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September 12, 2024

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NPCC, NYSEG Agree to Settle Control Center Violation

FERC accepted a settlement between New York State Electric and Gas (NYSEG) and the Northeast Power Coordinating Council in which the utility admitted to violating NERC’s requirements for maintaining backup control centers.

The settlement, which carries no monetary penalty, was filed by NERC in its monthly spreadsheet Notice of Penalty on July 31; it was the only settlement in the spreadsheet and the only NOP filed that month (NP24-10). In a filing issued Aug. 30, FERC said it would not further review the settlement. Commissioner Judy Chang did not participate in the decision.

The settlement stemmed from a violation of EOP-008-2 (Loss of control center functionality), approved by FERC in 2018 in order to “ensure continued reliable operations of the [electric grid] in the event that a control center becomes inoperable.” NPCC discovered the noncompliance during an audit in 2020.

According to the settlement, NPCC found that NYSEG’s backup and primary control centers used a shared communication path with a single point of failure. This contravened requirement R6 of the standard, which mandates that reliability coordinators, balancing authorities and transmission operators ensure their primary and backup control centers maintain separate functionalities.

NPCC reported that seven communications lines terminated in a single room common to both the primary and backup control centers. In the event of a “catastrophic event” at the primary control center, the utility would lose its connection with about 150 remote terminal units (RTUs), 62 of which provide data from its substations. This represents a loss of data from more than half of its 121 grid-connected RTUs.

Further investigation revealed that NYSEG had discovered the issue during a prior audit in 2017 and labeled it an area of concern. The utility first sought to address the problem with its telecommunications vendor, but the vendor delayed implementation of the proposed solution for more than a year before telling NYSEG in 2019 that it “could no longer support the solution as designed.”

NYSEG then pursued a permanent solution, which was “in the planning stages” when NPCC conducted its 2020 audit. But the regional entity said the utility did not assign the task the necessary priority or management oversight, and thus the violation lasted longer than it would have with proper prioritization. Along with EOP-008-2, NPCC also found that NYSEG had violated the standard’s predecessor, EOP-008-1, which was in effect when NYSEG registered as a transmission operator and was required to comply with it.

NPCC assessed the violation as a moderate risk to grid reliability. It pointed out that the shared point of failure would have reduced NYSEG’s visibility into its system and compromised its ability to work remotely if the primary control center became inoperable. The RE said a catastrophic event compromising the primary center “would likely be a long-duration event,” exacerbating the risk.

At the same time, the RE acknowledged that the risk of such a catastrophic event affecting the primary control center is low. It also pointed out that even if NYSEG lost its ability to monitor the system, NYISO and neighboring TOPs and BAs could still monitor their respective systems, ensuring some visibility into the grid’s health.

NPCC determined that no monetary penalty would be required in light of NYSEG’s cooperation in the enforcement process, lack of prior relevant noncompliance and agreement to settle the matter rather than calling for a hearing. However, the RE did feel it necessary to elevate the matter to the spreadsheet NOP because of the length of the noncompliance and the fact that it became aware of the issue through a compliance audit rather than the utility reporting the problem itself.

To mitigate the problem, NYSEG removed the single point of failure by migrating the communications lines. It also created a new NERC compliance tool to monitor compliance projects and make sure schedules are maintained properly, trained relevant personnel on the tool, and updated its project management procedures to specify that leadership must review the project management plan when changes to a project’s schedule are needed.

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Texas PUC Sets Reliability Standard for ERCOT

Texas’ regulatory commission has adopted a reliability standard for the ERCOT region, one of several policy parameters that will be used in upcoming analyses for the proposed performance credit mechanism (PCM) market design. 

As approved by the Public Utility Commission during its Aug. 29 open meeting, ERCOT must meet three criteria to comply with the reliability standard: frequency, duration and magnitude. To meet the standard, ERCOT outages should not occur more than once in 10 years on average, last more than 12 hours or lose more power than can be safely rotated (54584). 

“Our system must continue to evolve to meet the growing demand for power in our state … it’s critical we clearly define the standard at which we expect the market and system to operate,” PUC Chair Thomas Gleeson said in a statement. “By establishing a reliability standard for the ERCOT region today, we are setting a strong expectation for the market and charting a clear path to further secure electric reliability.” 

The new rule also establishes a process to regularly assess the ERCOT grid’s reliability. The commission directed ERCOT staff to conduct a probability-based assessment every three years, beginning Jan. 1, 2026, to determine whether the system is meeting the standard and is expected to continue to do so over the next three years.  

Should that assessment indicate the system fails to meet the reliability standard, the Independent Market Monitor (IMM) must conduct an independent review and commission staff must recommend their own potential market design changes. The PUC then would review ERCOT’s assessment, the IMM’s review, commission staff’s recommendations and public comments to determine whether any market design changes are necessary. 

ERCOT and IMM staff confirmed during the meeting that they have all they need to begin their respective analyses. Draft results are due to the PUC in early November; the commission will consider the final results in December. 

The ISO said it will use 19 GW as the amount of load it can safely rotate during an outage in its cost/benefit analysis, as it proposed in an April research paper. 

The reliability standard was just one of several actions the PUC took to establish regular assessments of the grid’s ability to meet demand and help determine any necessary future improvements. 

It adopted a value of lost load of $35,000/MWh, using information from a survey of ERCOT consumers and a Brattle study. Staff proposed a $30,000 VOLL, but Gleeson recommended Brattle’s suggested $35,685, saying it was “reasonable” after a “detailed and thorough” analysis (55837). 

“We don’t need the extra numbers in there,” Gleeson said. 

ERCOT will use VOLL for cost/benefit analyses in its planning models. The PUC said it will not be used to update the operating reserve demand curve or any current market-design elements. 

