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October 9, 2024

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BOEM Sets California Offshore Wind Auction Date

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.

PAC Californa Lease Areas (BOEM) Content.jpgFive 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.)

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NC Replaces ‘Dirtiest Diesel Buses’ with Electric and More Diesel

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.

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NREL: Sharp Job Growth Needed to Hit US’ 30-GW OSW Goal

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.”

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Sunrun’s Virtual Plant Sees Success in ISO-NE Capacity Market

Sunrun (NASDAQ:RUN) is calling its first year in the ISO-NE capacity market a success.

From June to August, the company’s virtual power plant (VPP), made up of thousands of home solar systems across New England, sent more than 1.8 GWh of energy back to the grid, the company said in a recent press release.

The capacity agreement made with ISO-NE back in 2019 was the first of its kind, according to Sunrun.

Chris Rauscher, the company’s senior director of market development and policy, said the VPP was successful at sending power back to the grid on the hottest days, replacing output from fossil fuel peaker plants.

“To operate [a virtual power plant] is to really find that balance, the sweet spot, providing value to the electricity grid and all customers on the grid, and retaining the fundamental customer value … for families who have solar in their homes,” he said.

It’s part of a vision for demand response that has ISO-NE leading in some ways: The grid operator’s passive on-peak DR pathway was what let Sunrun achieve its first-in-the-nation entrance into a capacity market.

“We were the tip of the spear,” said Rauscher. “In the ensuing years, there’s been way more interest from [distributed energy resources], and batteries in particular, in entering the market. We helped prove it was possible.”

2222 Filings Closing the Door?

There’s fly in the ointment for the grand plans of Sunrun and other companies trying to replicate its approach: Order 2222 compliance filings from grid operators that they say aren’t living up to the promise of a “new day” for DERs.

“At this point, we’re feeling disappointed in 2222,” Rauscher said.

For example, NYISO has proposed a 10-kW minimum system limit on DER participation in the markets, which Rauscher says would “obviously completely prevent any residential resource from participating in aggregation.” (See NYISO 10-kW Min for DER Aggregation Participation Riles Stakeholders.)

Sunrun isn’t waiting for FERC to finish ruling on the regional compliance filings though: It’s making plans to increase its work directly with utilities, in so-called “bring-your-own-device” programs.

Unlike working in a capacity market on the supply side, BYOD programs involve working with states and utilities on the demand side.

An entity like Green Mountain Power, a Vermont utility that Sunrun has been working with, will coordinate with Sunrun to dispatch its batteries in the service area when peak demand comes, reducing the amount that its customers owe.

“That’s a really good model, and we really like doing that. But it is different because those savings are constrained to a single load-serving entity as opposed to spread across the market,” Rauscher said.

And there’s another issue: As more states and utilities start utilizing that type of demand program, the ones that don’t have them will be left “increasingly holding the bag,” Rauscher said.

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FERC Report Finds CIP Issues Declining

FERC outlined several recommendations for registered entities to improve their compliance with NERC’s Critical Infrastructure Protection (CIP) standards in a report released last week.

The commission based the recommendations in the Lessons Learned from Commission-Led CIP Reliability Audits report on findings from the latest round of audits performed by commission staff during fiscal year 2022, which ended Sept. 30. NERC and the regional entities also took part, as they have since FERC began conducting CIP audits in 2016.

As with previous years, details about the audits — such as how many audits were performed and which utilities were visited — were not disclosed. According to the report, the fieldwork “primarily consisted of data requests and reviews, webinars and teleconferences, and virtual on-site visits.” During the virtual visits, commission staff interviewed the utilities’ subject matter experts and the utilities demonstrated operating practices, processes and procedures. FERC also interviewed employees and managers who performed tasks within the audit scope and examined entities’ compliance documentation.

This year’s audits produced just five recommendations, the fewest since FERC began issuing the reports and a drop of nearly two thirds from the 14 produced last year. Report authors did not acknowledge the decline in lessons learned or suggest any reason for it, stating only that “most of the cyber security protection processes and procedures adopted by the registered entities met the mandatory requirements of the CIP standards, [although] potential noncompliance and security risks remained.”

FERC’s suggestions encompassed three standards. For CIP-003-8 (Cyber security, security management controls) the commission recommended that utilities re-evaluate their policies, procedures and controls for low-impact cyber systems and related assets.

The report’s authors noted that “certain entities” had misinterpreted the standard’s requirement that utilities test their cybersecurity incident response plan at least once every 36 calendar months. Some utilities had concluded that they did not have to test their plans until 36 months after registration. FERC asserted that this is incorrect: Plans must be tested before registration and at least once every 36 months thereafter.

