The window closed Thursday afternoon on New York state’s third offshore wind solicitation.
The New York State Energy Research and Development Authority, which is leading the state’s ambitious offshore buildout, did not release details on the submissions. But at least some of the would-be developers are known: Four familiar names announced later Thursday that they had submitted bids.
Equinor and BP, already partners on Beacon Wind 1 and Empire Wind 1 and 2 off the New York coast, submitted a proposal for a 1,360-MW installation in the Beacon Wind 2 lease area.
Ørsted and Eversource, already partners on South Fork Wind and Sunrise Wind, submitted multiple bids with different configurations.
NYSERDA late Thursday said it has begun the bid review and qualifying process and will post a summary as soon as it can. The timeline estimates that companies chosen for contracts will be notified later in the first quarter of this year and the contracts executed in the second quarter.
In a news release Thursday, Equinor (NYSE:EQNR) and BP (NYSE:BP) said their plan would complement the 3.3-GW combined output of the three other wind farms the two partners are developing off the New York coast, and help the state realize its goal of 70% renewable energy by 2030.
They propose to create manufacturing facilities for key components such as cable parts, blades and nacelles in New York. They also promise $50 million for a collaborative effort to train and support workers for the offshore wind industry, with attention to historically marginalized communities and opportunities for minority- and women-owned business enterprises (MWBEs). They included options to install energy storage to help the state with its energy transition and for BP subsidiary BP Pulse to install up to 1,000 ultrafast EV charge points statewide.
In their news release, Ørsted and Eversource (NYSE:ES) provided few details about the multiple configurations they offered in their multiple bids. But they painted a general summary of the expected results: billions of dollars in economic activity for the state’s economy, strides for economic justice, prioritization of disadvantaged communities and MWBEs, and furtherance of the state’s climate goals.
The partners have reported steady progress so far on labor agreements, workforce training and supply chain development. Construction of their 130-MW South Fork Wind has begun, and it is expected to start producing power later this year. Their 924-MW Sunrise Wind is in advanced development with a late 2025 target for operation.
Meanwhile, Rise Light & Power, which owns New York City’s largest fossil fuel-burning power plant, said Wednesday it had secured a stake in an offshore wind project, and said its plans to convert the plant to a clean energy hub would be part of an offshore wind proposal submitted Thursday.
It had not followed up with further public information by late Thursday.
The subsidiary of LS Power last year proposed making its Ravenswood Generating Station the point of interconnection for power generated offshore, a connection to land-based clean-energy sources upstate, a source of clean thermal energy by repurposing its water intakes and a large-scale battery storage site.
It will cost the U.S. up to $100 billion to build and power the charging network necessary for a massive conversion of the nation’s transportation system to electric vehicles, an analyst said this week during a webinar produced by the EV Charging Initiative, a national collaborative.
“We really have to think in terms of how we build this new network. It’s not just a matter of modifying the existing network” of gas and diesel stations, said Phil Angelides, a partner with EVC Partners, a company created to identify viable building sites for EV charging stations in California.
Clockwise from top left: Phil Angelides, Riverview Capital Investments; Patricio Portillo, NRDC; Rachel Zook, Nuvve; and José Miguel Acosta Córdova, Little Village Environmental Justice | The National EV Charging Initiative
The company surveyed existing truck stops throughout California and found that limits on both the distribution and transmission system would make it difficult for many existing truck stops to convert to full EV charging, Angelides, a former California state treasurer, said during a virtual summit of the collaborative focused on Midwestern states.
Electrifying the nation’s transportation sector is a major goal of the Biden administration, which wants 500,000 public charging stations built nationwide by 2030. That’s about half the number that will be needed by then, according to experts outside of the administration, especially if half of all new automobiles sold in 2030 are electric, as administration officials hope, and if trucking companies embrace battery electric drive systems over diesel.
As a point of comparison, there are about 140,000 conventional fueling sites operating in the U.S., said Tom Kloza, global head of energy analysis at Oil Price Information Service. That total does not include the number of fuel pumps at each station, he said.
The Infrastructure Investment and Jobs Act (IIJA), passed in November 2021, created the National Electric Vehicle Infrastructure (NEVI) formula program, administered by the Federal Highway Administration. (See US Completes Review of State EV Charging Plans.)
