VALLEY FORGE, Pa. — PJM’s Stephanie Schwarz presented the RTO’s monthly operating statistics, which showed an average hourly forecast error of 1.26% for February and an hourly peak error just over 3% over forecast on Feb. 3.
The month saw three shared reserve events, one spin event and three post-contingency local load relief warnings.
During the Feb. 24 spin event, which lasted about 12 minutes, Schwarz said 36% of the 2,689 MW spin response assignment for generation materialized as well as 7% of the 262 MW assignment for demand response. The total penalty for the event was 1,967 MW out of a 2,951 MW spin assignment. Generation without a spin assignment increased by 1,777 MW during the event.
The Reserve Certainty Senior Task Force (RCSTF) is considering changes to the reserve penalty rate for resources that fail to perform. Stakeholders in the OC argued that the response from generation without a reserve commitment shows there’s capability for intramarket resources to move on dispatch.
PJM’s Glen Boyle said the underperformance Feb. 24 was concentrated in a few units and overall figures would have looked much better if those resources met their obligations. In response to questions about how reserve assignments interact with the basepoints resources are expected to follow, Boyle said assignments are not included in basepoints; however, the RCSTF is considering ways of aligning the two so that reserve resources can follow dispatch and provide reserves at the same time.
PJM Preparing Forecast for April Solar Eclipse
Pre-eclipse solar generation could decline by as much as 85% during the solar eclipse expected on April 8 and diminished temperatures during the event could result in varying outcomes for demand, PJM’s Michael Stewart presented to the OC.
Grid-connected solar generation could decrease by 1.8-6.7 GW based on cloud coverage, while the decrease in behind-the-meter solar could elevate net load by 4.8 GW on a sunny day or 2.2 GW under overcast conditions. Consumer behavior could also change load patterns, but the impact shouldn’t be as significant as that seen on holidays, Stewart said.
PJM’s Joe Mulhern said more generation may be needed to compensate for decreased solar output, particularly on a cooler day. Eclipses tend to cause temperatures to drop by between 4 and 10 degrees, which could increase load on a colder day as heating load increases, or decrease load on a hot day as air conditioning switches off. The tipping point tends to be between 55 and 65 degrees, depending on the region, Mulhern and Stewart told RTO Insider.
PJM Dispatch Manager Donnie Bielak said operators will be looking at best- and worse-case scenarios and will refine the actions that may be employed in the days leading up to the eclipse.
Stakeholders endorsed revisions to Manual 12: Balancing Operations and Manual 37: Reliability Coordination through the documents’ periodic review.
The changes to Manual 12 align language and diagrams with portions of Manual 11 pertaining to real-time market operations and bilateral transactions and added detail to the economic minimum and emergency minimum parameters requirements for hybrid resources.
The revisions to Manual 37 reflect updated NERC standards around establishing and communicating system operating limits, such as thermal ratings and voltage or stability limits.
PJM Provides Security Update
PJM’s Jim Gluck said cybersecurity professionals are recommending individuals restart their internet routers and install security software updates to mitigate the risk that they could be exploited by the hacking group Volt Typhoon, which was the topic of a cybersecurity advisory issued by the Cybersecurity and Infrastructure Security Agency last month.
He also encouraged members to ensure that their data is secured both on internal networks and through any external parties they work with. He highlighted a data breach exposing a security vulnerability at a Canadian nuclear operator caused by an employee of a third party with access to the company’s data.
The Colorado Public Utilities Commission has issued proposed rules that would govern how it will review applications from state utilities wishing to join the various regional electricity markets being developed in the Western Interconnection.
The rules implement a 2021 state law by setting out utility filing obligations, timelines, a legal standard of review and required PUC findings depending on the type of transmission utility, the nature of the market and relevant policy concerns based on prior commission studies, cases and comments (22R-0249E).
The rulemaking includes 10 conditions for market participation that reflect state law and the PUC’s policies. They include grid reliability, emissions tracking, customer rate impacts and transmission expansion for investor-owned utilities. Utilities also can keep a percentage (35%, to begin with) of the savings they gain from the markets.
PUC Chair Eric Blank said in an email to Western regulators that his agency’s primary concern is to develop a “consistent framework for tracking and accounting for [greenhouse gas] emissions” and maintain an interconnection queue process that allows winning projects to move forward in a timely manner. It also has more general concerns over rates, transmission expansion and seams.
The commission said it is important for Colorado utilities, regulators and other stakeholders to become involved in market development before market operators submit their tariffs for FERC approval because any subsequent changes will depend on the markets’ governance structures and stakeholder processes.
