NYISO did not identify any new near-term reliability issues in its third-quarter Short-Term Assessment of Reliability (STAR) released Friday, but it does anticipate significant load increases in western and central New York that could warrant more attention depending on how a previously identified supply shortfall in New York City is addressed.
In its previous STAR in July, the ISO identified a potential shortfall of up to 446 MW by 2025 because of peaker plants retiring to comply with state Department of Environmental Conservation regulations to limit nitrogen oxide emissions. (See NYC to Fall 446 MW Short for 2025, NYISO Reports.)
Last week’s STAR notes that NYISO has reduced that figure by 20 MW, but “this potential reduction does not eliminate the need and has a negligible impact of the findings in” last quarter’s report.
More significant, it said, “is the inclusion of additional large load projects primarily in western and central New York, many of which are currently undergoing a load interconnection study.” It expects the state’s large loads to increase by about 500 MW by 2025, reducing the state’s reliability margin to less than 100 MW during normal operating conditions. “The rapid growth of large load projects poses a risk to the future reliability of the New York grid if it is not matched with the equivalent addition of new resources,” NYISO said.
According to NYISO’s 2023 Gold Book, the large load projects are mostly new cryptocurrency mining and data centers. They also include the planned 1,250-acre Science & Technology Advanced Manufacturing Park (STAMP) in Genesee County in the west and a green hydrogen facility in Massena, along the Canadian border in the north.
Projected summer large load peak forecasts by NYCA zones (2024-2033) | NYISO
“While there is potential for a deficient statewide system margin in 2025, the primary driver is the New York City deficiency already identified,” the report said. “Depending on the solution to the New York City reliability need, the potential statewide deficiency may be mitigated.”
The planned addition of the Champlain Hudson Power Express transmission project would help the New York City shortfall, but it is not expected to go into service until summer 2026. (See Champlain Hudson Converter Station Breaks Ground in NYC.)
Without any additional resources, according to the report, a heat wave with temperatures of 95 to 98 degrees Fahrenheit in 2025 could lead to up to a 555-MW transmission security margin deficiency in New York City and over 1 GW statewide. The CHPE project would help alleviate that risk in subsequent years, but only until 2029, after which margins would decrease again.
The ISO is considering keeping certain peaker plants operational beyond the DEC’s mandated retirement dates, as allowed under certain conditions set by the department, but only as a last resort if projects like the CHPE do enter service on time, the report said.
New York Control Area demand forecast (2024-2033) | NYISO
“As we have noted in previous STAR reports, if there are insufficient solutions to the 2025 reliability need, then [NYISO] may very well have to extend at least some of the peakers that are subject to the DEC’s regulations,” Zach Smith, ISO vice president of system and resource planning, said during the New York State Reliability Council’s Executive Committee meeting last week. “We’re working diligently to identify solutions and hope to publish a short-term report describing those solutions and our findings within the next few months.”
The third-quarter STAR also flagged a transmission security issue in the Central Hudson area, driven by the assumed unavailability of certain generators because of the peaker rule. But because the relevant generators in the region did not provide complete deactivation notices before the STAR was conducted, the ISO only identified the issue for informational purposes and could not evaluate whether the deactivations would cause a reliability need.
Chicago-based developer Invenergy Transmission’s $7 billion, 800-mile Grain Belt Express HVDC line secured the final of its state approvals last week with Missouri agreeing to the line’s expanded design.
The Missouri Public Service Commission issued an Oct. 12 order granting the last of Invenergy’s state siting approvals. The 4-1 decision allows the developer to amend its existing certificate of convenience and necessity to complete the line’s more comprehensive design in two phases (EA-2023-0017).
Last summer, Invenergy Transmission said it planned to increase capacity of the Grain Belt Express to 5 GW by relocating and expanding the line’s midpoint converter station from 500 MW to 2.5 GW and adding a 40-mile delivery line, dubbed the Grain Belt Express Tiger Connector. (See Invenergy Announces Grain Belt Express Expansion.)
Missouri regulators said increasing the merchant line’s capacity, moving the converter station and adding the Tiger Connector will better interconnect “multiple regions to improve the reliability and resiliency of the grid for Missourians and national security.”
“This will help guard against price spikes and outages such as those experienced by Winter Storms Uri and Elliot,” the commission added. It said the HVDC converter can “serve as a critical grid asset to ensure grid stability.”
The Missouri PSC expects the line to result in $17.6 billion in savings to Missouri ratepayers and $7.6 billion in social benefits.
“There can be no debate that our energy future will require more diversity in energy resources, particularly renewable resources. We are witnessing a worldwide, long-term and comprehensive movement toward renewable energy. The energy on the project provides great promise as a source for affordable, reliable, safe and environmentally friendly energy that will increase resiliency of the grid. The project will facilitate this movement in Missouri [and] will thereby benefit Missouri citizens,” the Missouri PSC said.
