CAISO has launched an initiative to improve its congestion revenue rights market by addressing issues such as revenue inadequacy and auction efficiency.
The ISO held a working group meeting Nov. 14 to kick off the stakeholder process for the initiative. It also released a discussion paper outlining the issues regarding CRRs.
CRRs are intended to provide a hedging mechanism for congestion risks in the day-ahead market. They’re distributed through free allocations to load-serving entities and also are awarded through auctions in which a variety of entities may participate.
But auction efficiency has been a concern. According to CAISO, the CRR auction has been yielding only about 65 cents per dollar of congestion revenue.
Revenue adequacy is another issue: From 2019-2024, system-level revenue inadequacy was 81%, with a total shortfall of $684 million.
The current effort follows a previous initiative regarding CRR auction efficiency that led to rule changes in 2019.
Since then, losses from CRR auctions have decreased, but have been described as “still very high” by the Department of Market Monitoring (DMM), a longtime auction critic. (See Congestion Revenue Rents Still Underfunded, CAISO DMM Says.)
“The ISO should stop offering CRR positions on behalf of transmission ratepayers at $0 offer prices and enable trades to only take place between willing sellers bidding into a market for these financial contracts,” the DMM said in a presentation during the workshop, echoing an argument it has been making for years. (See CAISO CRRs Still Losing Money, but Less.)
Working Group Timeline
The working group will develop problem statements that will lead to proposed policy solutions. Those proposals will go to the ISO Board of Governors and the Western Energy Markets Governing Body for approval and ultimately be filed with FERC.
For the next steps in the process, CAISO staff have proposed following up the Nov. 14 meeting with one or two workshops in January to provide background information on the CRR market. The sessions would be geared toward those who recently have joined the stakeholder process and others who may need a refresher.
At the same time, CAISO wants to learn more about how different entities are hedging risk through CRRs.
Under the proposed timeline, February would be devoted to analysis, including CRR outcomes since the 2019 reforms. CAISO staff also have offered to provide benchmarking comparisons to CRR-like programs at other ISOs, which go by different names, such as financial transmission rights.
March would feature discussions of proposed problem statements and the scope of the initiative, followed by release of an issue paper from the working group in May or June.
CAISO welcomes comments on the CRR discussion paper and on the initial meeting — including the proposed focus of future meetings. Comments are due by the end of the day Dec. 12.
The West-Wide Governance Pathways Initiative on Nov. 15 released its final proposal for establishing a Western “regional organization” (RO) that would assume oversight for CAISO’s Western Energy Imbalance Market (WEIM) and Extended Day-Ahead Market (EDAM).
The proposal offers a blueprint for divvying up functions between CAISO and the RO that Pathways backers envision would provide an independent framework for governing the ISO’s Western markets. Launched in July 2023, the effort aims to address regional concerns about the state of California’s oversight of CAISO and to counter the appeal — and potential growth — of SPP’s Markets+, a competitor of EDAM for market participants.
The Pathways Launch Committee will vote on the proposal during its next public meeting Nov. 22. The content of the Step 2 proposal will play a big role in shaping the bill that Pathways supporters are looking to move through the California State Legislature in 2025 to relax the state’s authority over CAISO’s markets.
“This proposal marks a major milestone in a decades-long series of incremental steps,” Launch Committee Co-Chair Kathleen Staks, executive director of Western Freedom, said in a statement. “The regional organization will have sole authority over the energy markets, ensuring shared and independent Western ownership, while deliberately setting the stage for an organization empowered to develop its own regional solutions for years to come.”
As in the draft, a key element of the final proposal is the Launch Committee’s choice to launch the RO in the form of the “Option 2.0” structure discussed during Pathways meetings. Under that option, the RO would serve primarily as a “policy-setting” body and assume “sole” authority over WEIM and EDAM market rules, holding exclusive rights to file with FERC under Section 205 of the Federal Power Act.
That stops short of the more comprehensive “Option 2.5,” which would see the RO take on more of CAISO’s market functions and legal responsibilities along with the accompanying financial and legal risks. But the plan states that, within nine months of the RO’s formation, the RO board must perform analysis of advancing toward Option 2.5.
“The feasibility analysis would at a minimum evaluate: vendor management role, financial liability, existing regulatory contract changes and future RO staffing needs,” the proposal notes.
The plan also calls for the RO to maintain a single, integrated tariff with the ISO instead of establishing a separate tariff. The Launch Committee recommends the Formation Committee work with CAISO “to explore ways to provide more clarity in the tariff that can be proposed to the RO board once it is seated.”
The proposal also describes how the RO would be funded: through “a tariff-based mechanism under which the CAISO collects funding from market participants and remits the funding to the RO.” It notes that the RO and CAISO would follow a stakeholder process to develop the mechanism and how it might “interrelate” with the ISO’s current approach to collecting its grid management charge. The mechanism would be subject to FERC approval.
Budget, Location, Relationship with CAISO
The plan says the RO would start out with “limited staffing” at an estimated budget of $1.25 million to $1.5 million, which eventually could increase to $10 million to $14 million over time.
The proposal also sets out how the RO would influence CAISO’s management and market monitoring structure, saying it would have “advisory authority to provide noncontrolling input on hiring and performance of one or more officer-level senior CAISO managers responsible for the business line (or ‘vertical’) that oversees the markets.”