“Given these timing and other challenges surrounding the FERC approval and modification process, the best opportunity for Colorado utilities, regulators, customers, [independent power producers], clean energy advocates and others to shape the key aspects and structure of the regional market options may be prior to the FERC filings,” the PUC wrote. “Once a tariff is filed at FERC, additional changes can be challenging and time consuming to get approved and implement.”
The PUC held a March 5 hearing on the rules and is currently gathering written feedback from interested parties. It plans a full review following the comment period, which ends April 5.
Market Choices
Colorado utilities can participate in any of three regional markets currently planned for the West:
CAISO’s Extended Day-ahead Market, which already has FERC approval and is due to go live in 2026. PacifiCorp and the Balancing Area of Northern California (BANC) are its only two committed participants so far, although the Los Angeles Department of Water and Power has signaled its intent to join.
SPP’s RTO West seeks to extend the services SPP currently offers in the Eastern Interconnection. It, too, is targeted to go live in 2026 and has seven utilities evaluating whether to place their facilities under its tariff, which is expected to be filed midyear.
SPP’s Markets+ and its bundle of proposed services that would centralize day-ahead and real-time unit commitment and dispatch across a large footprint in the Western Interconnection. A tariff filing is planned for the end of March.
CAISO and SPP also both have imbalance markets operating in the interconnection. The PUC noted Colorado participants in the latter’s Western Energy Imbalance Service (WEIS) market suggest that optimizing dispatch in real time has already reduced curtailment and lowered production costs in Colorado.
SPP has already been working with Western stakeholders to develop a market solution, best practices, rules and protocols that support the Northwest’s only cap-and-trade program in Washington. Spokesperson Meghan Sever said the RTO is reviewing the proposed rules and has been working “extensively” with the Colorado commission and utilities on GHG emissions tracking and accounting.
“We foresee no issue complying with the proposed rule as drafted,” Sever said. “While these proposed rules are more directed toward Colorado utilities, SPP sees no barriers in our ability to comply with the proposed rule.”
Colorado Springs Utilities (CSU) and Tri-State Generation and Transmission Association are among the state’s utilities that are evaluating SPP RTO West. Both are already members of the RTO’s WEIS market that went live in 2021.
Steve Berry, a senior public affairs specialist with Colorado Springs Utilities, said it is premature for the utility to offer a formal position on the proposed PUC rules.
“We’ve been an observer of the process up to this point,” he said.
Tri-State did not return a request for comment. It has already told the PUC it intends to transition its load within the Western Area Colorado Missouri balancing area, which includes portions of Colorado, Wyoming, Western Nebraska, New Mexico and Arizona, into RTO West in April 2026.
Limits on imports from the Western Energy Imbalance Market into the CAISO balancing authority area between July 25 and Nov. 16, 2023, led to increased transmission congestion in the ISO’s 15-minute-ahead market and lower prices in the five-minute market, the Department of Market Monitoring told stakeholders March 6.
While CAISO operators’ actions helped the ISO maintain reliability during a brutal summer in the West, “it is not clear why the CAISO area continued these transfer limitations after the mid-August heat wave and through Nov. 16,” the department said. It recommended “that CAISO work with stakeholders to consider other methods of achieving the intended reliability outcomes without creating the large and systematic modeling differences between the 15-minute and five-minute markets.”
Presenting the department’s State of the Market report for the third quarter of 2023, Ryan Kurlinski, senior manager of market and policy analysis, said CAISO operators began limiting WEIM import transfers for the hour-ahead and 15-minute markets in late July when stressful weather conditions led to high levels of unfulfillable self-scheduled exports. (See CAISO DMM: High Exports to Southwest Led to July EEAs.) The limitations were then lifted in the five-minute market.
The limiting action was taken to mitigate the risk that during critical hours, internal generation and hourly block intertie schedules could be displaced by WEIM imports that might not materialize in real time. CAISO issued energy emergency alerts on three days in late July but was not forced to shed load.
“This limitation on these tight days did have the intended effect of reducing advisory WEIM imports into CAISO and replacing it with increased hourly block imports and decreased exports out of CAISO,” Kurlinski said. “While that limitation had the intended reliability impact, it also significantly impacted the rest of the West,” driving down prices.
Load adjustments in the hour-ahead and 15-minute markets were lower on average in the third quarter than those in the same quarter in 2022, though after July 20, they rose back to 2022 levels of about 2,000 MW.
