New York state has reached tentative contracts with developers proposing 24 land-based renewable energy projects totaling nearly 2.4 GW of capacity.
The announcement April 29 is the result of the rush solicitation issued in late 2023, as 81 onshore projects with a total 7.5-GW capacity were in the process of cancelling renewable energy certificate contracts that were no longer economically viable.
The New York State Energy Research and Development Authority expects to negotiate and finalize the tentative new contracts over the next few months. NYSERDA won’t release details on the projects or their costs until final contracts are awarded.
The state’s vaunted renewable energy development pipeline imploded in late 2023 and early 2024. Dozens of projects contracted years earlier had not begun construction when inflation and interest rates skyrocketed.
The state Public Service Commission rejected their petitions in October, saying that renegotiating deals would undercut the competitive process by which they were selected. (See NY Rejects Inflation Adjustment for Renewable Projects.)
Along with the 7.5 GW of land-based contracts that were canceled, developers bailed out on 4.2 GW of offshore wind projects.
It was a serious blow to New York’s hopes of reaching the first of its climate protection milestones: 70% renewable energy flowing through the grid by 2030.
NYSERDA undertook immediate damage control efforts, including onshore and offshore solicitations carried out far more quickly than past procurements.
The resulting tentative contracts fell far short of the cancellations, however: 1.73 GW of offshore wind was announced Feb. 29, and the 2.4 GW of onshore wind and solar was announced April 29. That’s 4.1 GW of tentative contracts to replace 11.7 GW of finalized contracts.
And the equation is worse than even that sounds: NYSERDA on April 19 announced tentative offshore wind contracts totaling 4 GW could not be finalized because the specified turbines would not be available. (See NY Offshore Wind Plans Implode Again.)
Contract cancellations do not equate to project cancellations, however. NYSERDA expects many of the developers will attempt to proceed to construction eventually. But the reset inevitably will mean longer time frames and higher price tags in a state where energy development is already slow and expensive.
One positive detail: The two provisional offshore wind projects chosen in February are mature plans that previously held contracts and are approaching construction-ready status.
NYSERDA said all the tentative onshore contracts announced April 29 also are for mature, late-stage projects, and said some of them were among the mass cancellations of late 2023.
That was a requirement to submit bids in the latest onshore solicitation: Projects had to have achieved late-stage interconnection and permitting milestones.
The trade organization representing the developers that canceled the contracts, the Alliance for Clean Energy New York, welcomed the latest news. It said via email:
“Any day a renewable energy project makes progress is a good day, and we thank NYSERDA for announcing these 24 provisional contract awards from the recent competitive solicitation. Since the projects provisionally awarded today are further along than previous competitive solicitations, it is exciting to know they could be on the grid serving New Yorkers as soon as 2025.”
Also on April 29, NYSERDA issued a request for information that will help it shape its eighth large-scale onshore renewable solicitation, which it expects to kick off as soon as late May and which could yield provisional contract awards as soon as October.
However, NYSERDA is looking at pushing the timetable back a few months to better mesh with the NYISO Class Year 2023 Study. This could give potential bidders a better understanding of their expected upgrade costs prior to submitting a bid proposal.
Responses to NYSERDA’s request for information are due by May 13.
NEW ORLEANS — Five Northeast states have seen contracts for offshore wind projects totaling more than 12 GW canceled in the past year.
Getting them back on track to construction and avoiding future derailments for other projects is a central concern for the advocates and officials working to expand offshore wind in the United States.
An International Partnering Forum panel discussion April 25 looked at lessons learned and ways to move forward. There is much to learn from and much to move forward from: The Northeast scratch sheet reads like a who’s who in the offshore wind industry.
In the past year, the contracts for SouthCoast and Commonwealth in Massachusetts, Park City in Connecticut and Skipjack in Maryland were canceled because of rising construction costs, as were Empire 1 and 2, Sunrise and Beacon in New York; Ocean Wind 1 and 2 in New Jersey were canceled due to construction costs and nonavailability of installation vessels; and provisional contracts for Attentive 1, Community 1 and Excelsior were canceled in New York after development of the 18-MW turbine specified in those contracts was halted.
Empire 1 and Sunrise already have tentative replacement contracts with New York, and bids have been resubmitted for some of the others.
But the wholesale reset of the pipeline in Northeast states inevitably will raise costs and extend timelines.
“You can’t look at everything that has happened over the last year and say, ‘No, we should just keep doing everything exactly the way we have been doing it,’” said Abby Watson, president of The Groundwire Group. “We clearly have designed a system that was not sufficient to meet some of the potential shifts in the market and macroeconomic environment that could come along, and so we need to find more resilient strategies for building this out because these are really long timeline projects … we’re going to have other shocks and disruptions to the system.”
Fred Zalcman, director of the New York Offshore Wind Alliance, said policymakers need to be flexible.
“Let’s remind ourselves that what we’re trying to achieve here is nothing short of standing up a new U.S.-based heavy industry,” he said. “It’s not just the steel in the water, but it encompasses localizing our manufacturing, standing up a new workforce, Jones Act-compliant vessels, community benefits. Those are all very laudable public policy goals, and I don’t mean to question them, but it also comes with some risks and some cost.”
Zalcman said he already is seeing that flexibility in the actions of the New York State Energy Research and Development Authority, which is seeking stakeholder input through a request for information (RFI) as it prepares the state’s fifth offshore wind solicitation and concurrent requests for supply chain development proposals.
NYSERDA Director of Offshore Wind Greg Lampman described the situation as a clean slate.
“We are now … working to not continue to engage and negotiate and revise but really just to start fresh, build a new solicitation gathered by input from the RFI and push forward to continue to develop the industry.”
Power Advisory President John Dalton said his firm is working with Massachusetts and Rhode Island on their latest offshore wind solicitations.
He said the contracts in Massachusetts involve electric distribution companies as counterparties, so they have a more commercial focus than the holistic contracts NYSERDA pursues.
Dalton said the interest rate considerations outlined in New York’s RFI are intriguing.
“Hats off to NYSERDA. The RFI that came out on Tuesday has an interesting formula, which I think really moves the industry forward in terms of one possibility how to better reflect interest rates and the impact on contract pricing,” he said.