It notes that CAISO’s Board of Governors would consider “the most appropriate way” for the RO board to advise on the hiring of any future CEO of the ISO. The two boards also would jointly select future heads of the ISO’s Department of Market Monitoring (DMM) and members of its Market Surveillance Committee.
The plan calls for the RO’s contract with CAISO to “provide an opportunity for the RO to offer an annual performance evaluation of the CAISO management personnel subject to the RO’s noncontrolling hiring input, including the CAISO officer(s) overseeing market services and the DMM.”
The proposal affirms the Launch Committee’s previous recommendation that the RO be incorporated as a 501(c)(3) nonprofit in Delaware and have its principal place of business in Folsom, Calif. — near CAISO’s headquarters.
It sets out the RO’s governance structure, including the seven-member board, the Formation Committee and the Public Policy Committee, the last of which would be “tasked with conducting outreach at key points in the stakeholder process to states, local power authorities and federal power marketing administrations to collect input about the potential for adverse impacts on a state, local or federal policy by an initiative.”
The Step 2 proposal also sketches out the RO’s framework for protecting the public interest, including the intention to carry over the existing Western Energy Markets Body of State Regulators (BOSR) into the RO and create an independent Consumer Advocate Organization and Office of Public Participation to facilitate engagement with the public.
The proposal’s program for stakeholder engagement includes the structure for the proposed Stakeholder Representative Committee (SRC) the Launch Committee discussed with stakeholders in October. (See Revised Pathways Proposal Focuses on Sector Issues.) The proposal notes that voting within the SRC is “ultimately advisory” and intended to identify “significant opposition” to an initiative; it says the Formation Committee in the future would work with a Stakeholder Process Work Group and stakeholders to develop the “remand” process to respond to such opposition.
The proposal additionally breaks out the roles for the SRC and RO staff in the stakeholder process. It also notes that the RO’s Formation Committee would work with CAISO to determine staffing for the RO’s stakeholder process and “to refine the roles needed” and identify whether they would “best sit with” the RO or CAISO.
‘Logical Next Step’
Most parties who commented on the draft proposal expressed support for the Launch Committee’s decision to proceed with Option 2.0 rather than a more aggressive option in which the RO would take on more responsibility for CAISO’s markets.
But key among the skeptics were entities in the Northwest known to favor Markets+ over EDAM, including Puget Sound Energy (PSE) and the Bonneville Power Administration.
“PSE is concerned that this proposal still leaves significant uncertainty with regard to achieving meaningful independence, does not ensure sufficient near-term independence of the RO from the California Independent System Operator, and does not provide a clear line-of-sight to Option 4 [which outlined a nearly complete transfer of CAISO functions to the RO] or a viable, broad, independent Western regional transmission organization footprint that includes California,” PSE said in its comments on the draft plan.
BPA officials expressed a similar view during a Nov. 4 workshop and follow-up press briefing to discuss the status of its day-ahead market decision process. (See BPA Execs Lay out Markets+ Benefits, Risks, Reasons.) They noted the agency’s preference for Pathways’ Option 4, questioned whether the RO would even adopt Option 2.5 and said Markets+ already offered the governance option that “satisfies” its needs.
“We have an option that’s no longer hypothetical. It is a real option that has a real independent market governance structure that satisfies us, and that’s what we’re measuring everything else against,” Rachel Dibble, BPA vice president of bulk power marketing, said during the briefing.
EDAM supporters have argued the Pathways Step 2 plan represents the incremental step needed to move the West to a regionwide market that includes California.
“We believe that the Step 2 proposal is a logical ‘next step’ for markets for the Western Interconnection,” said Jim Shetler, executive director the Balancing Authority of Northern California (BANC) and a member of the Launch Committee. “The concept of phasing the evolution of market services with participation on a voluntary basis is an approach that has worked successfully for the West and is consistent with BANC’s strategic vision. BANC is happy to support this next phase of the Pathways process.”
WASHINGTON — Both Sen. John Hickenlooper (D-Colo.) and former FERC Chair Neil Chatterjee (R) see the current lame duck Congress as having the best, possibly last chance to pass the Energy Permitting Reform Act of 2024 (S. 4753) and get it to President Joe Biden’s desk before he leaves the White House.
“The bill that’s sitting there right now, I think we can get that passed,” Hickenlooper said Nov. 13 during a forum hosted by Heatmap News at the Shaw Brewpub & Kitchen. “I’m not saying we’re going to, but I’m saying I think we’ve got a very good chance of Republicans and Democrats lining up [and] saying, ‘Alright, I don’t like a lot of this, but we need it.’ And I think both sides might hold their nose, and we might be able to get the thing through.”
Chatterjee, now a senior adviser at D.C.-based law firm Hogan Lovells, is less optimistic. But he said, “If we don’t get it done in the lame duck, it spills into next year, and you’re not going to get a lot of Democratic support to pass a permitting reform bill, and Republicans are not going to abolish the filibuster to pass legislative permitting reform. … Republicans are not going to overturn the birdbath to do legislative permitting reform.”
Authored by Sens. Joe Manchin (I-W.Va.) and John Barrasso (R-Wyo.), EPRA would double the target for renewable energy on public lands from the 25 GW already permitted to 50 GW no later than 2030 while also cutting the time allowed for filing legal appeals against federal decisions on energy projects from six years to five months.
It would also require RTOs and ISOs to collaborate on plans for interregional transmission and allow FERC to step in to permit interregional transmission projects after one year if a state delays or denies a permit, even if the project has not been designated as being in the national interest. (See Manchin-Barrasso Permitting Bill Would Give FERC Transmission Siting Authority.)
