Carbon capture and storage is having a banner year, with 30 commercial CCS facilities now in operation worldwide capable of storing more than 42 million tons of carbon dioxide per year. Add in a pipeline of 164 projects in various stages of development, and the potential stored capacity jumps to almost 244 million tons per year — a 46% jump over 2021 — according to the 2022 Status Report from the Global CCS Institute.
“After so many challenges and so many false starts … the momentum is palpable,” said Brad Crabtree, assistant secretary of the Department of Energy’s Office of Fossil Energy and Carbon Management.
But speaking at a webinar on the report Monday, Jarad Daniels, the institute’s CEO, said optimism about new momentum in the industry must be tempered by the need for unprecedented growth. “Global efforts to reduce emissions, including investment in CCS, are still grossly inadequate overall,” he said. “Government policy must be met with private capital to unlock the full potential of CCS and limit global warming to 1.5 degrees.”
Hitting that target will mean increasing carbon storage capacity more than 100-fold by 2050, said Guloren Turan, GCCSI’s general manager for advocacy and communications.
“The science shows that reaching our sheer climate goals is practically impossible without [CCS],” Daniels said. “CCS is a mature, well-understood technology that is increasingly commercially competitive across the full value chain from capture to storage.”
The report highlights major industry developments, with the expansion of the 45Q tax credit in the Inflation Reduction Act at the top of the list. Daniels said the new law’s $85/ton credit for CCS and up to $180/ton for direct air capture (DAC) could increase deployment 13-fold in the U.S.
Denmark’s €5 billion investment in CCS has also signaled a growing market in Europe, with the Orca DAC plant in Iceland now sequestering about 4,000 tons of CO2 per year. The plant uses a process called mineralization, which turns the injected gas into stone in about two years.
CCS plants worldwide now number 30, with 164 projects at various stages in the development pipeline. | GCCSI
Climeworks, the company behind the plant, recently broke ground on an even larger direct air capture facility in Iceland, which could sequester up to 36,000 tons per year, according to the company.
China has also opened its first CCS plant, with the capacity to capture 1 million tons per year, which is being used for enhanced oil recovery (EOR), according to the report. A second plant, which will capture carbon from coal-fired generation, is under construction.
Despite such progress, the industry faces a challenge in winning over the sizeable number of CCS skeptics, said U.K. and U.S. energy officials speaking at the event. In the U.S. and elsewhere, environmental and other community groups have criticized the technology as a too-expensive strategy for extending fossil fuel generation.
“Not everyone supports carbon capture as the route to net zero,” said Alex Milward, director of carbon capture utilization and storage at the U.K. Department for Business, Energy and Industrial Strategy. “It’s important for us all to work together to bring everyone along on this journey as well as we can.
“There’s more we all need to do together on international standards and modularization and product standards and transport standards, and then we [need] to get the optimal balance between where world CO2 is emitted and where we can cost-effectively capture and store it,” Milward said.
“We need to get implementation right,” agreed DOE’s Crabtree. “There’s a lot of misunderstanding about what [CCS] technologies can and cannot do, but there are also real legitimate concerns about how these investments will benefit in real tangible ways communities, economically and environmentally. That’s something we really have to focus on going forward.”
Turning Point
A turning point for CCS, besides the IRA, was its recognition by organizations such as the U.N. Intergovernmental Panel on Climate Change and the International Energy Agency as critical to the 1.5-degree global climate goal.
In line with that institutional validation, a core driver for market growth is “the demand for greenhouse gas emission reductions in line with net-zero commitments from governments and businesses, together with rising expectations from civil society,” Turan said.
Other factors include the need to decarbonize “products that are critical to human economic development,” such as steel, cement and chemicals, she said.
Early development has been focused on EOR, the injection of CO2 to produce more oil from low-producing wells, which accounts for 21 of the 30 facilities currently in operation. Turan expects the project pipeline will be more focused on other forms of sequestration.
The U.S. currently leads the world both in operating CCS facilities and in projects in development, according to the GCCSI report, with the IRA and $12 billion for direct air capture hubs in the Infrastructure Investment and Jobs Act, focusing on development and investment.
DOE issued a notice of intent for the funding in May, and according to the agency website, an application opening date is expected by year-end.
In addition, the report notes other key policy advances, with the Pipeline and Hazardous Materials Administration releasing new guidelines on CO2 pipeline safety and the Bureau of Land Management issuing guidance on CO2 storage on public lands.
“One of the exciting things for us, it’s not just the scale of these resources [in the IRA and IIJA], it’s also for the first time, we’ve really expanded research and development to include large-scale commercial demonstration, and that’s a major policy change in the United States. It’s long overdue and needed to really ramp up deployment of carbon management technologies across the economy.”
Other key funding in the IIJA includes $2.5 billion for “the development of dedicated regional geologic storage sites” and $2.1 billion for “carbon dioxide transportation infrastructure finance,” Crabtree said. The two projects will work in tandem, he said, so that “we can finally get beyond this historic chicken-and-egg challenge where you develop a carbon capture project, but how do you get the transport done, who develops the storage site?”
The goal, he said, is to build out a CCS “ecosystem in an integrated way on a regional basis, importantly to reduce costs and ultimately so we can bring carbon management to climate scale.”
Speakers at NERC’s annual GridSecCon security conference on Wednesday urged their colleagues to get involved in the Electricity Information Sharing and Analysis Center’s (E-ISAC) biennial GridEx security exercise, with one panelist calling the event a “perfect opportunity” to test emergency operations plans in a highly realistic setting.
Like last year’s event, GridSecCon 2022 was held online because of lingering concerns over the COVID-19 pandemic. (See GridSecCon Panelists Share Cyber Supply Chain Fears.) NERC, the E-ISAC and ReliabilityFirst hosted this year’s conference.
The ERO holds GridEx every two years. Each exercise consists of two parts: a two-day distributed play in which participants across the country work a core scenario developed by the E-ISAC and customized by each organization, and an executive tabletop hosted for leadership of various organizations, including investor- and publicly owned utilities, government entities, and grid operators, as well as representatives from other industries.
Last year’s GridEx VI saw participation in the distributed play portion of the exercise decline for the first time since the event was first held in 2011, which organizers attributed partly to the pandemic and partly to changes in how participants were counted. (See NERC: GridEx Lessons Already In Use.) NERC confirmed earlier this year that planning is already underway for next year’s GridEx VII, which is scheduled for Nov. 14-15, 2023.
Clockwise from top left: Jesse Sythe, E-ISAC; Blake Stave, Xcel Energy; Doug McCracken, Eversource Energy; Adrienne Lotto, APPA. | NERC
This year’s GridSecCon featured two separate panels focused on the security exercise. The first focused on recommendations from GridEx VI, while the second dealt with preparations for GridEx VII and the threats that it will need to consider.