The commission also accepted staff’s final recommendations for each of the PCM’s 37 base case parameters, including a firm $1 billion gross cost cap to comply with state law (55000). ERCOT had proposed a counterfactual of energy-only market equilibrium reserve margin instead of the cost cap, a “purely theoretical number,” according to Stoic Energy principal Doug Lewin. 

PUC staff and ERCOT also differed on four other parameters: the metric to determine performance credit (PC) hours; a duration-based cap for consecutive PC hours; the net-cost cap compliance framework; and non-performance penalties for PCs offered but not cleared in the forward market. 

The PUC selected the PCM from among five other suggested market reforms as its design of choice and approved it in 2023. That same year, the Texas Legislature passed a bill setting a $1 billion annual cap for the PCM. (See Texas PUC Submits Reliability Plan to Legislature.) 

The PCM will use the reliability standard and a corresponding quantity of PCs that must be produced during the highest reliability risk hours to meet the standard. Load-serving entities can purchase PCs, awarded to resources through a retrospective settlement process based on availability during hours of highest risk, and trade them with other LSEs and generators in a forward market; generators must participate in the forward market to qualify for the settlement process. 

CPS Energy MRA, RMR Update

ERCOT told the PUC it has changed course on must-run alternatives for three retiring CPS Energy coal units, postponing an inspection of the largest unit until after the winter season (55999). 

The San Antonio municipality told the commission this year it planned to retire the three coal units, which date back to the 1960s, in March 2025. However, ERCOT said the Braunig Power Station units, with a combined summer seasonal net maximum sustainable rating of 859 MW, were needed for reliability reasons and issued a request for reliability-must-run proposals in July. (See ERCOT Evaluating RMR, MRA Options for CPS Plant.) 

The grid operator said in an update to the commission that while it continues to negotiate a potential agreement with CPS Energy to inspect the 412-MW Unit 3, it would be “more prudent” to allow the resource to operate through the winter’s peak demand period. ERCOT staff said the inspection could be held in mid-February or early March. 

“If we waited until after winter peak load, we believe we’d still have plenty of time, barring unforeseen circumstances, to have the unit inspected and repaired during another shoulder season for outages and before the summer peak load season,” ERCOT’s Davida Dwyer said. 

The ISO extended the deadline for RFP responses to Oct. 7 after receiving fewer than 10 proposals to its initial request. (See “ERCOT Extends MRA Timeline,” ERCOT Board of Directors Briefs: Aug. 19-20, 2024.) 

Chad Seely, the ISO’s general counsel, told the commission the deadline would provide an “important data point” in seeing whether the industry has responded with enough MW to provide relief for a constrained area south of San Antonio. 

“The additional time affords us a more deliberative process on these critical policy issues to see if the industry is going to respond to the must-run alternative,” Seely said, “and then continue to move forward [on] a path where we still think it’s appropriate and prudent for reliability to start to open up the unit in advance of any April 1 RMR agreement.” 

“Is it looking bleak on the MRA?” Commissioner Lori Cobos asked Seely.  

Noting that ERCOT has amended the RFP after stakeholder feedback, he said, “We’re hopeful, with the amendments that we put forward and allowing almost another month of time for people to go do their due diligence, and talk to their shops about options, that we will see a higher [number] of offers come in in October.” 

“Ultimately, I don’t want RMR to be the norm, right?” Cobos responded. 

Seely said the three units are in a “prime” location to relieve the constraint’s interconnection reliability operating limits (IROLs), which makes the pre-RMR inspection work such an “extraordinary situation.” 

“[Braunig] is one of the best assets right now in the system, until we see other solutions to help relieve the overloads of the IROL for the next couple of years,” he said. “That’s why it’s critically important to be deliberative and these critical policy issues on how we approach this.” 

CPS has said it will cost about $22 million to inspect, repair and prepare Braunig Unit 3 to remain in service past March and an additional $35 million for the other two units. 

Utility and energy storage company Eolian announced Aug. 28 an agreement for two storage facilities south of San Antonio totaling 350 MW of capacity. The projects are not expected to come online until 2026, but work to upgrade the transmission infrastructure and relieve the South Texas constraint isn’t expected to be completed until the middle of 2027. 

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Counterflow: Back to the Future

It seems like yesterday I started scribbling about all manner of industry subjects — against the flow, the prevailing wisdom, the latest hype, etc. 

But it’s actually been 10 years. With that passage of time, spanning 90 columns and articles all available here, I thought I’d look back at what I might have gotten right, gotten wrong or whatever. And what such might portend for the next 10 years. 

Let’s start with — who else — Elon Musk and his claims for his new home battery, the Powerwall. Including pairing with his cousins’ SolarCity’s solar panels. Powerwall and SolarCity didn’t live up to Musk’s early hype, as I discussed in follow-up columns (one more), but they finally became a profitable part of Tesla. Maybe I should get partial credit.  

Steve Huntoon |

Next subject was Big Transmission (not to be confused with economic interregional ties). Back then, I summarized the prior 10 years: “It was heady stuff: Big lines and arrows sweeping across the country, depicting massive new transmission projects. But after 10 years of dramatic announcements and proposals, the reality today is that Big Transmission has fallen and it won’t be getting up. And a second reality is this: The fall of Big Transmission is not a public policy failure. Rather, Big Transmission never did make sense. Instead, the experience so far points to a continuation of what we’re doing now — to more of the incremental transmission expansions that have characterized the past 10 years — and not to count on Big Transmission as a solution to any future industry challenge.” Another 10 years and the song remains the same.✔️  

On to microgrids! I showed that microgrids are the irrational antithesis of everything we know about electric system planning and operation. A couple years later, I discussed the threat microgrids posed to national security, did a recap a couple years later, and then this year covered the microgrid boondoggle in Chicago. ✔️  

Next up were utility-scale batteries. I showed that the two claimed value propositions, capacity backup and energy arbitrage, didn’t pencil out. Battery costs have since come down significantly, but batteries remain a niche product absent subsidies and/or mandates. Hmm, maybe another partial credit. 

