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November 1, 2024

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ERCOT Technical Advisory Committee Briefs: Dec. 4, 2023

Members Support 2024’s Ancillary Services Methodology, Despite Costs

ERCOT stakeholders endorsed the grid operator’s proposed ancillary service methodology for 2024, but only after extracting a commitment from staff to bring the proposal back for further review by April 30. 

The approval came after ERCOT’s Independent Market Monitor, Potomac Economics, said the methodology has generated artificial shortages that produced “massive” inefficient market costs totaling about $12.5 billion this year through Nov. 27.  

The Monitor also told the Technical Advisory Committee that the methodology diminishes reliability by withholding units needed to manage transmission congestion, is not based on sound reliability criteria, and has led to excessive reserves procurements that far exceed those by other grid operators. 

“I don’t want to exaggerate how bad this is, but this is the worst performance we’ve ever seen since the beginning of organized electricity markets almost 25 years ago,” Potomac’s David Patton said. “I’ve been racking my brain to try to figure out whether I’ve ever seen anything like this, and I really haven’t.” 

Patton, whose firm also monitors the MISO, NYISO and ISO-NE markets, said there’s no way to pretend the costs are “efficient,” as ERCOT was not experiencing shortages during periods with $5,000 capped prices.  

“We weren’t close to being in shortage and yet the market, with this large increase in 10-minute reserves that gets held out of the energy market, perceived a shortage that didn’t really exist,” he said. 

“Inefficiency is not how we operate in this market and provide reliability. Our objective is to provide reliability at lowest cost,” said MD Energy Consulting’s Mark Dreyfus, who represents the city of Eastland and 154 other commercial consumers. “Since the very beginning of this market, commercial consumers have been very clear. They support competitive market outcomes, wherever possible. By supporting competitive market outcomes, we will get the lowest cost reliability possible.” 

At issue is ERCOT contingency reserve service (ECRS), the grid operator’s first new ancillary service in 20 years that was deployed early this summer. Dreyfus called for a commitment to reconsider how the service is used and to better understand the Monitor’s report. 

The service is economically dispatched within 10 minutes of deployment, using capacity that can be sustained at a specified level for two consecutive hours and supplementing the ISO’s conservative operations posture of setting aside ample reserves. 

The IMM has said ECRS essentially meets the same reliability requirements that previously were met solely by responsive reserve service. In its initial assessment of ancillary services, the monitor said ECRS “likely” raised the real-time market’s energy value by at least $8 billion. (See ERCOT Board, IMM Debate Ancillary Service Costs.) 

ERCOT disputed the Monitor’s analysis, noting the $12.5 billion figure is not the direct cost of procuring ECRS, but a study that estimates how much lower real-time energy costs would have been if resources were not reserving capacity to provide ECRS. It said in a statement that actual costs were likely much less than that and other factors, such as the historically hot summer, contributed to increased prices. 

Potomac urged stakeholders to reject the AS methodology and requested that ERCOT use a reliability analysis that models the uncertainties that drive reliability problems and then quantify the needed reserves. It said staff could mitigate its concerns with several changes, including reducing ECRS’ deployment back to one hour.  

ERCOT staff has made minor changes to the 2024 AS methodology. It said the ECRS proposal reflects the minimum volume of 10-minute reserves needed to cover the risks should a large unit trip offline or frequency losses occur.  

However, the grid operator also allowed that a “separate, broader discussion is warranted” to identify improvements to the ECRS market. 

Given that caveat and as required by the protocols, TAC endorsed the 2024 methodology with a 21-3 vote. Six members abstained. An earlier vote to approve the methodology as recommended by ERCOT failed 12-7 with 11 abstentions. 

Potomac’s four-year contract as ERCOT’s Independent Market Monitor expires Dec. 31. It remains the only listed applicant to the Public Utility Commission’s request for a new four-year contract, but no announcement has been made (55222). 

Staff Withdraws DRRS Change

The committee approved ERCOT’s request to withdraw a nodal protocol revision request (NPRR1203) implementing a new ancillary service that faces a tight statutory timeline. 

Staff had proposed adding dispatchable reliability reserve service (DRRS) as a subtype of non-spinning reserve, saying it was the only way to meet a Dec. 1, 2024, deadline set by state law. TAC tabled the NPRR in October after lawmakers objected to ERCOT’s plans and said the standalone service should be developed even if it fails to meet the deadline. (See ERCOT Technical Advisory Committee Briefs: Oct. 24, 2023.) 

The PUC last month linked its approval of the budget to meeting several performance metrics. They included implementing the DRRS product “aligning it with the real-time co-optimization plus battery project (RTC+B). (See Texas PUC OKs Smaller Budget, Admin Fee Increases for ERCOT.) 

Kenan Ögelman, ERCOT’s vice president of commercial operations, said staff plans to develop DRRS as a standalone service “as expeditiously as possible” and will file a draft NPRR by April that aligns with real-time co-optimization’s (RTC) implementation. He also agreed with stakeholders’ requests for a workshop to review the NPRR’s details. 

“The goal would be to make sure everybody is fully informed on the functionality and features that we were putting into the NPRR and that we absolutely got stakeholder feedback on making that better or adjusting it, such that we had a product that the stakeholder community was comfortable with and that also met the statutory goals,” he said. 

The DRRS work will also align with the Real-time Co-optimization plus Batteries Task Force, which is developing the market tool that procures energy and ancillary services every five minutes. The team is developing business requirements for RTC and single-model batteries, with plans to complete its project in 2026. (See ERCOT Technical Advisory Committee Briefs: Aug. 22, 2023.) 

“The feedback I’ve gotten so far from the commission is RTC+B is the priority,” Ögelman said. 

TAC endorsed ERCOT’s plan 28-0, with Luminant and Lower Colorado River Authority (LCRA) both abstaining over the statutory deadline concerns. Luminant’s Ned Bonskowski said his company did not want to stand in the way of those wanting to move forward. 

“I am a little worried about certain policy decisions being driven by secondary timeline goals,” LCRA’s Emily Jolly said. 

Staff also withdrew two other binding document requests (OBDRR049, OBDRR050) related to NPRR1203. 

West Texas Projects Endorsed

TAC endorsed two Tier 1 transmission projects in the West Texas weather zone projected to cost a combined $1.17 billion, placing both on the combination ballot. 

The Regional Planning Group’s West Texas Synchronous Condenser project accounts for the bulk of the costs at $892.2 million. It involves installing synchronous condensers at six 345-kV substations to address reliability risks in West Texas driven by the region’s increased penetration of inverter-based resources (IBRs). ERCOT expects more than 42 GW of IBR capacity by 2026 in the zone. 

Staff said the prevalence of IBRs coupled with the lack of conventional synchronous resources has further weakened the system and increased the likelihood of potential instability issues, such as the recent Odessa disturbances. (See NERC Repeats IBR Warnings After Second Odessa Event.) 

