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October 6, 2024

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FERC Corrects Error on ERCOT Probability Assessment

FERC has responded to ERCOT’s request to correct an “incorrect statement” by making a small modification to its annual Winter Energy Market and Reliability Assessment, issued last week.

The commission Tuesday evening published a revised version of the report, correcting a passage related to ERCOT’s probabilistic assessments. Staff corrected the original language by adding “low” before probability and deleting “significant” before risk.

That changed the original sentence from describing ERCOT’s 2022-23 winter probabilistic assessment as indicating a “probability of a significant risk of declaring an EEA [energy emergency alert] Level 1” to indicating a “low probability of a risk of declaring an EEA.”

The original assessment apparently drew the attention of the Texas Public Utility Commission, which has regulatory oversight over ERCOT. A PUC spokesman said the report contained “inaccuracies” and that ERCOT had called on FERC to correct the record.

“ERCOT’s assessment reflected a ‘low’ probability of energy emergency events occurring during the expected daily peak load hour. We have asked FERC to correct this error, which they have done,” spokesperson Trudi Webster said in an email to RTO Insider.

The Texas grid operator plans to release its final winter assessment in mid-November.

In its assessment, FERC said that with above-average temperatures expected across most of the continental U.S., the country’s electric reliability appears well positioned for this winter. However, the commission singled out ERCOT, ISO-NE and MISO as being in danger of “especially tight” capacity during extreme weather conditions. (See “ERCOT, MISO Vulnerable to Winter Weather,” FERC: Natural Gas Prices to Rise During Mild Winter.)

During a press conference following FERC’s monthly open meeting Oct. 20, Chairman Richard Glick was asked whether the commission is confident ERCOT has addressed the issues from the February 2021 winter storm.

“Things have been moving in the right direction, but I think it would be premature and probably an overestimate to say everything is hunky-dory,” he said. “There are concerns going into this winter. The assessment … does discuss that ERCOT is one of the areas of concern.”

ERCOT has added winterization requirements for its members’ generating units after legislation and PUC rules passed in the wake of the winter storm. Staff dedicated to winterization now inspect generators to ensure compliance, and the PUC can also assess financial penalties on those that fall short of the requirements. Other generators have added firm fuel supply service to strengthen their availability.

The grid operator has also brought more generation online sooner and purchased additional reserve power, especially when the weather forecast is uncertain, as part of its conservative operations posture.

“The reliability of the Texas electric grid is our No. 1 priority,” Webster said.

PUC Chair Peter Lake and Gov. Greg Abbott, who appointed Lake to his post after the winter storm claimed the careers of his three predecessors, have both frequently said the Texas grid is more reliable than it has ever been.

Richard Glick (SPP) Content.jpgFERC Chair Richard Glick speaks before SPP’s board and stakeholders. | SPP

“Things are improving, but there’s still a lot of work to be done in terms of winterizing plants,” Glick said.

Twice in the last week, Glick has recommended that ERCOT interconnect with its neighbors to be able to share power during emergencies. He noted that SPP and MISO did not suffer the same problems as ERCOT because they were able to import power.

“Texas, quite frankly, they’re a little bit stubborn because they don’t want to be subject to FERC regulation, and I understand that part,” he said during last week’s press conference. “But do you really want to cut your constituents off from power because you don’t want to be subject to FERC regulation and then have people die? That’s just not the right way to do it.”

On Tuesday, Glick made his first visit to SPP’s headquarters in Little Rock, Ark. His comments before the RTO’s Board and Directors and Members Committee were starker.

“We get pushback from Texas in particular saying, ‘Well, we don’t want to be subjected to FERC regulation,’” he said. “Well, I understand that’s an important issue. But are you willing to actually have hundreds of people die? Are you willing to have massive blackouts, four- or five-day blackouts, because you don’t have power from elsewhere?”

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NYISO Monitor: Freezing Weather Could Threaten Eastern NY Reliability

RENSSELAER, N.Y. — Gas supplies to Eastern New York (ENY) could be limited during freezing weather in winter because of demand exceeding interstate pipeline capacity, resulting in a reliance on imported LNG from New England, NYISO’s Market Monitoring Unit told stakeholders last week.

Speaking to the Installed Capacity/Market Issues Working Group on Oct. 20, Potomac Economics’ Joseph Coscia said the findings suggest NYISO should adjust its resource adequacy models and capacity accreditations to reflect the gas limitations likely to occur in winter. Such constraints would force the ISO to rely on imported LNG from New England, he said, a region that itself relies on imported LNG during winter for reliability.

Coscia also said the ISO should discount emergency assistance from non-firm gas from out-of-state generators during the winter and consider the availability of oil-fired units with limited capacity to ensure grid reliability in the case of very cold days when heat demand peaks.

The analysis focused on the availability of gas to the greater region of ENY and New England because it is served by eight critical interstate pipelines, such as the Iroquois, Algonquin and TETCO pipelines; has greater constraints limiting total flows than the rest of New York; and local distribution companies have systems in the area that serve many of the consumers in the entire state.

LDC Winter Peak Demand (Potomac Economics) Content.jpgLDC winter peak demand exceeds pipeline capability (2022) | Potomac Economics

 

LDCs secure supply to meet their “design days”: the estimated maximum retail gas demand based on the historically lowest temperatures. Peak winter demand for design days hovers above 10 million dekatherms/day. Potomac found that the estimated total import capability of the interstate pipelines, excluding LNG, was roughly 8 million dekatherms/day, which is both “far below the total design day demand of the local gas utilities” and “is even below the estimated peak demand of the coldest winter seen in the past five years.”

LNG and compressed natural gas is available, but these should be thought of as limited fuels because they are restricted to “either cargoes contracted in advance” or serve as “limited storage” for short periods of time.