On to New York’s REV (“Reforming the Energy Vision”). As I said back then, it was the most hyped regulatory initiative since the California restructuring some 20 years prior. REV was mostly word salad, but one of the few specifics was subsidizing utilities to install rooftop solar. I couldn’t imagine a worse idea. ✔️  

Well, except maybe California’s artificial creation of the Duck Curve by layering one bad policy on top of another. Free storage and distribution in the form of net metering, uneconomic time-of-use rates discouraging afternoon usage, subsidies of battery storage reducing afternoon usage. Yikes. Many years later, the Duck is finally getting targeted, but not before helping drive California’s electric rates to astronomical levels. ✔️ 

Another close contender from California was the planned closure of the Diablo Canyon nuclear plant. Perhaps my hair-on-fire column helped save the plant … and perhaps helped the planet. ✔️  

Oh, and lest we forget Bernie Sanders’ promise to ban fracking during his 2016 campaign. Not only to cost consumers some $100 billion annually, but to increase carbon emissions by increasing coal-fired generation. Yikes! ✔️  

Enough reminiscing for one day! 

P.S. Except to add to prior columns’ postscripts about Peace, Love and Understanding. Here’s an audio version by the guy who wrote it, Nick Lowe. Oh, and this cover by Elvis Costello 20 years ago is epic. 

As Spinal Tap said: Turn it up to 11. 

Columnist Steve Huntoon, principal of Energy Counsel LLP and a former president of the Energy Bar Association, has been practicing energy law for more than 30 years. 

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DOE Approves 1st LNG Exports Since Biden Administration’s Pause

The Department of Energy on Aug. 31 approved a five-year term for New Fortress Energy’s Fast LNG 1 project to export gas produced in the U.S. to countries without free trade agreements (FTAs).

The LNG facility recently started operations in Altamira, Mexico, and will receive U.S.-produced gas via pipeline to export. It announced its first exports in August, having already won approval to ship gas to countries with FTAs.

The authorization comes after a court stayed the Biden administration’s pause on such approvals, announced earlier this year, and while DOE works on a related study on the environmental impacts of LNG exports. (See Federal Judge Stays Biden’s LNG Export Application Pause.)

“This important authorization cements NFE’s position as a leading global vertically integrated gas to power company and enhances the marketability of our FLNG 1 asset,” CEO Wes Edens said in a statement Sept. 3. “NFE is now able to freely supply cheaper and cleaner natural gas to underserved markets across the world and further our goal of accelerating the world’s energy transition.”

DOE approved the facility to ship 145 Bcf/year of U.S.-produced LNG. The gas will flow into Mexico over the Valley Crossing Pipeline, which runs south from Texas, and potentially other cross-border pipelines that have yet to be completed.

The exports to non-FTA countries give NFE more flexibility with the facility, DOE said.

“These re-exports can diversify global LNG supplies and improve energy security for U.S. allies and trading partners,” the department said. “Based on this administrative record, DOE has determined that it has not been shown that NFE Altamira-proposed re-exports of LNG to non-FTA countries will be inconsistent with the public interest over the authorization period.”

DOE’s approval is in effect for five years, until Aug. 30, 2029, but NFE wants to keep exporting gas until 2050. The department will reevaluate its approval once the company formally asks for a new end date.

So far, DOE has approved 46.45 Bcfd of natural gas exports, which includes 6.71 Bcfd of gas shipped to Canada and Mexico before being exported overseas.

North America’s export capacity is on pace to double by 2028, from 11.4 Bcfd to 24.4 Bcfd, the Energy Information Administration said Sept. 3.

The U.S. is home to 9.7 Bcfd of projects under construction, with Canada building 2.5 Bcfd and Mexico 0.8 Bcfd. The Canadian facilities would export gas produced there, but the Mexican facilities are seeking to export gas initially produced in the U.S.

In approving NFE’s application, DOE said it would monitor market developments closely as the impact of successive authorizations of LNG exports continues to unfold.

“DOE also acknowledges that proposals to re-export U.S.-sourced natural gas in the form of LNG from Mexico or Canada to non-FTA countries raise public interest considerations that are not present for domestic exports of LNG,” DOE said. “In the case of re-exports, the U.S. economy does not receive a significant portion of the benefits DOE has recognized for LNG exported directly from the United States, particularly with respect to the jobs and infrastructure investment associated with construction and operation of liquefaction facilities.”

Foreign LNG export facilities are also not subject to U.S. environmental laws, which could lead to long-term issues if local laws are laxer, DOE added.

The export application was opposed by environmentalists, with Sierra Club protesting and Food & Water Watch releasing a statement blasting the approval.

“It’s ridiculous that the Department of Energy would issue this license despite the administration’s ongoing, incomplete public interest review of such exports,” said Mitch Jones, managing director of advocacy and policy. “The department is under no obligation to approve these ill-advised proposals, now or ever. As the disastrous impacts of increased fossil fuel development become more and more obvious here and around the globe, the notion of expanded LNG exports should be dismissed out of hand.”

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NYISO Presents Final 2025 Project Budget Recommendation

NYISO last week presented the Budget and Priorities Working Group with its final recommended 2025 budget for in-house initiatives, showing that it responded to stakeholder feedback by reincluding several projects that had been cut.

The ISO’s initial recommendations last month cut several stakeholder favorites, including implementing storage as transmission and market purchase hub transactions. (See NYISO Presents Initial 2025 Project Budget Recommendation.)

“We took the feedback that we got from the initial recommendation, went back, and looked at the projects,” said Kevin Pytel, senior manager of product and project management for NYISO. “We have modified some of our estimates when we further scrutinized those estimates, trying to bring them down as much as possible for the resourcing.” This freed up some resources for other projects, he said.

Most of the projects that had been excised were reincluded by modifying their deliverables, which may change when they come fully online. Pytel explained that some of the changes were possible because NYISO produced new estimates of how many labor hours they would take.