The Senate Energy and Natural Resources Committee passed the bill 15-4 on July 31, but it has yet to go before the full Senate. Hickenlooper is a member of the committee and voted for the bill.
While energy industry trade groups have largely supported the bill, environmental organizations have opposed it. But Hickenlooper sees the lame duck session as an opportunity for an “alignment of self-interest” between Democrats and Republicans, industry and environmentalists.
“Most of the environmental organizations recognize that if we’re going to successfully address climate change, we’ve got to get transmission lines,” he said. “We can’t spend 20 years permitting transmission lines. We’ve got to figure out how to make sure we do that in a way that protects the environment, protects [the] cultural heritage of these sites, but we’ve got to go faster. … The sense of urgency that we have is not nearly sufficient. …
“If we miss the chance with the Barrasso-Manchin bill, we’re still going to have to do all this work,” Hickenlooper said. “We’re just going to do it six months or a year or two years down the road, and it just puts us further away from beginning to address the issue.”
IRA vs. Tax Cuts
Hickenlooper and Chatterjee also were cautiously optimistic that the clean energy tax credits and incentives in the Inflation Reduction Act would not be sacrificed to pay for extending the tax cuts passed in 2017.
Hickenlooper’s main argument was that the new working-class voters in the Republican Party are among those benefiting from the clean energy manufacturing jobs the IRA is creating. “Rolling back those efforts for the simple purpose of giving another tax break to the publicly traded stocks of America doesn’t seem constructive,” he said.
Dismantling the IRA will create more uncertainty and disrupt business plans, he said, and such unpredictability could leave businesses not knowing “whether anything that’s agreed to is going to stay the same for more than two years.”
Chatterjee said he believes that even with Republican control of the House of Representatives and Senate, extending the 2017 tax cuts and rolling back the IRA through a single budget reconciliation bill could require more political capital than the GOP can muster.
Budget reconciliation is a legislative maneuver under which a budget bill can be passed with a simple majority vote in both houses as opposed to the three-fifths usually needed for such legislation. Both the 2017 tax cuts and 2022 IRA were passed via budget reconciliation.
But, Chatterjee said, in the Republicans’ new “populist working-class party, there’s not necessarily unanimity around the idea of extending corporate tax cuts at the expense of exacerbating the deficit. … I think [President-elect Donald Trump] and Republican leaders in Congress will leverage their political capital to get that piece of it done. But then to layer on IRA repeal on top of it, or IRA modifications to pay for it, at that point individual lawmakers start to have tremendous influence,” he said.
While the Republicans might have enough votes to roll back the IRA’s tax credits for electric vehicles, other incentives — for clean hydrogen, carbon capture or tech-neutral clean energy — could have individual supporters. “The end result is things get heavy, and they get tough to pass,” Chatterjee said.
At the same time, Chatterjee expects that former Rep. Lee Zeldin (R-N.Y.), Trump’s nominee to head EPA, will roll back the Biden administration’s regulations aimed at reducing greenhouse gas emissions from power plants and automobile tailpipes, but “in a thoughtful way that focuses on rational outcomes.”
“He may pursue a deregulatory agenda but do it in a way that is respectful and listens and brings different stakeholders to the table,” Chatterjee said. “I think that’s a good thing.”
‘Deep Uncertainty’
Hickenlooper and Chatterjee also are thinking similarly about the need to depoliticize the debate around climate and energy issues as lawmakers and regulators face the impacts of increasingly frequent and severe extreme weather, while meeting growing power demand from artificial intelligence, data centers and new manufacturing.
Trump may call climate change a hoax, Hickenlooper said, but “that’s not going to stop me from trying to go out and make the argument that if you live in Florida and you look at how you’re going to get insurance for property, you better look pretty closely right now because it’s now the states … [that] subsidize people’s property casualty insurance.”
If available at all, home insurance rates have skyrocketed in Florida and in other states that have experienced repeated extreme weather events. As a result, many homeowners have to rely on state-subsidized programs.
“We Democrats and Republicans and independents have to start finding ways to get this in the media and talking about it in real time,” Hickenlooper said.
Chatterjee sees the potential for bipartisan action on electricity demand growth. Neither party has, thus far, “fully grasped what this coming surge in demand means,” he said. “I think there is universal agreement amongst parties that we need to win the AI race against the Chinese Communist Party for national security purposes … and power will be the key to winning that AI race.”
But, he said, political and business leaders will need to do a better job of explaining those imperatives to the public, which could be faced with “increased consumer prices or potential threats to resource adequacy and reliability or backsliding on our decarbonization goals.”
Democrats will have to accept the need to keep fossil fuel plants online, and Republicans will have to accept that meeting new demand will require both an aggressive deployment of renewable energy and new transmission lines, he said.
“I actually think we are on a precipice of a moment in which, because of AI, because of investments in domesticating the supply chain for the clean energy future … we are on a trajectory to where red supply can feed blue demand,” Chatterjee said. “We are at a tipping point where we can take politics out of the clean energy transition and decarbonization and actually focus on collective solutions.”
Hickenlooper said getting buy-in from American consumers will require setting out a clear plan for the transition.
“I don’t understand how we got so far down the road without any kind of plan,” he said. “It’s hard to imagine the American people sacrificing and paying more for energy … if they can’t see where it’s leading and what the next sacrifice is and what their benefits are; the money they are going to [save].”