The analysis found that “an increasing sense of tightness of the gas system in the region” had meant that LDCs in ENY have held “large amounts of firm pipeline capacity” and are increasingly “relying on holding rights to the firm transport capability in order to satisfy design day requirements.”

ENY and New England are heavily reliant on LNG storage and imports to meet peak regional supply demands. Potomac emphasized that LNG importers generally do not “provide speculative supply or short-notice cargoes to the region,” threatening ENY’s reliability during extreme winter storms.

Potomac recommended that the NYISO resource adequacy model “discount external assistance from New England” to avoid “counting on imports from a region affected by the same set of gas constraints affecting winter reliability.”

Mark Younger, president of Hudson Energy Economics, asked Coscia if Potomac had seen “other areas of New York indicating significant concern” around gas supplies.

Coscia replied that gas bottlenecks are “primarily at the borders of the ENY and NE region.” Though it is possible that “pockets of specific generators elsewhere in the state have difficulty accessing gas,” they are “less acute outside of the ENY region.”

One stakeholder questioned the relevance of the analysis, noting that “New York has a state policy pushing for the elimination of every molecule of gas” and that this problem might “vanish” as the state “continues to electrify the heating, building and generation sectors.”

Coscia responded that “even with aggressive implementation” of state climate or energy policies, downstate New York utilities are anticipating “core gas demands to grow” over the next couple of years, so even if residential heating demands decline quicker than expected, the MMU is “focusing on the system as it is today.”

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ERO Identifies More Facility Misratings Themes

The ERO Enterprise continued its campaign against facility rating violations last week with the publication of a new report that builds on the work of NERC and the regional entities over the last several years.

The report, “ERO Enterprise Themes and Best Practices for Sustaining Accurate Facility Ratings,” aims to spread awareness among registered entities about the importance of maintaining accurate ratings of the equipment at their facilities. In the introduction, the authors note that “incorrect facility ratings can result in operating in an unknown state, uncontrolled widespread service outages and fires,” and can also make modeling the grid more difficult while hindering the planning of future expansions to the bulk power system.

Many recent penalties levied on utilities by their REs have involved violations of NERC’s reliability standards facility ratings. Just last month FERC approved a $105,000 penalty that the Texas Reliability Entity assessed against the Buffalo Gap Wind Farm because the rating for the facility did not match the utility’s documents. (See FERC Approves $105K Penalty for Texas Wind Facility Misratings.) So far this year, facility rating violations have accounted for $1.2 million in FERC-approved penalties.

4 Key Themes

NERC and the REs based their report on data that they have collected during their outreach and education efforts, as well as compliance monitoring and enforcement activities. They identified three common themes across the infringements involving inaccurate facility ratings.

First is an entity’s lack of awareness regarding the state of its equipment. This can include failure to adequately document or maintain an accurate equipment inventory, failure to understand the current carrying series equipment within its electrical system or an ineffective facility ratings validation program.

Lack of awareness can cause misratings to “go undetected for long durations, thereby potentially posing a greater risk to the reliability and security of the BPS.” The report said it may become a factor when an entity’s facility ratings program lacks internal controls for verifying and validating equipment in the field, instead relying on ratings provided by the manufacturer, or outdated diagrams and drawings. The authors recommended that entities “remain vigilant … and never assume that facility ratings issues do not exist on their systems.”

The second theme is inadequate asset and data management. In this context, asset management means the identification, management and tracking of physical facility ratings assets, while data management refers to the collection, validation and storage of data associated with ratings. Data may be spread across various locations or business groups within an entity, and moved back and forth as part of normal operations.

Failures related to data management include entities consolidating equipment in a database instead of listing it individually, or setting up programs that “do not identify and account for all necessary pieces of equipment or the equipment’s ownership in the field when determining a facility rating.”

In one instance, a transmission owner found two bundled transmission line conductors transitioned to a single conductor outside a station, wired to a switch using a single conductor because of physical constraints of the system. The utility “had situations where it failed to consider the switch configuration” and did not realize that the switch was the most limiting element of the facility.

The next identified theme is inadequate change management, involving failures by entities to document changes to equipment in the field or update their ratings documents to reflect newly installed or altered equipment. The ERO documented multiple instances of inadequate change management leading to inaccurate facility ratings, such as a generator and transmission owner replacing a transformer with a new piece of equipment with a higher rating, meaning the transformer is no longer the most limiting element, but not updating the facility’s rating.

According to the authors, failing to track, document and communicate all field changes creates “an increased risk of using inaccurate facility ratings.” To avoid this, utilities should implement strong change management processes that include:

  • requirements for data entry verification by qualified personnel;
  • a clear approval process prior to a change being implemented;
  • notifications to update equipment inventory after a change is implemented;
  • confirmation that the change was completed as planned;
  • validation through periodic reviews; and
  • checklists to verify that all necessary follow-up actions are taken after a change.

Finally, the fourth theme involves inconsistent development and application of facility ratings methodologies (FRM), referring to the methodology that each registered entity is required to have for determining facility ratings of its solely and jointly owned facilities.

An entity’s FRM can draw on many inputs, including manufacturer’s nameplates, engineering evaluations, testing or performance history, and physical or mechanical factors that might restrict a piece of equipment’s performance. However, the ERO said it has observed multiple issues in this regard, such as an entity considering only the electrical elements of a facility and failing to account for mechanical limitations. In addition, many entities fail to identify the next most limiting element in a facility, meaning that when the most limiting element is removed, they cannot quickly update the rating.

The report recommended that entities “strive to use a single consistent methodology and apply the same criteria when rating like components of a facility rather than using a mix of options.” While deviations from a single FRM may be inevitable, utilities should take care to minimize these events while ensuring that these deviations are “justified, consistently applied [and] well documented, and [that they minimize] inconsistent facility ratings.”