“One of the neat things about GridEx is its amazing flexibility,” Peter Grandgeorge, state national security and resilience programs adviser at Berkshire Hathaway Energy, said in the first session. “And this is part of why I think it’s so successful across the board, and it’s why we’re here today talking about it, because this exercise keeps building … both in the sheer amount of folks involved, but also in depth.”
Grandgeorge and his fellow panelist Lance LaBreck, CAISO’s business continuity manager, noted how the exercise had grown since their organizations began to participate. Grandgeorge reminisced about “sitting around a table [with] about 50 folks” the first time BHE participated in the distributed play in 2013, a number that had grown to 600 by GridEx VI.
LaBreck said one of the most satisfying elements of the evolution of GridEx over the years is its expansion to include stakeholders beyond the electricity industry itself, with input now welcomed from government bodies and other infrastructure sectors like natural gas and telecommunications. He said exercises like this are an opportunity to build relationships with these players so that a utility’s emergency personnel are not meeting them for the first time during a crisis.
“The key part I try to bring up again and again, focused specifically to the electricity subsector, is [that] we are all interconnected … what’s upstream and what’s downstream of us,” LaBreck said. “And if we don’t leverage this training opportunity … at every level we can within the organization, it’s a missed opportunity. There is no other place where you have the ability to bring in your incident command, your cyber and physical security components, [and] your operators to work together internally [and also] to interface with your state emergency management agency [and] your local county … to leverage that relationship.”
In the second panel, Jesse Sythe, the E-ISAC’s GridEx program manager, said the organization’s intent with the exercise is to foster a “train-like-you-fight, fight-like-you-train mentality.” Adrienne Lotto, senior vice president of grid security at the American Public Power Association, said utilities should take advantage of the training opportunity and not be afraid of exposing weaknesses in their defenses.
“I guarantee … you will find gaps and lessons learned. But that’s OK,” Lotto said. “It’s all part of the continuous process to improve, and I think there’s always value to be driven from the exercise.”
Clean energy and public consumer advocates questioned Wednesday whether MISO planners are sufficiently exploring alternatives to the projects transmission owners submit to staff.
Piqued by a batch of expedited substation projects in MISO South for the 2022 planning cycle, they asked for proof that the grid operator is identifying or studying alternative projects. They expressed hope during a Planning Advisory Committee that staff find larger regional projects that could satisfy several needs rather than blindly accepting TOs’ project plans. (See MISO’s 2022 Tx Planning Cycle Exceeds $4B.)
Several stakeholders said TOs don’t make enough project specifications public to allow meaningfully proposed project alternatives. “More detail needs to be given to stakeholders ahead of time,” Southern Renewable Energy Association Executive Director Simon Mahan said.
He suggested that MISO planners might also lack the capabilities to study project alternatives.
“As a stakeholder, I don’t know what to do,” Mahan said. “I think you all are doing the best you can … but $70 million is a lot to rush through. I don’t know if MISO has the tools to future-proof the system. I’m just worried how many more times this is going to happen in the future. I’m just really worried about this.”
This summer, Cleco applied to include a 230-kV and an 138-kV substation, each costing $15 million, for expedited treatment. Entergy requested approval to install two additional 230-kV breakers into an existing substation near the Louisiana-Texas border; to construct a 230-kV substation; and a $32.6 million, 115-kV substation in northern Mississippi. The utilities said the projects were necessary because of load growth in their territories.
MISO recommended all the projects for late inclusion in its 2022 Transmission Expansion Plan.
Clean Grid Alliance’s Natalie McIntire said her organization has raised the issue with MISO several times. She said she believes that Order 1000 obligates staff to offer and analyze project alternatives.
“Whenever we ask about this, MISO assures us it studies alternatives. But we don’t in the stakeholder process see alternatives. … This is an issue of costs for consumers,” McIntire said.
She said it seems that MISO “does a lot of hand waving” in only reassuring stakeholders that they study alternatives, but don’t back that up with evidence. The RTO is best positioned to examine alternatives with its “top-down” view of the system, McIntire said.
“We continue to make these comments, and I feel like it’s never quite resolved,” she said.
Jeanna Furnish, MISO’s director of expansion planning, said “there are situations in which” MISO comes up with alternative projects, with those alternatives sometimes presented in subregional planning meetings.
“So does every single project get an alternative? That’s probably not true,” she said.
Furnish said MISO will “think through” whether it has the tools to adequately study alternatives and how it might be more transparent in discussing the alternatives.
She also said grid operators stand to be affected by FERC’s notice of proposed rulemaking on more comprehensive transmission planning. Furnish appeared before the commission’s technical conference on transmission planning earlier in the month. She said then it isn’t feasible for grid operators to consider alternatives to every TO-proposed project. (See States Urge More Transparency on Tx Planning, Independent Monitors.)
Cleco Energy’s Chris Thibodeaux said the utility’s expedited projects will bring jobs to Louisiana and are requested by industrial customers who need transmission-level service.
“I’m not sure how the Environmental Sector really has a say in that,” he said.
Jeff Cook, with the Office of Consumer Advocate, said a public consideration of alternatives can help stakeholders more easily accept expensive projects.
LS Power’s Brenda Prokop added that an evaluation of alternatives could help determine whether the RTO could rely on larger projects to take care of various smaller needs.
Mahan agreed that MISO could help members figure out whether larger projects would save money and give stakeholders more confidence in the planning process.
The California Energy Commission approved a $31.3 million grant Wednesday for a long-duration storage project that will pair vanadium-flow and zinc hybrid cathode batteries with carport solar panels on tribal land in San Diego County.
The 60 MWh microgrid project is the first recipient of a grant under the state’s new Long-Duration Energy Storage Program (LDES), funded with $140 million in the state’s recently enacted 2022/23 budget.
Long-duration storage is a priority in California, where the grid is increasingly reliant on variable renewable generation, especially solar, requiring longer storage discharge times to compensate for cloudy weather and extended interruptions from equipment failure, forest fires and extreme heat.
Approximately 3,600 MW of four-hour lithium-ion batteries have been installed in the past three years, but those batteries have limits, Erik Stokes, deputy director of the CEC’s Energy Research and Development Division, said.
Invinity Systems makes vanadium flow batteries being used in the 60 MWh project in San Diego County. | Invinity
“Currently, we’re relying on one technology for our energy storage needs in lithium-ion,” Stokes said. “Lithium-ion is a great technology. It’s really enabled us to achieve a lot of our clean energy progress, but it’s not a silver bullet. There’s been a lot of well publicized concerns about supply chain and safety issues with lithium-ion technology.”
The batteries are vulnerable to overheating and fires, and worldwide competition for lithium is straining supply. So, the state is seeking non-lithium resources able to discharge energy to the grid for at least eight hours and up to 100 hours.
Priority for LDES is being given to technologies on the verge of commercialization or positioned for widespread deployment within the next five to 10 years.
