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November 19, 2024

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Avangrid to Pay $615K for NERC Violation Penalties

Avangrid has agreed to pay $615,000 to the Northeast Power Coordinating Council for seven separate violations of NERC reliability standards by its utilities in New York and New England, according to a settlement between the regional entity and the company approved by FERC on Friday (NP23-20).

The Avangrid-NPCC settlement was the only notice of penalty filed with the commission by the ERO in September. FERC said in a filing last week that it would not review the agreement, leaving the penalty intact.

NPCC’s allegations involve five of Avangrid’s subsidiaries:

    • New York State Electric and Gas;
    • Rochester Gas and Electric;
    • Central Maine Power;
    • Maine Electric Power (majority owned by CMP); and
    • United Illuminated.

Collectively the companies serve more than 2.2 million electricity customers across New York, Maine and Connecticut. They operate a combined 8,638 miles of transmission lines and 71,000 miles of distribution lines.

The RE accused the utilities of violating several of NERC’s standards, all relating to facility ratings. According to the settlement, the violations began as early as 2007, and in some cases have yet to be resolved. NPCC expects all the remaining issues to be resolved by the end of next year.

Avangrid self-reported all the violations, starting with the initial discovery in February 2020 of an issue on one of NYSEG’s transmission lines between its Hillside and Canton Avenue stations. NYSEG found that the ratings for a 115-kV feeder in its thermal limit database software application differed from those used in its control center and by the application used to perform reliability studies.

Further investigation revealed that although the line had undergone multiple modifications between 2009 and 2019, NYSEG’s rating database had not been updated to reflect their impact on the line’s thermal rating as required by FAC-008-3 (Facility ratings), which was replaced by FAC-008-5 in October 2021. NPCC determined that the noncompliance began in 2012, when NYSEG replaced a breaker at Hillside without updating the rating sheet, and ended in 2019 when the utility correctly updated the sheet.

NYSEG submitted a self-report of another FAC-008-3 violation to NPCC in December of 2020, while fellow Avangrid subsidiary RG&E submitted two self-reports that year concerning infringements of FAC-008-3 and FAC-009-1 (Establish and communicate facility ratings). Following these reports Avangrid conducted an extent of condition review across all its grid transmission assets in New York and Maine.

The review concluded in April 2023, and uncovered errors at 119 of Avangrid’s total facilities. Forty-one affected facilities were owned by NYSEG, 72 by CMP, four by MEPCO and two by RG&E. Sixty of the errors required a reduction in rating.

Avangrid’s review did not reveal ratings errors at any facilities owned by UI, but the utility did report a potential violation of FAC-008-5 to NPCC four days after the review concluded, indicating that it could not locate engineering documentation to support some facility ratings and that there was some confusion about the facility ratings methodology that UI had used. UI’s noncompliance, along with that of CMP and MEPCO, is ongoing and expected to be resolved by next year; the others were reported resolved by 2022.

NPCC determined that the root causes of these violations included ineffective interdepartmental coordination, inadequate internal controls for verifying facility ratings, lack of company-wide rating modification processes and inadequate ratings validation programs.

Avangrid’s mitigation steps include developing a comprehensive transmission facility rating and modeling process, implementing a companywide facility ratings methodology, creating a centralized rating and modeling group and designing a new database to track facility ratings information. The company is also performing an extent-of-condition walkdown, which it expects to finish by the end of 2024 at an estimated cost of $75 million. In addition, it will submit monthly reports through the end of 2024 to disclose any additional facility ratings discrepancies it discovers.

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FERC Approves Extension of Comment Period in PJM CIFP Filings

FERC has approved a nearly one-week extension of the comment period on PJM’s two filings to rework several areas of its capacity market following the conclusion of the Critical Issue Fast Path (CIFP) process in October (ER24-98, ER24-99).

The extension, issued Oct. 27, allows comments to be submitted through the end of Nov. 9, rather than the Nov. 3 deadline PJM sought. PJM Chief Communications Officer Susan Buehler said the extension does not impact the Dec. 12 effective date PJM requested in its filing and therefore would not impact its target to have changes in place for the 2025/26 Base Residual Auction, scheduled to be run in June 2024. (See PJM Files Capacity Market Revamp with FERC.)

The commission did not go as far as the Independent Market Monitor asked when it filed a request for comments to be permitted until Nov. 17, arguing that the intricacy of the filing warrants additional time. The request was supported by American Electric Power, American Municipal Power (AMP), Old Dominion Electric Cooperative, the PJM Industrial Customer Coalition and the Office of the Ohio Consumers’ Counsel.

“The Market Monitor requests an extension of time of 14 days because the filings in these dockets raise important, complex and intricate issues about the design of the PJM capacity markets. More time is required for preparation of an adequate response than the current deadline affords,” the Monitor wrote.

PJM responded that the Monitor and stakeholders should be aware of the changes being proposed in the filing through the months of discussion throughout the CIFP process. Extending the comment period would reduce the amount of time for the commission to evaluate the filing and comments to make a reasoned decision by Dec. 12.

“Specifically, PJM thoroughly discussed the proposed enhancements with all stakeholders, including the Market Monitor, through the Critical Issue Fast Path stakeholder process over a six-month period before the actual filing. Further, the PJM board issued a public letter to all stakeholders detailing the very proposals contained within the underlying dockets nearly one month ago on Sept. 27, 2023,” PJM wrote.

In its comments supporting the Monitor’s request, AMP wrote that the changes being considered could have substantial impacts on the capacity market that should be fully thought out. If full consideration of the proposals leads to the commission not issuing an order prior to the commencement of pre-auction activities, AMP recommended that the commission delay the auction schedule or order it to be run it under the status quo rules.

“If a delay becomes necessary, PJM should seek a revised date for that auction or run it under the existing rules, which have not been found to be unjust, unreasonable or unduly discriminatory. Neither the stakeholders’ nor the commission’s review of PJM’s complex filings should be cramped by PJM’s assertions that allowing two more weeks for comments will materially affect the auction schedule,” AMP said.

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PJM MRC Briefs: Oct. 25, 2023

Markets and Reliability Committee

Proposed Rules for Generation with Co-located Load Rejected

VALLEY FORGE, Pa. — The PJM Markets and Reliability Committee rejected a proposal to modify how generators with co-located load not interconnected with the RTO’s grid may participate in its capacity market.

The package, which was sponsored by Exelon in the Market Implementation Committee, received 19.5% support during the Oct. 25 vote. (See “Stakeholders Endorse Proposal on Co-located Load,” PJM MIC Briefs: Aug. 9, 2023.)

The proposal would have required that the generation and load each be separately metered, with the generator being designated as a load-serving entity for the load. The generator would have been billed for the energy consumed by the co-located load as an LSE in settlement.

Exelon Vice President of Federal Regulatory Affairs Sharon Midgley said the proposal would allow the generator to offer its full accredited capability as capacity and require the load to pay for a capacity commitment through LSE charges. She said the proposal would effectively be a net financial derate for capacity market participation.

