FERC on Friday granted NextEra Energy Transmission (NEET) Southwest’s request to recover 100% of “prudently incurred costs” to construct a competitive transmission project in New Mexico, should the project be abandoned or cancelled for reasons beyond its control (ER23-2630).
The commission agreed with NEET Southwest’s contention that the project faces certain regulatory, environmental and siting risks beyond the developer’s control that could lead to its abandonment. FERC said its abandoned plant incentive will address those risks by protecting NEET Southwest.
“Thus, we find that NEET Southwest has demonstrated a nexus between its requested incentive and its planned investment and that NEET Southwest has tailored its incentive rate request to its identification of risks and challenges associated with the project,” the commission said.
SPP awarded the NextEra subsidiary the Crossroad-Hobbs-Roadrunner 345-kV project in July. The project, 135 miles of double-circuit 345-kV lines at either end of the Hobbs generating substation, is estimated to cost $291.6 million and has a proposed in-service date of May 2026. (See SPP Awards NextEra 3rd Competitive Project.)
In August, NEET Southwest filed a request with FERC under Section 205 of the Federal Power Act and the commission’s 2012 policy statement on transmission incentives for incentive rate treatment.
The commission previously accepted the developer’s 2017 filing for a formula rate designed to be incorporated into SPP’s tariff. In its order, FERC also granted NEET Southwest’s request for several incentive rate treatments: a 50 basis point return on equity incentive for participating in an RTO or ISO; a regulatory asset for prudently incurred pre-commercial and formation costs for later recovery; and a hypothetical capital structure of 60% equity and 40% debt until its first transmission project is commercialized.
Commissioner Mark Christie concurred in a separate statement, but also called for FERC to revisit “the array of incentives offered to transmission developers.” Those include construction-work-in-progress and hypothetical capital structure incentives, and RTO participation adders.
“A core principle of utility law and regulation for decades is that consumers can only be forced to pay costs for assets that are ‘used and useful’ to them,” he wrote, noting that under Order 679, the commission may have to overlook that principle to address the “substantial challenges and risks” in building transmission facilities.
Christie said he previously questioned the commission’s determination of “whether ‘substantial challenges and risks’ exist when granting the abandoned plant incentive and other incentives has become nothing more than a check-the-box exercise.”
Consumers shy away from buying electric vehicles in New Jersey because of the high price and lack of charging infrastructure, and they’ll still be reluctant even if the state adopts California’s Advanced Clean Cars II (ACC II) rules, representatives of the vehicle sales and manufacturing sectors said at an energy conference last week.
Car manufacturers and dealers said they’re committed to the transition from gas to electric vehicles. But the ACC II rules don’t consider consumer attitudes.
Executives from the New Jersey Coalition of Automotive Retailers (NJ CAR) and North American Subaru voiced their concerns at a conference organized by New Jersey Business and Industry Association (NJBIA).
The ACC II rules require manufacturers to make EVs a steadily increasing portion of their car sales in New Jersey until all new vehicles sales are EVs in 2035. The New Jersey Department of Environmental Protection (DEP), which is accepting public comment on the rules until Oct. 20, is moving to adopt ACC II by the end of the year so they affect the 2027 car model year. The NJBIA is leading a coalition of businesses that oppose the rules. (See NJ’s Push Toward Clean Cars Rule Sparks Vigorous Debate.)
“When a consumer comes into the showroom, and they start shopping for a new car, and they are an ‘EV Intender,’ what winds up happening in the process is that they typically drive out with a hybrid or a plug-in,” said Jim Appleton, president of NJ CAR, referring to a hybrid gas-electric vehicle or a plug-in battery vehicle that also operates with gas.
One reason is that an EV can be $10,000 to $15,000 above the price of a gasoline vehicle, he said. Another reason is the lack of public chargers.
“If they are in a dealership, if they’re a multiple unit dwelling person, if they don’t live in a house with a garage where they can charge their vehicle every night, most consumers are walking out the door because they just don’t trust that the infrastructure is there,” he said.
Matt Forman, director of government and regulatory affairs for Camden, N.J.-based Subaru, said that although New Jersey is reasonably highly ranked in the nation by raw numbers of EVs, its charging infrastructure is lagging. The state is about sixth in the nation by the number of registered EVs, but has only about one charger per 40 EVs, when it needs one per seven EVs, he said.
“That’s the, I’d say, the biggest challenge,” Forman said. “That gap is growing. So for this to succeed, we need to see investment in charging, which traditionally is not the role of an OEM. But you’re starting to see OEMs actually putting money in charging.”
New Jersey had about 123,000 EVs in June, according to ChargeEVC, a pro-EV lobbying organization. But that’s a tiny proportion of the estimated 6 million light-duty vehicles registered in the state.