The project components approved Wednesday fit that bill because they have a successful history of field demonstrations and have attracted significant private capital to scale up manufacturing, the CEC said.
The zinc batteries, manufactured by EOS Energy Enterprises, do not use rare-earth minerals such as lithium, reducing risk in the supply chain, and they can operate at much hotter and colder temperatures than lithium-ion batteries, the commission said. The vanadium flow batteries, made by Invinity Energy Systems, have proven safe and stable and can perform for 25 years or more, the CEC said.
The project will be installed at the Viejas Band of Kumeyaay Indians Reservation and casino near the town of Alpine, California.
More LDES projects are set to follow. The CEC said it expects to provide $50 million to $180 million in total funding for long-duration storage next year through LDES grants and its Electric Program Investment Charge (EPIC) funding, which supports earlier-stage demonstration projects.
CAISO began a stakeholder process Monday to explore the benefits of greater regional cooperation and a Western RTO, as California lawmakers had requested in Assembly Concurrent Resolution 188, passed in August.
ACR 188 asked CAISO to report to the legislature by February on recent studies of the “impacts of expanded regional cooperation on California” and to identify “key issues that will most effectively advance the state’s energy and environmental goals, including any available studies that reflect the impact of regionalization on transmission costs and reliability for California ratepayers.” (See California Legislature Asks CAISO to Report on Regionalization.)
Despite its limited goals, many saw the resolution as potentially restarting discussion of a Western RTO involving CAISO. Several prior attempts from 2016-18 failed because lawmakers were unwilling to expand CAISO’s one-state governance to other states.
Monday’s meeting was a brief introductory session that laid out CAISO’s plans to produce the report in the next four months in partnership with the National Renewable Energy Laboratory (NREL), which it commissioned to author the study. NREL is expected to draft the report by November, followed by stakeholder comments and calls in December.
Monday’s meeting materials cited 30 relevant studies since 2011 as a starting point. They included a study conducted by CAISO in 2016 under Senate Bill 350, which found that a “multi-state regional electric market and grid overseen by the ISO would provide significant environmental and economic benefits to California and the West,” the ISO said.
Another study published last year found an RTO covering the entire U.S. portion of the Western Interconnection could save the region $2 billion in annual electricity costs by 2030 and cut carbon dioxide emissions by 191 million metric tons. A group of Western states led the study, financed by the U.S. Department of Energy. (See Study Shows RTO Could Save West $2B Yearly by 2030.)
A subsequent study released in July by Advanced Energy Economy looked at regional economic effects. It concluded an 11-state Western RTO could generate roughly $19 billion to $79 billion in additional gross regional product by 2030 and could help create 159,000 to 657,000 permanent jobs. (See Study Tallies Economy-wide Benefits of Western RTO.)
CAISO and NREL asked participants Monday to send comments listing additional studies they should consider and those they should not consider, both with supporting comments.
SPP told stakeholders last week that it has chosen a hybrid approach to improve its transmission- and congestion-hedging markets, focusing first on equitably allocating congestion rights instruments and then increasing the pool of awards available.
The proposal marks a change in direction from the initial focus on counterflow optimization. Stakeholders were unable to coalesce around the market mechanism despite three years of effort.
The SPP Board of Directors in April directed staff to survey members, the regulatory stakeholder groups and the RTO’s Market Monitoring Unit (MMU), gather feedback, and bring a final recommendation to the board’s October meeting. (See “Counterflow Optimization not Dead Yet,” SPP Board of Directors/Markets Committee Briefs: April 26, 2022.)
Staff will bring a proposal to the board later this month, but they will also ask that a vote be delayed until the directors meet again in January. That will give the board and state regulators an opportunity to provide the policy direction that will go into developing tariff changes. It will also give staff more time to build stakeholder support for the proposal and gather additional feedback.
“I know the board values input from the members, but we feel that this is taking a look at the entire picture and not just focusing on one thing,” COO Lanny Nickell told the Markets and Operations Policy Committee Oct. 10. “We feel pretty confident and pretty good on the direction where we’re going.”
Nickell complimented staff for their recent work “to get some movement on resolving the concerns and issues around the congestion-hedging process.” Congestion-hedging supervisor Micha Bailey said staff talked with stakeholders who provided input to gain a deeper understanding of their concerns.
“We kept hearing some of the same themes … Fair, transparent, equitable, needs to provide a hedge. And as we looked at those and as we were hearing the same common themes, we wondered, ‘What can staff propose?’” Bailey said. “What can we propose that’s going to help SPP today and also in the future, recognizing that generation is changing.”
Bailey said “hybrid” was the new buzzword, replacing counterflow optimization. That market mechanism, which keeps system transmission flows between two points in balance, was meant to address concerns about how congestion rights instruments are awarded and the current process’s efficiency. (See SPP Continues its Counterflow Optimization Work.)
The hybrid proposal will increase the number of hedges available as the Holistic Integrated Tariff Team intended when it approved a package of 21 improvements to the SPP grid in 2019, Bailey said.
“We’re going to increase equity and fairness within the congestion-hedging process,” Bailey said. “We’re focusing on bringing those who are getting nothing up right. When you introduce equity, some entities [receiving hedges] … have to give up some to allow other entities to come in. We need to focus on a short-term solution that that will help entities that are getting nothing get something.”
He compared the current process to a buffet line, where excess auction revenue is distributed to participants, who already have hedges, in what amounts to a load-ratio share.
“You’re double dipping … at the end of the year, you’re getting something on top of what you want,” Bailey said. “In the buffet line analogy, which we’ve heard time and time again, you’re going two to three times in the buffet line. Those sitting with empty plates at the end of the year, they’re the ones who should be getting the ARR excess revenue.”
Staff’s recommendations include:
Resetting long-term congestion rights (LTCR) awards every 10 years to give market participants more opportunities to gain the hedges.
Modifying the LTCR’s second round of nomination capacity from 100% to a more equitable incremental percentage up 100%.
Changing the auction revenue rights (ARRs) process’ annual first round nomination capacity calculation to more fairly allocate ARRs.
Revising the ARRs’ first round nomination capacity from 50% to an incremental percentage up to 50%.
Distributing excess auction revenues.
SPP also plans to update its load and generator modeling to better align them with transmission service that is studied, review the planning process’ firm transmission assumptions, and provide further stakeholder education.
“We need to involve the upstream applications from congestion hedging because congestion hedging starts with firm transmission service,” Bailey said.
While stakeholders generally expressed support for the proposal, American Electric Power’s Richard Ross, who chairs the Market Working Group that put a lot of time and effort into resolving the issue, offered a counterpoint.
“I don’t hold out much hope for the stakeholders suddenly going, ‘Oh yeah. This is great.’ But, you know, we’ll see,” he said, offering his own praise for staff’s work.
