply with our NGA and NEPA obligations,” the Democrats said. “Critically, the courts have upheld it. If this approach is continued, it will provide more certainty for all parties and stakeholders, fulfill the commission’s obligations to consider environmental impacts in its decisions and inform the public regarding the basis for those decisions.”
FERC on Jan. 24 approved CAISO’s tariff revisions related to real-time bid cost recovery rules for energy storage resources.
The ISO sought revisions on the grounds that the existing bid cost recovery structure allowed for unwarranted compensation at higher value than actual costs, creating an incentive to bid in a manner that would result in excessive payments (ER25-576).
Without the tariff changes, CAISO said, “scheduling coordinators for storage resources may exploit market buy-backs and sell-backs through strategic bidding to inflate bid cost recovery payments even more.”
From January 2022 to September 2024, storage resources received bid cost recovery payments totaling $58 million, CASIO told FERC, most of which reflect real-time cost recovery payments.
This is a much higher portion of bid cost recovery payments compared with the portion of energy that they provided to the grid, CAISO said. It said a 2024 report by its Department of Market Monitoring (DMM) found numerous situations where storage resources might receive inappropriate bid cost recovery payments.
CAISO indicated that storage is a rapidly growing energy sector — battery resources participating in CAISO markets expanded from about 500 MW in 2020 to more than 10,000 MW in October 2024, with 3,500 MW of it in the Western Energy Imbalance Market.
In comments to FERC, DMM said it did not oppose the tariff revisions as a temporary short-term measure because they would limit inappropriate payments and limit the potential for gaming the bid cost recovery rules for batteries.
DMM said it supports CAISO’s continued effort to further refine the rules through a new stakeholder initiative, but said these changes by themselves are insufficient because they address only the bid-cost component of the bid cost recovery calculation, which reduces gaming potential but does not address inefficient bidding incentives created by the revenue portion of the calculation.
As such, DMM said, the tariff revisions do not address the core problem: that the payments remove storage resources’ exposure to real-time opportunity costs, creating incentives that can lead to inefficiencies and reliability issues. It said it hopes CAISO will promptly propose additional changes that will address this.
In its Jan. 24 order, FERC accepted the proposed changes effective Dec. 1.
It wrote:
“We find that the revisions can help mitigate the magnitude of unwarranted or inflated bid cost recovery payments to storage resources, especially in real-time.”
“With respect to bid cost recovery related to incremental energy, we find CAISO’s proposal to use the lower of a resource’s real-time energy bid or proxy (the maximum of a resource’s day-ahead LMP, real-time market default energy bid or real-time LMP for that interval) provides a reasonable representation of the operational nature of storage resources.”
“With respect to bid cost recovery related to decremental energy, we find CAISO’s proposal to use the greater of a resource’s real-time energy bid or (the minimum of) the aforementioned proxies better reflect the costs of providing decremental energy.”
FERC wrote that some of the “core problems” DMM cites are beyond the scope of the proceeding but added that it found CAISO’s proposal a reasonable first step to mitigating real-time bid cost recovery payments. And it encouraged the efforts by CAISO, DMM and stakeholders to further refine the tariff.
TEMPE, Ariz. — The Western Power Pool faced “real potential weaknesses” in 2024 due to staff shortages and outdated financial and accounting systems that needed to be addressed quickly, the organization’s leadership said during WPP’s annual member meeting in Tempe on Jan. 24.
Following the WPP’s Board of Directors approval of a 13% budget increase — from approximately $13.4 million to $15.3 million — for the 2024/25 fiscal year, the organization embarked on a hiring spree to improve operational oversight and meet future challenges, WPP CEO Sarah Edmonds said during the meeting.
The new hires include a chief financial officer, board administrator, human resource manager, program management analyst, technical trainer and graphics designer. Edmonds said WPP also modernized its finance and accounting practices by moving from manual spreadsheets to automated systems.
“We do need to keep adding people, but not at the scale of last year,” she added. “That was a serious and somewhat urgent investment for some areas of real potential weaknesses that we needed to address quickly.”
WPP coordinates six stakeholder-driven programs aimed at improving the power grid in the West, including the Western Resource Adequacy Program (WRAP) and Western Transmission Expansion Coalition (WestTEC). All these programs have experienced growth in scope and regional expansion at a time when WPP’s “house wasn’t really properly in order,” Edmonds said.