“What you found in the past is that you’ve made conservative estimates, as in protecting yourselves: estimates of how much time projects would take and that they don’t take as much time as you estimate?” said Mark Younger of Hudson Energy Economics.

“That’s what the data suggests, Mark,” said Pytel.

Based on the recommended projects, NYISO estimates the total budget for 2025 to be $42.73 million — up from 2024’s $41.62 million — with $22.56 million for labor, $8.31 million for capital and $11.86 million for professional services.

In response to a stakeholder question, NYISO staff said the total cost is slightly higher than what it initially recommended, mostly because of a $500,000 increase in labor costs.

The Integrating Champlain Hudson Power Express project “could not fit into budget due to resource constraints,” NYISO said. The project aims to develop an operating protocol between Hydro-Quebec and the CHPE line, including identifying tariff revisions, software enhancements and integrating the facility to the system reliability tools. This would not impact the expected deployment in 2026, the ISO said. The line is expected to go into service that year.

The proposed budget is expected to be presented to the Management Committee at the end of this month, with a committee vote a month later and a Board of Directors vote in November.

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Large Consumers Miffed at NYISO Proposal to Shorten SCR Notice Period

NYISO last week proposed shortening the activation notice period for special-case resources from 21 hours to four, which caused consternation among program participants at the Installed Capacity Working Group’s meeting.

SCRs are large consumers that act as demand response resources at the direction of NYISO itself. As part of its Engaging the Demand Side initiative, the ISO has proposed to increase the required duration of SCRs’ load curtailment from four hours to six. That proposal has received broad support from stakeholders, with some caveats. (See NYISO Proposes Changes to Special-case Resource Program.)

Among those discussed at the Aug. 29 meeting was NYISO’s proposal to not give SCRs the option of curtailing load for only four hours. Michael Ferrari, a market design specialist with NYISO, said to have both the four-hour and six-hour options would require an annual elections process in which resources would have to declare ahead of the capability year what class they were in.

Zach Smith, senior project manager for NYISO, said adding the additional options would delay implementation and it did not want to delay a reliability program with broad stakeholder support.

Aaron Breidenbaugh, senior director of regulatory and government affairs for CPower, said this was the first time he heard NYISO say it was not doing something for a reason other than operational difficulty.

“Previously we’ve heard that operations can’t handle multiple durations in real time, and I suspect they’ll have a harder time if they only have four hours,” Breidenbaugh said.

NYISO staff acknowledged this was the primary issue with having multiple durations.

Notice Period

The ISO wants to reduce the current notice period to help maximize the grid operator’s flexibility and reduce the likelihood of false notifications, Ferrari said.

But this proposal left some stakeholders surprised and frustrated.

One stakeholder who represents Multiple Intervenors — a group of large industrial, commercial and institutional consumers — said the proposal was a “dramatic change” to spring on the demand side.

NYISO said in July it was considering shortening the notification period, though it did not say by how much.

“This whole project is supposed to be about NYISO engaging the demand-side participants in these programs,” the stakeholder said. “While participants could perform with less than 21 hours’ notice, they strongly desired some advanced-day notification, preferably prior to the end of the prior work day.”

To adjust load or activate generation, work schedules needed to be shifted in the event of a call, they said. The manufacturers who participate in the program go to great lengths to reduce their load when called on.

“They will see this proposed change as the straw that breaks the camel’s back and causes them to leave the program,” they said. “If that’s not a concern for NYISO, that’s fine. But I think NYISO should be aware that this could have a dramatic impact on participation.”

The stakeholder said Multiple Intervenors would be happy to have more meetings with NYISO, but they would not perform survey work for the ISO to assess their members’ sentiments.

“We’re not going to do a survey and do the NYISO’s work for it,” they said. “If you want that information, hold a meeting. We’ll participate.”

Jay Goodman, another representative of Multiple Intervenors, asked whether NYISO could provide any historical data on events in which it has called on SCR program participants and did not get corresponding activations. A NYISO staff member said they don’t believe such information is published.

“I do want to note,” Goodman said, “it’s frustrating in the context of a project that is supposed to be engaging with the demand side, where requests for information not only from the demand side but the MMU, is met with the response of ‘No, we can’t provide that information. We won’t provide that information.’”

Goodman went on to ask why NYISO hadn’t brought up the four-hour notice period with the demand side directly, during earlier meetings with Multiple Intervenors. Ferrari said the four-hour notice period had not been decided on by NYISO internally yet.

“The city is shocked as well to this significant change to the program,” said Couch White attorney Amanda De Vito Trinsey, speaking on behalf of New York City.

“This causes a lot of industrial issues, but even for non-industrial customers, this is still a very significant impact on their operations and their ability to respond in a four-hour period,” she said. “I encourage NYISO to come back right away with something to review.”

A representative of the New York State Energy Research and Development Authority said they were disappointed that NYISO wasn’t presenting a more flexible program and didn’t have more information available for reasonable stakeholder follow-up questions.

Another stakeholder compared the various revisions to the SCR programs to multiple ruptured bulkheads on the Titanic. No one issue was going to kill the program, but all of them together would drive participants out.

“The first hole was having revenue reduced by one-third because of capacity accreditation; wham bam, now we’re up to four bulkheads,” they said. “Like, how much more do you think you can do in the guise of catering to operational needs and desires and still have a viable program? I’d say you’re past that point.”

They went on to say this felt like evidence NYISO wanted to get rid of the SCR program entirely. If NYISO wants to save the program, it needs to tone down some of the changes, they said.

“Thank you for your comments,” said Ferrari. “If you’ll allow me to take liberties with your analogy, there are a lot more icebergs in the water. … The grid is changing; it’s a much more dynamic system; and you know we haven’t made changes to this program in a quarter-century.”