The project, involving Wind Energy Transmission Texas, LCRA Transmission Services Corp. and Oncor, has an in-service date of May-October 2027. 

ERCOT’s proposed synchronous condensers at six 345-kV substations in West Texas. | ERCOT

The second project, submitted by Texas-New Mexico Power, is projected to cost $273.1 million. The upgrade involves the construction of two 345-kV substations, two 345/138-kV substations and 20 miles of 138-kV line to address reliability needs. The project is expected to be completed by June 2027. 

With capital costs exceeding $100 million, the Tier 1 projects must be approved by ERCOT’s board, which next meets Dec. 18-19. 

TAC Remembers Brad Jones

Members shared the memories of the late Brad Jones, who chaired TAC at one point and served as ERCOT’s interim CEO and COO. Jones, who also served as NYISO’s CEO, passed away Nov. 8. (See Brad Jones, Former ERCOT, NYISO CEO, Dies at 60.) 

Reliant Energy Retail Services’ Bill Barnes, who attended a memorial service Saturday in Austin along with many other stakeholders, said ERCOT’s membership was one of his most important families. 

“We heard a lot about Brad’s optimism,” he said. “The thing that I will take with me forever is the spirit of compromise. That’s why we’re here, to hear from different perspectives, hear from other segments, each other’s opinions, and think about how we can work together as a team to solve the very challenging problems that face us.” 

“You could argue with Brad up and down, back and forth, and respect was always maintained through that entire process,” said Engie’s Bob Helton, whose relationship with Jones goes back to the market design work of the late 1990s. “That’s one of the things that was wonderful about Brad. He would listen to you, argue with you, and we’d come to a good decision.” 

“Brad is one of the core reasons we have what we have today,” Golden Spread Electric Cooperative’s Mike Wise said. “He’s one of the godfathers of our market.” 

“Obviously, Brad was a very special and influential person at ERCOT. He had two stints with us, made amazing contributions, and brought a lot of joy and laughter to the folks at ERCOT,” Ögelman said. “In some of our darkest moments, he was our shining light as we were trying to deal with the aftermath of Winter Storm Uri. I certainly miss him every day and appreciate all that he’s done for everybody in this room and in the industry and ERCOT as well.” 

Retail Choice Coming to Lubbock

TAC’s unanimous endorsement of the combo ballot resulted in approval of a change to the retail market guide (RMGRR176) that lays out the processes Lubbock Power & Light must use when it begins offering customers their choice of electric providers March 4. 

Oncor’s Debbie McKeever, chair of the Retail Market Subcommittee, told the committee that more than two dozen electric retailers are preparing to offer plans in LP&L’s service territory.  

The municipal utility is migrating the final 30% of its load from SPP to ERCOT by Dec. 11. LP&L first announced its intention to join ERCOT’s competitive market in 2015. Texas regulators approved the transition in 2018. (See Six Years in the Making: LP&L Migrates Load to ERCOT.) 

The combo ballot included three other NPRRs that, if approved by the board and the PUC, would: 

    • NPRR1181: Require qualified scheduling entities representing coal or lignite resources to submit to ERCOT a seasonal declaration of coal and lignite inventory levels and to notify ERCOT when the inventories drop below target and critical-level protocols. 
    • NPRR1201: Reduce exposure from resettlements and default uplift invoices for historical operating days by limiting resettlement timelines due to errors that are discovered and a market notice is provided to the market within one year after the operating day. This limit does not apply to alternative dispute resolution resettlements, a procedure for return of settlement funds or a board-directed resettlement addressing unusual circumstances. 
    • NPRR1204: Implement the state-of-charge (SOC) concepts necessary for awareness, accounting and monitoring energy storage resources’ SOC within the RTC+B project. 
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Industry Considers Building its Own Generation to Decarbonize

While the power and transportation sectors can highlight some success in cutting emissions, hard-to-decarbonize industry is severely lagging behind them, with the sector likely to become the biggest emitter in coming decades, according to a report released by the Rhodium Group last week.

“As other sectors decarbonize, industry very likely remains the biggest source of emissions by a wide margin,” Rhodium said. “In fact, by 2050, industrial emissions exceed all emissions from power, transportation and buildings combined in our projection mean. Without meaningful solutions to decarbonize industry, global emissions will remain stubbornly high for the foreseeable future.”

The lack of viable alternative technologies to power industry means Rhodium’s projections are based largely on pure economic considerations, such as China’s decadeslong growth slowing down. The legacy industries such as steel, chemicals and cement are already built out in the U.S., so they are going to change over to cleaner energy production measures when their equipment needs to be replaced, Intersect Power CEO Sheldon Kimber said in an interview.

“We see emerging electrification of whole new industries that don’t even exist today,” Kimber said.

Kimber’s firm wants to attract new industries such as clean hydrogen, artificial intelligence data centers and direct air capture to areas such as the Texas Panhandle, where both wind and solar resources offer high-capacity factors.

Bringing industry to where clean energy resources can produce the most power at the best price also gets around the issue of needing to build out the transmission grid, which to successfully decarbonize needs to expand by 60% by the end of this decade and triple by 2050, according to widely cited estimates from Princeton University. That is a massive political, regulatory and economic lift; Kimber doubts the grid can grow that much on that time scale.

Getting the equipment to meet that 2030 target given the realities of the supply chain is going to prove difficult, with Kimber saying it would take five to seven years to even start construction on major new lines even if the policy questions were all answered correctly tomorrow.

“So, you’re talking about mid-2035, before even the first trickle of transmission comes online, if you get it perfect right now,” Kimber said.

That would likely require additional legislation because the kind of lines that need to get built are not shipping power across one state, but across multiple jurisdictions to bring renewables to market.

“The big projects we need are to get essentially the really high-capacity factor, low-cost cheap renewables into the load pockets,” Kimber said.

It is not just about connecting any kind of clean power, but getting to those areas where the wind and the sun can offer 60 to even 70% capacity factors without battery storage, he added. It will make sense for big industries to move to areas where they can get wind and solar nearby and then ship their products, rather than transmitting electricity across multiple jurisdictions.

Creating new jobs and economic growth in rural areas, which are largely conservative, also can bolster the political consensus around clean energy.

“This country needs a durable, sort of political consensus around clean energy,” Kimber said. “And the only way we’re going to get that is if everybody can participate in the clean energy industry: across the political spectrum, socioeconomic spectrum, different parts of the country. And I think we’re starting to get that now under the” Inflation Reduction Act.

The IRA has showered the clean energy industry with incentives just as the era of worry-free, cheap solar panels from China is slowing down, with a renewed focus on stable supply chains. Intersect has domestic supplies of panels lined up through deals with First Solar.