Edmonds also acknowledged that WPP historically has not been as transparent as it should be.
However, the efforts to boost staffing and modernize WPP’s financial structure have paid off, according to board Chair Bill Drummond. He noted that WPP “has been almost like a startup in many respects. It has scaled up to such an amazing degree.”
Moving into 2025, Drummond said the financial and accounting systems are “in great shape now. Got that where it needs to be.”
Edmonds said cybersecurity is the next target area. She noted that’s an area not unique to WPP and has been underinvested in “given the kinds of threats that are out there on the system today. So that’s up next, and we’ll stay always nimble and vigilant.”
WASHINGTON, D.C. ― Karen Harbert, CEO of the American Gas Association, was the first to speak at the U.S. Energy Association’s 21st Annual State of the Energy Industry Forum and set a jubilant tone for the fossil fuel leaders at the Jan. 23 event at the National Press Club.
“We’re the cool kids now,” Harbert said. “We have to go first.”
An ongoing cold snap in the Midwest and East Coast has meant record use of natural gas, she said.
“We are the biggest part of the power generation fleet right now. We’re over 40%, and that’s going to continue to grow with the onset of data centers, advanced manufacturing and strategic industries. So, gas is back. … We’re popular, we’re affordable, we’re efficient and we’re clean.”
Coming three days after President Donald Trump began his second term with a flurry of executive orders promoting a major increase in U.S. fossil fuel production, the event reflected the quickly shifting landscape of national energy policy and the resulting shift in industry priorities and narratives. (See What is and isn’t in Trump’s National Energy Emergency Order.)
All-of-the-above strategies for meeting the exponential demand growth from artificial intelligence and megawatt-guzzling hyperscale data centers were a key theme at the day-long event, as was the desire for “durable,” bipartisan legislation to streamline and accelerate permitting.
No one mentioned climate change, or even Biden’s signature climate legislation, the Inflation Reduction Act, at least not by name.
Like Harbert, the CEOs of all the major fossil fuel trade associations exuberantly staked out their claims as preferred providers of the reliable, affordable, “clean” (or at least “cleaner”) power that data centers and U.S. consumers need. Leaders of renewable energy groups ― solar, hydropower and nuclear ― argued for their essential role in the diverse, carbon-free energy mix the high-tech hyperscalers want.
Mike Sommers, CEO of the American Petroleum Institute, began his pitch by noting that no one on the forum’s first panel had mentioned the words “energy transition.”
“We’re at a moment today where we’re transitioning from the energy transition to energy reality, and energy reality is that all of us are going to be using a heck of a lot more energy in the future, particularly in the developing world,” Sommers said.
The U.S. is best positioned to meet that global demand because of its “strong regulatory structure,” he said. “We produce oil and gas cleaner than any other country in the world.”
Michelle Bloodworth, CEO of America’s Power, the coal industry’s trade association, talked up the value of coal’s ability to deliver power in extreme weather events “because it has 90 days of onsite fuel. It’s hard to beat this onsite fuel when it’s really, really cold.”
But even Bloodworth said support for coal “doesn’t mean that we don’t support wind and solar. Again, we need them all. We need to keep all the existing resources that we have until all this new generation” comes online.
Renewables Retrench
Jason Grumet, CEO of the American Clean Power Association, led the retrenchment of renewables, dissociating his organization from former President Joe Biden’s goal of a 100% decarbonized grid by 2035. It was, he said, “a narrative that was not our own.” He and others pointed to a combination of natural gas and renewables as a likely and pragmatic way forward.
“The notion that molecules and electrons actually have political affiliation” needs to be set aside, Grumet said. The challenge and opportunity before the industry is to “show what it’s going to take to meet this demand in the time frame we need it.”
“Every technology has strengths and weaknesses,” Grumet said. “The ability to build renewables fast is one of those strengths; intermittency is one of those weaknesses, and that’s why we have to be combined … to come up with a rational policy.”
Abigail Ross Hopper, CEO of the Solar Energy Industries Association, said she would not support a 100% solar-powered electric system primarily because the U.S. should not be dependent on any one source of power.