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Mass. DPU Approves 1st Round of Utility Grid Modernization Plans

The Massachusetts Department of Public Utilities has approved grid modernization plans from electric distribution companies that outline longer-term strategies for handling increased electrification and the deployment of distributed resources.

The electric sector modernization plans (ESMPs) include five- and 10-year load forecasts, investments to meet forecasted demand and boost resilience, and cost-benefit analyses for the proposed investments. Overall, the plans predict major new costs for ratepayers. (See Mass. Utilities Submit Grid Modernization Drafts.)

The plans were mandated by 2022 legislation requiring utilities to submit new ESMPs every five years, along with two reports per year providing updates on investments and forecasts.

“The department expects the ESMPs to be each utility’s roadmap outlining how the discrete investments proposed will achieve the statutory objectives,” the DPU wrote in its Aug. 29 ruling.

The DPU largely accepted the utilities’ proposals, despite concerns raised by the Massachusetts Attorney General’s Office, Department of Energy Resources, and several environmental and consumer advocacy groups.

While the Grid Modernization Advisory Council, a stakeholder group set up to provide recommendations on the plans, advised that the ESMPs “should be the central distribution system planning document” for “whole-of-business” electric utility planning, the DPU rejected this suggestion.

“This approach would add requirements that the 2022 climate law does not envision,” the DPU ruled, writing that their review of the plans “is limited to the new, discrete and incremental investments proposed in the ESMP.”

The department did note the difficulties “regarding the need to monitor and attempt to influence multiple department proceedings that touch upon distribution system planning.” It wrote that it “sees value in the companies reporting high-level, informational-only data in the ESMP reports relating to non-ESMP investments.”

The investments proposed by the utilities are significant: Eversource Energy presented more than $600 million in additional spending over five years, while National Grid proposed more than $2 billion. The mounting costs are in part a reflection of projected growth in peak demand. Eversource anticipates a 21% increase in electricity demand over the next 10 years, while National Grid forecasts about a 29% increase.

The department’s approval of the plans is not a preapproval of the investments. The DPU wrote in a February 2024 interlocutory order that it will review the proposals “in the context of strategic planning documents only.”

However, the scale of the investment spurred concerns from advocacy groups and the AGO, which wrote that “the magnitude of the planned EDC investments is a sobering challenge to ratemaking and to affordability for ratepayers.”

Representatives of climate and environmental justice organizations expressed disappointment that the DPU did not take a broader approach to the ESMP proceeding.

“I wish they had gone further,” Kyle Murray of the Acadia Center told RTO Insider. There were “not a lot of significant changes from what the companies proposed,” and the DPU “didn’t take a lot of suggestions from the intervenors.”

However, Murray said the move toward long-term planning is a step in the right direction, and he applauded the DPU’s decision to lengthen the stakeholder process for the next round of ESMPs.

Larry Chretien of the Green Energy Consumers Alliance said the DPU’s decision not to use the ESMPs as central planning documents could make it difficult for the department and intervening organizations to evaluate and engage with proposals across separate dockets, filings and stakeholder advisory groups.

“The oversight is going to be tremendous, and it’s going to be every year,” Chretien said. “It’s just not practical to think that the public interest groups and the EJ groups will have the bandwidth to play this game over time.”

Demand Forecasting

The AGO and the DOER both expressed concern about deficiencies in the utilities’ load growth forecasts, writing that they lack consistent inputs and do not account for certain peak load reductions strategies.

“The forecasts offered by the companies fail to meet the standards established; are not transparent; are not comparable across the companies; do not provide a full accounting for underlying assumptions; and lack consideration of important tools like load management, which can reduce costs for ratepayers,” the DOER wrote.

The DOER argued that the EDCs appear to underestimate the potential of peak demand reduction strategies including managed electric vehicle charging, new rate designs, new building codes and energy storage.

The DPU ruled that ESMP load forecasting complied with the law, and that variance between the utilities’ approaches could help accommodate differences in the characteristics of their respective service areas.

“The department finds that each company’s forecasting method and assumptions are reasonable, appropriate and reliable,” the DPU found.

To evaluate the accuracy of future forecasts, the DPU directed the companies to include a comparison of forecasted and actual demand in their biannual filings, and to compare their ESMP five- and 10-year forecasts with their more recent figures. The DPU also required utilities to include separate modeling of demand reduction and energy efficiency programs in the next round of ESMPs.

Climate Resilience

The state’s 2022 climate law also required utilities to detail their plans to prepare the grid for the effects of climate change. The DPU determined the utilities’ proposals complied with the requirements of the law but found “the need for greater consistency in the climate vulnerability assessments prepared by the utilities.”

The DPU noted the utilities proposed different horizons for their climate projections and included limited detail on how they plan to mitigate the risks identified in climate vulnerability assessments. It directed utilities to identify resilience investments using “major event-inclusive performance data” to analyze cost-effectiveness and account for the location of critical facilities.

“In their biannual ESMP reports, the companies shall provide updates on their progress toward finalizing their frameworks for climate vulnerability risk assessments as well as on their targeted resiliency investment identification and prioritization method,” the DPU wrote.

Gas Planning

Environmental advocacy groups expressed concern that the plans do not include enough information on coordinated gas-electric planning and wrote that aspects of the plans citing the potential of hybrid heating systems and blending alternative fuels in the gas network are not compliant with a recent DPU order on the future of gas (20-80-B). (See Massachusetts Moves to Limit New Gas Infrastructure.)

The DPU wrote that it cannot rule on the viability of the gas companies’ decarbonization strategies in the ESMP proceeding, and that it will evaluate these proposals when the companies submit their Climate Compliance Plans in spring 2025.

The department did note that it expects the EDCs to be compliant with orders on gas decarbonization in ESMP filings and directed the companies to “account for any future department decisions on the propriety of these technologies in their future ESMPs.”