Watson raised a larger consideration about renegotiating failed contracts: “Something that we need to be really mindful of in this environment is that there are risks here regarding public perception of offshore wind,” she said.
Traditionally there have been three public selling points for offshore wind, Watson explained: A significantly higher capacity factor to offset its slightly higher levelized cost of electricity; hedging against future increases in the cost of renewables by locking in huge blocks of capacity with a single contract; and development of supply chain, with its economic benefits.
The second and third points have been undercut by the contract cancellations and rebidding, she said. Supply chain confidence is particularly important, she added, because of the long time frames involved. A manufacturer cannot commit to retooling for a project that may change.
“Developers are hugely incentivized to take big risks and big gambles in securing these procurement awards because that’s the way that our process tends to be — expect the developer to take on a lot of that risk and they’re competing on the lowest price with a very limited amount of information about their lease areas,” Watson said.
“We have to find a way to do this better if we want to attract those domestic manufacturing jobs and the supply chain piece,” she added, “also making good on our commitments to the people who have gone through workforce programs expecting to have jobs on a certain timeline that now we’re looking at pushing those timelines out.”
Lampman called that a chicken-and-egg problem: Manufacturers want market certainty before setting up factories to build offshore wind components, and offshore wind developers won’t give it to them until it is too late to add new production capacity for a given project.
Dalton said a helpful change would be a steadier cadence in development — a sense that there will be regular, manageable procurement, rather than states trying to lock down the supply chain for themselves with ever-larger procurement goals.
Watson flagged another issue: Financing is expensive and the interest costs for a new offshore wind farm trickle down to electric ratepayers.
“I think it’s worth noting that if you can get close to 6% on a Treasury bond right now, to be putting your capital at risk on something as long term and challenging as an offshore wind project, it is a fundamental challenge that the industry is facing,” she said.
Lampman said projects bids often are viewed as too high for ratepayers to afford or too low for developers to follow through on. The middle ground is missing in the conversation, he said.
“People sometimes cringe when I say this: We want everybody to make money — just not too much money,” Lampman said. “We continually say we’re trying to build an industry that’s going to be sustainable in the long term and keep persevering.”
Zalcman said the industry and those surrounding it could do a better job communicating the value of offshore wind, explaining why costs are high and explaining the requirements placed on developers — whether it’s sailing ships more slowly to avoid killing whales or expending money and effort for community benefit.
“We really don’t expect of other energy resources what we’re expecting of onshore wind,” he said. “We’re not asking coal plants to do workforce development or invest in ports and harbors, drive the trucks slower. We are encumbering the offshore wind industry with a lot of expectation. And again, I’m not challenging that, I just think as an industry, we probably need to do a little bit better messaging about the value proposition of onshore wind.”
Additional IPF24 Coverage
Read NetZero Insider’s full coverage of the 2024 International Partnering Forum here:
The Maryland Office of Peoples Counsel and the Independent Market Monitor for PJM are urging FERC to reject a settlement to compensate NRG for keeping a portion of its Indian River coal-fired generator online under a reliability-must-run (RMR) contract (ER22-1539).
The agreement would pay NRG $263 million to continue operating the 410-MW Indian River Unit 4 between June 2022, the generator’s initial deactivation date, and the end of the RMR term on Dec. 31, 2026. The payment is split between $35 million for project investment costs and a $228 million “black box” sum, which combined amount to a $164 million cut to the $357 million NRG had requested for RMR service in its initial filing April 1, 2022.
In addition to decreasing the RMR compensation, the settlement would reduce the notice PJM must provide NRG to terminate the contract early, include the Monitor in reviewing new project investments and create a requirement that updates be provided at least three quarters before transmission upgrades are completed to resolve the reliability violations created by Indian River’s retirement. The terms were signed onto by NRG, the Delaware Public Service Commission, Old Dominion Electric Cooperative, Delaware Municipal Electric Corp., the Delaware city of Dover and PJM. The settlement also states that it was not opposed by the Delaware Energy Users Group, Delaware Division of the Public Advocate, Maryland Public Service Commission and Southern Maryland Electric Cooperative.
The Maryland OPC and Monitor both argued the black box nature of the settlement figure prevents the commission from evaluating the merits of the compensation and that about half of the payment would be for sunk costs that NRG already had written off as impaired investments in 2013 and 2017.
The Monitor argued that PJM’s tariff has two pathways for recovering costs incurred to provide RMR service, neither of which allow for sunk costs from prior to the start of the RMR period. In an affidavit, Monitor Joseph Bowring argued the proposed compensation would include $115,862,358 in sunk costs.
“The goal of the tariff language is to ensure that a generation owner who operates a unit past its intended retirement date for reliability reasons is compensated for all the costs that it incurs in order to provide that service. Part V service has the limited purpose of allowing PJM time to complete transmission upgrades needed to ensure the reliable operation of the system after a unit deactivates,” the Monitor wrote, citing PJM’s tariff.
Based on figures included in NRG’s initial RMR filing, the OPC stated that about 43% of the compensation would be for investments made prior to the start of the RMR period. It argued that would put consumers in the position of being asked to pay for losses Indian River experienced during its time as a merchant generator or face increased reliability risk if the resource retired prematurely.
“NRG’s proposition to the commission embedded in the proposed settlement, to the affected states, and to affected electric consumers — boiled down to its essence — is that absent securing the windfall of recovery of a substantial and disproportionate quantum of its already-written-off investment, it will retire the plant, thereby putting at risk operation of the electric grid. The commission cannot and should not endorse this. The plant can be fully compensated for those ongoing operating costs incurred so the plant remains in service during the RMR period without providing it a windfall for sunk investments that it had no investment-backed expectation to recoup years following their write-off,” the OPC wrote.
If sunk costs were allowed to be included in RMR compensation, the OPC argued an incentive would be established for aging generators with poor capacity factors to deactivate early to pursue compensation far higher than what they could receive in PJM’s markets. It estimated the Indian River RMR would come out to about four times higher than recent Base Residual Auction (BRA) clearing prices for the DPL South zone.
“The distorted incentives resulting from possible recognition of an inflated rate base due to sunk, fully loss impaired, investment, for RMR service units will only accelerate this process. The recent filings by Talen Energy … seeking RMR service for the Brandon Shores and Wagner power plants in the constrained (Baltimore Gas and Electric Locational Deliverability Area) is an exponential exacerbation of this problem,” the OPC wrote (ER24-1787, ER24-1790).