SERC Release Formed Report’s Basis

The ERO’s report is similar to a document released earlier this year by SERC Reliability, “Facility Ratings Themes and Lessons Learned,” which touched on similar points and even identified the same themes, with the exception of the fourth.

While the ERO-wide report does not explicitly mention SERC’s report, Tim Ponseti — the RE’s vice president of operations — said at the North American Generator Forum’s Annual Compliance Conference earlier this month that SERC had submitted its report to NERC to serve as the basis for a broader analysis. (See NAGF Attendees Discuss Facility Ratings Challenges.) He also credited the ERO with finding “a fourth theme that we missed” — likely referring to the inconsistencies in FRM methodologies.

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CARB Looks to Refine Clean Bus Rules Amid Ridership Decline

California transit agencies are enthusiastically adopting zero-emission buses, industry representatives said, but regulators are worried that ridership downturns will stall ZEB progress.

The concern is great enough that members of the California Air Resources Board (CARB) have discussed modifying a zero-emission bus regulation so that ZEB purchase requirements are tied to the availability of funding for the vehicles.

“Public transportation is in crisis,” CARB member Daniel Sperling said. “We’re asking these transit agencies not only to spend a huge amount of new money [for zero-emission buses], but also to revamp their operations.”

“We need a principle that says compliance is dependent on funding becoming available,” from federal, state or other sources, he said.

Sperling’s comments came during a CARB board meeting last month, where board members heard a report on the Innovative Clean Transit (ICT) program. CARB adopted an ICT regulation in 2018 that will phase in requirements for public transit agencies to buy zero-emission buses starting next year.

The report looked at whether transit agencies are ready for next year’s ZEB purchase requirements and concluded that they are. That’s in large part due to more than a decade of ZEB roll outs and demonstrations.

Among roughly 200 transit agencies in California, more than 50 have purchased zero-emission buses. Three agencies have fully electrified their bus fleets, including the Antelope Valley Transit Authority, which became the first all-electric transit agency in North America this year.

Out of a total of about 13,000 public transit buses statewide, transit agencies had 510 ZEBs in service and another 424 on order at the end of 2021, according to CARB. The totals include 56 fuel cell buses deployed and 62 on order.

Transit Uncertainties

But the future of public transit is uncertain. Sperling said that ridership, which had been decreasing before COVID-19, took a major hit during the pandemic and has yet to fully recover. Federal and state funds that were used to bail out transit agencies are likely to dry up, he added.

Against that backdrop, ZEB purchase requirements under the ICT regulation are set to start next year.

For large transit agencies, the rule will require 25% of new bus purchases to be zero-emission from 2023 to 2025, increasing to 50% of new bus purchases in 2026 to 2028. Requirements for smaller transit agencies start with a 25% ZEB purchase requirement in 2026 to 2028. The regulation includes credits for early ZEB purchases.

All new buses purchased by transit agencies in the state must be zero-emission in 2029 and beyond.

CARB member Davina Hurt said she’s worried about how transit agencies will meet the more stringent ZEB purchase requirements that start in 2026.

“I’m really concerned about these agencies moving into the future and meeting some of our ambitious requests,” she said. “Some of these agencies are at a financial cliff.”

Board member John Balmes said the idea of tying ZEB purchase requirements to funding availability is “a very key issue.”

“The reality of the pandemic and the decreased ridership … it’s dire,” Balmes said. “I think we need to consider a course correction.”

But “if conditions change and there’s a lot more money available for the transit agencies, I think that’s great and we can keep going full blast,” he added.

The board took no formal action on the item, which was intended as an informational report on the ICT program.

Agencies ‘Lean In’ to ZEBs

The CARB board also heard from members of the California Transit Association, a nonprofit trade organization, on their experiences with zero-emission buses.

Michael Pimentel, the association’s executive director, said the group was initially skeptical of the ICT regulation, but has decided to “lean in” to the zero-emission transition. The organization now describes itself as a leading advocate for ZEBs at the state and federal levels.

Michael Hursh, CEO and general manager of AC Transit, said his agency is running battery-electric and fuel cell buses and comparing vehicle performance. On a cost-per-mile basis, the battery electric buses are less expensive to run than diesel or hydrogen-fueled buses, he said. And the rising price of hydrogen is a concern.

But Hursh said last month’s extended heat wave and urgent demands to reduce power use raised red flags regarding battery electric buses.

“If there’s an earthquake, if there’s a massive grid-down situation, can we get the fleet out?” he said. “With hydrogen and a diesel generator, I can run my fueling station and keep my buses on the road.”

Doran Barnes, chairman of the California Transit Association’s ZEV Task Force and CEO of Foothill Transit, said there is “great enthusiasm and excitement and energy” in the transit industry for a ZEB transition.

But the industry faces challenges including the greater cost of ZEBs compared to conventional buses, in terms of vehicle cost, infrastructure and workforce expenses. In addition, ZEBs may have range limitations or not be readily available, he said.

“We’ve got to figure all of these things out, and we’ve got to do it at a rate of change and learning that’s much quicker in the next three years as we move to 2026 than we’ve seen in the past 10,” Barnes said. “That momentum’s really got to build.”

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Can New England Conserve Like California?

New England state and grid officials are refining their plans to use conservation pleas in the case of an energy emergency, buoyed by the success of California’s call to action during this summer’s heatwave.

ISO-NE hasn’t had to employ a conservation request since 2013, when a July heatwave led it to ask energy consumers to raise their AC temperatures, turn off lights and appliances, and defer chores like laundry.

But increasing worries about winter resource adequacy in the case of extended cold weather has ISO-NE thinking about the next time it might have to ask New Englanders to voluntarily cut back, and what might be different this time.