Like Grumet, she talked about the speed and scalability of installation that solar brings to the table, but also the reliability benefits of distributed as opposed to centralized generation.
Distributed “makes a ton of sense” for addressing congestion on the grid, Hopper said. “Adding solar plus storage, other kinds of storage … that gives the grid more resiliency; that gives so [many] different ways of getting around outages. That allows consumers, if you have [solar] at your home, to be more secure.”
Rich Powell, CEO of the Clean Energy Buyers Association, stressed the role that data centers and other large energy consumers in his organization now play in the energy landscape, with their commitments to carbon emissions-free energy.
CEBA’s definition of emissions-free covers a broad range of technologies, from wind and solar to carbon capture and sequestration, making the group’s collective economic impact potentially significant, Powell said.
CEBA’s 400 members represent about $22 billion in market capitalization and 10% of all U.S. energy demand, providing significant demand and market signals, he said. An upcoming CEBA report will “sum up all the remaining demand signals for carbon emissions-free electricity in the United States alone, as part of an attempt to help grid planners who are thinking about new transmission that would be required to move new electrons to sources,” he said.
Transmission expansion and flexibility will be essential, said Arshad Mansoor, CEO of the Electric Power Research Institute.
“The changes we have seen in 12 months, we have not seen for the last 100 years,” Mansoor said, calling the speed of demand growth “unprecedented.” Borrowing Trump’s rallying cry, he said, the industry’s response must be to “build, baby, build,” but to do so in a smart way.
“There is 15 to 20% of [grid] capacity that is there today that can be unleashed if we can find some [way] for resources like data centers to back up the grid for 1% of the time,” Mansoor said. “Fifteen to 20% of the grid is supporting electric demand for 87 hours in a year; so, we see flexibility as a huge need.”
Fixing NEPA and ‘Overreaching’ EPA rules
Building on the impetus of Trump’s executive orders, both fossil fuel and renewable energy leaders continue to call on Congress for “durable” permitting reform, though their legislative priorities vary.
Dena Wiggins, CEO of the Natural Gas Supply Association, said, “fixing NEPA has got to be Job 1.” What that means in her view is that environmental reviews under the National Environmental Policy Act should be “procedural … not outcome-determinative.” The law should be interpreted as not requiring “an agency to take a particular action as a result of [its] analysis,” she said.
Fred Hutchison, CEO of LNG Allies, wants to rein in NEPA-related litigation. “We have to stop the ability of any litigant who wants to attack a licensed project,” Hutchinson said. “Whether it’s a pipeline, whether it’s an LNG facility, when you’ve gotten your licenses and a contract, all of the appeals are settled.”
Such reforms must be “legally durable,” so courts cannot put a hold on a licensed project that is under construction, he said.
For Maria Korsnick, CEO of the Nuclear Energy Institute, the priority is preparing the Nuclear Regulatory Commission for the next generation of reactors and cutting permitting times from five or more years to 18 to 20 months.
“What [the NRC is] really comfortable with are these large reactors; they understand the regulation around them,” Korsnick said. “But the new [reactors] that are coming … they’re going to come in all shapes and sizes and run in different ways.
“So, we want them to get better at saying, ‘I understand this design; let me target the regulation just to this design.’ … Especially if it’s a small modular reactor, even a smaller micro reactor, we want them to sort of take a fresh look.”
After permitting reform, the fossil fuel industry will continue to push for regulatory repeals and rollbacks that Trump has called for in his executive order on Unleashing American Energy.
Bloodworth specifically called for action on “overreaching EPA regulations,” including the rules on power plant emissions, mercury emissions and the “Good Neighbor rule” requiring states to submit plans for limiting interstate emissions.
Repeatedly raising concerns about reliability disruptions and price increases, Bloodworth said, “The EPA should immediately stop implementing those rules. … They need to look at different interpretations of those rules” and replace them with “sensible environmental policies.”
Rolling back regulations, however carefully targeted, can’t ensure community buy-in or prevent opposition at the local level, which often presents some of the toughest obstacles to getting projects approved and built. Hopper pointed to county-level moratoria and bans on new solar projects as an example of the need to ensure NEPA reform includes “stakeholder engagement and building an understanding of the assets and the benefits that are coming to communities.”