“The combination of high load adjustments in the 15-minute market and much lower adjustments in the five-minute market contributed to the lower average prices in the latter market,” the report says. “When the CAISO balancing area limited WEIM transfer imports to zero in the hour-ahead and 15-minute markets, most of the WEIM footprint was collectively export constrained at a lower price based on regional supply conditions outside of the CAISO area,” the report reads.
Kurlinski used transfers in and out of Arizona Public Service as an example. Before the transfer limitation was implemented, there were significant transfers from APS to CAISO and other BAs, but after the limitation was put in place in the 7-8 p.m. hour on July 26, dynamic transfers from Arizona to CAISO stopped.
The “DMM has recommended that CAISO work with stakeholders to consider if there may be other methods or other ways to try to achieve the same reliability outcomes that the CAISO BA is trying to achieve but without potentially creating this significant difference between the 15-minute market and five-minute markets,” Kurlinski said. “At the very least, it would be good to have a more transparent discussion about what the ISO is seeing in its systems that would lead them to do this again and to be more transparent about when they are going to do this.”
A new report from electricity marketer Powerex adds to the expanding debate around what transpired on the Western grid during a January cold snap that saw the Northwest forced to import large volumes of power in the face of record energy demand and tight supplies.
The storm saw five balancing areas — including the Alberta Electric System Operator — enter various levels of energy emergency alerts (EEAs), with one critical EEA-3 declared in the U.S. Northwest.
The March 6 report from the Vancouver, Canada-based company, which markets BC Hydro’s surplus generation and manages a sophisticated trading operation that covers the Western Interconnection, represents yet another salvo in the dispute over the Jan. 12-16 winter freeze that plunged the Northwest to near-record low temperatures.
The ensuing disagreement about how energy flowed during the event has largely reflected fault lines among Western electricity industry stakeholders in the contest between CAISO’s Extended Day-Ahead Market (EDAM) and SPP’s Markets+. The debate is sharpening as the Bonneville Power Administration nears the release of its market “leaning” in April. (See NW Cold Snap Dispute Reflects Divisions over Western Markets.)
Powerex so far is the only Western entity to tentatively commit to Markets+. Its report, “Analysis of the January 2024 Winter Weather Event,” amplifies the view held by some Northwest stakeholders that the region largely weathered the event because of support from the Desert Southwest and the Inland West — and not CAISO and other California balancing areas.
The report also notes that Powerex itself aided its southern neighbors during the freeze. It additionally delves into the capacity and fuel supply challenges that confronted the Northwest and concludes with a set of recommendations to the region to prepare for similar future events — all of which notably exclude participation by CAISO.
Interpreting the Data
Powerex’s report shows peak demand in balancing areas across the U.S. Northwest during the cold snap generally ranged about 2 to 6% higher than during a similar weather event in December 2022, with comparable temperatures. In PacifiCorp’s West area, the peak was 6.7% higher than during the 2022 event, while Seattle City Light’s peak was 6.2% higher and Idaho Power’s 5% higher. British Columbia set a new demand record Jan. 12, beating its previous mark by 3%.
“This is consistent with recent projections of accelerating demand growth for U.S. Northwest utilities,” the report said, citing last year’s forecast from the Pacific Northwest Utilities Conference Committee.
Powerex’s account of how power flowed across the Western Interconnection during January’s five-day event aligns with two separate assessments from the Western Power Pool (WPP) and the Public Power Council (PPC).
Relying on Open Access Same-Time Information System (OASIS) transaction schedules, BPA’s Pacific AC Intertie data, Energy Information Administration interchange data and figures from CAISO’s OASIS, Powerex estimated that the U.S. Northwest hourly net energy imports averaged 4,745 MW during the 4 p.m.-to-8 p.m. periods of peak demand during the January event.
The “most significant” source of supply during those hours, Powerex said, originated in the Rockies (2.399 MW exported) and Desert Southwest (2,765 MW exported) regions, with power from the latter being wheeled through California into the Northwest. Canada — mostly Powerex — also exported an hourly average of 336 MW directly to the U.S. Northwest.
“In contrast, [CAISO], and other California utilities that are not part of [CAISO], were net importers on average of approximately 443 MW (189 MW and 254 MW respectively) during these peak demand hours,” the report said, repeating a point made by the WPP and PPC in their analyses.