The legislation provided $5 billion in NEVI formula grants distributed to all 50 states to “strategically deploy” EV charging stations along 75,000 miles of federally designated highway. The law also authorized $2.5 billion for a competitive grant program. Both grants require 20% local matching.
Charger Challenges
In three separate discussions, the conference also looked at what it will take to electrify diesel-powered trucks and buses as quickly as possible and the difficulty involved in planning, building and getting power to public charging stations.
“There has been a significant commitment by the federal government, and a number of states have put resources forward to support the charging infrastructure,” Angelides said. “The money is substantial, but I don’t think it’s sufficient for the issue in front us.
“Given the uncertainty of the timing of when these EVs are going to show up, both in the light-duty passenger space and the medium and heavy-duty truck space, it’s very hard to finance major infrastructure investments against that kind of uncertain revenue.”
Angelides also argued for an immediate review of how utilities, working with state PUCs, plan system upgrades, which typically take three to five years of planning and negotiation.
In a separate panel, Drew Bennett, executive vice president at Volta Charging (NYSE: VLTA), said the availability of power at any potential charging site can determine whether charging stations are built. The availability of labor in a region is also a factor, as is the availability of transformers.
“Transformers are really backordered,” he said, “and taking over a year [to obtain] for some utilities. This is something that I think is not going away. I think if you want DC fast charging or even large Level 2 charging, we’re going to need a lot more transformers put into parking lots in the future, and that’s something that needs to adjust.”
In a third panel, Chris Bast, a climate and decarbonization policy expert and principal at Hua Nani Partners in Virginia, noted that $7.5 billion authorized by the IIJA should be seen as “a down payment” on the administration’s 500,000 charging station goal.
Lynda Tran, director of public engagement at the U.S Department of Transportation, said the federal money is an effort to stimulate broader direct investment from private companies.
“We are creating a market; we’re creating a demand that is now translating into lots of private sector investment,” Tran said, referencing a recent analysis commissioned by the Natural Resources Defense Council that found the EV industry has spent $210 billion since Biden took office.
Light, Heat … and Transportation
The analysis also concludes that the total potential funding, including grants, loans and tax credits, authorized by the IIJA and the Inflation Reduction Act in the coming years amounts to $245 billion. Bast pointed out another even more significant and obvious — but hardly discussed — consequence of the effort to electrify transportation is the merger of the transportation industry and the electric generation and distribution industries.
“It’s becoming clear that one of the big challenges we’ll be addressing over the next decade is the merger of two huge sectors of the economy, transportation and electric,” Bast said.
“And [by electric], I mean electric utilities and their regulators are going to have a big and important role to play as we try and bring these two sectors together.”
Katherine Peretick, a member of the Michigan Public Service Commission, said the issue is difficult because “it requires a totally new way of thinking about the electric sector and electric utilities.”
Clockwise from top left: Chris Best, Hua Nani Partners; Michigan Public Service Commissioner Katherine Peretick; Geoff Gibson, Forth; Lynda Tran, U.S. Department of Transportation; and Brittney Kohler, National League of Cities | The National EV Charging Initiative
Utilities have for decades supplied power for light, heating and cooling, she said, adding that many utilities across the country include the word “light” in the company name.
“Now we are adding transportation to that list. That means that the jobs of utilities and the jobs of regulators are front and center and are more important than ever as a part of this transition. It will require some unprecedented coordination among all of these parties,” Peretick said.
Referencing a recent report from the Electric Vehicle Council of the Fuels Institute, she said most cities and counties surveyed “had little to no public policies for public EV charging.”
“These policies are currently being established, and we need to make sure we are being thoughtful about their implications and purposefully coordinating with a very wide range of stakeholders that are involved in transfers, transportation and electrification planning,” she said.
“We need to intentionally include a wide variety of parties in this conversation, including parties who have not traditionally been included.
“As the usage of the electric grid changes, the way that we pay to maintain and upgrade that grid is also going to need to evolve,” Peretick said.
To illustrate that point, Peretick mentioned a program the state is coordinating with Consumers Energy (NYSE: CMS-PB), a Michigan utility, transmission company ITC Holdings and EV maker Rivian Automotive (NASDAQ: RIVIN) to install EV charging stations in Michigan state parks.
Rivian is installing the chargers; ITC is paying for the power; and Consumers Energy is paying for the upgrades to power lines inside the parks.
The demonstration project is part of a longer-term plan created by Michigan, Illinois and Wisconsin to build and maintain charging stations around the perimeter of Lake Michigan, she said.