At a regional tabletop exercise that the grid operator organized earlier this month, communication with the public about its ability to help was a central topic, said Matt Kakley, spokesperson for ISO-NE.

Mallory Waldrip (ISO-NE) Content.jpgISO-NE’s lead energy security analyst Mallory Waldrip speaks at a regional tabletop exercise. | ISO-NE

“A lot of what we talked about in the tabletop and in our standard emergency planning and discussions is how do we coordinate those messages? How do we make sure that everyone from the ISO to the utilities to the government folks is in the loop on things and understand what’s going on and what the ask is?” Kakley said.

ISO-NE would be the entity that would make the decision to call for energy conservation, based on its near- and medium-term forecasts.

But with its limited reach, the grid operator would rely on help from state governments and utilities (which already have customers’ email addresses and phone numbers) to get the message out.

“Close coordination with stakeholders such as our regional grid operator, emergency management officials and our fellow utilities among others is fundamental to any emergency response, and participation in regional trainings and exercises helps us to be ready in the event ISO-NE must take emergency action,” said William Hinkle, an Eversource spokesperson.

Learning from California’s Success?

Policymakers in New England see California’s recent experience as a strong example of the power of conservation.

The state’s urgent text to residents shortly before a period of impending record electricity demand, coordinated by the Governor’s Office of Emergency Services, was widely hailed as a successful, if drastic, step to stave off potential rolling blackouts. (See California Runs on Fumes but Avoids Blackouts.)

CAISO saw demand drop by 2,000 MW just 20 to 30 minutes after the text went out.

To ISO-NE, it was “comforting,” said Kakley.

“They were able to keep demand under the level they were able to serve, and not have to resort to the extreme measure of controlled power outages,” he said. “What that really drove home, what we’ve always known, but seeing it in a real-world example, was that if you ask the public to do something, and you’re clear in what you’re asking to do, they will respond.”

New England state officials have called for the region to employ that sort of call to action if needed.

June Tierney, commissioner of the Vermont Department of Public Service, made that point at the FERC forum in Burlington, Vermont, last month.  

“Let’s not underestimate the people of the United States, she said. “Let’s not underestimate the people of New England. If they’re called upon, as millions of Californians were on their cell phones, to reduce demand immediately, they will respond.”

But ISO-NE has also acknowledged that the scenario presented in an energy emergency in the New England winter takes on a different shape: Rather than a capacity crisis lasting just a couple hours, it could be a fuel shortage that lasts as long as multiple days.

It’s a nightmare possibility that the region has been wrestling with for years, with increasing anxiety each winter, as the region continues to rely on volatile LNG markets.

“We spent a lot of time talking about how that call for conservation would be different,” Kakley said. “It’s a different kind of request and one that people haven’t spent a lot of time thinking about. We’re realizing that our messaging needs to be very clear.”

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FERC: Rush Island Plant’s Extension Essential to MISO Reliability

FERC on Monday approved an agreement that will keep an Ameren Missouri coal plant online beyond its planned retirement date to maintain MISO grid reliability (ER22-2691).

In a separate order, the commission also said that Ameren might be overcharging customers to keep the plant operating and set the matter to hearing (ER22-2721).

MISO in August filed a 12-month system support resource (SSR) designation for the 1.2-GW Rush Island plant’s two units. The grid operator said that its analysis found “no alternative available at this time to avoid the need” for an SSR agreement and said that without the agreement, it could face severe voltage stability issues that might set off cascading outages.

MISO uses SSR agreements as a last-resort measure to sustain system reliability. It said it explored generation additions, dispatch changes, system reconfiguration, operation-guideline changes, amplifying demand response or load reductions, and adding new transmission projects, all to no avail.

The Illinois Municipal Electric Agency and the Wabash Valley Power Association lodged protests at the commission, alleging that MISO’s consideration of alternatives to the agreement was unsatisfactory. The commission said the grid operator properly arrived at a “determination that no feasible alternative exists at this time that could be implemented to allow suspension of the Rush Island Units by the requested September 1, 2022, suspension date.”

FERC found that both Rush Island units are necessary despite the stakeholders’ claims that one unit will suffice. The commission said MISO’s retirement study showed transient voltage recovery issues that would violate both NERC standards and Ameren’s local planning criteria and “pose a risk to the St. Louis metro area and Peoria, Ill.” It concluded the RTO presented “sufficient support” for the SSR agreement through next summer.

However, FERC agreed with Wabash Valley and Illinois Municipal that Ameren’s proposed $9.3 million monthly SSR payment could be too steep and ordered a hearing with possible refunds. The commission also rejected Ameren’s inclusion of a 50-basis point return-on-equity adder in the monthly payment calculation, saying the ROE adder for RTO membership is reserved for transmission owners, not generation facilities.

In the interim, MISO will assign proposed SSR costs associated with the Rush Island units to load-serving entities that require their continued operation.

Ameren last year fast-tracked the plant’s closure rather than install a court-ordered wet flue gas desulfurization system by March 31, 2024, to correct Clean Air Act violations. The utility originally intended to operate Rush Island until 2039, but the 2019 ruling from the U.S. District Court for the Eastern District of Missouri cut its plans short (19-3220).

Rush Island’s units date back to 1976 and 1977. Together, they currently emit approximately 18,000 tons of sulfur dioxide annually.

MISO recommended in this year’s transmission planning cycle $120 million of new static synchronous compensators to reinforce the system with Rush Island’s retirement. Those transmission solutions aren’t expected to be in-service until mid-2025, making it likely that the grid operator will renew the SSR, which it can do on an annual basis. However, the RTO has committed to a yearly re-examination of alternatives to the SSR. (See MISO’s 2022 Tx Planning Cycle Exceeds $4B.)

