The U.S. Department of Agriculture on Sept. 5 announced more than $7.3 billion in financing for 16 cooperatives as part of its largest investment in rural electrification since 1936.
The department released the grants under its Empowering Rural America (New ERA) program. The $9.7 billion program is part of the Inflation Reduction Act and designed for cooperatives interested in buying or building new energy systems.
National Rural Electric Cooperative Association CEO Jim Matheson welcomed the news, calling it a “transformative opportunity” for cooperatives.
“The New ERA program showcases what is possible when the government prioritizes voluntary, flexible decision-making and allows electric co-ops to take a tailored approach to respond to local needs,” he said in a statement.
All but one of the 16 cooperatives have completed the New ERA’s competitive stage and are in the underwriting process to receive an award. They include three co-ops from Colorado: Tri-State Generation and Transmission Association ($679 million), United Power ($261 million) and CORE Electric Cooperative ($225 million).
Tri-State, which provides wholesale power to its 41 members, plans to use the funds to build or buy 1,480 MW of solar, wind and battery storage and to support the retirement of 1,100 MW of coal-fired generation. It said that will eliminate nearly 5.8 million tons of greenhouse gas emissions annually.
Texas’ San Miguel Electric Cooperative said that if it is awarded New ERA funds, they will be used to convert the co-op’s lignite operations to 400 MW of solar generation and build a 200-MW battery storage facility. It also could use the funding to refinance debt from its stranded lignite infrastructure, a significant obstacle for the transition to solar generation, it said. San Miguel’s 410-MW coal plant is among the top 30 facilities in emitting mercury.
USDA received more than 160 requests for more than $44 billion in funding. Its first New ERA award ($573 million) went to Wisconsin’s Dairyland Power Cooperative, which plans to procure 1,080 MW of renewable energy through four solar installations and four wind farms across Wisconsin, Iowa, Minnesota and Illinois.
The NEPOOL Participants Committee voted Sept. 5 to update the Generation Information System (GIS) to enable the transfer of hourly certificates, opening the door for the sale of hourly renewable energy credits.
Constellation Energy, which developed the proposal, had argued that hourly tracking is the logical next step in the evolution of RECs and would help incentivize carbon-free resources.
“Customers are looking beyond annual procurement of clean energy and unbundled clean energy attributes [toward] supply options that match generation with hourly consumption,” Constellation’s Gretchen Fuhr told the Markets Committee this year. “ISO-NE is already a leader in tracking all generation sources. Tracking hourly attributes is the next step.”
The GIS system is administered by APX, which will develop the changes needed through 2025. The update is expected to cost an additional $75,000.
Financial Assurance Policy Changes
The PC did not reach a consensus to support proposed changes to the Pay-for-Performance (PFP) financial assurance policy, which ISO-NE has said are important to reduce the risks of generators defaulting on their payments.
In a memo prior to the meeting, ISO-NE wrote that it “has identified a fundamental gap in its credit risk management approach regarding the mitigation of PFP penalty payment defaults. The ISO’s proposal to assess capacity sellers’ liquidity and require more collateral from higher-risk entities on an ongoing basis addresses this risk.”
The PFP rate is set to increase from $5,455/kWh in the current capacity commitment period to $9,377/kWh in 2025/2026.
The RTO has proposed to introduce “a corporate liquidity assessment to evaluate PFP penalty default risk that could result in additional financial assurance requirements for higher-risk market participants.”
Following the liquidity assessment, ISO-NE would assign market participants a risk category, which would determine its financial assurance requirement. Some generators have expressed concerns about added costs associated with the additional financial assurance requirements.
ISO-NE’s proposal failed to pass the two-thirds approval threshold with 62.5% in favor, while NEPGA’s revisions also failed with 47% and 53% in favor, respectively.
Despite that, a spokesperson for ISO-NE said the RTO plans to file its proposed changes with FERC.
COO Report and Aug. 1 Scarcity Event
About 1,150 MW of generator outages and reductions, higher-than-expected temperatures, a pair of constrained interfaces and about 350 MW of out-of-service fast-start resources combined to cause ISO-NE’s capacity scarcity condition on Aug. 1, COO Vamsi Chadalavada told the committee.
Chadalavada noted that the RTO entered the day with a limited capacity surplus and experienced about 750 MW in outages prior to the scarcity event. An additional 400 MW in outages occurred as the grid approached peak load, he added.
The Aug. 1 peak load was the highest of the month, at 23,758 MW. Oil generation on the system increased drastically for the peak, while hydro resources also ramped up significantly.
PFP charges for underperforming resources totaled about $50 million during the event. The average systemwide LMP reached $2,113/MWh during the peak hour.