Christopher Budzynski, director of utility policy at Exelon (NASDAQ: EXC) — which serves four major metropolitan areas, primarily in the Mid-Atlantic region as well as northern Illinois — said the company is expecting 4 million EVs in its service area between 2025 and 2040, including 1 million in Illinois alone.
Clockwise from top left: Chris Budzynski, Exelon; Nancy Ryan, eMobility Advisors; Drew Bennett, Volta Charging; and Cory Bullis, Flo EV Charging | The National EV Charging Initiative
“I think we need aggressive policies that promote transportation electrification. That’s the starting point. And then I think specifically as it relates to what we can do as a utility is really promoting policies that support programs that allow us to get ahead of this. I think that’s where we’re starting to find some challenges across the industry where things are just happening so quickly,” he said.
“Your traditional utility model says build it and they will come. I think they’re already here. So, we need to start building out a little bit more to get ahead of them coming in. I think as we look at the light-duty vehicles coming on to the system, it’s happening, and it’s happening in a significant way. I think it’s happening quickly,” he continued.
Budzynski thinks Exelon is going to play a “critical role” in building that infrastructure and “supporting our customers and communities.” He said the company has a number of different programs across its utility subsidiaries that will allow for construction of over 7,000 charging ports, serving light-duty vehicles, commercial medium- and heavy-duty fleets and multi-unit dwellings.”
“We’ve got to also think about resilience and reliability and ensuring that we have that along with … wires that support these charging stations. It is a very comprehensive support role that the utility needs to play,” he said.
Cory Bullis, public affairs director for FLO EV Charging, a Canada-based company that manufactures chargers in Michigan, underscored Budzynski’s point about Exelon’s role.
Bullis said it is vital to create “well-defined roles for utilities to not only invest in infrastructure to support transportation electrification, but to do it on longer time horizons and to do it at a much larger scale. If we want a resilient grid, then let’s make sure we’re deploying assets or chargers that really fit the use case for the expected dwell time. Let’s have smart chargers so we can better manage the load.”
Keynote speakers for the webinar were Illinois Gov. J.B. Pritzker, supporting the crucial role of state governments in the initiative, and Gabe Klein, executive director of the U.S. Joint Office of Energy and Transportation.
The NRDC assisted in planning the event and provided speakers.
The California Energy Commission awarded grants totaling more than $46 million on Wednesday to four manufacturers of electric tractors, forklifts, car batteries, and charging stations with the intent to bolster in-state production of zero-emission vehicles and equipment.
Ranging from about $8 million to more than $14 million, the grants are among the largest manufacturing subsidies ever awarded by the CEC, part of a $184.7 million funding opportunity announced in March.
“We’re decarbonizing agriculture. We’re decarbonizing passenger vehicles. We’re decarbonizing industry, and we’re doing that by building things here,” CEC Chair David Hochschild said before the unanimous vote. “That is checking so many boxes, it’s just really exciting to me.”
The state is a leading manufacturer and exporter of ZEVs and related products. With Energy Commission oversight, the state and private industry are developing one of the world’s largest lithium sources in an area of Southern California known as Lithium Valley. (See ‘Lithium Valley’ Could Accelerate Calif. EV Sector Growth.)
“This is Lithium Valley,” Hochschild said of the manufacturers and products that received the grants. “These are all part of the same ecosystem. We’d like to see these electric vehicles being served with California lithium ultimately.”
More than 400 jobs will flow from the incentives, all of which were matched by industry, the CEC said.
The grants included $13 million to Monarch Tractor to establish a production line for its MK-V Electric Tractor and attachments in Livermore, California. The grant will help the state achieve its goal of reducing emissions from agriculture, its largest industry, by building 720 to 1,440 battery electric tractors per year, the CEC said.
A $10 million-plus grant to American Lithium Energy Corp., of Carlsbad, will help construct a fully automated battery cell assembly line that is expected to produce 1.5 million electric vehicle batteries annually while increasing the use of U.S. lithium and other domestic supplies, it said.
Wiggins Lift Co. of Oxnard received an $8.1 million grant to modernize and expand its Oxnard plant to increase production of its “eBull” zero-emission forklifts.
The largest grant of $14.6 million went to ChargePoint to increase its output of Level 2 charging stations and direct-current fast charging dispensers to 10,000 units each by 2026, the CEC said. The company manufactures its products in two facilities in the San Francisco Bay Area.
