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November 14, 2024

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ERCOT Technical Advisory Committee Briefs: July 27, 2022

Members Endorse Two Tier 1 Transmission Projects

ERCOT stakeholders endorsed two transmission projects with a combined capital cost of more than $760 million during last week’s Technical Advisory Committee meeting.

The Regional Planning Group classified both the Bearkat-North McCamey-Sand Lake project in West Texas and the Roanoke upgrade project north of the Dallas-Fort Worth area as Tier I projects because their costs exceed a $100 million threshold. Their status requires they receive TAC endorsement and the Board of Directors’ approval.

ERCOT staff said during the Wednesday meeting that it chose one of the first project’s three options to address reliability needs driven by rapid load growth in the Permian Basin’s Delaware Basin and to improve the region’s ability to import power. The recommended option will result in building two double-circuit, 345-kV transmission lines totaling about 165 miles, with the two segments meeting in McCamey, a former oil boomtown since labeled “the Wind Energy Capital of Texas” by the state legislature.

Bearkat-North McCamey-Sand Lake has a projected cost of $477.6 million in 2021 dollars, up from $371 million in 2019 dollars, and an estimated completion date of June 2026.

The Roanoke upgrade project involves 7 miles of 138-kV lines, 26 miles of 345-kV lines, four 345/138-kV transformers and five 138-kV low-voltage buses. Staff analyzed four options, choosing the one they say provides better operational flexibility and long-term load-serving capability for future load growth.

Oncor, the incumbent transmission service provider, expects to complete the upgrades by May 2025 at an estimated capital cost of $285.9 million.

The company has a hand in both projects. It paired with Lower Colorado River Authority Transmission Services and Wind Energy Transmission Texas to submit the first project to the RPG. It was alone in suggesting the upgrade project.

TAC approved the projects as part of its combination ballot, where they were included with unopposed revision requests and other measures. The board will consider both projects during its Aug. 16 meeting.

Staff Defer Comment on CSAPR

Staff told TAC they were unsure as to whether the Supreme Court’s recent decision voiding the Obama-era Clean Power Plan would affect a federal rule’s implementation that limits nitrogen oxide emissions. (See Supreme Court Rejects EPA Generation Shifting.)

Texas is one of more than 20 states that, under EPA’s Cross-State Air Pollution Rule (CSAPR) plan, must establish NOx emissions budgets beginning with the 2023 ozone season (May 1-Sept. 30). The agency says the reductions are necessary to address upwind states’ interstate transport obligations.

Staff were non-committal when asked whether the high court’s 6-3 decision in West Virginia vs. EPA would scuttle the CSAPR. The court rejected EPA’s assertion that “generation-shifting” was the “best system of emissions reductions” available and invoked the “major questions doctrine” that agency decisions involving “economic and political significance” require them to show “clear congressional authorization.”

Senior Corporate Counsel Katherine Gross noted that CSAPR was proposed under a different section of the Clean Air Act than was the CPP.

“At this point, we’re not sure of the significance of this case, and we don’t want to speculate too much about what it will mean for the ozone transport rule,” Gross said. “If the EPA rule here does have a significant economic impact, the EPA is going to need to be able to point to very clear congressional authorization, which they were not able to do in the Clean Power Plan rule, according to the court. And if they’re not able to do that, then that rule is going to be susceptible to being overturned.”

Gross said ERCOT would defer to the state’s Office of the Attorney General and the Public Utility Commission, both of which filed comments with EPA asking for the CSAPR rule’s withdrawal as it pertains to Texas (EPA-HQ-OAR-2021-0668-0007.)

The AG’s Office alleged the agency “acted arbitrarily and capriciously in several distinct ways, abused its discretion and failed to observe procedures required by law.”

“Regional actors are in the best position to determine how to meet the 2015 ozone transport obligations, but EPA failed to consult the necessary experts and denied states, specifically Texas, the opportunity to regulate where appropriate,” the office said.

The PUC said the transport implementation plan will have “significant, detrimental impacts on reliability” in the ERCOT region, as well as those portions of the state served by SPP and MISO.

ERCOT staff in June told the board that its preliminary analysis of the CSAPR rule assumed that over 10 GW of installed thermal generation would leave the market by 2026, requiring up to $1.5 billion to resolve local reliability issues. (See “10 GW Thermals Could Retire with EPA Rule,” ERCOT Board of Directors Briefs: June 21, 2022.)

Woody Rickerson, vice president of system planning and weatherization, told TAC that the thermal units staff “retired” in its analysis do not have the necessary emissions-reduction equipment and “seemed likely candidates” to be retired or retrofitted.

TAC Liaisons with R&M Trimmed

TAC Chair Clif Lange, with South Texas Electric Cooperative, told members that the committee’s leadership continues to work with several board members to iron out its reporting relationship under ERCOT’s new structure. (See ERCOT Technical Advisory Committee Briefs: June 27, 2022.)

He said TAC’s proposal to have as many as 11 liaisons with the board’s newly created Reliability and Markets Committee was found to be “cumbersome” and “unwieldy.” Lange said that in meeting with Directors Bob Flexon, the committee’s chair, and Peggy Heeg, they agreed that TAC’s chair and vice chair would act as liaisons. Segment representatives would be present should the R&M Committee want to hear from them.

Lange said the directors have additional changes they would like to see and they will continue to work with stakeholders on the details.

ERS Budget Increase Endorsed

The committee endorsed a Nodal Protocol revision request (NPRR1142) and its accompanying Other Binding Document revision request (OBDRR042) that had been granted urgent status by the Protocol Revision Subcommittee. The measure increases the annual budget for emergency response services (ERS) from $50 million to $75 million and gives ERCOT the ability to contract ERS for up to 24 hours in a standard contract term.

The NPRR is a result of a July PUC order that also allows the grid operator to broach the budget by up to $25 million for contract term renewals (53493).

Clayton-Greer-(RTO-Insider)-FI.jpgClayton Greer, Morgan Stanley | © RTO Insider LLC

Morgan Stanley’s Clayton Greer cast the lone opposing ballot in the 28-1 vote, saying he had requested information from ERCOT, still outstanding, on how many loads were already offline before ERCOT deployed them.

“We have waivers that allow loads to go offline when prices are high. We’re paying people to do what they would already do on their own,” he said. “There’s no additional value to this. I would rather see a capacity market where we pay all capacity that’s online.”

Staff said they wouldn’t have the data available until the end of August.

“We’re more than happy to bring this analysis to whatever stakeholder meeting would like to see it,” ERCOT’s Mark Patterson said.

RUC Scaling Factor to 100%

TAC members agreed with staff’s recommendation to change the reliability unit commitment’s (RUC) scaling factor from 20% to 100%, adding the measure to the combo ballot that passed unanimously.

ERCOT instituted a 20% scaling factor in 2018 with NPRR864, which modified the start-up and minimum energy costs for resources with a cold start time of one hour or less. This allowed the grid operator to defer commitment decisions and provide market participants additional time to self-commit their resources.

However, that has changed with ERCOT’s new conservative operations posture that makes greater use of the RUC process. Staff said the scaling has led to operators needing to make many of their RUC decisions outside of the process’s economic-based recommendations, leading to inefficient commitments.

Changing the cost-scaling factors to 100% will help ensure the commitment decisions better reflect the economically optimal commitment decision, ERCOT said.

“We’ve just seen more manual commitments occurring this year because of a desire to commit resources further in advance of the peak hours,” ERCOT’s Dave Maggio said.