MMU Executive Director Keith Collins said the hybrid proposal addresses the monitor’s concerns and is a good package.
“There’s no silver bullet in this process. The approach that Micha is outlining is like a scattershot approach … but it applies that basic set of points that Micha raised of how we improve the equity so that we can improve affordability,” Collins said. “We reduce the effects of the buffet line. You want people to go through the line and if you can do that at least a couple of times, you’ll allow folks to be able to get more if you’re at the back of the line.”
Members Address Resource Adequacy
MOPC approved five revision requests (RRs) related to resource adequacy and a planning reserve requirement (PRM) that the board and state regulators recently raised from 12% to 15% for the summer season, effective next year. (See SPP Board, Regulators Side with Staff over Reserve Margin.)
The committee had to first reconcile competing versions of a revision request (RR515) that lays out the process by which load-responsible entities (LREs) may qualify for and receive exemptions of the deficiency payments assessed to those that have not met the tariff’s resource adequacy requirement, if they have met the applicable criteria.
Members eventually sided with the version brought forward by the Supply Adequacy Working Group (SAWG), which allows a three-year exemption from a deficiency payment and adds triggers if the PRM was increased the year before. To qualify, LRES must demonstrate they had adequate capacity to meet the resource adequacy requirement based on the prior effective PRM and show enough capacity to meet the upcoming season’s forecasted load and a prior effective PRM.
Under SAWG’s version, LREs meeting the PRM, must demonstrate that as of April 5 of the current year, sufficient capacity for purchase has not been identified on bulletin board or demonstrate a contracted obligation to purchase capacity from a generator/developer or demonstrate it has a pending request for interim, surplus or replacement generator interconnection service that is of sufficient size.
The Cost Allocation Working Group, comprised of regulatory staff and which reports to the Regional State Committee, offered the same language, with the exception of using “and” instead of “or” before “demonstrate it has a pending request …”
The motion to endorse RR515 cleared the two-thirds threshold at 72.5%.
Casey Cathey, SPP’s director of system planning, said staff has already begun developing the principles for deficiency payment exemptions.
“[The exemption] needs to be realistic and must support reliability improvements,” he said. “We need to ensure the policy meets the proper incentive for the reserve margin. When it’s increased, we need to make sure we’re still sending the right signal for reliability purposes. We want to create a positive policy that FERC would agree to and approve.”
A bulletin board for informational purposes only will be developed so LREs and generation owners can view and post requests to buy or offers to sell power. All information on the board will be confidential, with only the MMU having the rights to review the data.
SPP bases its reserve margin requirement on a probabilistic loss-of-load expectation (LOLE) study during summer months that is performed every two years to determine the capacity needed to meet the reliability target of a one-day outage every 10 years (0.1 days/year).
Stakeholders also approved RR508, which allows LREs to use deliverable capacity to meet their winter season obligation as well. SPP said with more LREs seeing increased loads in the winter season and some becoming winter peaking, it became apparent that the LREs should be able to use the same method to meet their winter obligations.
MOPC also endorsed three other RRs:
RR513: Removes barriers to requesting surplus interconnection service by permitting expansion of existing substations to a location near enough to be considered part of the existing substation. Equipment additions required at the interconnection substation classified as network upgrades would not invalidate the request and would further permit added or modified “system protection equipment” at a remote substation.
RR516: Implements the planning reserve margin’s increase from 12% to 15%.
RR517: Creates a business practice documenting SPP’s consideration of a long-term service reservation as evidence that interim interconnection service or interconnection service subject to limited operations associated with a long-term service reservation causes no adverse thermal or voltage impacts to the transmission system. It also documents that the generating facility can continue to operate, provided there are no adverse short-circuit or stability impacts.
RRs 508 and 513 passed together unanimously and RR517 passed with 93% approval. RR516 barely passed at 67.9% approval, although it simply adds the 15% PRM to the tariff. AEP opposed the proposal during the SAWG vote, saying imposing an immediate 25% increase to the LRE reserve margin, given SPP’s generator interconnection queue backlog and other challenges faced by LREs, “sets a dangerous precedent and represent a poor implementation of capacity rules changes.”
Members Endorse 2022 ITP
MOPC approved a pair of working groups’ recommendation to endorse the 2022 Integrated Transmission Plan and its assessment report. The 2022 assessment report documented the 2022 plan as being complete.
The Economic Studies (ESWG) and Transmission (TWG) working groups said the reliability-only portfolio is smaller than previous ITP plans, thanks to the $3.4 billion in new transmission projects being placed in service between 2015 and 2019. The 17-project, $35.4 million plan solves 25 system needs in rebuilding 11 miles of transmission but will not result in any new transmission.
During the re-baselining process, staff worked with the ESWG and TWG on a comprehensive review of the ITP’s governing documents to find efficiencies and improvements to help meet future assessment deadlines. The work resulted in four to six weeks of time savings.
SPP staff is currently juggling three other planning studies: the 20-year long-term assessment and the 2022 and 2024 ITPs. The 20-year assessment is the only study that is still behind, and that is only by one month. Staff said they will have to reduce scope to meet its April 2023 deadline.
Cathey complimented the ESWG for developing 2024 ITP futures that reflect industry trends in arriving at realistic renewable energy projections.
The stakeholder group’s base case foresees solar capacity growing from 7.1 GW to 14 GW between years five and 10 and wind increasing from 43.8 GW to 49.9 GW. Its emerging technologies future has greater projects of 11 GW to 22 GW and 48.2 GW to 54.9 GW, respectively. The ESWG expects storage to grow to as much as 8.8 GW in 10 years, based on a percentage of solar capacity.
“For a number of ITPs, we feel like we’ve gotten better at hitting the future. That said, the last few cycles, we’ve been hitting 10-year numbers within two years,” Cathey said. “We believe, especially given the Inflation Reduction Act and everything that’s going on in the industry, that this is probably the first one that really is taking a leap. We’re kind of all on board that this is a better prediction of what we’re actually going to see in the next five to 10 years.”
The ESWG evaluated more than 35 projections, using input from SPP’s GI queue, the U.S. Energy Information Administration’s annual energy outlook, and extrapolated 2022 ITP input from its members and the Market Monitoring Unit to arrive at its numbers.
The group plans to bring the final 2024 ITP scope document to MOPC in January for its approval.
Cathey also said the long-term assessment, due in the spring, should inform more of the assumptions that will be made in the 2025 ITP and in the consolidated planning process.
Increasing BTM, DR Resources’ Visibility
MOPC approved a pair of Operating Reliability Working Group (ORWG) revision requests designed to give SPP’s balancing authority visibility into controllable, dispatchable, non-registered behind-the-meter (BTM) and demand response data, referred to as “cats and dogs” by some stakeholders.