The increase in chargers will eventually reduce carbon dioxide emissions by up to 1.6 million metric tons and create 264 manufacturing jobs, the commission said.
“A lot of people don’t know that right now California is the No. 1 source of ZEV manufacturing jobs, and we want to keep it that way,” said Commissioner Patty Monahan, who leads the CEC’s clean transportation efforts. That can be difficult because of California’s higher costs, so “these grants, I think, are welcome to the industry,” she said.
New York’s John F. Kennedy International Airport is planning an 11.34-MW microgrid powered by solar and fuel cells to cut emissions and continue operations during power outages.
The plan is part of the replacement of three international terminals at JFK with New Terminal One — a 2.4-million-square-foot facility with a $9.5 billion price tag.
It includes rooftop solar panels with 7.66 MW of generating capacity; fuel cells with 3.68 MW capacity; and batteries rated at 2 MW/4 MWH.
The microgrid will be configured in four separate systems that will be connected to the power grid but also able to function independently and to power the airport if needed. The project will use re-claimed heat to generate chilled water and heating hot water and is expected to result in a 38% reduction in greenhouse gas emissions.
AlphaStruxure on Thursday announced the agreement to design, build and operate the microgrid. The Boston-based company is a joint venture of investment firm Carlyle and energy infrastructure firm Schneider Electric.
No price tag was announced for the microgrid, which will operate under an energy-as-a-service contract.
Construction of New Terminal One began in September. The first gates are expected to open in 2026, and completion is targeted for 2030.
The more than 13,000 rooftop solar panels will be the most at any U.S. airport and will make JFK the first transit hub in the New York City region that can function off-grid during power interruptions.
Many military airfields have microgrids, and a growing number of civilian airports are adding such capacity. Pittsburgh International Airport in 2021 said it became the first airport in the world to be fully powered by an on-site microgrid.
As at JFK, the Pittsburgh microgrid was built, paid for and operated by an outside company — Peoples Gas. A notable difference is that the 20-MW system relies on five generators burning natural gas from on-site wells to supplement its roughly 10,000 solar panels.
The zero-emissions microgrid at JFK will mesh with the decarbonization goals of the Port Authority of New York and New Jersey, which operates the airport.
New Terminal One CEO Gerrard Bushell said “sustainability and resilience” are central to the airport’s overhaul.
“This is future-focused infrastructure that will facilitate the transition away from fossil fuels and sets a new standard for large-scale renewable development in New York and in the air transit sector,” he said. The partnership with AlphaStruxure also provides New Terminal One with price certainty, insulating the terminal from volatile energy markets, he added.
NYISO CEO Rich Dewey has rebuked NextEra Energy Transmission New York (NYSE:NEE) for attempting to “lobby” the grid operator to award it transmission projects to connect offshore wind projects to Long Island.
“The NYISO cannot, under its applicable rules, select a project based upon political, parochial or commercial interests,” Dewey said in a Jan. 5 letter, which was first reported by POLITICO. “Grassroots lobbying efforts and media coverage are simply not part of the NYISO’s evaluation of the more efficient or cost-effective solution” to the transmission needs identified by the Public Service Commission.
In August 2021, the ISO solicited projects to add “at least one bulk transmission intertie cable to increase the export capability of the [Long Island Power Authority]-Con Edison interface, that connects NYISO’s Zone K to Zones I and J to ensure the full output from at least 3,000 MW of offshore wind is deliverable from Long Island to the rest of the state” and upgrades to associated local transmission facilities to accommodate the offshore export capability.
Of 19 proposals received from four developers, the ISO last April identified 16 “viable” projects, including nine from NEETNY’s New York Renewable Connect. LS Power, Anbaric Development Partners and the New York Power Authority/New York Transco also made the short list.
Long Island offshore wind projects under development | NextEra Energy
NEETNY’s website for the project includes seven “letters of support” from labor unions, elected officials and others.
The New York State Laborer’s Organizing Fund, for example, said “NEETNY is the only potential developer that has actively reached out to the local labor communities where these lines will be constructed to pledge their commitment to good union jobs and involved us in their process.”
The “Western New York Delegation,” which includes three state senators and two assemblymen, praised the company for its “extraordinary level of communication and capability” in building the 20-mile Empire State Line, the first competitively bid transmission project in the state.