“We’re going to build $20 billion of infrastructure before the end of the decade,” Kimber said. “And we’re going to get all those modules from Ohio, Alabama and Louisiana.”

Building out high-quality renewables to directly serve new sources of load also avoids the issue of finding space on the grid, which is becoming increasingly crowded. Data center growth in Northern Virginia has made it so some sites have to run their on-site, inefficient gas generation as baseload to keep running, Kimber said.

“I think that hydrogen is going to be very similar, in that a lot of these folks are expecting to see an availability of interconnection that just isn’t going to be there,” he added.

Even if a large customer can plug into the grid, the only generation they will be able to find could be too far away.

“Any generation you can possibly source in the wholesale market is so far away from you on a basis perspective that you’re going to be paying four times as much, and you’d be better off building a pipe from the panhandle to that site than you would be building a wire from the panhandle to that site,” he added.

Producing clean hydrogen is a good example of an industry that Intersect wants to support because the electrolyzers to produce the fuel are costly, so the more they run, the greater amount of product those costs can spread around.

“That’s why I think in the near term, you’ll see a lot of those folks moving to places where you can get high-capacity factors from renewables only so you can get to 65 to 70% in the Panhandle of Texas; you add some batteries, [and] you can start getting closer to 80, 90 or 100%,” Kimber said.

Big Customers are Considering Going Nuclear

Renewables are not the only way to decarbonize. Lately industry has focused on building out its own nuclear plants for uses historically reserved for combined heat and power systems. Even Microsoft posted a job notice in September looking for a nuclear expert to help its energy strategy for data centers.

On the other side of Texas from the panhandle, Dow is developing small modular reactors at its Seadrift facility near the middle of the state’s coastline.

The firm is working with X-energy to deploy four 80-MW SMRs to supply its factory with power and steam, which will replace the more traditional cogeneration units on the site, Edward Stones, Dow’s vice president for energy and climate, told a Senate hearing recently. (See Senate Energy Committee Examines the State of Advanced Nuclear Reactors.)

Dow’s Seadrift facility is massive, covering 4,700 acres and producing 4 billion pounds of materials a year that go into applications ranging from food packaging and preservation, to wire and cable insulation, to packaging for medical and pharmaceutical products.

“Advanced nuclear provides a huge opportunity for industrial users of power and steam,” Stones testified. “Navigating the deployment challenges will require continued engagement between the private sector and federal government, particularly around the financial and operating risks to early adopters of this technology.”

One key consideration is timing because the SMRs Dow plans to install will replace aging cogeneration facilities so they cannot be tied up in regulatory processes that drag on so long the old plants break down, he added.

While 80 MW is small compared to the major nuclear plants with two or more reactors producing 2,000 MW or more, even smaller reactors are being developed that could help cut carbon from remote facilities such as mines.

NANO Nuclear Energy CEO James Walker said the market for “micro-reactors” — nuclear reactors that can fit inside a standard shipping container and be easily transported to sites that need power — was largely untapped when the company was forming.

“So, it’s almost like a nuclear battery and you’re competing with a diesel generator, and you could ship that anywhere in the world using conventional transportation infrastructure: trains, trucks, helicopters,” Walker said in an interview.

That kind of easily transportable reactor could serve mining sites, oil and gas production, data centers and car-charging stations, or it could replace the fossil fuel engines used on commercial ships around the world, he added.

Similar-sized reactors have been used in naval applications since the 1950s, so it is a matter of taking what is known from their use and adapting it for commercial purposes. The micro-reactor space is new, and it will take some time to win regulatory approval for such technologies, but Walker said they should be ready to start deploying by the end of the decade.

“We know that there are a lot of industries that were very keen on, say, wind and solar like that, but it was too intermittent,” Walker said. “The storage costs involved were enormous. The land usage required was prohibitive, often so prohibitive that it actually looked like it had increased their carbon footprint by the amount of land they would need.”

The Grid Will Still Serve Many Industrial Loads

While industry is considering building its own generation to help decarbonize, plenty of big customers will continue to draw power from the grid as they reach for net-zero emissions, but that is no longer just a matter of matching up some renewable energy credits with the amount of power consumed.

A shorthand for the new concept of deep decarbonization is “power to X,” which Lancium Director of Regulatory Affairs Andrew Reimers explained on a webinar hosted by the Energy Systems Integration Group. It refers to taking electricity and making something else with it, which is easily understood when it comes to clean hydrogen.

“If these loads can be operated in a flexible or controllable way, they can play a big role in allowing greater adoption of intermittent renewables,” Reimers said. “And so there is a pro to the con of the reliability impact they pose.”

The reliability impact is that many of these loads are very big, so if they were to unexpectedly trip offline, it could lead to grid stability issues. Reimers highlighted the plans for the “Hydrogen City” project in Texas that could scale up to 60 GW — while ERCOT’s all-time peak demand record is just 85.5 GW.

“The reliability issue is very significant, particularly because of how big some of these facilities are,” Reimers said. “And it’s going to take a lot of kind of creative thinking about how to deal with all of that as far as maintaining the reliability of the grid.”

Even beyond reliability issues, electricity is going to be difficult to plan for by grid operators who are ill equipped to monitor global commodity prices for different industries. Some industrial load might curtail significantly when residential air conditioning drives up the demand curve, but others might have contracts they need to meet or inflexible industrial processes incapable of responding to shifts in power prices, Reimers said.

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Treasury, DOE Issue Proposed ‘FEOC’ Rules for EV Tax Credits

As U.S. automakers pull back their plans to invest heavily in electric vehicles, claiming sales are not growing as fast as expected, the Treasury Department and IRS have issued new guidelines on the federal tax credits for EVs that could further slow sales. 

Beginning Jan. 1, EVs with any battery components manufactured or assembled by a “foreign entity of concern” (FEOC) — meaning, in this case, owned or controlled by China — will not be eligible for the $7,500 EV tax credit, according to the proposed rules. 

Issued Dec. 1, the notice of proposed rulemaking (NOPR) from Treasury and IRS would similarly prohibit tax credits for any EV containing “any critical minerals that were extracted, processed or recycled by a FEOC,” beginning in 2025. 

How to determine if an entity is a FEOC is detailed in additional proposed guidelines, also released Dec. 1, from the Department of Energy. Based on provisions in the Infrastructure Investment and Jobs Act, the guidelines define a “foreign entity of concern” as being “owned by, controlled by or subject to the jurisdiction or direction of a government of a foreign country that is a covered nation.” 

In addition to China, the U.S. has designated Russia, Iran and North Korea as “foreign countries of concern” or “covered nations.” DOE’s proposed guidelines spell out how certain terms in the IIJA should be interpreted, including “government of a foreign country,” “foreign entity,” “subject to the jurisdiction” and “owned by, controlled by or subject to the direction.”

