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November 19, 2024

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DOE to Provide $26M for Renewable Energy Projects

The Biden administration announced this week that it will make $26 million available for projects to demonstrate that renewable energy and distributed energy resources (DER) can reliably power the U.S. electric grid.

The investment is part of the Department of Energy’s Solar and Wind Grid Services and Reliability Demonstration Program, created under the bipartisan Infrastructure Investment and Jobs Act that President Biden signed into law last November. (See Biden Signs $1.2 Trillion Infrastructure Bill.)

According to a press release Tuesday, the program is intended to “show how clean energy resources can address key reliability challenges facing the grid [with] tools and plant functions that allow the grid to stay online amid disturbances and restart if it goes down.”

“Americans do not have to choose between a clean grid and a reliable one as we move forward towards our goals of a net-zero economy by 2050,” Energy Secretary Jennifer Granholm said in the release. “Thanks to funding from [the] infrastructure law, DOE is proving that transitioning to solar, wind and other renewable energy sources can keep the lights on without service interruptions while creating good paying jobs.”

Distribution of the funds will be handled by DOE’s Solar Energy Technologies Office (SETO) and Wind Energy Technologies Office (WETO), the department said in a funding notice on Tuesday.

The program will focus on two key areas.

First is design, implementation and demonstration of wind and solar grid services, with $3 million to $6 million each earmarked for three to five recipients. For this category, the program will seek projects that produce at least 10 MW with solar, wind and storage and conduct long-duration demonstrations at existing facilities of their ability to provide grid services at scale. Organizers encouraged applicants to “develop centralized and/or autonomous local controls that demonstrate” the facilities’ ability to react to “operational commands and schedules in the existing … grid.”

The second topic is protection of bulk power systems with high contributions from inverter-based resources (IBR), planned for three or four projects at $2 million to $3 million each. This category is intended to promote large-scale studies of transmission protection systems with large amounts of IBRs, focusing on their response to faults. Recipients should be able to demonstrate protection modeling and simulation capabilities, along with technologies and strategies for maintaining reliability with “any level of inverter-based generation.”

Applicants are expected to include a range of BPS stakeholders, such as utilities, laboratories, universities, vendors of hardware and software, and engineering firms, with preference given to applications from teams of multiple institutions rather than a single organization. The department also encouraged teams to cultivate diverse backgrounds, for instance by partnering with historically Black colleges and universities or other organizations focused on minorities. SETO and WETO will provide a forum for interested parties to connect with each other.

An informational webinar on the initiative is planned for Aug. 17. Concept papers are due by 5 p.m. ET on Sept. 1.

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OGE Benefits from Enable Midstream’s Sale

OGE Energy’s (NYSE:OGE) exit from a midstream gas joint venture continues to pay dividends for the Oklahoma City-based utility.

CEO Sean Trauschke said Thursday that OGE has shed 77% of its limited partner units in Enable Midstream Partners for an $813 million return at an average price of $11.09/unit. Trauschke said that’s a 33% premium from where the units were when OGE and CenterPoint Energy completed Enable’s $7.2 billion sale to Energy Transfer Partners in December. (See OGE, CenterPoint Complete Enable’s Disposal.)

“Interestingly, we’ve already received more net proceeds than the value of our investment when the transaction closed,” Trauschke told financial analysts during the company’s quarterly earnings call. “We’re pleased with the pace of our progress and the value that we’ve captured for our shareholders.”

OGE also received $750 million worth of securitization bonds in July stemming from the February 2021 winter storm. The company has also filed a request with Arkansas regulators to recover $80 million in storm costs over 10 years.

CFO Bryan Buckler said the revenues will be deployed so that OGE will not have to issue equity with its five-year, $475 billion capital investment plan. Much of that plan is customer-focused transmission and distribution assets.

OGE reported earnings of $73.1 million ($0.36/diluted share) during the quarter, as compared to $112.9 million ($0.56/diluted share) for the same period a year ago. It said earnings were primarily driven by more favorable weather and recovery of capital investments.

