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November 2, 2024

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FERC Staff Finds Dynegy Manipulated 2015 MISO Capacity Auction

FERC’s Office of Enforcement has concluded that Dynegy “knowingly engaged in manipulative behavior” during MISO’s 2015/16 capacity auction — rejecting the commission’s 2019 order that cleared the company.

As a result of  enforcement staff’s heavily redacted 85-page report, the commission will now consider briefs on whether Dynegy should refund $429 million to Illinois ratepayers (EL15-70).

The commission announced a second look at Dynegy’s behavior in June after the D.C. Circuit Court of Appeals ruled that FERC hadn’t sufficiently supported its decision to accept the Southern Illinois capacity price produced in the 2015/16 auction. (See FERC to Take 2nd Look at 2015 MISO Capacity Auction.)

OE’s report, issued in September, said Dynegy participated in a fraudulent scheme to “corner the relevant portion of the market, consisting of those megawatts that MISO would likely need to clear the auction and that could be offered into the auction at a zero price if not held on Dynegy’s unsold books.”

Dynegy, which was acquired by Vistra in 2018, took four steps outside of market fundamentals to make sure it could set prices in the capacity auction, FERC said. Staff described the utility’s actions in the report’s redacted portion and said Dynegy made sure it increased the odds that one of its resources offered into the auction at a non-zero price would become the marginal resource and set the clearing price for Southern Illinois.

FERC staff said Dynegy’s malfeasance began a year ahead of the 2014/15 auction when it purchased 3,152 MW in MISO Zone 4 in Illinois, and 1,241 MW in a neighboring zone, from Ameren. FERC said Dynegy failed to set the price in that auction, when no zone cleared above $16.75/MW-day.

“After failing to set the price in the 2014/15 auction, Dynegy saw an opportunity to set the price in the 2015/16 auction,” FERC staff said.

In the April 2015 auction for 2015/16, MISO saw clearing prices of $3.48/ MW-day or lower in all zones except Zone 4, which  cleared at $150/MW-day.

2015-16-MISO-PRA-results-(MISO) Alt FI.jpg2015/16 MISO PRA results | MISO

 

The OE report was compiled using evidence from a three-year, non-public FERC investigation that included testimony from 11 Dynegy witnesses and more than 500,000 pages of documents. The original investigation, which began on a vote by the entire commission in 2015, was ended by then-chair Neil Chatterjee in 2019 without giving notice to his fellow commissioners.

That prompted a dissent by current Chair Richard Glick when the commission voted 3-1 in July 2019 that Dynegy had not committed market manipulation and that the $150/MW-day clearing price was just and reasonable. The commission said a clearing price isn’t unjust simply because it’s higher than expected (EL15-70).

Glick contended Chatterjee prematurely “cut short” the investigation. Chatterjee said he was acting within his purview as chair and did not need to consult with his colleagues. (See FERC Clears MISO 2015/16 Auction Results.)

Staff’s report gives no indication of Chatterjee’s reason for closing the probe. The report said the original investigators agreed in mid-2017 that Dynegy had engaged in market manipulation and that the company’s responses in 2017 and 2018 failed to change staff’s conclusion.

Vistra Rejects Staff Findings

Vistra said last week it “strongly disagrees with staff’s allegation in this report” and contends that it “acted in accordance with all applicable market rules and procedures.”

“This matter has thoroughly been investigated several times and adjudicated,” Vistra spokesperson Meranda Cohn said in an emailed statement to RTO Insider. “When FERC cleared Dynegy in 2019, they found that no market manipulation occurred and that the MISO 2015/2016 capacity auction results were just and reasonable. No new facts, circumstances or evidence have come to light in the three years since this decision.”

Cohn said in the “years-long process, the same allegations have been periodically repeated but have routinely been disproved by experts and independent regulatory authorities, including FERC and the Independent Market Monitor for MISO.”

Financial Impact not Disclosed

OE staff calculated the financial impact of Dynegy’s actions,  but the details were redacted.

Public Citizen and the Illinois Attorney General asked FERC in February to recoup $428.6 million, plus interest from June 1, 2015, to load serving entities in Illinois in MISO Zone 4 to reimburse their customers.

Tyson Slocum, the director of Public Citizen’s energy program, told RTO Insider he believed the company raised capacity costs by about $100 million, an estimate he said was “confirmed by reams of non-public Enforcement staff conclusions.”

In addition to the $100 million in direct rate impacts, Slocum said, there are “hundreds of millions of dollars in cascading rate impacts.”

In ordering OE staff to reconsider Dynegy’s actions in June, the commission said it would determine any remedy in a later phase of the proceeding. On Oct. 7, the commission ordered initial briefs on the remand report by March 1, 2023, and reply briefs on May 1, 2023.

Cohn said that Vistra will “continue to vigorously defend Dynegy’s conduct.” She said FERC staff’s actions are “unwarranted, without merit, beyond the scope of the remand order and inconsistent with prior decisions and action by FERC.”

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NY CAC Debates the ‘Nomenclature’ of Natural Gas

ALBANY, N.Y. — New York Climate Action Council (CAC) members clashed last week over definitions of natural gas during discussions of potential edits to the Gas System Transition portion of its draft scoping plan.

Jessica Waldorf, director of policy implementation at the New York Department of Public Service, on Nov. 21 presented a summary of feedback given at earlier sessions, which included proposals to both change the term “fossil gas” to “natural gas” and to use the term “fossil natural gas” to differentiate from renewable natural gas (RNG) in the plan.