Treasury and IRS previously issued guidelines on the EV tax credits, in December of 2022 and March of 2023, both of which were sharply criticized by Sen. Joe Manchin (D-W.Va.) as providing loopholes that would allow EVs to circumvent the domestic content provisions he wrote into the law. (See IRA’s EV Tax Credits Spark Senate Debate.) 

The new guidelines appear to be aimed at plugging those loopholes, noting that “several critical segments of the battery supply chain today are predominantly processed and manufactured within covered nation boundaries.” 

For example, a company located in but not owned by a covered nation would be considered a FEOC if the covered nation could “exercise legal control … with respect to any critical minerals that are physically extracted, processed or recycled, any battery components that are manufactured or assembled and any battery materials that are processed” in that country. 

Also, a U.S. company could be considered a FEOC if it is “sufficiently controlled” by the government of a covered nation “via the holding of 25% or more of an entity’s board seats, voting rights or equity interest … [or] via license or contract conferring rights on a person that amount to a conferral of control.” 

Manchin remains critical of the guidelines. In a statement released Friday, he said the administration is “trying to find workarounds and delays that leave the door wide open for China to benefit off the backs of American taxpayers.” 

In this case, he may have been referring to provisions in the guidelines on ‘‘non-traceable” or “low-value” battery materials “that may originate from multiple sources and often are commingled during refining, processing or other production processes by suppliers to such a degree that the qualified manufacturer cannot, due to current industry practice, feasibly determine and attest to the origin of such battery materials.” 

These low-value materials include “applicable critical minerals contained in electrolyte salts, electrode binders and electrolyte additives” and make up less than 2% of battery components, according to Treasury. The guidelines propose a transitional rule “that would temporarily exclude a specific list of identified non-traceable battery materials from the due diligence requirements of the qualified manufacturers” through 2026, to give the industry time to develop standards for tracing the low-value materials.  

The Outlook for 2024

As written by Manchin, the IRA placed limits on the EVs and EV buyers that can qualify for the law’s EV tax credits. Light-duty EV sedans can’t cost more than $55,000, while the maximum price for electric SUVs and light-duty pickup trucks is $80,000. 

EV buyers also must meet certain income requirements, earning no more than $150,000 per year for a single consumer, $225,000 for a single head of household and $300,000 for couples filing joint tax returns.  

For the full $7,500 tax credit, EVs also have to meet domestic content provisions, separate from the proposed FEOC rules. For example, in 2023, to qualify for the credit, 50% of the value of battery components in an EV must have been manufactured or assembled in North America. In 2024 and 2025, the percentage goes up to 60%, with additional yearly increases eventually rising to 100% by 2029. 

Similar requirements are in place for the percentage of critical minerals in an EV battery. These provisions already have kept many foreign-made EVs ineligible for tax credits on new EV sales to consumers. 

At present, according to DOE’s fueleconomy.gov website, for the 2023 model year, more than 20 different models of EVs or plug-in hybrids, mostly from U.S. automakers, qualify for either a $7,500 or $3,750 tax credit. For the 2024 model year, the list shrinks to 10 models.  

For the 2023 model year, Ford’s F-150 Lightning pickup qualified for a $7,500 tax credit, while the Mustang Mach-E SUV qualified for a $3,750 credit. At present, Ford has no 2024 models eligible. 

The impact on EV sales remains uncertain. The National Automobile Dealers Association reported that the U.S. has racked up more than 1 million new EV sales in 2023 — with a month still to go — the first time sales have exceeded 1 million in a single year.  

Neither Ford nor General Motors have issued public statements on the guidelines. Both companies recently paused work on new EV factories. However, on Dec. 5, GM announced the opening of 17 public EV charging stations in 13 states, which it developed in partnership with Pilot Travel Centers and EVGo. 

Both the Treasury and DOE proposed guidelines were published in the Federal Register on Dec. 4, beginning comment periods. The comment period for the DOE guidelines on FEOCs closes Jan. 3. Comments on the Treasury guidelines are due by Jan. 18. 

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Panelists Warn of Winter Weather’s National Security Risks

After multiple severe weather events threatened grid reliability in recent years, the ongoing threat of winter weather is well known. But in a webinar hosted by the American Council on Renewable Energy on Dec. 5, several speakers said the risks to one particular customer are not fully appreciated.

Planning processes “do not take Department of Defense or national security loads into account,” said Jonathon Monken, a principal at consulting firm Converge Strategies. According to the most recently available data for fiscal 2021, there were more than 6,000 energy outages at DOD installations across the U.S., he said. The potential for mission impact is significant. “As far as I know, they’re the only [grid] customer that launches nuclear missiles.”

The webinar focused on the dangers extreme weather could pose to electric reliability at military bases and other critical national security loads. The topic was timely, considering multiple reports in the past month highlighting the risk of extreme weather events to grid reliability.

NERC’s 2023 Winter Reliability Assessment, released last month, provided plenty of material for panelists, as did FERC and NERC’s final report on the December 2022 winter storms that caused widespread load shed across the Southeast U.S., released the same week. (See FERC-NERC Elliott Report Calls Winter Outages ‘Unacceptable’.) NERC’s assessment found that large portions of the North American electric grid are at risk of electric shortfalls in above-normal peak conditions. (See NERC: Grid Risks Widespread in Winter Months.)

Thomas Coleman, executive director of energy think tank SAFE’s grid security project, emphasized that the danger of military bases losing power goes beyond that of a typical business, because “each military installation is very unique” in terms of national security benefits.

Monken said part of the challenge is that “DOD is not steeped in a very deep understanding of how the [grid] works,” and base commanders in particular do not always understand the importance of “what’s happening outside of their fence line with regard to critical infrastructure.” He pointed out that 90% of DOD bases depend on commercial utilities for energy, and there are multiple areas in the country where clusters of military bases all rely on the same energy provider, creating a major common point of vulnerability.

Monken and Coleman suggested investments in transmission could help mitigate these vulnerabilities by removing some of these single points of failure. They said they hoped NERC’s Interregional Transfer Capability Study, which Congress ordered the ERO to complete by next December, would be an important step in identifying the places where transmission investments could help the most — not just for protecting national security, but with encouraging the adoption of renewable energy sources.

“Wind power in Iowa … is so much less expensive than what we’re seeing in New York and L.A. on the coasts, but we don’t really have the way to transmit those electrons to the coasts,” Coleman said.

Mark Olson, NERC’s manager of reliability assessments, said if grid planners and DOD work together, they can help understand each other’s needs and abilities. He said future studies can ensure the grid has the flexibility to always optimize energy use, rather than just avoid major catastrophes.

“We really need to understand all the unserved energy that is occurring over the span of a year … and when we can get our tools and planning processes to be able to have that kind of granular view, we’re in a much better position to be able to make sure all the critical needs are being met,” Olson said.