CIP-003-8 also requires that entities identify all transient cyber assets (TCA) — removable media — that they manage, as well as those managed by third parties, to mitigate the risk of infiltration through inadvertent code transfers from unauthorized sources. This “may not be fully understood,” FERC staff said. The report warned utilities that failure to address these assets poses a “serious risk” of compromise to the bulk electric system.

Detailing the issues with CIP-007-6 (Cyber security, systems security management), FERC staff “noted multiple instances where the treatment of end-of-life or end-of-service … BES cyber assets created potential security and compliance risks.” Some entities were found not to have a patch management process or mitigation plans for these assets or were unaware of the extent of assets on their system that were vulnerable in this way. The authors also discovered that not all entities correctly followed the standard’s requirement that they implement a malicious code prevention program on their cyber systems.

For CIP-010-4 (Cyber security, configuration change management and vulnerability assessments), the report found deficiencies in entities’ adherence to the requirement that they have a vulnerability assessment program. Although utilities “generally included multiple vulnerability assessment elements,” at times they neglected “key elements” in the process, potentially leaving them unaware of dangerous vulnerabilities, FERC said.

Finally, staff reiterated the standard’s recommendation that entities “review and validate controls used to mitigate software vulnerabilities and malicious code on TCAs managed by a third party,” noting that “some entities accepted attestations from third parties without performing due diligence” to validate the TCAs’ risk level.

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Ohio Alliance to Support Appalachian Hydrogen Hub

Leaders of the Ohio Clean Hydrogen Hub Alliance (OH2Hub) say they will support a West Virginia-led initiative to create a regional hydrogen hub funded by matching grants from the U.S. Department of Energy.

Battelle, an independent research institute headquartered in Ohio, which had initially advised OH2Hub, is expected to file the initial application for the West Virginia-centered Appalachian Regional Clean Hydrogen Hub (ARCH2) by the DOE’s Nov. 7 deadline.

DOE has $9.5 billion to help local industries and governments create as many as 10 regional hubs in which hydrogen would be produced close to where it would be used, largely by industry or in gas-fired power plants. The agency is expected to offer up to $2 billion in matching grants for each hydrogen hub.  

Sen. Shelley Moore Capito (R-W.Va.) and Battelle simultaneously announced the creation of ARCH2 on Sept. 29. Pittsburgh-based EQT, the nation’s largest producer of shale gas, is one of the principal backers of the effort.  

EQT CEO Toby Rice has campaigned for the creation of a hub focused on making hydrogen from natural gas, capturing the resulting carbon dioxide for injection into deep wells. The Infrastructure Investment and Jobs Act, which appropriated the funds for the creation of hydrogen hubs, calls for blue hydrogen production where natural gas is plentiful.   

Backers of the OH2Hub had proposed a blue hydrogen hub for Ohio because shale gas has been plentiful in the state and the state’s industries already produce 161,000 metric tons of hydrogen annually for immediate use, according to a study prepared by the Midwest Hydrogen Center of Excellence (MHCE).

MHCE, the Stark Area Regional Transit Authority (SARTA), Dominion Energy and Cleveland State University organized the OH2Hub effort.  

“We formed the Alliance to ensure that Ohio and Ohioans would have the opportunity to reap the economic and environmental benefits that will flow from the federal government’s commitment to and massive investment in the development of clean hydrogen technology,” SARTA CEO Kirt Conrad said in a statement. “We firmly believe ARCH2 will enable us to achieve that objective. …

“We will continue to serve as a point of contact and source of information about the Hub, recruit end users, work with Battelle on drafting the formal proposal that will be submitted to the DOE, encourage the state of Ohio to formally participate in ARCH2, urge the General Assembly to pass any legislation that may be needed to facilitate the development of the hub, and encourage the business community, labor organizations, local elected officials and the public to support the ARCH2 campaign,” Conrad said.

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RTOs, Utilities Push Back on Interconnection Deadlines, Penalties

RTOs, utilities and others told FERC Friday it should drop its proposal to penalize transmission providers for failing to meet interconnection study deadlines, while generation developers balked at the commission’s proposed “commercial readiness” provisions.

More than 130 companies, agencies and organizations filed comments in response to FERC’s June 16 Notice of Proposed Rulemaking (NOPR) to clear clogged interconnection queues and give generators more certainty on upgrade costs (RM22-14). (See FERC Proposes Interconnection Process Overhaul.)

Commenters generally supported the NOPR’s proposal to replace the serial “first-come, first-served” study procedure with “first-ready, first-served” cluster studies.

The American Clean Power Association said the NOPR “contains many potentially valuable improvements to current interconnection policies,” calling for new rules to “provide predictability on the timetable for interconnection studies, as well as certainty on the upgrade costs that are identified through these studies.”