In initial comments on the settlement, FERC trial staff stated the settlement is “fair, reasonable and in the public interest” and recommended Settlement Judge Stephanie Nagel certify the agreement.
“The settlement reflects reasoned negotiations undertaken by all participants in good faith and resolves all issues in this proceeding. The settlement provides lower rates through a reduction in the monthly fixed cost charge and elimination of carrying charges in the project investment tracker,” trail staff wrote.
PJM stakeholders are considering two proposals to rework rules around generation retirement requests through the Deactivation Enhancements Senior Task Force. A PJM package would increase the amount of time generation owners must provide of their intent to shutter a resource ahead, while the Monitor introduced a proposal to establish a formula for calculating RMR compensation based on going-forward costs. (See PJM Stakeholders Considering Changes to Generation Deactivation Compensation and Timelines.)
A two-turbine pilot project so far has been the only U.S. offshore wind installation south of New England.
While pioneering projects in the Northeast have been first out of the gate and first to the finish line, the nation’s largest offshore wind farm to date — Coastal Virginia Offshore Wind — is set to start construction imminently in the Central Atlantic region.
Several other wind energy lease areas have been designated and leased in the Central Atlantic, and federal regulators plan another auction this year.
At the International Partnering Forum on April 25, representatives of four states shared their thoughts on how best to advance this new energy and economic sector.
The Central Atlantic region already has had one casualty amid the financial and supply chain constraints that came to fore in the past two years: Skipjack Wind canceled its offtake contract with Maryland, though the project itself remains in development. (See Ørsted Cancels Skipjack Wind Agreement with Maryland.)
“The theme to walk away with is collaboration and the need for collaboration,” Eric Coffman of the Maryland Energy Administration said as an introduction to the discussion. And that was a theme: Central Atlantic states advancing their own interests by collaborating to help grow a new industry that sprawls beyond any one state’s borders.
But as with other discussions at IPF24, the growing pains of the U.S. offshore wind industry also were evident in the remarks.
“One of the biggest challenges we’ve experienced talking with our stakeholders and our Tier 2 and Tier 3 suppliers is that there’s a lack of understanding of what industry needs,” said Emma Stoney, wind and water energy program manager at the Maryland Energy Administration. “Maybe not transparency, just a lack of understanding [of] what the industry needs, when it’s needed, and how the state can be that facilitator and help companies actually get into the industry.”
Stoney tallied the offshore wind aspirations of Maryland and its neighbors: “We have over a 20-GW goal for the Central Atlantic, and that is extremely vague and it’s going to provide a lot of economic development opportunities, but to engage our businesses in it, it requires collaboration.”
John Hardin, executive director of the North Carolina Department of Commerce’s Board of Science, Technology and Innovation, said offshore wind is an unknown for many businesses in his state.
“One thing that we have learned is that the general level of awareness in the industry about offshore wind opportunity is very limited,” he said. “There’s just not much awareness now. So, one thing we’ve been doing is doing a lot of webinars and in-person presentations across the state. We have done several dozen in the last couple of years.”
Alone among its neighbors, Delaware has no formal offshore wind goals. It is by far the smallest state in the region, unlikely on its own to develop economies of scale that could support the offshore wind sector, so it might find interstate collaboration particularly helpful.
Tom Noyes, principal planner for energy policy at the Delaware Division of Climate Coastal and Energy, reported some recent news: Legislation has been introduced that would authorize procurement of 800 to 1,200 MW of offshore wind capacity in his state.
“We understand that a gigawatt is sort of the sweet spot for a project, and at the same time, we’re interested in opportunities to partner with neighboring states if such an opportunity were to arise,” Noyes said. “We’re sort of bringing up the rear, we have learned a lot from working with, learning from our neighboring states.”
Maryland and New Jersey have offshore wind goals of 8.5 GW and 11 GW, respectively, so Delaware’s proximity positions it to support both and benefit economically, he said.
Stone said a study is looking regionally at ways to use each state’s strengths to overcome each state’s challenges, but also for ways to avoid a boom-and-bust cycle.
That’s a good thing, Noyes said. “We can’t be all things to all the districts, and economic benefits don’t stop at the boundaries.”
Jo-Elsa Jordan, business manager at the Virginia Economic Development Partnership, said her state has extensive maritime and industrial assets. Companies looking to enter the offshore wind space should explain their needs and ask for help — there are multiple agencies working to help them succeed.
“Be clear,” Jordan said. “What do you need? What do you like? What are your challenges, what suppliers are contingent on others? Let us know. We can’t write a blank check because we’re stewards of taxpayer dollars. But what we can do is be creative and bring solutions to the table.”
Hardin said there is not universal support for offshore wind in state government, and he advised businesses that want to benefit from the industry to tell their legislators. Businesses telling lawmakers about jobs and economic benefits for their constituents are more persuasive than bureaucrats, he said.
“That’s an important message, and you can help cut through some of the misinformation as well.”
Pulling back to the larger picture, Jordan said local and state entities need to be less parochial if they want to reap benefits.
“From an economic development standpoint, if I’m being really candid — we don’t collaborate, we compete. We want the capital investment; we want the jobs. We want that, and that’s traditional economic development. But offshore wind is a different animal.”
Stoney and Noyes called on the offshore wind industry itself to step up.
“There is a point where a supply chain needs to be able to keep up with the innovation,” Stoney said. “It is a challenge to continually have new turbine sizes coming out every single year, knowing that we need to build Tier 2 and 3 and 4 suppliers who can help support those turbine components. And that makes it really challenging to build a domestic supply chain.”
Noyes added: “We are counting on the industry working its way down, we call it, the learning rate. We’re counting on this industry becoming more efficient over time. We’ve been told to expect that … more important than any particular piece of the supply chain, we need — we all need — a supply chain that’s working and getting more efficient. Because that’s how the industry grows.”
Additional IPF24 Coverage
Read NetZero Insider’s full coverage of the 2024 International Partnering Forum here:
SPP and its stakeholders appear to be nearing consensus on two key parts of their resource adequacy work: establishing separate planning reserve margins (PRM) for the summer and winter seasons and setting up a fuel assurance mechanism.
