Texas regulators have pumped the brakes on the proposed performance credit mechanism’s (PCM) development, making it clear that they and stakeholders will be involved in the market tool’s design.
“We need broader input, not just from commissioners, but also from stakeholders,” Public Utility Commission Chair Tom Gleeson said during the agency’s open meeting March 7.
ERCOT staff filed a memo before the meeting outlining a study approach for designing a PCM strawman. It identified 37 design parameter decisions and an evaluation methodology to select the final design, with several options for each parameter decision (55000).
Staff also suggested a timeline that includes three stakeholder workshops and PUC approval of the final design in early 2025. ERCOT would then develop necessary protocols and, following commission approval, “evaluate” the PCM’s implementation.
“This timeline that’s laid out in in your filing is very compressed, it’s very rushed, and it completely leaves out the commission in terms of workshops and engagement and any kind of stakeholder feedback over here,” Commissioner Lori Cobos told ERCOT staff.
Gleeson called the implementation evaluation in ERCOT’s timeline “open ended.”
“That wasn’t a completion timeline,” he said. “There’s still work to be done in ERCOT through their protocols and through their system upgrades. The actual implementation of this would still be much further, so I just don’t know that we have enough information now to have a timeline somewhere in 2026, 2027 mean anything at this point.”
Further complicating the timeline is ERCOT’s development of real-time co-optimization, scheduled to be deployed by Dec. 31, 2026. That market tool is designed to improve energy procurement and dispatch.
Cobos laid out a schedule beginning with PUC staff filing a memo before the commission’s March 21 open meeting providing their input on ERCOT’s proposed design parameters. The PUC again would consider the PCM during its April 11 open meeting before handing over its feedback to the ISO. That would move the date for the grid operator’s first workshop from March 26 into April, with stakeholders submitting feedback to the PUC.
The commission agreed at least one of the workshops, likely the first, should be held at the PUC’s offices, and that the Independent Market Monitor and ERCOT staff conduct separate studies on the mechanism’s market effects.
“We need to have two data points, two views of how the PCM is going to cost and affect the market,” Commissioner Jimmy Glotfelty said, stressing that design decisions are policy questions best taken up at the commission.
ERCOT has engaged Energy and Environmental Economics (E3) to support the strawman’s development. E3 also worked with Astrapé Consulting at the PUC’s direction to evaluate the PCM and five other potential market reforms. While the study did not recommend the PCM, then-Chair Peter Lake determined the mechanism would best incent more dispatchable generation. (See Proposed ERCOT Market Redesigns ‘Capacity-ish’ to Some.)
The PCM establishes a reliability standard and corresponding quantity of performance credits (PCs) that must be produced during the highest reliability risk hours to meet the standard. Load-serving entities can purchase PCs, awarded to resources through a retrospective settlement process based on availability during hours of highest risk, and trade them with other LSEs and generators in a forward market; generators must participate in the forward market to qualify for the settlement process.
The PUC adopted the PCM for inclusion into the ERCOT market in January 2023. Also last year, Texas lawmakers passed a bill (HB 1500) establishing legislative guardrails for the PCM’s implementation.
The commission determined the PCM’s $1 billion annual cap, as set by the Texas Legislature, is an “absolute” annual cost cap, not an average annual cap.
MISO has registered a separate complaint with FERC to retract market-to-market coordination with SPP on a contentious flowgate persistently taxed by a North Dakota cryptocurrency mining operation.
MISO said it wants refunds for its members and for FERC to end what it calls “improper M2M coordination activities” on the 230-kV Charlie Creek flowgate because it cannot offer meaningful congestion relief (EL24-85). The grid operator sought fast-tracked treatment and said its complaint should dovetail with an initial complaint submitted by Montana-Dakota Utilities Co. (See Crypto Load on MISO-SPP M2M Constraint Draws Complaint from Montana-Dakota Utilities.)
MISO repeated concerns made in the original complaint that the flowgate, which serves the 200-MW Atlas Power Data Center, has cost its members more than $38 million in “unnecessary, unjust and unreasonable M2M charges.” (See SPP, MISO Clash over Crypto-strained M2M Flowgate.)
MISO said SPP is violating their M2M coordination procedures under the RTOs’ joint operating agreement by refusing to lift the line’s M2M status. It said the flowgate is being used to “address local congestion issues in a load pocket located in [SPP] … where MISO has no regional flows and is unable to relieve congestion due to the lack of generation.” MISO asked for refunds for M2M charges associated with the flowgate from April 1, 2023, onward.
Additionally, MISO asked FERC to pronounce it and SPP’s current M2M coordination termination process unreasonable and discriminatory because MISO doesn’t have recourse to revoke congestion management even when it’s unhelpful, leaving its members on the hook for millions. MISO also said it didn’t have faith that it and SPP could revise the provisions in their interregional coordination process without FERC guidance.
“This finding will ensure that the dispute that led to this complaint does not occur again and is promptly remedied, as both MISO and SPP appear to agree that changes are needed while disagreeing on how those changes should be implemented. MISO will work with SPP to develop appropriate revisions, but MISO does not believe that even a mutually collaborative effort, without the benefit of such a threshold FERC finding, providing a firm timeline and prescribed compliance process, would be effective or expeditious,” MISO wrote.
MISO said M2M coordination on Charlie Creek should have ended as soon as the Atlas Power Data Center began operating early last year.