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Full Requirements Customers Win Right to Use Own Storage

FERC last week ruled that three municipal power providers would not violate their full requirements power contracts by installing battery storage, which the commission determined does not count as the sort of generation they are obligated to purchase exclusively from Appalachian Power Company (APCO).

Under their agreements with APCO, Craig-Botecourt Electric Cooperative and the Virginia cities of Radford and Salem are obligated to purchase their power exclusively from the utility, aside from some pre-existing generation in the two cities.

The three entities rely on the services of Blue Ridge Power Agency, a non-profit formed to negotiate wholesale electric power purchase contracts and monitor their performance for its members. Blue Ridge filed an instant petition with FERC on Aug. 10, 2021, asking that the commission rule that use of storage is permissible within the terms of the contracts because it is not a form of generation and is not prohibited under the agreements (EL21-97).

APCO argued that, because the contracts do not allow for the installation of behind-the-meter generation for the purpose of peak shaving, they should be read with the understanding that other methods of reducing peak load, such as demand response programs, are not permissible.

APCO estimated that $8.5 million in expenses would be shifted to its other customers should the petitioners be allowed to install batteries and use them for peak shaving, largely the result of costs associated with building the transmission the utility was required to meet peak demand, but which it could not recoup through demand charges based on the highest hourly usage in a billing month.

Blue Ridge argued that, since the contracts with APCO address the potential for variation in their energy use and both cities have already participated in PJM’s demand response program, the methods of shifting their load are permissible under the contract, as long as the energy is ultimately procured from APCO.

Blue Ridge additionally contended that the contracts do not preclude its members from reducing demand, “but rather only preclude meeting that demand from sources other than APCO, and that the Blue Ridge Members accordingly retain ‘the right to use storage, demand response, load management, or other peak-shaving technologies or programs,’” the order noted.

FERC agreed with Blue Ridge with respect to the contracts with the cooperative and two cities.

“While these three agreements do not expressly mention battery storage investments, when read in context and in their entirety, these agreements support Blue Ridge’s position that such investments are permitted under the agreements,” the commission wrote.

“The agreements focus exclusively on generation, and the exclusive nature of both APCO’s status as sole provider, and each customer’s obligation to purchase generation during the delivery period from APCO alone,” the commission continued.  “The contracts define full requirements electric service as ‘the supply of firm energy to be provided by [APCO] to the customer at the delivery points, as the same may fluctuate in real time to serve customer’s retail load . . .’”

However, FERC ruled that a fourth party to the petition, Virginia Polytechnic Institute and State University, would be in violation of its full requirements agreement with APCO should it install batteries which, together with generation, would amount to more than 2.35 MW — the highest amount of behind-the-meter generation the university’s full requirements agreement allows for.

Unlike the other three contracts, the university’s agreement with APCO specifies that storage is to be considered a form of generation, a categorization the majority of the commissioners disagreed with but determined does subject batteries to the same contractual limitations as traditional generation.

Commissioners Danly, Christie Dissent

Commissioners James Danly and Mark Christie dissented from the ruling on the grounds that they did not believe that FERC should exercise its jurisdiction in a matter they believed was a contractual dispute that could have been resolved by the Virginia courts, an argument APCO made in its filings as well.

“The fact that the subject of the contract dispute happens to be battery storage units instead of bucket trucks or office equipment is no reason for us to assert jurisdiction and impose a preferred result,” Christie wrote.

The issue of jurisdiction largely centered on interpretation of three factors laid out in the Arkansas Louisiana Gas Co. v. Hall case, in which FERC declined to take jurisdiction in 1979. The majority in the Blue Ridge order determined that the commission met each requirement: possession of special expertise that makes the case peculiarly appropriate for commission decision; a need for uniformity of interpretation; and a case that is important in relation to the regulatory responsibilities of the Commission.

Danly also argued that each of the contracts should be read in the context of the Virginia Tech agreement, which was agreed upon in 2019, two years after the other three, since it was drafted prior to subsequent FERC rulings on the distinctions between generation and storage. The order, he said, could create a pathway for future petitions to seek to introduce new provisions to their contracts through the commission.

“The import of this order is that if your full requirements contract is silent as to this or that matter or if it fails to expressly prohibit a particular thing, then any such practice, might it later be at issue, can now be permitted by the commission, when it wants. This is absurd; this is not how contracts work. This decision will inevitably lead to confusion and disruption of other full requirements contracts and will encourage a slew of future petitions for declaratory orders seeking to reform extant contracts by inserting unnegotiated, uncontemplated, and unanticipated elements,” he said. “Contracting parties beware.”

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FERC Clarifies CAISO, NYISO Order 2222 Rulings

FERC on Thursday declined to rehear a case on NYISO’s Order 2222 compliance filing but clarified its comments from a June order on aggregated distributed energy resources providing ancillary services in the ISO (ER21-2460).

The commission reached a similar conclusion in CAISO’s Order 2222 compliance in an order also approved Thursday, during its monthly open meeting (ER21-2455). It denied a rehearing request by environmental and consumer groups but responded to a request by California utilities to clarify that its June order did not “modify or reverse commission precedent that wholesale sales by net metering customers are subject to commission jurisdiction.”

CAISO and NYISO were among the first to submit compliance filings last year under Order 2222, which FERC approved in September 2020 to remove barriers to the participation of DER aggregations in the capacity, energy and ancillary service markets of RTOs and ISOs.

In the NYISO case, FERC partially accepted NYISO’s Order 2222 compliance filing on June 16 but directed the ISO to file revisions related to small utility opt-in requirements, interconnection rules and other issues. (See FERC Partially Accepts NYISO Order 2222 Compliance.)