For the month, the real-time hub LMP averaged about $39/MWh, Chadalavada said. The overall monthly energy market value was $403 million through Aug. 27, compared to $674 million in July and $310 million in August 2023. The Forward Capacity Market value was $120 million.
Chadalavada’s monthly report indicated the New England grid’s carbon emissions for the year continue to outpace those of 2023, largely because of increased natural gas emissions.
Order 2222
Also on Sept. 5, FERC accepted by delegated order a compliance filing by ISO-NE for Order 2222 that specifies the deadline for meter data submission (ER22-983-008). The proposal was not protested by any parties.
Massachusetts and Rhode Island have selected 2,878 MW of offshore wind project bids from the states’ coordinated solicitation, which would make it the region’s largest offshore wind procurement.
The multistate solicitation, which included Connecticut, initially sought up to 6,000 MW in bids and ultimately received 5,454 MW. (See New England States’ OSW Procurement Receives 5,454 MW in Bids.) On Sept. 6, Massachusetts announced its selection of 2,678 MW from three project bids, while Rhode Island selected 200 MW. Connecticut did not announce any project selections, writing in a statement that “the evaluation of project bids remains underway.”
Massachusetts and Rhode Island selected the SouthCoast Wind project, with Massachusetts planning to buy 1,087 MW and Rhode Island planning to buy the project’s remaining 200 MW. Massachusetts also selected 791 MW from Avangrid’s New England Wind 1 project and “up to 800 MW” from Vineyard Offshore’s Vineyard Wind 2 project.
Vineyard Wind 2, which originally was proposed as a 1,200-MW project, could reach power purchasing agreements with other states or private entities, according to Massachusetts officials.
The project selection falls short of the authorized procurements for both Massachusetts and Rhode Island; Massachusetts’ request for proposals (RFP) authorized the selection of up to 3,600 MW, while Rhode Island sought up to 1,200 MW. The Massachusetts legislature has set an offshore wind procurement target of 5,600 MW by 2027. Representatives of both states say they plan a subsequent solicitation in 2025.
“Together with Massachusetts, we are setting a precedent for regional collaboration in clean energy and advancing a sustainable, resilient future,” said Rhode Island Gov. Dan McKee (D) in a statement.
Massachusetts Gov. Maura Healey (D) said at a press conference the selection marks “a historic step forward toward energy independence, cleaner air and transformation of our economy.”
Healey told reporters the projects ultimately will result in “lower electricity costs for our residents and our businesses.” She said state and independent evaluators determined that “this is a cost-effective way, one of the most affordable ways, for us to bring that power online in Massachusetts.”
State officials did not disclose project costs, saying details will remain under wraps until contracts are submitted to state utility regulators. Cost has been a key concern for policymakers and stakeholders throughout the solicitation process. The Massachusetts Attorney General’s Office recommended in 2023 a smaller-than-authorized procurement to limit costs to ratepayers. (See Mass., RI, Conn. Sign Coordination Agreement for OSW Procurement.)
In 2023, SouthCoast backed out of its power purchase agreements with Massachusetts utilities, citing inflation, interest rates and supply chain constraints. (See Developer Seeks to Terminate SouthCoast Wind PPAs.)
To help mitigate future cancellation risks, each of the three state’s RFPs included the option for developers to submit inflation adjustment mechanisms for their projects. Massachusetts officials said none of selected projects include adjustment mechanisms.
Massachusetts’ Executive Office of Energy and Environmental Affairs Secretary Rebecca Tepper emphasized the projects would help reduce dependence on natural gas, resulting in lower emissions and less price volatility.
Tepper said the selection will help the state “lead the nation in the global race for developers, vessels, materials and expertise. We’re going to lock in jobs and technical expertise, and we’re going to invest in our ports.”
Massachusetts officials indicated the bulk of the work is set to be based out of New Bedford and Salem, with work also occurring in the ports of New London and Providence. All three projects selected include project labor agreements, and they are projected to create thousands of jobs across the region. New England Wind 1’s expected in-service date is 2029, while SouthCoast expects to power up by 2030.
A range of clean energy organizations praised the announcement, emphasizing the importance of continuing to invest in the development of the region’s offshore wind industry.
Kelt Wilska of the Environmental League of Massachusetts called the project selection “a big win for Massachusetts and Rhode Island.” Wilska also praised the collaborative solicitation process.
Amanda Barker of Green Energy Consumers Alliance called on the states to continue to invest in offshore wind and “to issue additional solicitations to ensure we meet our climate targets and access the wide-ranging benefits of offshore wind.”