The Supply Adequacy Working Group on April 22 overwhelmingly approved two revision requests and a so-called transition motion, all related to resource adequacy (RA). The first (RR621) would install a fuel assurance mechanism and the second (RR622) would set winter and summer PRMs of 33% and 16%, respectively.
Given SAWG’s approval of the two reserve margins, members also endorsed a transition motion that, should the PRM be increased, bases the deficiency payment on the sufficiency valuation curve for up to two years from the effective season. The Cost Adequacy Working Group (CAWG) also recommended consideration of a longer sufficiency valuation curve method if a higher PRM is approved.
“This, to me, looks like a win across the board. It’s not just a win for fuel assurance, it’s a win for the planning margin and a win for the transition [motion],” American Electric Power’s Richard Ross said during an April 26 education session held by the Resource and Energy Adequacy Leadership (REAL) Team.
“A lot of staff hours and stakeholder hours … went into [the PRM policy], a lot of discussion. And it took a lot of work to get to where we were,” said SPP’s Chris Haley, who is responsible for developing and managing RA policy items in the RTO’s footprint.
CAWG also took several straw polls — as did the REAL Team in its previous meeting — gauging members’ comfort with the winter PRM. They split, 9-9, on whether staff’s 36% and 16% PRMs are appropriate when determining seasonal balance of risk. Seven members voted to impose those PRMs and keep the sufficiency valuation curve in place for three years; seven others favored a 33%/16% base PRM for 2026 that transitions to 38%/17% in 2028 or 2029.
Casey Cathey, senior director of asset utilization, while pleased with the work so far, focused on approvals yet to come.
“I think the real straw poll we will seek is official approval by the REAL coming in this May time frame,” he said. “It really comes down to the overall seasonal balance of risk and making sure that we’re covering what real-world scenarios were already seen in the winter time frame and where the risk is shifting.”
The REAL Team next meets May 24 and again in June. It intends to bring both PRM options to the Board of Directors and Regional State Committee in August.
“We’re just trying to bring you some of our major policies and to educate everybody and try to bring everybody up to speed,” said the REAL Team’s chair, South Dakota Public Service Commissioner Kristie Fiegen. “Some of it’s really detailed, but I kind of feel like sometimes it needs to be detailed for us to understand it.”
The team met April 18-19 in Denver for what Fiegen called a “family conversation.” It was a candid discussion, after which REAL took straw polls on some of the issues discussed.
REAL Team members agreed a fuel assurance policy is needed and supported SAWG’s direction. They selected, in a 9-4 vote, a 36%/16% base PRM and favored developing a voluntary load-shedding provision as an option for making deficiency payments. Finally, the team supported a 50% incremental cold-weather outage.
Cathey said if a 33%/16% or 33%/18% base PRM ends up being a “palpable option” to stay within a 0.1 day/year loss-of-load metric, SPP needs to avoid “setting an anchor” for the 2026/27 time frame that would place the grid operator behind the curve in two or three years.
“The recommendation would be to spend the time to make sure that we’re all appreciative of what risk we’re actually taking on at both the 33%/16% or the 36%/16% positioning for seasonal balance of risk,” he said, “and trying to cover where the risk of the region is starting to shift.”
VALLEY FORGE, Pa. — The Markets and Reliability Committee discussed a request from the PJM Board of Managers that stakeholders consider endorsing revising the RTO’s governing documents to transfer filing rights for regional transmission planning from the membership to the board. (See “TOs Considering Handing PJM Transmission Planning Filing Rights,” PJM MRC/MC Briefs: Feb. 22, 2024.)
The proposal comes as members of the Transmission Owners Agreement-Administrative Committee (TOA-AC) discuss similar revisions to the Consolidated Transmission Owners Agreement (CTOA) — moving filing rights over planning matters from the Operating Agreement (OA) to the Tariff.
Any changes to the CTOA would require the approval of the TOA-AC and the Board of Managers, which requested the Members Committee vote on the changes in an April 17 letter to the Organization of PJM States Inc. (OPSI). That vote is slated for the MC’s May 6 meeting.
PJM Director of Stakeholder Affairs Dave Anders said the board’s determination that members should weigh in on the change came after stakeholders voiced concern about how a significant change to the balance of authority between the RTO and its members is being considered, including through letters sent to the PJM board by OPSI and the Consumer Advocates of the PJM States (CAPS).
Jessica Lynch, PJM associate general counsel, said the changes would delete Schedule 6, which details the Regional Transmission Expansion Plan (RTEP) protocol, from the OA and add largely matching language to a new Schedule 19 in the Tariff.
General Counsel Chris O’Hara said if the MC endorsed the revisions and the Board of Managers opted to pursue them, the TOA-AC still would need to agree to corresponding changes to the CTOA. He said the PJM board has not ruled out making a Federal Powers Act (FPA) Section 206 filing asking FERC to grant the RTO filing rights if the MC voted against endorsing the proposed language.
Asked where PJM staff stands on the proposal, Vice President of Planning Paul McGlynn said expanding the RTO’s filing rights could allow it to make necessary planning decisions as the grid faces new realities.
“The system is changing dynamically right now. We’re seeing load growth like we have not seen in years, new generation retiring, new generation interconnecting … I do think it’s appropriate and I’m supportive of moving the protocol into the tariff,” he said.
CAPS Executive Director Gregory Poulos said advocates remain frustrated by the pacing of the changes and the lack of information about their potential impact on transmission costs, one of the largest portions of consumers’ electric bills, he said.
“I think there’s a significant amount of frustration that this is being pushed or rushed upon them,” Poulos said of consumer advocates.
Anders said the Board of Managers has asked that members vote on the changes in May to inform its thinking as the TOA-AC aims to conduct its own vote on the CTOA changes, also in May. Poulos questioned why the timeline the TOA-AC has set for itself appears to be defining the time the board and membership have to deliberate.
Adrien Ford, Constellation Energy’s director of wholesale market development, said it’s important PJM members be provided an opportunity to convey their perspectives to the Board of Managers through an endorsement vote.
Paul Sotkiewicz, president of E-cubed Policy Associates, questioned what members would have to gain by giving up filing rights and said the main difference in having the filing rights in the Tariff over the OA would be granting PJM the ability to override stakeholders with an FPA Section 205 filing.