Constellation Director of Wholesale Market Development Adrien Ford urged the committee to vote against the proposal, referring to her comments during the package’s first read in September arguing, in which she argued that it would violate the Federal Power Act by considering load not receiving energy from PJM’s grid to be FERC jurisdictional.

Midgley responded that the load under the proposal would be retail and end-use.

Independent Market Monitor Joe Bowring said that the IMM opposed the proposal because, despite its designation of the generator as an LSE, it would permit the same capacity to be sold twice.

PJM’s Tim Horger said that several proposed amendments were dropped based on stakeholder feedback in September and a determination that they were not necessary. He offered a friendly amendment, which the commission accepted, to adjust the cost-based offer definition to be in line with changes made throughout the manuals following the shift to cost- and market-based offers. In the event that the larger proposal did not pass, he said that PJM would seek to make the revisions as a standalone manual change.

Stakeholders have been discussing how to account for generators with co-located load, both in configurations where the load is interconnected to the wider PJM grid or only capable of receiving energy from the generator. Several proposals addressing both were voted on by the MIC in August, but none regarding grid-connected load were endorsed, and Exelon’s was the only one for unconnected load to pass.

Stakeholders Mixed on Sunsetting Clean Attribute Procurement STF

Stakeholders are considering terminating the work of the Clean Attribute Procurement Senior Task Force (CAPSTF) following several states opting to form a working group outside the PJM process to explore the creation of a voluntary market for trading clean energy attributes that is not under FERC jurisdiction.

The CAPSTF’s work culminated in three proposals being polled in May, but none received the majority support needed to advance to the MRC. The poll did show overwhelming support for putting the task force on hiatus while the Critical Issue Fast Path (CIFP) process on the capacity market that, initiated in February, ran its course.

The effort is being spearheaded by Ryann Reagan, of the New Jersey Board of Public Utilities, who told RTO Insider that the state working group is primarily focused on a forward clean energy market (FCEM) design, which she said is a process similar to the proposal that received the largest share of support in the poll at 41%.

The concept would allow the trading of products representing clean energy attributes, as well as existing renewable energy credits (RECs). PJM currently administers a registry of RECs through the subsidiary PJM EIS (Environmental Information Services), but it does not facilitate the trading of credits.

The FCEM design would not involve the procurement of capacity outside the Base Residual Auction (BRA); that would be more along the lines of an Integrated Clean Capacity Market, a variant of which received 33% in the poll.

The working group is open to the public, with those interested in participating welcome to reach out to Reagan; PJM and the Brattle Group are participating in addition to the states. The working group has a goal of reaching a general framework for a market design by the end of the year.

Whatever form any market created by the working group takes, Reagan said it’s intended for state participation to be voluntary and also be open for nonstate entities, such as companies with clean energy goals. She said she has heard frustration about the lack of a centralized way to purchase credits, particularly for smaller REC buyers.

The desire to move out of the PJM stakeholder process is partly borne of not wanting to lose momentum at a time that the RTO is beginning work on several significant issues, such as the rules around reserve resources and generation deactivation. She noted that the topic had been discussed at PJM for three years and the CAPSTF has been on hiatus for five months.

Katharine McCormick, of the Illinois Commerce Commission, said the working group is also building on discussions held at the Organization of PJM States Inc. (OPSI) that concluded over the summer. She highlighted a few priorities in the analyses at PJM and OPSI, including that all of Illinois be modeled, so that the impact of any resource deactivations to the southern, MISO-covered portion of the state are considered.

McCormick said Illinois is participating in the working group, but it has not committed to being involved in any final market design that may come out of it. In addition to being able to procure capacity that meets the state’s future clean energy requirements, she said it is also interested in ways of satisfying its capacity needs outside of PJM’s Reliability Pricing Model (RPM).

If the end result of the working group does turn out to be a FERC-jurisdictional market, PJM’s Scott Baker, facilitator of the CAPSTF, said a new forum can be found to hold those discussions.

Vistra’s Erik Heinle said the possibility of the working group yielding a product that is either FERC jurisdictional or has an impact on PJM’s markets that requires stakeholder attention could warrant leaving the task force open for at least a few additional months, especially considering the group’s goal for a framework.

Baker responded that PJM staff considered leaving the task force open but are generally averse to having task forces not actively engaged in work.

Multiple Proposals Considered for Incorporation of Multi-schedule Modeling

The committee discussed two proposals intended to allow modeling of combined cycle and storage resources to be incorporated in the market clearing engine (MCE) without causing computation times to increase to an untenable degree.

Both proposals were endorsed by the MIC at its Oct. 4 meeting and are slated to be considered for MRC endorsement on Nov. 15. (See “Multi-schedule Modeling in Market Clearing Engine,” PJM MIC Briefs: Oct. 4, 2023.)

The main motion, sponsored by PJM, would create a formula to select the offer expected to produce the lowest total dispatch cost and forward only that offer to the MCE. An alternative, jointly sponsored by PJM and GT Power Group, would select resources’ cost-based offers when they fail the three-pivotal-supplier (TPS) market power test and their parameter-limited offers during emergency conditions.

The issue stems from an expectation that the number of schedules that the MCE would have to consider would exponentially increase because of the number of configurations that combined cycle and storage resources can reflect in their offers. The changes are being considered as part of a larger overhaul of the MCE through PJM’s Next Generation Markets (nGEM) project.

GT Power’s Tom Hyzinski said the rationale behind the joint proposal was to find a middle ground between PJM’s proposal to pick a single generator’s offer using a formula, and another proposal that GT Power put forward with the Monitor that would have constructed a single offer using parameters from one offer and incremental costs from another. He said the joint PJM proposal uses the formulaic approach to pick a single offer from among multiple cost-based offers, while the IMM proposal would require the resource owner to select the single cost-based offer.

“The intent here was to move this thing towards the middle,” he said.

Deputy Monitor Catherine Tyler presented an issue with each proposal that she argued would create new ways for generators to avoid market power mitigation without resolving existing issues.

Tyler said PJM’s proposal would result in the RTO only considering offers at their economic minimum (EcoMin) value, even if that offer becomes much more expensive at higher outputs. She gave an example of a resource where the price-based offer is cheapest at its 100-MW EcoMin but which jumps to the $1,000/MWh offer cap when the resource is dispatched above 120 MW. In such a case, she said the cost-based offer should be selected even if it’s more expensive at EcoMin.

The PJM/GT Power proposal and the IMM/GT Power proposal, which was not endorsed by the MIC, would resolve the market power mitigation issue, Tyler said.

Both proposals would also use the PJM total dispatch cost formula to select among multiple cost-based offers, creating a possibility of a dual-fuel resource being dispatched on a fuel that is not the most economical for a portion of the day. Tyler said that could create a dilemma for generators because of the requirement that they base cost-based offers on the most economical fuel or risk being in violation of market manipulation rules.

PJM’s Keyur Patel said that some tradeoffs will have to be accepted to realize the benefits of combined cycle modeling.

“We know that this is not optimal,” he said.