The ORWG said RR520 improves the BA’s ability to forecast and measure non-registered, available demand response by analyzing data submitted daily from affected load-responsible entities (LREs). Under RR512, LREs will submit used and unused capacity on BTM resources that have qualified as accredited capacity that can be used to respond to emergency conditions.
The first change passed with 84.4% approval and 10 abstentions. RR512 passed unanimously, also with 10 abstentions.
The RTO said its tariff exempts certain generations of small size from full market registration. Because some entities don’t have the proper technology to meet market registration data requirements, SPP will allow data submission through its managed file transfer system but plans to also use its application programming interface before next February’s implementation deadline.
“[Being] registered is key, whether through the market or modeled in [the energy management system], but it is not a requirement for all units that are BTM,” SPP’s Yasser Bahbaz, director of markets development, told stakeholders. “If these resources are not registered, then we are not requiring or receiving telemetered information … Your BTM units may be modeled in the reliability model but not registered. In this case, we still need to know about the info requested in these RRs.
“Knowing that capacity that’s available is really important to SPP,” he said.
“We need SPP’s real-time visibility into what’s out there,” Nebraska Public Power District’s Ron Gunderson, the ORWG’s acting chair, said.
The changes are a result of the 2021 winter storm, which required SPP to rely on energy transfers from MISO to meet demand.
The MMU registered several concerns with the changes, saying BTM generation and demand response are not adequate for the grid operator to objectively apply its performance-based accreditation but would likely represent a small reliability risk. It disagreed with the grid operator’s legal determination that adding the data requirements to the operating criteria results in enforceability and recommended better definition of various terms.
GI Backlog Down to 405 Requests
Staff told MOPC that they have reduced the number of active requests in the GI queue down to 405 as of September, a 37.8% reduction since their backlog mitigation process began in January with 651 requests. SPP has eliminated 76 active requests since its last update to members in April. (See “Staff Reducing Interconnection Queue’s Backlog,” SPP Markets and Operations Policy Committee Briefs: April 11-12, 2022).
“We’re happy with the progress we’re making,” the RTO’s Juliano Freitas said.
Renewables dominate SPP’s current generation-interconnection queue. | SPP
More than 200 requests have been withdrawn, leaving 222 in progress and another 183 waiting to be processed. The grid operator has executed 33 GI agreements, with four more pending.
But SPP is still in a hole, though not as deep. Staff said they have received and validated another 82 GI requests totaling 17.7 GW of capacity since April. That leaves the current queue at 487 requests totaling almost 96 GW of capacity. Solar requests (210, 45.1 GW) account for the bulk of the new requests.
Freitas said the grid operator doesn’t plan to close the current cluster until its finishes the backlog mitigation plan, still on schedule by the end of 2024. He said SPP is forecasting that it could install more than 50 GW of capacity by 2028.
“We have to keep our eyes on [the current cluster], because we don’t think it’s feasible to study a cluster with 100 megawatts in it,” he said.
NASEB Gas-electric Forum Convened
Charles Yeung, SPP’s executive director of interregional affairs, encouraged members to engage themselves in a gas-electric harmonization forum recently begun by the North American Energy Standards Board.
The forum was convened in August at the request of FERC and NERC. The organizations want NAESB to address a recommendation from their 2021 joint report on the year’s winter storm that calls for improving the reliability of the natural gas infrastructure system in support of the bulk power system. The recommendation focuses on gas-electric information sharing regarding system performance, gas infrastructure reliability during cold weather, and generators’ ability to obtain fuel during extreme cold weather.
“Obviously, SPP alone cannot deal with those issues,” Yeung said, noting many of the items date back to a similar cold-weather event in 2011. “Some of these issues have been brought up before, but the perception of them has changed with the disaster in Texas.”
The forum is tasked with delivering a report that includes concrete actions to increase gas infrastructure reliability, detailed plans to implement the recommendations, and the entities responsible for deploying the changes. The group met for the first time in August and will continue to convene monthly into early 2023.
Among those involved in the forum are former FERC Chair Pat Wood and Department of Energy veterans Susan Tierney and Robert Gee, who, like Wood, also chaired the Texas utility commission.
MOPC Chair Buffington ‘Honored’
AEP’s Ross, who hands out to staff and stakeholders eponymous “Gold Star” awards, complete with certificates of authenticity, unveiled a new “Richard Ross Boot Award” during the meeting.
Ross, jokingly saying he was “booted off” a recent stakeholder conversation, promised to send the first Boot Award to Evergy’s Denise Buffington, who is cycling off the committee as its chair, for her leadership the past two years.
Buffington warned members her term does not expire until Dec. 31. ITC Holdings’ Alan Myers, MOPC’s vice chair, will succeed Buffington next year.
Gold Star awards are also due for SPP’s Bailey, Drew Gilvray and Nikki Roberts in recognition of their work to improve the congestion-hedging process, Ross said. He will bring the awards and certificates to an upcoming meeting.
12 Revision Requests Pass
MOPC unanimously approved a consent agenda with 12 RRs, although nine members abstained:
RR492: Provides clarity on the risks, timing and treatment of generator-interconnection requests’ financial securities refunds, cost allocation comparisons and withdrawn opportunities. It also adds a definition to distinguish “equally-queued” versus “lower-queued” priority of GI requests.
RR497: Adds further definition to the Project Cost Working Group’s oversight for applicable projects that are funded through direct assignment of cost.
RR498: Allows the ESWG to determine whether SPP’s additional incremental generation capacity recommendations should be included in the ITP’s economic model.
RR499: Adds new language to the planning criteria concerning terminology and their definitions, new capability and new operational testing requirements, out-of-season capability testing, capability and operational testing for new or upgraded units, and accreditation for thermal and hydro units.
RR500: Clarifies and documents a more efficient and detailed process for submitting late data submittals in the ITP, including a new submittal form to help staff assess impacts.
RR503: Modifies language in the market mitigation sections of the protocols and tariff by removing references to dispatch and “settlement purposes” and replacing them with clarifying language to specify the solution will be used for determining locational margin prices and marginal clearing prices (MCPs).
RR504: Addresses potential inefficiencies in the regulation mileage compensation design by revising the mileage factor calculation and setting the mileage MCP to the resource projected to provide the last mile based on the mileage factor.
RR507: Updates the list of transmission services grandfathered agreements.
RR510: Revises SPP’s competitive transmission process with changes to the request for proposal’s scoring methodology and deposits and cost calculations sections and adds an additional table to the confidential information treatment section.
RR511: Changes the tariff by updating the IEP public report deadline from 14 to 21 calendar days.
RR514: Updates the operating constraint and spin violation relaxation limits by increasing the values of all operating reserve constraints not subject to market-to-market coordination to be $1,500.
RR518: Corrects a calculation error in the protocols related to when regulation is not cleared in the real-time balancing market.