The combination ballot also included six NPRRs, single changes to the Planning Guide (PGRR) and the Retail Market Guide (RMGRR), and a system change request (SCR):

    • NPRR1085: improves the physical responsive capability calculation and dispatch’s validity by requiring quicker updates from qualified scheduling entities (QSEs) on telemetered resource status, high sustained limit and other relevant information.
    • NPRR1133: clarifies the responsibilities of DC tie facility owners and operators for reporting DC tie model data.
    • NPRR1134: removes references to first available switch date (FASD) after recent mass transition/provider of last resort events indicated ERCOT’s use of FASD when processing switch transactions created an unintended negative experience for customers being transitioned from a bankrupt retailer.
    • NPRR1135: modifies the definition of real-time generation resources with an offline non-spin (OFFNS) schedule  to allow non-zero values for the billing determinant only if the resource is offline when it telemetered OFFNS. This ensures an accurate settlement when an online resource erroneously telemeters OFFNS.
    • NPRR1136: adds clarifying language to the logic in place as fast frequency response is developed to ensure a QSE does not replace a regulation service with fast-responding regulation service.
    • NPRR1137: replaces the annual requirement to review the OBD list with a four-year review cycle.
    • PGRR101: clarifies that a DC tie’s owner will provide the appropriate dynamic model data to its tie operator, which will then provide the data to ERCOT.
    • RMGRR168: synchronizes ERCOT’s role and responsibilities with current market transactional solutions upon the removal of the “out-of-cycle” switch term and market process.
    • SCR822: creates a new daily integration report and dashboard for energy storage resources similar to the current wind and solar integration reports and dashboards.
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Massachusetts Legislators Send Climate Bill Back to Baker

Massachusetts legislators sent an amended climate bill back to Gov. Charlie Baker’s desk in a flurry of lawmaking that saw the year’s legislative session end in the early hours of Monday morning.

After the House and Senate passed a compromise version of the bill two weeks ago, Baker sent back a list of amendments Friday, giving the legislature two days to decide how to incorporate them before the session ended. (See Mass. Legislators Reach Deal on Clean Energy Bill.)

The legislature accepted Baker’s key amendment to eliminate a price cap on offshore wind procurements. It also added his changes to the board selection process for the Massachusetts Clean Energy Center.

But lawmakers rejected several of Baker’s other proposed amendments.

The State House did not go for provisions from the governor that would weaken a portion of the bill allowing 10 Massachusetts municipalities to ban fossil fuels from new buildings and major renovations. (Baker had proposed that multifamily housing be exempt and that the ordinances take effect when there is more clean energy on the grid.)

Legislators also denied Baker’s amendment to allocate $750 million in American Rescue Plan Act funding to the clean energy investment fund that the bill creates.

“A very strong climate bill for [Massachusetts], the second in as many years, is now on the governor’s desk,” said Sen. Michael Barrett, one of the bill’s lead sponsors.

Because the bill does not include any new funding, Baker cannot veto individual line items.

“Now all eyes are on you,” tweeted Ben Hellerstein, director of Environment Massachusetts. “Sign the bill!”

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SPP Board of Directors/Members Committee Briefs: July 26, 2022

Members Approve SPS Tx Project over Staff’s Recommendation

SPP’s Board of Directors last week approved stakeholders’ recommendation to issue a notification to construct for a 345-kV double-circuit transmission project in eastern New Mexico.

The Crossroads-Hobbs-Roadrunner project, proposed by Southwestern Public Service (NASDAQ:XEL) as an alternative to a previously identified project in the 2021 Integrated Transmission Plan, was recommended by two stakeholder groups following its re-evaluation after load-projection errors were discovered in the original solution.

At $395 million, Crossroads-Hobbs-Roadrunner is $15 million cheaper than the original Crossroads-Phantom project and offers SPS operational flexibility. It solves reliability concerns in a load pocket in the state’s petroleum-rich Permian Basin region and could lead to additional renewable development there. The line, about 150 miles long, runs from Crossroads to Roadrunner. SPS, the incumbent transmission owner, added a substation in Hobbs that SPP staff said gives more access to operating reserves in the load pocket.

The line also saves about $6 million by eliminating four EHV crossings that the original line, recommended by staff, would cross.

The Markets and Operations Policy Committee found both projects address the area’s reliability needs and economic congestion and endorsed both as potential solutions during its meeting earlier in July. But it pointed out that Crossroads-Hobbs-Roadrunner provides better net benefits over its 40-year life of between $2.8 billion to $3 billion, and that could increase to between $3.1 billion and $3.2 billion once the area’s residual congestion is mitigated. (See “MOPC Keeps SPS’ Tx Alternatives Alive,” SPP Markets and Operations Policy Committee Briefs: July 11-12, 2022.)

“We see a lot of benefits from routing line through Hobbs,” SPS’ Jarred Cooley said during the July 26 board meeting. “It’s in the high-growth load in New Mexico; generation is located in close proximity; and it gives a path to the southern part of our territory. Lingering congestion issues … [are] something that can be further investigated in future studies. We see Hobbs as more reliable … with the ability to adapt to more load growth.”

Staff recommended Crossroads-Phantom during the ITP study, saying it solved the majority of load and voltage issues at the Phantom substations. However, it agreed Crossroads-Hobbs-Roadrunner creates more flexibility for other interconnections.

“These projects are very similar. We can’t give a real strong preference to either project,” said Antoine Lucas, SPP’s vice president of engineering. “It depends on what happens next. We know there are potential new loads looking to interconnect to the southern end of the SPS system, but at this stage, those things are speculative. They don’t meet the level of certainty in our normal ITP processes.”

The Members Committee’s advisory vote passed unanimously with five abstentions: American Clean Power, Dogwood Energy, Golden Spread Electric Cooperative, Liberty Utilities and Oklahoma Municipal Power Authority (OMPA).

“I can’t help but wonder about the direction we’re going,” OMPA General Manager Dave Osburn said. “We have a load pocket that needs transmission because of a lack of generation. How long can we build out transmission with other regions paying for it without getting new generation built? It seems like we’re fixing a problem we could fix locally.”

Staff will now assess both upgrades to determine whether either qualifies as a competitive project. If they don’t, SPS will be awarded the NTC.

“There’s a good chance both could be competitive,” SPP General Counsel Paul Suskie said.

NextEra Energy Resources’ Matt Pawlowski pointed out that recent competitive projects have shown cost savings of 30 to 50% in the initial phase. Board Chair Larry Altenbaumer agreed, saying that it is an issue that haunts him.

“At the end of the day, the real determinant over which is the better project will be the competitive proposals that come forward with actual costs,” Altenbaumer said. “Those differences in [benefit-to-cost] ratios are the noise range. What we’ve seen historically is that competitive projects seem to bring improvements in actual costs to the table than what are frequently determine in planning estimates.”

Summer of ’22 ‘Wild One’

Calling this summer a “wild one,” CEO Barbara Sugg detailed for the board and stakeholders just how wild it’s been during her quarterly CEO’s report.

SPP has set six new records for peak demand this month, with the latest — 53.2 GW on July 19 — being a 4.23% increase over the previous mark of 51.04 GW set last year, she said.

Sugg said the RTO has sold more generation over the first six months of the year than ever before. The grid has recorded all-time highs for five of those months. Staff said load assumptions for the rest of year could result in a $6.8 million over-recovery that will be used to reduce next year’s recovery.

Sugg said the RTO has issued six resource advisories and one call for conservative operations in its 14-state balancing authority in the Eastern Interconnection. She noted that the grid operator’s footprint has spent 21 days under a resource advisory, nine under conservative operations, since May 1.

Make that 22 days under a resource advisory. Following the board meeting, SPP issued its seventh such advisory of the summer for July 27.

“Summer is far from over,” Sugg said. “Hot summers are becoming more of a regular thing.”

Sugg also welcomed the RTO’s three newest members: Oklahoma’s People’s Electric Cooperative, Colorado’s United Power, and the National Resources Defense Council. They raise SPP’s membership count to 113.