Tyler said that the MRC should endorse the IMM/GT Power proposal, arguing that neither PJM nor GT Power had explained why it would be not the best solution.

Recommended Values for 2023 Reserve Requirement Study

The committee endorsed PJM’s recommended values for the installed reserve margin (IRM) and forecast pool requirement (FPR) components of the annual Reserve Requirement Study (RRS), which would have the effect of increasing the amount of capacity the RTO aims to procure through future BRAs.

The parameters are set to go before the Members Committee in November and to the Board of Managers for final approval in December. (See “Stakeholders Endorse Reserve Requirement Study Values,” PJM PC/TEAC Briefs: Oct. 3, 2023.)

The IRM, which sets the targeted capacity level above expected loads, would rise from 14.7% for the 2026/27 delivery year in the 2022 study to 17.6% for the 2027/28 delivery year. The FPR, which includes forced outage rates, also would increase from 9.18% to 11.65% for the corresponding delivery years.

PJM made a handful of changes to how the study is conducted in the wake of December 2022’s Winter Storm Elliott and the changes to the capacity market being considered by FERC through the RTO’s filing resulting from the CIFP. Load models were developed using both the PRISM software PJM has historically used, as well as an hourly loss-of-load model developed from the effective load-carrying capability accreditation studies. PJM also included data from the 2014 polar vortex and Elliott, reversing a historical practice to not include extreme winter storms in the study’s modeling based on the impact of Elliott.

Minimal coincidence between the PJM peak load period and the “world” peak — which is defined as MISO, NYISO, TVA and VACAR — led to the capacity benefit of ties (CBOT) value more than doubling to 2.2% from the 1% value in the 2022 study. To reduce volatility, PJM elected to average the CBOT values from 2017-2022 and use that figure, which landed at 1.5%, instead.

The load model, which included data from 2013-2019, contributed to a 2.1-percentage-point increase in the IRM, while the winter peak week caused a 1.1-point increase. The values were slightly lower for the FPR drivers. The 1.5% CBOT contributed to a 0.5-point decline in the IRM value and a 0.58-point-lower FPR.

During a Resource Adequacy Analysis Subcommittee (RAAS) meeting in August, James Wilson, a consultant to state consumer advocates, calculated that the recommended values would constitute an approximate 3,700-MW increase in the summer reserve margin.

New Transmission Outage Coordination Rules

The committee signed off on revisions to Manual 38, which pertains to operations planning, to increase coordination between PJM and transmission owners to capture any potential extended transmission outages not identified by existing processes.

The proposal would add a step after board approval of Regional Transmission Expansion Plan (RTEP) windows for RTO staff and TOs to coordinate the sequencing of their outages and evaluate if any mitigation is needed, such as short-term emergency ratings or upgrades to limiting facilities. (See “Stakeholders Endorse Outage Coordination Manual Revisions,” PJM OC Briefs: Oct. 5, 2023.)

The overall outage coordination package approved by the Operating Committee in June also adds information about outage requests and transmission ratings to PJM’s website to increase transparency. (See PJM OC Briefs: June 8, 2023.)

Members Committee

3 Changes to Stakeholder Process Proposed

The Members Committee discussed first reads on three proposed changes to Manual 34, which sets the structure of the Consensus Based Issue Resolution (CBIR) stakeholder process.

Dayton Light and Power presented a change to the voting structure so that if a main motion fails, any alternative proposals submitted during the period for posting meeting materials would be voted on simultaneously.

Exelon’s Alex Stern presented a proposal that would specify that requests to add an item to a standing committee meeting agenda is considered to be timely when it is made at least seven days in advance. Requests should include a summary of the action that the committee will be asked to consider.

The language would provide committee chairs with discretion to consider agenda items posted within seven days of a meeting in the event of the subject being time sensitive or of unforeseen disruptions, such as PJM website or internet outages.

Chairs may also consider waiving the deadline for non-voting items, such as informational reports, with the suggestion that members instead provide enough time for PJM staff to review for formatting and agenda conformity.

Monitor Bowring asked for clarification on whether the flexibility around informational items would apply to the reports delivered to the MC webinar, which Stern confirmed would be the case.

Stern also presented a second proposed change aiming to clarify that senior standing committees hold final authority over issues considered by task forces and that the lower committees set the order that proposals will be voted on at the MRC and MC.

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Providers See ‘Mixed Signals’ on Demand Response in NYISO

RENSSELAER, N.Y. — Demand response providers in NYISO last week expressed concern that proposed market rule changes will harm the economics of special case resources (SCRs).

“This has not been a good week for demand response,” said Aaron Breidenbaugh, senior director of regulatory affairs at CPower Energy Management, which aggregates demand response and distributed energy resources.

Breidenbaugh’s comment came at the Oct. 26 Installed Capacity/Market Issues Working Groups meeting, where the ISO presented proposed modeling changes that could significantly cut capacity accreditations for SCRs. It followed the Oct. 25 Management Committee meeting, where Potomac Economics, the ISO’s market monitoring unit, proposed that the ISO compensate some capacity suppliers based on their contribution to transmission security, which could also reduce payments to SCRs.

SCRs are demand-side resources whose load can be interrupted at the ISO’s direction or behind-the-meter generators rated 100 kW or higher that can reduce load on the transmission or distribution system.

The ISO says its current modeling of SCRs in the installed reserve margin (IRM), locational capacity requirement (LCR) and capacity accreditation studies is not aligned with SCRs’ actual performance.

It proposes to model SCRs as duration-limited resources with hourly response rates based on historical performance beginning in the 2025/26 capability year. In the interim, the ISO said it will treat SCRs as part of the four-hour energy duration limited capacity accreditation resource class. (See NYISO Previews Capacity Accreditation Modeling Work.)

Breidenbaugh said the ISO’s proposed changes could cut capacity accreditation of SCRs by 20%. He said his company will seek a change in the SCR program “to move from four hours to some other number … in order to avoid gutting the SCR program.”

Breidenbaugh said Potomac’s proposed changes would reduce the payments to SCRs even more than is being contemplated by changes to accreditation rules, saying, “I’d prefer having my revenues reduced by 50% as opposed to 75%, but neither one of them is terribly attractive.”

Breidenbaugh said he’s received “mixed signals,” from the ISO on potential changes to the SCR program, citing NYISO CEO Rich Dewey’s comments at the Multiple Intervenors annual meeting about being willing to make SCR programs more flexible when previous NYISO presentations had suggested no such flexibility. He also cited statements by officials of the New York State Energy Research and Development Authority at the Alliance for Clean Energy New York annual meeting about “how important demand response is and how we aren’t going to meet the requirements in the CLCPA [Climate Leadership and Community Protection Act] without significantly greater demand-side flexibility.” (See Mood Anxious as Renewable Energy Industry Gathers in NY.)

He added that the ISO has made clear “that the future of demand response is the DER participation model — not getting rid of [the SCR program] but [NYISO is] making it so unattractive that the only alternative is to go into the DER participation model.”