The developers of the SouthCoast and Vineyard Wind 2 projects both applauded the project selection announcement. Vineyard Offshore did not release a statement, and NetZero Insider was unable to reach the company for comment in time for publication.
Project developers now will negotiate contracts with the electric distribution companies in Massachusetts and Rhode Island. The finalized contracts then will be filed with state utility regulators.
On the transmission side, Massachusetts’ press release noted the New England states are positioned to “request that ISO New England issue a competitive solicitation for proposals to address longer-term transmission needs, such as transmission to interconnect offshore wind or other clean energy resources, in late 2024 or early 2025.” (See FERC Approves New Pathway for New England Transmission Projects.)
MISO’s 2024 transmission planning cycle is shaping up to include 459 new projects totaling $6.7 billion. The RTO shared the plan with stakeholders in a series of subregional planning meetings.
The 2024 Transmission Expansion Plan (MTEP 24) investment contains a little more than $1 billion in baseline reliability projects and $763 million in transmission projects needed for generator interconnection. In keeping with previous MTEP packages, the “other” category takes the largest share of investment, this time at more than $4 billion. “Other” projects include those needed for load growth, transmission owners’ local reliability criteria, and to address the age and poor condition of facilities.
Projects driven by load growth and replacement of subpar facilities will take the largest share of investment this year, at about $1.5 billion apiece.
Senior Expansion Planning Engineer Amanda Schiro said this year, six of the top 10 most expensive projects are in MISO South, with all but one driven by the region’s load growth. This year’s most expensive baseline reliability projects also are in MISO South and involve rebuilding lines and substations, Schiro said during a Sept. 5 Central Subregional Planning meeting.
In a departure from previous years, the 2024 MTEP includes $858 million under what MISO classifies as “transmission delivery service.” The pair of projects submitted by Minnesota Power — one costing $800 million and the other $58 million — would modernize and upgrade Minnesota Power’s existing HVDC system. The HVDC project is MTEP 24’s priciest submittal.
By planning region, MISO West accounts for almost $2.7 billion, MISO South $1.8 billion, MISO Central $1.4 billion and MISO East $771 million.
In MISO South, a single Entergy Texas reliability project is set to account for 40% of the region’s spending. Entergy Texas’ 500-kV Cypress-to-Legend line is estimated at $406 million. MISO said the reliability project performed better when compared to the 500-kV Hartburg-Sabine Junction project, which MISO canceled in 2022 after a legal battle and the need for the project evaporated.
MISO will use another project alternative over a transmission owner’s original project submission. MISO recommended that Michigan Electric Transmission Co. pursue a $45 million relocation of the 138-kV Iosco-Karn line near Michigan’s thumb area rather than a $74 million rebuild. The alternative project involves stringing lines on existing poles.
Schiro said officially, MTEP 24 will include not only the traditional MTEP spending, but also it and SPP’s $2 billion Joint Targeted Interconnection Queue portfolio and its second, likely $25 billion long-range transmission plan, bringing total 2024 investment to almost $34 billion.
MISO will dedicate a special teleconference of the Planning Advisory Committee Oct. 1 to reviewing the draft MTEP 24 package of projects.
Rush Island SSR to End Oct. 15
MISO announced that its sole system support resource (SSR) agreement will get a final month-and-a-half extension as the Missouri coal plant associated with it is ordered offline by a federal court.
Ameren Missouri’s Rush Island coal plant is supporting the MISO system from Sept. 1-Oct. 15 under a final SSR agreement. After that, Rush Island will go dormant, ordered offline by the U.S. District Court for the Eastern District of Missouri following years of Clean Air Act violations. (See Ameren Files to Recoup Rush Island Closure Costs from Customers.)
“The boilers are shutting down with or without an SSR agreement,” MISO planner Grant Larson told stakeholders.
MISO said it won’t need the SSR once three MVAR static synchronous compensators are installed on the nearby system. Those upgrades aren’t expected until December, resulting in weeks of potentially precarious operations.
“MISO is prepared to address any operational issues that may arise following the retirement of Rush Island,” MISO spokesperson Brandon Morris said of the gap period beginning in mid-October.
Morris emphasized that MISO planning studies show no concerns once transmission upgrades are in place this December.
The plant has been operating for about two years under SSR agreements, which are used to keep generation operating past planned retirement dates for the sake of system reliability.
The Bonneville Power Administration plans to contribute its full share of funding for Phase 2 of SPP’s Markets+, an executive with the federal power agency has said.
“BPA intends to continue its funding of the development of Markets+ as we proceed with our public process,” BPA Vice President of Bulk Marketing Rachel Dibble said in a statement emailed to RTO Insider. “As outlined in our staff recommendation in April, Bonneville sees many benefits for its customers and the Pacific Northwest in SPP’s Western day-ahead electricity market, particularly its independent governance model.”