As the number of new projects waiting for permits and interconnection continues to grow, “we can’t just, like, shove more stuff through the system,” she said.
IRA Tax Credits
While the IRA’s clean energy tax credits were not specifically targeted in Trump’s executive order on energy, they are definitely in congressional crosshairs as Republican lawmakers start looking for funding cuts to offset extending the 2017 Tax Cuts and Jobs Act.
The House of Representatives Ways and Means Committee recently circulated a 50-page list of potential funding cuts and savings, with a repeal of “green energy tax credits” the first of dozens of proposed changes to tax regulations. Such IRA rollbacks could provide an estimated $796 billion in savings over 10 years, according to the list.
The list also proposes cuts to the 45Q, 45U and 45Z tax credits for, respectively, carbon capture, nuclear and tech-neutral clean technology. Without providing detail, the list says the cuts would “reduce government intervention in the energy industry that props up the green energy sector and distorts market competition” and save $404.7 billion over 10 years.
But congressional Republicans may face challenges here as the leaders of industry trade groups at the USEA forum said they will work to protect tax credits that benefit their members.
In addition to Bloodworth’s support for 45Q, Pat Vincent-Collawn, interim CEO of the Edison Electric Institute, said “energy tax credits are driving innovation, creating good American jobs and economic opportunity, and helping electric companies [meet] the rapidly growing demand for electricity while keeping customer bills as low as possible. It is important that lawmakers protect these tax credits.”
Maintaining tax credits that support clean tech supply chains was another point of agreement. Hopper pointed to the massive buildout of solar manufacturing in the U.S. since passage of the IRA. “We have gone from very little solar manufacturing capacity in the United States to, by the end of this year, being able to produce enough solar modules to provide for our entire domestic need.”
CEBA’s Powell made a direct connection between maintaining the tax credits and another of Trump’s top priorities, keeping electric bills low. “The marginal cost of new generation sets the price for everything,” he said. “If you effectively increase the price of that new generation by removing the incentives currently available to it, we’re going to see all electricity prices rise.”
Voltus has filed a complaint with FERC against MISO, alleging the RTO’s “11th-hour” changes in testing and contract proof requirements ahead of the spring capacity auctions will harm demand response resources and affect rates (EL25-52).
In its Jan. 24 complaint, Voltus said MISO essentially is imposing “new terms and conditions” on DR by cracking down on power tests and requiring more detail in contracts. It said the RTO had “moved the goalposts” after testing deadlines passed and with just 45 days to go before the March 1 auction registration deadline.
Voltus asked FERC to deem MISO’s stricter testing and contractual requirements unenforceable because they stand to affect rates and had not been filed with FERC for approval. It said that without action, all the 450 MW of load-modifying resources (LMRs) it intends to offer in the 2025/26 capacity auction is at risk of disqualification. The company requested that FERC fast-track its complaint and respond no later than Feb. 14.
Voltus argued MISO performed an about-face in late December when it announced to market participants via email that “real power tests” would be limited in duration to LMRs’ individual stated response times. That means an LMR with a six-hour response time would have a maximum of six hours to demonstrate it could scale back usage. Before then, Voltus said it was MISO’s practice to allow DR resources a full day to drop load by at least 50% for real power testing.
But that wasn’t the only deviation from MISO’s recent testing practices, Voltus told FERC. The RTO announced at the Resource Adequacy Subcommittee’s (RASC) meeting Jan. 15 that it would require all LMRs using a firm service level threshold to measure reductions to show in testing that they can cut use to that level and that the reduction be at least 50% of the LMR’s registered value. (See Following DR Exploitation, MISO Announces Stiffer Requirements Before Capacity Auction.)
Finally, MISO announced that market participants must be able to show that their LMR contracts are active for all seasons their resources offer their services. Contracts themselves must detail response time, how the LMR achieves demand reduction, and specify how many megawatts or to what firm service level end-use customers agree to curtail, the RTO said.
MISO staff said they were forced to double down on existing testing requirements after a handful of companies were caught manipulating the DR market in recent FERC investigations. Staff at the time said MISO’s testing requirements are already on the books and that it was merely renewing its enforcement.