Across the full 120 hours of the January event, the U.S. Northwest imported an hourly average of 5,241 MW, Powerex said, with the Southwest exporting an hourly average of 3,223 MW and the Rockies 2,399 MW, with Canada exporting 481 MW. Over the same period, CAISO and other California BAAs were net importers of 49 MW and 489 MW, respectively, the report said.
“Imports and exports can be the result of bilateral transactions arranged prior to the operating hour and scheduled through e-Tags under the contract-path framework, or they can be the result of participation in the Western EIM, which optimizes transfers based on available supply and transmission service across the footprint,” Powerex said.
The report cites WEIM data showing the Northwest received an average of 348 MW of supply from the WEIM across all hours and 164 MW during the peak hours. It notes that “most of the [Northwest’s] imported supply was transacted in the bilateral markets (including exports from the CAISO using the intertie bidding framework and contract path scheduling), with the Western EIM providing a relatively small volume.”
CAISO contested that characterization of energy flows in its own 80-page analysis detailing how the ISO and the WEIM supported the Northwest during the cold snap. (See NW Freeze Response Shows WEIM Value, CAISO Report Says.)
CAISO’s report, also published March 6, said the ISO “became a net exporter over the Martin Luther King Jr. Day weekend for all hours of the day, excluding WEIM transfers,” with hourly exports in the day-ahead and real-time markets exceeding 6,000 MW.
The ISO said WEIM transfers into CAISO stemmed from not limited supply within CAISO but instead the “economic displacement and opportunities optimized by the market and bounded by the transmission and transfers availability in the wider footprint.”
“The market identified least-cost solutions within the wider WEIM footprint, transferring lower-cost electricity from the Southwest into California,” the CAISO report said. “These transfers allowed exports scheduled in the day-ahead and hour-ahead markets to flow to the Northwest, replacing more expensive generation while managing congestion on key transmission lines.”
‘Distinct Reliability Challenges’
The Powerex report highlights “two separate and distinct reliability challenges” confronting the Northwest during the deep freeze: “inadequate capacity during peak demand hours” and “insufficient fuel supply across the multiday event.”
Regarding fuel supply, the report notes that BC Hydro and BPA hydroelectric generators associated with the largest storage reservoirs can operate “at or near maximum output across all hours of a multiday weather event,” but run-of-river hydroelectric facilities don’t have that option.
“The region’s dependence on these hydroelectric generation facilities gives rise to a risk of fuel supply insufficiency during weather events lasting multiple days, such as the January 2024 event,” Powerex said. “The risk that other variable energy resources, such as wind facilities, may also experience persistent reduced output during a multiday weather event also contributes to fuel supply risk.”
Powerex said that risk was evidenced by the fact that U.S. Northwest wholesale electricity prices were high in both the day-ahead and real-time market across all hours of the event, including in the WEIM, where prices hovered near caps.
The fuel supply risk also was apparent in the number of EEAs declared outside peak demand hours, including one during the overnight hours when demand was relatively low — “indicating a reliability challenge other than a lack of generating capacity to meet peak demand, such as a lack of fuel supply,” Powerex said.
WRAP Enhancements
The report concludes with four key recommendations for the U.S. Northwest.
The first is for the region to consider making “enhancements” to the WPP’s Western Resource Adequacy Program (WRAP) before it begins its first binding winter season, which could be as early as 2026/27.
Given the surge in peak demand compared with the region’s December 2022 event, Powerex calls for the WRAP to potentially revise its winter peak demand assumptions, evaluate how well demand response (DR) programs reduced demand during the January 2024 event and “explore a regional discussion of the opportunities” to expand the use of DR during such multiday events. The report also asks the WPP to evaluate how WRAP resources performed during the event to get a better read on the current resource adequacy situation and identify ways to improve the program.
The report’s first recommendation also contains a provision asking the WRAP to consider modifying how it transitions to its binding phase by accounting for utility capacity deficiencies that result from delays in obtaining interconnection for resources.
“This new transition framework may include a requirement that entities demonstrate that their current capacity deficits are temporary, or otherwise provide confidence of meeting resource adequacy requirements by the end of the new transition period,” Powerex wrote.
Circumventing California
Powerex’s second recommendation calls for the Northwest to use existing transmission facilities to increase import capability directly from the Southwest and Rockies regions. The report says that “additional supply appears to have been available in the Southwest and Rockies, but access to this supply appears to have been primarily limited by inter-regional transmission service.”