Waldorf explained that part of the thinking is that the distinction struck a middle ground between members who want the term “fossil natural gas” while addressing members’ concerns around public perception of the use of the term.

RNG refers to biogas produced by a variety of processes, such as anaerobic digestion or capturing agricultural waste emissions. Critics of labeling it “renewable” say it is misleading, as it is not produced naturally, and argue that “recycled” or “sustainable” would be better substitutes. According to EPA, “RNG is a ‘term of art,’ and there is not at present a standard definition.”

Some CAC members expressed opposition to the proposed revisions, however, based on the fact that RNG projects can still result in increased emissions.

Although he believed the proposal was a fine compromise, Bob Howarth, a professor at Cornell University, thought that too much weight was being given to RNG, which he said was an untested resource whose decarbonization role would likely be limited.

Raya Salter, executive director of the Energy Justice Law & Policy Center, expressed discomfort with the proposal, saying that the fossil fuel industry wants us to move forward with untested fuel models.

Meanwhile, supporters of the proposal argued that the distinction would enable flexibility within the scoping plan and that any debate was moot because these wider disagreements would not be resolved by the council.

Donna DeCarolis, president of the National Fuel Gas, stressed that it was important that the scoping plan include all available fuel options for the state to meet its energy goals.

Gavin Donohue, CEO of the Independent Power Producers of New York, agreed with DeCarolis’ assessment and added that he objected to the inclusion of the word “fossil” anywhere in the scoping plan because the word is not contained nor defined anywhere within the Climate Leadership and Community Protection Act.

Thomas Falcone, CEO of Long Island Power Authority, told the CAC that he supported the compromise, understanding both sides of the argument, but that it was more of a symbolic issue that, although important, would not be solved through the scoping plan.

Peter Costello, general counsel of the New York State Energy Research and Development Authority (NYSERDA), explained that the scoping plan is not a legally binding document, but, from a legal standpoint, these clarifications would help inform those who may be required to legally contextualize these terms in an effort to avoid any legal action.

Doreen Harris, CEO of NYSERDA, argued for the CAC to include a glossary at the end of the scoping plan that defines unresolved terminology or better contextualizes contentious topics. Paul Shepson, dean of the College of Marine and Atmospheric Sciences at Stony Brook University, agreed, saying readers could be confused.

Climate Protesters in NY (Allison Considine Sierra Club) Alt FI.jpgClimate protesters call for the end of gas usage in New York. | Allison Considine, Sierra Club

 

The debate around natural gas was fortuitous, as the start of the meeting was interrupted by protesters carrying a long string of photographs and signs calling for the end of gas usage across New York. Protesters told NetZero Insider that the photos were of individuals calling the governor’s office throughout the day to demand for the elimination of gas from the CAC’s final scoping plan.

“The actions we take today will have major implications for our future,” one protester said, adding that they were disheartened by the CAC’s debate around the “nomenclature” of gas.

Only two more CAC meetings remain, with Dec. 5 being the final day to resolve any outstanding items before the final vote on the scoping plan on Dec. 19.

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NY PSC Accepts NYSEG Proposal to Address Gas Leak Fire

The New York Public Service Commission this month approved New York State Electric and Gas’ (NYSE:AGR) proposed plan to address the installation errors that caused a natural gas explosion that destroyed a two-family home in the village of Brewster last February (22-G-0425).

The PSC on Nov. 17 directed NYSEG to repair and remediate all errors identified in the 450 randomly selected inspection sampling sites no later than May 17, 2024, and submit quarterly progress reports.

The commission indicated that it may fine NYSEG a “civil penalty not exceeding the greater of $250,000 or ‘[0.03%] of the annual intrastate gross operating revenue of the corporation’” for each established violation.

The incident at 2592 Carmel Ave. was caused by “an underground gas leak, which contributed to a residential fire and ultimately led to the complete destruction of the duplex residence,” according to the PSC.

The commission’s investigation determined that efforts to prevent the fire were complicated because NYSEG employees lacked proper equipment to effectively respond to the leak, installed the nearby tapping tee improperly and failed to maintain reliable record keeping.

Specifically, NYSEG informed the PSC it could not “ascertain from its own historical records the specific personnel involved in installing the PermaLock Tapping Tee” related to February explosion, leading the PSC to write that additional “opportunistic inspections” are likely.

NYSEG intends to perform inspections “before the 2023 winter season, and subsequently completing the project by spring 2024,” but if additional “anomalies and defects are detected,” the company “may be required to increase its sampling size.”

If additional evidence is found that NYSEG has not maintained reliable “record keeping pertaining to piping and component installation,” the PSC “has the regulatory authority to order changes to internal utility protocols and procedures.”

The commission stressed that it expects that “utilities maintain their distribution systems and components to ensure public safety and that they avoid or replace components whose failure can harm to public.”

In a statement to NetZero Insider, the PSC said that they are currently focused “on testing before any next steps are decided” in response to questions about whether it planned on tightening the rules or regulations surrounding tapping tees.

Earlier this year, one person died and many more were injured due to gas leak explosion in a Bronx three-story home.

Meanwhile, National Grid recently agreed to pay approximately $650,000 to settle a 2018 natural gas explosion in Herkimer County that destroyed an entire home and settled a 2018 gas explosion in Long Island for nearly $2 million (18-G-0716 and 15-G-0298).