The Environmental Defense Fund said the changes were needed to address the “inequitable distribution of costs among interconnection customers based on the first-come, first served study process [and] delays created by the proposal and withdrawal of speculative projects [and] the lack of binding deadlines for transmission providers [and] the general failure of transmission providers to evaluate use of alternative transmission technologies.”

Calls for More Outreach

But there were disagreements on many of the details, and several commenters called for additional outreach before issuance of a final rule.

The Electric Power Supply Association said FERC may need to collect additional comment or convene a technical conference to work out the details. “Competitive generators strongly support a timely final rule from the commission to address long-plagued interconnection queues, but getting that rule as clear as possible saves time in the end for all stakeholders, including customers.”

CAISO said that “although many of the individual proposals in the NOPR are ripe for implementation, the sum of the NOPR would not achieve the commission’s goals and would instead slow study processes and increase backlogs.

“The CAISO strongly urges the commission to iterate with stakeholders further before issuing a final rule. At the very least the commission should issue a revised NOPR based on comments and should consider technical conferences on ISO/RTO-specific reforms, commercial readiness criteria and realistic study timelines.”

Regional Flexibility

The many state agencies that issued comments on the NOPR were broadly supportive of the changes to interconnection rules, which they said could help alleviate backlogs that are hurting their states. But they urged FERC not to interfere with existing regional efforts to make their processes more efficient.

“The imposition of overly prescriptive compliance obligations may disrupt and potentially dismantle many of the successful processes and practices already underway in the MISO region,” the Organization of MISO States wrote. “As such, we recommend that the commission permit transmission providers that are initiating their own stakeholder-supported interconnection reforms … to continue developing regionally appropriate solutions.”

“The commission should be sensitive and avoid creating additional burdens to those regions that have already adopted best practices,” MISO said. “Any proposed reform should be careful not to burden transmission providers by imposing non-essential or regionally inappropriate requirements to already-strained interconnection queue study processes and inadvertently increase the duration of the interconnection queue or risk of delays.”

“In discussing the need for queue reforms, the NOPR does not appear to recognize the different approach that New England has taken to interconnection-related network upgrade costs,” the New England States Committee on Electricity wrote. ISO-NE also asked the commission to avoid a “prescriptive” final rule.

The Edison Electric Institute also called for flexibility. “For example, FERC should allow transmission providers to develop the technical details for cluster studies, including how clusters may be split into subgroups of interconnection customers based on areas of geographic and electrical relevance,” EEI said.

“To the extent these ongoing efforts appear likely to accomplish the Commission’s goals of expediting the interconnection process, WIRES believes the commission should accommodate these efforts rather than slow down or preempt these initiatives by enforcing standardization with the proposed pro forma” interconnection agreements, the trade group WIRES said.

“Several of the NOPR’s proposals could harm existing interconnection processes and could specifically harm the NYISO processes that are working well to integrate the significant amounts of new clean energy resources required to attain the requirements of New York’s ambitious climate change legislation,” said the New York Transmission Owners, a comment that was echoed by NYISO.

PJM, which filed its own interconnection overhaul days before the NOPR, said the commission should allow it to complete its transition period before being required to comply with a final rule. (See PJM Files Interconnection Proposal with FERC.)

The PJM Transmission Owners opposed the commission’s proposal to allocate network upgrade costs among interconnection customers in a cluster based on the degree to which each generating facility contributes to the need for the upgrade. “The NOPR proposal for allocation of network upgrade costs should not be mandatory and regions should have the flexibility to determine just and reasonable approaches for cost allocation,” they said.

Proving Commercial Readiness

There was wide support for measures to discourage speculative projects from entering interconnection queues, with EEI saying, “The reforms that the commission has proposed involving study deposit frameworks, site control requirements and commercial readiness demonstrations are important tools to help cut down on speculative projects, increase certainty and reduce queue backlog.”

But numerous parties challenged FERC’s proposal to use finalized purchase power agreements as evidence of commercial readiness.

“Independent power producers would be challenged to enter into binding contractual sale obligations without having any reasonable certainty into their final interconnection costs,” the Solar Energy Industries Association said. “SEIA believes the final rule should allow developers to demonstrate commercial readiness through means other than firm contractual sale contracts or financial deposits. Commercial readiness should be evaluated based on the totality of circumstances, and should be required later in the process, so to avoid injecting uncertainty into the interconnection process.”

Vistra said requiring a demonstration of commercial readiness to proceed in the interconnection process “ignores the reality of competitive solicitations and unduly discriminates in favor of self-build options.”