Search on for 2 Board Directors

The Corporate Governance Committee will bring nominations for two board vacancies to October’s meeting. SPP already has one opening for a director’s seat with Julian Brix’s retirement; a second will open up at year-end when Mark Crisson’s term expires and he retires.

The board will lose longtime members Altenbaumer and Joshua W. Martin III in December 2023, when both will retire. They have 34 years of experience between them, with Martin serving 18 and Altenbaumer 16.

The bylaws limit SPP to nine independent directors, but Sugg said the CGC could bring two recommendations for the vacancies in October because of the expected steep learning curve.

“The search is highly focused on the competencies we’ll be losing,” she said of Altenbaumer’s and Martin’s experience.

Western RC Calls 2 EEAs for EPE

SPP had to twice place El Paso Electric (EPE) under energy emergency alert (EEA) status in June when two of the utility’s 345-kV transmission lines tripped offline within a week of each other.

Senior Vice President of Operations Bruce Rew told the board and stakeholders that EPE was pleased that SPP, the reliability coordinator for it and 14 other utilities in the Western Interconnection, was “able to respond and get through it.”

“We were able to provide assistance over [a] DC tie,“ Rew said. “It was only 200 MW, but when you’re short or really close, 200 MW is 200 MW.”

Early in the morning on June 10, the West Mesa-Arroyo line in Eastern New Mexico tripped, causing a derate on EPE’s import capability because of the risk of overloading an underlying 115-kV line. When the utility said it had concerns about meeting its contingency reserve obligation later that afternoon, SPP West RC placed the EPE balancing authority in a Level 1 EEA while working to determine projected system conditions.

At 2:42 p.m. CT, SPP raised the EEA to Level 2 because it and EPE agreed interruptible demand was necessary to compensate for the lack of local generation and its import capability given the load forecast. The EEA was called off when load dropped off that night.

At 6:50 p.m. June 16, the Luna-Diablo line out of El Paso into New Mexico tripped offline, causing a derate for the same reasons as the June 10 event. The RC placed EPE in EEA 1 over concerns it could not cover its most severe single contingency and then an EEA 2 because of the use again of interruptible loads. The event ended at 8:36 p.m. when load dropped and additional generation was supplied over the Artesia DC tie.

SPP’s Western Energy Imbalance Service (WEIS) market is also active in the Western Interconnection, balancing generation and load in real time for eight participants. That will grow to 12 when Colorado Springs Utilities joins Aug. 1 and Black Hills Energy, Platte River Power Authority and Xcel Energy-Colorado join next April, Rew said.

“It’s encouraging to see the continued growth of SPP’s energy services in the west,” Rew said in a press release issued Monday. “Organized markets save utilities and their customers money, make the delivery of electricity to customers more reliable, and help utilities and states achieve clean energy goals.”

“Participation in the [WEIS] is a significant step in our pursuit of clean energy goals and sends a strong signal that we’re doing everything possible to secure a reliable electric grid and reduce energy-related costs for our customers,” CSU CEO Aram Benyamin said.

The RTO’s Integrated Marketplace lost a couple of financial-only participants during the second quarter, leaving 184 in that category, Rew said. SPP’s markets have 103 asset-owning participants and 287 overall. They’ve been drawn by the markets’ bountiful wind resources, which have grown from 24 GW of installed capacity two years ago to 31.85 GW in 2022.

Board Approves DC Tie Solution

The board’s consent agenda included a congestion-hedging solution for three DC ties that will connect the SPP’s Eastern and Western interconnection footprints. The DC ties are owned by members of SPP’s Western Energy Imbalance Service market, providing up to 510 MW of capacity for RTO operations.

The measure was previously endorsed by the Regional State Committee on July 25. (See related story, SPP Regional State Committee Briefs: July 25, 2022.)

By passing the consent agenda, the board also approved:

  • bylaw revisions that clarify RSC membership is only available to regulatory agencies in states within SPP’s footprint that receive RTO services;
  • filling vacancies on the Strategic Planning Committee (Matt Caves, Western Farmers Electric Cooperative) and Human Resources Committee (Matt Dills, ITC Great Plains);
  • creating a third withdrawal deposit category to allow certain non-load-serving entities to terminate their membership without providing a withdrawal deposit;
  • forming the 18-person industry expert pool that will evaluate competitive transmission proposals in 2022;
  • sponsored upgrades studies for NextEra of terminal equipment on two 161-kV lines near Warrensburg, Mo.; Invenergy’s proposal to build a 345-kV line between two substations in West Texas and its upgrade of two 345/230-kV transformers in South Dakota to a 581-MVA rating; and Oklahoma Gas & Electric’s reconductoring of a 69-kV transmission line to increase their normal and emergency ratings of the lines while replacing aging assets;
  • a revision request (RR452) adding a standardized process for evaluating projects proposed by transmission owners for reasons other than meeting SPP regional criteria or a limited subset of local planning criteria evaluated in the planning process;
  • the 2023 operating plan that describes SPP’s high-level objectives and initiatives for next year (strategic opportunities, implementing FERC orders 881 and 2222, addressing two major FERC proposals related to transmission-planning processes, and responding to the 2021 winter weather event) and serves as the foundation for the annual budget process; and
  • removing the suspension earlier this year of an NTC, originally awarded in 2018 to Nebraska Public Power District, for a 115-kV project valued at $53.8 million.
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Study Tallies Economy-wide Benefits of Western RTO

Adoption of an RTO could yield significant economic benefits for the West, adding billions to the region’s annual gross product and generating tens of thousands of new jobs, according to a new report.

Released last week by Advanced Energy Economy (AEE), the Western RTO Economic Impact Study was prepared by Energy Strategies and Peterson & Associates. It draws on analysis Energy Strategies performed for a state-led study published last year to quantify the electricity system benefits of a Western RTO.

Speaking on a call July 26 to discuss the study, Energy Strategies’ Caitlin Liotiris said that while previous RTO-related studies have focused on the savings to the Western electricity system itself, there has not been much research on how those savings “might flow into the broader economy and can create ripple effects, creating additional jobs and attracting more businesses from more competitive electricity prices.”

“And this study really aims to fill that gap, looking at high-level impacts to the Western region as a whole,” Liotiris said, adding that state-by-state summaries will be coming out in the future.

Last year’s state-led study, which was a collaboration among energy offices from Colorado, Idaho, Montana and Utah, found that an RTO covering the entire U.S. portion of the Western Interconnection could save the region $2 billion in annual electricity costs by 2030. (See Study Shows RTO Could Save West $2B Yearly by 2030.)

The AEE economic impact study focuses on a similar time frame, finding that an 11-state RTO could generate $18.8 billion to more than $79.2 billion in additional gross regional product (GRP) by 2030, equivalent to 0.4 to 1.6% of the region’s current GRP. The study also found that an RTO could help create between 159,000 and 657,000 permanent jobs at an average total compensation (including benefits) of $73,000 a year.

“The analysis shows that the growth from lower electricity prices may be substantial, ranging from about 51,000 to 230,000 jobs, and would affect industries crucial to the West’s long-term economic prospects,” the study said. “Notably, things like data center expansion or new data center location in the West, which one would expect to be affected by lower electricity costs afforded by a Western RTO, shows up as a substantially affected industry. Manufacturing and construction also show up as industries likely to be impacted, on aggregate, across the West.”

Other financial benefits include incremental tax contributions ranging from $619 million to $2.4 billion a year and 2,800 to 13,700 temporary construction jobs in 2030 from the development of clean energy resources needed to meet additional corporate demand.

Tim Nadreau, assistant research professor at Washington State University and one of the study’s authors, said that the economy-wide benefits from a Western RTO would likely fall in the lower end of the study’s estimates, with the higher end “certainly feasible if market conditions improve.”