The ISO’s DER and aggregation participation model, which will allow heterogenous groups of technologies to be compensated for services that they can provide collectively, was approved by FERC in January 2020 (ER19-2276). (See NYISO DER Participation Model Gets FERC OK.) On Oct. 19, the ISO informed FERC that it would not be implementing the DER participation model until the commission acts on companion tariff changes in docket ER23-2040.

Engaging the Demand Side

Adam Evans, a staffer at the New York Department of Public Service, also expressed concern. Although the ISO’s Short-Term Assessment of Reliability report for the third quarter identified a need to respond to new loads and shrinking margins, he said, “there’s really not much coming out of the Engaging the Demand Side effort,” an initiative to identify problems or gaps in the ISO’s existing demand side programs.

“I am really concerned about the long-term viability of the SCR program,” said Jay Goodman, an attorney with Couch White, which represents large consumer stakeholders. “It seems that with every change layered onto the modeling, the impact generally seems to be in the direction of decreasing [SCRs’] capacity value.

“Our expectation is that SCRs being available is increasingly important, and so it doesn’t make sense to have a … market rule change at a time when we think we need to be able to rely on them more,” Goodman said.

In a presentation in September on the Engaging the Demand Side initiative, the ISO said it was not seeking to eliminate the SCR program but to respond to stakeholders’ requests to modify SCR rules so that resources are compensated for their true operating capabilities.

The ISO said some SCRs can respond to events more frequently than others, and with less than the current 21-hour advance notification requirement. Some also can operate for up to eight hours. “In short, some resources have expressed that they are more flexible than the SCR program allows, but not flexible enough to fully participate in the DER program on dispatch,” the ISO said.

The ISO said it would prefer to modify the DER participation model to tailor it to SCR operating characteristics rather than expanding the SCR program. Unlike the SCR program, which relies on manual actions by NYISO operators, demand-side resources in the DER model are automatically scheduled and dispatched based on the economics of their bids.

Maddy Mohrman, NYISO capacity market design specialist, told the ICAP/MIWG that “the goal of this project really is to come up with a modeling that just better represents the [SCR] program today.”

NYISO will bring the results from its enhanced SCR modeling to the Nov. 1 meeting of the New York State Reliability Council Installed Capacity Subcommittee, which may vote to recommend changes be implemented into future IRM/LCR modeling.

MMU Recommendation

Breidenbaugh said SCRs could also lose revenues under Potomac Economics’ suggestion to the Oct. 25 MC meeting that NYISO implement proposal No. 2022-1 from the MMU’s May State of the Market report.

Potomac’s Pallas LeeVanSchaick reiterated the monitor’s recommendation during a discussion of NYISO’s draft annual Comprehensive Reliability Plan, which the MC recommended be approved by the Board of Directors.

The CRP said that although the probabilistic resource adequacy analysis did not identify any reliability needs, the deterministic transmission security analysis predicts a deficiency for New York city starting in 2031 if the New York Power Authority’s small gas plants, totaling 517 MW, retire without replacement resources.

Overview of factors causing higher resource-adequacy-based New York City margin in 2025 | Potomac Economics

The MMU’s memorandum summarizing its comments on the CRP’s resource adequacy assessment assumes that up to 1,180 MW of “emergency” resources in New York City for 2025, including 219 MW of SCRs. The transmission security assessment does not include emergency actions.

The MMU’s State of the Market report found that SCRs and large resources whose size causes the transmission security planning contingency to increase “provide limited value towards satisfying reliability requirements based on transmission security criteria.”

“Transmission security requirements are increasingly likely to cause higher [locational capacity requirements], especially in New York city. When this occurs, SCRs and large resources will be overcompensated and have inadequate incentives to take actions that would improve system reliability. In the upcoming 2023-24 capability year, we estimate that large resources and SCRs in New York City could be over-compensated by up to $52 million. (See NYISO MMU Calls for Improved Shortage Pricing, More Capacity Zones.)

LeeVanSchaick said the MMU proposes a two-part pricing mechanism that separates resource adequacy and transmission security when transmission security criteria determine the LCR, ensuring SCRs, large contingency resources and intermittent renewables are appropriately compensated based on their contributions to the planning reliability requirements.

LeeVanSchaick pointed to a chart in Potomac’s presentation to the MC that showed a roughly 800-MW difference in the marginal requirement needs for New York city projected by the two assessments. “If you calculate the margins [for New York city] using a transmission security assessment, there’s a deficit in 2025, while a resource adequacy assessment would tell you there’s a surplus,” LeeVanSchaick said.

Breidenbaugh said that under the MMU’s proposal, “you pretty much wouldn’t have any SCRs in New York city.”

Both NYSIO and Potomac acknowledged stakeholders’ concerns but stressed more discussion is forthcoming.

LeeVanSchaick emphasized that Potomac “wanted only to highlight these differences to increase people’s understanding of how the emergence of transmission-security-based capacity requirements are likely to affect investment incentives.”

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Four New Wind Energy Areas Designated in Gulf of Mexico

Four new wind energy areas with a potential capacity of 9.27 GW of power generation have been designated in the Gulf of Mexico.

The Bureau of Ocean Energy Management said Oct. 27 that the sites total 763,000 acres and stand 47 to 82 miles off the Texas and Louisiana shorelines.

A notice of proposed sale will be issued next, with a 60-day public comment period to follow.

The move is part of the Biden administration’s continuing effort to expand offshore wind generation. BOEM conducted the Gulf of Mexico’s first offshore wind area auction in late August with disappointing results: Two of the three wind leases drew no bids, and the third attracted only two bidders, one of whom dropped out after the first round.

The final result: RWE Offshore US Gulf got rights to install up to 1,244 MW on 102,480 acres with a winning bid of $5.6 million. That is less than $55 an acre and compares with top bids of more than $10,000 an acre in a 2022 auction off the New York-New Jersey coast.

BOEM Director Elizabeth Klein alluded to the lackluster results of the August auction as she announced the new wind areas: “Creating an offshore wind industry in the Gulf of Mexico will take time and partnership. BOEM is pursuing another offshore wind lease sale in the Gulf of Mexico due to continued industry interest and feedback from our partners and key stakeholders.”

Multiple factors complicate offshore wind development in the Gulf, starting with the supply chain constraints and soaring costs plaguing the offshore wind industry elsewhere as it attempts to establish itself in the United States.

Also, the Gulf has weaker winds and a softer seabed than the areas being targeted for offshore wind development off the Atlantic and Pacific coasts, plus a greater threat of hurricanes.

Finally, the economics are less than ideal in the Gulf region, where electricity is relatively inexpensive.

On the positive side, there is potential interest in the Gulf region in using offshore wind to power clean hydrogen production. The fossil energy industry has a large offshore presence in the area, making wind turbines more palatable to the public. And Louisiana is encouraging offshore wind development closer to shore, in state waters.

The trade group Business Network for Offshore Wind welcomed BOEM’s announcement and noted that the Gulf region already is playing an important role in U.S. offshore wind development.