There are about 1,645 Level 2 chargers and 755 Direct Current Fast Chargers in the state, according to the DEP’s Drive Green website. And the state added another $12.7 million to incentive programs designed to encourage developers to install chargers at tourist sites, in multi-unit dwellings and in other locations. (See NJ to Add 400 EV Chargers with $12.7M Investment.)
Although New Jersey has a strong EV purchase incentive program, the weakness in the ACC II is that it focuses on sales to stimulate EV buyers, Appleton said. The regulation starts with a 35% ZEV sales requirement for model year 2026, increasing to 68% in 2030 before reaching 100% in 2035.
“The rule requires manufacturers to send cars, but unfortunately, it doesn’t require consumers to buy them,” he said. “Manufacturers will build what government mandates and they will ship them to dealers who’d be happy to sell them. But the flaw in this program has always been that it lacks a mechanism to require consumers to buy them.”
However, proponents of the rules — including government officials and environmental groups — say climate change requires an urgent, rapid uptake in EV adoption and the ACC II rules will trigger a much faster uptake than the state otherwise would see. Transportation is New Jersey’s biggest emissions source, generating about 40% of greenhouse gases.
Appleton said one impact of the ACC II is that it “corrupts the marketplace,” so that manufacturers will respond to the diminishing number of gas vehicles that can be sold in the state by focusing only on selling higher priced vehicles that give them a larger profit margin. He predicted the state’s dealers nevertheless would suffer as buyers seek gas vehicles out of state.
“I’m sure there’ll be dealers in Idaho, who will be trying to unload their inventory here in New Jersey, and they’ll be reaching out to you and you’ll be able to go online and buy a car in Idaho and they’ll flatbed it here in the state of New Jersey,” he said. “And the dealerships that do business here will lose business.”
OSW Developers Unbowed
In a separate panel, offshore wind (OSW) developers acknowledged the sector faces tougher opposition than in the past, but say they have no intention to back away from a key piece of the state’s energy future.
“I’m not going to sugarcoat it — it is really rough out there on the ground level,” said Crystal Pruitt, external affairs lead for Atlantic Shores Offshore Wind, one of three projects approved by the state. She said it’s difficult “having conversations with communities, having conversations with elected (officials) and policymakers and just seeing the turn of faith away from the policy goals that they were so supportive of.”
The conference followed the release on Sept. 28 of a poll by Stockton University that showed that 50% of those polled support the installation of wind turbines off the New Jersey coast, down from 80% in 2019. The poll was the second to show dramatically diminished support. A Monmouth University Polling Institute poll released on Aug. 29 showed support for offshore wind had dropped from more than 82% in the early 1980s to 54% now. (See Poll Shows Drop in Support for Offshore Wind in NJ.)
New Jersey is in the middle of its third offshore wind solicitation, having backed the 1,100-MW Ocean Wind 1 project in the first, in 2019, and the 1,148-MW Ocean Wind 2 and the 1,510-MW Atlantic Shores projects in 2021.
The polls follow months of growing opposition from Jersey Shore residents and representatives of the tourism and fishing industries who fear the turbines will harm business. Some opponents have seized on a series of whale deaths to boost opposition to the projects, depicting the deaths as potentially tied to the preliminary undersea work underway in preparation for the OSW projects.
State and federal investigators looking into the deaths say there’s no evidence the deaths are linked to the offshore work.
The developers also have faced challenges from rising costs and supply chain difficulties, which have raised questions about the economic feasibility of some projects.
Janice Fuller, mid-Atlantic president of Anbaric, a transmission development company, acknowledged the sector has faced some “negative attention, not just in New Jersey” but in multiple states in recent months. But she cast the downturn as “rationalization” from the unduly high support and expectations early on.
“We were very aggressive, set some really aggressive targets,” she said. “And right now the industry and the world, because of things that are outside of New Jersey’s control, are adjusting. Timelines are being adjusted, prices are being adjusted and a realistic schedule is going to emerge from that.”
“This is a little bit of a bump in the road, unfortunately,” she said, and blamed “misinformation about the industry and its impacts.”
The New York Power Authority has named a new executive to guide it into its expanded role as developer of large-scale renewable energy generation.
Vennela Yadhati assumed the new position of vice president of renewable project development last week, several months after passage of legislation that gave NYPA a larger role in the state’s push to carry out a clean energy transition.
She told NetZero Insider that NYPA’s first strategic plan for doing this will be formulated next year, and the process of conferring with stakeholders and state agencies on priorities for that plan is underway now, so she could not be specific about what types of projects NYPA will pursue, or where. But it will entail consensus-building, she said.
The decision to expand NYPA’s development effort grew from the push by some advocates to make the state’s energy sector more democratic and responsible to residents rather than investors. Generation and transmission development is a blend of finding the right technology for a project, convincing everyone affected by the project that it would benefit them and finding a way to pay for it. Yadhati has grounding in all three, and she expects to need it.