Nadreau said the study leaned on three separate analyses, with the first considering the increased purchasing power for consumers stemming from the $2 billion in electricity savings estimated in last year’s state-led study, and how that additional money will ripple through the larger economy.

The second analysis focused on the potential for increased business activity in the West resulting from lower electricity rates, assuming improved recruitment of businesses into region and increased business formation and expansion.

The third leg of the study’s analysis looked at increased investment in clean energy and “backstop technologies” to largely meet corporate demand, and to comply with some state and local initiatives.

“The range of results is really a reflection of the uncertainty in the market response for businesses and firms,” Nadreau said. “So business relocation, business growth and business formation — there are a lot of factors that go into that, and uncertainty in the markets contributes to those decisions. But the lower energy costs are a driving factor in those business decisions.”

Corporate Buildout

Rising corporate demand for clean energy would contribute significantly to the economy-wide benefits of an RTO, according to the study.

“On one hand, many states in the West are already on a path to significant clean energy penetration (with six targeting 100% clean electricity in the coming decades), indicating there is likely to be significant clean energy development across the West regardless of the region’s wholesale electricity market status,” the study states. “On the other hand, corporate buyers tend to drive further renewable energy investments in areas with RTOs, and previous studies have found that in order to achieve these state clean energy goals, more organized wholesale electricity markets (which provide needed system flexibility) may be required.”

Citing data from the Clean Energy Buyers Alliance, the study notes that the volume of clean energy capacity associated with corporate buyers rose from 3.22 GW in 2015 to more than 11 GW in 2021.

In calculating the low-end estimates in the AEE study, the authors assumed that corporate deals nationwide would fall to 50% of 2020 levels, equating to 5,250 MW of deals per year from 2025 to 2035, while high-end estimates assumed a continuation of the 2020 growth rate of 10,500 MW annually.

CEBA data show that 82% of corporate clean energy deals in 2020 occurred in organized electricity markets, which served only about two-thirds of the nation’s demand, meaning those markets contained 25% more corporate deals than their straight-load ratio, “suggesting that organized wholesale markets facilitate clean energy development used to meet corporate sustainability goals,” the study said.

Applying that 25% above-straight-load ratio to an organized Western market, the study found that from 2025 to 2035, the region would see an additional 1,888 MW of clean energy development on the low end of estimates and 9,409 MW on the high end.

“The West is home to some of the best wind resources in the country, though many wind resources are currently far from load and their development may be hampered by the additive transmission costs to bring them to a large load. However, the transmission cost structures would be modified under an RTO, making remote resources, such as wind, more attractive and more likely to be developed under an RTO framework,” the study said.

The study also noted that the Southwest is home to “high-quality” solar resources, and the authors assumed that solar contracted to corporate buyers would include a battery storage component.

Time is of the Essence

“I think one of the highlights of this study really shows how if we can move more rapidly to an RTO, there’s huge savings for customers, but there’s also a huge upside for new investment, new jobs and how that ripples out through the rest of the economy. And that was really how we tried to approach this debate in Colorado,” state Sen. Chris Hansen (D) said Tuesday. Hansen sponsored a bill (SB 72) passed by Colorado lawmakers last year requiring utilities with transmission assets in the state to join an RTO by 2030.

“I guess my only concern [is that] 2030 seems like a long time because at my age, I’m not even buying green bananas right now, so we need to get this done,” said Colorado Sen. Don Coram (R), another SB 72 sponsor.

“I’m very concerned about the Colorado River. We’ve got 40 million people dependent on the Colorado River; power production could be at risk. And without this grid set up to relieve that gap, we’re treading on thin ice here. So I think it’s very important that we as a region get this organized,” Coram said.

“The study confirms what we’ve known in Nevada for some time: that joining a Western RTO will save consumers on energy costs, create jobs and allow for more transmission of Nevada’s abundant clean energy resources,” said David Bobzien, director of the Nevada Governor’s Office of Energy.

Bobzien said the expanded transmission resulting from an RTO will foster increased sharing and trading of renewable energy, helping to reduce electricity prices and help Nevada meet its clean energy and carbon-reduction goals.

“We’ll also be able to offer companies with sustainability targets the opportunity for clean energy procurement as well, as more Western states and utilities pursue clean energy policies and climate goals,” he said.

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FERC Approves $249K Penalties in SERC, RF, Texas RE

FERC on Friday approved nearly $250,000 in penalties leveled by SERC Reliability and the Texas Reliability Entity in separate settlements against Duke Energy and Bryan Texas Utilities (BTU) for violations of NERC reliability standards (NP22-27).

NERC filed the settlements with the commission June 30 in its monthly spreadsheet Notice of Penalty, along with a separate NOP concerning an unnamed entity’s violation of the Critical Infrastructure Protection (CIP) standards; details of this NOP were not disclosed in accordance with NERC and FERC’s policy treating CIP violations as critical energy/electric infrastructure information. (See FERC, NERC to End CIP Violation Disclosures.) In its Friday filing, the commission said it would not further review the settlements, leaving the penalties intact.

Ratings Issues Across Duke Companies

SERC’s settlement with Duke involves FAC-009-1 (Establish and communicate facility ratings) and its successor FAC-008-3 (Facility ratings), which replaced the earlier standard in 2012. According to the NOP, Duke and its Energy Carolinas (DEC) and Florida (DEF) subsidiaries — had multiple instances of “facility ratings that were [not] consistent with their respective facility ratings methodology [FRM],” as called for in FAC-009-1. The violations began in 2007, when the original standard first took effect, and had not been fully resolved at the time of the filing.

The regional entity first learned of the violation in August 2018, when DEC submitted a self-report that DEF had discovered three cases of inconsistent facility ratings at a single 500-kV substation. (DEC submitted the report as part of an existing agreement with SERC.) DEF found that three 500-kV line segments had been recorded in the facility ratings database as bundled line conductors rather than single; as a result, the segments were not documented as the most limiting element in the substation.

During preparations for a subsequent audit by SERC, DEC and Duke discovered and reported additional instances of noncompliance; in a walk-down during the audit, SERC found more ratings that were inconsistent with the FRM. SERC then requested all Duke companies conduct extent-of-condition inspections, which returned as of November 2021:

  • DEC: 65 instances of noncompliance at 326 facilities;
  • DEF: 26 instances at 96 facilities; and
  • Duke: 69 instances at 725 facilities.

SERC identified the root cause of the violations as “the presence of vertical organizational silos,” primarily originating from Duke’s merger with Cinergy in 2006. Following the merger all of Duke’s companies had separate FRMs; while Duke and DEC later merged their FRMs, DEF and Duke Energy Progress still maintained their own facility ratings programs. This contributed to “a lack of uniformity and coordination over the years [and] a lack of awareness of the facility ratings program challenges” across Duke’s companies.

Duke’s mitigation activities include committing to form teams for each region to define walk-down processes and timelines and complete field walk-downs for all bulk electric system transmission substations at all Duke companies, reporting walk-down results and correcting any identified ratings discrepancies. The companies have also promised to conduct training for all relevant personnel and “assign additional staff to support FRM-related processes.”

Because part of the violations occurred in ReliabilityFirst’s footprint, SERC will share the $210,000 penalty with its fellow RE; based on the relative net energy for load of each region, RF will receive $85,260.

BTU also Settles over Ratings

Texas RE’s $39,000 settlement with BTU also stems from violations of FAC-009-1 and FAC-008-3, along with FAC-008-5. The noncompliance was first detected by Texas RE during a compliance audit, with a subsequent review by BTU discovering nine facilities in all where facility ratings were not consistent with the FRM.

The RE attributed the violation to “overreliance on stale field verifications,” noting also that BTU had not done a good enough job communicating with neighboring entities on the equipment ratings for their jointly owned facilities. Instead of using old field data, Texas RE said BTU could have proactively checked and verified facility ratings “when the opportunity was available,” for example during construction and maintenance.