A partial reversal of a first-quarter interim period consolidating tax benefit related to mark-to-market activity and the gain from Energy Transfer unit sales resulted in a 5-cents/diluted share hit.

Trauschke said its Oklahoma Gas & Electric subsidiary’s grid has performed well during the summer, which has seen 18 days above 100 degrees Fahrenheit since June 1.

“The grid has not been strained; we’ve not cautioned the public about potential blackouts or asked for conservation,” he said. “I’m proud of the performance of our system and employees.”

OGE’s share price lost 54 cents during a down day for the Dow Jones Industrial Average, closing at $40.13.

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Duke Considering Sale of 3.5-GW Renewable Portfolio

Duke Energy (NYSE:DUK) put a “for sale” sign on its 3.5-GW commercial renewable business Thursday, saying it wants to focus its capital on regulated spending.

The company has about 5.1 GW of wind and solar in operation, with net ownership of 3.5 GW and a book value estimated at $4 billion. That puts Duke among the top 10 wind and solar operators in the U.S. and has helped it gain experience in renewable energy development and operations that it will rely on in the future.

But the unit represents less than 5% of the company’s profits, generating $46 million in adjusted earnings for the second quarter.

Competition for Capital

“As we look forward to the remainder of this decade and beyond, we have line of sight to significant renewable grid and other investment opportunities within our faster growing regulated operations,” CEO Lynn Good said during the company’s second-quarter earnings call. “We believe this is the right time to step back and really look at the strategic fit of the commercial business, because there’s going to be competition for capital at Duke.”

The company is projecting an adjusted per-share growth rate of 5 to 7% through 2026.

The renewable business includes a pipeline of 1 to 1.5 GW “that could be quite valuable in 2024-2025, in addition to what we had planned for 2023,” Good said.

The company expects to conclude its review by the end of 2022 or early 2023. Sale proceeds would be used to avoid debt and postpone the need for raising equity, Good said.

NC Carbon Plan

The company will need capital, in part, to fund the new solar, battery storage, onshore wind and “hydrogen-capable” natural gas the company wants to add as part of the proposed carbon plan it filed with the North Carolina Utilities Commission on May 16. The plan also seeks permission to begin early development of long lead-time resources needed in the early 2030s, including offshore wind, pumped storage and small modular nuclear reactors (SMRs).

Good said Duke is working on SMRs “in an advisory capacity” by lending its operating expertise. The company operates the largest regulated nuclear fleet in the U.S., producing about half of its power in the Carolinas.

“We do not have an intention of being Version 1 of anything,” she said. “We would like to see a broader adoption of the technologies, a broader understanding of not only operating characteristics, but the commercial attributes — a price — and the ability to construct them within a time frame that we’re comfortable with. And so we see the decade of the 2020s as an important one to continue that work. And if it progresses, as we all hope it does, we would be in a position to potentially invest in one to come into service in the early 2030s.”

Good indicated that neither supply chain problems in the solar industry nor rising natural gas prices have led the company to rethink its coal retirement plans. “Frankly … the logistics of getting coal from point A to point B are also a challenge,” she said, citing labor shortages in railroads and mining companies.

Inflation Reduction Act, Load Trends

Good said the U.S. Senate’s proposed Inflation Reduction Act would benefit the commercial renewables business and save customers money through the nuclear production tax credit. “We will be impacted by the [15%] corporate minimum tax, but we will also benefit from the credits which will pass to our customers,” Good said.

Duke said it expects its 2022 load growth to be above its initial projection of 1.5%. But CFO Steve Young said the company is continuing to project minimal load growth over its five-year planning horizon as it balances the impact of electrification against energy efficiency.

Good said that while the company is basing its spending on assumptions of little additional load growth, migration trends in the Southeast give it “some tailwinds on growth that I think we’ll enjoy for a period of time.”

“But we continue to believe that flat to 0.5% is the best way to manage the business and always hope to be surprised to the upside,” she added.

Q2 Results

Duke reported GAAP second-quarter earnings of $893 million ($1.14/share) versus $751 million ($0.96/share) in 2021. Adjusted earnings were identical to GAAP results for 2022, a drop from $898 million ($1.15/share) for 2021.