NYISO responded on July 18 with a request that FERC clarify the discussion in its June order on aggregated DERs providing ancillary services or grant it a rehearing. The ISO had proposed in its compliance filing that aggregations could provide certain ancillary services only if all of the individual DERs in the aggregation were able to provide the same ancillary service.

In its June 17 order, FERC said that “so long as some of the DERs in the aggregation can satisfy the relevant requirements to provide certain ancillary services (e.g., the one-hour sustainability requirement), we find that those DERs should be able to provide those ancillary services through aggregation, in accordance with the goal of Order No. 2222 to allow distributed energy resources to provide all services that they are technically capable of providing through aggregation.” Being “‘technically capable’ of providing a service means meeting all of the technical, operational and/or performance requirements that are necessary to reliably provide that service.”

NYISO said its system software allows aggregated DERs to provide only one ancillary service at a time, such as operating reserves, and asked FERC if it intended otherwise.

FERC said the ISO’s software limitations meant the resources were technically incapable of providing certain services and that its June 17 order did not “require NYISO to allow a heterogeneous aggregation to simultaneously make available multiple operating reserve products.”

The commission denied rehearing requests by clean energy and consumer advocates, including the Natural Resources Defense Council and Advanced Energy Economy, which argued that NYISO’s definition of a DER was not technology-neutral, as required by Order 2222, and could prohibit energy efficiency and other passive-demand resources from participating in its capacity market even though they are technically capable of doing so.

FERC disagreed with that argument, as it had in its June decision.

“NYISO’s proposal includes a technology-neutral definition for DER and therefore does not prohibit any type of technology from participating in an aggregation,” it said.

Commissioner Allison Clements dissented in part “because [the decision] affirms the majority’s prior finding that [NYISO] may exclude energy efficiency from participating in distributed energy resource aggregations without running afoul of the requirements of Order No. 2222.”

“I disagree with that decision and therefore would have granted the request for rehearing on this issue submitted by [the] clean energy and consumer advocates and found that NYISO’s definition of DER does not comply with Order No. 2222,” Clements wrote.

CAISO Clarification

In June, FERC asked CAISO to file a further Order 2222 compliance filing addressing concerns about its model for aggregated distributed energy resources, rules for participation of DERs that are customers of small utilities and other matters. (See CAISO Order 2222 Filing Needs Some Work, FERC Says.)

On July 15, Southern California Edison, Pacific Gas and Electric, and San Diego Gas & Electric submitted a request to FERC for clarification of the compliance order, which the commission granted.

The “California utilities seek clarification that the compliance order does not modify or reverse commission precedent that wholesale sales by net metering customers are subject to commission jurisdiction,” FERC said. “They argue that clarification is needed because a wholesale sale is a sale for resale in interstate commerce subject to commission jurisdiction, whether the seller is behind or in front of a retail meter. …

“They contend that, if commission policy is modified or overturned, then wholesale sales may no longer be subject to commission jurisdiction.”

In its order, FERC said that “as [the] California utilities request, we clarify that … the compliance order does not reverse or otherwise modify commission precedent.”

FERC also denied AEE’s request for rehearing of the CAISO compliance order. AEE argued that “the barriers created by the 24-hour settlement requirement run afoul of the provisions of Order No. 2222 requiring each RTO/ISO ‘to allow distributed energy resource aggregators to register distributed energy resource aggregations under one or more participation models in the RTO’s/ISO’s tariff that accommodate the physical and operational characteristics of the distributed energy resource aggregation,’” according to FERC.

The commission said it had already addressed AEE’s argument in its prior rulings, and “we remain unpersuaded by its claims on rehearing.”

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A Massachusetts Climate Group Takes its Message to NEPOOL

Another climate organization in New England has joined NEPOOL membership as it looks to add a regional lens to its work.

The Massachusetts Climate Action Network (MCAN) on Oct. 1 became the newest member of the end user category of stakeholders in the ISO-NE stakeholder organization. It joined a small group of climate and environmental advocates who have been trying to make a dent in a process they say sometimes seems tilted against them.

MCAN’s focus is largely local; its model is to support municipal chapters that often focus on specific projects within their footprint.

But the group’s advocacy against the Peabody peaker, a contentious gas and diesel plant under construction north of Boston, has led it down a rabbit hole of regional debate that its leaders felt they could not ignore.

“We’re really focused on supporting residents and taking local action,” Logan Malik, the group’s interim executive director, said in an interview. “But in order to do that, sometimes you need changes to take place at the statewide or regional level.”

Starting with the debate around ISO-NE’s minimum offer price rule (MOPR), and more recently discussions around capacity accreditation, MCAN has been paying more attention to the regional dynamics that help shape the projects they’re focused on.

“We saw this as an opportunity to engage with the various stakeholders across the region who are working on these issues day in, day out,” Malik said.

He added that one of the organization’s goals of participating is to make the information coming out of ISO-NE and NEPOOL more accessible.

“I think there’s still definitely a challenge in translating these very complex discussions into things that people understand and people can engage in,” Malik said. “Residents care about this stuff. Residents care about these decisions. And it’s very hard for residents not working fulltime in an organization like MCAN to actually understand the material that’s coming out.”

Taking on ‘Entrenched’ Fossil Interests

MCAN won’t be without friends as it starts navigating its way through what can be a confusing and intimidating stakeholder process. There are a handful of other environmental groups, like the Acadia Center, Conservation Law Foundation and Natural Resources Defense Council, that have increasingly seen NEPOOL as an important venue for their advocacy and a necessary part of their work. Malik cited all of those groups and others as allies that have helped the organization get up to speed on the regional level.

The NEPOOL stakeholder process MCAN is joining hasn’t historically been an easy place for environmental groups to gain a foothold. It’s a big time commitment, with complex meetings that take place during the week for as long as multiple days at a time. Some groups, like NRDC, have elected to hire consultants to help stay on top of the process and present their ideas.