In a news release, BNOW Vice President John Begala said:

“With nearly a quarter of U.S. market contracts going to Gulf firms, the area is already the engine for U.S. offshore wind industry; building a robust pipeline of projects will further unlock the true potential of the region’s supply chain capacity. Gulf expertise in offshore construction is unparalleled, and innovative solutions developed there will continue to drive not just the U.S. but the global offshore wind industry forward.”

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Mass. Climate Chief Issues Wide-Ranging Recommendations

As climate impacts continue to accelerate, Massachusetts must redouble its efforts to cut emissions and boost resiliency, the state’s Climate Chief, Melissa Hoffer, wrote in a lengthy set of recommendations issued Oct. 25.

“Massachusetts finds itself at a pivotal moment,” Hoffer wrote. “Massachusetts must act with far greater urgency and our efforts must be better coordinated. Every state agency must prioritize, as a core function, efforts to drive effective action to reduce emissions, build resilience and mitigate the impacts of climate change on our communities and the natural world.”

Hoffer leads the Office of Climate Innovation and Resilience, established in January by Democratic Gov. Maura Healey’s first executive order.

At a high level, Hoffer said the state needs to shift from planning to implementation of climate resilience programs, secure more money for decarbonization and climate mitigation and coordinate planning across state entities on workforce and economic development.

Hoffer highlighted several key barriers to the clean energy transition, including opposition from fossil fuel interests, inadequate funding for electrification and resilience, workforce shortages, supply chain constraints and the need to upgrade the grid.

“Those with vested interests in fossil-fuel-based systems continue to use political and economic power to stall action in the Commonwealth and around the world,” Hoffer said, adding that a general bias toward the status quo also has slowed the region’s energy transition.

To address the barriers and increase the pace of the transition, Hoffer detailed a set of recommendations for state offices and agencies, including a proposed comprehensive analysis to quantify the investments needed to reach net-zero by 2050.

“While investments in decarbonization and resilience will be significant, those costs are much less than the cost of failing to make such investments,” Hoffer said. “When government policymakers consider the social cost of greenhouse gases such as extreme weather and disaster response costs, infrastructure damage and human morbidity and mortality, it becomes easier to see the true social cost of greenhouse gas emissions.”

Hoffer estimated recent federal legislation will account for about 8-30% of the necessary spending to reach net-zero and said the state will help fill the remaining gap. She did not explicitly endorse putting a price on carbon but said the state should consider market mechanisms that simultaneously incentivize decarbonization and provide funding for clean energy and climate resilience.

Grid Upgrades

Hoffer wrote that the state must prioritize developing transmission infrastructure while also embarking on a “large-scale public education campaign” to connect the need for this infrastructure to address the climate crisis. She highlighted the importance of reducing the environmental damage of new transmission projects as much as possible, while ensuring local communities see tangible benefits.

Hoffer also emphasized the importance of establishing a domestic supply chain for critical grid components including distribution transformers to insulate the industry from global price increases. She added the region should use advanced technologies as much as possible to limit the number of critical components needed.

“Non-wired alternatives that can replace the need for large, expensive and backlogged components are also essential, and should be prioritized in utility planning,” Hoffer said. “[The Department of Energy Resources] and [the Department of Public Utilities] should accelerate efforts to align utility incentives to prioritize non-wired alternatives.”

She added that reducing interconnection timelines will be critical to scaling up renewable energy at the pace needed to meet the state’s goals, saying that interconnection delays pose an “existential threat to our ability to achieve our emissions reductions mandates.”

Hoffer said the state needs proactive utility planning that will enable high levels of distributed resources and electrification growth. She added that the state should work to increase grid resilience using local networks of solar and storage.

Noting the regulatory difficulties that microgrid developers have faced in the state, Hoffer recommended the Department of Public Utilities clarify or update its regulations of multi-user microgrid facilities intended to provide local power during outages of the larger grid.

“The question is not whether but when the Commonwealth will be struck by a devastating hurricane, heat dome or other deadly climate-driven weather event,” Hoffer wrote. “Now is the time to invest in the resilient energy infrastructure that is necessary to keep our residents safe.”

Reforms to Mass Save

Hoffer called for significant reforms to Mass Save, Massachusetts’ energy efficiency program that is administered by the state’s gas and electric utilities.

“Mass Save is structured primarily to support cost savings from energy efficiency and not to achieve building decarbonization/electrification,” Hoffer wrote. “[As] a result, Mass Save continues to support fossil-fuel heating systems and typically does not support deep enough retrofits or related technologies (such as solar, EV chargers, storage).”

Hoffer highlighted the energy efficiency programs implemented in Maine and Vermont and said Massachusetts’ relevant agencies should work to redefine the goals of the program and align it with the state’s climate targets. She acknowledged this would be a long-term project and said the state should simultaneously pursue incremental reforms.

“The long-term success of the Mass Save program should be measured by the rate at which the programs accelerate the market transformation from incumbent fossil fuel use to the efficient electrification of heating,” Hoffer wrote, adding that the program’s administrators “should focus on phasing out most fossil-fuel heating equipment in new construction and providing incentives for owners of existing buildings to transition to electric heating.”

Environmental Justice and Workforce Development

Noting that climate change disproportionately affects people of color and low-income communities, Hoffer said Massachusetts must focus on these environmental justice communities as it plans resilience efforts and builds clean energy infrastructure.

Hoffer called on state agencies to work with the Climate Office and the Office of Energy and Environmental Affairs’ Environmental Justice Office to develop community benefit agreements for infrastructure projects that affect environmental justice populations.

“To achieve widespread market deployment of technologies such as EVs and heat pumps, the Commonwealth should conduct outreach to people in rural areas, Gateway Cities, immigrant communities, working class neighborhoods, indigenous populations and communities of color,” Hoffer said.

The report also emphasized the importance of growing the state’s clean energy workforce for a wide range of jobs, from bus drivers to electricians to workers collecting organic waste. Citing estimates from the Massachusetts Clean Energy Center, Hoffer said the state needs to grow its clean energy workforce by nearly 30,000 people to meet its 2030 climate goals.

“The Commonwealth should develop, by May 2024, a comprehensive, cross-agency plan to build the clean energy, climate and resilience workforce that includes measurable targets and goals,” Hoffer said. She also advocated for the creation of a “climate service corps” that would provide opportunities for young adults, citing the federal American Climate Corps and state programs in Maine, Michigan and Hawaii.

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Conn. Seeks Proposals for Onshore, Offshore Renewables

The Connecticut Department of Energy and Environmental Protection launched two new clean energy solicitations Oct. 27.

The first request for proposals calls for up to 2,000 MW of new offshore wind capacity and includes provisions to avert the problems plaguing the offshore wind industry.

The onshore solicitation is broader: Developers can propose most types of clean energy technology in response, including solar, wind, zero-carbon fuel cells, geothermal, energy efficiency, run-of-river hydropower, and energy storage paired and co-located with a zero-carbon resource.

The onshore solicitation is intended to provide up to 3.975 million MWh, or about 15% of the state’s electricity load.