Lower 2022 adjusted earnings resulted from higher operations and maintenance expenses from plant outage timing, higher interest costs and the impact of Singapore-based GIC’s 2021 purchase of 11.05% of Duke Energy Indiana.

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Share Winter Data, States Urge ISO-NE

New England state energy officials are urging ISO-NE to share confidential data about fuel supply and grid reliability with FERC ahead of the upcoming winter.

In a letter to ISO-NE this week, the New England States Committee on Electricity (NESCOE) said it would accept the RTO’s decision not to move forward with a winter reliability or inventoried energy program this year. (See ISO-NE Says No Extra Winter Programs Make Sense this Year.)

But the group said that it is “very concerned that the long-known, significant structural issues contributing to winter reliability challenges remain unresolved.”

To that end, it urged ISO-NE to share with FERC the confidential data that drove the decision not to create a winter program this year before the commission holds a forum in Vermont next month to discuss reliability issues in New England. That could include information about “fuel supplies, resource availability, historical resource performance and overall system conditions” to which the public does not have access.

“We understand that your recommendation for this winter rests in part on your confidence in your assumptions about oil and LNG availability over the coming months, which are based on both economic expectations grounded in historical actions and information not available to us or other stakeholders,” the letter says. “Sharing your analysis and the confidential information behind your fuel supply assumptions and recommendation with FERC would be helpful and appropriate given FERC’s regulatory role, ability to receive and protect confidential information, and expressed interest in discussing New England’s winter 2022/2023 outlook.”

The letter comes a few days after the states’ governors wrote to the Biden administration urging it to consider several actions before this winter, including a waiver of the Jones Act for LNG deliveries to the region. (See New England Governors Ask Feds for Help with Winter Reliability.)

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California Boosts Offshore Wind Goals

The California Energy Commission released an updated draft report this week that would greatly increase the state’s offshore wind goals to 25 GW by 2045, potentially doubling anticipated long-term capacity in response to urging by stakeholders and Gov. Gavin Newsom.

The draft report proposing the targets stemmed from last year’s Assembly Bill 525, which required the CEC to “evaluate and quantify the maximum feasible capacity of offshore wind … [and to] establish megawatt offshore wind planning goals for 2030 and 2045.” The effort is intended to contribute to the state’s goal under Senate Bill 100 to supply all retail customers with 100% clean energy by 2045.

A prior draft of the report in May proposed goals of 3 GW by 2030 and 10 to 15 GW by 2045, but critics contended those goals were too conservative, and the CEC re-evaluated its estimates.

In its latest draft report published Aug. 1, the commission considered stakeholder comments and a July 22 letter from Newsom to the chair of the California Air Resources Board in which he urged “bolder action” to address the urgency of climate change.

“In the letter, among other requested actions, the governor asks the CEC to establish an offshore wind planning goal of at least 20 GW by 2045 and to work with the state’s federal partners to accelerate the deployment of offshore wind, noting that California is home to one of the best offshore wind resources in the world and that offshore wind can serve as a clean, domestic source of electricity that can play an important role in meeting the state’s growing need for clean energy,” the draft report said. “The Energy Commission factored this climate urgency and the call for at least a 20-GW goal into these proposed revisions.”

Soon after the CEC released its first draft report in May, the federal Bureau of Ocean Energy Management issued a proposed sale notice for five lease areas off the California coast, a major step toward BOEM auctions expected this fall and the eventual development of the first offshore wind farms on the West Coast.

Two of the proposed lease areas in the proposed sale notice are in the Humboldt Wind Energy Area off the coast of Northern California, near the city of Eureka. Three are in the Morro Bay Wind Energy Area off Central California, about halfway between Los Angeles and San Francisco. Together, the wind energy areas (WEAs) cover 583 square miles and have the potential to generate at least 4.5 GW of electricity, enough to power 1.5 million homes.

In raising its 2030 offshore wind goals to 3 to 5 GW, the CEC said the “upper end of this range could come from a full build-out of the Morro Bay Wind Energy Area or a combination of a partial build-out of the Morro Bay WEA and Humboldt WEA,” which will require development of a wind port in Humboldt Bay.