Texas RE assessed the violations as a moderate risk to the reliability of the bulk power system, noting that no harm is known to have occurred as a result. However, it also said the violations were aggravated by their length, having begun in 2007 and continued until 2021 when BTU recalculated the inaccurate ratings and reported the results to ERCOT.

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What’s in the Inflation Reduction Act, Part 2

The passage of the Inflation Reduction Act of 2022 (IRA) (H.R. 5376) — formerly known as the Build Back Better Act — is once again hanging on the vote of a conservative Democrat, in this case Sen. Krysten Sinema (Ariz.) and not Sen. Joe Manchin (W.Va.).

Sinema was not part of the negotiations between Manchin and Senate Majority Leader Chuck Schumer (D-N.Y.) that resulted in a deal on the bill, announced Wednesday. (See Schumer, Manchin Reach Climate Deal.) She has in the past opposed one of the bill’s key tax provision — the closing of so-called carried-interest loophole — which could cut into the lucrative income that asset managers earn from the large investments they manage.

Meanwhile, Manchin blitzed all the major Sunday talk shows to promote the bill. “This is a red, white and blue bill,” not green, he told Jake Tapper on CNN’s “State of the Union.”

While Sinema was not directly involved in the drafting of the IRA, Manchin said many of its provisions were influenced by her. Manchin also justified the secret negotiations between himself and Schumer because “I didn’t think it would come to fruition. I didn’t want to have disappoint people again,” he said.

“I think that basically when [Sinema] looks at the bill and sees the whole spectrum of what we’re doing and all of the energy we’re bringing and all the reduction of prices and fighting inflation … hopefully, she will be positive about it,” he said.

As they await Sinema’s decision and a review of the law by the Senate parliamentarian, clean energy companies and advocates are lining up with other Senate Democrats to push for passage of the bill, even if the Senate does not vote on it before its planned monthlong recess begins Aug. 8. (See related story, What’s in the Inflation Reduction Act, Part 1.)

Here are some of the key stakeholders and the provisions they support.

Carbon Capture and 45Q

The carbon capture industry has long lobbied for expanding the 45Q tax credit to apply to more projects by raising incentive amounts and lowering capture threshold amounts, the minimum CO2 facilities would have to capture to qualify for the credit.

The IRA would deliver on both counts. Under the bill, the incentive for carbon captured and sequestered in geologic formations, such as saline aquifers, would jump from $50/MT to $85/MT. The incentive for carbon utilization ― for example, for either alternative fuels or enhanced oil recovery ― would increase from $35/MT to $60/MT.

The incentives for direct air capture would go as high as $180/MT for permanently sequestered CO2 and $130/MT for carbon utilization or enhanced oil recovery.

Reductions in capture thresholds are even more dramatic. To qualify for the credit currently, CCS equipment at an electric generating facility has to capture 500,000 MT/year; under the IRA, the amount would be slashed to 18,750 MT/year. The threshold for other industrial facilities falls from 100,000 MT/year to 12,500 MT/year, and the threshold for direct air capture projects is cut from 25,000 MT/year to 1,000 MT/year.

If passed, these “monumental enhancements” could “provide the most transformative and far-reaching policy support in the world for the economy-wide deployment of carbon-management technologies,” said Madelyn Morrison, external affairs manager for the Carbon Capture Coalition. “Economy-wide commercial deployment of carbon-management technologies and infrastructure [are vital] if midcentury global temperature targets are to remain within reach.”

Green Hydrogen

Hydrogen production got a major boost in the Infrastructure Investment and Jobs Act with its $8 billion for regional clean hydrogen hubs and $1 billion aimed at reducing the cost of the electrolysis process used to produce zero-emission hydrogen.

The IRA follows up on this with a substantial production credit of 60 cents/kg for clean hydrogen, which could rise to $3/kg for facilities that pay prevailing wages and have certified apprenticeship programs.

Hydrogen production worldwide is estimated at 120 million MT, only about 1.9% of which is green, according to the International Energy Agency.

The bill would also provide reduced tax credits — 12 to 20 cents/kg — for blue hydrogen, produced from natural gas with carbon capture, depending on the level of emissions associated with any specific facility. However, a plant already receiving 45Q tax credits for carbon capture would not be able to receive the hydrogen credits.

These tax credits could make green hydrogen cheaper to produce than gray hydrogen, produced from natural gas without carbon capture, said Mona Dajani, global co-head of the Energy and Infrastructure Projects Team at New York law firm Pillsbury Winthrop Shaw Pittman.

Facilities qualifying for the $3/kg credit “will make it cheaper to produce [clean] hydrogen here in the U.S. than anywhere else in the world, because of natural gas prices,” she said.

Advanced Nuclear and HALEU

The IRA provides $700 million for building out a U.S. supply chain for high assay, low-enriched uranium (HALEU), which is the higher-density nuclear fuel needed for the advanced nuclear reactors being developed.

Unlike the uranium used for existing reactors in the U.S., HALEU has a higher level of the U-235 isotope, which allows it to produce more power per unit of volume, which in turn allows for smaller reactors.

According to Judi Greenwald, executive director of the Nuclear Innovation Alliance, $500 million of the IRA funds would go to supply chain development, with $100 million each for research and development, and for the transportation system needed to support the U.S. industry.

“It’s a significant investment for a really important component for advanced reactors,” Greenwald said. “A key condition for the success for advanced reactors is the availability of HALEU.”

At present, the Department of Energy is the only producer of HALEU in the U.S., and it can only enrich a small amount for use in research. Lawmakers on both sides of the aisle are eager to develop a domestic supply chain because Russia is the only other major producer of HALEU.

The IRA would provide another boost for advanced nuclear in the technology-neutral energy tax credits that will replace renewable energy production tax credits beginning in 2025, specifically for facilities producing zero-carbon energy. For plants complying with prevailing wage and apprenticeship requirements, the credit would be 1.5 cents/kWh.

Once a facility is online, credits would be available for 10 years, which “will make a huge difference in helping to get these early reactors built,” Greenwald said. “As you build them, you learn by doing, and then they get cheaper. This is the way we’re going to really help to commercialize advanced nuclear.”

Two advanced reactors, one in Wyoming and one in Washington state, being built with DOE funds are scheduled to be online by 2028.

Methane Emissions

The IRA would tackle methane emissions with a mix of incentives for mitigating emissions at wells, pipelines and other facilities, and penalties for emissions exceeding certain levels.

On the incentives side, the bill would give EPA $850 million through Sept. 30 2028, for “grants, rebates, contracts, loans and other activities” aimed at reducing methane emissions. The funds could be used for monitoring and reporting emissions, installing innovative emission-cutting equipment and plugging wells on nonfederal land.

An addition $700 million is allocated for similar activities targeted at “marginal conventional wells,” those that are more expensive to run because of environmental issues or low levels of production.

The bill would also authorize EPA to “impose and collect” penalties at a range of oil and gas facilities — including on- and offshore production plants, pipelines and storage — that emit more than 25,000 MT of CO2 per year. The thresholds for different kinds of oil and gas facilities vary, but the penalties are uniform, starting at $900/MT in 2024, $1,200/MT in 2025 and $1,500/MT in 2026 and beyond.

These provisions got a chilly reception from fossil fuel groups.

“While there are some improved provisions in the spending package … we oppose policies that increase taxes and discourage investment in America’s oil and natural gas,” said Amanda Eversole, chief advocacy officer of the American Petroleum Institute.

The American Gas Association tweeted out praise for the bill’s support for hydrogen and renewable natural gas but was mum on the methane provisions.