None of the other competitors’ project websites included such testimonials.
In an email to RTO Insider, Kevin Lanahan, NYISO’s vice president of external affairs and corporate communications, said “the independence of the NYISO is paramount.”
“This process, as with much of our work, requires that decisions are made according to an impartial analysis of facts and data, as stipulated in our tariff,” and furthermore “the outcome is critical to the climate goals of the state and reliability of the power grid,” which is why “when attempts to introduce outside influence into the decision-making process became apparent, we determined the prudent course of action was to remind all participants of the criteria being considered,” Lanahan said.
After initially declining to comment, NEETNY told RTO Insider late Wednesday that it would comply with the ISO’s rules.
“As with any project, we always reach out early to the local community and key stakeholders to explain the project need, gather feedback and establish an ongoing dialogue so that if our proposal is selected for construction, we can quickly begin engaging with local partners to incorporate their input,” NEETNY President Richard Allen said in a statement.
“NextEra Energy Transmission New York is grateful to be a participant in the New York Independent System Operator’s Public Policy Transmission Needs process, and we are committed to continue following the processes they have set forth.”
NYISO’s Management Committee on Wednesday approved the ISO’s proposed tariff revisions related to the expiration and transfer of capacity resource interconnection service (CRIS).
The multiyear effort intends to enhance CRIS rules, with the objective of spending 2023 finishing the functional software requirements necessary to allow the ISO to track partial CRIS expirations.
The proposals seek to facilitate increased capacity deliverability by lowering the cost of new entry into the capacity market for an internal generator or an unforced capacity deliverability rights (UDR) facility looking to either transfer their CRIS rights to a same-location unit or expire their partial CRIS rights.
NYISO also adjusted the CRIS retention rules by enabling deactivated facilities to simply notify the ISO at any point that they will voluntarily relinquish their CRIS.
The Long Island Power Authority continued to object to the changes, saying they “do not address their concerns with CRIS expirations associated with interregional transmission ties with UDR,” while three other organizations abstained from the vote. (See ‘CRIS Revisions Advance,’ NYISO Business Issues Committee Briefs: Jan. 18, 2023.)
The proposals now move to the Board of Directors for approval. NYISO anticipates filing the rules with FERC before the end of the first quarter.
External and Virtual Transaction Errors
Sheri Prevratil, NYISO counterparty and credit risk manager, told stakeholders that the ISO identified typographical errors in the tariff language related to changes to credit requirements for external and virtual transactions, approved last year. (See ‘Credit Requirements on Virtual Transactions,’ NYISO Management Committee Briefs: Nov. 30, 2022.)
Prevratil said the two errors “changed one digit in the import supply table and one digit in the virtual supply table,” though these “did not affect the analysis presented to the MC, and [the ISO has] already updated the presentation and tariff language” accordingly.
In response to a question from Howard Fromer, who represents Bayonne Energy Center, Prevratil confirmed that the tariff changes have not yet been filed with FERC and said NYISO intends to first seek board approval for them in February.
As Californians ponder how the state can achieve a 100% clean energy future while maintaining electric reliability, the chair of the California Energy Commission this week offered a two-part solution.
“Offshore wind coupled with storage is how we do that,” CEC Chair David Hochschild said. “Those two things to me go hand-in-hand.”
Hochschild’s comments came Monday during an offshore wind webinar hosted by the California Natural Resources Agency. One listener asked Hochschild if there’s a guarantee that the state will stop using “the dirtiest forms of energy” once offshore wind is deployed.
Hochschild noted that state law requires all electric retail sales to come from renewable and zero-carbon resources by 2045. At the same time, he said, “the paramount issue is reliability.”
The CEC chair spoke enthusiastically about offshore wind, which he said could power a home for a day with a single turbine rotation.
“In my judgment, after rooftop solar, offshore wind is the lowest-impact form of electric generation in the world,” Hochschild said. And offshore wind is “highly aligned” with the late afternoon and early evening hours when power is most needed, he said.
The webinar was moderated by Natural Resources Secretary Wade Crowfoot as part of his Secretary Speaker Series. Crowfoot said more than 500 people tuned in to the session.
Optimizing Locations
For California offshore wind, floating turbines would be 20 to 30 miles off the coast — a location with potential environmental advantages.
“We are very pleased … that this floating technology is able to push projects 20-plus miles from shore,” said webinar speaker Kristen Hislop with the Santa Barbara-based Environmental Defense Center. “Many environmental groups are very concerned about projects closer to shore.”
