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November 15, 2024

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FERC Upholds MISO Ban on Renewables Supplying Ancillary Services

FERC has reaffirmed that MISO can exclude renewable resources from providing ancillary services in its markets.

The commission rejected the Solar Energy Industries Association’s request for rehearing on two related FERC dockets allowing MISO to block renewable energy’s participation in its ancillary services market (ER23-1195-002). The American Clean Power Association, Clean Grid Alliance, Natural Resources Defense Council, Fresh Energy, Union of Concerned Scientists and Sierra Club joined SEIA on one of the two requests for rehearing.

Dec. 19’s denial continues a pattern of FERC insisting the output from renewable energy isn’t on equal footing with that of traditional resources because pervasive transmission congestion keeps renewables’ ancillary services from being economically deliverable to market. (See FERC Blocks Solar Group’s Contest of MISO Ban on Renewable Ancillary Services; FERC: MISO Can Ban Intermittent Resources from Providing Ramp.)

The group of clean energy groups argued FERC erred in its original judgment because it extended the exclusion to hybrid resources.

The commission disagreed. It said the arguments that hybrid resources have distinct characteristics from standalone wind and solar resources “lack specificity and are not sufficient to support an undue discrimination claim.”

“SEIA has not demonstrated that hybrid resources … will not be subject to the same deliverability issues MISO has identified for standalone wind and solar,” the commission said.

FERC pointed out that the MISO tariff allows hybrid resources to register their wind or solar portion and on-site storage together as a single dispatchable intermittent resource or separately in the markets.

The commission also said the clean energy groups did not argue on rehearing that standalone wind and solar resource are inappropriately barred from supplying ramping needs. FERC said the groups might now be hoping for a separate market designation for hybrid resources.

“To the extent that [the] clean energy coalition now seeks new market participation rules for ‘integrated hybrid sources,’ such a challenge is outside of the scope of this … proceeding,” FERC wrote.

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DOE Announces $890M in IIJA Funds for CCS Demonstration Projects

The Department of Energy is preparing to award up to $890 million to three carbon capture and sequestration (CCS) demonstration projects located at existing natural gas- and coal-fired power plants, with the goal of avoiding up to 7.75 million metric tons (MMT) of carbon dioxide emissions per year.

Announced on Dec. 14, the three projects are the first to be selected as part of DOE’s Carbon Capture Demonstration Projects Program, with $1.7 billion from the Infrastructure Investment and Jobs Act to fund at least six CCS projects at both power plants and industrial facilities that do not produce power.

According to the funding announcement, originally issued in February, DOE was looking for projects that would provide “transformational domestic, commercial-scale, integrated CCS demonstration … designed to further advance the development, deployment and commercialization of technologies to capture, transport (if required) and store CO2 emissions.”

The three projects selected are:

    • The Baytown Carbon Capture and Storage Project in Baytown, Texas, near Houston, is a natural gas, combined cycle plant, owned by Calpine, and is slated to receive up to $270 million. The CCS technology to be used has been developed by Shell and would sequester the captured CO2 in underwater saline aquifers on the Gulf Coast. The project could use a greywater cooling system that recycles wastewater and would sequester an estimated 2 MMT per year. The primary off-taker for the power produced with CCS would be Covestro, an industrial manufacturer of plastics.
    • Project Tundra, located near Center, N.D., near the state capital of Bismarck, would use Mitsubishi CCS technology to capture up to 4 MMT of CO2 at the Minnkota Power Cooperative’s Milton R. Young coal-fired power plant. The CO2 would be stored in “saline geologic formations” sited beneath or near the power plant. The project could receive up to $350 million in federal funds.
    • The Sutter Decarbonization Project in Yuba City, Calif., another Calpine natural gas combined cycle plant, would use yet another CCS technology developed by Ion to sequester up to 1.75 MMT of CO2 per year. According to DOE, the project also would be the first in the world to use an air-cooling system, rather than water, responding to “a critical concern of the local community and an imperative to further deployment of CCS in the arid Western U.S.” The pipeline for the project would run within or parallel to an existing natural gas pipeline right of way. Federal funding could be up to $270 million.

None of the CO2 captured by the projects would be used for enhanced oil recovery, in which captured CO2 is pumped back into low-producing oil wells to push out more oil. Awardees are required to provide at least 50% of project costs, according to the funding announcement.

DOE is funding three CCS demonstration projects at power plants in California, North Dakota and Texas. | DOE

CCS Normalized?

Immediate reactions from awardees and CCS industry groups framed the projects as critical for the U.S. to reach its goals for greenhouse gas emission reductions.

“We’re grateful that the Department of Energy recognizes the importance of developing carbon-capture systems and is positioning the United States to be a leader in the advancement of this critical clean energy technology,” Minnkota CEO Mac McLennan said in a statement. “Innovation is our path forward through the energy transition.” Project Tundra could “help pave the way toward a future where electric grid reliability and environmental stewardship go hand in hand.”