The two solicitations are designed to move the state closer to its statutory goals of a 100% zero-carbon electric portfolio by 2040 and greenhouse gas emissions at least 80% lower than 2001 levels by 2050.

The offshore solicitation comes at a difficult time for the young U.S. offshore wind industry.

Earlier in October, Avangrid reached an agreement to cancel power purchase agreements for its Park City Wind project, which would send up to 804 MW to Connecticut. Two major offshore projects in Massachusetts canceled their PPAs this year, and three major New York projects are considering doing the same.

The developers will likely attempt to rebid the projects they have invested billions in, but such a move would inevitably increase ratepayer costs and delay start of construction.

The problem in each case is the same: Developers’ costs for building the projects soared after they locked in the income they would receive from operating the completed projects.

Connecticut’s new offshore solicitation gives bidders a cost-indexed option allowing an up-or-down price adjustment of up to 15% based on inflation and other factors between bid submission and financial close.

Also new in this offshore wind solicitation is the option of submitting a multistate bid. In early October, Connecticut, Massachusetts and Rhode Island agreed to coordinate their offshore development efforts. Each state has been having significant difficulties in the sector, and they hope collaborating will increase efficiencies while reducing cost and risk.

The three states have now issued requests for proposals for a combined 6.8 GW of new offshore wind capacity in the space of two months.

Connecticut has included specific environmental requirements in the solicitations:

Onshore proposals must conform to the state’s broader environmental policy goals. Development in core forest is prohibited, as are solar projects on slopes greater than 15% and development on prime farmland, unless a proposal meets specific dual-use requirements.

The offshore solicitation includes a requirement for robust environmental and fisheries mitigation plans and imposes fees of at least $15,000/MW for fish and wildlife monitoring and mitigation.

Bids are due by Jan. 31. DEEP said another request for proposals — this one for energy storage — will be released in draft form this year.

“Grid-scale clean energy projects are critical investments to diversify our grid, which will help protect Connecticut residents and businesses from price spikes linked to global fossil fuel markets and geopolitical events, while making our energy supply more reliable and our air safer to breathe,” DEEP Commissioner Katie Dykes said in a news release. “Continuing to make progress toward a zero-carbon grid is essential, as the public health and economic costs of carbon pollution are now being felt more regularly and severely here at home.”

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PJM Stakeholders Approve New CONE Area for ComEd over Consumer Opposition

The PJM Markets and Reliability Committee (MRC) voted Oct. 25 to approve the creation of a fifth cost of new entry (CONE) area for the Commonwealth Edison (ComEd) zone to reflect an expectation that the Illinois Climate and Equitable Jobs Act (CEJA) will shorten the lifespan for combined cycle generators — the current reference resource CONE values are based on.

The vote capped months of discussions of how to reflect particularities at the local and state level that could affect the inputs in calculating the cost to build the reference resource, a subject broached by J-Power USA in a protest to PJM’s 2022 quadrennial review filing. The company argued that new combined cycle resources would be forced into retirement within the 20-year amortization period included in the CONE calculation due to the legislation’s requirement that generators have zero carbon emissions by 2045. (See “J-Power Critiques Amortization Period,” PJM Defends Quadrennial Review Parameters from Generator Protests.)

The vote, which carried 80% support, came after a motion from the Illinois Citizens Utility Board (CUB) to defer the vote by a month failed after receiving 46.7% support against the two-thirds sector-weighted threshold needed to pass. Clara Summers of the Illinois CUB said that the delay would have provided more time to evaluate the effect of the proposal and potentially develop an alternative or amendments to the package. In particular, she expressed concern the proposal had no mechanism for reevaluating whether the ComEd-specific net CONE zone is providing relevant price signals as we near 2045, the expected end date for the combined cycle reference resource.

The proposal was endorsed by the Members Committee following the Oct. 25 MRC vote. A motion to defer the vote made by Summers was rejected by the MC as well.

She argued the legislation could affect inputs used to calculate CONE beyond the reference resource asset life, including the energy and ancillary service (E&AS) revenue offset.

“This proposal focuses on one factor in setting net CONE, asset life, because of CEJA … but CEJA also has an impact on things like the E&AS offsets,” Summers said before motioning to defer the vote.

She also pointed to comments PJM made in support of its quadrennial review filing at FERC stating there hasn’t been a holistic analysis of CEJA’s impact on CONE and that creating a region to account for legislation in Illinois could establish a precedent for creating CONE areas across several states and localities to account for various policies. Instead of establishing a new CONE area to account for specific legislation in one state, she said creating a clear standard for when a new area is warranted would be preferable.

Zachary Callen of the Illinois Commerce Commission said commission staff are not opposed to creating a new CONE area on principal, but he believes it’s a complicated subject that hasn’t had enough stakeholder discussion.

“It does give us pause that this is a really Illinois- and CEJA-specific policy and what we’d like to see more is something more rules-based,” he said.

He said the tightened Base Residual Auction schedule over the next few years would provide little time for policy makers, load and generation to respond to price signals based on a new CONE area. Given PJM’s analysis that the effect would be minimal at first, Callen suggested it may be better to wait until the next quadrennial review to make the change and to use the additional time to conduct more research.

Paul Sotkiewicz, president of E-cubed Policy Associates, said he had brought an alternative proposal that would have automatically created a new CONE area when policies affecting a region affected CONE inputs. He withdrew the package out of a desire to have the reduced asset life implemented in time for the 2025/26 auction. The further in advance the change is made, the less sharp any change in CONE values would be, he said.

“It’s important to send those signals about reliability sooner rather than later, rather than have everything fall off a cliff” and risk a larger rate shock, Sotkiewicz said.

PJM’s Gary Helm said the new area would have a CONE value of $201,714/MW-year, higher than any of the existing four areas. CONE Area 3, which ComEd is a part of, has a value of $197,800/MW-year. The proposal would affect only the reference resource asset life factor, based on the assumption that natural gas resources will retire based on CEJA’s requirement that those generators reduce their emissions to zero by 2045.

Helm said waiting until the next quadrennial review would mean any changes would not be implemented until the 2030/31 delivery year, well into the period that PJM has stated it’s concerned about resource adequacy as loads increase and fossil generation retires. He said that the proposal is part of a larger strategy for maintaining resource adequacy and that making the changes at this time would avoid a sudden change in capacity prices.

The motion to defer was supported predominantly by the electric distributor and end-use customer sectors, with about 90% support in both categories. The other supplier and generation owner sectors were strongly opposed and transmission owners more mixed about the proposal, with 40% support. When the vote shifted to the actual proposal to create a fifth cone area, the transmission owner, other supplier and generation owner sectors were unanimous in their support, while 70% of the electric distributor sector and 46.2% of end-use customers voted in support at the MRC.

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ERCOT Technical Advisory Committee Briefs: Oct. 24, 2023

ERCOT stakeholders last week agreed with the staff’s decision to table a protocol revision request implementing a new ancillary service that faces a tight statutory timeline.

Kenan Ögelman, ERCOT’s vice president of commercial operations, told the Technical Advisory Committee Oct. 24 that tabling the protocol change would give the Public Utility Commission time to “digest” a recent filing by state lawmakers pushing back against the grid operator.