According to a report released by the U.S. Public Interest Research Group’s Educational Fund, a gas pipeline incident occurred roughly every 40 hours in the U.S. between 2010 and 2021, with 2,600 of those incidents being serious enough to report to the federal government and resulting in the death of 122 people.

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NJ’s $2M Agrivoltaics Study Advances

A more than $2 million New Jersey study that will look at whether crops and cows can thrive next to bifacial vertical and rotating solar panels is moving ahead even as the state is nearly a year behind in the legislature’s timeline for implementing rules that will govern dual-use solar projects, also known as agrivoltaics.

The New Jersey Agricultural Experiment Station (NJAES) is on track to complete construction by April, David Specca, assistant director of Rutgers University’s EcoComplex, said at the New Jersey Farm Bureau’s annual conference in Princeton on Nov. 15.

Crop trials will begin immediately after, and initial results from the study could be ready in a year, said Specca, who heads the Rutgers Agrivoltaics Program.

The study will be carried out at three sites around the state, two of which will study the growth of crops beneath a 337-kW, single-axis tracking system of 695 solar panels that rotate as the sun moves from East to West. Aside from improving energy production efficiency, the rotation will give the crops — including soy beans, hay and vegetables — a more evenly spread exposure to shadow and sun than would fixed panels, Specca said in an interview with NetZero Insider.

The third site, with 378 solar panels and a capacity of 179 kW, will study the experience of cows grazing next to vertical bifacial panels. “Our observations are going to be of the grass and forage crops [that] are being grown for feed for the animals,” he said, adding that researchers will also look at how the cows react, such as whether they graze contentedly in that environment and whether they prefer the shade from the panels or direct sunlight.

Agrivoltaics, which enables the land below or around solar developments to be used for farming, has proven successful in other parts of the country but is still largely an unproven quantity in New Jersey. The study comes amid friction in New Jersey and other states over the merits of using farmland for solar projects, with some farmers wary that solar projects will eat up farmland and weaken the farming sector, and others concluding that solar projects could provide already struggling farmers with another revenue stream — especially if that can be done side by side with crop cultivation or animal rearing.

The tension over solar use of farmland is heightened in some parts of New Jersey by the loss of farmland to the voracious demand for logistics and e-commerce warehouses that serve the Port of New York and New Jersey and the New York market. But that pressure also heightens the attraction of agrivoltaics, which can provide revenue without destroying farms or permanently assigning farmland to another use, as do warehouse developments. (See NJ Solar Push Squeezes Farms.)

Peter Furey, executive director of the Farm Bureau, said that Specca’s presentation showed “some real promising activity.” He said he has no doubt that farms and solar projects can cohabit the same space and be productive, but that doesn’t mean the concept will work.

“Is it financially feasible?” he said. “Well, the answer to that remains to be seen.” Given the high cost of solar equipment and installation, a key factor will be the incentive structure laid out by the New Jersey Board of Public Utilities (BPU), he said.

Developing Rules

What that will look like is still pending. More than a year after Gov. Phil Murphy signed a law, A5434, that required the BPU, in consultation with the state Department of Agriculture, to adopt rules and regulations for a pilot dual-use solar program within 180 days, the program has yet to emerge. The legislation set aside $2 million for the agrivoltaics study.

The pilot program, as set out in the law, would establish a framework for the “construction, installation and operation of dual-use solar energy projects that are connected to the distribution or transmission system owned or operated by a New Jersey public utility or local government unit and located on unpreserved farmland.”

The law limits the annual capacity of all projects in the program to 200 MW and will restrict each project to no more than 10 MW. The rules will define the incentives available, and the law requires the BPU to convert the pilot to a permanent program between 36 and 60 months after the rules are approved by the BPU and Agriculture Department.

BPU staff are currently “in the process of developing the program and do not have a timeline to share for release at this time,” said spokesman Peter Peretzman.

More imminent are the rules for another program that will affect farmland use, the Competitive Solar Incentive (CSI) program, which are expected to be released in the coming weeks. The program uses a competitive solicitation process to allocate incentives for grid-scale solar projects, those larger than 5 MW. Draft rules released earlier in the year included guidelines on what land can be used for such projects and the steps needed to mitigate the impact on the land of an approved project. (See NJ Tries to Balance Solar Growth vs. Farmland Protection.)

Furey said the agricultural and solar sectors are waiting for them to drop.

“The law put parameters limits on how much farmland can be used for industrial-scale solar,” he said, and the official release of the rules will start the process of developers thinking “about whether they want to come out on farmland.”

Grid Connection Impact

New Jersey’s initiative comes amid other advances toward implementing dual-use programs in the Northeast. Sheep grazing on solar array lands has already shown some success, and the possibilities of pairing solar with beekeeping, crops and even cattle is under scrutiny, according to speakers at the Renewable Energy Vermont conference in October 2021. (See Overheard at REV2021: Cattle, Crops, Bees Trend in Agrivoltaics.)

New York State Energy Research and Development Authority (NYSERDA) said in August that developers that incorporate agrivoltaic strategies would get a “favorable scoring credit” in the state’s annual solicitation for large-scale renewable energy. (See NY Scorecard Makes Way for Utility-scale Agrivoltaics.)

Dual-use solar has proven successful in other, sunnier and drier parts of the country, Specca said. But its efficacy in New Jersey, “where there’s less sun but a lot of indirect light” because of the light bouncing off the frequent cloud cover, is still not clear, and the impact of that is part of what the study will determine, Specca said.

One thing that is already clear in New Jersey is that the feasibility of an agrivoltaic project may be determined by where it is in the state, and the availability of connections to the grid, he said.