Citing Baytown’s ability to provide firm, dispatchable and “non-duration-limited” power, Caleb Stephenson, Calpine executive vice president of commercial operations, said similar natural gas plants “will be part of our energy infrastructure for the foreseeable future, and now with CCS technology, we can decarbonize them.”

Baytown and the Sutter Decarbonization Project are part of Calpine’s pipeline of 11 CCS projects, according to DOE.

Jessie Stolark, executive director of the Carbon Capture Coalition, hailed DOE’s choice of “geographically diverse projects [that] will demonstrate best-in-class methods to capture carbon at various power generation settings … providing further insight into the continued development and deployment of carbon capture at this critical juncture of climate mitigation.”

Stolark and others point to reports from the International Energy Agency and the U.N. Intergovernmental Panel on Climate Change, both of which have said carbon capture will be essential for the world to cut emissions and limit climate change to 1.5 degrees Celsius.

While acknowledging that CCS and other carbon-management technologies are not “a silver bullet” for reducing emissions, Stolark said they should be part of a broader set of solutions and receive “sustained legislative and regulatory support.”

DOE estimates the U.S. will need to capture and sequester between 400 million and 1.8 billion MT of CO2 annually to meet President Joe Biden’s target for economywide net-zero emissions by 2050. But carbon sequestration projects require a special permit from EPA to inject carbon into geologic formations, such as caverns or aquifers needed for permanent storage. As of Dec. 8, EPA is considering 61 applications for these Class VI permits; it has issued only two.

Getting to ‘Go/No-go’

Speaking during an online briefing Dec. 18, Kelly Cummins, acting director of DOE’s Office of Clean Energy Demonstrations (OCED), said that, as is the case with most DOE award selections, CCS projects in this first round of awards are not guaranteed federal funding. Rather, they will begin negotiations with the department for a phased-in release of the money over four planning and development stages, she said.

“During the negotiations process, OCED will discuss how the selectees can make their projects more robust from a technical, financial and community benefit standpoint,” she said. As part of any potential award, “OCED and the project teams will enter into a cooperative agreement, which gives OCED substantial involvement throughout the public-private partnership.”

Between each phase of planning and development, “DOE will assess the project’s progress, and we’ll make a decision about whether the project should receive additional funding. We call this a ‘go/no-go’ review,” she said.

Actual installation and construction of the projects could take three to six years, Cummins said, with ramp-up and operation adding an additional two to four years to timelines. Projects also may have to undergo an environmental review under the National Environmental Policy Act.

Each project also must have a community benefits plan that may include labor agreements with unions and training programs and internships for local students. Under Biden’s Justice40 Initiative, 40% of project benefits have to go to low-income, disadvantaged or underserved communities.

The Sutter Decarbonization Project, for example, is negotiating a project labor agreement and has set “a 10% diverse supplier spend goal,” targeting small businesses owned by women and people of color, according to DOE. The Lawrence Berkeley National Laboratory would serve as an independent third party to monitor the project’s implementation of its community benefits plan.

Next steps will include a series of virtual community information sessions for each project in early January, Cummins said: Project Tundra on Jan. 9, Baytown on Jan. 10 and Sutter Decarbonization on Jan. 11.

A second round of funding is expected “in the future,” Cummins said, to meet the requirements in the IIJA. The law calls for the CCS demonstrations projects to be located at two natural gas-fired plants, two coal-fired plants and two industrial sites.

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FERC’s CIP Report Finds Fewer Issues Again

FERC staff’s audits for compliance with NERC’s Critical Infrastructure Protection (CIP) standards this year produced the fewest recommendations for improvement yet, indicating that North American utilities’ cybersecurity practices largely meet the standards’ mandatory requirements. 

As in previous years, however, the commission identified several aspects in which registered entities’ compliance needs improvement, as well as voluntary actions to improve cybersecurity protections in general. 

FERC has been performing the CIP audits since 2016. Each audit covers the preceding fiscal year, which runs from Oct. 1 to Sept. 30. Audits comprise “data requests and reviews, webinars and teleconferences, and virtual and on-site interview sessions,” FERC said in the audit report. 

Auditors spoke with entities’ subject matter experts, along with employees and managers responsible for CIP compliance tasks, and watched as personnel demonstrated the utilities’ operations. Audits also included reviews of relevant documentation, remote field inspections and observations of relevant cyber assets in operation. Staff from NERC and the regional entities participated in the audits alongside FERC personnel. 

Details about the audits, such as how many audits were performed and which utilities were selected for examination, were not disclosed. 

This year’s report included four lessons learned from the audits, relating to seven specific CIP standards. This is the fewest lessons learned since the commission began issuing the annual reports. Last year’s report produced five lessons learned, after 14 the previous year. (See FERC Report Finds CIP Issues Declining.) 