MISO’s tariff instructs market participants who wish to register LMRs to conduct real power tests if they have not previously responded to an emergency. The tariff also requires market participants to have “contractual rights” with their resources.
However, Voltus argued that MISO has not defined a “real power test” in its tariff or Business Practices Manuals. The company said it has seen efforts to define DR testing in stakeholder committees repeatedly “fizzle out.”
Because MISO and stakeholders have never settled on a definition, the company argued, FERC should act to make sure market participants registering LMRs who relied on the RTO’s typical guidance in recent years for the 2025/26 auction are treated fairly.
MISO’s late December email came after registration for the 2025/26 planning year had already begun and days before LMRs’ testing deadline, Voltus said. And it wasn’t until the Jan. 15 RASC meeting — after the LMR testing deadline passed — that MISO announced it would require aggregators of retail customers demonstrate “contractual control” of their demand resources and resubmit registrations that lack details, it said.
“MISO’s beyond-the-11th-hour changes to these requirements will have catastrophic impacts on market participants,” Voltus said, adding that it’s now impossible for market participants to retest LMRs while still meeting the RTO’s original end-of-the-year deadline for testing.
Voltus argued MISO’s seemingly new contract specifications are discriminatory because aggregators now are held to a different standard than utilities. While aggregators must submit the more detailed contracts, utilities must show only that customers are enrolled in their DR programs. Voltus argued MISO did not attempt to explain the disparate treatment.
The company also said it’s “unlikely” that contracts between aggregators and their customers “will include all the exact information MISO is now (for the first time) mandating be included.”
“As a result of these changes, all of the demand resources Voltus intended to register as LMRs to participate in the [Planning Resource Auction] for the 2025/2026 planning year may be disqualified entirely,” Voltus said, explaining that “none” of its customer contracts contains all the data MISO wants. It said that as of Jan. 24, it’s still waiting for MISO to confirm whether it will accept additional documentation detailing curtailment plans that it has submitted.
“While Voltus has curtailment plans for each of its customers, those curtailment plans are not codified in the contract. Similarly, while some of Voltus’ customer contracts specify the [firm service level] to which the customer commits to drop, in many cases that information may be contained elsewhere (e.g., in an email confirmation or other document extraneous to the contract),” Voltus said.
Voltus said that of its 450 MW of LMRs, 112.7 MW are from those that on paper no longer pass MISO’s real power testing requirements, either because of new time span limits or the firm service level stipulation. The company said it communicated testing requirements to customers using RTO rules in the past four planning years.
“MISO’s 11th-hour change in methodology therefore forced Voltus to choose between two terrible options: (1) not register these demand resources, losing revenues and failing to satisfy its commitments to these customers; or (2) register such demand resources as ‘untested,’” the company wrote.
Voltus told FERC it was forced to submit the 112.7 MW as “untested,” which it said will increase its potential penalty exposure by $3.16 million per market dispatch and up its collateral requirement by $270,480.
The company predicted that “hundreds of megawatts of demand resources” will be unable to register to participate in MISO’s seasonal capacity auctions by the March 1 registration deadline. It warned of “cascading impacts” where aggregators and other market participants will be forced to find replacement capacity or default on bilateral contracts.
Voltus said that while it does not oppose MISO’s attempts to strengthen its requirements, the grid operator should not be allowed to “unilaterally impose new requirements on market participants with no basis in the tariff.”
MISO told RTO Insider via email that it is “reviewing the complaint to determine our response” but declined to comment further.
Arizona Corporation Commissioner Nick Myers, chair of the Markets+ State Committee, said Jan. 24 he’s drafting a response to FERC’s requested compliance filing to clarify some of the key points raised in the commission’s approval of the day-ahead market’s tariff (ER24-1658).
Myers, vice chair of the ACC, told the MSC his letter will explain the regulatory group’s structure and how it will be funded by SPP. The MSC comprises regulators from most Western states who provide their perspective on Markets+’s development and operations.
“I think this reply would be more of an informal response, as it is a point of clarification other than actual comments, but open to feedback from you all,” Myers told the MSC. “I do think having as many as MSC members as possible behind that would be beneficial and helpful and also just keeps everyone on the same page with where these discussions are at moving forward.”