Like Chatterjee, Hickenlooper says all generation technologies will be needed. But even with a plan, a key challenge will be “making decisions under deep uncertainty. … That’s what we’re going to have to do: make decisions when there are, in many cases, not enough facts.”
“We don’t have enough information to really have the confidence our decisions need,” Hickenlooper said. “But we have to keep making decisions under deep uncertainty because we do not have the time. We don’t have the luxury.”
North America’s electric grid faces “familiar challenges” this winter but is also displaying “good reasons for optimism” heading into the cold months, NERC staff said while presenting the ERO’s newly release 2024-2025 Winter Reliability Assessment.
The assessment, released Nov. 14, covers December 2024 through February 2025. It was developed over “several months of work with the regional entities and industry, and reviewing projections for demand and resources and the preparations that are been put into place for this upcoming winter,” NERC Manager of Reliability Assessments Mark Olson said in a media briefing.
While the report did not identify any grid areas as facing high risk of insufficient operating reserves in normal peak conditions, it found multiple areas face elevated risk of energy shortfalls during “extreme winter conditions extending over a wide area.” All or part of most regions were mentioned as facing shortfall risks, including Texas, SPP, MISO, PJM, NPCC and SERC.
“Winter demand forecasts … are elevated across most areas that we look at,” Olson said, noting demand is projected to rise at least 2% over last winter in most assessment areas. “It’s a significant jump from last year, and that was a big jump from the year before that.”
The report also called out generation retirements in some areas as a factor in potential shortfalls. For example, MISO has experienced over 5 GW of reductions in coal and natural gas-fired generation from winter 2023/24. In MRO’s SaskPower subregion, coal generation capacity has fallen 140 MW (though offset by increases in gas generation capacity), while dispatchable thermal generation capacity “has declined by 2.6 GW from last year” in NPCC-New England and nearly 1 GW in the portion of SERC Reliability’s territory that includes North and South Carolina.
Even in areas where dispatchable generation has increased — mostly through installation of gas generation — the growth has not always kept pace with new demand. This was the case in Texas, where dispatchable resources have increased by 1 GW since last year as demand rose more than 2 GW. Although solar and wind capacity have grown by 3 GW, the report noted these resources may have limited use in times of extreme cold weather.
Limits on natural gas pipeline capacity were also noted to affect PJM, as well as NPCC’s New York and New England subregions. NERC cited “ongoing concerns with natural gas production and delivery in extreme conditions.”
Balancing these concerns, the report also observed significant action by industry and regulators to address the systemic issues revealed by the winter storms of 2021 and 2022. In the media call, Olson said “there’s a lot of information to be gained from the things that went right in the January 2024 Arctic cold blast.” FERC and NERC’s joint report, issued in April, said the grid’s performance last winter demonstrated significant progress from previous years. (See FERC, NERC Review January Winter Storm Performance.)
NERC staff also noted the ERO’s ongoing development of requirements for cold weather preparations by utilities, with EOP-012-2 (Extreme cold weather preparedness and operations) taking effect last month and its successor expected to be completed by next year. (See NERC: Board’s 321 Authority on the Table for Cold Weather Standard.)
While Olson acknowledged the challenge of quantifying the effect of the standard on grid reliability, he said the report’s authors could consider the winterization requirements’ impact on non-fuel-related generator outages. He added that utilities’ preparations ahead of the standard’s effective date could be seen in the January winter storm, which NERC took as a positive sign for the report.
‘Natural Gas Remains Essential’
In their reactions to the assessment, grid stakeholders focused on its information about energy sufficiency and resource retirements. In a press release, Todd Snitchler, CEO of the Electric Power Supply Association, said the assessment “once again underscores the serious power supply challenges facing our nation.” He added dispatchable generation resources will be key to ensuring reliability throughout the winter months.
“Natural gas remains essential to ensuring a reliable system,” Snitchler said. “Generators and our partners in the natural gas value chain have taken meaningful action to address issues faced during recent storms and to enhance gas-electric coordination. As they do every year, our member companies take significant steps to prepare for winter operations and help ensure optimal performance.”
Jim Matheson, CEO of the National Rural Electric Cooperative Association, also weighed in, emphasizing the danger that energy shortfalls pose to “the health of local communities and … the American economy.”
“Demand for electricity is skyrocketing across America, and supply is not keeping pace. And flawed public policies that focus on shutting down always available power generation are compounding this problem,” Matheson said. “This report clearly highlights the need to swiftly implement a pro-energy policy agenda with a focus on affordability and reliability for American families and businesses. Smart energy policies that keep the lights on are more important than ever.”
FERC on Nov. 13 approved tariff revisions and modifications to the joint operating agreement between MISO and SPP that will enshrine a structural and cost-allocation framework for the five 345-kV projects in the RTOs’ $1.6 billion Joint Targeted Interconnection Queue (JTIQ) portfolio (ER24-2798, ER24-2825).
In a 4-0 decision (in which Commissioner Judy Chang did not participate), the commission found the proposed revisions to the RTOs’ generator interconnection processes and pro forma GI agreements in their respective tariffs and Joint Operating Agreement complied with its rules “by helping to ensure that interconnection customers are able to interconnect to the transmission system in a reliable, efficient, transparent and timely manner.”