The first lesson concerns identification and categorization of grid cyber systems and associated cyber assets. Requirement R1 of CIP-002-5.1a (Cybersecurity — BES cyber system categorization) mandates that registered entities identify cyber systems and assets whose “loss, compromise or misuse … could [impact] the reliable operation of the” electric grid. The report’s authors observed such identification “forms the foundation of the CIP … standards [because] miscategorization … can lead to the application of inadequate cybersecurity controls, or no controls at all.” 

Utilities’ procedures for identifying applicable cyber systems were “generally … strong,” FERC staff found; however, auditors did find some cases in which systems were not categorized properly. In particular, some entities did not correctly classify hypervisors — software used to operate virtual machines — by the highest impact level of the virtual assets they manage. In addition, medium-impact cyber systems at some utilities were not identified as critical to derivation of interconnection reliability operating limits and associated contingencies. 

Incident Notification Challenges

FERC’s next lesson learned relates to cybersecurity incident notification, the subject of several CIP standards. 

CIP-008-6 (Cybersecurity — incident reporting and response planning) requires entities with medium- and high-impact cyber systems to notify the Electricity Information Sharing and Analysis Center (E-ISAC) in the event of a reportable cybersecurity incident, as identified in the standard. CIP-003-8 (Cybersecurity — security management controls) mandates that entities with low-impact cyber systems determine whether incidents at such systems compromised or disrupted reliability tasks and to notify the E-ISAC if so. 

The commission found several incidents that entities did not properly identify or report to the E-ISAC. In one case, the entity discovered malware on a cyber system that it did not report as required by its incident response plan because the entity determined it was not compromised. 

Another entity found malicious code on an installer in a cyber system’s recycle bin, a situation not covered by its incident response plan. The utility decided its system had not been compromised and no report was necessary; however, FERC staff said the malware still had “potential to perform malicious actions” and CIP-008-6 required such incidents to be reported. 

FERC’s report emphasized that unreported incidents make it harder for grid operators to identify security risks, leading to compromised situational awareness for all entities. Recommendations included “developing more holistic criteria” for incident identification and improving the processing and investigation of CIP-related events. 

The next lesson involves restriction of inbound and outbound access permissions as required in CIP-005-7 (Cybersecurity — electronic security perimeters). Requirement R1 mandates that utilities deny all access attempts that lack such permission. 

Audit staff found that the standard was “generally” followed, but in some cases, entities either did not restrict access permissions, did not document the reason for granting access or both. Staff observed that “allowing [traffic] throughout the network without valid reason and oversight could lead to possible security compromise.” Recommendations included reviewing access configurations on a quarterly basis to ensure access is denied by default and all exceptions are documented. 

Finally, the auditors noted that some entities’ supply chain risk management plans had not been updated with responses to identified risks in contracts negotiated with vendors after the effective date of CIP-013-1 (Cybersecurity — supply chain risk management). 

While the standard (which has since been replaced with CIP-013-2) does not require entities “to renegotiate or abrogate existing contracts,” FERC staff noted that inadequate risk assessment can affect reliable grid operations if entities use vulnerable products. Staff urged entities to review contracts that have not already been examined for potential risks — whether negotiated before or after the effective date of CIP-013-1 — and ensure that their plans address such risks. 

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Maryland Adopts California’s Advanced Clean Trucks Rule

Maryland last week became the 10th state to adopt the Advanced Clean Trucks rule, which sets targets for the delivery of zero-emissions medium- and heavy-duty vehicles that gradually increase every year.

The rule was pioneered in California, which has authority under the Clean Air Act to set its own standards for vehicles that other states can adopt. It was published in the Maryland Register on Dec. 15 and will become effective on Dec. 25.

The annual increases will end in 2035, at which point zero-emission vehicles would need to make up 55% of pickup truck and van sales, 75% of rigid/box truck sales and 40% of tractor-trailer sales.

“Transportation is the largest source of climate pollution in Maryland and a leading source of toxic air pollution that is hazardous to human health,” Maryland Sierra Club Director Josh Tulkin said in a statement. “Adopting strong clean vehicle standards will help put the state on track to meet its ambitious climate goals, reduce dependence on fossil fuels and improve public health.”

While they represent just 9% of registered vehicles, medium- and heavy-duty trucks and buses generate 39% of smog-forming nitrogen oxide (NOx), 48% of particulate matter (PM2.5) pollution and 21% of greenhouse gas emissions from all on-road vehicles in the state.

A group of businesses and environmentalists urged the state to start implementing the rule as soon as possible — starting with model year 2027 cars. The benefits of lower pollution from the rule are expected to create $19.8 billion in health benefits over the next three decades, avoid 1,800 premature deaths, 46,800 asthma attacks and 231,200 lost workdays, according to analysis by the American Lung Association.

Maryland’s General Assembly voted to adopt the rule this spring, and the Clean Trucks Act of 2023 was signed by Gov. Wes Moore (D) in April.