FERC conditionally approved the market’s tariff Jan. 16. The commission found the tariff still was “insufficiently clear” on some points and directed a compliance filing due Feb. 15. (See SPP Markets+ Tariff Wins FERC Approval.)
Commissioner Mark Christie (now chair) and Commissioner David Rosner filed a joint concurrence to FERC’s order, expressing their concern with governance and ensuring “robust” state involvement in the market’s development. They urged SPP to ensure the MSC, and its Regional State Committee in the Eastern Interconnection, can provide adequate independent staff support and the means to maintain dedicated staff, similar to the structures of the Organization of PJM States Inc. and Organization of MISO States.
The Western Interstate Energy Board currently serves as the MSC’s staff support. WIEB’s Gia Anguiano, who supports the MSC, said SPP staff will visit Christie and Rosner in Washington, D.C. this week to discuss their concurrence in a “little bit more detail.” She said there also have been discussions to have the two commissioners participate in an MSC meeting.
“[We] really want to get to the root of their concerns around [their concurrence] and see what we can do to further address it,” Anguiano said.
FERC Commissioner Judy Chang issued a separate concurrence that noted the tariff leaves some uncertainties about key market design details, such as transmission capability rules, greenhouse gas pricing and potential seams issues, between Markets+ and CAISO’s competing Extended Day-ahead Market.
“I think the biggest point in Commissioner Chang’s concurrence is just really to make sure that the market is operating at its greatest potential and for the consumer’s benefit,” Anguiano said.
ERCOTannounced Jan. 27 that it filled two vacancies on its Board of Directors, bringing it to a full complement of eight independent members.
The Texas grid operator said its Board Selection Committee tabbed Alex Hernandez and Sig Cornelius to serve three-year terms, effective immediately. They replace former Chair Paul Foster and Director Bob Flexon, both of whom left in 2024. (See ERCOT Board Chair Foster Steps Down.)
Alex Hernandez | Talen Energy
Hernandez is the founder and CEO of Cumulus Data, the first hyperscale data center platform directly connected to carbon-free nuclear power. He brings with him 20 years of experience in business formation, operations, executive leadership and strategic advisory roles, most recently serving as Talen Energy’s CEO. Hernandez also served as TerraForm Power’s CFO, a board member for the Nuclear Energy Institute’s Executive Committee and a managing director at Goldman Sachs.
He holds bachelor’s degrees in economics from both Rice University and the London School of Economics, and an MBA from Columbia University.
Sig Cornelius | Freeport LNG
Cornelius has spent 45 years in several senior management positions, most recently as president of Freeport LNG Development. Previously, he was with ConocoPhillips, retiring as CFO in 2010.
He has a bachelor’s degree from Iowa State University and master’s degrees from both Purdue University and Stanford University.
The ERCOT board includes four ex officio and nonvoting members to provide an in-person sounding board for member companies: the CEO of ERCOT, the public counsel of the Texas Office of Public Utility Counsel, the chair of the Public Utility Commission and a PUC commissioner designated by the PUC chair.
All board members are from Texas, a change made after the February 2021 winter storm.
Groups of generation owners and developers have asked MISO to adopt a queue fast lane only as a last resort and employ a more limited process that involves scoring criteria to gain entry.
However, the Coalition of Midwest Power Producers (COMPP) said MISO should establish a screening process for the fast lane based on project readiness and limit the process to just two accelerated studies — one in 2025 and one in 2026. The two studies should be open to all interconnection customers, independent power producers and load-serving entities alike, COMPP said.
Speaking at a Jan. 22 Planning Advisory Committee meeting, COMPP representative Travis Stewart said MISO’s expedited process as proposed creates the possibility of discriminatory treatment in the interconnection queue. This is especially a concern, he said, because designated resource adequacy projects might get first dibs on some of the billions of dollars in freshly constructed transmission capacity MISO has approved in recent years.
Stewart suggested MISO introduce a scoring system to permit projects in the express lane to make sure it’s accepting “commercially mature” projects that meet resource adequacy needs. He said project proposals could earn points based on developers’ ability to show that projects will serve resource adequacy needs, the completeness of an engineering design and equipment procurement, and that projects have been selected through either regulators or load-serving entities’ competitive solicitation. He said the burden to show project need and readiness would be on developers, with MISO to simply “trust and then verify” information from developers and regulators.