Hislop said the nonprofit is optimistic about offshore wind’s potential to help California fight climate change, reduce air pollution and improve energy reliability. At the same time, she said, choosing offshore wind sites should consider species and habitat data and not just wind speed and technical considerations.
“We don’t want to see projects inadvertently impact migrating whales, birds and bats, sea turtles, sharks, fishes and other animals that rely on the California coast,” Hislop said.
Another webinar speaker was state Sen. John Laird (D), whose Central Coast district includes the site of the Diablo Canyon nuclear power plant.
Laird said he took part in negotiations over postponing the retirement of Diablo Canyon’s two reactors, which had been planned for 2024 and 2025. The state is now eyeing a 2030 closure date for the plant.
“I helped fashion that deal in a way that if there was going to be an extension, it would be just extended to the time that offshore wind was coming on, so that we could transition the transmission in that area to use [for] the offshore wind,” Laird said.
First Auction Completed
Last month, the U.S. Bureau of Ocean Energy Management held an offshore wind auction for five leases off the Northern and Central California coasts. The auction, the first for the West Coast, brought in $757 million from the five winning bidders combined. (See First West Coast Offshore Wind Auction Fetches $757M.)
The five lease areas — three off the Central Coast in the Morro Bay Wind Energy Area and two off the Northern California coast in the Humboldt Wind Energy Area — have a total capacity of up to 4.6 GW.
That’s far short of the state’s goal of 25 GW of offshore wind capacity by 2045, and some are already thinking about the next auction.
“We need to move quickly to develop siting plans for the next set of call areas,” said Adam Stern, executive director of Offshore Wind California, an industry coalition.
Stern pointed to planning areas off the coast of Mendocino and Del Norte counties, saying there’s potential for another auction within two years. He said stakeholder involvement is crucial.
“It’s critical that all of the constituencies that are represented on this call are part of this discussion,” Stern said.
That theme was emphasized throughout the webinar.
“How do we get this done as quickly as climate change demands?” Crowfoot said in recapping the offshore wind conversation. “But in a way that’s actually inclusive and thoughtful and careful to avoid and mitigate impacts.”
Berkeley Lab researchers say growing renewable generation means it’s likely time to retool wholesale markets’ designs of financial transmission rights (FTRs).
In a study released Monday, “Rethinking the Role of FTRs in Wind-Rich Electricity Markets in the Central U.S.,” Lawrence Berkeley National Laboratory said wholesale markets should consider establishing more flexible FTRs that mimic variable generation profiles to better match congestion rents and payouts. The researchers said more tailored designs would be especially helpful in the wind-rich MISO, SPP and ERCOT markets.
“For an ISO to remain revenue neutral, congestion rent should equal the payout of the FTRs,” they said. “Linking FTR payout to the actual utilization of the grid can improve the match between congestion rent and FTR payout.”
Berkeley said wind generators don’t realize much benefit from FTRs as they’re currently designed and recommended improved hedging mechanisms to lower locational basis risk. Congestion often creates divergences in wholesale market prices between individual pricing nodes and trading hubs; the researchers said fluctuations in locational basis can hurt a generator’s bottom line, deter investors and ultimately slow renewable energy development.
“Conventional FTRs … are structured around an unvarying or fixed contract capacity, which is not particularly suited to generators with varying output,” the report said.
Berkeley researchers recommended the three grid operators design FTRs that can fit variable resources’ operational characteristics. They suggested markets develop wind FTRs, where volume varies based on an hourly systemwide aggregate wind profile. A wind generator could then purchase an FTR for a certain capacity, a portion of which would be dispatched based on the day-ahead schedule. The remainder would then be returned to the RTO or ISO at “no cost or profit to the wind generator.”
Berkeley also suggested FTRs could become dispatch-contingent so that they would only pay the price difference when the generator is operating or that markets institute “cap FTRs” (where the payout is the difference between the load and generator nodes), but only when the node’s price is above a predefined strike price.
The research team acknowledged that “adapting FTR auctions to include new products is not trivial.”
Berkeley said that after studying 2015-2019 data from MISO, SPP and ERCOT, the researchers said it’s clear that wind plants “face a disproportionately larger” locational basis.