BPA used similar language when it announced Aug. 26 that it would postpone until next year its decision between Markets+ and CAISO’s Extended Day-Ahead Market (EDAM), but it was unclear at the time whether the agency’s mention of continued support for the SPP day-ahead market included a commitment to funding its share of the estimated $150 million price tag for the Phase 2 implementation stage of the market, which is scheduled to begin in 2025. (See BPA Postpones Day-ahead Market Decision Until 2025.)
“We are currently reviewing and negotiating Phase 2 funding agreements with SPP as are other utilities and participants. Ultimately, ensuring the viability of two day-ahead market options remains a key principle of our evaluation and decision process,” Dibble said.
A Sept. 5 article in the Portland Business Journal article quoted Dibble as saying BPA estimates its Phase 2 costs will come to about $25 million.
According to an SPP document dated July 31, BPA would be responsible for 17.4% of Phase 2 funding, second only to Powerex at 23.2%. Those percentages are likely to increase slightly after two Black Hills Energy utility subsidiaries recently committed to leave SPP’s Western Energy Imbalance Service to join CAISO’s Western Energy Imbalance Market, indicating their likely withdrawal from Markets+ development efforts. (See CAISO’s WEIM Plucks Black Hills Utilities from SPP’s WEIS.)
Controversy Accompanies Funding Decision
BPA’s decision on whether to continue funding Markets+ represents yet another flashpoint in the already politically fraught atmosphere that has materialized around its process for choosing between Markets+ and EDAM.
The controversy has risen into the upper reaches of U.S. politics, with all four Democratic U.S. senators from Oregon and Washington in July sending BPA Administrator John Hairston a letter urging the agency to delay its day-ahead market decision until more developments play out around the two markets. That letter reflected many of the concerns of Northwest supporters of the EDAM, who fear BPA is moving too quickly in the direction of Markets+. (See NW Senators Urge BPA to Delay Day-ahead Market Decision.)
But BPA also faces pressures from below — in the other direction. A large contingent of BPA’s base of “preference” customers — the Northwest publicly owned utilities that rely on the federal Columbia River hydroelectric system for low-cost power — has urged the agency to stay the course and continue funding Markets+ into its implementation phase and ultimately join the market. (See Northwest Public Power Group Endorses Markets+ over EDAM.)
Last month, 47 of those utilities collectively sent their own response to the letter from the Northwestern senators, asking the delegation to consider the impact of BPA’s day-ahead market decision on the region’s consumer- and tribal-owned utilities and cautioning them against applying pressure that could delay BPA’s funding for Phase 2.
In a similar vein, Washington-based investor-owned utility Puget Sound Energy independently sent a letter to Washington Sens. Patty Murray and Maria Cantwell saying competition between the two markets “is proving beneficial for participants” and warning that “delaying market decisions will have the consequence of delaying real economic benefits to customers across the region.”
On the other side of the debate, in conversations with RTO Insider, Northwest-based supporters of the EDAM have questioned the soundness of BPA committing so much funding to Markets+ ahead of other developments. Chief among them is the continued progress of the West-Wide Governance Pathways Initiative in moving CAISO’s markets toward more independent governance — something BPA and other Markets+ supporters view with skepticism. (See related story, ‘Leaning’ Evident in BPA Response to NW Senators.)
One source, who is not authorized to speak on behalf of their organization, also pointed to the fact that, unlike the EDAM tariff, the Markets+ tariff still is in limbo after SPP’s filing received a deficiency notice in July covering 16 items. That source pointed out the notice contained a number of substantive issues for SPP to address, including important details the RTO assumed could go into the market’s business practice manual or protocols, but that FERC might require be included in the tariff itself.
Texas regulators have rejected the second-largest project from its portfolio of potential generation resources that would be built with state funds.
The Public Utility Commission said Sept. 4 that a project put forward by Aegle Power had failed the due diligence portion of the Texas Energy Fund’s loan-application process. The project’s developer had said NextEra Energy was a party to the application, but the Florida company told the PUC that it was not involved.
“Please be advised that NextEra’s name was submitted in the Aegle application without NextEra’s knowledge or consent,” General Counsel Mitchell Ross wrote to the commission in a letter filed Sept. 3. “NextEra is not seeking funding as part of the TEF Program, is not participating in the project for which NextEra was named, and hereby requests that NextEra be immediately removed from PUCT records as a sponsor for the Aegle Power project.”