“How much of each is something we’ll have to figure out,” she said.
Renewable energy development, of course, is not new at all for NYPA. It was created in 1931 and is now the largest state-owned power organization in the U.S. It operates 1,400 circuit-miles of transmission, two of the largest hydropower plants in the nation and one of the largest pumped-hydro storage facilities. It even operated nuclear reactors at one time.
“NYPA has been doing large energy infrastructure forever,” Yadhati said. “I am in a fortunate and very pleasant spot right now because I can leverage all of what we have built internally.”
Yadhati is an engineer by training, first in her native Hyderabad, India, then at Missouri University. She most recently worked in development for Ørsted, and during a previous stint with NYPA, she was a distributed energy resources manager. In White Plains, where she now lives, she is a member of the city’s Planning Board and a board member of Sustainable Westchester.
All of this gives her a wide basis not only in planning projects but gathering the consensus needed to get them built. The team at NYPA and whatever private developers the agency works with will bring with them an equally varied set of skills, none of which will stand out as more valuable than the others.
“It’s not one taking priority over the other; the ultimate [combination] is consensus and community outreach and engagement,” Yadhati said.
Projects must be emissions-free; they must be acceptable to those around them; and they must be financeable.
“That is going to be key,” Yadhati said. “Because when we talk about best value and best fit, it can’t just be the environmental benefits; it has to come along with the economic sustainability as well.”
The question is posed to her: Will NYPA look for the path of least resistance? For example, the 1,160-MW pumped storage project NYPA built in the Catskill Mountains is already a half-century old, and it will still far outlast any of the battery energy storage systems being built today.
But to build new pumped storage would be an order of magnitude more difficult than to site dozens of battery systems. And one pales at the thought of trying to site a new large-scale nuclear plant in the Empire State.
Does NYPA therefore aim for batteries — or whatever technology easily can get New York closer to its statutory goals of 70% renewable electricity by 2030 and 100% zero-emissions by 2040?
“To me — part of this is coming from the engineer inside of me — they’re not competing technologies per se; they are complementary,” Yadhati said.
There is a growing need for immediate short-duration storage, and electrochemical technology meets this need, she explained. In the longer term, long-duration storage will be indispensable, and that could be hydrogen, pumped hydro, some other technology or, most likely, a combination of multiple technologies.
“They each have their own place,” Yadhati said. “That’s where I say we’re going to keep it technology-agnostic.”
The legislation that expanded NYPA’s role, the Build Public Renewables Act (BPRA), laid out a laundry list of objectives ranging from building power plants to aiding disadvantaged communities, alone or in partnership with the private sector.
The broad range of possibilities is why creating the strategic plan is the first step in the process, and one of Yadhati’s first major duties. She said there are many verbs in the directive — plan, design, develop, construct, own, operate, maintain — but they are not all binding, nor is it clear that they will have equal weight in every region or for every project.
“The conferral process will help us identify where the gaps are in the industry and what best value NYPA can offer,” she said.
Yadhati spoke to NetZero Insider on Thursday, her fourth day in the new position. She laughed at the suggestion that the job would be like herding cats — but she did not protest the comparison.
The BPRA, and the fight surrounding it, is a good illustration of the dynamics at play. It was a darling of the progressive wing of the Democratic Party that controls New York government, but initially it did not gain enough traction for passage.
Gov. Kathy Hochul (D) in her 2023-2024 budget plan included provisions derided as “BPRA Lite,” and the battle was underway, with progressives fighting for stronger measures, and private-sector energy developers opposed to even the weakened measures lobbying just as hard but unsuccessfully.
During the process, Justin Driscoll, then acting president of NYPA, was cast as insufficiently supportive of the stronger measures and was tarred to the point that the Senate refused to hold a confirmation vote on his nomination to be president. (He became president anyway, through a quirk in state law.)
New York is not unique in having a slow, complicated and expensive siting and permitting process, or a long wait for interconnection, but it often seems more so than in other states. With a strong home-rule tradition and some significant regional political differences, many stakeholders need to be pushed or coaxed to the table.
NYPA is not exempt from any of these pressures, nor does it have an endless supply of revenue like the water flowing down the Niagara River.
What it does have in its favor, Yadhati said, is a long history in the communities where it operates — it is a known commodity, whether for the 2.6-GW Niagara Power Project it brought online in 1961, or for the recent distributed solar projects it partnered on that yield a few megawatts apiece.
NYPA expects to continue with small DER projects (up to 5 MW), but the focus of this new push will be large-scale renewables that feed 20 MW or more into the wholesale market.
“The economies of scale do offer additional benefits, another thing we want to leverage and take advantage of,” she said.
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.