Invenergy Transmission said the approval “provides the necessary certainty about power delivery to support ongoing and upcoming commercial contracting efforts.” The company will finance and build the line in two phases, starting with the first phase between southwest Kansas and northeast Missouri. Invenergy reports it has acquired 95% of the easements for the first phase.
Grain Belt Express required approvals from Kansas, Missouri and Illinois.
The Kansas Corporation Commission in mid-June granted a similar amended approval to expedite the Grain Belt Express in two phases. The KCC said amending its approval was in the public interest “because it expedites the benefits of the project to Kansas, while maintaining all of the safeguards.”
The Illinois Commerce Commission put its stamp of approval on Grain Belt Express in March.
“We thank the state leaders in Kansas, Missouri and Illinois who have thoughtfully considered the tremendous benefits of Grain Belt Express,” Shashank Sane, executive vice president and head of transmission at Invenergy, said in a press release.
“Now that Grain Belt Express has received every state approval needed to construct the first phase and 95% of the main line easements are already acquired, we are more confident than ever that 39 communities across Missouri will be able to receive clean, homegrown energy that will save millions in lower electricity costs each year,” Missouri Public Utility Alliance CEO John Twitty said in a statement.
Several other groups support the line, including industrial and manufacturing groups in Illinois and Missouri, clean power organizations, consumer advocates and a government office in Kansas dedicated to development.
“Lower energy costs are a major advantage for Missouri businesses, but it will only remain so if we can continue to increase our energy supply to meet demand and modernize the grid through state-of-the-art energy projects like the Grain Belt Express,” Associated Industries of Missouri CEO Ray McCarty said in a statement. “The approval of this transmission line and the ability to bring five times as much power to Missouri as originally planned will not only help us tap a significant source of domestic energy, but also help improve reliability and affordability for the Missouri business community.”
The Missouri Farm Bureau remains opposed to the line and expressed disappointment with the order.
In a statement, MOFB President Garrett Hawkins said the PSC’s decision dismisses the right of landowners and puts “a lot of faith in [Invenergy] to do the right thing, when they have a track record of failing to do so time and time again.”
“It is simply wrong that landowners along Invenergy’s proposed route are forced to sell their land at a time — and to a buyer — not of their choosing, to forever host a line they do not want,” Hawkins said.
The New York Public Service Commission on Friday petitioned the D.C. Circuit Court of Appeals to review FERC’s approval of NYISO’s 17-year amortization period in its installed capacity market.
The saga around NYISO’s proposal to shorten the assumed lifetime of a hypothetical peaker plant from 20 to 17 years seemed to be settled after FERC earlier this month reaffirmed its decision to approve it (ER21-502). (See FERC Reaffirms NYISO’s 17-Year Amortization, Dismisses Protests.)
But the PSC’s petition argued the D.C. Circuit should add FERC’s October order to an existing case before the court. The PSC said a comprehensive review by the court of “all aspects of FERC’s decisions” is necessary “to remove any doubt” about the matter (23-1192/23-1259).
NYISO sought the shorter amortization period in response to the state’s strict energy and climate legislative mandates. The PSC says the ISO’s proposal is “unjustified” and will likely increase capacity costs by more than $225 million per year, and $400 million over the 22-month period from July 2023 through April 2025.
NYISO’s proposal was first rejected by FERC, but after the commission’s ruling was appealed by generators, the D.C. Circuit remanded the case back to the commission. FERC reversed course and accepted the ISO’s proposal.
The ISO incorporated its proposals as part of the demand curve reset, a set of adjustments made to help forecast the energy supply needed to meet demand for the upcoming capability years.
ROSSLYN, Va. ― Getting transmission built in the U.S. today takes intensive community, workforce and supply chain engagement, while ensuring communication on all those fronts starts early and often, according to a panel of transmission developers at the American Council on Renewable Energy’s recent Grid Forum.
It doesn’t work to take on any one part of a project — such as supply chain — in a vacuum, said Steve Caminati, vice president for government and regulatory affairs at Pattern Energy, which recently started construction on the 550-mile SunZia transmission line.
“You’re trying to do that as you’re trying to line up permitting, as you’re trying to line up financing, as you’re trying to figure out the tolling arrangements through the line, [and] the projects that are going to utilize the line. You’re trying to land all these planes simultaneously,” Caminati said.
“It’s like playing a three-person game of chess or something where you’re trying to get all the pieces together,” agreed Stuart Nachmias, CEO of Con Edison Transmission. “Strategic partnerships and relationships are certainly one piece of it. So, we really need to think, how is this going to unfold, because the need is tremendous.”