Doug Lewin, Stoic Energy Consulting’s principal, came across the letter while searching regulatory filings in PUC dockets and raised its profile on social media.
“Not a great start,” he posted on X, formerly known as Twitter.
It gets worse. Lewin discovered that Aegle’s CEO, Kathleen Smith, had pleaded guilty in 2017 for embezzling a “significant” amount of money from a company that was trying to build a power plant in Corpus Christi, Texas.
“It was not like they created some crime in Europe. It was in Texas on a power plant,” Lewin told RTO Insider.
Smith was president of Chase Power Development, which cited low gas prices and difficulty in securing environmental permits when it abandoned the $3 billion Las Brisas Energy Center project in 2013 and said it was going out of business. The plant was to burn petroleum coke from nearby oil refineries.
The Aegle project supposedly would have built a combined cycle facility in the Rio Grande Valley with a nameplate capacity of 1,260 MW. It was among the 17 applications selected for further review as part of a $5 billion loan program intended to add thermal generation to the ERCOT grid. (See PUC Shortlists 17 Projects for Loans from Texas Energy Fund.)
PUC Executive Director Connie Corona said the commission is “still a long way” from selecting the companies that will receive TEF loans.
“Proposed projects that have reached this stage have only met the initial requirements for applications,” she said in a statement. “We have a multistage application and verification process that gets more rigorous at every step to ensure only financially sound applicants with viable projects receive these loans.”
The commission said it will pursue at least a 10% repayment from the TEF contractor, Deloitte. The advisory services firm conducted the first review of applications.
In testimony before the state Senate Finance Committee on Sept. 5, PUC Chair Thomas Gleeson said the commission had learned the previous week that one of the TEF applications was “perhaps submitted with potentially fraudulent information.”
Texas PUC Chair Thomas Gleeson and Executive Director Connie Corona appear before a Texas Senate committee. | Texas Senate
“While I am absolutely certain that this this project never would have gotten funded, and we assumed that some projects would fall out … it is still unacceptable to have moved this forward,” he told the committee. “I think it is clear that our contractor needed to do better in their initial review of this company and that our staff needed to hold our contractor more accountable for that review. … We should have asked a lot more questions about these companies.”
State Sen. Charles Schwertner (R), who authored the bill authorizing the TEF (Senate Bill 2627), called the developments “disappointing” and promised “hard questions” during a Texas Energy Fund Advisory Committee joint oversight hearing with House members Oct. 8.
Schwertner said the request for a contract administrator included “very specific requirements of the … contract administrator regarding fraud prevention.” He also raised issues around NextEra’s involvement in the application, noting that their letter to the PUC “doesn’t say they didn’t have a relationship” with Aegle.
Gleeson told Schwertner that NextEra has a nondisclosure agreement with Aegle. He said that in a call with the company Sept. 4, he asked NextEra to “reconsider their stance” and break the NDA.
“They informed me that they were not changing their stance,” Gleeson said.
“I don’t know what’s going on with NextEra about their relationship here with this applicant, Aegle Power, but I want to know,” Schwertner said. “We’re going to get to the bottom of it, whether it requires subpoenas to [legislative committees], but this is unacceptable that we have large publicly traded companies as well as new entrants with questionable backgrounds.”
“This doesn’t smell right. I’m not believing everything I’m hearing,” said Sen. Joan Huffman (R), the committee’s chair and a member of the TEF Advisory Committee.
The PUC says it expects the due diligence review to take up to eight months. Commission and Deloitte staff will verify each project’s details, including participating companies, financial viability, construction plans, interconnection capabilities, ability to complete the project and ability to pay back the taxpayer-backed loans, the PUC said.
While the lawmakers questioned the initial vetting process, Stoic’s Lewin said his concerns lie with the 10 GW of dispatchable thermal generation that the TEF is designed to construct.
“It looks to me that they were trying to pick a whole lot of different generators. Seventeen different projects, but there are not really 17 difference credible thermal energy generation developers in Texas,” Lewin told RTO Insider. “Somebody really wants [new thermal capacity] to be 10 GW. I want to see the study that says 10 is the number. Where’s the data, where’s the study that says 10 is the magic number?”
Lewin advocates for microgrids and backup power packages that can be used at the local level, such as during the recent Hurricane Beryl, and funding for wires infrastructure and generation facilities in Texas’ non-ERCOT regions. He said the two TEF programs could be at risk should the push for 10 GW of thermal generation encroach upon their funding.
“You have credible power companies out there,” Lewin said. “Let them do their projects and stop fixating on 10 GW.”
The Western Transmission Expansion Coalition’s (WestTEC) steering committee on Sept. 5 unanimously approved the plan that will underpin a Western transmission study designed to stimulate development of interregional projects over the next two decades.