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Maine Ethics Commission Resolves Probe of NECEC Foes

Maine’s ethics watchdog has resolved alleged campaign finance law violations surrounding the controversial New England Clean Energy Connect project.

The two entities targeted in a probe by the Maine Commission on Governmental Ethics and Election Practices consented to a combined $210,000 in penalties in an agreement executed Nov. 29. Neither admitted liability or wrongdoing, but both agreed they should have registered as a political action committee or ballot question committee.

The NECEC line is designed to carry up to 1.2 GW of electricity from hydro facilities in Quebec to Massachusetts. It has faced multiple challenges since it was first proposed in 2017, including a citizen referendum seeking to block construction. Avangrid resumed construction in August 2023, four months after winning a key court ruling. (See New England Clean Energy Connect Wins Court Battle.)

Two separate but related cases arising from the fight over NECEC went before the Maine ethics commission, one involving Clean Energy for ME LLC (doing business as Stop the Corridor), the other involving Alpine Initiatives LLC.

Advocates for NECEC complained in January 2020 that Stop the Corridor should have registered as a political action committee because it engaged in financial activities to support petitioning for a citizen initiative on the project.

Stop the Corridor challenged the ethics probe, dragging out the time frame.

The commission ultimately gathered 6,339 pages of documents and conducted five interviews to show the involvement of Stop the Corridor in efforts to block NECEC or impede progress on it.

The commission concluded Stop the Corridor qualified as a ballot action committee, should have registered with the commission and should have filed campaign finance reports.

Among its other findings, the commission discovered Stop the Corridor made payments to Alpine Initiatives. A consultant transferred $160,000 to Alpine, which then donated $150,000 to the Maine Democratic Party, the leaders of which were viewed as more likely to oppose NECEC.

The public did not learn of the source of this pass-through contribution because it was reported only in Alpine’s name.

The commission began to investigate Alpine in July 2021, concluded Alpine through its actions did qualify as a political action committee and said it should have registered as such and filed a campaign finance report.

Alpine agreed to pay $160,000 in civil penalties, and Stop the Corridor agreed to pay $50,000.

Supporting documentation posted in the Spot the Corridor case shows only one source of money: $95,726 provided by NextEra Energy Resources from August 2019 to March 2020.

NextEra operates the 1.24 GW nuclear power station in Seabrook, N.H., and through the years, the Florida-based utility has run interference on the NECEC project, which would provide an influx of low-cost clean energy competing with the emissions-free output of Seabrook.

A late 2021 report indicated NextEra spent $20 million to influence public opinion against NECEC in the runup to the Maine referendum.

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Hydro Fuels Uptick in CAISO Exports, Market Monitor Reports

CAISO’s net energy exports have increased sharply this year, with imports being displaced by increased output from California’s hydroelectric and natural gas resources, the ISO’s Department of Market Monitoring (DMM) said Dec. 1.

Speaking during a call to discuss the DMM’s market report for the first and second quarters of 2023, Amelia Blanke, the department’s manager of monitoring and reporting, said the trend reflected the reduction in imports and a “tremendous amount” of exports coming out of CAISO into the Western Energy Imbalance Market, flowing into the Southwest and Northwest, with substantial volumes going into BC Hydro’s territory.

The flows tended to reverse during CAISO’s net load peak hours, she said — except for the exports into BC Hydro. Most of the imports into CAISO came from the Desert Southwest.

While the DMM hasn’t released the Q3 report, Blanke noted the quarter saw “absolutely unprecedented levels of exports.”

The Monitor highlighted the significant role hydro played for California this year.

“The weather pattern that prevailed coming into 2023 is one that resulted in relatively high rainfall and snowfall in the CAISO BA,” Blanke said. There was less precipitation in the Northwest, though, resulting in a relative shift of hydroelectric output between the Northwest and CAISO’s footprint.

The strong hydro equated to low prices during many intervals in Q1 and Q2. Those quarters typically see the highest levels of hydropower in combination with solar and wind, increasing the frequency of intervals with very low — and even negative — prices.

Blanke also highlighted the new resources that have been added to the CAISO fleet, including a “very large penetration” of battery resources.

The year began with high natural gas prices, which declined across the system in Q2, bringing wholesale electricity prices down as well, Blanke said.

Q1 electricity prices average about $97/MWh in the day-ahead market, $93/MWh in the 15-minute market and $87/MWh in the five-minute market. Q2 saw much lower prices across the board, though there was still a persistent gap between the five- and 15-minute markets, and lower 15-minute prices on average compared with the day-ahead, boosting the profitability of virtual supply.

“Historically, that’s been due in large part to a consistent imbalance conformance for the CAISO BA,” Blanke said, referring to the process by which the ISO dispatches units up and down to match grid conditions to prevent frequency deviations.

While CAISO has assumed that it can rely on flexible ramping resources to reduce the need for imbalance conformance, that did not hold for most of the period in covered by the analysis.

But CAISO did change some operational practices in the middle of Q2 to reduce the need for conformance.

“It was the first time in many years that our quarterly metrics show a reduction in imbalance conformance,” Blanke said.

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Former Ohio PUC Chair Charged with Bribery

Former Public Utilities Commission of Ohio Chair Sam Randazzo has been indicted on several bribery charges alleging that FirstEnergy paid him over $4 million before his appointment in 2019 with the understanding that he would act in the company’s interest. 

“Today’s indictment outlines an alleged scheme in which a public regulatory official ignored the Ohio consumers he was responsible for protecting, instead taking a bribe from an energy company seeking favors,” FBI Cincinnati Special Agent in Charge William Rivers said in an announcement of the charges. “The FBI will remain vigilant in investigating allegations of corruption at all levels of government and hold those who violate the law accountable for their actions.” 

Randazzo served as commission chair from April 2019 until November 2020, when he resigned following an FBI raid on his home in Columbus. He was indicted on Nov. 29 of this year with two counts of travel act bribery, one count of wire fraud, five counts of making illegal monetary transactions, two counts of honest services wire fraud, and one count of conspiring to commit travel act bribery and honest services wire fraud. 

FirstEnergy spokesperson Jennifer Young said the company cannot comment on the allegations; however, it has sought to remedy past issues. The company agreed to pay a $230 million fine in July for allegedly spending $61 million in bribes, campaign contributions and advertising for the election of former Ohio House Speaker Larry Householder, who supported a bill providing $1.5 billion in subsidies for the company’s nuclear plants. (See DOJ Orders $230 Million Fine for FirstEnergy.) 

“While we can’t comment on the actions taken by the U.S. Attorney’s Office for the Southern District of Ohio, FirstEnergy has taken significant steps to put past issues behind us. Today we are a different, stronger company with a sound strategy and focused on a bright future,” Young said in an email. 