MISO said neither it nor SPP have adequate generation to relieve the constraints “exacerbated” by the cryptocurrency facility situated in the Williston Load Pocket (WLP). It also said it and SPP have no “economic” M2M coordination available to them, with SPP acknowledging in a 2021 transmission planning report that the “root” of the issue lies in “the lack of transmission to accommodate the level of transfers required to serve the forecasted load in the future, contributing to a weak system unable to maintain acceptable voltage levels.”
“In fact, congestion in the WLP stems primarily from a local reliability issue and the best solution is to build additional transmission,” MISO argued, saying the “obvious ineffectiveness” of the M2M coordination should be clear to FERC.
SPP has asked FERC to deny Montana-Dakota Utilities’ complaint, maintaining that the M2M activation and congestion coordination is permitted according to the joint operating agreement. It has said it and MISO are working through the disagreement, though MISO has said negotiations are at an impasse, which effectively works as SPP blocking any hope for an M2M cancellation.
A new analysis concludes that building long-distance high-voltage transmission would save money and speed decarbonization of the U.S. power grid.
The National Renewable Energy Laboratory report on interregional renewable energy zones (IREZ) issued March 7 is the first of several companion reports for the National Transmission Planning Study, targeted for release later this year.
The IREZ concept would link the highest concentrations of the lowest-cost renewable energy potential with the highest concentrations of need for that power by building new transmission lines stretching hundreds of miles.
The value of interregional transmission has been well established as the nation shifts to a more intermittent power generation profile. The challenges of building it also are well known.
For starters, state-level review of transmission proposals often focuses heavily on needs and benefits within that state, rather than the region or nation. Then there are multiple federal permits, local authorizations and other state approvals to secure, plus willing cooperation of states with each other and in some cases, the approval of tribal nations.
FERC flagged these and other barriers to siting long-distance high-voltage transmission — as well as opportunities — in a 2020 report to Congress. The Brattle Group offered its take in 2021.
In announcing the new report, NREL acknowledged the importance of multistate cooperation to make the IREZ concept work.
Lead author David Hurlbut, an NREL researcher, said the IREZ report is intended to make it easier for states to answer the questions that arise in their regulatory processes.
“Long-distance transmission between planning regions was always harder to get through the approval process than new lines within the same region,” he said. “But over the past few years, the power sector has been changing in ways that might make interregional transmission a more compelling option than it used to be.”
This diagram created by the National Renewable Energy Laboratory shows the concept of interregional renewable energy zones. | NREL
The report could also inform tribal nations that will be part of the decision-making process when their lands are included in IREZs.
The report’s authors wrote that the renewable energy zone concept originated in Texas two decades ago as wind power expanded in that state. Lessons learned from Texas’ experience helped guide the process, which yielded several high-value IREZ corridors.
The authors say these corridors could help reduce carbon emissions, improve resource adequacy and boost grid resilience with a relatively small impact on customers’ bills.
They are, the authors say, the “low-hanging fruit” in the clean energy transition, maximizing the value of commercially mature wind and IREZ solar technology and delivering that value to the customers who would pay for it.
The wind IREZ regions cited in the report are almost all in the Midwest and the solar IREZ regions are all in the Southwest, while the load centers are mostly hundreds or many hundreds of miles distant.
Subsequent analyses by states in a proposed corridor might lead to other configurations, but for the report, NREL analyzed the role of a 600-kV HVDC line with 3 GW of capacity in the resource mix. The authors also assumed that the best 15 GW of resource potential within the zone would compete for access to that 3-GW transmission hub.
Several of the IREZ corridors analyzed in the report align with those in the U.S. Department of Energy’s National Transmission Needs Study, issued last October, and the upcoming National Transmission Planning Study, as well as with projects under construction or in advanced permitting.
The Pacific Northwest National Laboratory contributed economic analysis to the IREZ report. It also is collaborating with NREL on the National Transmission Planning Study.
BOSTON — Transmission limits remain a major barrier to scaling up wind and solar energy to meet state decarbonization goals, speakers at the Northeast Energy and Commerce Association’s Renewable Energy Conference said March 8.
The conference featured panels on offshore wind, resource interconnection and networked geothermal heating, but grid constraints were a major theme throughout the day.
“We are in full recognition that a lot of work needs to be done on the grid in order to interconnect a lot of offshore wind projects,” said Joanna Troy, deputy commissioner of the Massachusetts Department of Energy Resources. Coordinating the planning and cost allocation for this transmission will be key components of scaling up offshore wind, she said.
Troy highlighted the work of the state’s Interagency Offshore Wind Council, which is conducting stakeholder engagement for a “strategic offshore wind road map” the administration intends to release in late summer or early fall.
Andrea Hart of Atlantic Shores Offshore Wind stressed the importance of coordinating planning efforts for offshore wind transmission.
Connecting an increasing number of offshore wind projects in an uncoordinated manner could create a “spaghetti dilemma,” with separate lines connecting to the shore at different points, Hart said. This could increase project costs, timelines, environmental impacts and local opposition.
Hart said separating offshore wind development and transmission into separate procurements can help reduce the development risks, highlighting ongoing processes in New York and New Jersey.
“States are starting to do this, but it is still in a piecemeal fashion,” Hart said. “States aren’t yet in this place where they can come up with transmission solutions that transcend state lines, that transcend ISO or RTO territory.”
Hart added that until transmission solutions are “waiting and ready to be used by developers, generators are going to bake in a lot of risk into their prices.”