“The lower end of that range reflects an understanding that achieving a 2030 online date for any proposed offshore wind project will take a significant mobilization of effort and resources, and timely infrastructure investments, among other factors,” it said. “The CEC will work with state and federal partners to identify process steps and milestones that could allow for a 2030 online date for California’s first offshore wind projects.”

The higher 2045 targets “are designed to be potentially achievable but aspirational and are established at levels that can contribute significantly to achieving California’s climate goals,” the report said.

“These preliminary planning goals may be refined as part of completing the strategic plan as more information becomes available from the analysis of suitable sea space and potential impacts on coastal resources, fisheries, Native American and Indigenous people, and national defense, as well as other strategic plan topics,” it said.

The CEC is scheduled to vote on the revised goals in its business meeting on Aug. 10.

Proponents praised the higher targets.

“These goals set an ambitious course and show California is very serious about ‘going big’ on floating offshore wind to strengthen and diversify its clean power portfolio,” Adam Stern, executive director of trade group Offshore Wind California, said in a statement. “We’re determined as an industry to work closely with state and federal agencies and other stakeholders to ensure the high end of these goals becomes a reality.”

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Exelon, PPL Differ on Impact of 15% Corporate Minimum Tax

Exelon (NASDAQ:EXC) said Wednesday that the proposed 15% minimum corporate income tax included in the Democrats’ energy and climate bill could impinge its cash flow and slow infrastructure investments, while PPL (NYSE:PPL) said the change would not affect it significantly.

The companies commented on the proposed Inflation Reduction Act of 2022 during their respective second-quarter earnings calls.

Exelon CEO Chris Crane praised the bill’s extended tax benefits for solar and wind and its new ones for nuclear and hydrogen, as well as its measures to support energy efficiency and electrification.

But he said the incentives could be undermined by the new minimum tax and “slow the investment needed to make this [low-carbon] transformation.”

“As currently drafted, we could see an impact of … approximately $300 million per year starting in 2023. Higher taxes would ultimately limit our ability to invest in infrastructure needed to accommodate the clean energy our customers want,” Crane said, adding that the company and its trade group, the Edison Electric Institute, is lobbying for “language that better aligns incentives to achieve” decarbonization.

CFO Joseph Nigro declined to say whether the alternative minimum tax (AMT) would increase the company’s equity needs, saying the company would determine a response during its end-of-year planning. “It’s unclear at this point how these taxes will flow through to our customers,” Nigro said.

The company reiterated its previously announced plans to raise $1 billion in equity by 2025, half of it this year, in part to pay down short-term debt from the Feb. 2 spinoff of Constellation Energy (NASDAQ GS:CEG), its former generation unit.

Crane said the company could resort to cost cutting and adjusting project schedules to maintain its capital spending plans and earnings metrics despite the tax.

“There’s a few balls in the air that we’ll have to … juggle. But we’d rather have the fix to the bill so we’re not having to juggle this,” Crane said. “We’ll see how we prevail as an industry as we go forward.”

No Unity

The industry does not appear united on the minimum tax, however.

At PPL’s earnings call later Wednesday, company officials said they did not expect the AMT to have a material impact.

“As you know, we are now a federal cash taxpayer,” CEO Vincent Sorgi said in response to an analyst’s question. “So, we’re not anticipating the 15% AMT provision to have a significant impact on our business. … No real headwind there.”

CFO Joe Bergstein said the company’s effective tax rate is currently about 15%.

Vincent Sorgi (PPL) FI.jpgPPL CEO Vincent Sorgi | PPL

Sorgi said the IRA is a net positive for PPL, particularly as it looks to replace 1,000 MW of coal-fired generation in Kentucky by 2028 and meet Rhode Island’s newly enacted 2033 target for 100% renewable energy. In a solicitation that closes in mid-August, PPL’s Kentucky utilities said they would consider replacing the coal generation with renewables, battery storage, and peaking or baseload natural gas. PPL completed the acquisition of Rhode Island Energy in May.