According to the indictment, Randazzo solicited a $4.3 million payment from former FirstEnergy CEO Charles Jones and Michael Dowling, former senior vice president of external affairs, in late 2018 in exchange for seeking a position on the commission to aid the company. After meeting with two executives at his home in December, Randazzo allegedly arranged the payment, which was made on Jan. 2, 2019, and the executives lobbied for his appointment. The indictment included messages between the executives and Randazzo. 

“We’re gonna get this handled this year, paid in full, no discount. Don’t forget about us or Hurricane [Jones] may show up on your doorstep! Of course, no guarantee he won’t show up sometime anyway,” one executive messaged Randazzo, accompanied by an “image of a venomous snake protruding from a hurricane.” 

“Made me laugh — you guys are welcome anytime and anywhere I can open the door. Let me know how you want me to structure the invoices. Thanks,” Randazzo responded, according to the indictment. He added, “I think I said this last night, but just in case — if asked by the administration to go for the chair spot, I would say ‘yes.’” 

After his appointment in April 2019, the indictment shows further messages between the executives and Randazzo discussing how he could aid the company in ensuring the passage of House Bill 6, which provided subsidies for the company’s nuclear plants, and help a financial issue they referred to as the “Ohio 2024 hole.” 

A series of messages between executives said, “Stock is gonna get hit with Ohio 2024. Need Sam to get rid of the ‘Ohio 2024 hole.’” 

Another executive responded, “I spoke with Sam today. Told me 2024 issue will be handled next Thursday.” The announcement of the charges stated that the commission issued an order the following Thursday alleviating the issue. 

In another message sent on March 4, 2020, an executive recounted being told by Randazzo that he would help with an issue the company was facing but needed time because of discussions circulating among commission staff about his allegiances. 

“He will get it done for us but cannot just jettison all process. Says the combination of overruling staff and other commissioners on decoupling, getting rid of SEET [significantly excessive earnings tests] and burning the DMR [distribution modernization rider] final report has a lot of talk going on in the halls of PUCO about does he work there or for us? He’ll move it as fast as he can. Better come up with a short-term workaround,” the message said. 

The indictment also alleges Randazzo embezzled at least $1 million from an industry group representing large industrial energy users in Ohio through his consulting firm Sustainability Funding Alliance of Ohio going as far back as 2010. When the group received settlement payments to be distributed among its membership, it said Randazzo used his control of its bank accounts to divert a portion of the payments to a fictitious member he created. He allegedly attempted to conceal the embezzlement by sending the funds through multiple bank accounts and concealing the amount the group received. 

The announcement states that Randazzo could face 20 years in prison if convicted. 

“Public officials — whether elected or appointed — are tasked with upholding the highest level of integrity in their duties and responsibilities. Such service to the public must be selfless, not selfish,” U.S. Attorney Kenneth Parker said in the announcement. “Through the indictment unsealed today, we seek to hold Randazzo accountable for his alleged illegal activities.”

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4 Things Cathy Zoi Learned About the Car-charging Business as Head of EVgo

When Cathy Zoi joined charging company EVgo as its CEO in 2017, only a couple of electric vehicle models were for sale, and their range was limited to about 70 miles.

Founded in 2010 as a unit of NRG Energy, EVgo had only 50 employees and no revenue model. By the time Zoi retired from the company in November, it had about 300 employees, and more than 40 EV models were for sale in the U.S., many with a range over 300 miles. Although EVgo, now owned by LS Power, has yet to earn a profit, Zoi is bullish on the industry’s future.

“Now, there’s not a car company that is not investing significantly in electrifying its offerings — to the tune of a trillion dollars globally,” she said in an interview with Resources for the Future CEO Richard G. Newell on Nov. 29 as part of its Policy Leadership Series of webinars. “That is a once-in-a-century transformation of a major sector that is happening present tense. … I did not anticipate that amount of commitment by private capital would happen so quickly. And that’s really, really heartening.”

The industry’s biggest challenge now is creating the charging infrastructure needed to make new converts confident they won’t get stranded without power, Zoi said. “What is probably underestimated by everybody was the complexity of building a new ecosystem,” she said.

Zoi told Newell and an audience in D.C. she is unfazed by reports of automakers pulling back on their EV plans.

Former EVgo CEO Cathy Zoi spoke with Resources for the Future CEO Richard G. Newell during a webinar Nov. 29. | Resources for the Future

“I think it’s an ephemeral thing,” she said. “If they’re pulling back, they’re pulling back from a slope that was like this,” she said, pointing steeply upward, “to a slope that was like that” — less steep. “It’s still very, very fast compound annual growth rates. You know, maybe the new model was going to come out in Q1 next year, [and] it’s going to come out in Q3 instead.”

Nor is she concerned that a Republican president or Congress will seek to halt EVs’ growth, saying elected officials will not want to lose the jobs resulting from the EV and battery factories that have been announced since the Inflation Reduction Act and Infrastructure Investment and Jobs Act.

“There were elected members of office in this town that might have been hostile to clean energy because it’s environmental. And yet, their constituents — the farmers of Iowa — are making more money out of having wind turbines on their property than they are out of the corn they’re selling and the soybeans they are growing,” she said.

“On the consumer side, I have not talked to a driver who has experienced an EV and doesn’t adore it,” she continued. “And this is why you’ve got the market growing in Texas, in Florida, as quickly as it is. They are really great products. They’re fun to drive; it’s a better-performing technology. And you know, people say, ‘I love not having to go to a gas station anymore.’”

Reality check: While EVs have fewer moving parts than internal combustion engine (ICE) vehicles, and thus should need fewer repairs, Consumer Reports says EV owners continue to report far more problems than owners of conventional cars or hybrids. Many drivers of EVs other than Teslas have complained about nonworking chargers. S&P Global Mobility says half of EV owners — excluding those with Teslas — go back to ICE vehicles as either a replacement car or a second vehicle for their household.

Scaling Up

Zoi is optimistic the industry can meet the Biden administration’s target of making EVs half of new car sales by 2030.

The U.S., which has 30,000 fast chargers, will need 200,000 to 300,000 by 2030, she said.

EVgo — which has 3,400 DC fast-charging stalls in operation or under construction at more than 950 locations nationwide — has identified about 10,000 sites for additional chargers, assuming available capital.

“So I can tell you on the charging side, we’re up to the task. … But as I mentioned, it’s a whole ecosystem,” she said. That means utilities must upgrade distribution grids, and carmakers must transform from ICE vehicles to EVs. “So it’s ambitious, but achievable.”

Below are four things Zoi learned in her time at EVgo, with implications for the industry:

  1. People like to top off at the store even if they have home chargers.

The demand for DC fast chargers has grown faster than expected, Zoi said.

“We thought the whole idea was if you can charge at home, you’re only going to charge at home. Turns out that’s not the case. If you have a charging station conveniently located at your grocery store, people are topping up there. It’s a good parking space. [They will] spend five bucks while they’re going to get their weekly groceries.”