Invenergy also opposed the commercial readiness requirements. “Interconnection customers will already be subject to other requirements that are far more indicative of ‘readiness,’ such as the increased site control requirement to enter the queue and withdrawal penalties under the new rules,” it said. “This additional ‘readiness’ proposal is unnecessary. Moreover, the focus on having a power purchase agreement (PPA) term sheet or contract to simply enter the queue ignores the commercial reality that independent developers do not typically have an off-taker so early in the process.”

EDF Renewables said FERC should increase study deposits and other capital requirements to discourage “overly speculative high-risk projects and project spamming” rather than relying on PPAs.

EEI said that allowing interconnection customers to provide financial security in lieu of meeting milestones or readiness requirements “can be used as a loophole for speculative projects to proceed well into the interconnection process,” potentially leading to restudies and delays.

Penalties, Deadlines

FERC also received strong opposition to its proposal to replace the current “reasonable efforts” standard for transmission providers and impose penalties for failing to meet study deadlines.

The ISO/RTO Council said although it understood the commission’s intent, “the proposal overlooks the reality that the RTOs/ISOs and their transmission owners have no control over the size of their respective interconnection queues and limited control over the quality of the submittals.”

It said the proposal would deprive transmission providers of their due process rights and introduce “a more litigious relationship among the parties.”

“Study deadlines must consider the scope, complexity and uniqueness of each such interconnection,” the New York TOs said. “Rather than allowing sufficient time to develop optimized interconnection studies, TSPs and TOs will be incentivized to rush or abbreviate the needed study effort to avoid running afoul of such deadlines and penalties, potentially leading to less optimal studies.”

The TOs said interconnection delays are often caused by interconnection customers. “Moreover, such IC-driven delays are often intended to allow them to improve their projects, and removing that flexibility would harm ICs and the overall effectiveness of their respective projects,” they said.

“Proposals such as automatic penalties for study delays and blanket elimination of the reasonable efforts standard will not help transmission providers manage the present overwhelming queue volume because they do not get to the root of the delays,” PJM said. “The commission’s proposed penalties may compromise reliability by forcing transmission providers to prioritize speed over accuracy.”

As an alternative, PJM proposed setting “tolerance bands for delays” and focusing on process improvement reporting to the commission, “with penalties potentially established after due process, based on misfeasance or malfeasance by the transmission provider in carrying out the specific process improvements.”

CAISO also opposed the proposed deadlines, saying “many of the NOPR’s proposed reforms are based solely on the tariffs of single utilities operating in a single state. Such utilities enjoy unique advantages because they can be both the generation off-taker and the transmission provider conducting the interconnection studies, and they have a single local regulatory authority over procurement. … The vast majority of commission jurisdictional interconnections occur in ISOs/RTOs where the off-taker and transmission provider are not only different, but may not even be in the same state. Many of the commission’s proposed reforms fail to recognize that the ISO/RTO may be the ‘transmission provider,’ but it depends on the actual transmission owners to perform study work.”

State officials expressed concerns that the penalties could ultimately be passed on to ratepayers.

“The record does not appear to support the position that fines will materially aid in reducing the interconnection backlog,” wrote a coalition of 13 East Coast state agencies, made up largely of attorneys general and state consumer advocates.

The Transmission Access Policy Study Group (TAPS), an association of transmission-dependent utilities in 35 states, expressed the same concern.

While TAPS recognized that FERC allows penalties imposed by NERC or regional entities for violation of reliability standards to be passed through in this manner, the organization argued that this situation is fundamentally different.

“The money collected from RTO ratepayers is used to offset the costs of operation of NERC or the relevant [RE]. … In contrast, the NOPR’s proposed study delay penalties will be remitted to specific interconnection customers, which may have no commitment to use these payments to offset costs to any consumers, much less ratepayers bearing those costs,” TAPS said.

A group of environmental organizations dubbed the Public Interest Organizations cited data from the Lawrence Berkely National Laboratory that they said showed that queue withdrawal rates have been consistent over the last 10 years, suggesting that the fear of speculative projects is misplaced. As a result, the commenters said that FERC’s contemplated queue withdrawal penalties are probably unwarranted. They suggested that the commission instead “emphasize the information sharing and process improvement aspects of the reforms over the aspects that introduce barriers to applications.”

Google expressed fear that the commission’s proposals “risk providing an advantage to utility development over independent power producer (IPP) development.” Google urged FERC to adopt a “holistic approach” that balances the readiness requirements, study deposits and withdrawal penalties in order to avoid “undermining the vibrant IPP sector.”

Acciona Energy, Copenhagen Infrastructure, Hecate Energy, Leeward Renewable Energy Development, and Tri Global Energy — filing jointly as the Affected Interconnection Customers — called for expanding the list of indicators of commercial readiness and granting interconnection customers “the unilateral right to retain preapproved outside consultants … if the transmission provider or transmission owner is unable to complete the necessary interconnection studies on time.”