“It’s a question of resources. The technical committees meet regularly, and the meetings can be lengthy,” said Phelps Turner, a senior attorney for CLF.

There’s also an incumbency effect that gives many of the longer-standing members advantages.

“I think that the way that the system is set up, in the way that the voting structure and [NEPOOL] operation works … there is a certain bias towards incumbency and the existing system. Trying to move in a new direction isn’t always easy,” said Bruce Ho, a deputy director at NRDC who represents the organization within NEPOOL.

Ho’s experience with the MOPR debate and other changes that he argues are needed to enable the clean energy transition and decarbonization has featured lots of pushback, he said.

“I think there’s a lot of entrenched value, a lot of entrenched economic investments and interests in the current fossil system.”

There are just six environmental organizations out of more than 500 NEPOOL members, although they also often align on issues with renewable developers and suppliers, or state officials and consumer advocates.

“I think those voices can serve as an important counterbalance in the stakeholder process, to stakeholders from the fossil fuel industry, who have historically dominated the conversation and who have a vested interest in maintaining the status quo at all costs,” Turner said.

Whether they have a meaningful impact on ISO-NE’s decision-making in the region is an open question though.

“I think there’s always room for more participation, and more diverse participation,” said Turner. “Until then, it may be hard to influence the ultimate outcome of various decisions.”

The View from NEPOOL

Groups like MCAN are welcome, encouraged and appreciated in the stakeholder process, said David Cavanaugh, chair of the NEPOOL Participants Committee.

He said that the climate and environmental groups that have previously participated in meetings have represented their interests well.

“We welcome others who are similarly willing to invest the time to understand and work collaboratively in seeking ways to address creatively the many interests and concerns at the table, and to find enduring solutions to the challenges we are now facing, including prominently the need to reliably serve the region’s energy load while addressing climate change by reducing carbon emissions from the industry,” Cavanaugh said.

He acknowledged that joining NEPOOL can be a challenge for new members.

“There is unquestionably some ramp-up time to learn about the members and their various interests and concerns, and to understand the issues facing the region and alternative ways to address those issues,” Cavanaugh said.

But he laid out a series of ways that the organization aims to get them up to speed, from targeted orientation sessions and trainings, to elected sector officers tasked with helping new members in their sector.

“In my experience, new members will find that representatives of the NEPOOL participants and NEPOOL counsel who have been in the region for decades are generally very willing to educate and fill in knowledge gaps,” he said.

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FERC Clarifies When Board Appointees Make Companies Affiliates

FERC on Thursday ruled that it will deem companies it regulates as affiliates if one nominates its own members, investors or employees to another’s board of directors.

The commission issued two orders regarding separate transactions that both required it to determine whether the companies involved — TransAlta (NYSE:TAC) and Brookfield Asset Management (BAM) (NYSE:BAM) in one, and Bluescape Energy Partners and Evergy (NYSE:EVRG) in the other — were affiliates of each other. FERC applies stricter oversight of affiliated companies and their transactions to, for example, determine market-based rate authority and screen against market manipulation.

“It’s very important that we have the kind of insight to understand when parties are affiliated so we can do a better job of regulating” them, FERC Chair Richard Glick said during the commission’s monthly open meeting. “If one company … essentially names board members to another company [who are] affiliated with the first company, then we’re going to deem that an affiliate relationship.”

TransAlta and Brookfield

In one of the orders (EC22-45), the commission addressed an application for a change in control affecting Canada-based TransAlta, based on a shift in company holdings controlled by BAM, a global investment firm.

TransAlta has an extensive presence in U.S. electricity markets through its two power marketing divisions and its ownership of several wind assets and the 730-MW coal-fired Centralia Generation Station in Washington. BAM is affiliated with six power marketing companies in the U.S. and with other entities that own or control generation assets across the country.

In 2019, BAM affiliate Brookfield BRP Holdings (Canada) Inc. purchased debt securities in TransAlta with an option for converting to an equity interest in TransAlta’s hydroelectric assets in Alberta, Canada.

In their application to FERC, filed in March 2022, TransAlta and BAM said the debt securities did not confer any equity voting rights in TransAlta and are not convertible into an equity interest in any of TransAlta’s U.S. assets. But the transaction did result in the expansion of TransAlta’s board from 10 members to 12, two of which would be nominated by BRP while it holds the debt securities.

The debt securities agreement also included a “standstill agreement” that established barriers to control during a “standstill period” expected to end around May 1, 2022. That agreement included a number of provisions, including a restriction on BRP or its affiliates (including BAM shareholders) acquiring more than 19.9% of TransAlta’s shares, engaging in any takeover activities, effecting other restructurings and asset sales, and seeking to obtain additional representation on the board, among other activities.

“In addition, applicants state that the standstill agreement provides that any voting rights associated with shares in TransAlta owned by [BRP] or its affiliates must be exercised in favor of the board’s management nominees and voted in accordance with any recommendations by the board on all other proposals and matters, including director appointments and removals, at annual shareholder meetings,” FERC noted in its order. “Applicants argue that as a result, [BRP], shareholders and other BAM affiliates currently have no discretion to vote any common shares, except solely with respect to a board-recommended extraordinary transaction that would result in a person acquiring more than 50% of the outstanding common shares.”

The companies told FERC that BAM shareholders increased their aggregate holdings in TransAlta’s common shares to 10.1% in March 2020 and now own 13% of the shares. Before expiration of the standstill agreement, they sought the commission’s approval for BAM affiliates to own, with power to vote, 10% or more of common shares.