“The study plan approval was the result of many months of collaboration within the WestTEC committees and with community and regional partners,” Sarah Edmonds, CEO of Western Power Pool, which is coordinating WestTEC, said in a press release. “We are grateful to these partners who have helped get us this far and to the Western Electricity Coordinating Council as a major sponsor of our upcoming work.”
WestTEC’s transmission study plan, jointly facilitated by WPP and WECC, is an industry-led effort to address long-term interregional transmission needs as the grid expands and climate change accelerates. Approval of the plan commences the study itself, which will take place over the next two years.
The main objective is to create an “actionable” transmission study by conducting integrated planning analysis across the Western Interconnection that produces 10- and 20-year transmission portfolios. (See Group Looks to Create ‘Actionable’ West-wide Transmission Plan.)
The effort is voluntary, intended to respond to the “widely recognized concern that current transmission planning frameworks in the West do not result in the identification of sufficient transmission solutions to support the needs of the future grid and that interregional transmission planning can be strengthened,” the study plan reads.
The study horizons focus on evaluating transmission requirements in 2035 and 2045, with the goal of prioritizing “flexible and scalable transmission solutions for nearer term needs to help better position the system for efficient long-run expansion.”
Assuming the system will evolve based on current trends, existing policies, generation projections and load forecasts, the study will primarily reference the WECC 2034 anchor dataset, utility integrated resource plans, state agency data and other non-proprietary data sources.
The study isn’t meant to replace existing transmission planning processes or alter FERC Order 1920 — the landmark ruling requiring regions to undergo long-term transmission planning — but to complement them.
Notable features of the transmission study include:
a study footprint spanning the Western Interconnection, as well as interties connecting the Canadian provinces of Alberta and British Columbia.
load-growth forecasts that capture the increasing demand for electricity.
resource forecasts that result in a generation mix that meets state policy requirements, reflects clean energy goals and accounts for voluntary procurement of clean energy.
consideration of multiple planning scenarios to reflect the inherent uncertainties of long-range planning.
an integrated approach to identifying transmission portfolios, with an emphasis on identifying transmission needs not addressed by other planning efforts.
regional partner engagement and governance.
credible and objective study execution through an independent consultant team.
The study’s goals include addressing reliability and commercial and economic efficiency by ensuring the footprint has sufficient transmission capacity to meet future energy needs while reducing congestion, identifying a plan that complies with NERC reliability standards and enabling operational efficiency.
WestTEC also aims to address affordability by unlocking the benefits associated with a coordinated transmission portfolio that can enable greater diversity in supply and demand. Other goals include increasing visibility into the combined capabilities and requirements of the study footprint and addressing cost allocation.
If those goals are met, backers of the plan hope the study will serve as input into local and regional planning processes; initiate bilateral negotiations and development activities; facilitate engagement with local communities, tribal nations and regulators; provide meaningful data; and a serve as a resource to developers, utilities and state regulators.
Study Limits
While WestTEC backers anticipate the effort will “fill many planning gaps currently present in the West,” they also acknowledge its limits.
The study won’t provide a comprehensive list of all needed transmission infrastructure, nor will it capture all the infrastructure needed to maintain economic and reliable operations.
It also won’t focus on identifying infrastructure needed to address pre-existing reliability issues within a single transmission-owner area, or on resolving lower-voltage thermal issues “reasonably expected to be addressed through existing interconnection, local or regional planning processes, even if such issues are present on transmission infrastructure that would otherwise be in the scope of the assessment.”
Additionally, the study offers a “point in time” view of transmission needs, meaning the projects explored by WestTEC will be implemented in response to evolving needs that will be clearer over time.
While WestTEC emphasizes the plan will not be a “singular transmission solution in the West,” participants are confident the study will help ensure reliable and sustainable grid operations in the future.
The 10-year horizon study is already underway and is expected to be complete by September 2025. The 20-year study will begin in spring 2026, with the full report slated for September 2027.
“With this milestone, there’s good momentum right now, and we need to keep our partners engaged and keep it going,” Edmonds said.
This week’s technical conference to address industry objections to NERC’s proposed standard on inverter-based resources, the ERO’s first ever after invoking section 321 of its Rules of Procedure, is likely to be followed by “a lot more” in the near future, NERC staff said.
NERC’s Standards Committee hosted the conference Sept. 4-5 at the Westin Washington, DC Downtown hotel following a directive from the ERO’s Board of Trustees at its meeting last month. (See “Board Invokes Standards Authority to Meet IBR Deadline,” NERC Board of Trustees/MRC Briefs: Aug. 15, 2024.) ERO staff had planned to hold the gathering at NERC’s office in D.C. but moved it to the Westin to accommodate the high level of stakeholder interest.