Informational Studies, GETs

PJM and its TOs joined SPP and SEIA in opposition to proposed “informational” interconnection studies, saying it would provide information of limited value while taxing limited RTO resources.

SPP opposed the proposal “due to its past experiences in offering such a study and based on feedback received from its interconnection customers,” saying its feasibility and preliminary impact studies “did not provide results that could be relied on in making business decisions.”

Some, including the MISO TOs, also opposed a provision that would require transmission providers to consider “alternative transmission solutions” if requested by an interconnection customer.

The WATT Coalition, a trade association that promotes deployment of grid-enhancing technologies (GETs), supported the requirement but said it should be an “opt-out” rather than an “opt-in” rule, saying “advanced transmission technologies should be considered as a routine matter in interconnection processes in all regions.”

The Clean Energy Buyers Association warned that FERC’s suggestion of allowing interconnection customers to submit up to five informational study requests at a time could bog down “already over-burdened transmission provider resources and interconnection queues.” The group said that transmission providers should be allowed to establish windows of time each year to submit such requests.

More Please

A few commenters asked the commission to go beyond the proposals in the NOPR.

“Reforms to participant funding rules are also critical to any meaningful interconnection reforms,” Invenergy said. “Similarly, the commission needs to address the current inconsistency between generator interconnection and transmission planning studies, and develop pro forma procedures for HVDC transmission interconnection so development can move forward.”

Anbaric Development Partners asked the commission to draft a rule ordering ISOs and RTOs “to remove tariff barriers to the development of planned transmission or transmission-first projects,” saying the commission “already has before it a more than adequate record on which to justify this relief.”

The Electricity Consumers Resource Council, which represents large industrial consumers, asked FERC to add an independent transmission monitor to the NOPR “to ensure that there is coordination among the interconnection process and the transmission planning process.”

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NJ BPU Approves Waivers for 26 Residential Solar Projects

The New Jersey Board of Public Utilities (BPU) on Wednesday granted waivers of rules governing its new solar incentive program to 26 residential projects in a sign of the agency’s strategy as the state struggles to reach its ambitious goals.

The board granted waivers to seven projects on which developers had begun construction — and to seven that had begun operating — before the program opened. It gave waivers to another 12 projects with more capacity than is allowed under the program.

The move comes as the program under which the incentives were awarded, known as the Successor Solar Incentive Program (SuSi), which the BPU created in July 2021, has faced criticism. The incentives are about half the size of those in the previous program, which critics have said are too small and insufficient to stimulate the amount of new solar needed in the state. (See NJ Sees Solar Growth in Reduced Incentives.)

BPU staff told commissioners that the rules preventing the program from awarding incentives to projects that are already under construction or operating were designed to ensure that incentives go only to proposed projects that need subsidies to be brought to fruition, Scott Hunter, the BPU’s manager of the Office of Clean Energy, said in outlining staff’s recommendations. The limit on project overcapacity aims to create clearly defined eligibility standards and ensure that the “limited block” of power capacity set aside for the program is not oversubscribed, he said.

In granting the waivers, the BPU said many of the projects would not be successful without incentives.

Speaking before the 5-0 vote to approve the waivers, BPU President Joseph Fiordaliso said they don’t create a precedent for the future.

“We can never tie the board in a position that it has no alternative,” he said. “Because every case is unique in its own way. And we have to have that flexibility in order to look at each case individually, to determine what’s in the best interest of the citizens of the state of New Jersey.”

Future Implications

The board said in its order that the waivers were warranted in part to overcome the turbulence surrounding the state’s incentive programs, which have changed twice in the last three years, creating the “consequent potential for confusion among solar market participants.”

It also said the extra capacity from the 12 projects, totaling about 30 kW, will not “place the residential market segment megawatt allocation in jeopardy.” That’s because only about half of the 150 MW set aside for the segment has been allocated, according to the board, which predicted that the capacity would be fully subscribed by January.

“The ADI [Administratively Determined Incentives] program is still relatively new, and the megawatt caps included in this program did not previously exist,” the board explained. “While prior programs required registrants to notify staff if installed capacity exceeded what had been approved, incentives have not to date been denied for the excess capacity.”

But the order added that BPU has already put on hold another 14 projects that would create larger capacity than is allowed under the program rules. Those rules state that a project can be no more than 10% or 25 kW (whichever is smaller) greater than the approved size. “Staff is concerned about the implications” of granting waivers and the possibility that it will encourage project developers to develop larger-than-approved projects in the future, the order said.