“The transition to electric fleets is beginning to take shape. State policies like the ACT rule create a foundation for an electrified future — one where a diverse array of electric vehicles are driving on our nation’s roads and a robust charging network is built out from coast to coast,” Siemens’ Ryan Dalton said in a statement. “By adopting the ACT rule, Gov. Moore has again established Maryland as a leader in America’s green economy — producing lower carbon emissions and less pollution — all while creating equitable economic benefits for its communities.”

The Swedish furniture firm IKEA said it’s committed to getting 100% zero emissions on its home deliveries, but it needs policies to help hit that goal.

“The ACT rule is vital to helping Maryland companies meet our climate goals to move away from dirty deliveries and toward a cleaner and more just economy,” said Steven Moelk, IKEA manger of retail U.S. fulfillment project implementation.

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Former Employee Details Failures at Entergy’s Grand Gulf

A former employee of Entergy’s Grand Gulf Nuclear Station testified last week that he witnessed mismanagement by plant supervisors and was fired for refusing to revise audits documenting problems.

Jairus Greene testified Dec. 12 at the request of the Louisiana Public Service Commission, which is seeking millions in refunds from Entergy over alleged mismanagement of the 1,443-MW plant (EL21-56).

Testifying at the law offices of Stone Pigman Walther Wittmann in New Orleans, Greene said he witnessed poor engineering decisions, frequent reactor trips and scrams — or the sudden shutting down of a nuclear reactor — exemplified by Grand Gulf’s unusually low capacity factor. At one point, Greene said he couldn’t recall the length of individual outages because trips were commonplace. From 2016 through 2018, Grand Gulf ran at about a 55.5% capacity factor when other nuclear plants in the nation averaged over 92%, according to data from the U.S. Energy Information Administration.

Entergy says it has improved the plant’s operations, touting its 95% capacity factor in 2021. The utility also said Grand Gulf attained the highest rank in the Nuclear Regulatory Commission’s performance matrix in 2022.

Greene, who has more than 20 years’ experience in nuclear capital projects and cybersecurity, worked at Grand Gulf for about three years before he was fired in April 2022.

Greene spoke carefully during his deposition, acknowledging he lacked first-hand knowledge of some of what he reported, which came from other employees.

He said he believed security personnel at the plant worked shifts that were too long and they had no time for bathroom breaks. Employees found human excrement in some areas of the plant, he said.

He said he was aware of Grand Gulf’s poor reputation when he was hired. He “was kind of ashamed to admit” he worked in “a place like this,” he testified.

Greene said Grand Gulf leadership choose not to conduct engineering hold points — a pause on construction activities until an inspection is passed — as part of a turbine controls project in 2020.

Greene said he was concerned that some equipment considered critical digital assets at other reactors he worked at wasn’t considered such at Grand Gulf.

He also said there seemed to be numerous maintenance deferrals throughout his employment.

Greene said he took his concerns over pressures to issue more favorable audit findings and a chilled work environment to the Nuclear Regulatory Commission. 

Greene said he and other employees would meet informally at a nearby supermarket to discuss their concerns over the plant. Some colleagues left their positions to avoid compromising their integrity, he said. 

Greene said shortly after he wrote a memo on security lapses, he found his security clearance revoked. Shortly after, he was fired. 

However, Greene said he still believes in nuclear power though some utilities don’t operate plants reliably. 

In March, Greene filed a federal lawsuit against Entergy in the Southern District of Mississippi alleging he was fired for refusing to falsify safety reports (5:23-cv-00016). He contends he used legally prescribed THC derivatives to treat severe glaucoma and that Entergy used the pretext of a failed drug test to fire him in retaliation. He said he has never used marijuana.

Entergy spokeswoman Mara M. Hartmann declined to comment Monday on Greene’s allegations, citing “pending legal matters.” 

“Entergy is committed to the safe, secure and reliable operation of our plants in compliance with all applicable NRC regulations, including the NRC’s fitness-for-duty requirements,” she said. “We are proud that our Grand Gulf Nuclear Station has all green, or best possible, performance indicators in the regulatory performance matrix.”

Greene’s deposition came in a long-running dispute between Entergy and state regulators. Entergy subsidiary System Energy Resources Inc. operates and owns 90% of Grand Gulf and sells the plant’s output to Entergy’s Arkansas, Louisiana, Mississippi and New Orleans affiliates.

The Louisiana PSC maintains that ratepayers are owed hundreds of millions of dollars because Entergy mishandled plant operations, undertook an expensive and excessive plant expansion, and engaged in improper accounting and tax violations that shifted costs to ratepayers.

FERC has ruled against Entergy on some tax maneuvers and lease payment collections in another proceeding, though the exact amount owed is still up for debate. Louisiana regulators are asking FERC to fine Entergy $1 million a day for refusing to pay the refunds. (See Latest FERC Order on Grand Gulf Nuclear Plant Ambiguous on Refund Amount.)

Last month, Louisiana Public Service Commissioner Davante Lewis told The Times-Picayune/The New Orleans Advocate that it seems “Entergy is playing a legal maneuver that basically tries to bully us and wear down the clock.”