With an estimated 2,000 GW of renewables and storage sitting in RTO/ISO interconnection queues across the country, the need for rapid expansion of the country’s transmission system, and in particular, interregional high-voltage, direct current (HVDC) lines, has become an electric power industry imperative. The Department of Energy’s draft Transmission Needs Study, released in March, called for a 57% expansion of the existing grid by 2035.
But the obstacles to permitting and building such projects have become almost legendary. SunZia’s 525-kV line, which will bring wind energy from New Mexico to Arizona, took 16 years to permit. Pattern got the final go-ahead from the Bureau of Land Management in May. (See SunZia Project Wins Final Approval, Signs Offtakers.)
But while discussing the difficulties involved in such projects, the panel also focused on successes and lessons learned, with a strong focus on community and stakeholder engagement.
Nachmias said getting to know upstate communities was critical to the success of the recently completed New York Energy Solution project, a 67-mile, 345-kV line installed in an existing right-of-way.
“I would often meet with the team, and they would tell me … about the beekeeper, about the llama lady, about all the people on the right-of-way,” Nachmias said. “We had people who live there and who brought cookies to our field crews, and the reason they did that is we engaged with them.”
A major selling point for the project was that it was going to remove about 600 old lattice transmission towers and replace them with 400 monopile towers, he said.
“We showed renderings of what the right-of-way would look like; we gave local community centers and libraries [computers] and encouraged people to go in and look at the maps, which indicated exactly where the towers would be,” Nachmias said. “We heard if there were concerns; we didn’t promise we’d be able to move towers, but … if there was a request to move a little bit here or there, we did so.”
Job 1: Name Recognition
Patrick Whitty, senior vice president for public affairs at transmission developer Invenergy, stressed the importance of ensuring that interregional transmission lines deliver benefits — and power — to the states they cross. The company’s Grain Belt Express, a 5-GW, 800-mile line starting in Kansas and running across Missouri and Illinois to Indiana, was originally designed to deliver 500 MW of power to Missouri, Whitty said.
“The desire to see more local delivery and more power delivered locally was a driving factor of [Missouri] stakeholders … and so Invenergy went to work, looking at how that issue and how that stakeholder input could be reflected back into positive changes to the project,” he said.
The Missouri Public Service Commission on Wednesday approved Invenergy’s updated plan for the project, which will now deliver 2,500 MW to the state.
Invenergy also had to do basic public education, Whitty said.
“The name of a company like ours isn’t one that everybody knows how to pronounce when they read it. … So, we have to work from the very first minute to build credibility and to educate about the need and what we’re doing and why we’re there,” he said. “One aspect that’s really important is you’ve got to get a team that is familiar with and drawn from the places you’re working.”
Caminati added that building relationships, even with people or groups opposed to a project, can be important.
“It’s hard to build a $10 billion infrastructure project and not have opposition,” he said. But even opponents of SunZia have conceded that Pattern listened to them and has tried to mitigate some of their concerns, he said.
Communication across a range of stakeholders can be especially critical in heading off misinformation, Nachmias said.
“Don’t underestimate that people make stuff up, and things that are not true [can] get a life of their own,” he said. “If you don’t think about that and get ahead of it, so there’s consistency and accuracy and factual information being shared, that’s when you start to lose control and then you can have more delays.”
Workforce and Supply Chains
Workforce development requires striking a balance between immediate needs for project construction and a longer-term vision for providing local workers opportunities to build careers, the panelists said.
Pattern is looking to align incentives in the Inflation Reduction Act — which are often linked to projects paying prevailing wages and working with registered apprenticeship programs — with its own conversations with local and state workforce development groups, including labor unions, Caminati said.
Construction jobs may be temporary, so the company is trying to figure out how its transmission projects can be “about building a more robust permanent industry,” he said.
Yearslong permitting timeframes do allow developers to work with local unions and community colleges to stand up training programs, Nachmias said, but even then, getting the mix right can be tricky. “We need all levels,” he said. “We need people who are going to be in the field. We need electrical engineers … it’s not popular in schools, but we need them.”
Whitty shared an anecdote about a New Mexico project Invenergy has in early development. In a community meeting in Hardin County, one of the local residents repeatedly stressed how sparsely populated the area is. “I ended up looking it up, and it’s the 15th-least-populous county, by people per square mile, in the country, and that includes counties in Alaska,” he said.
The issue was brought back to the construction team, he said, to ensure they could be working on it ahead of time.
Increasingly, community benefits packages, with money for workforce training, are becoming a standard part of Invenergy’s project planning, he said. “We’ve realized that almost every market we’re working in, that’s an essential piece of what the industry looks like.”