Commissioner Dianne Solomon said that it “is important that we are not tying ourselves into a blanket waiver under any conditions.”

“There is an acknowledgement that these are new rules; it takes a while for everybody to get on board and understand their requirements,” she said. “We accept that. But I think it is important that we make it clear what our intentions are: that the rules be followed.”

Power Surge

New Jersey had 4.14 GW installed solar capacity as of the end of August, according to the latest figures available, and the state is seeking to reach 17.2 GW by 2035 as part of Gov. Phil Murphy’s goal of 100% clean energy by 2050. Murphy wants the solar sector to generate 32 GW by 2050. Murphy in 2021 signed the Solar Act of 2021, which called on the state to add 3,750 MW of new solar by 2026.

BPU data on solar installations suggest that the state may reach its goal of 5.2 GW by 2025 but may find it difficult to reach the 2030 goal of 12.2 GW.

Since the start of the year, the state has added about 345 MW. If it continues at that rate, it would add nearly 520 MW this, surpassing the previous record of about 449.8 MW in 2019.

Not all of that surge is from a strengthening solar sector; part stems from the reshaping of the state’s solar incentive programs. For more than a decade, the state offered relatively generous incentives under the Solar Renewable Energy Certificate program that paid about $250/MWh. The program was cut in 2020, in part because of concerns that it was too generous, and replaced with the temporary, lower incentives of the Transition Incentive (TI) Program, which ranged from about $90 to $150/MWh.

The BPU replaced that program, which was created as a short-term stop gap, with SuSi, which provided a two-pronged approach. One half, the ADI program, offered even lower incentives, from $70 to $100 depending on the project. The second prong, the Competitive Solar Incentive (CSI) program, will set the incentives of solar projects larger than 5 MW through a competitive solicitation. The final rules are expected to be released later this year.

One impact of the shifting incentive terrain is that solar developers, seeing that the BPU expected to reduce incentives, scrambled to submit projects in the TI Program before it ended. That created a surge of projects, with 1.6 GW in the pipeline at the start of the year, three times as much as a year earlier. (See NJ Solar Pipeline Surges While Installations Drop.)

That pipeline capacity has since dropped to 1.05 GW as of August, as some of it has begun operating, and it is unclear how long the high level of monthly installations will continue.

Critics of the new incentive program, among them the International Brotherhood of Electrical Workers Local 102 and the New Jersey Utility Scale Solar Association, argue that the incentives are too low and, as a result, applications to the BPU for new solar projects have fallen. Both want the legislature to enact a pending bill, S2732, that would extend the deadlines by which projects must be finished in the TI Program, allowing those that are delayed to be completed with the higher incentive.

The BPU, however, denied some TI extension requests in August, saying they have to balance the demands of solar developers with the need to protect ratepayers from rising incentive costs. (See NJ BPU Denies Deadline Extensions for Solar Project Incentives.)

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Non-standard Loads Becoming an Issue in SPP

An ad hoc group in SPP’s Strategic Planning Committee, tasked with advising the committee on “non-standard loads,” said last week that the RTO’s tariff is based on a wholesale/retail regulatory regime and, therefore, can handle the potentially interruptible load interested in interconnection.

Staff said SPP has received 56 requests for delivery point changes totaling 7.1 GW of capacity since June 2021, primarily for data centers and cryptocurrency miners. While they are the most familiar non-standard loads, others include server farms, biofuel manufacturers and hydrogen electrolyzers.

Richard Dillon (SPP) Content.jpgRichard Dillon, SPP | SPP

“And our favorite, the cannabis growhouses, especially in Oklahoma, where it’s very legal to do that for recreational purposes,” SPP’s director of market policy, Richard Dillon, said during the SPC’s virtual meeting Wednesday.

These loads represent significant potential firm or non-firm additions. Staff determined that stranded transmission costs, resource adequacy and whether the loads would be considered interruptible or demand response were all significant issues.

“There was a lot of concern about what happens if these loads come on and then disappear,” Dillon said. “These are major concerns for load-serving entities because ultimately, they will be comparing costs with those decisions.”

He said many of the loads interesting in the SPP market are trying to sidestep being considered retail load in a footprint that is devoid of retail competition. Some of the inquiries are trying to co-locate with renewable generation and net out the load with generation where both the load and the generation is behind the meter.

“The discussion with those entities has been, ‘OK, so you’re going to put in controls that automatically cut power off in microseconds, the moment that the renewable generation drops,’” Dillon said. “Thus far, no one has taken us up on that scenario, because crypto miners make money by burning electricity. If they’re down, they’re not making money.”

This has raised members concerns about resource adequacy and stranded costs because of the loads’ uncertainty. Southwestern Public Service’s Jarred Cooley said his company has been fielding several calls a week from loads, some as large as 1,400 MW, interested in connecting to its system.