In October, the Arkansas Public Service Commission accepted Entergy’s $142 million offer to settle its claims, a year after turning down the same offer. Entergy estimates it has already refunded $50 million of that amount to Arkansas, according to a filing with the U.S. Securities and Exchange Commission.

Mississippi settled its claims related to Grand Gulf in 2022, accepting a $300 million refund. (See Entergy Offers Regulators $588M to End Grand Gulf Complaints.) 

During a third-quarter earnings call last month, Entergy CEO Drew Marsh said the deals with Arkansas and Mississippi resolve approximately two-thirds of the financial risks related to lawsuits over Grand Gulf. Marsh also warned that reaching a resolution in the FERC cases could take up to two years. 

Grand Gulf, the largest single-unit nuclear plant in the U.S., began commercial operations in 1985. In 2016, the NRC granted the plant a 20-year license extension, allowing it to operate through 2044.

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Storm Cuts Power to 750,000-plus in New England

A coastal storm packing high winds and heavy rains left hundreds of thousands of customers across the Northeast without power Dec. 18. 

Electric utilities prepared in advance, bringing in reinforcements and pre-staging them as the unnamed storm moved north with rain and storm surges that wreaked havoc in parts of the Southeast on Dec. 17. 

But damage on Monday was so widespread, particularly in New England, that power outages proved slow to fix.  

By midafternoon, poweroutage.us was showing 750,000 customers without electricity in five of the New England states. According to utility reports, well over 100,000 others lost power but had regained it by that point. 

The sixth state — Vermont, so badly pummeled by flooding earlier this year — held up much better, with only 1,300 outages at 2 p.m. and 1,900 by 6 p.m. 

The weather system moved north into Quebec and the Maritime Provinces, with rain ending in southern New England by late afternoon. The National Weather Prediction Center warned of moderate risk of flash flooding into Tuesday in northeast New England. 

Maine was hardest hit, with 372,000 customers without power as of early Monday afternoon, climbing to 430,000 by early evening. 

Versant Power’s outage map showed outages spread across the eastern side of the state. At 3:20 p.m. Monday, it posted on X that it was temporarily standing down its restoration efforts:  

“Wind gusts up to 70 mph will continue through the afternoon into the evening. For the safety of our crews, they will not be going up in buckets to perform work and are responding to emergency situations only at this time until further notice.” 

Central Maine Power’s outage map showed scores of outages concentrated in the southeast portion of the state. Around noon, the utility posted on X:  

“Our nearly 400 line and 200 tree crews are working with local agencies to respond to emergencies. With several more hours of strong winds expected, we anticipate a multiday restoration effort is ahead.” 

A day earlier, Central Maine Power had warned about the possibility of heavy tree damage as the storm moved toward New England: “Given the already water-saturated soil from previous storms, with more rainfall expected, trees may be more vulnerable to the strong winds associated with this storm,” it said Sunday. 

ISO-NE told RTO Insider that it was monitoring the situation, but the storm had not affected the regional grid as of midafternoon Monday: “While there are outages on the distribution side of the system because of the storm, the bulk power system in New England is currently operating under normal conditions. ISO New England is constantly monitoring the system, and our experienced system operators are trained to handle various weather-related outages that may arise.” 

Massachusetts was a distant second in the poweroutage.us tally — 260,000 customers without power at midafternoon, dropping to 239,000 by evening.  

Eversource provided the public a stream of updates in Connecticut, Massachusetts and New Hampshire that described a continuing give-and-take with a storm — power restored to 61,000 customers in Massachusetts alone, but 93,000 still without power as of midday, and more outages happening as more trees toppled. 

The utility used newer technology to avoid sending crews up in bucket trucks where possible: Its 38-MWh battery energy storage system on outer Cape Cod kept the lights on for 5,600 customers and smart switch technology turned the power back on for thousands more. 

Steve Sullivan, president of Eversource Connecticut, gave an update broadcast live on Facebook toward sunset Monday. He said that the utility had approximately 1,200 crews on duty, but progress was slow. 

“This is a multiday restoration. It’s really too early to pin down when we will finish because we have well over 2,000 outage events and we want to make sure that we get eyes on every one of them. And really, the winds just died down within the last few hours.” 

Sullivan said Eversource is triaging its response, clearing downed trees from roads first in partnership with municipalities, for whom that is a top priority. Next, it will restore power to critical-priority facilities, then schools. Remaining outages will be prioritized by size, with the largest being addressed first. 

Rhode Island Energy said it had about 23,000 customers without power late Monday afternoon and anticipated restoring the vast majority by Tuesday evening. It brought in hundreds of line and forestry workers before the storm and had more than 1,600 people in total working on recovery Monday. 

“This was a very severe storm that ripped through the region, and with the ground already saturated and trees weakened from last weekend’s storm, we expected we would see significant outages today,” President Dave Bonenberger said in a news release. “And while we’ve been able to get many customers restored, we’ve also seen some challenges in getting our buckets up in the air with these ongoing winds.” 