WASHINGTON — The Energy Bar Association last week held its annual Mid-Year Energy Forum over two days at the Renaissance Downtown Hotel to discuss the latest developments in energy law, including West Virginia v. EPA, the Inflation Reduction Act, supply chain issues and hydrogen regulation, among many other topics.
Panelists expressed enthusiasm about the Inflation Reduction Act, even as they acknowledged its limitations and the significant amount of work it will take to implement it.
The law provides for about $370 billion in funding for clean energy technologies, including electric vehicles and energy storage, making it the most significant piece of legislation passed by the U.S. to address global climate change. But the bill, originally called the Build Back Better Act, was considerably pared down from trillions in incentives and passed via congressional budget reconciliation to avoid a filibuster by Senate Republicans.
Because of the way it was passed, the IRA “deals only with the opportunity to provide — and very substantial, but still — loans, grants and tax incentives,” Jim Wrathall, general counsel for New Energy Equity, said during the forum’s opening general session on Wednesday. It is “using policy solutions that are not market-based; they’re not comprehensive; and they’re not aimed at targets. They’re money upward. We have to build using these tools and make sure they’re successful.”
“It’s really going to be a renaissance in our domestic manufacturing,” said Edward Hild, principal of government relations for Buchanan Ingersoll & Rooney. “I think that’s where this ultimately leads: to manufacturing [on a scale] we have not done here before. … There’s really a desire not to be dependent on China and other countries, and to do things here.”
“We in this room and in this industry have a challenge here,” Wrathall said. “We’re in the first inning with the tools that are being made available. … We have a job to do to make sure we don’t have missteps.” He reminded the audience of Solyndra, the solar panel manufacturer that went bankrupt after receiving loans from the Obama administration and became a talking point for Republicans against renewable energy.
That’s creating a lot of pressure on not just the industry and its lawyers, but also on the Treasury Department, which needs to issue the regulations and guidance for how the law will be administered. Though $28 billion in investments have already been committed as a result of the law, according to Wrathall, speakers during a different panel the next day noted that it left many aspects, such as definitions, for Treasury to decide.
“I cannot overstate how significant an undertaking this is going to be for the Treasury Department,” said William Davis, a partner with Capitol Tax Partners. “A lot of it are issues of first impression for the Treasury Department; the tax writers in that building and in the IRS. …
“I looked at the Tax Cuts and Jobs Act of 2017; it took three to four years to get all the guidance out on that bill, and [for some aspects], the guidance is still coming out. … So it’s going to be a long process.”
Forced Labor
Also on the panel with Davis was Stacy Ettinger, a partner with K&L Gates, who spoke about the numerous actions taken by the U.S. government by both the Trump and Biden administrations against foreign manufacturers, mainly in the form of tariffs on products shipped from adversaries.
They include the Commerce Department’s investigation into alleged dumping of solar components by China to avoid U.S. tariffs, launched in March. (See Solar Sector Braces for Tariff Probe Impact.)
Also impacting trade with China is the Uyghur Forced Labor Prevention Act, signed by President Biden late last year. The law assumes that certain goods manufactured in China’s Xinjiang province were done so using forced labor, unless U.S. Customs and Border Protection can certify that they were not. The Chinese government is widely suspected of holding Uyghurs, an ethnic minority in the country, in internment camps and using them as slaves.
The law also requires firms outside of Xinjiang to disclose any ties with companies within the province. However, Ettinger said, China has laws that penalize its own companies for complying with what it perceives as the imposition of foreign policy.
“So Chinese suppliers are in a rough spot,” she said. “They cannot agree to language [in a contract] that talks about certification against the use of forced labor because China’s position is, there is no forced labor in China.” Many Chinese suppliers are now refusing to sign contracts for trade with the U.S. “and would rather deal with Europe.”
Ettinger said lawyers should advise their clients to “fix the language [in the contracts.] Don’t talk about forced labor … because the suppliers won’t be able to do it. If they do take that step, the Chinese companies are at risk of action against them. … They’d rather deal with somebody else who doesn’t worry about these issues.”
Michael Skelly, founder and CEO of Grid United, marveled at the attentiveness of the audience at his panel discussion Oct. 11.
“It may be that this is because transmission is one of the most legally intense aspects of the energy transition. Or as we say — ruefully — in our company, ‘No lawyer left behind,’” he said. “Or maybe we’re just having a moment with transmission. … Transmission was in Esquire magazine. Come on.” Esquire’s article was titled, “The Sexiest Part of the Clean Energy Transition Is Big-Ass Power Lines.”
75 Texts an Hour
Former ERCOT CEO Bill Magness, now senior principal consultant for DNV, recounted that at the peak of February 2021’s — “the largest controlled outage ever seen” — he was receiving about 75 texts an hour. “And most of them were just, ‘You suck!’” he joked.
NERC General Counsel Sônia C. Mendonça said the organization is seeking to broaden whom it talks to.
“One of the things that we continuously ask ourselves at NERC is, ‘Are we doing the right outreach? Are we doing enough outreach?’ The risks in the bulk power system are more and more coming from outside of the bulk power system. So if we continue to talk to ourselves, that’s not going to be a very successful conversation, in terms of mitigating that risk. So we need to expand … constantly to states, other critical infrastructures. And we are always asking ourselves, ‘Who is not at the table?’”
Angela Kolar, chief risk officer of Colonial Pipeline, said her company moved several years ago to use its incident command structure for any kind of emergency. But company officials couldn’t have anticipated the ransomware attack that led it to shut down its gasoline pipeline system in May 2021.
“When you go to your crisis management team, and you have a scenario that [includes] a nationwide pandemic and nobody is working from the office and you have a cyberattack at the same time, people want to ask you when the aliens are invading too,” she said. “It just doesn’t seem practical, until it actually happens to you.”
Kolar said her company attempted to be as transparent as it could following the attack but had to make decisions without knowing how severe the attack was. “We didn’t know if they had gotten into our IT side and our OT side. We shut down the pipeline out of an abundance of caution, until we knew what was going on.”
Craig Glazer, vice president of federal government policy for PJM, said the RTO is “disappointed” with FERC’s “piecemeal” approach to planning, with NERC assigned to write reliability standards addressing hot and cold temperatures and extreme weather conditions listed as a factor to be considered by planners in the commission’s Notice of Proposed Rulemaking on transmission planning (RM21-17). Meanwhile, critical facilities planning, including gas-electric coordination, storm hardening and interregional transfer capability goals were not addressed, Glazer said.
“We started this as a way to reform planning, yet this aspect of planning is really piecemeal [and] chopped up. And I think we’re going to look back and say we didn’t address it comprehensively when we had the opportunity to do so. …
“Is there a role for NERC? Yes. Should we proceed to standard setting at this point? No, we don’t think that’s the right thing to do,” Glazer said. “We think we’ve got to take a holistic look at all these issues, and then develop standards rather than piecemealing standards. … We’re really asking the staff and the commissioners to step back, look at the totality of what’s going on and what you’re trying to get done.”