McGlynn responded that PJM still would intend to go through the full stakeholder process to vet proposals, but that it would more appropriately complement PJM’s role as an independent planner to have filing authority.
Asim Haque, PJM senior vice president of governmental and member services, said last year’s critical issue fast path (CIFP) process focused on resource adequacy underlines how holding filing rights can allow PJM to conduct a stakeholder process to solicit proposals from membership to inform its thinking, but still have the authority to bring a filing to FERC if consensus cannot be found. That power could address goals pursued through the stakeholder process, including bringing renewable generation onto the grid, limiting the number of costly reliability-must-run contracts and reducing the backlog of resources in the interconnection queue.
Sotkiewicz argued the CIFP process is a cautionary tale for stakeholders, as the filings PJM ultimately brought to the commission varied significantly from the options the Members Committee most supported.
“To me you’re making an argument to keep everything in the OA,” he said.
MORGAN CITY, La. — With decades of experience servicing offshore oil and gas rigs, Louisiana manufacturers are finding offshore wind a natural expansion for their businesses.
Louisiana companies making the jump hosted visitors from the 2024 International Partnering Forum for a review of their work to date and a preview of their plans to come April 22.
Each has a different niche they hope to seize, but there was a common message in their presentations: We’ve got this.
Oil and gas are the polar opposite of wind power in more than one sense, but there is some commonality in both industries’ skills and tools.
A fine example is the first U.S. offshore wind farm, Block Island Wind — which Louisiana oil workers helped build.
That synergy is what marine fabricators in Louisiana and elsewhere on the Gulf Coast are looking to exploit.
The hard assets are in place; waterfront land is cheap and plentiful; the all-important human infrastructure and institutional knowledge already exist.
However, offshore wind is less an energy transition than an energy addition in their eyes. They expect oil and gas to thrive for a long time to come, regardless of how many state and national proclamations set net-zero or emissions-free targets for one year or another.
On April 25, the closing day of IPF24, a report suggesting ways for Louisiana to parlay its offshore expertise into wind power was released by the Southeastern Wind Coalition, GNO Inc., Center for Planning Excellence and The Pew Charitable Trusts.
Cindy Cutrera, economic development manager for the Port of Morgan City, said the facility is a crossroads for all forms of transportation, with a small airport; direct rail access and future interstate access to the rest of the nation; and water access to much of the nation and world via the Atchafalaya and Gulf Intracoastal waterways.
“We are at the focal point of waterborne transportation in four directions,” she said.
An assortment of marine industrial activity already is in place along those waterways, Cutrera said, and expansion is planned.
“It’s expected to be completed by the summer of 2026 and that’s going to increase our dock space [with] about 900 feet for waterfront access,” she said, “and the laydown area is going to increase from about 200,000 square feet to about 500,000.”
Offshore wind has little presence so far at the port — Oceaneering International and InterMoor are the extent of it — but there is room to grow.
“For the Port of Morgan City or South Louisiana right now, we see the fabrication side — you’re in the hub of fabrication here,” port Executive Director Raymond “Mac” Wade said.
“Louisiana is still trying to figure it out. I think we might be a little behind, but we are trying to push to get wind energy off the Louisiana coast,” he said. “But if nothing else, a lot of fabrication can be done here. I don’t care where it’s shipped, I just want it done using our waterways.”
Wade noted InterMoor recently shipped an order of suction piles from its Morgan City shop to Guyana.
Expansion Strategies
However eager Gulf Coast manufacturers and officials are to supply the offshore wind industry, the region has been slow to embrace it for electricity.
Last year’s federal auction of wind energy lease areas in the Gulf drew minimal interest, although Louisiana itself secured agreements for two wind farms in state waters in late 2023, shortly before then-Gov. John Bel Edwards (D) left office.
Wayne St. Pierre, InterMoor’s facility manager at Port Fourchon, noted the port is going to be the site of Louisiana’s first commercial-scale onshore wind turbine, and is ramping up to dredging to a 50-foot depth, which would allow the largest offshore wind installation vessels to dock.
Here again, wind energy joins fossil fuel rather than replacing it: The port also is the proposed location for a new LNG export terminal.
“Those vessels that do install windmills are really large. They need a place like this, and we are very close to the Gulf of Mexico. That puts us in a strategic spot to develop this facility,” St. Pierre said.
“It’s going to be wind-driven, obviously, but there’s also going to be a need for topside repair, stuff like that,” he added.
He noted there is not an immediate need: The large wind turbine installation vessels requiring a deepwater berth are foreign-flagged and cannot dock to pick up equipment, thanks to a 104-year-old protectionist law known as the Jones Act.
Instead, a workaround is used — load the equipment onto a barge and take the barge out to the installation vessels. But fans of the Jones Act and opponents of offshore wind are trying to stamp out such subterfuge, St. Pierre said.
“They’re already concentrating on that,” added Carrie Adams, InterMoor’s U.S. general manager. “They’re attempting to make that change to say if you take something off that barge and you put it on that vessel and you move that vessel at all to do an installation, you have violated the Jones Act.
“It is difficult for all of us, not just what the renewables industry looks like, it’s also the oil and gas industry,” she said. “It is becoming more and more of a hindrance to all of us.”
Tom Fulton, head of renewables and mooring development for Acteon, InterMoor’s parent company, said the company built its offshore expertise in oil and gas and moved to offshore wind.
Floating wind is the latest focus for Fulton and Acteon, which is using InterMoor’s experience with moorings as an entry point. It does not have any “steel in the water” for the new floating wind sector but it is close, he said.
Floating wind is more expensive and complicated than the fixed-base wind turbines being installed off the Northeast U.S., and there are few floating wind farms worldwide.
Fulton also pointed out there is no supply chain to produce certain floating wind components at scale. Yet.
“A lot of challenges, but it’s all doable with time, money and innovation,” he said.
Undersea Opportunity
Oceaneering International gave a look at its Morgan City facility, where it maintains some of its remotely operated vehicles and trains their operators.
Oceaneering designs its own hardware and software in an iterative process driven by employee and customer input, senior manager David Macnamara said.
While the machines are not terribly difficult to operate — “Even Dave Mac can fly them,” he said — they are quite expensive, and they are working on critical underwater infrastructure. So, there is little margin for error.