OSW, Permitting, Clean Ports

The IRA would reverse the Trump administration’s 10-year moratorium on development off the shores of Florida and the Carolinas. It also would begin a process for exploring the feasibility of offshore wind development in Puerto Rico, Guam, American Samoa, the U.S. Virgin Islands and the Northern Mariana Islands.

To accelerate the permitting process, the bill allocates $125 million for DOE, $100 million for FERC and $150 million for the Department of the Interior “to provide for the hiring and training of personnel, the development of programmatic environmental documents, the procurement of technical or scientific services for environmental reviews, the development of environmental data or information systems, stakeholder and community engagement, and the purchase of new equipment for environmental analysis to facilitate timely and efficient environmental reviews.”

The bill would also provide $400 million through 2031 to provide incentives for businesses serving communities with high levels of air pollution to replace heavy-duty diesel vehicles with zero-emission vehicles. Another $2.25 billion would be available for zero-emission equipment at U.S. ports.

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PJM MRC/MC Briefs: July 27, 2022

Markets and Reliability Committee

2022 Quadrennial Review

The PJM Markets and Reliability Committee last week received a briefing on four alternative sets of capacity auction parameters as part of its 2022 Quadrennial Review.

Members will be asked to select one of the packages from PJM, the Independent Market Monitor, Calpine and Cogentrix at the MRC’s Aug. 24 meeting, which will be followed by a vote at a special Members Committee meeting. The votes are advisory, however; the Board of Managers will make the decision on what parameters to propose to FERC.

The parameters — which include the shape of the variable resource requirement curve, the cost of new entry for each locational deliverability area, and the methodology for determining the net energy and ancillary services (E&AS) revenue offset — would be effective with the July 2023 capacity auction for delivery year 2026/27.

Cogentrix’s proposal was the overwhelming favorite in a vote of the Market Implementation Committee on July 19-22, winning 73% support, with 62% saying they preferred it over the status quo. The PJM and Calpine packages tied at 28% each, while the Monitor’s proposal garnered only 15% support. (Members were permitted to vote for more than one option.)

The Cogentrix proposal, which was presented by GT Power Group’s Jeff Whitehead, adopts the status quo:

      • reference technology (combustion turbine);
      • variable operations and maintenance (VOM) parameter (major maintenance and operating cost included);
      • simulation method for calculating net energy revenues (peak hour dispatch); and
      • net E&AS (historical-looking inputs).

Cogentrix’s proposal also adopts PJM’s fuel assumption (firm transportation) and for the three points on the VRR curve but with the use of a CT rather than the RTO’s combined cycle reference technology.

The Cogentrix curve would result in a price of about $600/MW-day for an unforced capacity (UCAP) reserve margin of about 7.5%, up from about $500/MW-day with the current curve, according to PJM. The curve is almost identical to the RTO’s proposed curve above a 10% UCAP reserve margin.

Whitehead said Cogentrix chose a CT as the reference technology because it is less dependent on E&AS revenue than combined cycle plants. “We’ve seen how much E&AS revenues can change … in a relatively short period of time,” he said, a danger when parameters are being set four years in advance of delivery. LMPs, which hovered around $20/MWh “around the clock” during the coronavirus pandemic, averaged about $67/MWh in June, he noted.

He said CTs are also the most likely generation to be built in a “capacity crunch.”

David Scarp Scarpignato (PJM) Content.jpgDavid “Scarp” Scarpignato, Calpine | PJM

He acknowledged energy storage may be a more appropriate reference technology in the future, noting they are “extremely dependent” on capacity revenue, with regulation their only other revenue source.

David “Scarp” Scarpignato of Calpine said his company’s proposal was based on PJM’s and the recommendations of the RTO’s consultant, The Brattle Group. However, Calpine favored a historic E&AS offset rather than the forward-looking approach proposed by PJM and the Monitor.

“It’s a bad time with all the volatility in the gas markets to be switching to the forward” approach, Scarp said.

Calpine chose PJM’s proposal for the first two points on the VRR curve and the status quo for the third point.

“The bottom part of the curve makes a lot of sense,” Scarp said. “MISO has a vertical curve. And we saw how that worked out in the last auction.” (See MISO Capacity Auction Values South Capacity at a Penny.)

Monitor Joe Bowring made a case for his proposal to use only operating costs in the VOM calculation. “Ideally the VOM would all be in avoidable costs, but we recognize it’s not currently” he said. As a result, the IMM proposed including major maintenance in energy offers. “If they are in the energy offers, they should not be in avoidable costs,” Bowring said.

Manual Revisions OK’d

The MRC endorsed:

      • changes to Manual 01: Control Center and Data Exchange Requirements, Manual 18: PJM Capacity Market and Manual 28: Operating Agreement Accounting to conform with new testing requirements for demand response and price-responsive demand. The changes, which were approved by FERC in June 2020, will become effective with delivery year 2023/24 (ER20-1590).
      • updates to Manual 14D: Generator Operational Requirements to support the process timing changes for generation deactivations. (See “‘Quick Fix’ Changes OK’d for Manual 14D,” PJM Operating Committee Briefs: July 14, 2022.)
      • revisions to Manual 28: Operating Agreement Accounting to support the start-up cost offer development proposal the MRC approved in May, which allows costs associated with a resource’s initial ramping megawatts and soak costs to be included in its start cost. The MC later endorsed related changes to Manual 15: Cost Development Guidelines, tariff definitions, Attachment K, Operating Agreement definitions, and Schedules 1 and 2. (See “Start-up Cost Offer Development Proposal Endorsed,” PJM MRC Briefs: May 25, 2022.)

Members Committee

Application of Designated Entity Agreement

PJM’s notice that it planned to make a Federal Power Act Section 206 filing asserting that the OA’s provisions on designated entity agreements (DEAs) are unjust and unreasonable prompted the cancellation of scheduled MRC and MC votes on competing issue charges on the matter.

One issue charge was proposed by consumer advocates for Delaware and New Jersey, and a second was by East Kentucky Power Cooperative on behalf of transmission owners. The latter would make out of scope any consideration of changes to the rights and responsibilities of PJM and the TOs under the Consolidated Transmission Owners’ Agreement.

Greg Poulos (PJM) Content.jpgGreg Poulos, CAPS | PJM

The sponsors withdrew their proposals after PJM gave notice of its planned FERC filing on the MRC and MC agendas. PJM also gave the MC “notice of consultation” of a potential filing under FPA Section 205 to revise the pro forma DEA in Attachment KK of its tariff.

“It didn’t make sense to have both a FERC proceeding and a stakeholder proceeding going on at the same time,” explained Greg Poulos, executive director of the Consumer Advocates of the PJM States (CAPS).

On July 26, a group of load-side stakeholders beat PJM to FERC, filing a complaint asking the commission to force the RTO to require incumbent TOs to sign DEAs on “immediate need” projects. The complainants contended the RTO has violated the OA by refusing to do so. (See related story, PJM Challenged on Oversight of ‘Immediate Need’ Tx Projects.)

PJM attorney Pauline Foley said the RTO received the stakeholders’ complaint late last Tuesday afternoon. “PJM is reviewing the complaint and assessing its path forward,” Foley told the MRC on Wednesday.

‘Seeding’ the Matrix

Members endorsed a proposal to allow PJM and stakeholders to add options to a Consensus Based Issue Resolution (CBIR) matrix before posting the matrix for discussion.

The change will allow PJM and stakeholders to offer options after completing the identification of design components (Step 1) and before posting to facilitate creation of the options matrix (Step 2) prior to solution package development (Step 3).

PJM’s Dave Anders said the proposal by John Horstmann of Dayton Power & Light and Adrien Ford of Old Dominion Electric Cooperative to modify Manual 34: PJM Stakeholder Process would address the “writer’s block” that sometimes occurs at the beginning of the matrix development.