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Brattle New Mexico Study Shows EDAM Benefits Outpacing Markets+

A new study may dispel the notion that New Mexico utilities must follow the day-ahead market choice of their Arizona counterparts in order to realize benefits from market participation.

The Brattle Group performed the study for Public Service Company of New Mexico (PNM) and El Paso Electric (EPE). It compared the projected benefits from joining either CAISO’s Extended Day-Ahead Market (EDAM) or SPP’s Markets+. The study models a scenario in which three Arizona utilities — Arizona Public Service, Salt River Project and Tucson Electric Power (TEP) — join Markets+.

Brattle Principal John Tsoukalis presented the study results Aug. 29 during a New Mexico Public Regulation Commission workshop.

PNM’s annual benefits would be $20.5 million in the EDAM case, the study found, compared with $8 million from participating in SPP’s Markets+. For EPE, projected benefits are $19.1 million a year for EDAM, versus $9.1 million for Markets+.

Compared to previous analyses, the new study modeled transmission connectivity in the two day-ahead market options in much more detail, including how third-party transmission rights could be used, according to Kelsey Martinez, PNM’s director of regional markets and transmission strategy.

“What we realized through this study is that we do have a choice,” Martinez told the commission.

That realization means that factors not included in the study may become more influential in PNM’s market choice, Martinez said. She noted the potential operational challenge of having large amounts of wind energy moving through the PNM system.

“One market would be dispatching our resources, and another market would be dispatching all the resources that are using and connected to our system,” she said.

Comparing Seams

Tsoukalis said the study was designed to look at the impact of two potential seams resulting from a day-ahead market choice.

“One of those key study questions was looking at which seam was worse,” he said: “that seam with Arizona, or the seam with all the wind in New Mexico that has off-takers in California?”

Brattle looked at the results of the New Mexico utilities joining EDAM or Markets+ as compared to a “current trends” case, which is “a representation of where we think the WECC could go,” Tsoukalis said.

In the current trends case, the Arizona utilities join Markets+ along with a cluster of Northwestern entities, including the Bonneville Power Administration, Powerex and Puget Sound Energy. Western Area Power Administration (WAPA) Upper Great Plains and WAPA Colorado Missouri go with SPP’s RTO West in the scenario.

Entities including CAISO, PacifiCorp, NV Energy, Portland General Electric and Idaho Power would participate in EDAM in the current trends case, while PNM and EPE would remain in CAISO’s real-time Western Energy Imbalance Market (WEIM) but would not join a day-ahead market.

Brattle chose 2032 as the study year.

The study found that for PNM, adjusted production costs fall from $55.4 million in the current trends case to $45.4 million in EDAM and $43.9 million per year in Markets+.

Annual congestion revenues are higher in the EDAM case, at $25.6 million for day-ahead and real-time markets combined, compared with $14.3 million in the Markets+ case. Bilateral trading revenue in EDAM is $3.3 million compared to $0.7 million in Markets+, a reduction from $8.6 million in the current trends case.

EPE also sees a difference in congestion revenues between the two cases: $16 million in EDAM versus $12.5 million in Markets+, relative to $7.8 million in the current trends case. EDAM also gives EPE a big potential boost to bilateral trading revenue: $14.4 million a year in EDAM compared to $6.6 million in the current trends case. Bilateral trading revenue drops to zero in the Markets+ case.

Because of increased imports from the Four Corners trading hub in the EDAM case, New Mexico “becomes flush with low-cost power,” Tsoukalis said. EPE then has an opportunity to sell that power to TEP in the Markets+ footprint.

In response to a commission question, Tsoukalis said Brattle did not study a case in which TEP or the other Arizona utilities joined EDAM, saying the results would be almost a “no-brainer.”

“I tend to think it would skew the benefits more for EDAM, of course, by adding more to that footprint,” he said.

Building Transmission

Scott Dunbar, a partner with Keyes & Fox representing the Clean Energy Buyers Association, asked whether congestion revenues projected for the New Mexico utilities in the EDAM case were likely to fall as new transmission is built.

Tsoukalis said the congestion revenue is a signal that more transmission, or greater availability of transmission rights, would be valuable. He said more transmission would shift a number of metrics.

“If you build more transmission, my intuition would be that benefits would go up overall,” Tsoukalis said. “It just might shift from congestion revenue to adjusted production cost reduction.”

Emmanuel Villalobos, EPE’s director of market development and resource strategy, said the company is still reviewing details of the Brattle study. But a big takeaway was the $14 million in potential revenue from bilateral trading in the EDAM case.

“[It’s] really enough to kind of sway [us] back and forth between the EDAM decision and the Markets+ decision,” he said, noting the figure was potential revenue and not guaranteed.

EPE will weigh other factors such as governance and start-up costs in its day-ahead market decision. And the company may ask Brattle for analysis of additional scenarios, which could include EPE and PNM choosing different markets.

The PRC’s Aug. 28 meeting was the third workshop the commission has held on regional markets. Commissioner Gabriel Aguilera said he now plans to work with his staff on a set of guiding principles for market participation, which will come to the full commission for a vote.

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ERCOT Technical Advisory Committee Briefs: Aug. 28, 2024

ERCOT has told stakeholders it may move up the real-time co-optimization project’s go-live date from its previous September 2026 target, welcome news about a mechanism that will be integral to the future market design. 

“We’re not going live in September 2026. It’s well ahead of that,” ERCOT’s Matt Mereness, chair of the Real-time Co-optimization + Battery Task Force (RTC+B), told the Technical Advisory Committee during its Aug. 28 meeting. “There is a possibility for getting this in by the end of 2025. By next month at this time, we should have a better feel for what that date is.” 

Mereness said several sequenced issues need to be resolved before going live. They include parameters for ancillary service (AS) demand curves, readying the real-time co-optimization (RTC) simulator and market readiness. 

ERCOT’s Matt Mereness | ERCOT

“We’re on the eve of having the project schedule. Some of the details are still working out,” he said. 