Bound up in this recommendation is a criticism of CAISO’s practices and a plug for Markets+
“Transfers of electricity across the West are limited by contract-path scheduling limits on key transmission paths. In addition to applying to deliveries of forward, day-ahead and real-time bilateral transactions, these limits are also applied by [CAISO] to transfers between BAAs in the Western EIM and will be applied in its proposed EDAM,” the report says. “In contrast, organized markets elsewhere in the U.S. — as well as the proposed [SPP] Markets+ platform — do not generally layer contract-path limits on top of standard flow-based transmission limits.”
The report’s third recommendation, for the Northwest to upgrade and build new transmission connections with the Southwest and Rockies regions, includes another critique of CAISO practices. During the January event, Powerex and other Northwest entities have contended, the $650/MWh wholesale power price spread between the Northwest and Southwest was squeezed by congestion charges at CAISO’s border with Oregon. An additional 2,000 MW of direct transfer capability with the Southwest could have saved the Northwest $140 million and reduced the region’s reliability risk, Powerex said.
“Notably, roughly half of the deliveries from the Southwest and Rockies region to the U.S. Northwest region during the event flowed through California, and particularly through the California ISO’s service territory. Transmission service through the California ISO’s service territory is provided under different terms and conditions than transmission service provided throughout the rest of the West,” the Powerex report said.
CAISO has sought to address that contention, arguing that it is the only balancing authority in the West that uses mechanisms to manage transmission congestion in the day-ahead market and that it cannot overlook resolving situations in which it can foresee stress on a portion of the grid. The ISO’s March 6 report said EDAM “provides additional mechanisms for managing congestion on either side of balancing area borders for participating entities and provides transparency on the distribution of congestion revenues collected through nodal pricing.”
Overcoming Fuel Supply Challenges
Powerex’s fourth recommendation urges the Northwest to consider how specific resources and resource types contribute to the fuel supply challenges that can arise during multiday events like the January cold snap.
The report notes that resources with “base load or dispatchable capabilities,” such as hydro with longer-term storage — like that operated by BC Hydro — as well as nuclear, gas, coal and geothermal resources, “are able to contribute at a very high level” to meet the region’s RA and fuel supply challenges.
“At the other end of the spectrum are shorter and medium duration storage facilities, such as batteries and pumped storage hydro,” the report says. “These technologies contribute substantially towards meeting capacity challenges (through 4-hour or longer discharge cycles) but do little to address (and may actually exacerbate) multiday fuel supply challenges, as they do not provide net energy over the course of one or more full charging/discharging cycles (i.e., they actually consume energy across each day of a multiday event due to cycle losses).”
The report also points out that solar and wind resources might contribute differently from each other, with solar providing “little to no benefit” for capacity challenges occurring after sunset, while wind could be available during those intervals, depending on conditions.
“At the same time, these same solar resources may provide a greater contribution to fuel supply challenges over multiday events than wind resources, since wind resources may be more susceptible to multiday periods of little or no wind output,” the report said.
“Ultimately, the WRAP may need to evolve to include additional resource adequacy requirements associated with multiday fuel sufficiency requirements,” it said.
The Texas Public Utility Commission said March 11 that Jeff McDonald, a 22-year market monitoring veteran, has been hired as director of ERCOT’s Independent Market Monitor.
He replaces Carrie Bivens, who resigned as the IMM’s director last year.
McDonald spent nearly eight years at ISO-NE as its vice president of market monitoring. Before that, he held several managerial positions during 14 years with CAISO’s Department of Market Monitoring.
He will be responsible for collaborating with the PUC to detect and prevent market manipulation and identify potential design improvements for the ERCOT market, the commission said.
“Jeff’s deep expertise and decades of experience make him the perfect person to lead the IMM team in Texas and ensure the market is operating efficiently, fairly and competitively,” Potomac Economics President David Patton said in a statement.
Potomac Economics has served as ERCOT’s IMM since 2005, when the organization was created. It recently was awarded another contract to monitor the market through 2027.
Bivens resigned in November after 3.5 years as the IMM’s director following several disagreements with PUC and ERCOT leadership. She cast doubt on the performance credit mechanism pushed by former PUC chair Peter Lake and defended before the ERCOT board an IMM report that said the grid operator’s newest ancillary service “likely” raised the real-time market’s energy value by at least $8 billion. (See Bivens Resigns as ERCOT’s Market Monitor.)
McDonald joins Potomac Economics from Concentric Energy Advisors, where he was the firm’s vice president. He holds a Ph.D. in economics from the University of California, Davis, a master’s in natural resource economics from the University of Massachusetts, Amherst, and a bachelor’s in agricultural and managerial economics from Cal Davis.
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.”