Looking south along the Atlantic coast, other states were in far better shape than New England.  

New Jersey, New York and Pennsylvania respectively had 18,000, 14,000 and 7,000 utility customers in the dark at 5:30 p.m., poweroutage.us indicated. Delaware, Maryland, Virginia and the Carolinas had fewer than 5,000 combined. 

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CAISO Board Approves Nevada Transmission Line to Access Idaho Wind

CAISO’s Board of Governors on Dec. 14 approved the inclusion of the Southwest Intertie Project-North (SWIP-N) — a 285-mile, 500-kV line in Nevada that would enable access to Idaho’s wind resources — in to the ISO’s 2022-2023 transmission portfolio.

The project is the only proposed line that would connect California’s load-serving entities to Idaho wind power. (See CAISO Pursuing Approval of New Line to Tap Idaho Wind.)

“This is a really exciting opportunity to open up some … really valuable resource diversity indexed straight to the California [Public Utilities Commission]’s integrated resource plans … and build on that legacy of transmission connectivity that exists across the West,” CAISO CEO Elliot Mainzer told the board before its vote.

The approval of SWIP-N diverges from the standard transmission planning process. The board already approved the ISO’s transmission plan in May. (See CAISO Board Adopts Revamped Transmission Plan.)

“This is a unique project, and it has quite a few differences from a conventional transmission plan approval decision … both because of the nature of the project and because of our negotiated arrangements with Idaho Power to access the capacity jointly,” Neil Millar, CAISO vice president of infrastructure and operations planning, told the board.

The project would require CAISO to assume entitlements from LS Power subsidiary Great Basin Transmission (GBT) on the existing One Nevada Transmission Line, which connects to the ISO via the Harry Allen substation north of Las Vegas. SWIP-N would connect with the existing line at the Robinson Summit substation near Ely, Nev. Both the ON Line and Robinson would need upgrades to accommodate the new project.

SWIP-N could be online by 2027, but the board’s approval is conditional on the Idaho Public Utilities Commission’s by Sept. 30. The CPUC also would have to reaffirm the need for Idaho wind power as part of its consideration of CAISO’s 2024-2025 transmission plan. And FERC would have to approve GBT’s tariff as a participating transmission owner and transmission revenue requirement.

Assuming everything is approved, CAISO expects it would file a project sponsor agreement with FERC in January 2025.

Jeff Billinton, CAISO director of infrastructure planning, reported that stakeholders generally supported the project, but some were concerned about costs. Millar noted the approval timeline allowed for plenty of opportunity for comment throughout 2024.

“Only after the FERC approves the project sponsor agreement do any cost-commitment issues arise; termination provisions go into effect,” he said. CAISO also then would begin a quarterly cost review process with LS Power. “So we believe that these gating checkpoints provide the right milestones, the right transparency [and] the right visibility.”

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Texas RE: Winterization Activities in ‘Good Shape’

The Texas Reliability Entity’s chief engineer, Mark Henry, told the organization’s Board of Directors last week that ERCOT generators’ winterization efforts are in “pretty good shape” in preparing for a NERC cold-weather standard. 

“We found that people who did have issues in our region during [the December 2022] winter storm generally are following through with the actions that are expected here and of course with the things that are part of the state rules now,” Henry said during the board’s Dec. 13 meeting, promising Texas RE will follow up with some of the entities to ensure “we’re not missing something.” 

NERC gathered the data last year from balancing authorities, transmission operators, and 1,160 generation owners and operators. They were asked to identify specific actions determined to be essential to the bulk power system’s reliability and the status of those actions. 

Henry said 245 ERCOT generators were surveyed, with 82% saying they didn’t experience a cold-weather reliability event during last winter and 86% saying they have completed or partially completed essential actions identified by NERC. 

ERCOT generation owners have calculated the extreme cold weather temperature (ECWT) for their facilities, with 96% saying they can operate at that temperature, Henry said. The ECWT is higher than 10 degrees Fahrenheit, which is higher than the February 2021 winter storm’s extreme conditions. 

Texas RE staff has shared some of the information gathered with ERCOT that could boost the ISO’s weatherization-inspection program. 

“We’re going to stay plugged into what they’re doing and let the folks in the other NERC regions know how we’re prepared down here in Texas,” Henry said. 

The cold-weather standard (EOP-012-2, extreme cold weather preparedness and operations) is hung up in NERC’s approval process, having failed two rounds of voting. NERC’s Board of Trustees have said they may have to take matters into its own hands if the standard fails another vote. (See NERC Board May Force Action on Cold Weather Standard.) 

Corbett to Chair Board

The board approved the nominations of Jeff Corbett and Suzanne Spaulding as its chair and vice chair. They will replace Milton Lee and Crystal Ashby in 2024. 

Corbett was a senior executive with Duke Energy after 30 years at Dominion Virginia Power and Progress Energy. Spaulding, who recently was elected by Texas RE’s membership to another three-year term as an independent director, has cybersecurity experience at the federal level and also spent six years at the CIA. She currently is senior adviser for homeland security at the Center for Strategic and International Studies (CSIS). 