Reducing the number of transmission lines landing onshore could also help reduce the opportunities for lawsuits from local opponents. The first wave of offshore wind projects under development has faced a series of so-far-unsuccessful lawsuits aimed at halting them. (See Another Federal Lawsuit Seeks to Invalidate OSW Approvals.)
Josh Kaplowitz, senior counsel at law firm Locke Lord, emphasized the importance of early and meaningful engagement with host communities.
“It’s critical to go into communities early to share facts on the benefits of offshore wind, listen to concerns and adapt projects if feasible,” Kaplowitz said. At the same time, “at this early stage in the industry, when people are still getting used to offshore wind, you’re not going to prevent all lawsuits. It’s unlikely that you’re going to be so good at community engagement that no one’s going to want to challenge projects.”
The transmission constraints in New England are not limited to gigawatt-scale offshore wind projects; they also impact smaller onshore projects connecting to both the transmission and distribution networks.
“I think it’s a great step in the direction of holistic planning,” said Sheila Keane, director of analysis for the New England States Committee on Electricity. “When I think about Order 2023 and the broader context of where we’re going, we’re going to need a lot more resources coming online.”
Barry Ahern, director of transmission planning and asset management for National Grid, said he is “trying to remain on the optimistic side” regarding the impacts of the order on transmission interconnection.
The order will likely make it “more predictable when you will get your results, but more unpredictable on what they will be,” Ahern added.
Weezie Nuara, assistant secretary for federal and regional energy affairs at the Massachusetts Executive Office of Energy and Environmental Affairs, applauded ISO-NE’s incorporation of stakeholder input into the Order 2023 compliance proposal.
“It really does seem to be a good news story of the stakeholder process working for all of us,” Nuara said. “Of course, there can be further improvements, and it remains to be seen how effective all these reforms will be. These are massive changes, moving from first-come-first-served to first-ready-first-served with a cluster study approach.”
The order could also affect state-jurisdictional projects connecting to the distribution system, Nuara added.
“I’m very curious to see how the coordination with [affected system operator] studies plays out,” Nuara said, adding that some interconnection customers to the distribution system “are also having to undergo transmission studies because they’re just such large clusters of distributed generation requesting interconnection to the distribution system. So that is having knock-on effects on the transmission system, and ISO New England has gotten involved in a big way.”
Nuara expressed hope that Order 2023 compliance “will maybe help corral some of the study work that’s going on for [distributed generation] projects.”
NEW ORLEANS — After being forced to turn away attendees from 2023’s Gulf Coast Power Association MISO–SPP Forum, the association set up shop this year in a name-brand hotel near the French Quarter. All the better to welcome more than 330 attendees, a record, for discussions that focused primarily on the energy transition.
“Here we are in a real hotel,” said R Street Institute’s Beth Garza, chair of the GCPA board, in kicking off the March 4-5 conference.
During a friendly opening chat between MISO’s and SPP’s CEOs, Barbara Sugg said maintaining resource adequacy and addressing “massive” load growth during the transition comprises the nucleus of RTO operations today.
Sugg said she sympathized with SPP members having to make decisions about resource retirements while also facing potential capacity deficits. SPP needs to ensure it has “enough of the right resources,” Sugg said, noting adequate future reliability attributes “are just not there yet” in generation lining up for the grid today versus what’s retiring.
“For us, it’s all about the energy transition,” MISO CEO John Bear said, adding that MISO has a good feel for what its members hope to accomplish over the next 15 years.
He said MISO is preoccupied with transmission planning, a market redesign and completing a market platform upgrade to handle a great deal more variability. MISO is also working on a complete redesign of control room operations, he added.
“Besides that, we’re not very busy,” Bear joked.
Bear said before, MISO operations were a “simple exercise,” with MISO carrying enough reserves to get the footprint through a predictable afternoon peak. Today, Bear said, MISO must secure many more types of operating reserves to handle weather conditions that “vary significantly by day.”
“We’ve got to watch closely new technology, but it’s still out there” in the distance, Bear reminded attendees. He said though new technologies are promising, they’re not yet developed enough to be able to take over for scores of retiring baseload generation resources. He emphasized that MISO needs to maintain a fleet of dispatchable generation resources to supplement weather-dependent resources.
However, Bear said he’s optimistic about the potential for iron-air battery storage, once an unwieldly and forgotten technology of the 1970s. He said MISO is set to add three 5- to 15-MW iron-air batteries in the coming years.
Mike Wise, senior vice president of regulatory and market strategy at Golden Spread Electric Cooperative, said load-serving entities are in a “real challenging environment.” He said the fleet transition for LSEs is like a bad version of an ’80s beer commercial. He said instead of the “more taste, less filling” slogan conveying two competing positives, LSEs face a “more cost, less reliable” reality with only disadvantages.
Wise blasted SPP’s recent FERC filing hiking its planning reserve margin requirement from 12% to 15%. Golden Spread, American Electric Power, Xcel Energy and several cooperatives have protested the proposal in a joint filing. Wise said SPP simply cannot dictate a planning reserve margin 25% higher than six months ago. He said the RTO and market participants need to slow the transition down so “we don’t destroy” today’s system.
“You’re putting loads between a rock and a hard place: … can’t find it, can’t build it. What are you going to do?” he asked rhetorically. “These are unmanageable numbers.”
Wise said new natural gas combustion turbines are the most attractive choice for affordable and reliable power that earns a consistent capacity credit.