FERC said the proposed allocation of 100% of the JTIQ portfolio’s cost to interconnection customers is consistent with the cost-causation principle and allocates costs at least roughly commensurate with estimated benefits. The commission said the JTIQ study addressed transmission system limits preventing the interconnection of future generation capacity, thus benefiting all interconnection customers.
“Interconnection customers are the primary beneficiaries of the JTIQ upgrades, and therefore the proposed allocation of 100% of the capital costs … to interconnection customers when fully subscribed is just and reasonable,” FERC said. “The RTOs also have shown that the JTIQ upgrades do not provide sufficient benefits for load in either RTO to qualify as transmission projects selected in the regional transmission plan for purposes of cost allocation.”
MISO and SPP will now take the JTIQ portfolio to their respective boards’ upcoming meetings for their approval. Both boards meet in December.
The RTOs expect a grant of up to $464.5 million in matching federal funds under the U.S. Department of Energy’s Grid Resilience and Innovation Partnerships (GRIP) program to offset about 25% of the portfolio’s capital costs. (See MISO, SPP Ditch 90/10 JTIQ Allocation After $465M DOE Grant.)
Commissioner Mark Christie wrote a concurring opinion, noting that the JTIQ projects would not have been selected in the RTOs’ regional transmission plans.
“These projects are not designed to serve load, i.e., consumers, with optimal solutions to identified reliability concerns or economic drivers,” he wrote. “Rather, the primary purpose of these projects is to provide interconnection customers — generation developers, primarily wind and solar — with more interconnection opportunities. Accordingly, it is appropriate that the primary funding for these projects is from the generation developers themselves, as they are the primary beneficiaries.”
Christie said the order establishes that the benefits to load meet the cost-causation principle, justifying the RTOs’ proposal that load provide backstop funding for the portfolio. He said the funding mechanism is only just and reasonable with the GRIP funding covering 25% of the capital costs.
“Without this funding, it would be unjust and unreasonable to allocate to load any of the [portfolio’s] costs,” he said. “These projects were not designed to serve load, plain and simple, and if there were no funding, the JTIQ proposal would not be acceptable.”
Aubrey Johnson, MISO’s vice president of system resource planning and competitive transmission, said in an email and on social media that the JTIQ is a “critical process” to add more generation.
“It provides certainty to interconnection customers near the SPP-MISO seam and enables lower-cost energy in each region,” he said in extending his appreciation for SPP’s “strong collaboration and innovative thinking” that led to the “first-of-its-kind framework.”
SPP’s Casey Cathey, vice president of engineering, said the grid operator is “thrilled” that FERC recognized the JTIQ’s long-term value and its future benefits to members and customers.
“We’ve had a successful partnership with MISO for many years and look forward to building on that success with the JTIQ initiative,” he said in an email. “These transmission projects will be a significant step toward eliminating barriers and improving the efficiency and reliability of transmission between our regions.”
The two RTOs began working on the JTIQ process in 2020 after several unsuccessful attempts to find joint projects to alleviate congestion on their seam. They conducted reliability, economic and generation-enablement studies and coordinated with stakeholders to develop transmission solutions to identify the JTIQ upgrades that unlocked generating facilities and aligned their interconnection processes to reduce restudies and delays.
MISO and SPP say the projects, focused on their northern seam, are expected to enable 28 GW in generation additions. They said the generation projects were stymied by the massive amounts of interconnection requests; the lack of current system capacity to accommodate the requests; and the significant incremental cost of upgrades that interconnected individual clusters that would otherwise be obligated to pay for the upgrades under the RTOs’ existing “but for” cost-allocation frameworks.
The backbone of network upgrades consists of five projects, cut down from the original seven:
Bison-Hankinson-Big Stone South, 147 miles of new 345-kV lines in the Dakotas (MISO).
Lyons Co.-Lakefield Junction, 80 miles of new 345-kV lines in South Dakota and Minnesota (MISO).
Raun, a new 345/161-kV double circuit and rebuilt 161-kV lines near Omaha, Neb. (MISO, SPP).
Auburn-Hoyt, new 345-kV lines in Nebraska (SPP).
Epanding and rebuilding a 345-kV substation in Sibley, Iowa (SPP).
ANAHEIM, Calif. — The power industry should encourage increased collaboration and transparency to address the many challenges posed by major new loads, presenters said during the National Association of Regulatory Utility Commissioners’ (NARUC) Annual Meeting Nov. 10-13.
Data centers, hydrogen, transportation and other industries are all contributing to the rapid load growth, which can present both efficiency opportunities and forecasting challenges, according to Natalie Mims Frick, deputy department leader of energy markets and policy at Lawrence Berkeley National Laboratory.
Providing opportunities for conversations between stakeholders can help address those challenges, Frick said. She pointed to the North Carolina Utilities Commission’s recent ruling on Duke Energy’s consolidated carbon plan and integrated resource plan. One of the requirements is that the utility must provide frequent updates on load growth, Frick said.
“Having regular conversations can be really useful about how to deal with the growth and where it’s happening,” Frick said. She added that another requirement the North Carolina commission imposed was requiring the utility to work with their large customers “to try and identify opportunities for efficiency or other resources, whether it’s flexibility or something else.”
“And I think that kind of feeds back into the loop forecasting, you know, making sure that there’s robust consideration of all of the opportunities for the large loads, whether it is through flexibility or demand response to reduce peak demand,” Frick said.
Forecasting from a data center and automation perspective will likely remain a challenge, given confidentiality around business strategies, according to Samantha Klug, enterprise sustainability development director of logistics real estate investor Prologis.