Oceaneering International senior manager David MacNamara shows IPF24 visitors the company’s Isurus remotely operated vehicle at its Morgan City, La., facility on April 22. | Oceaneering International
The company invests four weeks of training in new employees and gives them advanced training as they gain experience and demonstrate competency.
Two flight simulators fill a large portion of a classroom.
“You don’t need a degree to come in here to do this,” Macnamara said. “We’ve had little kids come in on tour and just blow us away with the simulators. There’s a job for you in 10 years.
“We get a lot of young people out of the military,” he added. “The Navy has fantastic A schools and C schools for electronics.”
Instructor Andrew “Putt” Bernard, a retired high school teacher who started a second career at Oceaneering two years ago, uses two once-identical cameras as teaching tools. One is normal, the other was crushed like an empty beer can when the ROV it was mounted upon was taken too deep.
The Isurus ROV is rated for 3,000 meters. “You can always fly lower — once,” Macnamara said.
Oceaneering has not worked on the earliest U.S. offshore wind projects, Macnamara said, but the emerging industry is a natural progression for the company.
“The tools are a very good common fit,” he said.
Oceaneering sees expanding into offshore wind as a growth strategy on top of oil and gas as well as a defensive strategy in case the offshore oil and gas sector does shrink, Macnamara said.
“I don’t think we as a company think we’re going to be ending fossil fuels anytime soon,” he added. “We want to be a player in those [offshore wind] markets as those markets develop.”
Building More Boats
Metal Shark Boats has been building a wide array of work, emergency and military vessels on the Gulf Coast for 36 years. Crew transfer vessels for offshore wind facilities are now taking shape in the company’s Franklin, La., boatyard.
Vice President of Commercial Sales Carl Wegener apologized in advance to the Europeans in the contingent from IPF24, then debunked some skepticism about U.S. shipbuilding capabilities.
“When I hear the Europeans say, oh there’s not enough shipyards in the United States to build all the CTVs we need, bull! I could have four more of these going here right now,” he said, pointing to a gleaming catamaran towering in one of the work bays.
Wegener cited the fleet of 32 ferries plying the East River in New York City. The offshore CTVs that Metal Shark is building are of a similar design but with heavier plating to withstand the controlled collisions they will make with monopile towers.
“We built 22 of the 32 right here in 38 months,” he said.
Wegener said his company cannot supply CTVs for some projects because of states’ efforts to steer work to local companies. He does not think those policies can continue — it would be impossible to build and staff an industrial boatyard in every state that wants one.
A welder works at Metal Shark Boats’ Franklin, La., boatyard. | Metal Shark Boats
Metal Shark has not built the offshore service vessels that are the workhorse of the Gulf oil and gas industry, but it has benefited nonetheless from that sector’s heavy presence.
“We’re really lucky that the [offshore oil and gas industry] started here,” Wegener said. “We’ve got tons of tradespeople, training programs, all the companies, the pipefitting, everything that supports oil and gas, there’s a lot of it in this area. It’s just a culture of workforce and that’s really the advantage the Gulf Coast is going to have over the Northeast.”
He added: “Is it hard for us to find labor? Yeah, but not nearly as hard as for my friends up in Massachusetts, Rhode Island and other areas.”
Additional IPF24 Coverage
Read NetZero Insider’s full coverage of the 2024 International Partnering Forum here:
WASHINGTON — The federal Government in the Sunshine Act was passed to bring decision-making into public view, but when it comes to FERC, it does the opposite, a panel of former chairs said at the Energy Bar Association’s Annual Meeting last week.
Some level of agreement is helpful when the commission acts, but it is more difficult to negotiate when the law, enacted in 1976, forbids more than two commissioners from meeting with each other outside of open meetings, said Cheryl LaFleur (2013-2015 and 2017), now chair of the ISO-NE Board of Directors. In any other job, you would gather the decision-makers together in one place and hash out a complex issue, she said.
But “you couldn’t do that; you have to meet one on one with your commissioners,” LaFleur said. “You couldn’t meet as a group. And I always say FERC is not like the Beatles, [who] grow up playing music [together]. It is like the Monkees or the Spice Girls: five individuals chosen separately, and they say, ‘Go make music.’”
FERC used to effectively work on its orders through discussion during the open meetings — and some state regulatory commissions still do that to an extent, like the Texas Public Utility Commission. But now the meetings are almost entirely choreographed, with even the questions commissioners ask staff and the answers written down ahead of time.
Whether it would be a good idea to go back to the old way split the panel.
“I’m all about it,” said James Danly (2020-2021), now a partner at Skadden. “I love deliberating at the horseshoe; it’s my favorite part of the job. … So I can’t speak to that other era; I wasn’t there for it. I think it would be helpful to have more discussion. I certainly was always happy to do so.”
“I think increasingly, as markets are focused on the commission, people are watching very closely, and we’re talking about billions of dollars in investments that the commission is deciding upon at these meetings,” said Neil Chatterjee (2017 and 2018-2020), now a senior adviser at Hogan Lovells. “And if I’m a general counsel; if I’m a CFO of a company; if I’m a lawyer in the Energy Bar, I very much prefer a boring, stable, staged commission meeting. A curveball could potentially roil markets.”
When Chatterjee was on the commission, it voted on a case involving United Airlines and master-limited partnership taxation, which caused companies’ share prices to crash in real time during an open meeting, he added.
Having a debate could work sometimes when it is an issue around reliability, or another issue where politics are not a major factor, LaFleur said.
“What I wouldn’t want to see is just an opportunity for like political grandstanding, where you weren’t really deciding at the table — you just were kind of making speeches — because I think that would be a step in the wrong direction,” she said.
Actually writing complex orders line by line during an open meeting could easily get chaotic these days, said Richard Glick (2021-2023), principal and co-founder of GQ New Energy Strategies. While the overly scripted nature of the open meetings can get tiresome, going off script has its pitfalls as well, with Glick recalling one time he asked staff an impromptu question and the results were not great.
“I feel badly about it,” he said. “But it’s important to have real give-and-take, real questions, as opposed to everything written down in front of you on a piece of paper, and you just go by a script.”