“The ability to elect the production tax credit instead of the [investment tax credit] for solar will improve the economics of our self-build options as we look at renewables as a potential source of replacement generation in Kentucky,” Sorgi said. “In addition, the extension of the renewable tax credits should lower the cost of renewables overall. …

“The transferability provisions around tax credits also makes it more likely that renewables will be built,” he added. “And that’ll also be good in general for the industry and for accelerating our clean energy transition. It simplifies the structure of the deals significantly.”

EEI told RTO Insider on Wednesday that it welcomed the bill’s “robust clean energy tax package.”

But Eric Grey, EEI’s vice president of government relations, did not directly respond when asked whether the group was seeking changes to the AMT.

“As always, EEI continues to be a resource for policymakers seeking feedback on how provisions in this legislation would impact electric companies and their customers during implementation,” Grey said in a statement.

PPL said EPA’s proposed “good neighbor” rule, expected to take effect late 2022 or early 2023, could require shifting the retirement of an additional 500 MW of coal generation from a planned 2034 shutdown to the “2026 to 2028 time frame.”

The rule would require EPA and states to address interstate transport of air pollution that affects downwind states’ ability to attain National Ambient Air Quality Standards. Based on the final rule, PPL will determine whether to retire the plant or invest in “back-end technology” to keep it operating until 2034, Sorgi said.

Earnings Results

Exelon reported GAAP net income from continuing operations of $962 million ($0.47/share) for the second quarter, up from $808 million ($0.33/share) a year earlier. Adjusted (non-GAAP) operating earnings were $935 million ($0.44/share), up from $842 million ($0.36/share).

Nigro said 2021’s second quarter reflects a 9-cents/share impact for corporate overhead costs that were previously allocated to the company’s generation segment and were required by accounting rules to be presented as part of Exelon’s continuing operations. “These costs were paid for by generation and are not indicative of our corporate overhead post-separation,” he said.

PPL’s second-quarter GAAP earnings were $119 million ($0.16/share) versus $19 million ($0.03/share) in 2021. Non-GAAP earnings from continuing operations were $222 million ($0.30/share), compared with $147 million ($0.19/share) the year before.

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Entergy Beats Expectations with Q2 Earnings

Entergy (NYSE:ETR) easily beat analysts’ expectations with its second-quarter results Wednesday, thanks to better-than-expected retail sales during the early-summer heat.

The company reported earnings of $160 million ($0.78/share) for the quarter. A year ago, the company disclosed a loss of $6 million ($0.03/share).

The New Orleans-based company’s adjusted earnings of $364 million ($1.78/share) far exceeded Zacks Investment Research’s consensus estimate of $1.42/share.

“We had a productive second quarter,” CEO Leo Denault said in a statement.

Denault said Entergy had reached a settlement valued at $300 million with the Mississippi Public Service Commission over performance and accounting issues at its 1.43-GW Grand Gulf nuclear plant in the state. The agreement was designed as a global settlement to resolve all disputes between FERC and Entergy subsidiary System Energy Resources Inc., the plant’s majority owner. (See Entergy Offers Regulators $588M to End Grand Gulf Complaints.)

Arkansas regulators and the New Orleans City Council rejected or opted out of similar settlements this week. The Arkansas Public Service Commission said Entergy’s “low-ball” offer did not include a cash refund for Entergy Arkansas’ customers, as did the Mississippi settlement.

Denault told financial analysts during the company’s earnings call Wednesday that the Mississippi commission “recognized the opportunity to deliver meaningful value to customers today, rather than wait for an uncertain outcome potentially years down the road.”

A FERC decision is expected later this fall.

Grand Gulf sells most of the output at wholesale to Entergy’s Arkansas (NYSE:EAI), Louisiana (NYSE:ELC), Mississippi (NYSE:EMP) and New Orleans (NYSE:ENO) operating companies, but it has been the subject of complaints for overcharges because of poor plant operations and incentive pay to company executives. The plant has been offline for several weeks to repair mechanical issues, Entergy said.