“We’re forced into making 30- to 40-year decisions very quickly,” 1803 Electric Cooperative COO Ron Repsher said of resource planning. Despite the obstacles, he said the relatively new cooperative will continue to pursue self-built generation and not rely solely on power purchase agreements with independent power producers.
Repsher said while it’s true that 1803 customers want environmentally friendly power when they are polled, they also indicate they’re unwilling to shoulder more costs to implement it.
“What that really means is they want reliability. First and foremost,” he said.
Entergy Director of System Planning Samrat Datta said the transition is complicated by resource adequacy risks, large load additions, and ever-evolving rules from RTOs and federal agencies. He said Entergy intends to meet its sustainability goals “because our customers want it.”
Jim Dauphinais, an attorney representing multiple industrial customers in MISO, said customers not only are concerned over a large-scale reliability failure, but RTO market rules “moving very quickly.” He said the costs of market rule changes “trickle down very quickly” to customers and he said they’re concerned about an overinvestment in grid facilities.
“We can get ahead of the game and build facilities that are neither used nor useful,” Dauphinais said. “We can make progress toward clean energy, but we have to do it in a way that’s economical.”
Keith Collins, SPP’s vice president of market monitoring, said standby generation is undoubtedly undervalued and called for the industry to improve the quality of green energy.
“It’s one thing to have the four-hour battery. It’s another thing to have a four-day battery,” he said. “We need resources to be available.”
But “the market cannot get what is not valued,” Collins said, adding that premiums should be placed on attributes that promote flexibility, availability, resiliency and dependability.
“A gas resource that’s more secure should have more accreditation,” he said.
Carrie Milton of Potomac Economics, MISO’s Independent Market Monitor, said the RTO’s markets are “well structured” to reliably handle the clean energy transformation. MISO intends to pivot to a marginal, availability-based capacity accreditation and recently proposed to up its value of lost load from $3,500/MWh to $10,000/MWh.
Milton said the grid operator’s markets would benefit from longer-lease reserve product to handle uncertainties that arise over two to four hours and a look-ahead dispatch that anticipates instructions an hour ahead of time, rather than during five-minute intervals.
Although some “tweaks” will be needed along the way, Milton said, the MISO markets send strong price signals when generation is necessary.
“The nice thing about shortage pricing … is that every generator in that moment is going to try to get on the system,” she said.
But Collins said when neighboring RTOs choose different reserve pricing setups and values of lost load, those differences can complicate or even dissuade some power exports.
“That’s something of real concern that as different markets choose different designs, that can affect imports and interchanges,” he said.
“You’re hearing about the doom and gloom we’re facing over the next five to 10 years. We’re here to talk about the solutions,” Southern Renewable Energy Association Executive Director Simon Mahan said in opening a panel on how hydrogen, offshore wind, carbon capture and small modular nuclear reactors can assuage a reliability crisis.
He asked panelists what makes them optimistic about their burgeoning technologies.
“We’re going through the ‘hype cycle’ for clean hydrogen,” Center for Houston’s Future CEO Brett Perlman said, citing 35 potential hydrogen projects in development around the Gulf of Mexico.
“It’s a testament to the developer-friendly mentality we have in Texas and Louisiana,” Perlman said. He said he thinks hydrogen is on the cusp of greater adoption and likened it to the atmosphere in Texas 20 years ago, when the state began adding wind and solar resources at a record rate.
Perlman also said tax incentives that put early hydrogen projects on equal footing with other generation builds are vital. Anthony Bodin, development director for RWE’s Gulf of Mexico offshore wind project, said the developer secured a federal lease last year to develop an up-to-2-GW offshore wind farm about 40 miles off the Louisiana coast. However, the “GoMex” project isn’t expected to be commercially operational until the mid-2030s.
“It’s going to take time, so we have to be patient,” Bodin said. “The potential for offshore wind is massive.”
Michael Curtis, Dow’s carbon and energy technology principal, said he’s hopeful the company’s development of a small modular reactor at its Seadrift Operations manufacturing site in Texas by 2030 will create a blueprint for other similar projects at industrial sites.
“Being first, there are a lot of eyes on us … Maybe in 15 years, we’ll see more of these projects actually up and running,” Curtis said. However, he added, a beleaguered enriched uranium supply chain presents obstacles to developing SMRs.
“Instead of giving out millions of dollars with an ‘M,’ we’re giving out billions of dollars with a ‘B,’ and that’s a real shift,” said Maria Duaime Robinson, director of the Department of Energy’s Grid Deployment Office.
Duaime Robinson said the department recently distributed about $7 billion and will hand out more than that in the coming years. She said despite some perceptions, DOE is making its investments in a “thoughtful fashion and not just throwing money at the problem.”
Durham McCormick, a partner at McGuire Woods, said the monetary awards contained in the Inflation Reduction Act don’t operate under a carrot-and-stick mentality. Instead, he said the IRA’s tax credits and grants are equivalent to smacking the industry with a “giant carrot.”
McCormick said new types of resources must come online for the U.S. to meet the Paris Climate Accord’s emissions goals. He said he foresees more renewable curtailment and increased battery storage over the next decades to keep generation and load lined up.
Electric-gas Harmonization not Rocket Science
Bob Gee, co-chair of the 2022 Gas-Electric Harmonization Forum for the North American Energy Standards Board, called for more transparency into gas pipelines and “more timely collection” of granular information regarding their operational status.