“A lot of the areas in rural parts of the state don’t have very big wires, big electric service. And so it really limits how much [electricity] can be exported,” Specca said. That won’t affect grid-scale projects, which often install their own cabling to the grid, but for smaller farms looking to set up solar projects, “that’s where these constraints would come in,” he said.

Dual-use Legal Battle

The BPU’s delay in setting up an official agrivoltaics pilot comes as the agency is in litigation with the developers of two private projects: the 18.8-MW Washington Solar Farm in Washington Township, and the 17.6-MW Quakertown Solar Farm in Franklin Township.

In each case, the project has secured local approvals and about half of it is up and running. The two developers want the BPU to award them incentives under the state’s Transition Incentive Program, funds that would enable them to develop the second halves of the project as a mini-pilot program that will study the impact and benefits of agrivoltaics.

Part of the BPU’s argument against the effort, however, is that the state pilot program will soon be in place and there is no need for a small independent pilot to run in “parallel.”

The BPU denied the two projects petition for incentives on Dec. 1, 2021, agency spokeswoman Tracey Munford said.  An appeal of the board’s order “is pending before the Appellate Division,” she said, adding that the BPU would not comment further.

The developers argued that dual-use solar meets the criteria of an “innovative technology” under program rules, and so should be eligible not only for incentives, but for a high level of incentive, under the program rules.

“Petitioners urge the BPU to consider dual-use agrivoltiacs as an innovative technology that will play an important role in New Jersey’s solar future,” an attorney for the two projects, Mark S. Bellin, wrote in a June 4, 2021, petition to the BPU, laying out the developers’ case.

“The establishment of these pilot projects would give the BPU the ability to monitor and evaluate the performance of the dual-use solar farm as more than just a concept, more than just a classroom experiment,” Bellin wrote. The project would also provide a “a substantial means of delivering a meaningful number of megawatts towards the state goals and preserving farmland simultaneously.”

“The projects represent a short-term solution for the evaluation of the dual-use agrivoltaic concept at the same time as it promotes local agriculture, provides employment and municipal revenues,” according to the petition. “Creating this dual-use pilot program is a successful scenario for every stakeholder affected by the process.”

The land parcels beneath the two projects are no longer being used for farmland, Bellin argued, adding that “each of the property owners has indicated that if the complete buildout of the solar farm is not permitted, each will develop the property residentially or commercially.”

As a result, “the ability to preserve the ground for agriculture will be forever lost unless the solar use is preserved,” he wrote.

But the board on Dec. 1 rejected the petition, saying it was “duplicative and moot.”

“The goals and benefits of establishing a robust dual-use pilot program simply cannot happen in the limited context of evaluating the projects here, no matter how well intentioned,” the board said. It added that allowing the developers to create a pilot program “in parallel” to the one that the BPU will develop under the new legislation would “unnecessarily strain agency resources.”

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State Regulators Endorse New Demand Curve in MISO Capacity Auction

The Organization of MISO States (OMS) has released a position statement in support of a downward-sloping demand curve in MISO’s capacity auction.

MISO’s state regulators drafted language that said the existing vertical demand curve may not sufficiently value the reliability contribution of excess capacity and might cause load-serving entities to over-rely on the RTO’s market to procure capacity. They also said the vertical design might be hastening resource retirements and is likely not sending price signals that would spur investment in new generation.

The regulators said the grid operator’s current resource adequacy “has led to capacity shortfalls in part of the MISO footprint, may fail to maintain appropriate price signals and may not lead to reliability going forward.”

MISO has been seriously weighing adopting a sloped demand curve since early summer, after the spring capacity auction laid bare a 1.2 GW capacity deficit across MISO Midwest. (See MISO Promises Stakeholder Discussions on Capacity Auction Reform.)

The Kentucky Public Service Commission and the Public Service Commission of Wisconsin abstained from voting on the statement, and the Manitoba Public Utilities Board did not participate in drafting the letter. However, the Kentucky commission added that it “strongly believes that MISO must immediately endeavor to address the most prominent issues with its capacity market, through actions which include, but are not limited to, implementing a downward-sloping demand curve.”   

OMS said it “looks forward to contributing to the final design of a revised demand curve” and said its “support of a revised demand curve is contingent on reviewing and approving MISO’s final proposal.”

OMS also warned that it will oppose a minimum offer price rule in the capacity auction.

During the OMS’ annual meeting in October, North Dakota Commissioner Julie Fedorchak said the organization’s members still need to know the final shape of the proposed curve and understand the options for states to self-supply or opt out in meeting their reliability needs.

Fedorchak also said the sloped demand curve’s formation should be done in conjunction with other resource adequacy measures, like improved scarcity pricing and a new generation valuation that can provide necessary system attributes. She said a sloped demand curve is “just one tool” in the quest for resource adequacy.

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West Could Save $1.2B a Year in CAISO EDAM

CAISO’s proposed extended day-ahead market (EDAM) for its Western Energy Imbalance Market could generate $1.2 billion a year in benefits, or 60% of the savings of a West-wide RTO, if it encompassed the entire U.S. portion of the Western Interconnection, a new study commissioned by CAISO found.

The report by Energy Strategies was similar to a study the consulting firm performed last year that found a single RTO covering the entire U.S. portion of the interconnection could save the region $2 billion a year in electricity costs in test-year 2030. The study was prepared for state energy offices in Colorado, Idaho, Montana and Utah with funding from the U.S. Department of Energy. (See Study Shows RTO Could Save West $2B Yearly by 2030.)