The board invoked its section 321 authority to order the meeting after PRC-029-1 (Frequency and voltage ride-through requirements for IBRs) failed to receive approval in its most recent formal ballot round. FERC ordered NERC in October 2023 to submit reliability standards addressing several aspects of IBR performance, including ride-through protection, by Nov. 4, 2024, and ERO leadership feared that the normal standards development process might not move quickly enough to meet the commission’s deadline.
During the two-day technical conference, NERC staff presented on the background of the standard, including FERC’s order and the work of the standards development team. Industry stakeholders also took part in panels with NERC staff discussing their issues with the proposed standard and possible ways to address them.
In one panel, representatives from original equipment manufacturers laid out some of the challenges they saw with meeting NERC’s proposed requirements, particularly in existing inverters manufactured before the standard becomes enforceable. Scott Karpiel, principal applications engineer at SMA America, mentioned that while he thought meeting the new requirements should be easy for utilities buying newer inverters, entities using older hardware might have trouble because of the legacy equipment’s firmware limits.
Another panel saw representatives from NERC, utilities and industry groups discuss strategies for implementing the ride-through standard alongside others resulting from FERC’s assignment that have already received industry approval. These include PRC-028-1 (Disturbance monitoring and reporting requirements for inverter-based resources) and PRC-030-1 (Unexpected inverter-based resource event mitigation).
Howard Gugel, NERC’s vice president of regulatory oversight, said entities concerned about implementing the new requirements could consider turning to trade organizations for aid.
“Working by yourself, you might come up with something, but as a community, if you come up with a solution, there’s a power that could occur there,” Gugel said. “I think there’s a wealth of information that can be tapped there as you get involved in those things.”
Soo Jin Kim, NERC’s vice president for engineering and standards, observed that the ERO has “several other projects on the horizon” that are also the subject of FERC directives. She highlighted Project 2023-07 (Transmission system planning performance requirements for extreme weather), which has been working to meet FERC’s directive to submit a standard by December that addresses performance concerns of transmission equipment in cold weather.
The team for Project 2023-07 has produced a new standard, TPL-008-1, which has failed to reach industry approval in two formal ballot rounds. In the most recent round that closed Aug. 22, the standard received a weighted segment approval of just over 18%, well below the two-thirds majority needed to send it to the board for approval. (See Cold Weather Standard Fails Second Ballot.) Kim said this project, and others facing FERC deadlines, may need to follow the path laid out in section 321.
“For some of the major projects that we see on the horizon — high-priority projects, things that require a lot of coordination [and] where there’s major gaps in information that the team just did not have at its fingertips — I do think that these events are [very] fruitful,” Kim said. “The department is [not just] going to … look at this from the standards perspective, but also on the engineering side, we have talked about doing more technical conferences generally, even before we get to some of the standards development steps.”
Collaboration among stakeholders is crucial to maintaining Western grid reliability in the face of increasing demand posed by large loads such as new data centers, speakers said Sept. 4 during a webinar hosted by WECC.
Representatives from Elevate Energy Consulting, the Pacific Northwest Utilities Conference Committee (PNUCC) and the Grant County Public Utility District in Washington participated in the webinar. The panelists discussed the challenges of integrating large loads in the Western Interconnection.
According to PNUCC’s Northwest Regional forecast for 2024, electricity demand is projected to increase from approximately 23,700 average MW in 2024 to about 31,100 aMW in 2033, an increase of over 30% in the next 10 years.
“That is an increase of 7,000 average MW, or enough electricity to power seven cities the size of Seattle,” said Crystal Ball, PNUCC’s executive director. She noted the increase in demand is primarily from three things: data center development, high tech manufacturing growth and electrification.
“But really, we see it coming from these companies developing large data centers in the Pacific Northwest,” Ball added.
Grant County has been dealing with the increase in large loads for some time, according to Shane Lunderville, business development manager for the county’s publicly owned utility.
“We’ve had data centers for the last 10 years and a lot of growth that has not stopped,” Lunderville said. “We have averaged in just industrial growth between 5 to 7% per year of that growth, and we’re not seeing it slow down.”
Ball said the increased demand for electricity is a sign of economic growth opportunities. However, it also poses significant reliability challenges, such as integrating large loads while adhering to efforts to reduce carbon emissions.
“One misstep really could lead to cascading consequences,” according to Ball. “It’s really the reliability of the power system that is at risk during this transition while meeting this increasing demand for electricity.”