Whitty also spoke on supply chain challenges Invenergy is facing, particularly in securing converter stations that are an essential component of HVDC lines, “where the power switches from AC to DC and vice versa.”
The stations are “incredibly complex, incredibly expensive facilities that require years of planning and engineering and manufacturing work,” he said, and in the wake of Russia’s invasion of Ukraine, the global supply chain has been largely bought up by TenneT, the Dutch-German transmission operator.
Developers for U.S. transmission projects typically need two or three converter stations but could find themselves “in the back of the line” behind TenneT, he said. Invenergy is working with Siemens on equipment for the Grain Belt Express and also negotiating for the power lines it will need for several projects at once “to enhance certainty across the whole portfolio,” he said.
‘Do the Cheap Stuff First’
The transmission developers’ panel, which closed out the forum, provided an on-the-ground counterpoint to the keynotes on high-level federal policy that started the conference.
FERC Commissioner Allison Clements framed the U.S. energy transition now underway as a response to the opportunities and challenges of “extreme weather, a rapidly changing resources mix, aging, outdated infrastructure, [and] cyber and physical threats.”
“I am focused on whether our federal regulatory framework is aligned with what’s happening in the world,” Clements said. “Throughout history, there have been lots of moments where regulations lagged behind where the markets want to go. I think this is the ultimate example.”
FERC’s role is to modernize the rules, to facilitate change while ensuring affordability and reliability and without favoring any specific technology, she said. “That’s where the country is moving, so that’s what this commission is going to do.”
The way forward, she said, should be “data-driven, reality-based planning and market reform. Make … the low-cost, easy changes first while taking the time to grind the regulatory machine for deeper reform.”
But, Clements said, “If you are thinking about what you can do near term … you have to start with grid-enhancing technology on the grid, period. You cannot stand up and say you represent consumers and their interests if you are not serious about getting grid-enhancing technologies.”
“If we want to create the room for interconnection, if we want to create the opportunity to invest in relatively expensive transmission alongside, we have to do the cheap stuff first,” she said, noting that support for grid-enhancing technologies — such as advanced conductors and dynamic line ratings — is included in Order 2023.
While the bigger issue of market reform is hard if not impossible to simplify, Clements believes the next step is to “get regional transmission system planning done and align our interconnection process with our regional planning process. If we finalize that, we have a chance of moving system planning out from under this ill-suited interconnection process,” she said.
Rep. Scott Peters (D-Calif.) took on the issue of permitting reform in an impassioned keynote address. Instead of combating the climate crisis with the urgency it requires, he said, “we’re debating whether a decade is an appropriate amount of time to construct a single high-voltage transmission line, an offshore wind facility or a geothermal plant.”
With the IRA and the Infrastructure Investment and Jobs Act, the previous Congress provided the money for a strong response to climate change, he said, but “we will still fail if we don’t act faster.”
The National Environmental Policy Act (NEPA) was written and enacted into law when “our environmental imperative was to stop dirty projects,” he said. “It was a law that responded to the challenge of its time, but it didn’t come down from Moses on stone tablets.”
NEPA can and should be updated to meet the need to build new, green infrastructure that can cut emissions, Peters said. “Climate activism is about building stuff, not stopping stuff,” he said.
But Peters said he is working with colleagues across the aisle on a permitting reform package that “would improve community input and fix the broken judicial process.”
A main obstacle to permitting reform could be the political process itself, Peters said. “Transmission has become seen as … the way to displace oil and gas. If it’s perceived as that, then we’d have problems. … Transmission is needed for all sorts of projects. It’s a reliability issue; it’s a cost to consumers issue and a competition issue.
“The learning we need to pursue right now is to make sure people understand transmission is bigger than just renewables.”
The New York State Reliability Council’s Executive Committee on Friday approved the modeling assumptions for its 2024/25 installed reserve margin requirement study base case, including those for emergency assistance.
The committee approved both the final base case assumptions matrix — which sets parameters like load forecast, system topology and generation — and the final emergency operation procedures white paper, which examines how emergency assistance is accounted for in the IRM modeling and provides recommendations for improved operations.
The base case projects expected system conditions in New York, particularly during extreme weather events or major system failures, which could force the state to rely on neighboring jurisdictions like PJM to ensure reliability during emergency operations.
The base case is crucial for setting the state’s IRM, which represents the minimum level of capacity that NYISO market participants must procure through its capacity market.
The white paper serves as a five-year strategic plan focused on improving resource adequacy modeling. The report highlighted tightening reliability conditions in the state, particularly during winter conditions, and recommended that more emergency assistance be incorporated into IRM modeling in case of a future emergency.