The firm’s EDAM study for CAISO built on that work. It examined operational savings obtained through more efficient dispatch and management of transmission capacity, lower operating reserve requirements, and the removal of transmission wheeling costs in the market footprint. It also looked at capacity reductions from regionally shared planning reserve requirements met through geographic diversity of generation resources and peak demand.

“The methodology and the underlying databases used to perform this assessment were consistent with those that my firm used to perform the state-led market study for a consortium of Western states,” Energy Strategies Principal Keegan Moyer said Friday in a meeting hosted by the Committee on Regional Electric Power Cooperation (CREPC). CREPC is seeking to play a larger role in Western market formation. (See CREPC Seeks to Become an OPSI for the West.)

The EDAM study differs from the state-led study because it dealt with a specific market proposal instead of a generic RTO framework, Moyer said.

“The framework that we assume here is really just based off of a sharing of resources, assuming planning reserve margins stay consistent, and we just begin to plan for a consolidated peak relative to individual peaks,” he said. “It’s really quite simple. It’s just a regional arbitrage of non-coincident peaks.

“There are, of course, other energy benefits that were not captured in this analysis,” he said. “So, for example, an EDAM could produce price signals that improve the efficiencies of transmission planning. That would be helpful to see a day-ahead price process to plan the transmission grid better, but that benefit isn’t captured here.

“Markets also tend to increase access to public-policy renewable resources,” Moyer said. “The reason for that is that you don’t have to wheel them across the system and/or you have different settlement points or different transaction options that are typically seen in SPP and MISO and help to increase that offtake optionality for those resources. So, it just provides better access to those low-cost wind regimes and solar regimes.”

The Western Energy Imbalance Market (WEIM) operates in real-time to share lower-cost and renewable resources among its participants, which now number 19. It has generated nearly $3 billion in benefits since it launched operations eight years ago. (See WEIM Benefits Top $500M, Near $3B Total.)

The fast-growing WEIM produced $739 million in savings for its 15 participants last year and $325 million in 2020 for its then-11 members. Energy Strategies said the EDAM would more than double the average of $525 in annual benefits from the past two years.

California would be the single largest beneficiary, with about $309 million in benefits in 2030, it said. All other Western states combined would save $886 million in 2030, including operational and capacity savings.

“An EDAM footprint across WECC causes California operational costs to decline by 6.2% from the status quo,” the firms said.

The operational-only benefits of the EDAM would equal 78% of the operational savings from a single all-encompassing Western RTO, as modeled in the state-led study, it said. Including capacity savings, the EDAM would achieve 60% of the benefits of a Western RTO.

The report bolstered CAISO’s sales pitch to Western entities to join the EDAM once it is approved.

CAISO fast-tracked the EDAM stakeholder initiative this year amid competition for Western market share by SPP, which is pursuing its own day-ahead Markets+ program and a Western RTO.

In a Nov. 14 meeting, CAISO presented its draft final proposal for EDAM with hopes of finalizing it next month and seeking approval from its Board of Governors and the WEIM Governing Body in February. (See CAISO Finalizing Plan for WEIM EDAM.)

“Some of the design is still in flux, but we’re kind of at the tail end of the design phase,” CAISO COO Mark Rothleder said at the start of Friday’s CREPC meeting. “Hopefully these additional data points, in terms of the value proposition of EDAM, help in the final stages of the process and really understanding its total value proposition.”

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Legislators, Stakeholders Pan Proposed ERCOT Market Design

Texas lawmakers and ERCOT stakeholders did not hold back last week as they took their first shots at the Public Utility Commission’s proposed redesign of the grid operator’s market.

“The end loser is the end user,” Sen. Donna Campbell (R) said during a Thursday hearing of the Senate Business and Commerce Committee. “This plan is so convoluted, [and] a long timeline to be put into place, that it’s a setup for failure for everybody.”

Campbell was one of several senators who cast doubt on the PUC’s proposals, chief among them the performance credit mechanism (PCM). The design would require load-serving entities to buy performance-based credits from generation resources that meet reliability standards. It has been widely portrayed as throwing extra money at dispatchable generators and ignoring cheaper renewable resources.

The PCM is one of six market designs the commission has asked ERCOT stakeholders and the general public to provide feedback on by Dec. 15. The commission only rolled out the designs earlier in November after months of analysis and modeling by two consulting firms. (See Proposed ERCOT Market Redesigns ‘Capacity-ish’ to Some.)

The performance credits must be produced during the highest reliability risk hours to meet the reliability standard. LSEs can purchase the credits, awarded to resources through a retrospective settlement process based on availability during the riskiest hours, according to their load-ratio shares during those same periods. This allows generators and LSEs to trade credits in a voluntary forward market, the consultants said. Generators must participate in the forward market to qualify for the settlement process.

San Francisco-based Energy and Environmental Economics (E3), which was paid $614,000 for its work, recommended a forward reliability market that has been called a “straight-up forward capacity market.” Other designs it analyzed included an LSE reliability obligation and a backstop reliability service that the PUC first proposed last December.

Charles Schwertner (Business Commerce Committee) Content.jpgTexas Sen. Charles Schwertner | Business & Commerce Committee

“To be quite frank, I don’t see … a requirement for new generation,” B&C Committee Chair Charles Schwertner (R) said. “That’s what I think we need to be focusing on: … ensuring we get what we need as a state. The bottom line is we need more dispatchable thermal generation because of the changing characteristics of the world and the federal pieces of law that allow for non-dispatchable to be really incented. Texas has to respond.”