However, it would be helpful if regulators could provide a roadmap around electrification and sustainability incentives, Klug argued.
“Because then what we can do is forecast out these projects and where we want to do them based on those incentives, and when the timing for capital investment is right for us,” Klug said. “And so for us, it’s really the communication between stakeholders.”
In a separate panel discussion, Farah Mandich, presidential sustainability executive at the General Services Administration, argued that transparency is important to help “people understand why the utilities and commissioners are making some of the decisions they do.”
Mandich added that thinking about customers’ needs as an asset, instead of just a problem to solve, is a good “mindset to be in.”
“The federal government is a longstanding existing customer. We are electrifying loads, but we’re not going to be causing the type of growth that you know a data center necessarily is in one given place, but that means that our buildings could potentially be an asset for load flexibility,” Mandich said. “And so thinking about how to bring customers into that conversation up front is really important, because it’ll take us a while to figure out how to do that in our own buildings and work with the utilities effectively.”
Jeff Riles, director of energy markets at Microsoft, noted that customers, regulators and utilities are all cooperating more frequently now than a few years ago. However, he said that there are challenges, including mistrust around growth of the data center industry.
“There’s a real concern about what’s speculative and what’s real,” Riles said. “And there’s a need to make sure that we’re showing up and helping them address the problem of what is speculative and what’s real. And so that’s been another reason why we have begun to engage more directly in a lot of these regulatory proceedings.”
He added that engaging in forums like NARUC “is new for us as an industry, and so we really appreciate the opportunity to have this collaboration. But I will just say we’re growing up right along with you in terms of how we engage in these processes and procedures.”
CARMEL, Ind. — MISO will take a breather from its long-range transmission planning over 2025 to retool the 20-year future scenarios that are the foundation of the transmission portfolios.
Speaking at a Nov. 13 Planning Advisory Committee meeting, MISO’s Jeremiah Doner said after consultation with stakeholders, MISO will concentrate on a futures makeover throughout 2025. MISO maintains three possible futures scenarios in Goldilocks style: a conservative view of the system with limited load growth and decarbonization, a middle-of-the-road view, and a progressive outlook where clean energy, innovation and demand thrive.
Some MISO stakeholders have said repeatedly the rate of change the three planning futures predict is obsolete considering that clean energy goals are revised frequently to be more aggressive and load additions are rising. MISO last overhauled its futures in 2019 and refreshed them in 2022.
MISO said it won’t embark on another long-range transmission plan (LRTP) analysis until 2026, when the RTO will work on a follow-up portfolio to the second Midwestern LRTP portfolio. That would leave MISO South’s comprehensive planning needs unaddressed until at least 2027.
Doner said MISO’s futures update will kick off unofficially with the RTO’s Dec. 18 stakeholder workshop on medium- and long-term load forecasting, where it plans to discuss probable load increases over the next 20 years.
“Let’s get through the futures update, and this time next year, we’ll have better answers” on when the Midwest follow-up portfolio and a third LRTP portfolio will take place, Doner said.
“One thing we want to do with the futures update is to make sure it serves multiple masters,” Executive Director of Transmission Planning Laura Rauch said, adding that discussion on the futures revision would start in workshops, and likely in Planning Advisory Committee and Resource Adequacy Subcommittee meetings.
The Organization of MISO States lent support to the futures revision, though it emphasized the “importance of improving connections between Midwest and South and needs within South region.”
Some of the regulators in the Organization of MISO States have asked what MISO plans to do about MISO South planning in the meantime. Illinois Commerce Commissioner Michael Carrigan pointed out at a Nov. 11 OMS board meeting that MISO’s LRTP timeline seems to leave MISO South without an economic planning study for about six years.
The working group of the Entergy State Regional Committee also recently asked MISO to perform a market congestion planning study for the MISO South region as part of MISO’s 2025 Transmission Expansion Plan (MTEP 25). So far, the RTO hasn’t added an economic study to its MTEP 25 tasks.
Doner said in addition to the futures renovation and usual MTEP 25 studies next year, MISO would like to examine how it can address large load additions in planning, focus on its current interregional planning studies with PJM and SPP and make sure it’s ready for compliance under FERC Order 1920.
Doner said MISO also has to devote staff hours to making sure approved LRTP projects are best positioned to advance through state permitting processes.
“Even though [LRTP] Tranche 1 was approved two years ago, there’s work to support [these projects] in regulatory processes. Until those projects are certain, there’s still some risk there,” Doner said.
Finally, Doner said MISO will work on planning coordination with neighbor Associated Electric Cooperative Inc. (AECI) over next year. He said AECI has planned projects that will tie into Ameren and SPP’s territories and the cooperative has approached MISO for some advice on how best to proceed.
MISO does not foresee a scenario where it comes close to risky operations this winter, saying even a 107-GW demand peak should be manageable without emergency protocols.
The grid operator published its annual winter outlook this week, predicting a nearly 21-GW excess in cleared capacity December through February using a coincident peak forecast and normal generation outages. Beyond its traditional supply, MISO has about 12 GW in load-modifying resources and operating reserves to lean on.
At a Nov. 14 workshop to discuss results, resource adequacy engineer John DiBasilio said that though MISO’s capacity auction cleared 121.6 GW of traditional generation for the winter, offers totaled 137.4 GW.