Denault said completing the sale of Michigan’s Palisades Nuclear Plant in May to Holtec Decommissioning International represented the “last major milestone” in exiting the merchant nuclear power segment. (See Federal Aid Likely Too Late to Save Palisades, Diablo Canyon Nukes.)

Entergy’s share price closed Wednesday at $117.38, up $2.27 (1.97%) from the previous closed.

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New England Governors Ask Feds for Help with Winter Reliability

Staring down the possibility of fuel shortages this winter, New England’s governors are asking the Biden administration for help, including a possible waiver of the Jones Act for LNG deliveries to the region.

In a letter to Energy Secretary Jennifer Granholm dated July 27, the six governors in the region warned that price volatility because of the war in Ukraine will have “have significant implications for our region’s electric and natural gas customers and raises reliability concerns if the region suffers a severe winter.”

New England relies on LNG for both electricity generation and heating in the winter, as domestic natural gas capacity is constrained.

The new letter follows increasingly vocal warnings from ISO-NE and a back-and-forth between it and the states over how to prepare for the possibility of extreme cold that could strain the electric grid.

Despite its alerts about the precarious state of the grid in winter, ISO-NE recently determined that no out-of-market solutions to make sure that generators stockpile fuel would be appropriate for this winter because of their cost and unclear benefits. (See ISO-NE Says No Extra Winter Programs Make Sense this Year.)

The states are turning to the federal government with three distinct asks.

First, they request that the administration begin “to explore the conditions under which it might be appropriate to suspend the Jones Act for the delivery of LNG for a portion or all of the winter of 2022-2023.”

The letter notes that the law, which requires that ships hauling cargo between U.S. ports be built in the U.S., “effectively precludes all U.S.-exported LNG from being delivered into New England.”

The governors also asked that the Biden administration consider utilizing the Northeast Home Heating Oil Reserve and consider developing a “new or modernized strategic energy reserve to protect against low-probability weather events to ensure energy system reliability.”

And third, the letter asks that the federal government and the states “commence coordinating immediately to monitor the developments as winter approaches.”

The issues facing New England’s system aren’t likely to disappear overnight, the states acknowledged.

“While our immediate focus is on this upcoming winter, the ramifications of Russia’s invasion and the realignment of natural gas supplies will have long-term global consequences and could have adverse impacts in New England,” the letter says, calling for an expanded energy strategy and construction of new critical infrastructure.

“It’s really important that we have active and direct collaboration and communication going on among all of the entities that have a role to play in ensuring our grid is reliable for consumers in New England,” Katie Dykes, commissioner of Connecticut’s Department of Energy and Environmental Protection, told RTO Insider on Wednesday.

“We’re in a really unprecedented time with the war in Ukraine and supply chain disruptions and volatile commodity prices falling out of the pandemic,” Dykes said. “We know how this is affecting consumers already in terms of energy costs, and we’re keenly aware of the unique vulnerability of the New England electric grid.”

FERC is holding a forum in Vermont in September to examine the challenges facing New England’s grid reliability in winter.

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NH Takes Comments on Climate-centered Waste Management Plan

The New Hampshire Department of Environmental Services (DES) released a draft solid waste management plan Monday that includes a goal of considering climate change in all management planning and decision-making.

Efforts to reach the state’s goal of reducing solid waste disposal 45% by 2050 will have indirect benefits related to the reduction of greenhouse gas emissions, DES said in the plan. New Hampshire set a non-binding emission reduction goal in 2009 of 80% below 1990 levels by 2050, and a bill to establish more stringent reduction targets did not make it through the legislature in this year’s session.

Recycling and food waste diversion practices are two areas the department said could support state climate goals by reducing energy use and associated emissions and reducing methane emissions from food in landfills. In addition, the department said the buildout of local diversion markets would reduce transportation emissions.

Gov. Chris Sununu signed a bill last summer that found New Hampshire “lags behind” in waste reduction and recycling policies and established a solid waste management working group to help DES develop a long-range management plan.

The state’s draft 10-year plan is based on priorities set in 1990 by the legislature that emphasize reducing waste generation at the source and increasing recycling and composting. Despite those priorities, DES said the state’s waste management infrastructure has not shifted significantly from disposal to the preferred management methods over the last 30 years.