Perhaps because his keynote address came during the first day’s last session, the former Texas Public Utility Commission chair chose hot dog vendors as his analogy.
“A certain degree of transparency is required when your business serves the public, whether you are an electric or gas utility or a hot dog seller,” Gee said. “But today, we have more transparency in how Nathan’s makes hot dogs and what goes into them than we do on certain intrastate pipelines, such as available capacity. This is significant because if I don’t like Nathan’s hot dogs, I can buy one from another hot dog maker. In the intrastate pipeline industry, there is no Oscar Mayer pipeline.”
Gee, former FERC Chair Pat Wood and Sue Tierney, DOE’s assistant secretary for policy under President Bill Clinton, spent more than a year working to produce their report at the request of FERC and NERC. “Houston, We Have a Problem” laid out 20 recommendations to improve coordination between the electric and gas sectors, although five revealed “widely divergent opinions” between the industries.
“Despite this increasing interdependence between our natural gas and electric power delivery systems, we have yet to significantly overhaul the way these two industries interact and rely upon one another, and thus remain at risk,” Gee said.
He said the gas-electric system has its weaknesses because the gas infrastructure originally was designed to supply local distribution companies, not to serve power markets. “Over the last 20 years, this interdependence has doubled. But with that interdependence, our needs for attention and responsiveness have increased,” Gee said.
“We ignore the long-term consequences of this dynamic relationship at our peril.”
The forum report’s title is a reference to the historic 1970 Apollo 13 mission. “Houston, we have a problem,” were astronaut Jack Swigert’s words back to Mission Control after an oxygen tank ruptured and disabled the spacecraft’s electrical and life-support systems. The crew relied on the lunar module’s backup systems to return safely.
“NASA dusted itself off, fixed its quality-control systems, and successfully completed four more manned lunar missions in the succeeding two years,” Gee said. “Unlike Apollo 13, harmonizing the gas-electric divide isn’t rocket science. We can do this.”
Just Transition for the Disadvantaged
Sanya Carley, co-director of the Kleinman Center for Energy Policy at the University of Pennsylvania, delivered a sobering reminder that many in the U.S. cope with overwhelming poverty and are overlooked in the energy transition.
Carley said U.S. utilities carried out about 2.62 million disconnections in 2022, according to utilitydisconnections.org. She said disconnections disproportionately affected households of color, households with children under age 5, households that rely on medical equipment or households with homes in disrepair.
According to information from the U.S. Energy Information Administration, one in three households reports difficulty affording energy bills while keeping their homes at comfortable temperatures. One in three households also struggles to pay bills.
New low-carbon technologies are adopted predominantly by wealthy and white households. The associated financial tax incentives flow disproportionally to them, Carley said, arguing for a reassessment of subsidies.
“Energy systems have always created winners and losers and this energy transition will be no different unless there are deliberate and coordinated efforts otherwise,” she said.
Carley said she has visited communities that were “very heavily rooted” in coal production, calling them “mono-economies.” She described coal companies going under and “completely removing” an entire town’s tax base, leading to cascading effects where breadwinners lose salaries and no longer can afford to dine out, leading to a “degradation of the entire economy.”
Carley said she’s spoken to community members who reported feelings of grief, bitterness and being used by the nation when coal was king. She said during 2020 and 2021, autoworkers told her they were being deceived about the electric vehicle boom. They said the EVs they were building were unaffordable and lacked adequate charging infrastructure once they’re on the road, Carley said.
Nevertheless, she said, the workers felt they’ve earned the right to build the next generation of automobiles, having given their youth and oftentimes health to build gas-powered vehicles.
“Inequities in the energy system are inevitable, yet avoidable with deliberate action,” Carley argued.
Evaluating FERC Order 2023
“The era of flat demand is over!” declared Chelsea Howard Robben, an executive director of regional origination for NextEra Energy, during a panel discussion on FERC Order 2023 and its incorporation by grid operators.
Referring to the never-ending hunger for energy by the oil and gas sector and electrification, Robben said, “This is an exciting time for our industry. As we see these demand growth opportunities, let’s capitalize on it.”
Order 2023 is designed to do just that. It requires transmission providers to study projects in clusters, penalizes those that don’t complete the studies on time and adds requirements discouraging speculative projects to unclog jammed interconnection queues. (See FERC Updates Interconnection Queue Process with Order 2023.)
“I know both SPP and MISO have stated goals to shrink that process to a 12-month process, but we still have interconnection queues that are five and seven years old,” Robben said.
FERC special counsel Kim Smaczniak said transmission planning must be forward-looking rather than reactive, saying the future is going to look very different from the past.
“When we see the pace of retirements and the volume of generation that is seeking to interconnect, ensuring that that new capacity can come online quickly and safely is essential to ensure the reliable, affordable grid,” she said. “Doing a better job of looking ahead to understand the future supply and demand conditions is, in my view, a no-brainer. We need to ensure transmission investments float infrastructure that will make the grid more reliable and resilient.”
“Having a well-functioning interconnection queue means we can get through it quickly. We know what our upgrade costs are going to be. It’s incredibly important to my company,” said Nicole Luckey, senior vice president of regulatory affairs for Invenergy. “We were really pleased with Order 2023. I think there are little tweaks here and there that we’ve certainly raised, but we think implementing cluster-based studies across the U.S. is going to make for a more efficient interconnection process.”