Cautioned by stakeholders that RTC’s go-live date could have a large effect on forward prices, Mereness agreed. 

“I think part of it is, will the program have a date? And then there’s the risk management around it … what are the dates that have the confidence in it?” he said. “So yes, that’s part of the vetting process.” 

RTC is used by most other grid operators in North America and has been on ERCOT’s market design and policy radar for more than 10 years. The market tool procures energy and ancillary services every five minutes, automating many processes that currently are managed manually. 

A previous task force, also chaired by Mereness, secured approval for seven nodal protocol revision requests (NPRRs) and two other changes that will guide the tool’s implementation. The task force was disbanded in 2020, but the disastrous 2021 winter storm put further work on hold until 2023. (See “RTC Stakeholder Group to Form,” ERCOT Technical Advisory Committee Briefs: July 25, 2023.) 

ERCOT’s Independent Market Monitor released a report in 2018 that evaluated RTC’s effect on the market. Using 2017 as its simulated operating year, it found a $1.6 billion reduction in total energy costs; an $11.6 million reduction in production costs to serve load; a $257 million reduction in congestion costs; a $155 million reduction in AS costs; and reliability improvements due to a reduced overloading of transmission constraints and a decrease in regulation up. 

TAC Tables Remanded NPRR

Members agreed to table a nodal protocol revision request (NPRR1215) after it was remanded back to TAC by ERCOT’s Board of Directors to correct an error that led to its withdrawal. (See “Error Forces NPRR’s Withdrawal,” ERCOT Technical Advisory Committee Briefs: July 31, 2024.) 

Staff said they pulled back the NPRR after they found an error in its formula calculation. They said they have since discovered potential issues that need further investigation and requested it be tabled. 

The rule change clarifies that the day-ahead market energy-only offer credit exposure calculation zeros out negative values. 

TAC also will have to take the bifurcated part of a Nodal Operating Guide’s rule change (NOGRR245) that was partly approved by ERCOT’s Board of Directors Aug. 20. While approving voltage ride-through requirements for inverter-based resources (IBRs), the directors ordered that a board priority NOGRR be drafted to clarify hardware modification requirements and exemption standards and processes. (See ERCOT Board of Directors Briefs: Aug. 19-20, 2024.) 

The subsequent rule change will address more details around NOGRR245’s exemption process, including the ability to supplement information if a resource entity makes an exemption request by April 1, 2025; appropriate criteria for some level of hardware upgrades for a “vintage” resource to meet relevant ride-through performance requirements or whether it be granted an exemption; and details about the reliability assessment process. 

TAC Chair Caitlin Smith, with Jupiter Power, said ERCOT staff is waiting until the Public Utility Commission approves NOGRR245, likely during its Sept. 26 open meeting, before beginning work on the bifurcated portion. Staff hope to bring a final version of the subsequent NOGRR to the board’s February meeting to meet the April 1 deadline for exemption requests. 

“Having something that’s done and approved and implemented by April, that’s a big lift,” Luminant’s Ned Bonskowski said. “I’m not saying we can’t do it. I just want us to be honest with ourselves about what’s possible.” 

Smith voiced similar concerns to the board during its August meeting. 

Ancillary Services Workshop

Following the morning TAC meeting, members gathered again in the afternoon for a workshop on the PUC’s ancillary services study. The commission will use the study in reviewing the type, volume and costs of the grid operator’s four AS products and evaluate whether additional services are needed (55845). 

The PUC asked both ERCOT staff and the IMM to collaborate on the study. They reviewed AS products for reliability needs and improvements in their procurement to improve efficiency and lower costs. 

Staff aren’t recommending additional AS products for the time being. However, it has proposed exploring two potential improvements: developing a probabilistic method to calculate the appropriate quantities of non-frequency responsive non-spin and ERCOT contingency reserve service (ECRS); and determining the final AS quantities closer to the operating day, rather than annually.  

The IMM used a model with a random probability distribution to perform its analysis. It found ECRS and non-spin quantities can be “substantially” reduced while maintaining reliability. The monitor said a 1-in-10 reliability standard still can be satisfied with 50 and 35% reduced procurements for ECRS and non-spin, respectively. 

A draft study will be filed at the PUC by October, opening a comment period for stakeholders. The PUC will host a workshop on the study Oct. 31. 

Lightening the Mood

American Electric Power’s Richard Ross, who also sits on SPP’s Markets and Operations Policy Committee and does his best to boost the levity in both committees, offered Smith a method to lighten the mood among members.  

“I understand someone said earlier we don’t have fun in these meetings anymore. One of the things some of us do is force the group in unison to read the [antitrust] attestation at their own pace,” he cracked. “It does give us a smile opportunity, should you feel the need to amp up the culture of the meeting.” 

Smith responded that she was open to Ross’ suggestion. 

“I was just told that at TAC, unlike SPP, we don’t have ‘cookies and laughter,’ so we will work on that,” she said. “Someone else said we do have snickering, so with that, let’s get started.” 

Consent Agenda OK’d

TAC endorsed a combo ballot that included three NPRRs, one NOGRR and a single change to the Retail Market Guide that, if approved by the ERCOT board, will:  

    • NPRR1221, NOGRR262: Align manual and automatic firm load shed provisions; clarify the proper use and interplay of under-voltage load shed, under-frequency load shed and manual load shed; and address reliability concerns over the extent of transmission operators’ manual load-shed capabilities. 
    • NPRR1227, RMGRR181: Align defined protocol terms and add five definitions (“acquisition transfer,” “decision,” “effective date,” “gaining competitive retailer” and “losing competitive retailer”) that previously were located in the Retail Market Guide (Acquisition and Transfer of Customers from one Retail Electric Provider to Another). The NPRR also replaces the broadly titled terms “decision” and “effective date” with the specific terms “mass transition decision,” “acquisition transfer decision,” “mass transition effective date” and “acquisition transfer effective date” to provide clarity. The change also expands the “gaining competitive retailer” and “losing competitive retailer” definitions to apply beyond the mass transition and acquisition transfer processes. 
    • NPRR1236: Reflects Real-Time Co-optimization Plus Batteries (RTC+B) Task Force’s modifications to the reliability unit commitment capacity-short calculations and addresses limits in the current calculations by considering ancillary service sub-types. It changes the calculation process involving regulation down service and addresses changes required to align protocol language with recently approved NPRR1204 (Considerations of State of Charge with Real-Time Co-Optimization Implementation). 
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CAISO IDs More Challenges in Refining Interconnection Process

CAISO dove into Track 3 of its Interconnection Process Enhancements (IPE) initiative Aug. 28, as staff and stakeholders grappled with how to solve problems related to the proposal’s allocation of transmission plan deliverability (TPD). 