State Sen. Charles Schwertner (R) and state Reps. Justin Holland (R) and Todd Hunter (R) sent a letter to ERCOT and the PUC objecting to an ERCOT nodal protocol revision request (NPRR1203) that would create the new service, dispatchable reliability reserve service (DRRS), as a subset of non-spinning reserve service. The legislation (House Bill 1500) they helped push through earlier this year mandates DRRS be implemented as a standalone service by Dec. 1, 2024.

“We studied every way we could think of a standalone DRRS delivered by Dec. 1, 2024, and none of those were feasible,” Ögelman told TAC. “I could try to reprioritize as much as I wanted, and there’s just not enough time.”

He said creating DRRS as a standalone service would require market testing “that adds time to the option.”

The lawmakers differed and urged the commission to direct ERCOT to revise NPRR1203 and to establish DRRS as a standalone ancillary service, “even if doing so will cause a delay.”

Combining DRRS into non-spin will create a single clearing price that could have a negative impact on consumer costs and diminish “market incentives to invest in the specific type of dispatchable resources needed to improve reliability,” the lawmakers said.

“The purpose of this provision was to create a targeted ancillary service product that could leverage flexible, dispatchable generation resources to more efficiently manage operational uncertainty within the ERCOT market,” they wrote. “We are concerned the current proposal does not meet the legislature’s goal of creating an ancillary service product designed to meet actual system needs in a targeted, transparent manner and could have a negative impact on consumer costs.”

ERCOT filed a response with the PUC, requesting guidance from the PUC on whether to proceed with implementing DRRS as a non-spin subtype to meet the deadline or to begin developing a standalone product. It said work already has begun on the former option and that “any pause in this work would introduce risk of missing the delivery deadline” (55156).

The grid operator said TAC and its board will need to vote on NPRR1203 and two related binding document revisions (OBDRR049 and OBDRR050), also tabled, during their December meetings to stay on schedule.

The PUC plans to take up the matter during its open meeting Nov. 2.

To be eligible for DRRS, resources must be dispatchable, be off-line and able to come on-line within two hours and capable of operating at their high sustained limit for at least four hours. NPRR1203 would establish a maximum amount of non-spin that can be provided by DRRS as a sub-type of non-spin. HB1500 also requires reliability unit commitment activity be reduced by the amount of DRRS procured.

Non-spin reserves in ERCOT also are off-line capacity that can start up and provide power, usually within 10 minutes.

Representing Reliant Energy Retail Services, Bill Barnes said stakeholders are concerned DRRS delays could push back real-time co-optimization (RTC), a market mechanism that clears energy and ancillary services every five minutes in the real-time market and is scheduled to come online in 2026.

“As stakeholders, when we compare the two, I think we see much more value in RTC in terms of impact to consumers,” he said. “I think we would have concerns if that [DRRS] change in direction would change the implementation and push that back significantly.”

ERCOT’s Independent Market Monitor prefers a standalone product that it says would better address reliability needs and have more accurate pricing.

ERCOT to Propose Price Correction

ERCOT staff told TAC they were investigating a potential price correction after an Oct. 22 problem with the security constrained economic dispatch (SCED) system. Following the meeting, ERCOT made it official by issuing a market notice that said the pricing issue met the grid operator’s initial criteria for the Board of Directors to review the real-time prices before they become final.

Staff will take the price correction to the board’s Reliability and Markets Committee Dec. 18 and then the directors Dec. 19 for their approval. They also will present the potential price correction to TAC during its Dec. 4 meeting.

According to the market notice, SCED was unable to consume specific three-part supply offers (energy offer curves) and real-time energy bids for several resources after an issue with the market management system (MMS). That resulted in SCED failing to produce valid prices for its intervals between 12:15 p.m. and 12:54 p.m. Another related issue caused SCED to fail to run from 12:56 p.m. to 1:09 p.m.

Staff ran into another error trying to process the price correction data and were unable to post the corrected prices before they became final.

Ögelman said an integer field that tracks submissions, each with a unique identifier through the ISO’s systems, exceeded a limit of more than 2 billion submissions. At that point, additional submissions were rejected. That led to price spikes before noon and a little after 1 p.m.

Staff addressed the issue by freeing up some of the numbers and letting market participants resubmit. They then were able to clear the day-ahead market, Ögelman said.

“It is a parameter that dates back to nodal go-live,” he said. “It was not envisioned that we would exceed that number, but clearly, we did. I do think that ultimately, we would need to change that cap.”

Sreenivas Badri, director of grid and market solutions, told members it would take “probably five, six years” before the issue would happen again. In the meantime, he said, staff is working with a vendor to make application changes and implementing a revision that would significantly reduce the growth of unique identifiers.

TAC Endorses RUC Change

TAC approved a revision request (NPRR1172) brought forward by consumer groups that removes the mitigated offer cap multipliers and creates a 100% claw-back for RUCs. The revision’s intention is to encourage generation resources to self-commit.

“It makes sure that the generator that’s committed by ERCOT through RUC, which would have no downside risk because its costs are guaranteed, can’t make money from the RUC,” Eric Goff, who represents residential consumers, said. “It encourages self-commitment because in today’s environment, a generator that is marginal could trade some of their profits in exchange for a guarantee that they won’t lose any money.”

Not surprisingly, the generator segment opposed the measure, casting three of five dissenting votes. The cooperative segment accounted for the other two opposing votes when the NPRR passed, 23-5 with 2 abstentions.

“This is bad policy. I fundamentally disagree with Eric’s assertion that there is no downside risk because costs are guaranteed,” Luminant Generation’s Ned Bonskowski said. “I encourage anyone that is sympathetic to resources having [been] effectively co-opted by many times a load forecast that is in excess of what the market believes and incurring costs … ideally they should have full recovery, but our experience has been that is not always the case.”

The consent agenda, passed unanimously, included two NPRRs and changes to the nodal operating guide (NOGRR) and planning guide (PGRR) that, if approved by the board and the PUC, would:

    • NPRR1192: Incorporate the other binding document “Requirements for Aggregate Load Resource Participation in the ERCOT Markets” into the protocols.
    • NPRR1196: Correct and update equations used to determine ancillary service (AS) failed quantity calculations for load resources other than controllable load resources (NCLRs) developed under NPRR1149. Changes would include: calculation updates to account for AS allowances and restrictions that NCLRs can and cannot carry simultaneously with ERCOT contingency reserve service’s (ECRS) implementation; specifying the snapshot components to be used for the “telemetered AS for the NCLRs as calculated” variable; and adding a non-zero check for the “telemetered ECRS responsibility for the resource as calculated” variable.
    • NOGRR257: Resolve a conflict in emergency response service event-reporting timelines between the operating guide and protocols by striking the guide’s 90-day event-reporting requirement.
    • PGRR110: Remove a paragraph from the guide to accommodate the release of steady-state planning models in node-breaker format pursuant to a system change request.
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DOE to Sign up as Off-taker for 3 Transmission Projects

The U.S. Department of Energy will put $1.3 billion in federal funds into becoming the anchor off-taker for three interstate transmission projects that together will put 3.5 GW of new transmission capacity online, Secretary Jennifer Granholm announced on Oct. 30.