Glazer said PJM has three “asks” of FERC, starting with a “clear policy statement” on the importance of enhanced reliability planning to counter critics alleging RTOs are “gold plating” the system.
“Absent some direction from the federal regulator that all the planning authorities need to focus on this, I think we’re going to be in this finger-pointing exercise … forever,” Glazer said.
Second, PJM is asking FERC to give RTOs a “homework assignment” to identify the enhanced reliability needs in each region and how they plan to address them. “We don’t have that record really anywhere at this point,” he said.
Third, PJM would like FERC to work with NERC and the national labs to identify metrics for determining the minimal interregional transfer capacity.
“It’s not a number. It’s a way to analyze what’s the right level of interregional transfer capability,” he said. “I’ve had commissioners say to me, ‘Just go negotiate with your neighbor on interregional coordination.’ It doesn’t work. One system ends up leaning on another system.”
Glazer also questioned FERC’s call for long-term planning looking 20 years into the future. “Twenty years ago, the commission held a technical conference in Charleston, W.Va., to direct us to build more transmission to move coal-fired generation into Maryland and Baltimore and Washington, D.C.,” he said. “And we actually did come up with a plan to do that, which we had to withdraw. But imagine if we had built that transmission.”
The West Coast’s first offshore wind auction will take place Dec. 6 for five leases off the Northern and Central California coasts that together could generate 4.5 GW of electricity, the U.S. Bureau of Ocean Energy Management said Tuesday.
The 373,268 acres, or 583 square miles, of deep-sea lease areas will also be the first to require floating wind turbines in U.S. coastal waters.
The sale is crucial to achieving the Biden administration’s recently stated goal of deploying 15 GW of floating offshore wind by 2035, the Interior Department said.
Five areas off the coast of Northern and Central California will be leased. | BOEM
“Today, we are taking another step toward unlocking the immense offshore wind energy potential off our nation’s West Coast to help combat the effects of climate change while lowering costs for American families and creating good-paying union jobs,” Interior Secretary Deb Haaland said in the release.
The final sale notice followed BOEM’s issuance of a proposed sale notice in May for two leases in the Humboldt Wind Energy Area off the coast of Northern California and three leases in the Morro Bay Wind Energy Area off Central California.
The areas hold 5 to 7 GW of total capacity, the National Renewable Energy Laboratory said in June, amid discussions of increasing the state’s offshore wind goals.
The California Energy Commission in August boosted the state’s long-term OSW goal to 25 GW by 2045, potentially doubling anticipated long-term capacity, in response to urging by stakeholders and Gov. Gavin Newsom.
The governor praised BOEM’s action Tuesday, calling it “a historic step today toward achieving [California’s] goal of 90% clean energy by 2035 and moving the state away from fossil fuels.” The state has a 100% clean-energy mandate by 2045; the 2035 goal is an interim target.
“California could not have better partners in our march toward a clean energy future than the Biden-Harris administration,” Newsom said in a statement. “Together, we’re fighting for energy independence and a future free of fossil fuels and full of clean energy sources like offshore wind.”
The bureau’s decision to set a date “sends a powerful signal that the federal agency is moving forward with speed and scale to support California in reaching its ambitious planning goals to deploy up to 5 GW of floating offshore wind power by 2030 and a nation-leading 25 GW by 2045,” Adam Stern, executive director of trade group Offshore Wind California, said in a statement.
BOEM Director Amanda Lefton first announced the news of the decision to issue a final sale notice (FSN) on Tuesday morning during her keynote remarks to the Offshore WINDPOWER conference in Providence, R.I., hosted by the American Clean Power Association.
The FSN was also published Tuesday on BOEM’s California website. In it, the bureau identified 43 eligible bidders it deemed “legally, technically and financially qualified to hold a commercial wind lease offshore California.” They include companies such as Avangrid Renewables, BP US Offshore Wind Energy, Equinor Wind US, Orsted North America and Shell New Energies. To participate, bidders must deposit $5,000,000 by Nov. 12.
The FSN lays out the details of the upcoming auction, lease areas and lease provisions and conditions. One new provision is that “BOEM will offer bidding credits for bidders who enter into community benefit agreements or invest in workforce training or supply chain development; require winning bidders to make efforts to enter into project labor agreements; and require engagement with tribes, underserved communities, ocean users and agencies.”
The auction will be one of many developments needed to get OSW up and running in California in coming years.
Port infrastructure, for instance, remains a major obstacle. The Port of Humboldt Bay is slated to serve the 1.6-GW Humboldt WEA but requires wholesale redevelopment. The CEC gave the historic timber port’s operator $10.5 million in March to begin upgrading its facilities.
The Morro Bay WEA could be served by several ports, including Long Beach near Los Angeles or Hueneme in Ventura County.
The wind ports must be capable of handling the massive platforms expected off California, potentially larger than any yet afloat at 900 feet tall and capable of generating 15 GW each.
Transmission is another issue. The Morro Bay WEA could tap into existing onshore infrastructure that serves the nearby Diablo Canyon nuclear power plant. Humboldt will require transmission to be built over mountainous terrain to reach the Pacific AC Intertie running down the center of the state or an undersea cable traveling more than 200 miles to the San Francisco Bay Area, developers have said.
“The West Coast market will singularly rival those on the global stage and could draw billions in U.S. supply chain investments,” Liz Burdock, CEO of the Business Network for Offshore Wind, said in a statement Tuesday. “However, the U.S. must move with urgency to capture this rare economic opportunity by freeing up critical support for port and transmission investments, and do the hard work to identify and build an American supply chain that will anchor the U.S. as a global industry leader.”
BOEM has plans to open two areas for OSW development totaling almost 1.2 million acres off of Oregon. The Coos Bay Call Area and the Brookings Call Area are 12 nautical miles from shore at their closest points. (See BOEM Moves on OSW Plans for Oregon, Central Atlantic.)
North Carolina is using $30.1 million from its share of the Volkswagen settlement to replace “some of the dirtiest diesel buses in the state,” but only 43 of the 161 replacements will be electric.
However, those buses will account for more than half of the VW funds — $16.5 million — according to a Monday press release from Gov. Roy Cooper’s (D) office. A list of the awards showed that cost could be a key consideration for the smaller number of electric buses.
While the new diesel buses will average out between $105,000 and $125,000, the cost range on the electric buses will be $370,000 to $410,000. Shawn Taylor, public information officer for the Air Quality Division at the Department of Environmental Quality, said that the department had received applications for a range of technologies, electric, diesel and propane, and in some cases, a school district requested both electric and diesel.
He cited cost, infrastructure — specifically, issues with installing chargers — and other local factors as key considerations for individual school districts. New diesel buses must also comply with tighter emission standards than 20- to 30-year-old buses, Taylor said.