Bowring said his prior concern that the proposal would give PJM an advantage were addressed by assurances that any options proposed by the RTO could be ignored. (See “Members Debate Change to CBIR Matrix Procedure,” PJM Stakeholders Pump the Brakes on ‘Clean Energy Expertise’ for Board.)

Steve Lieberman of American Municipal Power said he thought the change was unnecessary because the individuals sponsoring a problem statement and issue charge should be prepared to initiate discussion of options. But he said he was “not willing to fall on my sword” by opposing it.

The measure passed by acclimation with one objection and two abstentions.

PJM Annual Meeting

PJM will hold its first off-site Annual Meeting since the pandemic on Oct. 24-26 at the Hyatt Regency Chesapeake Bay in Cambridge, Md. Registration will be conducted online between Aug. 1 and Oct. 19. No walk-up registrations will be permitted. The fee for guests will be $400.

‘Clean Energy Expertise’ Requirement

The Illinois Citizens Utility Board presented three proposed revisions to the OA to add a requirement that one member of the PJM board have “clean energy resource expertise.”

Albert Pollard, who heads CUB’s CLEAR-RTO project, said one of the proposed revisions — requiring “expertise and experience in the development, integration, operation or management of clean energy resources” — was nearly identical to language the RTO is using in its current search for a replacement for Manager Sarah Rogers, who attended her final MC meeting Wednesday.

Pollard said the change is needed because the transition to carbon-free generation is a “top priority” for the RTO.

ODEC’s Ford questioned whether the OA should be revised. Cybersecurity expertise is also important to the board but is not mentioned in the agreement, she said.

“If the [requirements] matrix gets too big, it might result in focusing on some areas of expertise and neglecting of others,” she said.

MC Chair Erik Heinle said the issue will likely be on the agenda for the committee’s Sept. 21 meeting.

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NYISO Management Committee Briefs: July 27, 2022

Grid Performs Well in July Heat Wave

The New York grid performed well in the summer’s first heat wave July 20 to 24, Aaron Markham, NYISO vice president of operations, told the Management Committee on Wednesday.

NYISO and transmission owners recalled facilities to service and rescheduled transmission and generation outages to prepare for the hot weather. That week’s peak load occurred on July 20, a Wednesday, at 30,505 MW, or just over 97% of the baseline forecast for the summer, Markham said.

NYISO July Peak Loads (NYISO) Content.jpgJuly 20 zonal peak loads in the New York Control Area | NYISO

 

“In general, generation performed well,” Markham said. “From a transmission perspective, the Neptune cable with PJM did return to full capability on Tuesday, [July 19,] so it was able to supply additional megawatts into Zone K [Long Island] from PJM.”

The Western New York public policy transmission project was also effective at reducing supply bottlenecking through the period, Markham said.

The ISO did activate emergency demand response and special-case resource (SCR) programs in Zone F [the Capital District] on both Tuesday and Wednesday in response to a forced outage at the 115-KV Greenbush substation in that area, which caused some supply bottling and added to transmission congestion into the region, he said.

“In summary, things went well, and we are watching the weather for next week,” Markham said. “It looks like it is warming up again, probably not to the level we experienced last week, but we will continue to monitor that and take actions as needed to be ready for it.”

June LBMPs Rise Slightly; Gas Prices Ease

NYISO locational-based marginal prices averaged $76.72/MWh in June, up from $70.60/MWh the previous month, COO Rick Gonzales said in delivering the monthly operations report.

Day-ahead and real-time load-weighted LBMPs came in higher compared to May. Year-to-date monthly energy prices averaged $87.37/MWh, a 115% increase from $40.59/MWh in June last year.

June’s average sendout was 422 GWh/day, higher than the 372 GWh/day in May but lower than the 458 GWh/day a year earlier.

Transco Z6 hub natural gas prices averaged $6.91/MMBtu for the month, down from $7.39/MMBtu in May and up 164.5% year-over-year.

Distillate prices were up 115.4% year-over-year but mixed compared to the previous month. Jet Kerosene Gulf Coast averaged $30.68/MMBtu, up from $29.17/MMBtu in May. Ultra Low Sulfur No. 2 Diesel NY Harbor averaged $31.30/MMBtu, down from $32.97/MMBtu in May.

June uplift decreased to ‑61 cents/MWh from ‑5 cents/MWh the previous month, and total uplift costs, including NYISO’s cost of operations, came in lower than those in May. The ISO’s local reliability share dropped to 46 cents/MWh in June from 60 cents/MWh the previous month, while the statewide share decreased to ‑$1.07/MWh from ‑65 cents/MWh in May.

No RS1 Cost-of-service Study 

The MC voted not to conduct a new Rate Schedule 1 cost-of-service study in 2022-2023. (See “RS1 Cost-of-service Study,” NYISO Management Committee Briefs: June 14, 2022.)

The last study, which considers the impact of the significant market design changes to be implemented, was done in 2011, and the tariff requires the committee to vote on whether to conduct one each year.

CEO Rich Dewey said NYISO will review the steps required to make a tariff change to remove the topic from requiring an annual vote. The ISO has plenty of work to do with the projects now underway, but next year it will come to the issue prepared with information on how much human resources would be needed to perform the cost-of-service study, he said.

“Then we’ll have better data in terms of how that intersects with other efforts within the project schedule, and market participants can be more informed about what that impact might be,” Dewey said.

Bad Debt Loss Methodology

The committee approved a recommendation from the Business Issues Committee to adopt a proposal from DC Energy to change the “look back” period in the tariff for determining each participant’s contribution to recover a bad debt loss, expanding the period from one month to three.

Bruce Bleiweis, director of market affairs for DC Energy, presented the change and said the company believes the goal of the payment default and bad debt loss allocation methodology is to spread the loss fairly based on NYISO stakeholders’ overall billing determinants. (See “Bad Debt Loss Methodology,” NYISO Business Issues Committee Briefs: June 22, 2022.)

One stakeholder asked whether the proposal had any risk of increasing market participants exposure to bad debts.

“This proposal does nothing to change the amount of credit or collateral that we have here,” said Sheri Prevratil, NYISO manager of corporate credit. “If a market participant defaults, we would always use that credit support first to cover any default before we declared a bad debt loss. … The ISO has no objection.”

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Stakeholders Troubled over MISO Response to FERC Planning NOPR

MISO’s response to FERC’s proposed transmission planning rule will emphasize its worry that it could be too arbitrary and bog down the RTO with compliance check marks.

The grid operator plans to send comments to the commission in August warning against an overly prescriptive rulemaking. It will say it is concerned over the notice of proposed rulemaking’s level of detail and specifics and that “ongoing compliance will impede ongoing expansion.”

However, some stakeholders said this week they are worried that MISO’s fixation on specifics could leave the nation with another toothless transmission rulemaking.

MISO staff said its transmission planning already covers the NOPR’s suggestion for scenario-based regional transmission planning (RM21-17). (See FERC Issues 1st Proposal out of Transmission Proceeding.)

During a Planning Advisory Committee (PAC) meeting Wednesday, MISO’s Jackson Evans said that while the RTO supports the aim of long-term, scenario-based planning, grid operators need flexibility “to meet the unique needs of the regions and their stakeholders.”

“There’s really no one way to do this correctly,” Evans said. He said MISO doesn’t want to be forced to “take resources away from its existing planning and devote them to compliance.”

Evans said an overly prescriptive rule might imperil the grid operator’s ongoing planning under its long-range transmission plan (LRTP) and its joint targeted interconnection queue (JTIQ) study with SPP.

“MISO was a leader in this area before this week,” Evans said, referencing the Board of Directors’ approval of the $10.3-billion LRTP Monday. (See MISO Board Approves $10B in Long-range Tx Projects.)

MISO said FERC should “order direct changes to regions it deems to be insufficient in meeting objectives” and said the commission should exercise its Section 206 authority and “tailor its focus” to regions that are not performing robust planning.