Update on Environmental Regulations
Committee Chair Chris Wentlent provided updates on recent discussions with the New York Department of Environmental Conservation and EPA regarding upcoming environmental regulations at the state and federal levels.
Wentlent said the DEC indicated it may propose new rules to New York’s cap-and-invest program next year following a potential second round of informal stakeholder outreach for comments and recommendations. The department said the proposed rules would come after it produces either a white paper or fact sheets summarizing the feedback that helped inform its rulemaking process.
The council had requested that EPA include “a reliability safety valve” in the final rule. “It’s important to have that flexibility because there’s no way for anybody to figure out all the potential outcomes with all the moving variables that are going on right now within the industry,” Wentlent said, citing load growth, the changing resource mix and the timing of new resources and infrastructure as some of the uncertainties.
The NYSRC also urged the agency to consider how its rules might impact the interactions between neighboring jurisdictions. Although New York is going green, the state’s grid is highly interconnected with neighbors that may have less ambitious clean energy goals, potentially impacting the level of imports and exports available, he said.
PJM filed its proposed capacity market revamp Friday, saying the changes would improve reliability and incentivize resource development while ensuring market forces control costs.
The filing lays out the tariff revisions the Board of Managers outlined last month following conclusion of the critical issue fast path (CIFP) process. (See PJM Board Releases Outline of Capacity Market Changes.)
“These proposed capacity market reforms will help PJM do what we do best — operating markets that attract critical investment in the resources we need to keep the lights on,” PJM Vice President of Market Design and Economics Adam Keech said in an announcement of the filing. “Maintaining enough resources that can support reliability [is] crucial to PJM’s ability to serve demand through the transition to a less carbon-intensive grid.”
The slate of changes the board directed was divided into two filings: one (ER24-98) concerns the market seller offer cap, which market sellers are eligible to receive capacity performance (CP) bonus payments and forward energy and ancillary service revenues.
The second filing (ER24-99) encompasses the remaining changes, including a shift to the marginal effective load carrying capability, an accreditation framework PJM said reflects the actual capacity value that resources provide. It also increases the granularity of risk modeling and tightens testing requirements for capacity resources. The filing also includes changes to the fixed resource requirement framework to align with the Reliability Pricing Model.
Comments on the filings are due Nov. 3.
During the Oct. 4 meeting of the Market Implementation Committee (MIC), PJM Senior Counsel Chen Lu said staff were weighing splitting the proposed changes into two filings to mitigate the risk of components seen as riskier sinking the whole proposal. (See “PJM Reviews Board of Managers CIFP Letter,” PJM MIC Briefs: Oct. 4, 2023.)
The RTO said the current tariff language concerning how resources include the cost of the risk of nonperformance charges — capacity performance quantified risk (CPQR) — lacks clarity, resulting in disputes among PJM, market participants and the Independent Market Monitor.
The proposal would add a provision stating that CPQR values can be included in offers when supported by documentation and review from an independent third party. While it would not change the CPQR review and approval process, PJM argued that adding third party review would give more certainty regarding which components are “consistent with actuarial practices used in this industry.”
The proposal would not change the penalty rate for generators that don’t live up to their capacity obligations during an emergency; however, it would base the annual stop-loss limit on the Base Residual Auction (BRA) clearing price. Currently, both are derived from the net cost of new entry.
The filing would also limit the eligibility of CP bonus payments — which go to resources that overperform during a PAI and are paid out of the CP penalties — to cleared capacity resources. “Noncommitted capacity resources, non-capacity resources and imports not associated with committed pseudo-tied external resource would not be eligible,” the filing said.
Although the proposed stop-loss would reduce the total penalties generators could face for failing to perform, the filing argues that the tightened triggers for initiating a PAI will maintain the incentive to ensure performance.
PJM argued that the capacity resources coming online now have different characteristics that change the daily and seasonal periods with the highest risk. The December 2022 winter storm also revealed shortcomings in its current approach to modeling thermal generation. The RTO said natural gas resources that lack on-site storage are vulnerable to common-mode outages should production sites or transportation falter. Such problems contributed to resource outages during Elliott and the 2014 Polar Vortex.
“The resources coming online have different operating characteristics and vulnerabilities than those they are replacing. Additionally, recent operating experiences, particularly in the winter periods, such as Winter Storm Elliott, have demonstrated that current modeling approaches focused on peak load conditions and average performance do not fully capture all of the risks that impact resource adequacy needs and resource performance,” PJM said.
PJM’s new approach to risk modeling would include a longer weather lookback — starting in 1993 — which it expects will shift some risk into the winter.