Kayla Messamore, vice president of strategy and long-term planning for Evergy, said her company has some concerns with the order’s penalty structure. Were SPP to pay a penalty for missing a deadline, she said, its nonprofit status would mean the members would end up covering the costs.
“So that’s the main concern. … But in general, I think it’s great,” she said. “We have 4,000 MW of renewables that just Evergy is trying to add over the next 15 years. So, we have a lot of reasons to want the queue to move more quickly and to avoid future backlogs.”
A former Washington State Department of Transportation (WSDOT) economist is suing the state over allegations he was forced out of his job because his superiors did not like his forecasts showing that gasoline prices would jump under the state’s cap-and-invest program.
Scott Smith’s attorney filed the suit March 5 in Thurston County Superior Court against Gov. Jay Inslee, Washington’s Office of Financial Management (OFM) and WSDOT. Smith in November filed an employment claim against the same three parties seeking $750,000 in lost income because he felt pressured to leave the agency before he was ready to retire. (See Cap-and-trade Subject of Employment Claim Against Wash.)
When Washington’s cap and-invest program went into effect in January 2023, Smith was an economist specializing in gas prices for WSDOT. His lawsuit alleges that he submitted an estimate to agency officials that cap-and-invest would raise Washington’s gasoline prices by 40 to 50 cents per gallon.
Smith and his attorney, Jackson Maynard, spelled out the allegations in the suit during a March 6 press conference. They said Smith was told to revise his estimates and asked to clear subsequent work with the OFM and that he faced retaliation within his department.
“They repeatedly attempted to get me to jimmy my numbers,” Scott said during the conference.
The retaliation allegedly consisted of having his workplace evaluation revised and backdated, as well as being denied access to up-to-date software, turned down for a promotion and denied leave to visit a sick mother in New Orleans. The atmosphere was unfriendly enough that Smith left, he said, and he has not been able to find a job since.
The lawsuit said: “The fact that carbon taxes raise the cost of gasoline is a matter of 6th-grade math. The incidence (who the cost ultimately falls on) is usually assumed to be 100% on the consumer.”
Washington’s Department of Ecology — and not WSDOT — prepares economic forecasts for the cap-and-invest program, which is the cornerstone of Inslee’s climate change efforts. WSDOT’s gas price predictions were for internal purposes and were to be sent to the state House and Senate transportation committees. Citing Ecology’s estimates, Inslee has in the past said the program would add only pennies per gallon to gas prices.
However, Washington’s cap-and-invest auctions have produced higher-than-expected prices for carbon allowances, increasing costs for polluters, including oil companies. Various estimates have shown the program adding 21 to 50 cents to the price of gas.
One difficulty in assessing the economic ripple effects from the allowance prices is that while seven oil companies are eligible to bid during the quarterly auctions, some have skipped the events. Also, names of winning bidders are confidential, so nobody outside the Ecology Department knows exactly which oil companies have actually bought allowances and how many.
While Washington’s gas prices increased significantly in 2023, they also dropped sharply in the latter half of the year. Washington and the other West Coast states have had the highest gasoline prices in the nation for many years for a variety of geographical and economic reasons.
Conflicting Accounts
At the press conference, Smith and Maynard contended that WSDOT additionally retaliated against Smith by approaching the Legislature in February 2023 to introduce House Bill 1838, passed unanimously by both houses last year, which eliminated WSDOT’s gas price section and transfer its functions to the state’s Economic and Revenue Forecast Council (ERFC), which is made up of legislators, government officials and support staff. The bill also tweaked the ERFC in unrelated ways.
HB 1838 went through three hearings in 2023, at which bill sponsor Rep. Jake Fey (D) and a pair of OFM officials were the only people to testify, with no participation by WSDOT. In an email to NetZero Insider, a department spokesperson said WSDOT did not approach any legislators about the bill’s changes.
At a Feb. 20, 2023, House Transportation Committee hearing on the bill, Fey and the OFM officials said WSDOT economists had done an excellent job but that the department was having trouble recruiting economists to fill openings, while the ERFC has a better record of attracting candidates. Fey also said it is important that the transportation revenue forecast be consistent and coordinated with the forecasting done for the overall state budget.
No opposition was voiced during the hearings last year. At the February 2023 hearing, Rep. Ed Orcutt (R) said the transfer of duties had been suggested several years ago. The House and Senate unanimously passed HB 1838.
In a December email to NetZero Insider, Inslee’s office said the OFM official cited in Smith’s November complaint did not recall declaring that Smith’s work needed to be reviewed by OFM.
The governor’s office noted also that WSDOT was considering Smith’s request to work remotely, but that he did not finish the process for that decision-making, and that Smith’s request for time off with his mother around Thanksgiving conflicted with a presentation he was scheduled to give.
Smith said March 6 that his offer to give the presentation remotely had been rejected. He said other WSDOT employees were allowed to work remotely while he was not.
Inslee’s office and WSDOT declined to comment on the lawsuit.
WSDOT said it is conducting an internal investigation of the retaliation allegations and expects that investigation to be complete by the end of this month.
FERC has issued an order partly approving rule changes CAISO filed to its tariff that are meant to enable its participation in the Extended Day-Ahead Market (EDAM) once it goes live (ER24-379).
The EDAM tariff is the largest and most complex suite of software enhancements since CAISO’s market redesign and technology upgrade almost 15 years ago, and it requires the ISO itself to change its internal rules to participate smoothly.
On March 7, FERC accepted all of the proposed rules except for the proposal to calculate EDAM historical revenue recovery, which drew a protest from Southern California Edison.