They also run on low-sulfur fuel that produces fewer nitrogen oxides and other emissions, according to the Diesel Technology Forum, an industry association.
Cooper said the new buses would be good “for the health and pocketbooks of North Carolinians as we continue on our path to clean transportation. Transitioning to cleaner school buses reduces greenhouse gas emissions, lowers costs to our schools, creates great manufacturing jobs and reduces pollution in our poorer communities.”
Some of the buses being replaced are more than 30 years old and “emit more than 20 times the [NOx] and particulate matter of today’s clean buses,” the press release said. The new buses will cut 126 tons of NOx emissions over their lifetime, the release said.
The new buses will also be going to mostly rural counties, including 80 vehicles heading to “schools in the 37 historically under-resourced counties that DEQ targeted for additional outreach and support during the application process.”
Taylor said the clean bus program has attracted a lot of attention across the state. “Folks are excited to see these buses on the street,” he said.
Oversubscribed
Reflecting national trends in school bus replacement programs, the North Carolina program was oversubscribed, with DEQ receiving 42 applications seeking more than $58 million for 330 clean school buses, according to the release.
EPA was similarly overwhelmed with 2,000 applications when it announced the first round of funding for zero-emission school buses from the Infrastructure Investment and Jobs Act. In that case, the agency decided to almost double the available funding, from $500 million to $965 million. The IIJA provides $5 billion in funding over five years for the program. (See EPA Doubles IIJA Funding for Electric School Buses.)
The Volkswagen settlement funds come from agreements between the German carmaker and the U.S. Justice Department, the Federal Trade Commission and California after it was found that the company had used “defeat devices” in its cars to cheat on emissions tests. North Carolina received $92 million, based on the number of cars with the defeat devices in the state.
Another $1 million from the settlement has been awarded to state agencies to install Level 2 electric vehicle chargers in public locations, such as state parks, museums, aquariums and state government office buildings, according to the Monday press release. More than 100 chargers will be installed at 25 locations, with 22 located in historically under-resourced communities and 13 being used to charge state government electric vehicles.
In a 2018 executive order, Cooper set a target of having 80,000 EVs registered in the state by 2025 and ordered state agencies to prioritize zero-emission vehicles when purchasing or leasing new cars.
The U.S. will need up to 58,000 full-time workers to meet the Biden administration’s goal of building 30 GW of offshore wind by 2030, according to a new study by the Department of Energy’s National Renewable Energy Laboratory (NREL).
Released Tuesday, the study estimates that reaching the 30-GW goal will require creation of between 15,000 and 58,000 full-time equivalent positions between 2024 and 2030, based on assumptions of 25% and 100% U.S.-made content in the offshore installations, respectively. The industry currently employs fewer than 1,000 workers, DOE estimates.
“The offshore wind energy industry could provide tens of thousands of good-quality clean energy jobs for Americans over the next decade,” Alejandro Moreno, DOE’s acting assistant secretary for energy efficiency and renewable energy, said in a statement accompanying the report. “With this study’s comprehensive findings, we can capitalize on this opportunity and grow a strong domestic workforce for the burgeoning offshore wind energy industry.”
NREL said its estimates include only “the direct and indirect offshore wind jobs associated with development, manufacturing, installation and operation of offshore wind energy plants,” and not additional jobs that could be created in communities supported by offshore development.
The study’s authors said they modeled their scenarios by “assuming a deployment pipeline of awarded, soon-to-be-awarded and anticipated lease areas for fixed-bottom and floating offshore wind projects sufficient to reach 30 GW by 2030,” which were detailed in another NREL report released earlier this year. Fixed-bottom capacity was assumed to be installed on the East Coast, and floating capacity was assumed for the deep waters along the West Coast.
NREL expects the industry to rely on a relatively small domestic workforce for offshore wind farms installed between 2022 and 2025 but foresees U.S.-based jobs expanding after that along with the growth in OSW manufacturing and supply chains and the vessels needed to support installation activities.
The study breaks employment into five industry segments, including:
Development, which could see average annual employment of 800 to 3,200 from 2024 to 2030 based on the 25%/100% domestic content scenarios. Job growth in this segment is expected to grow in parallel to increased use of domestic content. “The workforce need is likely closer to the upper limit because the United States has professionals and training programs to support a domestic workforce. Project development is underway, and many development jobs for initial offshore wind projects have been hired,” NREL said.
Manufacturing and supply chain, which could support between 12,300 and 49,000 jobs, with the largest contribution coming from factory-level positions related to producing subcomponents, parts and materials for OSW installations. “The extent to which domestic jobs are realized depends on the building of U.S. manufacturing facilities and those facilities leveraging a U.S. supply chain to source subassemblies, parts and materials,” the report said.
Ports and staging, which could account for 400 to 1,600 jobs a year, with the largest subset being terminal crews involved in stage components and load installation vessels. “Ports supporting offshore wind energy activities will support economic development in industrial waterfront communities by creating jobs,” NREL said.
Maritime construction, with average annual employment levels estimated at between 500 and 2,100, although NREL notes that development of this domestic workforce is “highly uncertain” given the potential for different installation strategies and vessel availability. “Maritime construction workforce needs are estimated to develop slowly between 2022 and 2026, as we expect the initial offshore wind projects may use installation strategies
with foreign-flagged installation vessels with a larger international workforce. However, if Jones Act-compliant vessels are built to meet future development demand, we expect an increase in the domestic workforce need.”
Operations and maintenance, which could grow from 100 to 500 jobs in 2024 to 600 to 2,300 jobs in 2030. “O&M jobs will begin ramping up to support offshore wind energy plants in 2023-2024. O&M roles are needed throughout the wind plant’s life; therefore, workforce needs are cumulative, increasing based on the number, size and commissioning year of projects,” NREL said.
Good Timing
The NREL report also identifies the strategies needed to fill OSW-related jobs, including attracting and training skilled tradespeople; improving awareness of the roles required by the sector; clarifying and standardizing the credentials needed for those roles; helping workers from similar fields, such as offshore oil and gas, transfer into OSW jobs; focusing on developing a local workforce in communities affected by OSW development and prioritizing members of underserved populations; and increasing coordination across states and regions to develop workforce training and education programs.
The report also points to a need for coordination of installation activities across OSW projects to account for the variability in demand for certain types of workers along the timeline of an individual project’s development.
“The types, numbers and geographic locations of jobs vary during an offshore wind power plant’s life and, when considered across the pipeline of projects across the United States, can lead to large variability in workforce demand,” the study said. “Therefore, workers should be trained and hired strategically to alleviate potential peaks and troughs of workforce demand. For example, jobs related to installation activities are temporary, but a large deployment pipeline allows workers to move to other projects if those projects are properly timed.”
CCS plants worldwide now number 30, with 164 projects at various stages in the development pipeline. | GCCSI