Another factor: “The … EVs that are being sold, [their] batteries are bigger, and they’re heavier. And so they’re a little less efficient … than we originally forecast, which means that the folks need to fill up more frequently.”

EVgo’s national use rate — the percent of time a charger is in use — is more than 15%, with some stations, such as one in Brooklyn, in use more than 50% of the time.

  1. Only some customers are price responsive.

The company has seen a wide range of price elasticity as it has adopted time-of-use pricing.

“Some of our drivers are very price responsive, like our rideshare drivers. Others do not care at all,” she said.

After joining the company, Zoi imposed a rule that it should make a profit on every kilowatt-hour dispensed, which required it to abandon its single national price.

“In order to not lose money in San Diego … we had to double our rates,” she said. “And the demand dipped a little bit for a couple of weeks, and then it went right back up.”

The average out-of-pocket spend per charging session is about $10, not including monthly subscription fees of up to $13. “So it’s two Starbucks things, right? It’s just not that much money. And you come out and you’ve got electrons in your car, and off you go, and you feel great.”

  1. It takes a long time to plug into utility distribution lines.

It takes between six and 18 months from site identification to having the station go live, Zoi said, far from hopes of a six-month turnaround.

“Because we’d like to build stations with at least 10 stalls, now it almost always requires a service upgrade, which means that the utilities buy a transformer … and the site host has to allow the utility access to the site. … It turns out that landlords — we don’t own the land — don’t like utilities tromping on their [property]. And then at the back end, in order for a station to go live, the utility has to come and do the final inspection before we enter. And we are often in the queue for something like six, eight, 12 weeks until they show up.”

EVgo is trying to shorten the timeline by providing utilities with its siting plans for the next 18 to 24 months. “We say this is where we’d like to build … and sometimes they say, ‘Oh my gosh, don’t build here, because we’re really constrained,’ or ‘We’re not going to upgrade that local connector until 2027.’ But they usually say, ‘Great. Now we’ll order transformers for all these locations.’

“As we get into larger, heavy-duty trucks being electrified, those are going to be megawatt[-scale] charging stations that need to be integrated into utility plans — like in a big way.”

  1. Chevron needs to improve its menu.

The biggest share of EVgo’s $35.1 million in revenue in the third quarter — up 234% year-over-year — was from retail chargers. It has partnerships with shopping center owners; Target; Chase Bank; Lowe’s; supermarkets Kroger, Safeway and ShopRite; and convenience store chains Sheetz and Wawa.

“We like to build where people are anyway. … So you can just plug in, go do something else and come back, and the car’s charged,” Zoi said.

It is also building depots with 20 or 30 stalls for fleet customers. And on highways, it has a partnership with Pilot Flying J truck stops for “white label” chargers owned by Flying J and built and maintained by EVgo.

And it’s experimenting with gas stations through 14 Chevron locations in California.

“I always used to joke with them … ‘You guys are going to need to improve the quality of your coffee if you’re going to get people to want to stay. Because we also partner with Whole Foods. And would you rather [hang] at Whole Foods, or [eat] beef jerky at Chevron?’”

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OPSI Urges Reliability Coordination Between PJM, States

PJM is taking a reactive stance in addressing the evolving grid, impacting ratepayers and reliability in a way that could be addressed by closer coordination with member states, the Organization of PJM States Inc. (OPSI) has told the RTO’s Board of Managers. 

OPSI leveled its contention in a Nov. 28 letter that said increases in both load and generation retirements are leading to reliability risks that require major “immediate need” transmission expansions with little time for exploration of alternatives.  

The group said the $5 billion Regional Transmission Expansion Plan (RTEP) project PJM presented its Transmission Expansion Advisory Committee (TEAC) on Oct. 31 highlights the “negative impact of siloed, reactive planning” that states have been concerned about for years. The TEAC is scheduled to discuss the proposal again on Nov. 5, and the board may consider approval in the coming weeks. (See PJM Recommends $5B in RTEP Transmission Projects.) 

“The reliability challenges that have recently presented themselves, coupled with the significant cost impact on customers associated with addressing these challenges, have amplified our concern that factors outside the transmission planning process may contribute to the high cost of transmission upgrades and warrant attention to ensure these costs do not become an undue burden to retail consumers,” the letter said. “As such, the OPSI board requests your support in working hand-in-hand, with the help of our respective staffs, to better understand the issues and explore solutions, tools and reforms that may more timely and cost effectively ensure grid reliability.” 

In addition to its concerns with the transmission planning process, OPSI said the need for reliability-must-run (RMR) contracts to keep generators online past their deactivation date threatens to saddle ratepayers with a second round of expenses on top of transmission needed to accommodate the retirement. 

“These concerns range from transmission projects designated as ‘immediate need,’ even though many of them have remained uncompleted past their required in-service dates, to multiyear reliability-must-run agreements that can cost customers hundreds of millions of dollars per year, all while the region waits for even costlier transmission upgrades,” OPSI wrote. “What’s more, the costs of these RMR agreements are not factored in selecting the most overall cost-effective reliability solutions. As such, the PJM board should not read this letter as a reaction to a single set of RTEP projects, but rather a culmination of concerns that is only growing and that has resulted in our resolve to timely seek solutions through our boards working together.” 

The letter was signed by 13 of the 14 OPSI member commissions, with only the Virginia State Corporation Commission voting in opposition. The Virginia agency did not respond to a request for comment on the letter. 

The letter notes that PJM has undertaken efforts to address the reliability concerns it has identified over the past year, including an overhaul of the capacity market through the critical issue fast path process and a long-term transmission planning working group, but OPSI said more work is needed to explore holistic solutions to grid reliability. 

‘Eye-popping’ Transmission Needs

Maryland Public Service Commissioner Michael Richard, who also serves as OPSI treasurer, said state policies have a central role to play in promoting the clean energy transition while maintaining reliability in the most cost-effective manner.  

Richard said if the states were brought on board with planning the response to data center growth in Northern Virginia and the retirement of the Brandon Shores generator outside Baltimore, both of which contributed to the $5 billion RTEP project, recent Maryland legislation requiring the development of 3 GW of storage could have provided a non-transmission solution at a lower cost for ratepayers. (See Maryland Legislature Ends Session with Big Wins for Clean Energy.) 

“There are things that we can do at the state level, at the distribution level, to help address and take action regarding demand and some of the distributed energy resources that we’re working to bring on,” he said. “We have a lot of storage projects in the queue and if we just had more visibility into where the reliability concerns are, it’s very possible we could tap some of those storage resources to address some of the concerns PJM has.” 

While Richard said the scale of the transmission PJM has proposed was “eye-popping,” he thinks it reflects longstanding issues the states have had with PJM’s planning processes. He said the move to a cluster approach to studying generator interconnection requests marks a significant improvement, but work remains to improve PJM’s governance and create opportunities for collaboration with the states. 