EDAM participation might affect the allocation of revenues that transmission owners get for using their transmission system, and the ISO proposed an “EDAM access charge” to recover any shortfalls relative to historical revenues.
The charge is designed to recover three types of costs: foregone historical transmission revenue from sales of short-term firm and nonfirm transmission products under the transmission service provider’s tariff; any new lines that get approved to increase transfer capability between EDAM entities based on the proportional ratio of historical short-term sales to overall historic transmission revenues; and foregone revenues for the use of the grid when wheeling through transfer volumes in a balancing authority are greater than total import and export transfer volumes for it.
SCE did not take issue with the three allocation components for calculating revenue, but it protests the inclusion of “subscriber” participating transmission owners or other PTOs in the allocation of EDAM recoverable revenue.
The subscriber PTO model allows developers building lines to bring renewables from out of California that are not picked by the ISO’s planning process by signing up “subscribers” who will pay for the transmission line, which would be controlled by the ISO once operational. (See CAISO Board OKs Plan to Admit Subscriber-funded Transmission Lines.)
The subscriber model is new, so none of them will have historical costs and they would not provide transmission service because the ISO does that, SCE said.
SCE also argued the rules would provide windfalls to any subscriber PTOs just because they exist. CAISO argued it has limited the rules so subscriber PTOs will not get any undue revenue.
FERC did not weigh in on the dispute, but having rejected a related rule in the EDAM filing, it also rejected the historical cost recovery proposal without prejudice so something could be refiled after the marketwide rules are worked out. (See CAISO Wins (Nearly) Sweeping FERC Approval for EDAM.)
FERC accepted the other rules revisions, including settling transfer system resources, settling transfer revenue, settling EDAM resource sufficiency evaluation failure surcharges and enabling the net EDAM export transfer constraint.
The Department of Market Monitoring told FERC the net export transfer constraint limits were well designed to prevent the shifting of the responsibility for load curtailment from one EDAM participant to another. The method must allow enough flexibility to cover the dynamic nature of other EDAM entities’ load and resource uncertainty, DMM said.
MISO announced last week that it saved its membership roughly $5 billion in 2023 by providing a resource sharing pool for utilities.
Most of the estimated $3.9 billion to $5.8 billion in savings is derived from MISO members having to maintain fewer grid assets to meet peak demand versus operating as isolated utilities; it includes management of shared capacity, demand response and economical renewable generation dispatch.
MISO said 2023 savings also stem from more efficient use of members’ existing grid assets through its energy and ancillary service markets, its reliable system management and its FERC and NERC compliance activities on behalf of members.
MISO estimates the value it provides annually and publishes it under its Value Proposition.
The RTO said its total benefit-to-cost ratio was 15:1 last year, up from 12:1 in 2022. Last year, MISO said it saved members $4 billion in 2022. (See MISO Says 2022 Value Proposition Tops $4B.)
MISO said despite inflation, it expects the value of its markets and planning efficiencies to rise in coming years because it will help members navigate a “hypercomplex” system dotted with more intermittent energy sources. By 2030, the RTO said single-year benefits could conservatively range between $4.3 billion and $5.8 billion and by 2040, they could nearly triple to between $11.6 billion and $14.3 billion.
“Although costs may continue to increase due to the current environment, MISO expects these costs to remain a small fraction of the benefits provided now and in the future,” MISO said, pointing out that it holds its cost of membership at or below inflation.
MISO estimates that since 2007, it has saved members more than $45 billion. The grid operator said the annual benefits it delivers have increased significantly from about $600 million in 2007.
MISO said the more substantial savings this year can be attributed to its members’ resource capacity sharing at anywhere from $2.5 billion to $4.1 billion; savings achieved through the RTO’s energy and ancillary service markets at $795 million to $878 million; and integrating renewable energy into planning at $402 million to $472 million.
MISO’s newest value proposition comes as multiple organizations are voicing concerns that consumers aren’t realizing the full potential of possible benefits in MISO South.
Center-right think tank R Street Institute last week said MISO South has a pattern of safeguarding its transmission constraints, resulting in utility-owned power plants that are insulated from competition with lower-cost resources.
MISO South suffers from “overcapitalizing self-built generation and transmission … the opposite of what regional markets are supposed to accomplish,” R Street said.
Renewables watchdog organization Energy and Policy Institute has voiced similar concerns. Both have cited a working paper from the National Bureau of Economic Research, concluding that a more integrated MISO South grid would have dropped Entergy Arkansas’ and Entergy Louisiana’s net revenues by a combined $930 million in 2022.
NEW ORLEANS — FERC Commissioner Mark Christie brought his message of grid reliability to the Crescent City on March 4, near the site of what he says is the best college football atmosphere in the country: LSU’s Tiger Stadium at night.
“When the sun goes down, that Tiger Stadium is a rocking environment,” Christie said. Hands down, he said, it beats the atmosphere at Alabama, Michigan, Notre Dame, Southern California and Texas.
Dispensing with pleasantries, Christie tended to the business at hand with his keynote address to the Gulf Coast Power Association’s MISO–SPP Forum.
“In America, we’re heading for a very dark place. We’re heading, as Franklin Roosevelt said, to a rendezvous with destiny,” he said. “Well, we’re heading, in terms of the reliability of our power grid, for a rendezvous with reality. And you can’t escape reality because ultimately, reality will track you down. And reality is tracking us down and we need an honest conversation about why we’re heading for a reliability crisis.”