“PJM and the PJM board thank stakeholders for their focused consideration of market reforms designed to support resource adequacy and grid reliability,” said PJM CEO Manu Asthana. “The grid is evolving, and our markets must also adapt to facilitate the energy transition without sacrificing reliability.”
A three-judge panel from the 9th U.S. Circuit Court of Appeals on Monday rejected a lawsuit from the Idaho Conservation League alleging Bonneville Power Administration is underfunding fish conservation efforts.
The Northwest Power Act (NWPA) requires BPA to protect fish and wildlife from the impacts of its dams. The conservation league and its allies argued a decision to lower rates would place the federal power administration in violation of that law.
While BPA is under the Department of Energy, it is self-funded based on revenues from its sales of electricity and the transmission of electricity, which means it must set its rates high enough to cover costs. By statute, that must be balanced with the requirement that BPA sell power at the lowest possible rates.
The administration’s rates are set through rate cases that resemble agency rulemakings, which include numerous chances for the public and interested parties to comment, including with written briefs. BPA estimates its anticipated spending through a process called Integrated Program Review, which also offers a chance for public input.
In neither process does BPA set specific funding levels for different programs, nor does it decide which costs to incur.
One of the concerns BPA was dealing with in 2022-23 rates at issue in the case was its latest strategic plan, which required a response to concerns over growing costs, centered on cutting costs and improving its financial health.
BPA must recover the costs associated with fish and wildlife measures by developing a realistic projection of those costs that reflect the best information at the time rates are set.
The NWPA set up the Pacific Northwest Electric Power and Conservation Planning Council, which is made up of representatives from the state governments of Idaho, Montana, Oregon and Washington. While BPA and the council operate independently, the power administration must adhere to its “program” laying out measures to protect, mitigate and enhance the fish and wildlife affected by its dams and reservoirs.
BPA expected to earn an extra $100 million from wholesale power sales and initially was split between lowering rates 4.5% to provide short-term rate relief or holding rates flat while investing the surplus in financial reserves — the option it preferred.
Stakeholders were split on the issue, and BPA eventually reached a settlement that split the difference: cutting rates by 2.5% and taking measures to improve its finances. While most parties supported it, the conservation groups opposed it because they believed the lower rates would mean underfunding fish and wildlife protections.
“Essentially, petitioners want BPA to use some of its surplus in favor of greater fish and wildlife mitigation measures,” the court said.
FERC approved the rates BPA came up with and the Idaho Conservation League challenged them before the commission. FERC’s order determined compliance with fish and wildlife protection obligations was outside of that proceeding, so the conservation groups took the issue to court.
A big part of the case was devoted to whether the conservation groups had standing, with two of the judges agreeing they did and the third filing a dissent saying they would have thrown out the decision because of that issue.
BPA must provide equitable treatment for fish and wildlife while considering the conservation planning council’s program to the fullest extent practicable. The conservation groups argued that meant BPA had to set aside more funds for fish and wildlife, while BPA said those requirements do not apply to ratemaking at all.
BPA argued it must take those provisions into account when it manages and operates its dams, but the court did not go that far. The judges concluded the fish and wildlife mitigation laws do not extend to ratemaking.
The relevant language in the NWPA does not mention ratemaking, which does come up in another part of that law with technical requirements focused on the ratemaking process. Congress did not even acknowledge the fish and wildlife provisions of the law in NWPA’s ratemaking sections.
“In this case, the NWPA simply does not ‘mandate the comprehensive, detailed mechanism that petitioners seek BPA’ to implement, and ‘we cannot impose this procedural requirement ourselves,’” the court said, quoting a 2003 precedent on BPA.
If Congress wanted to apply the fish and wildlife conservation requirements to ratemaking and budget projections (a significant legal obligation), it would have drafted the statute to say that, the court said.
A change in nomenclature has heightened some concerns that Texas regulators are attempting to restrict the ERCOT Market Monitor’s independence.
Several ERCOT market observers were quick to notice that the Public Utility Commission’s request for proposals for a four-year monitoring contract refers to an “electric market monitor,” as opposed to an “independent” market monitor. The PUC said it is simply updating the Monitor’s name to align it with the statute and accurately represent its role.
However, state Sen. Charles Schwertner (R), who has overseen legislative changes to ERCOT’s market since the deadly February 2021 winter storm, said in a letter to the commission that renaming the Independent Market Monitor (IMM) as the Electric Market Monitor (EMM) “implies the position is no longer truly independent.”
“While this contractor is hired through a contract with the PUC, it is ultimately the people of Texas within ERCOT who pay for this position,” Schwertner wrote. “This position is similar to an auditor or ombudsman, and their analysis should not be influenced, nor their recommendations suppressed, by politicians or bureaucrats.”