Under a program set up by the Infrastructure Investment and Jobs Act (IIJA), the department will start negotiating contracts for up to 50% of the capacity on the lines, with the goal of de-risking and accelerating construction of projects that provide vitally needed new interregional transmission, according to DOE.

Located in the Southwest, Mountain West and New England regions, the projects were selected based on regional needs and priorities detailed in DOE’s final National Transmission Needs Study, also released on Monday, according to the department.

Speaking during an advance press call on Friday, Granholm explained that having DOE as an anchor off-taker — an entity that commits to buying a significant amount of power from a project — will minimize upfront financial risk and give “developers the confidence that they can actually build.”

Calling the contracts a “unique and creative solution,” Granholm stressed that “these awards are not for construction costs.” A developer would not receive any cash until a project is completed and online, and DOE will be able to sell its capacity to other off-takers, ensuring funds are available for contracts or other support for additional projects.

Ideally, the risk to the department will also be minimal. DOE’s commitment could draw in other off-takers, so the project is “fully subscribed by other customers before the project is finished and energized,” according to a DOE email.

The IIJA provides $2.5 billion for the initiative, officially called the Transmission Facilitation Program (TFP), which is being administered by DOE’s Grid Deployment Office. The money will be used in a revolving fund that can be awarded to projects via capacity contracts, loans or public-private partnerships.

The program webpage says TFP awards are best suited for projects that are nearly shovel-ready, and that no awards will be made to projects that are already fully subscribed or “have a fully allocated source of revenue.”

A second round of funding, for up to $1 billion, is expected in the first half of 2024, DOE said.

The three projects selected for the first round of TFP funding, all in the form of capacity contracts, are:

    • The Cross-Tie Transmission Line, a 1,500-MW line running 214 miles between Utah and Nevada. The line will improve grid reliability and resilience, relieve congestion on other lines and allow access to low-cost renewables in the region.
    • The Southline Transmission Project, a 748-MW line stretching 175 miles between Hidalgo County, N.M., to Pima County, Ariz. This project will support ongoing renewable energy development in southern New Mexico while delivering clean energy to areas in Arizona currently dependent on fossil fuels.
    • The Twin States Clean Energy Link, a 1,200-MW line connecting New Hampshire and Vermont to clean energy resources in Canada. The bidirectional line will also allow New England to export power to Canada from future offshore wind projects. The 185-mile project includes 75 miles of new underground line and 110 miles of upgraded lines in an existing right of way, according to the project website.

The Cross-Tie and Southline projects are expected to break ground in 2025, with the Twin States line to follow in 2026, an administration official said. According to the Transmission Needs Study, all three projects are in regions that will need major amounts of new transmission or interregional transfer capacity by 2030.

In the Mountain West region, the DOE study anticipates a need for nearly 2,300 GW-miles of new transmission as clean energy projects come online, leveraging incentives in the Inflation Reduction Act. The study also predicts 1.5 GW of interregional transmission will be needed in New England.

DOE defines gigawatt-miles as capacity multiplied by distance. The department said the figures in the Needs Study could be met with a mix of projects; for example, the 2,300 GW-miles needed in the Mountain West region could be broken down into nine 200-mile, 500-kV lines, but other configurations are possible, the department said.

Top Need: Reliability

The Biden administration sees high-voltage transmission as critical to reaching its goal of a decarbonized grid by 2035 and net-zero greenhouse gas emissions economywide by 2050.

Speaking on Friday, National Climate Advisor Ali Zaidi noted the TFP announcement follows other administration initiatives on transmission, such as DOE’s recent selection of 58 projects to receive $3.46 billion in IIJA funds for local grid improvements. (See DOE Announces $3.46B for Grid Resilience, Improvement Projects.)

Such federal funding “is doing exactly what it was designed to do,” Zaidi said. “It’s catalyzing the private sector, industry and labor all to step up at this moment of critical need.”

Granholm also hailed the number of jobs the projects could create — 13,500 direct and indirect positions — and the community benefit packages all the projects have negotiated with stakeholders and communities affected by their projects. The Twin States project is providing a community benefits package that includes $60 million to be divided between the nonhost states of Massachusetts, Connecticut, Rhode Island and Maine, according to a DOE fact sheet on the project.

Extreme weather events have also underlined the need for more interregional lines to move power in emergency situations and to allow clean energy produced in remote areas to move to where there is demand for it. The Needs Study calls for the U.S. to double existing regional capacity by 2035 and expand interregional capacity fivefold, according to a DOE press release.

The report’s top takeaways, Granholm said, are, “no surprise, that we need to seriously build out transmission in order to improve reliability and resilience, and of course, to lower energy costs and relieve congestion on the grid.”

Reliability has remained a key driver for new transmission, growing from 44% of new lines in 2011 to 74% in 2020, according to the report. The most pressing and valuable new lines are needed between Texas and all its surrounding regions, and between the Plains and Mountain West, the report says.

The report anticipates that by 2035, Texas will need a median of 9.8 GW of additional transfer capacity with the Plains region, a whopping 1,201% increase over 2020 levels. Slightly less eye-popping, New England will need to expand its interregional lines with New York about 255%, or 5.2 GW, and the Midwest will need a 156% increase, or about 33.8 GW, of new interregional capacity with the Mid-Atlantic.

According to the Needs Study, the proportion of overall transmission installed to address system reliability needs has grown from 44% in 2011 to 74% in 2020. | DOE

Reactions

One of the developers on the Southline project, Michael Skelly, CEO of Grid United, sees the TFP as a kick-starter for interregional transmission growth.

Developers want to sign up off-takers for as much of a line’s capacity as possible before putting steel in the ground to minimize their risk, Skelly said in an interview with RTO Insider. For Southline, getting the line’s 748 MW fully subscribed is “a tall order even in today’s markets. So, this lowers the bar. If we get one customer [taking] a few hundred megawatts and we have DOE, off we go,” he said.

Echoing DOE, Skelly said having the department on board will draw in other off-takers, so its share of the project’s capacity likely will be sold before it goes online. DOE “might actually never put a penny out the door,” he said.

Stephen Woerner, New England president for National Grid, the lead developer for Twin States, said the TFP announcement “is an important step forward … as we work to make the project a reality for the region. DOE has recognized the significant economic and environmental benefits of this project to New England communities, residents and businesses.”

Rob Gramlich, president of Grid Strategies, said TFP “can address the perennial ‘chicken and egg’ problem with transmission,” in which construction may wait upon demand, but demand waits upon construction. Having DOE as an anchor off-taker “promises to work a lot better than the current stalemate,” he said in an email to RTO Insider.

But Gramlich also feels the program’s $2.5 billion pot “only allows [it] to support a very small set of lines. Congress and the administration should prioritize raising that pot in future appropriations.”