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November 18, 2024

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Utilities Oppose NJ BPU Plan Limiting EDC Storage Ownership

Public Service Enterprise Group (NYSE:PEG) and three trade groups told the New Jersey Board of Public Utilities (BPU) on Friday that utilities should play a greater role in owning and operating storage facilities than the one allowed under a proposal by the agency.

During an over three-hour hearing into the storage plan that attracted 300 participants, PSEG pushed back on the BPU’s plans to limit utility participation in order to encourage private investment and ownership of the new facilities that the state hopes to develop as part of its plan to have 2,000 MW of storage in place by 2030.

The BPU’s proposed Storage Incentive Program (SIP), released on Sept. 29, would go to privately owned and operated storage, consistent with New Jersey’s “restructured competitive market structure.” But “there will also need to be a robust effort by EDCs [electric distribution companies] to ensure that the grid is capable of connecting storage devices at the distribution and transmission levels,” the proposal says.

“Thus, while the New Jersey SIP does not propose to allow for utility ownership or operation of devices, EDCs will play a key role in building the grid infrastructure necessary to enable the effective dispatch of energy storage devices,” it says.

“So it wouldn’t be just ‘OK, the utilities can just install and ratebase’” the development of new storage, explained Paul Heitmann, a BPU staffer who presented the proposal at the hearing.

But a PSEG representative argued that given the “urgency” of reaching the state’s goal, utilities should be able to do more under the plan.

“We believe that the board needs to use every available resource to meet this challenge,” said Kate Smith, managing counsel for PSEG’s state regulatory group. “And we respectfully suggest that the these goals may not be feasible without more participation from the EDCs and that the EDC should be a resource that should be more a part of this New Jersey SIP solution now.”

Smith said the utility believes “that we need to be more of a part of these solutions from a utility deployment standpoint.” She noted that PSEG in 2018 filed a proposal for the utility to develop 35 MW of storage. That plan, in which PSEG proposed to spend $180 million, is still pending, and the utility has agreed to put it on hold while the BPU develops its policy.  

“We don’t believe that the goals expressed here, and the plan that’s put forth here, are mutually exclusive to utility investment,” Smith said. “We think that the EDCs can support and complement private investment.”

Storage is ‘Critical’

The hearing, the first of three to be held on the SIP, is part of the BPU’s effort to jumpstart the development of a storage sector after several years of inactivity. The next meetings are on Nov. 4 and 14.

The state Energy Master Plan in 2019 said the state would need 9 GW of storage capacity to manage its clean energy goals, and the state Clean Energy Act, enacted in 2018, said that the BPU should create a process for putting 600 MW of storage in place by 2021 and 2,000 MW in place by 2030. Yet the state today has only about 500 MW in place, much of which is decades old. (See NJ Lagging in Energy Storage Progress.)

The SIP sets a target of building 1,000 MW of four-hour-plus storage by 2030 and is part of a two-pronged approach to reaching the 2,000-MW goal. The remaining 1,000 MW would come from the Competitive Solar Incentive (CSI) program, which is designed to provide incentives for grid-scale solar projects, along with co-located storage. Final rules for the CSI program are expected to be released this year.

Storage is widely seen as a paramount element needed to manage electricity supply without relying on fossil fuel as intermittent renewables increasingly dominate the resource mix.

“Whether it’s the board’s energy [plan], or New Jersey’s Energy Master Plan, or any number of other pathways to 100% clean energy, energy storage is really a critical element in keeping the grid balanced and making sure that we can do the clean energy transition on time and on budget,” Abe Silverman, executive policy counsel for the BPU, told the hearing.

The BPU’s plan would provide incentives for both utility-scale and distributed projects. About 30% of the incentives would be paid to storage projects as fixed annual incentives, with a set value per kilowatt-hour of capacity. The remainder of the incentives would be paid through a “pay for performance” mechanism and tied to the environmental benefits.

Speaking at the hearing, Sarah Steindel of the New Jersey Division of Rate Counsel said the BPU needs to closely monitor the cost of the plan and look beyond ratepayers for funding, such as federal infrastructure money and private research funding.

“We need a plan for how much we’re going to spend on this, including the costs of utility infrastructure, and how much measurable non-speculative benefits we’re going to get from this,” she said. “The board’s well aware that many ratepayers are already stressed. They’re already paying for solar, offshore wind, nuclear subsidies” and electric vehicles. “And we need to think carefully about the money we’re spending and how we’re spending it.”

Seeking an Additional Utility Role

Other speakers also said they were not convinced that allowing solely private investment in storage would enable the state to reach its storage targets, and they advocated for utilities to be able to participate more.

“Given the magnitude of the state’s storage goals — in addition to efforts for electric vehicles, energy efficiency, peak demand reduction, renewable targets, and the need to ensure reliability and resiliency — EDC ownership should remain a viable option because of the expertise and knowledge the EDCs have about their unique systems,” said Christopher Wehr, staff analyst for FirstEnergy (NYSE:FE), parent of Jersey Central Power & Light. “And they’re kind of best suited to identify the areas where these strategic investments will provide the benefits to customers.”