“Applicants state that because termination of the standstill agreement would result in a change in control over the TransAlta companies if shareholders, together with any other BAM affiliates, own 10% or more of the common shares, applicants request commission authorization for the proposed transaction and associated change in control over the TransAlta companies,” FERC wrote.

The companies contended that, despite BAM affiliates already exceeding 10% ownership, the standstill agreement ensured that BAM and its affiliates could not control TransAlta or its subsidiaries.

“Therefore, applicants argue that a change in control requiring prior commission approval will not occur until the expiration of the standstill provisions, anticipated to occur on or about May 1, 2022,” FERC wrote. “We disagree.”

The commission specifically disagreed with TransAlta and BAM citing FERC’s 2009 decision in Cascade Investment, L.L.C. (EC09-78) to support their contention that the initial investment that elevated BAM and affiliate ownership above 10% did not result in a change of control because of the limitations set out in the standstill agreement. It noted that the Cascade proceeding involved a standstill agreement that included provisions intended to restrict Cascade Investment’s ability to control a public utility through ownership in a holding company, Otter Tail Corp. Those provisions included limiting Cascade’s holding to less than 20% of Otter Tail’s voting securities, a commitment not to seek a seat on board of either Otter Tail Corp. or Otter Tail Power, and a commitment not to influence Otter Tail’s operations or the price at which it sold power.

The TransAlta/BAM proceeding differed in key ways, the commission said:

  • The application in Cascade was filed before the acquisition of 10% or more voting securities in Otter Tail, whereas BRP and other BAM affiliates had acquired 10.1% of TransAlta in March 2020, which is above the threshold provided in FERC’s blanket authorization of such transactions.
  • Unlike in Cascade, the BAM affiliates have placed two directors on TransAlta’s board, arguing that holding two seats is insufficient to gain control of the board given its large size and independent composition. But the commission pointed out that it has concerns with structures where the investor itself will be represented on the board, “which confers rights, privileges and access to nonpublic information, including information on commercial strategy and operations,” as noted in FERC’s other decision issued Thursday (see below).
  • Although the TransAlta standstill agreement contains limitations on the ability of the affiliates to vote shares, it does not contain explicit prohibitions regarding the ability to influence the day-to-day operations of TransAlta, unlike in Cascade.

“We find that contrary to the requirements of [Federal Power Act] Section 203, applicants failed to file a timely request for the disposition of a public utility and acquisition of securities,” the commission wrote. “Specifically, applicants were required to receive commission approval prior to the acquisition by shareholders of greater than 10% of the outstanding TransAlta shares. While we take no further action here, applicants are reminded that they must submit required filings on a timely basis or face possible sanctions by the commission.”

Still, the commission did approve the companies’ application, finding the change in control would have no impact on competition, rates and regulation, nor would it result in cross-subsidization.

Bluescape and Evergy

In a similar proceeding, the commission found that Dallas-based Bluescape is “individually an affiliate” of Evergy and directed the Midwest utility’s operating companies to submit additional information within 30 days so that FERC can process a notice of change in status (ER20-67, ER20-113, ER20-116).

FERC said that Evergy’s appointment of C. John Wilder, Bluescape’s executive chairman, to its board of directors presented a “concern” the commission previously expressed in a proceeding involving CenterPoint Energy. The commission said then that it had an issue with “structures where the investor itself would be represented on the board through the appointment of the investor’s own officers or directors, or other appointee accountable to the investor, in order to support a finding of control.”

“Where an investor’s own officer or director … is appointed to the board of a public utility or holding company that owns public utilities, the investor itself will have those rights, privileges and access, and thus the authority to influence significant decisions involving the public utility or public utility holding company,” FERC said. “As a result, we find that the appointment of a non-independent director from Bluescape to the Evergy board rebuts the presumption of lack of control … and that Bluescape is deemed to be an affiliate of Evergy.”

The commission directed Evergy’s subsidiaries to update their asset appendix with all of Bluescape’s energy affiliates and their associated assets, as well as their horizontal and vertical market power analysis with their affiliates’ generation and transmission assets and inputs to electric power production.

Evergy’s subsidiaries in September 2020 filed a notice of change in status regarding changes to their upstream ownership. This came shortly after Evergy said it would remain a standalone company after exploring several purchase offers by other companies. (See Evergy Releases Standalone Plan Details.)

FERC twice filed deficiency letters in 2021 requesting more information on the upstream ownership. Public Citizen and the Communications Workers of America filed a joint protest in November 2021.

In its Thursday order, the commission found another investment management firm, Elliott Management, was not an Evergy affiliate. It said the record indicated Elliott owns less than 10% of Evergy’s outstanding voting securities and said Public Citizen did not present enough evidence to rebut the presumption of lack of control under federal regulations.

FERC ruled that Elliott’s appointment to Evergy’s board, former U.S. Sen. Mary Landrieu (D-La.), is independent and not compensated by Elliott.

Wilder and Landrieu were named to the board in February 2021, with Wilder also chairing the Finance Committee.

Tyson Slocum, director of Public Citizen’s Energy Program, still applauded the ruling as a “a win for consumers, market integrity and protection from corporate raiders.”

“For utilities with captive ratepayers, all affiliates can only engage in financial transactions with the utility at arm’s length,” Slocum said in a statement. “This prevents an investor from selling services at inflated costs, and then having the utility recover those inflated costs from ratepayers. Today’s order ensures that banks, hedge funds and private equity funds that seek to control a utility’s board cannot engage in such abusive practices.”

Speaking to reporters after the commission’s meeting, Glick said, “This is about consumer protection. If you have affiliates engaging in self-dealing, and we have no way of knowing it or seeing it because we don’t consider two entities affiliates, we’re not going to be able to protect consumers adequately enough.” He also said the rulings would provide certainty to companies so that they know when they would be considered affiliates.