“Empirical data from markets in the central U.S. confirm that wind plants face the largest, and among the most volatile, generation-weighted basis of any type of generator,” the report said. “Because wind plants tend to be located far from load centers, they rely on the transmission network to deliver power and are exposed to congestion when transmission capacity is limited.”
The research team said while annual fixed-volume FTRs “can nearly eliminate basis for most conventional generators” with steady output, they’re “less effective for reducing the average basis for wind.”
A fixed-volume FTR reduces wind’s locational basis by $1 to $5/MWh, according to the report, but still leaves wind generators with an average of $1.80 to $3.50/MWh of “residual basis” across the three markets. A wind FTR, on the other hand, could drive down that residual basis to less than $1/MWh.
A financial consulting firm recently concluded MISO needs to update its auction revenue rights and FTR market to reflect the system’s changing flow patterns. Among other recommendations, London Economics International suggested MISO tailor its products to an evolving supply mix and load patterns by offering morning, afternoon, evening and night options. (See Financial Firm Finds MISO FTR Market Needs Work.)
CARMEL, Ind. — MISO appears set to limit transmission congestion by instituting a lower system impact threshold on interconnecting generation that is all but certain to prompt more network upgrades.
“We’ve received a lot of feedback on this item,” MISO’s Kyle Trotter said during a Planning Advisory Committee meeting Wednesday. “We continue to believe that this change will bring positive impacts to stakeholders and future system reliability.”
Last summer, MISO suggested halving new generation’s allotted distribution factor’s (DFAX) effect on transmission from 20% to 10% for its basic and unguaranteed energy resource interconnection service (ERIS). (See MISO Recommends Lower Distribution Factor to Address Congestion.)
Trotter said the change will result in upgrade costs being shared among more interconnection customers and fewer unaddressed reliability issues being passed on to later queue cycles or surfacing in MISO’s annual transmission expansion plans. He also said the likely additional upgrades will help reduce “future reliability issues and overloaded equipment.”
The grid operator responded to a request from MISO South members and studied a 5% DFAX limit but decided the threshold would be too drastic. Staff said a 10% limit provides a good balance without being too aggressive.
Some stakeholders have said that it’s premature to lower the DFAX threshold across the board when MISO hasn’t yet put together a long-range transmission plan portfolio for the South region. Staff have marketed the LRTP portfolios as being able to support more generation interconnections.
Generation developers maintain that a tighter DFAX threshold is punitive and places even more responsibility for system planning on interconnection customers. Some stakeholders have argued that MISO is conflating transmission reliability with real-time congestion costs.
“The plan remains the same,” Trotter said, adding that MISO will begin applying the change to the 2022 cycle of projects entering the definitive planning phase. The revision requires a change to MISO’s business practice manuals.
Several stakeholders complained that staff haven’t studied the possible financial impact to interconnection customers.
“This was sold as a way to reduce congestion,” NextEra Energy’s Matt Pawlowski argued. “I as a NextEra representative don’t know what I’m actually getting with this change. No dollars have ever been shown. I know one thing: My costs are going to be higher. But I’m not sure what I’m going to get for that money. I would love to know what the plan is to actually show that.”
Pawlowski said that the issue was introduced as an economic benefit, but MISO morphed it into a reliability matter.
Andy Witmeier, director of resource utilization, agreed that stakeholders initially raised the issue as an economic one. He said when staff examined the situation, it became clear that the RTO needed to act out of a concern for reliability.
“We’re going to be adding three to four times more generation to our grid than is retiring. So, this is just going to continue. Our stance is that now is the time to make this change. We can’t wait for all these units to come online,” Witmeier said. “Certainly, there are economics at play here, but MISO’s position has always been, ‘This comes down to reliability.’”
“The problem is you’ve not proven anything,” Pawlowski said. “We’ve conflated economics with reliability and come up with reliability because it’s the easier one to pursue. And we’re going to pay those extra dollars not knowing … whether we have better access to the grid. That hasn’t been addressed.”
Witmeier countered that MISO’s reliability analyses of a tighter DFAX threshold turned up “a lot of constraints that we’ve been ignoring.”
Union of Concerned Scientists’ Sam Gomberg said MISO has not performed a cost-benefit analysis to show that a lower DFX cutoff would combat congestion.
“We don’t know the impact of this change. All of the projects could withdraw, and none of these upgrades could be built,” Clean Grid Alliance’s Rhonda Peters said. “I’m not saying that’s the case. I’m saying we haven’t done an adequate study.”