The state’s politicians have focused on new dispatchable thermal resources since the February 2021 storm, despite the fact that they, like all resources, failed to perform during the event. PUC Chairman Peter Lake said E3’s analysis recommended that the PCM’s reliability payments only go to “truly reliable sources” that can commit in advance. He said that by reserving revenues for those resources, the PCM’s expected costs are $200 million cheaper than ERCOT would be expected to pay in 2026 “in the absence of any reform.”

Schwertner asked Lake how fast Texas would see the 5.6 GW of gas-fired capacity that E3 said would be on the system by 2026.

“As always, it depends on a number of variables, [the] first of which the generators would tell you is regulatory certainty,” Lake said, noting E3 expected it would take three or four years to build out the ERCOT system. “Some generators have expressed to us that once they have regulatory certainty, they’ll start building generators concurrently.”

“Are they prepared to come before us today and promise they’ll do that?” Schwertner asked.

“I’ll leave that to them,” Lake responded.

“Yeah, they’re not going to be here today,” Schwertner said.

The lawmakers zeroed in on the costs of the proposed designs and whether they will incent the dispatchable generation. E3 said the recommended designs would improve ERCOT’s loss-of-load expectation (LOLE) to 0.1 day/year by 2026 at an incremental cost of $460 million over the current energy-only construct’s total customer costs of $22.3 billion. A hybrid design combining the backstop reliability service and dispatchable energy credits would be most expensive at an incremental increase of $920 million a year.

Carrie Bivens, ERCOT’s Independent Market Monitor, said the E3 report doesn’t accurately model the operating reserve demand curve, the market mechanism that values the market’s operating reserves based on their scarcity and reflects that value in energy prices.

“This will understate the future revenues of the energy-only market and therefore alter the build and retention signals for resources,” Bivens said. She said E3 also overstates generator retirements by 2026 at 11 GW, resulting in an LOLE that is higher than it should be.

“We don’t see 11,000 MW of retirement. … That affects many of the conclusions throughout the report,” Bivens said.

She allowed that the PCM could be designed to send appropriate price signals “consistent with competitive market principles,” but the backstop reliability service would be costly because it would immediately sideline about 5 GW from the energy-only market and withhold it at the price cap, she said.

“That’s economic withholding and that will serve to increase energy revenues in the short run,” Bivens said.

The IMM has recommended that ERCOT develop a two- to four-hour day-ahead capacity product to account for the increased uncertainty associated with intermittent generation, load and other factors. It says the product could be deployed to bring online longer lead-time units when the grid operator detects operating conditions are “departing from expected conditions.”

Speaking for Texas Industrial Energy Consumers’ commercial customers, Katie Coleman said she shared Bivens’ concerns. She said the E3 report’s newest recommendations are “new spins on old concepts … essentially, the Northeastern-style forward capacity market.”

The PCM “is still fundamentally creating an electricity tax where customers are being mandated to pay a certain amount to generators. All the complexity in this report is just figuring out what’s the size of that tax,” Coleman said. “None of these proposals guarantee any new investment. None. The PUC does not have the authority to command capital. You can create incentives based on reports from a consultant, and you can hope that the capital markets respond, but there is no guarantee that they will. … If they don’t, what happens is customers pay a penalty price.”

“It seems like the loser is always the end user, and this is getting really, really expensive,” Sen. Lois Kolkhorst (R) said. “We can come out with all these proposals, but nobody’s willing to really say, ‘I’m going to do that.’ So, there’s market uncertainty.”

Lake responded to the repeated comments and questions about increasing costs to ratepayers with the same message, saying, “We can deliver 10 times improvement in reliability for roughly the same or even lower cost to our consumers in the absence of action.”

Once it receives stakeholder input next month, the PUC plans to issue its final market design, which will then be vetted by lawmakers early next year.

“I’m looking forward to see what the marketplace and the public tell us,” Lake said.

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California PUC OKs $1B EV Charging Program

The California Public Utilities Commission last week increased the state’s multibillion-dollar commitment to transportation electrification by approving a $1 billion, five-year effort to provide charging infrastructure for electric vehicles.

Approximately 70% of the funds will be dedicated to charging medium- and heavy-duty vehicles; the rest will be for light-duty EV charging at or near multifamily housing complexes, with priority given to investments in low-income, underserved and tribal communities.

“This decision marks what I think is an important milestone in our role in promoting transportation electrification and achieving the state’s very ambitious climate goals,” said Commissioner Clifford Rechtschaffen, who led the effort.   “Transportation emissions, as we often hear, are the state’s largest share of greenhouse gas emissions. They’re also responsible for the largest share of harmful air pollutants such as NOx, which causes ozone, and particulate matter, which has very harmful health effects.”

The 220-page decision adopting a Transportation Policy and Investment Plan also is meant to consolidate and streamline the CPUC’s efforts to fund transportation electrification by revamping the piecemeal approach it has taken in a dozen decisions since its first EV-funding rulemaking in 2009, Rechtschaffen said.

“The decision today results from over three years of hard work by staff and very engaged stakeholders,” he said. “Until now our electrification funding decisions came as a result of individual and really ad hoc applications for programs by each of the utilities. These programs weren’t especially well coordinated” and were often slow to win approval, requiring evidentiary hearings and long decision-making processes.