Across the board, MISO’s load-serving entities predict a 100.1-GW coincident peak; however, LSEs’ non-coincident peak predictions are 101.9 GW in December, 107 GW in January and 101.5 GW in February. Should a 107-GW peak occur in January, the RTO still predicts a 14.6-GW surplus among its nonemergency supply.
In a press release, Executive Director of Market Operations J.T. Smith credited MISO’s relatively new seasonal capacity auction for better preparing the footprint.
Last winter, MISO managed a 106-GW peak Jan. 17 during a wide-reaching cold spell without resorting to emergency procedures. (See MISO Holds Steady in Mid-Jan. Storm with Help from Wind.) MISO experienced its 109-GW all-time winter demand record on Jan. 6, 2017.
Part of MISO’s anticipated capacity sufficiency this winter is also thanks to an anticipated warmer winter across the footprint.
Analytics company and weather forecaster DTN predicts above-normal temperatures for the season in MISO’s South and Central regions with slightly warmer or closer-to-normal temperatures in the North region. The RTO splits its Midwest region into the Central, which includes the Dakotas, Minnesota, Iowa and Montana, and the North, which includes Wisconsin, Michigan, Illinois, Indiana, Missouri and Kentucky.
The National Oceanic and Atmospheric Administration anticipates closer-to-normal temperatures for MISO Midwest and a winter that trends above normal in MISO South.
Both forecasting authorities call for above-normal precipitation in MISO Midwest, especially around the Great Lakes, and a drier season for MISO South. MISO said the expected below-normal precipitation should decrease generation icing risks across the South.
MISO’s in-house meteorologist, Brett Edwards, said the season will be similar to last winter, which saw “exceptionally warm” temperatures, except for the mid-January cold snap, and normal precipitation patterns. The grid operator said last year’s temperatures are not a reference point for the upcoming winter.
Edwards said the best chances for some frigid days in MISO Midwest come in December and February if a weaker La Niña prevails. If a moderate-to-strong La Niña occurs, warmer air is expected to spread farther north. Edwards said the climate pattern appears to be shaping up to be weaker. He said historically, “weaker La Niña events have generated some cold shots and heavier precipitation events for the Midwest.”
MISO meteorologist Adam Simkowski added that though the RTO is anticipating a warmer winter overall, it is not ruling out the possibility of a few frigid blasts that drive load up, even in the South. He said that an active storm pattern around the Great Lakes could increase generation icing risks.
Many state utility regulators, policymakers, utilities and others construct the orthodox, and politically palatable, argument that market failure justifies utility energy efficiency (EE) programs and that the vast majority of those programs would pass a cost-benefit test.
Electric and natural gas utilities together spend about $10 billion annually on energy efficiency. This is in addition to the billions of dollars the federal government spends, boosted substantially by the Inflation Reduction Act (e.g., an expansion of tax incentives for the installation of energy-efficient building upgrades and the construction of energy-efficient homes). Besides all of this, subsidized EE is a major component of state and federal governments’ energy policies, driven in recent years by efforts to combat climate change.
Using the label “no-regrets,” policymakers frequently push actions they endorse as unequivocally good —everyone wins, no one loses. The “free lunches” that EE advocates ascribe to EE programs should therefore seem suspicious to anyone after little thought.
They certainly do to many analysts who have seriously studied the benefits and costs of EE initiatives. If these efforts are such a good deal, then why must government mandate or utilities subsidize them? Why aren’t energy consumers taking advantage of the large benefits that EE supposedly offers them? Are they that irrational and unaware of the benefits from EE to warrant subsidies or mandates; or, more accurately, do consumers just find better ways to invest their limited monies? It may very well be that energy consumers prefer to invest in other things, like home repairs, a new car or college. And it’s not because of market failure.
I am skeptical for two basic reasons. First, the idea that markets are less than perfect should not infer that intervention in the form of utility subsidies or government mandates benefits society. One of the major errors with government actions in a wide array of areas starts with the premise that since markets aren’t perfect, the government should intervene. This more times than not results in a higher cost to society than the benefits received. There is a concept that is often ignored in public policy debate: “government failure.”
One glaring problem is that ostensibly objective analysis of specific EE initiatives often reaches different conclusions from evaluations prepared either by utilities or for utilities.
Why is this, and whose results are more credible? Most utilities or their evaluators fail to apply the best analytical tools to their evaluations of EE programs. These tools include randomized trials and quasi-experimental designs to measure energy savings and account for consumer behavior. The problem with other approaches is that they are unreliable — in some instances grossly flawed — in measuring the actual energy savings from individual EE programs.
Another evident reality is that utilities have a self-interest in portraying their EE programs as cost-effective and, therefore, worthy of favorable treatment by their regulator (e.g., allowing the utility to profit). We cannot forget that regulators and policymakers themselves receive kudos from the public for supporting subsidies whose intent is to tackle climate change, in addition to promising reduced utility bills.
Going back, academic reviews of EE programs conclude that such programs are not the “low-hanging” fruit many people believe. They show that utilities grossly overstate energy savings from EE programs because they rely on engineering estimates that fail to account for consumer behavior (the so-called “rebound effect” or price-elasticity effect) in using, say, their higher energy-efficient air conditioners and heating systems more intensively because of lower operating costs.
Studies also find “free riders” participating in EE programs. These are individuals who would have purchased lower-energy-use appliances or heating and air conditioning systems in the absence of the EE program. It would be wrong to count their energy savings as real benefits, which can show a program as cost effective when in fact it is not. Some studies have shown that participants in utility EE programs primarily are consumers who are wealthier, own their own homes, and are more informed about and attentive to energy costs.