That view was echoed by trade groups including the New Jersey Utilities Association, the New Jersey Alliance for Action and New Jersey Energy Coalition. Allison McLeod, public policy director for the New Jersey League of Conservation Voters, encouraged the BPU to look for an additional role for the utilities, saying that “their participation could be a valuable resource to the board and to the overall efforts to electrify.”

Too Little Support Early on

Other speakers focused on the allocation of incentives in the proposal.

Scott Elias, director of  Mid-Atlantic state affairs for the Solar Energy Industries Association (SEIA), questioned the impact of what the SIP proposal describes as a “declining block structure” for allocating incentives. The program would set capacity blocks at a certain incentive, and once the BPU has allocated a block of incentives to storage projects, a new block would open at a lower incentive rate. BPU officials say the system would enable the agency to assess the demand for incentive’s to build storage capacity at certain rates and adjust it if there are too few applications at particular levels.

Elias said that SEIA is concerned at the “size and cadence of the capacity blocks.”

“Backloading most of the capacity to later years and later blocks means that a single grid supply project, for instance, could eat up the entire capacity” for a year, he said.

Lyle Rawlings, president of the Mid-Atlantic Solar and Storage Industries Association, said he also believes that there needs to be more incentives in the first two years of the program. In addition, his organization is concerned by the SIP’s plan to allocate incentives to develop three times as much storage from grid projects as from distributed energy projects. Given that the BPU plans to secure half of its storage development from solar-tied storage in the CSI program, which would also come from grid-scale projects, the state is giving too little focus on the distributed energy sector, Rawling said.

“There should be a much greater emphasis on distributed” energy storage, he said. With “distributed generation, there’s a lot of pent-up demand ready to go. So this can quickly be deployed to meet the goals.”

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Overheard at RFF Net Zero Economy Summit

WASHINGTON — Decarbonizing the hardest-to-decarbonize industries will likely involve some failures, said Geraldine Richmond, the Department of Energy’s undersecretary for science and innovation.

“We have to accept that some things are going to fail, that things are not going to go out as fast as we want. But that’s because we’re moving hard and we’re trying to do the best we can,” Richmond said at Resources for the Future’s Net Zero Economy Summit on Thursday. “But if you don’t take those risks, you’re not going to get anywhere. … So, we’re just going to have to suck it up and keep going. It can’t stop us.”

Geraldine Richmond 2022-10-20 (RTO Insider LLC) Content.jpgGeraldine Richmond, DOE | © RTO Insider LLC

Tackling industrial decarbonization is now widely recognized as essential to U.S. and global efforts to cut greenhouse gas emissions to net zero by 2050, and it has become a regular part of the agenda for any clean energy conference. At RFF’s event, discussions ranged from steel and cement to international aviation.

During an industrial decarbonization panel, both Richmond and Alan Krupnick, industry and fuels program director at RFF, argued for the value of the lessons learned from failure. Krupnick pointed to the Petra Nova carbon capture project, a much hailed project at a coal plant in Texas, which received about $190 million in DOE funds and closed down in 2020.

Referring to funding for carbon capture in both the Infrastructure Investment and Jobs Act and the Inflation Reduction Act, Krupnick said, “Even failures can provide us learnings. … What we have to do … going forward, we have to expect failure. We have to learn from it and then move forward.”

The DOE’s Earthshots initiative is aimed at solving some of the core challenges of industrial decarbonization, such as the Hydrogen Shot’s goal of cutting the price of green hydrogen to $1/kg within the decade and the Industrial Heat Shot’s effort to reduce emissions from industrial heat processes by 85% by 2035.

The goal, Richmond said, is “to take everything from a discovery science all the way to the applied science and demonstration, so they can pass them off to deployment.”

Each of the shots has a goal, she said, that has “in mind a cost, has in mind efficiency, has in mind stumbling blocks that we have to get over in order to make progress. In the past the Department of Energy hasn’t been as coordinated as it is right now with regards connecting the discovery science to the applied science. … Now we’ve gotten tight; we’re rolling so that we can make sure that the discoveries get all the way to deployment.”

‘A New DOE’

With the midterm elections looming, Krupnick said the DOE is creating challenges of its own in its effort to get the IIJA and IRA funds out the door as quickly as possible “before the possible change in control of Congress and before a possible change in the presidency to the Republicans.”

Alan Krupnick 2022-10-20 (RTO Insider LLC) Content.jpgAlan Krupnick, RFF | © RTO Insider LLC

Referring to the DOE’s recent funding announcement for hydrogen hubs, he said, “we’ve taken the discipline of the market in making decisions across technologies, and we’ve moved it basically to DOE, [which] has to pick winners out of let’s say there might be 30 or 25 hydrogen hub proposals, and only a fraction of that will get go/no-go decisions for the next round. … It puts a lot of responsibility on DOE to make correct choices.” (See DOE Opens Solicitation for $7B in Hydrogen Hubs Funding.)