The Member Representative Committee selected its 2024-25 representation in November. It will vote on its leadership in January. 

The MRC members are: 

      • Chad Thompson, ERCOT; 
      • Daniela Hammons, CenterPoint Energy; 
      • Lance Spross, Oncor; 
      • Frank Owens, Rayburn Country Electric Cooperative; 
      • Shari Heino, Brazos Electric Power Cooperative; 
      • Curt Brockmann, CPS Energy; 
      • Brock Carter, Austin Energy; 
      • David Hodges, RWE Renewables; 
      • Kristina Marriott, Miller Bros. Solar; 
      • Jeremy Carpenter, Tenaska Power Services; and  
      • Venona Greaff, Occidental Power Services.

    Brockmann, Greaff, Hammons and Heino are incumbents. 

    Texas RE Wins Workplace Award

    Texas RE CEO Jim Albright celebrated the organization’s inclusion among the top workplaces in the greater Austin area, as nominated by employees and recognized by the Austin American-Statesman. The reliability entity placed 14th among organizations with between 50 and 149 employees. 

    “This is a great achievement. Over the past three years, we’ve worked together to enhance our workplace culture,” Albright said during the annual membership meeting. “We believe this award … provides us some evidence that we’re going in the right direction. We were just 14 out of 66, so we still have room for improvement.” 

    Staff also reported Texas RE had a net gain of 17 members during the year to push its membership to 125. Generation accounts for most of the total with 89 members, followed by municipal utilities (11) and transmission and distribution providers (10). 

    As of Nov. 1, Texas RE had 335 registered entities, a gain of 32 from a year ago. 

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Texas Public Utility Commission Briefs: Dec. 14, 2023

ERCOT staff last week shared additional details with Texas regulators on the Sept. 6 frequency drop that lead to the grid operator entering emergency operations for the first time since the disastrous 2021 winter storm.  

Dan Woodfin, ERCOT’s vice president of system operations, told the Public Utility Commission during its open meeting Dec. 14 that more than 500 MW of the system’s physical responsive capability (PRC) was incorrect and/or unavailable at a time when PRC was dropping to 2,100 MW (54444). 

Woodfin said staff issued a request for information to entities contributing to PRC because “we had reason to believe” the information it was receiving from participants to calculate the reserves “was probably too high.” He said when frequency was at its lowest, calculated PRC was about 564 MW higher than what it should have been. 

Thermal generators were reporting about 200 MW of capacity they could reach, an incorrect reading based on ambient air temperatures, Woodfin said. 

“There’s always a little bit of error there,” he said. 

Woodfin said another 200 MW were unavailable from curtailed wind resources that were unable to respond to frequency because their automatic controls didn’t work properly. Another 158 MW were unavailable from energy storage resources (ESRs) that had depleted their state of charge (SOC) and couldn’t regain their SOC quickly enough. 

The frequency drop led to a dip in operating reserves below the 2,300-MW threshold, forcing ERCOT to issue a Level 2 energy emergency alert to maintain critical system frequency. The grid operator limited transmission from South Texas, trapping available wind generation along the Gulf Coast. (See ERCOT Voltage Drop Leads to EEA Level 2.) 

Demand peaked at 82.7 GW on Sept. 6, setting a new high for September. The ERCOT grid was without 10.5 GW of unplanned outages at PRC’s lowest point, below the summer’s typical daily outages of about 12 GW, Woodfin said. 

“I think these are things that are going to be more normal than not, at least until the transmission line from the south gets completed and some of the reliability issues get resolved. Long term. I hope this was a lesson,” commissioner Jimmy Glotfelty said. 

The PUC has approved a pair of transmission projects designed to increase capacity between South Texas and the rest of the grid. 

Jimmy Glotfelty shakes hands with Will McAdams during latter’s last PUC open meeting. | Admin Monitor

SOC Discussion Deferred Again

The commission granted ERCOT’s request to defer further discussion of a proposed rule change that sets a one-hour SOC for ESRs participating in two ancillary services and that Glotfelty has called “totally discriminatory” to the resources (54445). 

The grid operator told PUC staff that the delay would give it a chance to better prepare its materials and give the commission and market participants to review and comment on its presentation materials. ERCOT is committed to filing a detailed presentation no later than Jan. 4. 

The nodal protocol revision request (NPRR1186) has drawn opposition from storage developers during the stakeholder process. The PUC declined to approve the change during its last meeting and will take it up during its next open meeting Jan. 18. (See Texas Public Utility Commission Briefs: Nov. 30, 2023.) 

Glotfelty accepted the delay, questioning whether ERCOT staff’s time couldn’t be better spent on other work. 

“We want to make sure that we get all the information that ERCOT can provide before we take action on it,” Commissioner Lori Cobos said. “I really do hope that we get some good information from ERCOT to help us better understand the issues they’re seeing from their perspective.” 