Studies also note that government and utilities often fail to consider “hidden costs” for consumers from the time and effort spent on both energy audits and investments. The combination of these factors, according to some academic studies, has understated the true costs of EE programs by as much as 50% or more.
Policymakers should ask the fundamental question: Why should utilities and the government subsidize EE when energy consumers are capable of making rational decisions for themselves? Is it equitable and good public policy to compel utility customers to pay for EE initiatives that benefit a relative few (who are on average wealthier than the funders of those initiatives) when some of those would have invested in EE without utility assistance?
Kenneth W. Costello is a regulatory economist and independent consultant.
In a teleconference that Chair Todd Bennett, of Associated Electric Cooperative Inc., acknowledged was “heavy with content,” NERC’s Standards Committee agreed to move forward on a number of standards development projects Nov. 13 amid sometimes lively discussions.
Changes to SAR Revision Approved
The agenda began with a proposal to revise a standard authorization request (SAR) intended to address reliability risks in the performance of inverter-based resources (IBRs). The SAR was developed by NERC’s Inverter-Based Resource Performance Subcommittee (IRPS) and endorsed by the ERO’s Reliability and Security Technical Committee (RSTC) at its last meeting Sept. 11. (See NERC RSTC Approves Charter Revisions.)
As drafted by the IRPS, the SAR would update the existing standards FAC-001-4 (Facility interconnection requirements) and FAC-002-4 (Facility interconnection studies) to require transmission owners to establish IBR performance requirements along with their associated transmission planners and planning coordinators. SC members were asked to accept the SAR, authorize posting it for a 30-day informal comment period and assign it to the standard development team for the ongoing Project 2022-04 (EMT Modeling).
Members generally expressed support for the SAR, although Amy Casuscelli of Xcel Energy asked why NERC staff proposed assigning the SAR to the Project 2022-04 team rather than Project 2023-05 (Modifications to FAC-001 and FAC-002), which is already working on the same standards. NERC Manager of Standards Development Alison Oswald explained that staff “felt that this [task] better aligned with the work that the 2022-04 team was already doing.” In addition, she said that Project 2023-05 is considered “low priority” by NERC, so its team has not met recently.
Following this exchange, Casuscelli moved that the proposed informal comment period be changed to a formal one. She explained that she was concerned that the SAR had not received wide support from the RSTC and noted that even at the IRPS meeting that approved it, only 11 of 40 members voted in favor.
“That, to me, does not read like consensus,” Casuscelli said. Her fellow members agreed to accept her modification to the proposal and passed it unanimously.
Approved Standard to be Updated
Next was a proposed correction related to the draft standard TOP-003-7 (Transmission operator and balancing authority data and information specification and collection) and its implementation plan, which recently received industry approval in a third formal comment and ballot period that ended Nov. 4.
TOP-003-7 received a 92.77% segment-weighted approval, with the accompanying standard BAL-007-1 (Energy reliability assessments) receiving 81.53%. Both exceeded the two-thirds majority needed to move to NERC’s Board of Trustees for approval.
According to ISO-NE’s Mike Knowland — a member of the team that developed the standards — two errors were identified during the public comment period. NERC staff considered the issue urgent enough to request as part of the consent agenda that SC members waive the normal five business day limit for agenda changes.
The first error involved the effective dates for the terms “energy reliability assessment” and “near-term energy reliability assessment.” According to the balloted proposal, the terms would become effective at the same time as BAL-007-1, 24 months after the date of the standard’s approval by FERC.
However, the terms are also used in TOP-003-7, which would become effective six months before the other standard, according to the proposed implementation plan. This would mean TOP-003-7 would become effective before the definition was officially entered into NERC’s Glossary of Terms.
NERC staff proposed amending the implementation plan to move the effective date of the definitions forward by six months. In addition, staff proposed removing the term “energy reliability assurance” from TOP-003-7. Knowland explained that this term was erroneously left in the standard from a previous draft and should have been deleted before the ballot was conducted.
Committee members approved both proposals with no votes against them, although Marty Hostler of the Northern California Power Agency and Maggy Powell of Amazon Web Services both abstained, citing discomfort with the idea of changing an implementation date that industry already approved without giving stakeholders another chance to weigh in.
Because the updates are considered non-substantial, no further ballot period is required. The standards and implementation plan will be submitted to the board with the changes applied.
Next Phase of IBR Effort Underway
From there, the committee moved to three SARs concerning FERC Order 901, which requires NERC to submit new standards to improve the reliability of IBRs by 2026.
The ERO recently submitted the first of three planned tranches of new standards intended to satisfy FERC’s order. (See NERC Submits IBR Standards to FERC.) Now NERC is moving to the second tranche, which will cover data-sharing and model validation for IBRs; they are due to FERC by November 2025.
As unanimously approved by the SC members at the meeting, the SARs will be assigned to three existing standards projects:
Project 2020-06 — Verifications of models and data for generators; and
Project 2021-01 — System model validation with IBRs (the new name of this project is on page 86 of the agenda but not yet on NERC’s website).
SC members also approved a proposal to appoint replacements for the chair and vice chair of the team for Project 2021-01, along with several SDT members. NERC’s Oswald explained that most of the original team members felt they lacked the expertise for their new remit. Only two of the existing team members will remain on the roster going forward, for a total team strength of six.