Still another factor in the funding process is President Biden’s Justice 40 initiative, which requires that 40% of the benefits from federal funding go to low-income and disadvantaged communities.

“It’s important for us to make sure that we are putting these facilities in places that have had their factories shut down,” Richmond said. “So, we’re really paying a lot of attention to that, whether it means we’re thinking about putting a nuclear plant where there was a coal mine so that it provides jobs for workers in that place.

“It’s a new DOE,” she said. All basic science programs at labs and universities that apply for funding “must put [in] a plan on how you’re going to be inclusive in your operation. … That means the students that you’re going to train for the future, those that have been marginalized, those that have been left out in the past because they couldn’t afford to, for example, go to graduate school, you have to show what you are going to do to get those students into the workforce.”

Cement

Sean O’Neill, senior vice president of government affairs for the Portland Cement Association, an industry trade group, talked up his organization’s roadmap to make the cement and concrete industry net zero by 2050. The processes involved in making cement require high temperatures, generally provided by coal and carbon capture utilization and storage which “is a critical part” of the PCA’s roadmap, O’Neill said. “We cannot reach our goals without CCUS,” he said, while also noting that the industry is experimenting with other, lower-carbon fuels, such as biomass and natural gas.

Sean ONeill 2022-10-20 (RTO Insider LLC) Content.jpgSean O’Neill, Portland Cement Association | © RTO Insider LLC

But the one thing O’Neill says his members are not talking about is cutting back on production, particularly in light of the need for cement and concrete for infrastructure projects funded by the IIJA. “It’s not a conversation we’re having,” he said. “The conversation that we’re having is how can we continue to meet infrastructure needs in this country, in the world, while also looking to decarbonize the process.”

One example, he said, is Portland limestone cement, which has a higher limestone content and lower carbon intensity than traditional cements. But the industry is still struggling to get it included in project specifications, O’Neill said. Instead of “prescriptive specifications” for big infrastructure projects, he called for “performance-based specifications … [that] will drive the market for our low-carbon cement and concrete.” (See Challenges Loom for Decarbonizing Concrete.)

Looking ahead, O’Neill said the industry is focusing on “what can we do to ensure there is a market for these materials. A lot of it has to go to standards and specifications. … At the end of the day, a contractor or owner who’s going to be constructing an asset, they want to have the confidence that the lower-carbon concrete that they’re using to build whatever they’re building will perform.”

Aviation

International aviation is notoriously hard to decarbonize “because lightweight liquid transportation fuel is pretty tough to beat when it comes to the challenge of lifting a heavy aircraft off the ground,” said Annie Petsonk, assistant secretary for aviation and international affairs at the U.S. Department of Transportation.

Even most “sustainable” fuels are carbon-based, Petsonk said during an on-stage conversation with Billy Pizer, RFF’s vice president of research and policy. “They, when burned in the engine of the aircraft, emit carbon dioxide. … But what sustainable aviation fuels are better for the environment is on a lifecycle basis from the time that your feedstock was produced to transporting the fuel to the airfield.”

Developing standards for that analysis took the Carbon Offsetting and Reduction Scheme for International Aviation (CORSIA), an international body, seven years, she said.

Annie Petsonk 2022-10-20 (RTO Insider LLC) Content.jpgAnnie Petsonk, DOT | © RTO Insider LLC

Another longstanding challenge has been how to allocate emissions from international flights. “If the plane is taking off in one country and landing in a different country, whose emissions are they — the emissions of the country of departure, the country of arrival? The [nationality] of the aircraft or the airline … may be different. How about the people on the plane?”

Earlier this month, the International Civil Aviation Organization, an UN agency, adopted a long-term “aspirational goal” of net-zero emissions for the industry by 2050, “with the [provision] that each country implement it in its own way,” Petsonk said. At the same meeting, CORSIA also set an emissions reduction baseline for international aviation of 85% of 2019 emissions beginning in 2024.

“What this means is that, for the first time, global aviation has both a near- and mid-term goal from now to 2035 … and a long-term goal, which is a really important signal to send, the 2050 goal, since aviation is a long capital stock industry,” she said. “It takes many years to develop [a plane], test it, fly it and [put] it into production and keep it in production for decades.”

The international lifecycle standards are being used as a baseline for the IRA’s tax credits for sustainable aviation fuels, Petsonk said. The tax credit starts at $1.25 per gallon “if the fuel is at least 50% better than fossil fuel on a lifecycle basis.”

It goes up a penny per gallon “for every percentage point improvement in lifecycle [emissions] up to completely carbon neutral,” she said. “We’re already seeing a terrific market response to this. … We’re hearing a lot from investors,” who already want the tax credit extended beyond the IRA’s 10 years, she said.

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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.”