Stewart said COMPP’s idea, which he dubbed the Alternative Resource Connection Queue, could accept 50 of the highest-scoring projects apiece in 2025 and 2026 to proceed with faster studies aimed at interconnection agreements within 90 days.
“COMPP is concerned that an unchecked, uncapped [express] queue that can continue in perpetuity will likely mimic the ‘lane expansion’ phenomena in which creating new highway lanes does not improve the flow of traffic but only creates more lanes with more traffic,” Stewart said.
Some stakeholders said that asking MISO to institute more evaluation and scoring criteria will inherently slow down and convolute a queue lane designed to be faster.
“We’d rather have some small hurdles set up at the beginning to demonstrate commercial maturity … than have MISO dedicate their engineering expertise to study a project that ultimately doesn’t get built,” Stewart said, adding that “two weeks of evaluation upfront is better than four months” of ultimately wasted analysis.
NextEra Energy’s Erin Murphy, representing a group of MISO generation developers, said MISO’s proposal raises fundamental discrimination and undue preference concerns. She agreed with Stewart that a fast lane should be open to independent power producers and load-serving entities alike.
“We are concerned that the most constructable projects and the ones most able to address RA concerns won’t get online under this process,” Murphy said.
Murphy said while a limited fast track might ultimately prove necessary, MISO should focus first on improving operations of the existing queue to reduce the backlog. She said MISO should increase staffing and allow time for its recently approved queue regulations with FERC to take hold before it establishes specialized processing.
“We’re of the firm belief that the volume currently in the queue is more than enough to meet projected resource adequacy needs,” Murphy said. She argued that MISO first should take stock of projects already in the queue to ascertain which can meet the footprint’s resource adequacy needs. She implied MISO is establishing a fast lane while disregarding viable projects in the regular queue that already have been vetted.
“There’s a heck of a lot of value in the queue that’s locked up,” Murphy argued.
Murphy said if an imminent resource adequacy gap persists after that, any express lane should come equipped with a scoring system “so the best projects come online in a timely manner.” She also said a fast lane option shouldn’t “erode” the value of the existing queue.
But WEC Energy Group’s Chris Plante said identifying resource adequacy needs is a subjective exercise today.
“It’s not as simple as meeting a reserve margin. It used to be that simple,” Plante said. He said today’s variable requirements in seasons, the sloped demand curve now in place in MISO capacity auctions and more volatile accreditation values year-over-year complicate the picture.
“There’s a tremendous amount of uncertainty in determining resource adequacy needs,” Plante said.
Murphy agreed and suggested resource adequacy needs could begin with states articulating them and then MISO validating them.
MISO’s Andy Witmeier said MISO is delaying its FERC filing into mid-March to consider stakeholders’ suggestions. He said MISO would return to the February Planning Advisory Committee to present a final proposal.
However, Witmeier said the point of the fast track is to get projects online quickly as load grows. He said MISO’s new queue regulations approved in January 2024 — which include higher fees, automatic withdrawal penalty costs and stricter evidence of land use — will take a few years to bear results.
“We’re facing a new phenomenon with spot loads,” Witmeier explained.
Witmeier confirmed that projects that elect to drop out of the regular queue to join the fast-tracked queue will face automatic withdrawal penalties.
MISO also plans to collect higher fees from fast-lane developers than in the regular queue. It will start with a $100,000 nonrefundable upfront fee and then a milestone payment of $24,000/MW. Customers in the regular queue pay $8,000/MW.
Clean Grid Alliance’s David Sapper argued that MISO’s proposal still appears to “violate” FERC’s mandate on open access and nondiscriminatory treatment.
Minnesota Public Utilities Commissioner Joe Sullivan said he heard stakeholders offer fair recommendations to MISO.
“I think we have to find a way to treat the existing queue reasonably and fairly,” Sullivan said.
Sustainable FERC Project’s Natalie McIntire said it seemed MISO wasn’t requiring enough proof that projects are ready to embark on construction. She said MISO might consider requiring engineering designs, fuel contracts if applicable and their permitting progress. McIntire said there’s “strong stakeholder support” to ensure projects will be able to meet demand in the timeframe MISO needs them.