The PUC did approve two consulting firms’ work plan for a value-of-lost-load survey and study to determine the estimated value of reliability in the ERCOT region (55837). 

The Brattle Group and PlanBeyond plan to survey retail customers using contact information provided by the grid operator in competitive areas and historical kilowatt-hour energy usage in competitive areas. The firms will have to depend on ERCOT’s relationships with non-opt-in entities, such as municipalities and cooperatives, and partner with them in their service territories to gather the same information. 

The firms plan to complete the survey and deliver its results to the commission by the end of June. They say the study will be “fundamental” in supporting the PUC’s market design initiatives, including the development of a reliability standard.  

Permian Basin Reliability Plan

Cobos and commission staff hosted a public workshop for oil and gas representatives, transmission and distribution utilities, and ERCOT staff in Midland on Dec. 12 to discuss reliability and electrification needs in the petroleum-rich Permian Basin (55718). 

“Texas is the No. 1 energy-producing state in the United States, Texas energy powers the world, and the Permian Basin is a critically important part of this success,” Cobos said.

Legislation passed earlier this year requires ERCOT to work with transmission service providers to develop a reliability plan for the Permian Basin region. The plan must address the region’s transmission needs, additional generation to meet the energy industry’s demand and streamlining interconnection processes.

The plan is due to the PUC in July for stakeholder feedback. The commission then will consider the plan for its approval.

345-kV Project Approved

The PUC approved revised certificates of convenience and necessity for a 345-kV double circuit transmission line in West Texas needed to address reliability issues driven by rapid oil and gas load growth and to improve import capability into the Delaware Basin.

The joint project between Lower Colorado River Authority Transmission Services Corp. and Wind Energy Transmission Texas involves 68 miles of new circuits and substation upgrades. It’s estimated to cost $370 million and be in service in 2026, when the region’s load will exceed 4,000 MW (55120).

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PJM MRC/MC Preview: Dec. 20, 2023

Below is a summary of the agenda items scheduled to be brought to a vote at the PJM Markets and Reliability Committee and Members Committee meetings. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.

RTO Insider will be covering the discussions and votes. See the next newsletter for a full report.

Markets and Reliability Committee

Consent Agenda (9:05-9:10)

B. Endorse conforming revisions to Manual 12, Balancing Operations; Manual 13, Emergency Operations; and Manual 14D, Generator Operational Requirements to implement a renewable dispatch package. (See “Other Committee Business,” PJM MIC Briefs: Nov. 1, 2023.)

Issue Tracking: Renewable Dispatch

C. Endorse proposed revisions to Manual 14B, PJM Region Transmission Planning Process as a part of its periodic review. The changes include specifying that the 300-MW load loss rule is meant to apply to possible outages that would affect a large number of consumers, rather than a single large industrial customer. (See “First Read of Periodic Review of Manuals 19 and 14B,” PJM PC/TEAC Briefs: Oct. 3, 2023.)

D. Endorse conforming revisions to Manual 21A, Determination of Accredited UCAP Using Effective Load Carrying Capability Analysis addressing Hybrids Phase II Market Participation of Hybrid Resources and other Mixed Technology Facilities instituting the second phase of PJM’s rules for hybrid resources.

Issue Tracking: Solar-Battery Hybrid Resources

E. Approve sunsetting the Energy Price Formation Senior Task Force (EPFSTF).

Issue Tracking: Operating Reserve Demand Curve (ORDC) & Transmission Constraint Penalty Factors

Endorsements (9:10-9:55)

  1. Performance Impact of the Multi-schedule Model on the Market Clearing Engine (9:10-9:30)

PJM’s Danielle Croop will present the proposal endorsed by the Market Implementation Committee on Aug. 9 to revise how some resource offers are entered into the market clearing engine (MCE) to allow multi-schedule modeling to be implemented without overloading the engine with an exponential increase in the number of schedules it must consider. Croop also will present an alternative approach which received lesser MIC support, but still a majority. (See “Endorsement of Multi-schedule Modeling Solution Deferred,” PJM MRC/MC Briefs: Nov. 15, 2023.)

The committee will be asked to endorse the proposed solution and corresponding tariff and Operating Agreement revisions.

Issue Tracking: Performance Impact of the Multi-Schedule Model on the Market Clearing Engine

  1. Regulation Market Design Senior Task Force (RMDSTF) (9:30-9:55)

Croop will present a proposal to shift the regulation market to have a single price signal with two products representing a resource’s ability to adjust its output up or down. (See “PJM Presents Regulation Market Rework,” PJM MRC/MC Briefs: Nov. 15, 2023.)

The committee will be asked to endorse the proposed solution and corresponding tariff and OA revisions.

Issue Tracking: Regulation Market Design

Members Committee

Endorsements (10:10-10:20)

PJM’s Michele Greening will present the proposed sector representatives for the 2024 Finance Committee, 2024 sector whips and 2024 MC vice chair.

The committee will be asked to elect the proposed representatives.