Stakeholders Push Back

Multiple stakeholders said FERC Order 1000’s failure to spur transmission projects is evidence that the commission should be more prescriptive, not less, when it comes to planning.

“I’m not saying we need a nanny state, but we need a prescriptive set of requirements,” the Union of Concerned Scientists’ (UCS) Sam Gomberg said during a cost-allocation meeting Tuesday.

Others said MISO should assume there’s always room for improvement and that FERC’s final rule could help the RTO achieve better quality planning.

“I think it would be arrogant to assume we’re doing it 100% right and we’re perfect,” Customized Energy Solutions’ Ginger Hodge said during the PAC meeting.

Andy Kowalczyk of activist group 350 New Orleans suggested MISO highlight the ingredients of its planning success with FERC to help shape minimum requirements. “I strongly urge MISO to lean not too hard into flexibility,” he said.

“MISO is a leader in transmission planning, but that doesn’t mean we can and shouldn’t do better,” Sustainable FERC Project attorney Lauren Azar said.

Azar said MISO’s planning aims can be swayed or stymied by stakeholders, who are in some instances able to “thwart” transmission planning. She pointed to the 2017 regional transmission overlay, which failed to yield a project, as an example. (See Early Release for MISO Long-Term Tx Overlay Study.)

“We’re more than five years behind in building out a grid,” she said.

Azar said some nationwide standards could help MISO and the nation overcome resistance to grid expansion.

Mississippi Public Service Commission attorney David Carr disputed the idea that the 2017 regional overlay study was ever meant to result in projects. He characterized the study as MISO’s response to the Clean Power Plan, which was ultimately struck down.

Basking in LRTP’s Afterglow

MISO took a victory lap after approving its first LRTP portfolio.

During an executive update Tuesday, Aubrey Johnson, vice president of system planning, said he was “pleased and excited” that the board voted in favor of the LRTP’s 18 lines.  He said staff will now study a second set of transmission needs for MISO Midwest that considers a more rapid fleet change and decarbonization.

“Growing pressures on the fossil fuel industry are accelerating retirements,” Johnson said. He added that new renewable energy additions aren’t currently keeping pace as a reliable, accredited replacement.

“It is clear that the future is going to look very different than the past,” he said.

With the LRTP’s approval, MISO and SPP’s JTIQ study investment will shrink from $1.65 billion to $1.06 billion. The portfolios contain the same two 345-kV projects in North Dakota and Minnesota. MISO decided several months ago that it would independently pursue the projects under its regional planning; it has said SPP’s share of benefits from the projects are negligible and not worth pursuing in cost splits. (See MISO Stakeholders Uneasy Over Long-range Tx, JTIQ Overlap.)

The NOPR and long-term planning discussion come as MISO’s cost-allocation stakeholder group mulls new benefit metrics for transmission projects that strengthen the grid’s reliability and resilience. On Tuesday, the group discussed how to quantify the benefits of a line’s ability to withstand extreme weather events and valuing a minimum transfer capability.

Climate scientist Rachel Licker, with UCS, said it’s clear that climate change is driving more common and longer-lasting heat waves, which will intensify air conditioning demand. She said MISO may be underestimating future demand for cooling in its modeling. Licker added that nighttime lows are no longer dipping to historic averages, making air conditioning use at night more common.  

Gomberg said MISO should value transmission that helps achieve decarbonization to avoid more devastating heat waves and storms, which can decimate power lines and equipment.

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FERC Proposes Allowing RTOs to Share Credit-related Info

WASHINGTON — FERC on Thursday proposed allowing RTOs and ISOs to share credit-related information about market participants, fulfilling one of the main requests the grid operators made at a technical conference last year (RM22-13).

The Notice of Proposed Rulemaking, approved unanimously at the commission’s monthly open meeting, would require the grid operators to revise their tariffs to eliminate confidentiality provisions that prevent them from sharing such information. They would also be allowed to use received information for the same purposes for which they use information from their own market participants.

Allowing this information sharing “could improve the accuracy of credit exposure and risk assessments across multiple electric power markets,” the commission said in a statement. “It also could enable market operators to respond to credit events more quickly and effectively, thereby minimizing the overall risks of unexpected defaults by market participants.”

At a technical conference in February 2021, RTO credit risk officials told FERC that although they meet monthly with their counterparts to share best practices, confidentiality rules prevent them from sharing market participant-specific information, even if the participant may pose a credit risk in multiple markets. (See RTOs: Let Us Share Trading Info.)

The commission agreed this is a problem.

“Negative credit events affecting a market participant’s credit standing in one market may impact its credit standing in other markets,” FERC said in its proposal. “An RTO/ISO that cannot obtain market participants’ credit-related information arising from their activities in other organized wholesale electric markets may not be able to fully protect its organized wholesale electric market from mutualized default risk.”

The commission also specified that information sharing must not be predicated on a market participant’s prior notice or consent. “A market participant facing financial difficulty would have little incentive to consent to credit-related information sharing,” it said.

Comments on the NOPR are due 60 days after publication in the Federal Register.

Collateral Requirements

The technical conference stemmed from PJM’s debacle with GreenHat Energy, which FERC accused of defrauding the RTO by acquiring a massive 890 million-MWh portfolio of financial transmission rights with only about $550,000 in collateral. When it defaulted on the portfolio in 2018, its three principals made off with $13 million and left PJM members holding a $179 million bag, FERC said in a January lawsuit after the company failed to pay $242 million in fines. (See FERC Levies $242M in Fines on GreenHat, Owners.)

FERC cited GreenHat in a second unanimous order Thursday requiring CAISO, ISO-NE, NYISO and SPP to show cause as to why they shouldn’t revise their tariffs to include provisions ensuring FTR market participants maintain sufficient collateral (EL22-62, et al.).

The commission said that after considering remarks at the technical conference and comments in that docket, it believes “that two specific practices may be particularly critical to effectively managing credit risk for FTRs”: a mark-to-auction mechanism and a volumetric minimum collateral requirement. Three of the grid operators cited in FERC’s order already implement one practice, but not the other; CAISO implements neither.

The first practice requires that participants maintain sufficient collateral to support the change in value of the FTR positions they hold based on the most recent auction prices for those FTRs. The commission noted that GreenHat’s losing positions went unnoticed by PJM because the RTO used historical FTR values. Since the company’s default, PJM — along with ISO-NE, MISO and NYISO — revised their tariffs to implement mark-to-auction mechanisms.

“While CAISO has limited opportunities to update the collateral requirements of [congestion revenue rights], it does not have a robust mark-to-auction FTR collateral requirement similar to what has been adopted recently in other organized wholesale electric markets,” FERC said. “SPP’s current TCR [transmission congestion rights] collateral requirements also do not include updating of collateral requirements based on the current value of a market participant’s TCR portfolio for all TCR positions.”

In addition, a minimum collateral requirement based on volume ensures that a market participant is required to cover potential defaults even when it has offsetting positions, FERC said.

“In some RTOs/ISOs, market participants are allowed to net FTRs with negative collateral requirements against FTRs with positive collateral requirements within the market participant’s portfolio, which can lead to large, risky FTR portfolios that require little or no collateral,” FERC said. “This can be a problem if future congestion is significantly different than historical congestion because the collateral held by the RTO/ISO may be insufficient for a portfolio’s risk.”

MISO, PJM and SPP all instituted volumetric minimum requirements after GreenHat’s default. “While [CAISO, ISO-NE and NYISO] establish minimum capitalization and participation requirements, they appear to lack any volumetric minimum collateral requirement that scales with a participant’s FTR portfolio to ensure participants cannot minimize their required collateral without correspondingly reducing their risk,” FERC said.

CAISO, ISO-NE, NYISO and SPP must file their responses within 90 days.