MISO so far requires details like synchronization and commercial operation dates, interconnection facilities finish dates, generator output, manufacturer and model numbers, fuel type and facility and transformer data.
NYISO on Jan. 21 presented stakeholders with its preliminary proposal for complying with FERC Order 1920, giving a first glimpse into how the ISO may conduct a long-term transmission planning process.
The ISO would repurpose elements of its current Economic Planning and Public Policy planning processes while retaining reliability studies like the Short-Term Assessment of Reliability and Reliability Needs Assessment as separate processes. The System & Resource Outlook would serve as the “core assessment and analysis element” of the new process.
“It’s a tough balance,” Yachi Lin, director of system planning for NYISO, told the Transmission Planning Advisory Subcommittee. “FERC does give us options on how to comply with Order 1920. We either have a multi-value [process], [with] everything going into one batch, or we decide how to repurpose our current processes, or we develop a new one.”
Lin said adding a fourth process specifically for Order 1920 would be overwhelming.
“That’s why we landed here,” Lin said. “Let’s repurpose, leverage, our existing success and experience in economic and public policy planning processes.”
NYISO would also adapt its current solution solicitation, evaluation and selection process into the new long-term process. This would incorporate the seven categories of benefits that FERC specified in the order.
Order 1920 also requires a 20-year horizon for transmission planning with cost allocation for projects that ensures that only customers who receive benefits pay for the projects. The order mandates that new grid enhancing technologies and previously passed-over projects be considered.
With Order 1920-A, FERC gave state governments more of a say in the new long-term processes, granting “relevant state agencies” the opportunity to propose alternative cost-allocation methods for long-term regional transmission facilities. (See FERC Order 1920-A Wins Approval with Accommodations to States.)
Several stakeholders asked about why NYISO had only included the Department of Public Service and Long Island Power Authority as “relevant state entities.”
“We looked at this issue in connection with a meeting around cost allocation options,” said Liz Grisaru, senior adviser for policy at the DPS. “And it appears to us anyway that a ‘relevant state entity’ is either a state permitting authority or a state entity with the authority to set rates.”
One stakeholder pointed out that New York Power Authority sets rates for its communities “all the time,” and it was not clear why it was excluded from being a relevant state entity for the purposes of Order 1920. Another stakeholder chimed in that which state entities qualified should be better clarified before “we get too far down the road.”
Challenges
The commission required that transmission providers conduct their long-term planning processes every three years. The new process requires NYISO to incorporate more factors, develop more scenarios and include more evaluation metrics than those in the Outlook and Public Policy Transmission Process combined, Lin said.
If the Public Policy and Outlook processes were simply combined without expanding the scope mandated by Order 1920, it would take about four years of NYISO-only work, she said. “We’ve got to think of ways, creative ways, to try to squeeze the time into three years,” she said.
In addition, the New York Public Service Commission will still play a role in the new process. She noted that the involvement of the PSC would add processing time, particularly with the notice and timing rules of the State Administrative Procedure Act.
Lin said that some time could be saved by soliciting data from stakeholders and relevant state entities that might affect long-term transmission needs. In effect, this would replace the biennial Public Policy Transmission Need solicitation.
Chris Casey of the Natural Resources Defense Council said that he was worried about the separation of the reliability processes and the new planning process. He said that in the past, the reliability planning assumptions had typically been conservative.
“I guess what I’m worried about is having a separate reliability process identifying a longer-term reliability need and potentially acting on it through that process without understanding if we should be expanding what the solution might be,” Casey said.
Lin replied that the objectives of the reliability planning process and the new long-term process were different. Reliability planning is about making sure that there’s enough energy and capacity. She said that short-term reliability solutions should be used as inputs into the long-term situation.
“There are opportunities to make sure that we link them up together,” Lin said. “I do not envision that we will be in a vacuum, only addressing long-term reliability needs without understanding [short-term] reliability.”
Lin asked stakeholders and state entities for feedback on the preliminary proposal. NYISO is aiming to submit its compliance filing on regional planning requirements by June 12 and another filing on interregional requirements by Aug. 12.