“Even though landfilling represents the least preferred method … landfills comprise a significant portion of New Hampshire’s overall waste management capacity,” DES said.

There is no ban on food waste and common food packaging in New Hampshire landfills, but the department recommended in the plan that the state “explore” such legislation. The plan also recommends consideration of legislation that would update state agencies’ procurement policies to prioritize products with “high post-consumer recycled content.”

The department is accepting comments on the draft plan through Aug. 26 and will publish a final version Oct. 1.

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Report: Global Floating Wind Pipeline Grows 228% in 18 months

The global floating offshore wind (FOSW) development pipeline has grown 228% since the last quarter of 2020, reaching 115.9 GW, according to The Renewables Consulting Group’s 2021 Global Offshore Wind Annual Market Report.

New FOSW capacity that is operational, secured or in development, including capacity that is scheduled for auction, has reached 116.2 GW, the report said. Of the new development capacity, 4.9 GW is attributed to the U.S., where the Bureau of Ocean Energy Management is planning lease auctions in California that would unlock at least 4.5 GW of FOSW capacity.

That planned capacity puts the U.S. eighth in the world in terms of national FOSW pipelines, with the U.K. and Sweden taking the No. 1 and 2 slots at 20.9 GW and 18 GW, respectively.

Industry studies of the global pipeline generally expect between 5 and 12 GW reaching commercial operation by 2030, with the remaining capacity coming online post-2030, Dan Kyle Spearman, director and global lead for floating wind at RCG, told NetZero Insider.

RCG analysis expects that West Coast FOSW projects could come online by 2030. Given the nascent status of the FOSW market, those projects looking to deploy by 2030 will be relying on a growing and risky supply chain.

A lot needs to happen by 2030 for the FOSW market to “pump out the big projects,” Spearman said, including identifying the most cost-effective and reliable floating platforms. “We have a database of over 100 different floating wind platform designs, which is madness.”

The market needs to winnow those designs down to a handful that can use the same supply chain and work in an industrialized, modularized process, he said.

Building a domestic FOSW supply chain for the early West Coast projects will bring a complex set of challenges.

“The West Coast is particularly difficult because you don’t have the history of either big ship building or oil and gas,” like on the south and east coasts, he said. That limits the ability of existing ports to service projects in the near term.

Developers will have to be clever about the construction process, according to Spearman. That might include finding alternatives to the current construction approach that favors erecting turbines on their platforms at port and towing them to the project site.

“It’s quite challenging actually to tow a platform long distances with a turbine fully erected because you get quite significant fatigue in areas such as your tower,” he said. If, for example, construction for Morrow Bay projects were to occur in Humboldt Bay, towing the platform approximately 500 miles to Morrow Bay would test the tower’s structural integrity.

The West Coast’s very deep waters of between 900 and 1,200 meters will also present challenges for the platforms’ mooring system design and required supply chain.

“It’s not insurmountable, but there will be a cost to installation,” Spearman said.

The process of sorting out which of the major platform designs the market will choose to invest in likely will come down to geography, cost and the capabilities of local suppliers.

Designs that are suitable for harsh, deep-water conditions on the U.S. West Coast also might be suitable for projects such as in Australia, Spearman said. Currently, semisubmersible technologies are the “most preferred choice,” but Spearman says he would not rule out a tension-leg-platform (TLP) design. TLP is a “very attractive technology because you can reduce your steel weight,” which is beneficial at scale.

If the U.S. is unable to build a robust domestic FOSW supply chain by 2030, developers will be forced to compete for components internationally against developers in more mature markets.

While there will be a strong opportunity for U.S. domestic component supply to develop, Spearman said, there will be uncertainty about the price point developers will be “willing or forced to pay.”

Ultimately, policy will influence supply chain development and the choice between low-cost energy and a thriving domestic economy.

“Developers can go either way, but if they are left with no policy framework, they’ll just go for the lowest [component] option, and local suppliers are just not going to be able to compete,” Spearman said.

The U.S., he said, will need a policy framework in place to build a joint business case for developers and the supply chain.