Norman Bay (2015-2017), now a partner at Willkie Farr & Gallagher, also was against the idea of going back to less scripted meetings, noting that it could give the wrong impression of FERC.
“I think members of the bar want to see a commission that is collegial, that is bipartisan and that works well together, right?” Bay said. “Recognizing that there are going to be times when there are sharp policy differences among the commissioners … I fear that if you do everything publicly, it may send the wrong signal in a way that Neil mentioned. So, I think it’s actually better that we have these very vigorous debates in the background.”
All the commissioners agreed earlier in the panel that it is generally better for FERC to act as one, with Danly saying that is especially true for its more “legislative” powers like rulemakings. But politics can sow division on the regulatory body.
When he joined the commission after being an aide to Sen. Mitch McConnell (R-Ky.), Chatterjee admitted he was still acting like a political operator, especially on the Notice of Proposed Rulemaking that the Department of Energy issued early in the Trump administration that would have paid coal plants extra money and torpedoed years of FERC’s work around markets. He wound up voting against that in the end, but some of his communications to the press were a little too political, he said. (See DOE NOPR Rejected, ‘Resilience’ Debate Turns to RTOs, States.)
But now that the rubber is hitting the road when it comes to decarbonization of the grid, the politics are heightened for reasons outside of any commissioner’s background or personality, Chatterjee said.
“I think larger factors have come into play as questions around decarbonization bump up against reliability,” he said. “It just made it harder and harder to compromise on some of these issues.”
NEW ORLEANS — New York’s latest misadventure with offshore wind was impeccably timed, going public three days before a major industry summit.
Its latest attempt to bounce back was equally well timed, announced one day before the head of the agency leading the state’s offshore wind development gave a keynote speech at the summit.
New York State Energy Research and Development Authority President Doreen Harris said at the 2024 International Partnering Forum that the state is pushing forward and so should the industry.
“I believe we need to take a pragmatic approach to how we face these challenges together, and how we find solutions together that will set us up for long-term success. Now is not the time to be complacent or wait it out, or hope these challenges will go away, or hope that someone else will find an answer.”
Every Atlantic state pursuing offshore wind development from Maryland to Massachusetts has suffered contract or project cancellations. New York, with some of the loftiest goals, arguably has had the worst of it.
Contracts totaling more than 4 GW awarded in the state’s first and second solicitations were doomed in October 2023 when the state rejected a request for higher compensation to developers facing soaring costs. (See NY Rejects Inflation Adjustment for Renewable Projects.)
Provisional contracts totaling just over 4 GW awarded in the third solicitation were canceled because General Electric opted not to bring to market the large turbines planned for those wind farms. (See NY Offshore Wind Plans Implode Again.) That was announced April 19, three days before Oceantic Network convened IPF24.
The steps in response were numerous and prompt.
In November 2023, NYSERDA announced an expedited fourth solicitation to backfill the crater left by the October decision, and that solicitation has since yielded two provisional contracts.
On April 23, NYSERDA issued a call for stakeholders to provide input on its fifth solicitation, which it plans to issue this year. Within that solicitation will be a request for proposals on how to reallocate $300 million in state funding for development of major supply chain components.
“So many of you should see yourselves in the solicitation because it’s focused on the suppliers and how to build them domestically,” Harris told the audience at IPF24’s plenary session April 24.
Meanwhile, the state is looking several years ahead, working on version 2.0 of its Offshore Wind Master Plan, and is looking farther out to sea, in deep water where floating wind turbine technology would be needed.
New York’s offshore wind target still officially is 9 GW by 2035, but that increasingly seems like a placeholder while new lease areas are designated, the supply chain develops, onshore infrastructure is built and better deepwater technology is developed.
“My friends, this is just the beginning,” Harris said.
Multiple Iterations
Each of New York’s offshore wind solicitations has been different from its predecessor. The Request For Information issued April 23 will help determine how different the fifth solicitation is, and in what ways.
The RFI suggests some significant changes. NYSERDA may:
switch to a two-step bid process, with developers submitting initial proposals stripped of any dollar figures and follow-up proposals with price tags after NYSERDA provides feedback on the initial proposals;
impose an information blackout, with no public disclosure of details of proposals or price tags all through the process until after the contract is finalized;
require an award security of $10,000 per megawatt upon contract award;
allow contract delivery term extensions for delays for reasons beyond the developer’s control, such as unavailability of key components or installation vessels;
double the contract security sums;
retain a portion of the contract security if the developer misses project milestones, rather than terminating the contract;
define interconnection cost-sharing thresholds and cost-share allocation consistently across all proposals;
make all offer pricing subject to inflation adjustment to protect ratepayers and limit attrition; and
modify the formula for calculating the inflation adjustment to make it more accurately reflect offshore wind’s levelized cost of electricity.
Harris told NetZero Insider that NYSERDA wants input from the industry on the potential framework for the fifth solicitation outlined in that RFI.
“One of our goals in taking in that feedback is how to accelerate our timeline, our procurement timeline,” she said. “And one of the proposals that we have is to run our generation solicitation separate from the $300 million supply chain solicitation. It will have the benefit of accelerating the timeline of the generation procurement, but it will also — at least as we are theorizing it in this RFI — allow more flexibility for the developers to identify and advance supply chain investments.”
New York has a continuing interest in working with other states to expand that supply chain, she said. The hope is that a region can accomplish more than one state.
“The parochialism of the states has diminished somewhat, and very much we’re seeing this integrated supply chain emerge in ways that could be quite useful,” Harris said. “So, for example, if we have a $300 million supply chain focused on primary components, it very much could be the case that an OEM uses those funds to invest in New York for components that will serve another market. And that’s a good thing.”
Harris said there is a dual role for NYSERDA in focusing on the long goal — preserving a livable state and planet — while dealing with the day-to-day bumps in the road to that goal.
“Focusing on the projects that are under construction, focusing on the jobs that are being obtained, focusing on the benefits that we see coming to our communities, those are tangible and real,” Harris said. “And to me if your eye’s on the horizon, it allows you to pay less attention to the twists and turns that are naturally part of a transition. But you know, we’ve got to respond.”
One thing she is less worried about is an increasingly frequent topic of conversation in the industry: the potential victory in the November presidential election of self-professed wind energy hater former President Donald Trump.