Peters said that MISO has not contemplated how much generation might drop out because of a 10% cutoff.
Travis Stewart, representing the Coalition of Midwest Power Producers, said the change means that the grid operator should update upgrade estimates for affected interconnection customers.
Witmeier said that IC customers, who consistently withdraw from the queue, should perform their own benefits analysis. He argued that the footprint doesn’t currently have enough customers to buy all 280 GW of the generation in the queue.
“MISO is responsible for setting the reliability standards on congestion from generator interconnection. We’re doing that,” he said.
Sustainable FERC Project’s Lauren Azar has maintained that lowering the DFAX threshold will result in more costs transferred to generators.
“Interconnection is about reliability and not addressing congestion,” Clean Grid Alliance’s Natalie McIntire argued during an October meeting of MISO’s Interconnection Process Working Group. “What’s resulting is congestion in real-time, which is an economic issue. ERIS generators are energy-only and should expect to be curtailed.”
MISO staff contended at the time that the binding constraints interconnections ultimately cause are a reliability issue. They said potential constraints are currently being ignored in the GI process, only to crop up later in the system.
NextEra Energy CEO John Ketchum on Wednesday pushed back against allegations of campaign finance violations at the company’s Florida Power & Light (FPL) subsidiary.
In a prepared statement made during the company’s year-end earnings call, Ketchum told analysts that an internal review of media reports of alleged violations by FPL is “substantially complete.”
“We believe that FPL would not be found liable for any of the Florida campaign finance law violations as alleged in the media articles,” he said, basing his comment on “information in our possession.”
Ketchum said the media coverage was used in a subsequent complaint filed in October by Citizens for Responsibility and Ethics at the Federal Election Committee. The ethics watchdog named names in its complaint and tracked contributions totaling $1.27 million to federally registered super PACs in 2020.
John Ketchum | NextEra Energy
NextEra (NYSE:NEE) plans to seek dismissal of the complaint in the next few weeks, Ketchum said.
“[The complaint] primarily relies on media articles that allege certain violations … by various parties, including, by implication, FPL,” Ketchum said. “We do not believe it is appropriate for a complaint such as this to move forward … we do not expect that allegations of federal campaign finance law violations taken as a whole would be material to us.”
NextEra also announced that FPL CEO Eric Silagy plans to retire after 20 years with the company, 11 as the utility’s top executive. Armando Pimentel, who retired from NextEra in 2019 as CEO of NextEra Energy Resources, will replace Silagy.
Silagy has denied any knowledge of the utility’s alleged involvement in manipulating Florida elections, although leaked messages have shown he was in frequent and detailed communication with his senior staff about influencing a state senate race. Silagy served as senior vice president of regulatory and state governmental affairs before being named FPL’s CEO.
Ketchum said NextEra wasn’t making a “connection” between the allegations and Silagy’s retirement but acknowledged the reports may have played a role.
“When you think about all the challenges that he had to overcome, with the hurricanes and high natural gas prices and inflation and supply chain and, you know, the media allegations and all those things, I think it took a toll on Eric that year,” Ketchum said in a response to an analysts’ question. “The way I look at it is it’s a little earlier than I would have hoped Eric would have wanted to do it.”
Shares Plunge
The earnings discussion, leadership changes and NextEra’s mixed results led to nearly a 9% drop in the company’s stock price. Shares closed at $76.59 Wednesday, down $7.31 from the previous close.
NextEra reported a fourth-quarter earnings of $1.52 billion ($0.76/share), compared to $1.20 billion ($0.61/share) a year ago.
For the full year, earnings were $4.157 billion ($2.10/share), up from $3.57 billion ($1.81/share) in 2021.
Operating revenue was up to $6.16 billion from $5.05 billion in 2021. However, analysts had expected $6.3 billion.
NextEra Energy expects 2023 earnings in the range of $2.98-$3.13 per share. The midpoint, $3.05 per share, is lower than the Zacks Consensus Estimate of $3.11.
Ketchum said the Inflation Reduction Act’s passage leaves NextEra “better positioned than ever before to offer low-cost renewables and other clean energy solutions” beyond 2030. He said the company is extending its adjusted EPS growth expectations to $3.63-$4.00 for 2026.
“We will be disappointed if we are not able to deliver financial results at or near the top end of our adjusted earnings per share expectations ranges,” Ketchum said.