The CPUC has approved $1.8 billion over the years for “a whole host of utility programs, [including] light-duty and medium-duty market segments, workplaces, forklifts, school buses and many more. But as we gained more and more experience in this space, we thought it better to replace this ad hoc approach with something that’s more uniform, more streamlined and hopefully faster, and that’s what’s been developed here.”

Developments in state EV policy made funding programs more urgent, he said.

Gov. Gavin Newsom issued an executive order in September 2020 requiring that all new light-duty vehicle sales be zero-emission vehicles by 2035 and all new medium- and heavy-duty vehicle sales to be zero-emission by 2045. The California Air Resources Board adopted similar regulations in August as part of its Advanced Clean Cars program.

In October 2021, the CPUC, California Energy Commission (CEC) and the governor’s Office of Business and Economic Development met jointly to weigh the need for an additional 1.1 million light-duty public and shared EV chargers to meet the state’s transportation decarbonization goals, requiring a rapid acceleration in the spread of EV charging infrastructure by 2030.

An estimated 157,000 chargers will be needed for medium- and heavy-duty vehicles, the CEC found in its first Electric Vehicle Charging Infrastructure Assessment in July 2021.

The CPUC decision sought to address those needs through rebates for EV infrastructure.

“This decision adopts a long-term transportation electrification policy framework that includes a third-party-administered statewide transportation electrification infrastructure rebate program and directs the California electrical corporations, specifically, Pacific Gas and Electric, Southern California Edison [and] San Diego Gas & Electric … to jointly fund the program and associated activities,” the decision adopted Thursday said.

“The transportation electrification framework and rebate program further state policy promoting decarbonization and will continue to do so, as the supporting technology and policy mechanisms continue to mature,” it said.

In addition to the utility and ratepayer investments authorized by the CPUC, “billions of dollars in approved federal and state funds will support California’s [transportation electrification] infrastructure,” the decision said.

“As a result of the federal Infrastructure Investment and Jobs Act of 2021, for instance, California will receive $383 million in funding for [transportation electrification] infrastructure,” it said. “The act authorizes an additional $2.5 billion for ZEV infrastructure available in competitive grants nationwide.”

The CEC approved $1.4 billion for EV and hydrogen vehicle charging infrastructure over three years in November 2021.

And the past two state budgets committed a total of $10 billion to accelerate the state’s transition to ZEVs, with much of the funding dedicated to supporting medium- and heavy-duty fleets and disadvantaged and low-income communities. (See Calif. Governor Proposes Spending $10B on EVs.)

“California is leading the world in the zero-emission vehicle revolution, and this $1 billion investment will continue building out the state’s charging infrastructure to make the transition to electric vehicles easier than ever,” Gov. Gavin Newsom said in a statement following the decision.

“This complements the $10 billion package we enacted to build out the infrastructure and make it more affordable for Californians to make their own transition to electric vehicles, part of our overall $54 billion California Climate Commitment,” Newsom said. “These collective efforts are exactly how we will make our zero-emission transportation future a reality, cutting pollution and driving economic opportunity for Californians.”

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NY TOs Seek Clarification on ROFR for Upgrades

New York transmission owners have proposed tariff amendments that would clarify their ability to exercise a right of first refusal (ROFR) for public policy transmission (PPT) network upgrade facility (NUF) upgrades identified in the interconnection study process.

FERC in March approved tariff changes that confirmed TOs could exercise a ROFR for upgrades that are proposed by other developers, but they lacked provisions on whether this applied to upgrades identified later by NYISO as necessary to reliably interconnect a project (EL22-2-001). (See FERC Approves ROFR for NY Transmission Upgrades.)

The Operating Committee on Thursday recommended that the Management Committee and Board of Directors authorize NYISO to file the proposed revisions, presented at the meeting by Stu Caplan, partner at Troutman Pepper, which represents the eight TOs.

In a statement to RTO Insider, Caplan said the proposed revisions would “merely apply a similar mechanism to upgrades that are identified in the interconnection process for the public policy transmission projects that are selected by the NYISO board.”

The revisions are the “logical extension of the process FERC approved in March of this year for upgrades identified at the project proposal stage,” he said.

Caplan told stakeholders that the proposal would replace a bilateral process that lacks certainty and timelines, provide for a transparent process that closely replicates approved standards, and define the ISO’s role in identifying which of the NUF components might qualify as an “upgrade” subject to a ROFR.

The TOs also want to make sure the rules are clear amid NYISO’s ongoing PPT project solicitation for interconnecting offshore wind. (See “Offshore Wind,” NYISO Stakeholders Propose Three Areas for Public Policy Transmission.)

“It is the only current solicitation for a public policy transmission projects, and the first project that may result in the identification of upgrades in the interconnection process for a public policy transmission project,” Caplan said.

During Wednesday’s Business Issues Committee meeting — where the proposal was also presented — Howard Fromer, who represents the Bayonne Energy Center, asked whether NYISO had expressed support for the changes.

Caplan answered that the ISO has said the TOs are “free to carry this forward as a TO-led effort.”

This response was followed up by NYISO attorney Brian Hodgdon, who said that “nothing has jumped out as an immediate concern” to the ISO.

The proposed amendments now move to the Nov. 30 MC meeting for approval.

Winter Capacity Assessment

NYISO expects sufficient capacity margins for this winter but anticipates continued year-to-year declines as more fossil fuel generators retire.

The ISO told stakeholders that that they expect a total of 477 MW worth of generation to be deactivated and a total of 672 MW of new generation to be added during the upcoming seasonal assessment period.