“We do have good dialogue between OPSI and PJM and the states. I think we have good discussions, so I’m hopeful and again this letter is presented as an invitation, a request to work collaboratively with PJM. I know they tell us they take OPSI dialogue very seriously and so I expect they will do so with this letter,” he said. 

Morris Schreim, senior advisor to the Maryland Public Service Commission, said transmission is looked at as the last solution for meeting demand when the market signals don’t produce an adequate supply of generation. He said PJM should be seeking innovative ways to improve the interconnection process to ensure new resources aren’t held up, consider how federal policy around electrification and generation development can be incorporated, and work with states to find solutions on the distribution side of the grid. He said the discussions in PJM’s Deactivation Enhancements Senior Task Force to streamline the process for transferring capacity interconnection rights (CIRs) from a retiring resource to a replacement is a promising pathway. 

“They have an opportunity to come up with creative and innovative ways of making the parts work together,” he said. 

Kentucky Public Service Commissioner Kent Chandler, who also serves as OPSI president, said he hopes the letter can open avenues for his commission to work closer with PJM to find new ways of maximizing reliability at lower costs. 

“My overarching concern is that the PJM region is engaging in too much reactive engineering, and are just calling it planning,” Chandler said in an email. “At the same time, the region is too siloed at addressing needs, such as the chasm between supplemental and baseline planning. Customers can’t afford siloed, reactionary investments in the [bulk electric system], and doing so likely results in a more expensive and less reliable system. I look forward to working with PJM on how we can address this.” 

‘A Real Frustration’

Greg Poulos, executive director of the Consumer Advocates of the PJM States, said there’s widespread agreement among advocates on many of the issues raised in the letter. He said the advocates are concerned about the “extremely significant” costs ratepayers will face should the RTEP projects be approved and are frustrated with the short timeline between when PJM selects projects and seeks board approval. 

“There’s not many things that happen in such a short time period as this $5 billion project with this little input from stakeholders,” Poulos said. 

One of the chief reasons generator retirements such as Brandon Shores require extensive transmission development is the compressed Base Residual Auction schedule, which causes generators to receive the price signals to retire much closer to the start of the delivery year, Poulos said.  

PJM’s markets were designed to have generators seek deactivation three years in advance, but when that period is shortened, the amount of time to plan and construct solutions is likewise limited, increasing the odds of needing a costly RMR contract. Poulos anticipates the next major generation retirements also likely will provide little to no warning and come with even larger costs. 

“These decisions about when resources retire, you would think would be made three years and 90 days in advance of auctions. … You’ve cut that time down and put the pressure [on consumers] to address the situations and consumers to pay for situations,” he said. “One of the consequences is having these $5 billion retirement issues that are immediate needs, so we get less competition. It reduces the solutions when these things come on so fast. We need to really be thinking comprehensive long-term planning.” 

Poulos said consumer advocates also are frustrated about the lack of discussions around increasing the scope of PJM’s long-term planning. The Long-Term Regional Transmission Planning Workshop started this year addresses projects only of 345 kV or higher, which Poulos said limits its scope to a small fraction of the projects PJM might consider. 

“That long-term regional process is not aimed at the entire picture of how we go forward and that’s a real frustration,” he said. 

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FERC Approves Texas RE Standards Process Changes

FERC on Dec. 1 approved a set of updates to the Texas Reliability Entity’s Reliability Standards Development Process (RSDP) intended to give more flexibility to the regional entity’s Member Representatives Committee to develop standards and align the document more closely to NERC’s Standard Processes Manual (SPM) (RR23-1).

NERC filed the RSDP changes with FERC in May, after the RE’s Board of Directors approved them at its quarterly meeting in February. (See “Regional Standards Process Approved,” Texas RE Board/MRC Briefs: Feb. 8, 2023.) The RSDP defines the process for adopting, approving, revising and retiring Texas RE’s regional standards, as well as for creating a regional variance to a NERC standard.

The approved changes will affect all 10 sections in the current RSDP to varying degrees, with most of the revisions in the first four sections. These comprise the introduction (Section 1), elements of reliability standards (Section 2), roles in the standard development process (Section 3) and the development process itself (Section 4).

In Section 1, Texas RE will merge the background section of the current RSDP — which “requires regional reliability standards to support one or more of the NERC reliability principles and to be consistent with the NERC market principles” — with the introduction. Additional revisions to this section add principles for standards development and assign the task of determining who may participate in standards development to the RE’s Reliability Standards Manager.

Next, Texas RE will move language from one of the current RSDP’s appendices to Section 2, adding references to NERC’s 10 Benchmarks of an Excellent Reliability Standard and changing terminology to be consistent with the SPM.

New language in Section 3 will specify that the MRC “may undertake reviews of [FERC] orders and coordinate with NERC in the development of NERC’s annual reliability standards development plan.”

Revisions to Section 4 require Texas RE to follow NERC’s evaluation procedure when developing new regional standards, create “distinct process steps” for creating standard authorization requests (SARs) and add a requirement for the MRC to be notified when a SAR is submitted. Public comment periods for SARs have been lengthened from 15 days to 30; comment periods for draft standards were extended from 30 days to 45, with a ballot in the last 15 days; and the MRC will now be required to meet at least once per quarter.

Additional changes to Section 4 include organizational updates removing language requiring standard drafting teams to assess the impact of a SAR on neighboring regions and creating more options for obtaining feedback on draft standards. The revisions also add voting positions, consolidate language and provide flexibility regarding the termination of unsuccessful projects and procedures if a draft standard does not pass industry ballot.

Updates to Sections 5 to 10 provide for regional reliability standards to be “considered for review at least every five years,” instead of requiring a review as is currently the case; list information that SARs must provide to the MRC; give reasons the MRC can reject requests for interpretation of regional standards; update the appeals process; and outline a method for conducting field tests that is consistent with NERC’s SPM.

Public Citizen Opposes Language on Markets

FERC received only one filing opposing the changes, from Public Citizen.

The advocacy group objected to language in the revised RSDP requiring reliability standards to “accommodate competitive electricity markets” on the grounds that market considerations are outside the ERO’s purview. It requested that any references to competitive markets be removed from the document.

In response, NERC defended the language, citing the Federal Power Act’s requirement that FERC “not defer [to the ERO] with respect to the effect of a standard on competition” and the commission’s order that proposed standards should have “no undue negative effect on competition.” NERC also observed that nearly identical language was already in the previous version of the RSDP, albeit in a different section.

FERC said Public Citizen’s request was “outside the scope of the instant proceeding” while echoing NERC’s observation that the proposed revisions “do not substantially differ from” previous versions of the RSDP. As a result, the group’s objections were rejected, and the new RSDP was approved, effective immediately.