Offshore wind spending is infrastructure spending that enjoys bipartisan support, Harris said, and the money flows freely to red states.
“We actually launched our offshore wind goals during the Trump administration. And it has been extraordinary, actually, how much the industry has grown and changed since that time.”
But no offshore wind projects were permitted during the Trump administration, Harris is reminded.
“Permitting is a different matter,” she acknowledged. “Certainly, we need projects to advance through permitting to enter operations. Yes, we pay close attention to the federal context in that matter, because there’s a necessary intersection.”
Additional IPF24 Coverage
Read NetZero Insider’s full coverage of the 2024 International Partnering Forum here:
DENVER — Backers of the West-Wide Governance Pathways Initiative want to move quickly on the first part of their proposed plan to shift CAISO’s governance to an independent entity, leaders of the effort told Western state energy officials April 25.
The straw proposal released by the Pathways Initiative’s Launch Committee on April 10 outlines a “stepwise” approach for gradually transitioning much of the authority of the ISO’s state-run governance into an independent “regional organization” (RO). (See Western RTO Group Floats Independence Plan for EDAM, WEIM.)
Effecting that transition is the initiative’s key mission as it attempts to lay the groundwork for a single Western electricity market that includes California and builds on CAISO’s Extended Day-Ahead Market (EDAM).
“We’re not talking about market design in this group, we’re talking about governance, and that’s been the box we’ve stayed in,” CalCCA General Counsel and Director of Policy Evie Kahl, co-chair of the Launch Committee’s Functions and Scope Work Group, said at the spring joint conference of the Committee on Regional Electric Power Cooperation and Western Interconnection Regional Advisory Body (CREPC-WIRAB) in downtown Denver.
Kahl was speaking on a panel moderated by Washington Utilities and Transportation Commission member Milt Doumit — also a Launch Committee member.
“The problem we’re trying to solve is a perceived lack of independent governance in today’s CAISO Western Energy Imbalance Market [WEIM] and Extended Day-Ahead Market [EDAM],” Kahl said.
Step 1 of the proposal entails elevating the “joint” authority the WEIM’s Governing Body shares with the ISO’s Board of Governors over WEIM and EDAM matters to “primary” authority, a move that would require FERC approval but not a change to California law, according to legal analysis performed for the Launch Committee.
Launch Committee Co-Chair Pam Sporborg, director of transmission and market services at Portland General Electric (PGE), said Step 1 was built on previous work done by the WEIM’s Governance Review Committee (GRC).
“And that’s one of the reasons we’ve been able to move so quickly into a Step 1 recommendation, because so much of these challenges and discussions have taken place with the GRC,” Sporborg said.
Step 2 would establish the RO as a legal entity and, after passage of required California legislation, transition the Governing Body’s primary authority defined in Step 1 to “sole” authority seated within the RO.
Kahl told RTO Insider that Pathways backers are pushing for CAISO to this summer kick off the stakeholder process that would establish the Governing Body’s primary authority, with the hope the ISO would complete the relevant tariff revisions by late fall.
Waiting on NV Energy
According to the straw proposal, CAISO’s filing of those tariff changes with FERC wouldn’t be triggered until EDAM obtains implementation agreements from a “set of geographically diverse” WEIM participants representing load equal to or greater than 70% of CAISO balancing authority area annual load in 2022.
“Assuming all the entities who have expressed an intent to join EDAM as of April 10, 2024, execute implementation agreements, only one additional utility representing at least 10,000 GWh of load and located in the Southwest would be required to trigger the Step 1 governance transition,” the proposal says.
PacifiCorp on April 26 became the first Western utility to announce it will sign such an agreement. (See related story, PacifiCorp Fully Commits to CAISO’s EDAM.) Other entities signaling their intent to join EDAM include the Balancing Authority of Northern California, Idaho Power, Los Angeles Department of Water and Power, and PGE.
“We are not counting NV Energy in [the assumed commitments], but NV Energy could trip the trigger,” Kahl told state officials.
The Nevada-based utility is expected to decide on a market this year, multiple sources have told RTO Insider. A recent study by The Brattle Group indicated NV Energy would gain significantly more benefits from participating in EDAM than Markets+. (See NV Energy to Reap More from EDAM than Markets+, Report Shows.)
Sporborg said PGE’s decision in favor of EDAM came down to an assessment of customer value based on studies by Brattle and Environmental+Energy Economics that examined benefits based on various market footprints.
“We found that the EDAM footprint would provide benefits to PGE’s customers in all ranges of scenarios,” she said. “We also found Markets+ would provide benefits, but to a lesser extent.”
PGE also determined that unwinding its current participation in the WEIM would reduce its financial benefits by about $20 million annually.
Sporborg also noted PGE is a net purchaser in the electricity market and that “getting the right congestion protections for our load was incredibly important to us in our decision making.”
First Step for Step 2
Kahl said Pathways backers will spend the latter part of the year working with California lawmakers to craft the legislation needed to fulfill Step 2 of the straw proposal, with a bill to be taken up in the 2025 session. Still, the group expects to stand up the new RO as a legal entity by the end of this year.
“We do not need legislation to do that,” she said.
After establishing the RO, Sporborg said, Pathways could seat an independent board and begin to work through market oversight issues.
“I think that legislation helps smooth the path towards the RO’s ultimate destination, but that we can do many things and take a lot of action absent a legislative change,” Sporborg said.
Oregon Public Utility Commission Chair Megan Decker asked Sporborg and Kahl how the Pathways Initiative can sustain its efforts both “financially” and “administratively.” The group, which so far has covered its budget from money pledged by supporters, recently was rejected for an $800,000 grant by the U.S. Department of Energy. (See Pathways Initiative Rejected for $800K in DOE Funding.)
“We were disappointed not to receive a DOE grant, but we do have an opportunity to reapply, and based on the feedback we received [from the DOE], we think that we are in a much better position to have a more detailed and specific proposal,” Sporborg said.
Sporborg added the group likely will seek more contributions from supporters.
“It’s been a real challenge, honestly, to stand up a brand-new organization, without the kind of institutional budget that normally comes with a lot of these efforts,” she said. “I think that’s a unique part of this journey, and something that I’ve been really just glad about, which is the support we’ve gotten from a really diverse group of stakeholders.”