In California, TPD refers to the amount of transmission capacity needed in an individual study area to allow proposed generation projects in the area to reach their expected deliverability status. CAISO will allocate TPD to the most viable projects in an area, which then will be reimbursed for their needed network upgrades. 

The initiative’s Track 2 proposal, approved by the board in June, will apply to Cluster 15 of the interconnection queue and beyond, but the ISO still struggles to address the “unprecedented volume” of interconnection requests for Cluster 14. (See CAISO Board Approves Interconnection Enhancements Proposal.)  

Although Cluster 14 projects already have been studied, they’re “log-jammed” behind major network upgrades, according to the Track 3 straw proposal, causing concerns about how to allocate TPD to projects with long lead times.

The ISO’s proposal identified three main issues with the TPD allocation process. 

The first is related to TPD allocation issues for long lead-time projects with delayed deliverability network upgrades (DNUs). The second involves allocations for projects with long lead-time reliability network upgrades (RNUs). The third is for long lead-time resources that have met defined resource policy goals of the local regulatory authorities (LRAs) in California for specific technologies and project locations. 

The structure for TPD allocation prioritizes projects that have a power purchase agreement. For those with longer lead times, the window of opportunity to seek an allocation can be several years before network upgrades are complete, making it challenging for such projects to know when to enter the queue. Projects will have three consecutive opportunities to seek an allocation; if they don’t receive one, they’ll be converted to “energy-only” (EO) projects, which are not included in resource adequacy counts.  

Bob Emmert, CAISO senior manager of interconnection resources, said projects with longer timelines and needed upgrades may struggle to execute a PPA.  

“It may be difficult for long lead-time network upgrades and long lead-time generation resources to actually get that PPA or be shortlisted before they’re converted to energy only, even if the number of opportunities were increased to four,” Emmert said during the Aug. 28 workshop. “We want to at least discuss ways that we might be able to rectify that situation.”  

Proposed Solutions

For projects with long lead-time DNUs, Emmert presented a potential interim solution: increasing the number of PPAs for projects to come online as EO while waiting for Full Capacity Deliverability Status (FCDS). 

“We definitely think that offering a pathway for early interconnection for energy-only projects is critical,” said Sushant Barave, senior director of grid integration at Clearway Energy Group. “I also think this pathway has to be paired with an interim deliverability framework because that’s what makes standalone energy-only projects coming online earlier financeable.” 

“I would encourage CAISO to think about it as part of the larger solution, where, because of long lead-time upgrades, even projects that have deliverability sometimes cannot get the contractual assurance and show up early on as energy only,” Barave added.  

Other stakeholders were concerned about the proposal’s implications for storage resources.  

“I see this being a struggle for storage projects, which are a lot of the projects that are seeking deliverability,” said Soumya Sastry, senior manager of structured energy transitions at PG&E. “I think that there would be a lot of challenges from a buyer’s perspective. I don’t know if we would want to pay the same price for something that is EO.” 

The proposal also raised concerns about the uncertainty of procuring on such long timelines.  

“I think this could lead to potential over-procurement in the reliability space or just stranding projects that there’s not a need for this sort of conversion from energy only to FCDS that far in advance,” said Michael Freeman, contract origination manager at Southern California Edison. “If you’re in a market where you’re procuring for long-term assets, how are you judging when a project is going to come online or get RA at year six, year eight, year 10? … It just makes planning for reliability more difficult, and I could see projects that have that sort of option be stranded because LSEs may not want to take that sort of risk.”  

Emmert reiterated concern about the risks associated with the proposal.  

“There may be certain project conditions that are just too risky, and you would not be willing to go down that road. But there may be other projects that the risk profile is less.”  

Regarding the second issue — projects with long lead-time RNUs — Emmert suggested that contracting with projects that won’t be in operation for five to seven more years could enable such projects to obtain a TPD allocation within the three or four opportunities provided.  

“From an LSE perspective, if there’s a path forward to getting TPD and there’s certainty and a robust pool to select from, I don’t see an issue,” Freeman said.  

The third issue considers whether special TPD allocation criteria should be developed for long lead-time resources that meet defined resource policy goals of LRAs. The idea is that unique criteria could allow these projects to avoid the risk of being converted to EO before procurement begins.  

“There may be infrastructure such as offshore wind that needs to be put in place before you can even start building it,” Emmert said. “The question is, will the central procurement entity be authorized and willing to contract for these resources within the period where these resources are eligible to seek an allocation? Or should we look in another direction to try and solve this problem?” 

Stakeholders showed support for the third solution.  

“Capacity needs to be reserved for generic long lead-time resources because developers don’t invest in remote resource areas where transmission doesn’t currently exist and isn’t being planned for,” said Nancy Rader, executive director of the California Wind Energy Association. “The 10-year timeline for planning and building those is just too far out to enable a PPA, so these resources really need to be treated separately from non-long lead-time resources in the intake process.”  

The ISO hopes to publish a revised straw proposal for Track 3 by October and is targeting a Board of Governors vote in March 2025.