“One of the key issues here is the transient nature of the loads and the likely need for significant transmission investment,” he said. “We’ve talked at the point of interconnection that’s between us and our load and us and our customers and figuring out how to properly protect them or how we charge those based on our state jurisdictions.

“These loads, we don’t expect them to be transmission investments that are going to be paid for,” Cooley said.

Dillon was unable to offer solutions but suggested members take advantage of this week’s Market Working Group meeting for an in-person discussion of the issue. He said the MWG will revisit a draft revision request (RR521) that clarifies the tariff’s DR and net metering provisions.

SPP Staffing up in West

Bruce Rew, SPP’s senior vice president of operations, told the SPC that the grid operator’s efforts in the Western Interconnection remain on track.

Seven Western entities are continuing to evaluate membership in SPP’s RTO West, he said. They face a commitment target date of March 1, 2023.

“Once that begins, they will move forward with the RTO transition and everything associated with that,” Rew said.

Markets+, an RTO “light” service offering, is also on schedule to receive commitments from interested parties next year. A final development session is being held in Westminster, Colo., in November.

The development of RTO West and Markets+ will be funded by the participants, but Rew said SPP has still hired more than 40 staffers to support those and other efforts.

“We would hire additional staff based on the implementation effort and long term effort for supporting the RTO expansion,” Rew said. “We will ultimately go to receive approval of the budget once we have a final commitment from those parties and know exactly what size and scope that we’re dealing with. We will add additional staff should we receive a long term commitment to RTO West or Markets+.”

Cupparo Joins Committee

SPC Chair Mark Crisson welcomed Director John Cupparo onto the committee as a replacement for Director Susan Certoma, who will chair the Board of Directors next year.

Cupparo will replace Crisson, who is cycling off the board next year, as the committee’s chair.

“A lot of important things come through here. I look forward to working with everyone,” Cupparo said.

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ACORE Panel: IRA Will Accelerate Storage Deployment, but Markets not Ready

WASHINGTON — Energy storage, along with other distributed energy resources, are changing the way electricity markets and the grid are planned, structured and operated, and the new tax incentives for standalone storage in the Inflation Reduction Act will accelerate the pace and urgency of the transformation ahead.

The impact of the law and the growing presence of storage as a core technology for grid reliability and decarbonization were the focus of a panel at the American Council for Renewable Energy’s Grid Forum on Thursday. In his opening remarks, Carl Fleming, a partner at McDermott Will & Emery, reported that the IRA is driving deals at his law firm, even before the Internal Revenue Service issues guidance on the new law’s tax credits.

“We’ve seen a number of deals — the first two tax equity … deals, the first two energy community deals and the first two transferability deals,” Fleming said, referring to specific provisions in the law that provide bonus credits and expand the entities that can receive credits.

New figures from BloombergNEF are predicting global storage capacity of 411 GW by 2030, a 15-fold increase from the 27 GW online at the end of 2021, he said — a forecast driven in part by the IRA.

Ann Coultas 2022-10-13 (RTO Insider LLC) Content.jpgAnn Coultas, Enel North America | © RTO Insider LLC

Ann Coultas, regulatory affairs director at Enel North America, said her renewable energy development company, like many others, is still “digesting everything in the legislation and figuring everything out. I would say we are very familiar with working across a variety of platforms, whether it’s wholesale energy markets, whether it’s microgrids; and one of the exciting things about this legislation is that it has incentives for all types of applications.”

Similarly, for Gabe Murtaugh, storage sector manager at CAISO, the law provides more options for leveraging the 5,000 MW of storage that will be coming onto the California grid in the next two years, doubling the close to 5,000 MW now online.

Existing tax credits for storage are narrowly drawn, Murtaugh said. To qualify, a project had to be co-located with and only charge from solar or another renewable energy source.

“If you as a grid operator need those resources to charge during the middle of the night, when there is no solar [or when] there’s no wind, you can’t do that under the current rules,” he said. “The new rules are going to allow a lot more flexibility for these resources to participate maximally in the market.

“Those are the kinds of rules and the kinds of incentives we need in place … to build the new renewable resources and the resources that are going to make a sustainable resource portfolio mix possible, but don’t necessarily restrict how those resources are going to work in the market,” Murtaugh said.

Nidhi Thakar 2022-10-13 (RTO Insider LLC) Content.jpgNidhi Thakar, Form Energy | © RTO Insider LLC

The IRA will also help startup Form Energy bring its multiday, iron, air and water-based long-duration storage technology to market faster, said Nidhi Thakar, vice president of policy and regulatory. “It helps companies like us who are preproduction and prerevenue to commercialize faster, to put steel in the ground faster and to start producing our batteries.”