She added that stakeholders must work collaboratively and focus on proactive solutions.
Kyle Thomas, vice president of compliance services at Elevate Energy Consulting, agreed, saying that “all parties have to be at the table.”
“Doing one thing on the grid actually involves many different departments … because it’s so interconnected, it’s so involved, and the data centers is no exception,” Thomas said. “So, we need policy, we need regulatory, we need legal, we need the engineers.”
However, according to Thomas, one issue is that data centers often have strict confidentiality rules due to the competitive space between different developers. This makes it difficult to study how to best integrate data centers while ensuring reliability, he said.
“We should still start and try and figure out where our gaps of knowledge are and partner with them to get information, get data, get models, and then learn from these real operations with monitoring data and get that cycle as fast as possible,” Thomas said.
The U.S. also could learn from other countries that have successfully brought on data centers while ensuring the reliability of the grid, according to Thomas.
“You look at Ireland and their adoption of data centers is unbelievable,” he noted. “You look at the [European Union], they have had interconnection requirements in place and policies for large loads since about 2009. We can learn from others in the collective global industry here to learn and accelerate our knowledge where it may be lacking, and we can also help others in that aspect.”
American Clean Power Association on Sept. 5 released its latest Clean Power Quarterly Market Report, in which developers set a record for the second quarter with 11 GW of installations — up 91% from the same period last year.
In all, 137 utility-scale projects went online, and they brought the cumulative nameplate capacity up to 283.6 GW across utility-scale solar, storage and wind — enough to power 70 million homes.
The second quarter brought installations up to 19 GW across the first half of the year. ACP noted the second half usually sees higher installations, so 2024 could set a record for solar, storage and wind installations. The first half of the year beat the previous five-year average by more than 10 GW.
“While all clean energy technologies are expanding their market share, energy storage is scaling at a stunning speed and has surpassed 20 GW of operating capacity,” ACP CEO Jason Grumet said in a statement. “With rapidly growing demand and the need to make significant strides in decarbonizing our economy, the stakes are high. Our recent progress is encouraging, but we are not moving fast enough.”
The quarter saw California lose its crown as leading state for utility-scale solar, as Texas added 1,656 MW — bringing its total installations to a whopping 21,932 MW. Across the country, solar saw 6.7 GW installed, or 61% of overall clean energy installations.
Storage added 2.9 GW around the country in the second quarter, which brings its total installations to 21.6 GW.
Land-based wind saw the smallest installations among the three technologies, with 1,370 MW installed in the second quarter. But that was more than triple the capacity added in the first quarter.
Onshore wind still represents most of the installed capacity for renewables in the country, but solar is closing the gap — at 39% at the end of the second quarter, up from 26% on Jan. 1, 2020.
Some 32 states and the District of Columbia added clean energy capacity in the quarter, with Texas leading the way with 2,596 MW overall. California came in second, adding 1,947 MW. Of that, nearly 70% was storage, a trend that should continue because storage represents 64% of the clean capacity in the Golden State’s development pipeline.
The clean power pipeline of projects under development is at nearly 163 GW, which is up 13% from the middle of 2023 and has been growing at 5% annually. The steady expansion of the pipeline can be attributed to storage and solar, which have grown at average rates of 12% and 3% per quarter since 2022.
The pipeline dipped 1.5% from the first quarter due to projects entering operation and the cancellation of New York’s third offshore wind project. The decline should be short lived, with an additional 8 GW to 12 GW of offshore wind set to be added to the pipeline as states wrap up ongoing procurements.
ACP Welcomes the 10th BOEM Offshore Wind Approval
The report was released a few hours before the Bureau of Ocean Energy Management approved the country’s 10th offshore wind project — the Maryland Offshore Wind Project, which brought total approvals by the agency to 15 GW.
“Today’s approval of our nation’s 10th offshore wind project — a total game change from the zero projects approved before President Biden and Vice President Harris took office — shows the tremendous progress we are making to harness this economic opportunity that [benefits both] American workers and the planet alike,” White House National Climate Advisor Ali Zaidi said in a statement. “From port infrastructure upgrades and new tax credits to speeding responsible and efficient permitting, we are using every tool available to continue turbocharging this industry and delivering a clean energy future for the nation.”
The Maryland project is planned to add 2 GW of offshore wind capacity and would supply power to the Delmarva Peninsula. Its lease area is 8.7 nautical miles offshore Maryland and about 9 nautical miles from Sussex County, Delaware.
“In just four years, the U.S. went from zero permitted offshore wind power projects to 10, representing real progress,” ACP Vice President for Offshore Wind Anne Reynolds said in a statement. “Of these, one project is completed and five are under active construction.”