SRIS Scopes Amended

The OC unanimously approved revisions to the system reliability impact study (SRIS) scopes for 35 generation projects, which the ISO identified as possessing evaluations that could either be removed, were redundant or could be conducted later.

NYISO had recommended that these previously OC-approved SRIS scopes be narrowed to expedite interconnection processes and streamline transmission studies (See NYISO Identifies 35 Projects for Narrowed SRIS Scope.)

Intermittent Resources Update

For the first time, NYISO shared the total nameplate value of installed intermittent power resources in the New York Control Area:

  • Land-based wind: 2,191 MW
  • Behind-the-meter solar: 4,123 MW
  • Front-of-the-meter solar: 74 MW

NYISO promised to expand this list to more intermittent resources, such as OSW, as they are installed in greater amounts, and promised to consider including battery storage in the future.

BIC & OC Elections

NYISO stakeholders unanimously elected Scott Leuthauser of Hydro Quebec Energy Services and Greg Yozzo of Central Hudson Gas & Electric as the new vice chairs of the BIC and OC, respectively.

[Editor’s Note: An earlier version of this article incorrectly attributed Brian Hodgdon’s quote to Brian Hurysz.]

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FERC Partially Grants Z2 Protests Against SPP

FERC last week partially granted three complaints by SPP members alleging
the grid operator violated its tariff’s terms and
generator interconnection agreements (GIAs)
and engaged in unduly discriminatory and
preferential practices related to its revenue
crediting process under Attachment Z2 (EL19-75, EL19-96, EL19-93).

The commission, however, rejected a similar complaint from Oklahoma Gas & Electric (EL19-77).

EDF Renewables, Enel Green Power North America, NextEra Energy Resources and Southern Power filed a joint complaint in May 2019 under three sections of the Federal Power Act. They argued that they are entitled to revenue credits associated with transmission service that could not have been provided but for the use of network upgrades for which they paid.

Under Attachment Z2, SPP transmission customers that fund network upgrades can be reimbursed through transmission service requests, generator interconnections or upgrades that could not have been honored “but for” the upgrades. FERC in 2020 approved the RTO’s request to replace revenue credits with incremental long-term congestion rights. (See FERC Approves SPP’s 2nd Go at Dropping Z2 Credits.)

The developers argued their companies had together funded, through their respective GIAs, almost $95 million in network upgrades owned by SPP transmission owners on the RTO’s system. The first of the upgrades became operational in 2010, they said, but SPP took until 2016 to add the software required for Z2, collecting charges for service that relied on network upgrades.

In their complaint, the developers pointed out that FERC said in a 2016 response to an SPP waiver request that the grid operator had already determined that they are eligible for revenue credits associated with their funded creditable upgrades.

FERC agreed with the complainants that SPP had violated the tariff, GIAs and the filed-rate doctrine, but it denied the remaining allegations. It also declined to set the proceeding for hearing and settlement judge procedures and to grant the developers’ requested relief, that being the full revenue credits and interest for transmission service SPP provided over the creditable upgrades since 2010. The commission said the underlying facts were “materially the same” as a D.C. Circuit Court of Appeals ruling in an OG&E complaint against SPP.

“We believe that exercising our authority under [Section 309 of the Federal Power Act] under these circumstances would be inappropriate for the same reasons,” FERC said.

FERC Commissioner James Danly agreed in a concurring statement to all four orders, writing that “FPA Section 309 cannot be invoked to provide equitable exceptions or retroactive modifications to the filed rate. … It is not a matter of discretion.”

The commission used the same arguments and reached the same decisions in complaints filed in September 2019 by Cimarron Windpower II.

It relied on some of those arguments in accepting and rejecting parts of Western Farmers Electric Cooperative’s August 2019 request that it be able to recover and retain revenue credits that it said it was entitled to under its network integration transmission service agreement and Attachment Z2. FERC found the attachment does not guarantee full cost recovery for network upgrades “but merely provides the opportunity to recover such costs.”

FERC rejected OG&E’s complaint, filed in May 2019, that being required to refund revenue credits related to the use of OG&E’s transmission facilities would violate Attachment Z2, the filed-rate doctrine, and the sponsored upgrade agreement between OG&E and SPP. The utility had also argued SPP must pay restitution if it required the revenue credits be refunded.

The commission responded by saying the upgrade agreement does not supersede the tariff, as OG&E suggested, because the agreement expressly incorporates the tariff. SPP does not have the revenue credits to provide as restitution to OG&E; those funds are with the transmission customers, who cannot be invoiced for credit payment obligations because of the tariff’s one-year billing adjustment limitation, FERC said.

SPP had been trying to replace Z2 credits since 2016, when controversy arose after the grid operator identified eight years of retroactive credits and obligations that had to be resettled after staff failed to apply credits. (See SPP Invoices Lead to Confusion on Z2 Payments.)

The commission granted the grid operator a retroactive waiver of its tariff so that it could invoice transmission service customers for Z2 credit payment obligations dating back to 2008. However, it reversed course in March 2019, saying its original decision was prohibited by the filed-rate doctrine and the rule against retroactive ratemaking.

FERC in March 2019 issued a voluntary remand of the waiver following a D.C. Circuit ruling in a separate waiver case involving PJM. The court ruled in 2021 that the commission acted correctly in reversing the retroactive waiver. (See DC Circuit Upholds FERC Ruling on SPP Z2 Saga.)