Form is in the process of selecting a site, east of the Mississippi River, for its first factory, which will be able to produce 500 MW of its 100-hour batteries, Thakar said. However, while lauding the “unprecedented” clean energy investments in the IRA and Infrastructure Investment and Jobs Act, Thakar also pointed to the gaps in the laws, including the need for permitting reform and tax incentives to support new transmission.

“We can’t take full benefit of what’s in the IRA for clean technologies” without addressing these issues, she said.

‘Shallow’ Markets and Marginal Pricing

The panel also tackled the uneven pace of storage integration on transmission and distribution systems and its deployment as a grid asset, as some utilities, regulators and grid operators continue to argue that the technology is not sufficiently mature or cost competitive.

In California, the leading storage market, four-hour duration lithium-ion battery storage is now the standard, Murtaugh said. But longer-duration technology will be needed for the days or weeks when renewables aren’t available, because of the increasing frequency and severity of extreme weather events driven by climate change.

A core challenge in California and other markets is the need to develop market structures that incentivize the deployment of storage and appropriately compensate the specific attributes of the technology. Traditional marginal pricing, effective for fossil fuel generation, doesn’t mean much for storage developers, Murtaugh said. “They don’t care so much about instantaneous prices; what they care about is the price that they can buy energy at and the price they can sell energy at,” he said.

Markets based on thermal generation and spinning and non-spinning reserves are not designed for battery growth, Coultas agreed. They don’t offer “the right products to attract a battery,” she said.

Enel has had a lot of success with batteries in Texas, where ERCOT has “defined products in ways that suit batteries really well. So, there are products where you must respond within 20 cycles; you must respond within a matter of seconds or milliseconds. Products like that in a market [are] going to attract batteries.”

ERCOT’s battery-friendly products, however, are offset by the grid operator’s “shallow” markets, Coultas said, meaning that the energy needed is relatively small. “To attract more batteries, markets need to be really thinking about creating the right level of ancillary services,” she said.

Further, no one has completely cracked the pricing issue yet, Coultas said, though she pointed to ERCOT and CAISO as models of progress.

Murtaugh said one possible solution is to replace LMP with “something where we pay a fixed amount to a storage resource when we’re charging that storage up, and the ISO has sort of a call option to be able to discharge that resource any time we want to.”

Coultas offered yet another possibility — technology-neutral dispatchable energy credits, similar to renewable energy credits, for resources “that have attributes guaranteeing dispatch,” she said. At the same time, she cautioned, “There are values [of storage] that will just never be compensated in a multistate ISO because they don’t have the power to do that; for example, clean peak. I don’t think in a multistate ISO we’re ever going to a see a product that pays batteries for clean peak.”

In CAISO, Murtaugh and others are working on changing California’s resource adequacy programs, now based on peak demand, “to a new paradigm where we’re going to be looking at making sure we have enough energy overall 24 hours a day, as well as actual generation during each hour of the day and for charging resources earlier in the day,” he said.

New Tools 

Thakar believes that long-duration technologies, like Form’s, could provide targeted, “microfitted” solutions for a range of grid challenges, “whether it’s for use on a consistent basis or as support to central service providers or other critical communities that are stuck in some of these difficult load pockets and experience a lot of grid instability,” she said.

But, she said, no markets, not even California’s, have created market valuation or compensation structures for the “innovative resources that are going to be coming online in the next couple of years.”

Part of the problem, Thakar said, is that the focus on federal implementation of the IRA has left a blind spot around implementation of the law by state utility commissions.

State-level integrated resource plans have relatively short time frames — two or three years — for procuring clean energy resources, she said. “How does that hamstring the general ability to take advantage of the 10-year window we have for benefits from the IRA now? … We need to be thinking about what kind of tools can help state regulators really fully capture the overall benefits of IRA for customers.”

Form has built its own modeling tool that “focuses on a 365-day evaluation, using a model that looks at that entire yearlong snapshot. It also looks at multiple weather years,” she said.

Murtaugh said he and CAISO’s operations team have also spent the last few years “building a whole suite of tools that we never even contemplated having before because we were never worried about storage state of charge and thinking about energy we could potentially dispatch later.”

“We’re enhancing all of our markets and the modeling we do for storage resources to accommodate resources that can charge and discharge, resources that have a minimum and maximum state of charge, so that our market can optimize those resources alongside all the other resources. There are a lot of unique operating characteristics for storage resources,” he said.

“In the next five to 10 years, I think a lot of ISOs are going to be seriously thinking about their market constructs,” Murtaugh said. “I think we’re going to see some pretty radical changes come after that.”