To be fair, the RFP does refer to an “independent wholesale electric market monitor.” PUC spokesperson Ellie Breed said that because this was the first time the Monitor’s contract has come up in four years, it was the “appropriate time to update” its name.
“For context, the word ‘independent’ describes the market monitor’s relationship to the ERCOT ISO and market participants,” she said, pointing to the commission’s rules that the Monitor “shall offer independent analysis to the commission to assist in making judgments in the public interest.”
“I don’t know that they’re necessarily doing anything to weaken the position, but I don’t see how you take the word ‘independent’ out of the name and not have everybody conclude that’s what you’re trying to do,” said Stoic Energy’s Doug Lewin, who closely watches the state’s electric market. “It sends a pretty strong signal, whether intended or not.”
The missive was co-signed by Lt. Gov. Dan Patrick, who is president of the Senate and has a contentious relationship with Gov. Greg Abbott, who appoints the PUC’s commissioners.
Beth Garza, who served as the IMM’s director from 2014 to 2019, pointed to that rivalry between two of the state’s political leaders as possibly playing a role in the letter’s issuance.
“I would like to think this has a lot to do about nothing, but it could just be signaling just these bigger tensions between the Legislature and the commission, which may just be evidence of underlying tensions between our lieutenant governor and the governor,” she said. “You can build a pretty credible kind of conspiracy for a pretty credible argument for all of this.”
Monitor Carrie Bivens — a vice president for Potomac Economics, the firm that has held the IMM’s contract since 2006 — has twice found herself at loggerheads with the commission.
She has consistently opposed the performance credit mechanism, former PUC Chair Peter Lake’s preferred market design, and recently said ERCOT’s use of its new contingency reserve service “likely” raised the real-time market’s energy value by $8 billion to $10 billion in three months. (See Market Monitor Pans ERCOT Market Redesign and ERCOT IMM Raises Concerns over Newest Ancillary Service.)
“It’s a tense position, because you really do need to take unpopular positions that not only the commission may not like, but there’s very few in the market that are going to like it,” Lewin said. “You’re going to get just a lot of it by its very nature. It’s not conflict, but it’s tension. It’s just inherent in the role.”
Bivens said she was unable to comment on the matter.
Schwertner also criticized the RFP’s language requiring the PUC to be notified by the Monitor of any request to speak and for the apparent ability of the commission’s executive director to remove the IMM’s director with the commissioner’s approval.
“We urge you to consider the concerning provisions contained in the new RFP and ensure the IMM’s continued independence in the final scope of work and the contract,” he wrote.
Breed clarified that the EMM would not be required to seek approval from the commission for speaking engagements, but only notify the PUC of those engagements and the topics they are invited to address. She said the commission’s standard contract terms and conditions direct that, at the PUC’s request, the contractor “must remove from the project any individual whom the PUC finds unacceptable for any reason” in its discretion.
Garza said requiring the Monitor to notify the commission of any speaking requests and the topic “was a practice during my time at the IMM.”
“They’re just codifying that expectation,” she said.
The issue may be moot anyway. Responses to the RFP are due Oct. 30, and the contract begins Jan. 1. Should the contract not be awarded to Potomac, the new Monitor would have to begin a transition period Dec. 1.
“The timing of the RFP would indicate to me that the commission is not really in a position to go to somebody else,” Garza said.
The NYISO Operating Committee on Wednesday voted to recommend that the Management Committee approve the draft annual Comprehensive Reliability Plan, which reported no “actionable” long-term reliability issues but noted narrowing reliability margins.
The report also reinforced findings from the ISO’s second-quarter short-term reliability report, which identified a shortfall in New York City that needs to be addressed by summer 2025. (See NYISO Addresses NYC Near-Term Reliability Need.)
NYISO noted that the CRP also shows fossil fuel generator retirements are outpacing the addition of renewable resources. That threatens future reliability, which has become increasingly reliant on the timely completion of transmission projects like the Champlain Hudson Power Express.
“Without the CHPE project in service or other offsetting changes or solutions, the reliability margins would be deficient for the 10-year planning horizon,” NYISO said in its presentation of the draft.
The report also stressed the need for more state investment and research into dispatchable, emissions-free resources, which will be needed to serve future loads at times when intermittent resources cannot produce enough energy because of poor weather.
Summer Operations
Aaron Markham, NYISO vice president of operations, discussed the impact of three summer heat waves on the ISO’s operations, noting how solar resources are becoming increasingly important as peaker unit retirements reduce surplus capacity and solar production shifts peak load times.
“It was a cool, wet summer, but from a capacity perspective, we definitely observed less surplus in real time due to retirement of the peaker units,” Markham said. “We also continue to see the net load peaks shift to later in the afternoon due to the addition of behind-the-meter solar resources.”