Christie has been making the rounds with his warning that dark times — figuratively and literally — lie ahead for the nation.
Last May, he told the U.S. Senate’s Energy and Natural Resources (ENR) Committee that the grid is facing “potentially catastrophic consequences.” During an SPP forum on resource adequacy in September, he ran through a list of capacity shortfalls that grid operators are expecting and explained his use of the adjective “catastrophic.” (“Multiple-day outages [are] … catastrophic by any definition.”) (See Senators Praise Phillips, FERC’s Output at Oversight Hearing, Nation’s Grid Faces ‘Rendezvous with Reality’.)
“It’s arithmetic. We are subtracting dispatchable resources at a pace that’s not sustainable, and we can’t build dispatchable resources to replace the dispatchable resources we’re shutting down,” he said.
Christie said the problem is not necessarily the massive additions of intermittent wind and solar resources in many parts of the country, but rather the pace of thermal resources’ retirement.
“We’re pushing [dispatchable resources] off the grid far too quickly for any replacement resources to take up the slack,” he said. “That’s why we’re heading for crisis. Its simple subtraction.”
He bolstered his case by linking George Orwell and Vladimir Lenin to fellow revolutionaries MISO’s John Bear and NERC’s Jim Robb.
Bear and Robb?
“If you’ve ever met John Bear, he doesn’t look like a revolutionary. If you’ve ever met Jim Robb, he doesn’t look like a revolutionary,” Christie said. Referencing a quote often attributed to Orwell — “In a time of deceit, telling the truth is a revolutionary act.” He said the two CEOs are performing revolutionary acts.
“Because why? Because they’re telling the truth,” Christie explained. “They’re telling the truth, that we are forcing dispatchable resources off the grid at a pace that simply is unsustainable, and it is going to affect our reliability.”
“What to do? Well, this didn’t come from Lenin, but it comes from where I grew up in West Virginia,” Christie said. “It’s called the first rule of holes, and the first rule of holes is when you’re in one, stop digging. So, if we’re digging a hole deeper because we’re shutting down dispatchable resources at a pace we can’t sustain, let’s stop doing it.”
Christie’s remarks were received positively by several regulators in the audience.
Andrew French, chair of the Kansas Corporation Commission with a background in environmental science, said he couldn’t disagree with anything Christie said.
“I’m an environmentalist. I come from a perspective of wanting to transition as much clean energy onto the grid as we can,” French told RTO Insider. “But, also, as a state regulator that is obviously concerned about both cost and absolutely reliability, I can’t really disagree with anything.
“As Commissioner Christie has said before, it’s not the addition of [renewable] resources that’s the problem. It’s the subtraction of the attributes associated with some of the traditional resources that is the issue. That is the issue we have to solve,” he added.
Marcus Hawkins, executive director of the Organization of MISO States and jaded by years of projected shortfalls that failed to materialize, shared a more nuanced perspective of Christie’s comments.
“In MISO-land, we have a ‘boy who cried wolf’ problem” with projected shortfalls, he said. Hawkins noted OMS surveys over the past decade of the RTO’s members have consistently found shortfalls three or four years out.
“It’s different this time. There’s load growth that’s complicating this. You need context. You can’t just go and say, “Eight gigawatts short in 2028,’ because that’s been the story since 2015,” he said.
Hawkins said he agreed with Christie’s comments that MISO states with vertically integrated utilities give regulators a lot of power to address reliability issues.
“That’s what we’ve seen these last 10 years. We’ve had the gaps projected and you see the regulators work with their utilities and fill that gap,” he said. “I think we’re in a great position to continue to do that and MISO is providing more useful information to the regulators to make decisions, and that’s helpful.”
Christie urged those listening to repeat the actions taken by Bear and others sounding the alarm on energy shortfalls.
“You have got to be brutally honest with your state regulators, your federal regulators and policymakers about the direction that we’re heading in and the rendezvous with reality that we’re facing,” he said. “If our power supply doesn’t keep up with load, it goes out. That’s not an engineering marvel. That’s just the way it works.”
SPP’s latest attempt to comply with FERC Order 2222 has resulted in the commission’s partial acceptance and a directive to make another compliance filing.
FERC on March 1 ordered the RTO to submit its filing by April 30 and to update the commission on implementation timeline milestones associated with the target effective date in the third quarter of 2025 (ER22-1697).
The commission found several areas of concern with SPP’s proposed tariff revisions to comply with Order 2222’s requirements removing barriers so distributed energy resource (DERs) aggregations can participate in RTOs’ and ISOs’ capacity, energy and ancillary service markets:
compensation for demand response in heterogeneous aggregations.
attestation requirements for aggregators.
clarity around interconnection requirements.
the potential for double-counting services.
Responding to the Missouri Public Service Commission’s request for more stakeholder engagement on the part of SPP, FERC urged the grid operator to work with distribution utilities, relevant electric retail regulatory authorities and other stakeholders to ensure its implementation process complements any state-level changes to comply with Order 2222.
“We encourage SPP to explore use of a stakeholder group to promote transparency, and in particular, to share information about progress on the major software and process changes to core SPP systems necessary for implementation,” the commissioners wrote.
SPP made its first compliance filing in May 2022. That August, FERC staff issued a data request advising SPP that more information was necessary to process the filing. SPP filed its response in October.
The proceeding has drawn more than three dozen intervenors.