Markham noted that although the heat waves required no emergency actions, they underscore the pressures on New York’s grid as it transitions to more weather-dependent energy resources and the importance of public policy transmission projects to alleviate bottlenecks.
Interconnection & Transmission
Thinh Nguyen, NYISO senior manager of interconnection projects, updated stakeholders about proposed tariff revisions that the OC recommended last year but that were not brought before the MC. (See “Interconnection & Transmission,” NYISO Operating Committee Briefs: Dec. 15, 2022.)
The revisions are intended to improve coordination between NYISO’s interconnection and transmission expansion studies. They would, among other things, revise the criteria for what transmission projects are included in study assumptions and account for generators that are outside of the ISO’s interconnection procedures but are included in state agencies’ own processes.
While the OC gave its approval in December, the ISO held off on presenting the revisions to the MC while it waited to see how FERC would rule on a proposal by transmission owners to clarify their ability to exercise a right of first refusal for public policy transmission network upgrade facility upgrades. (See NY TOs Seek Clarification on ROFR for Upgrades.) The commission approved that proposal in April.
The revisions were further held up by FERC’s Order 2023. The ISO told the committee it has determined the order’s directives do not conflict with the revisions.
NYISO will present the revisions to the MC for approval Oct. 25.
September Operations Report
Markham also informed the OC that September saw the summer’s peak load of 30,206 MW, short of the record, 33,956 MW, set in 2019.
The ISO has added 20 MW of energy storage and 60 MW of behind-the-meter solar resources since August.
CAISO maintained normal grid operations during Saturday morning’s solar eclipse, with swings in solar production that were more muted than what the ISO had modeled based on clear-sky conditions.
As the moon obscured much of the sun throughout California and other Western states, solar production in CAISO’s territory dropped to 3,434 MW at 9:30 a.m. PST, following an early morning peak of around 8,100 MW shortly before 9 a.m. That’s a drop of 4,666 MW.
As expected, net demand in the ISO spiked at 9:30 a.m. as both utility-scale and behind-the-meter rooftop solar dropped off. Still, demand of 24,023 MW at 9:30 a.m. was well within the 44,756 MW of available capacity at that time. Energy supplies from natural gas and imports increased between 8:30 a.m. and 9 a.m. as solar output fell.
After bottoming out at 9:30 a.m., solar output quickly climbed to nearly 11,000 MW around 11 a.m. The eclipse lasted from about 8 a.m. to 11 a.m.
The eclipse-day figures are from CAISO’s daily outlook data posted to its website on Saturday.
“The power grid remained stable throughout the duration of the eclipse, and system operations returned to normal shortly after the conclusion at 11:05 a.m,” CAISO spokesperson Anne Gonzalez told RTO Insider in an email Monday. “Overall, generators followed their forecasted dispatches closely, and ramping was smooth heading in and out of the eclipse.”
The ISO plans to release a full analysis of eclipse operations in December, she said.
In modeling of eclipse impacts ahead of the Oct. 14 event, CAISO had forecast a dip in solar production to 3,240 MW at 9:30 a.m., with a rapid ramp up to 14,041 MW at 11 a.m.
In a technical bulletin released in August regarding the Oct. 14 eclipse, CAISO identified that ramping period as a time of “operational interest” that it would study “to ensure adequate supplies of generation [reserves] are available to mitigate any adverse effects of the anticipated steep up-ramp in solar production.” (See CAISO Sheds Light on October Solar Eclipse Preparations.)
The swings in solar production seen on Saturday were less intense than what CAISO had modeled. CAISO had estimated a ramp-up rate of 120 MW per minute between 9:30 and 11 a.m. The actual rate was roughly 84 MW per minute.
CAISO’s modeling was based on a day with clear skies, when the drop-off and return of solar would be most marked. The ISO noted the modeling was a “high impact” scenario, and that cloudy skies on Oct. 14 would lessen the impact.
Saturday’s weather conditions included cloudy conditions in parts of California.
The Oct. 14 event was a partial — or annular — eclipse, in which the sun was obscured by 65% to 90% within the Western Energy Imbalance Market territory.
In its technical bulletin, CAISO contrasted Saturday’s event with the total eclipse on Aug. 21, 2017.
Since 2017, grid-scale solar within the CAISO footprint has increased from 10,000 MW to 16,500 MW, and behind-the-meter solar has grown from 5,700 MW to 14,350 MW. That raised concerns that this year’s eclipse might have greater impacts than the 2017 event.
On the other hand, because the Oct. 14 eclipse fell on a Saturday, demand was expected to be less than it would have been on a weekday. The 2017 eclipse was on a Monday morning.
