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November 4, 2024

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PJM Refines Risk Modeling, Stakeholders Begin Final CIFP Presentations

PJM detailed changes to the performance assessment structure and risk modeling in its critical issue fast path (CIFP) proposal Aug. 1, followed by presentations from Constellation Energy and Vistra.

While an additional meeting has been scheduled for Aug. 14, several stakeholders expressed concern there would not be enough time to get through the remaining stakeholder presentations and hold a dialogue about them before sponsors propose to the board and the Members Committee votes on the proposals Aug. 23. (See PJM Updates Proposal as CIFP Nears End.)

Paul Sotkiewicz, president of E-Cubed Policy Associates, questioned if it would be possible to delay the Stage 4 presentation to the board and subsequent MC vote to allow more Stage 3 meetings to be held.

“We’re trying to do too much in too short a time, and I just don’t see how we’re going to get through this all,” he said.

PJM Director of Stakeholder Affairs Dave Anders said staff are investigating all the ways of ensuring stakeholders have the information they need to make an informed vote. He told RTO Insider that any delay of the meetings would need to be made at least seven days prior to their scheduled date but that PJM would intend to announce any such changes as early as possible to respect stakeholders’ travel arrangements.

PJM Modifies Performance Assessment Proposal

Presenting how PJM could measure performance during emergencies and how it would determine penalty charges and bonuses, Pat Bruno said the proposal would retain the current capacity performance framework, while making changes to the penalty structure and balancing ratio and creating a new bilateral trading system.

The proposal would use the same performance assessment interval (PAI) trigger as was included in a filing PJM made in May, which allows an emergency to be declared only when there is a primary reserve shortage, voltage reduction warning and at least one of several additional emergency actions, including a manual load dump warning or maximum emergency generation action. The commission approved the filing July 28.

The penalty rate and stop loss will remain status quo under PJM’s proposal. Both were components of a proposal endorsed by the Members Committee in May, but which the board decided not to include in its filing. (See PJM Board Rejects Lowering Capacity Performance Penalties.)

Resources’ performance in the balancing ratio would be capped at their installed capacity (ICAP) rating, meaning a resource with a capacity obligation of 70 MW and 100 MW ICAP would receive a maximum overperformance bonus equal to 30 MW. The status quo rules do not include a cap.

PJM’s Pat Bruno said energy prices likely would be sufficiently high during an emergency to continue to incentivize resources to perform above their ICAP if they are able.

Energy-only and uncommitted capacity resources would be ineligible to receive bonus payments, but the latter would be eligible to take on committed capacity resources’ obligations through a new hourly financial capacity trading option. Capacity resources would be able to sell a portion of their obligation to another resource, so long as the buyer had accredited capacity that was not committed. The buyer would be eligible for capacity performance bonuses and penalties and the seller would be required to indemnify PJM if the buyer could not perform and could not pay the penalty.

David “Scarp” Scarpignato, of Calpine, said PJM’s analysis of the December 2022 winter storm showed that 70% of the overperformance was from capacity resources and generators. Around 30% was from uncommitted capacity and energy-only resources, which are not eligible for bonuses under PJM’s proposed new rules because they are categorically excluded.

Scarp said the “non-committed capacity” resources might find it uneconomical to provide desired emergency energy, especially after the timely gas nomination period has passed.

“I’m not sure you want the uncommitted capacity generator having to make a decision about losing money to help out. The energy market revenues are not enough in some instances, such as when competing for emergency energy imports,” he said. “I’m worried that in adhering to PJM’s strict ‘committed capacity’ theory, we’re ignoring the reality that the huge quantity of energy-only and uncommitted resources are absolutely needed by PJM for reliability.”

PJM also proposed to modify the fixed resource requirement (FRR) penalties by lowering the insufficiency charge from 2 times the cost of new entry (CONE) to 1.75 times net CONE. The daily deficiency charge would be changed from 1.2 times the Base Residual Auction (BRA) clearing price to 1.75 net CONE.

PJM Updates Risk Modeling Calculation

PJM’s Patricio Rocha Garrido presented updated risk modeling figures focused on where the RTO believes the balance between winter and summer risk lies. The new “base case” the proposal uses is based on weather data going back to 1993, does not include any adjustment for climate change, a proposed change in how demand response and storage are dispatched and updated planned outage data.

The latest modeling places 68% of the annual expected unserved energy (EUE) risk in the winter, with the remainder in the summer. The seasonal risk shifts 56% of the risk to the summer if PJM does not include data from the 1994 winter, which included a particularly severe storm in January.

Previous risk modeling proposals included a longer weather lookback to 1973 and adjusted past weather events with a climate change modifier to account for the expectation that temperatures would be warmer if similar weather occurred in the future. PJM’s Walter Graf said the amount of variability PJM saw in the modeling outcomes when implementing the adjustment led it to become less confident in the adjustment.

The new dispatching in the modeling would deploy demand response before storage, which would be ordered so long-duration storage is used before short-duration.

Presenting estimated 2026/27 class average accreditation values, Garrido said storage resources would have significantly higher values during the summer owing to the historical finding that winter outages are likely to be more prolonged. Four-hour storage would have a 90% accreditation during the summer, while 10-hour resources would have 100%; during the winter, however, those resources’ values would be 38% and 69%.

Demand response and solar also see large hits to their accreditation during the winter, which Garrido said is because the times at which their contribution is strongest tend to not align with the peak reliability risks for the season.

Showing a heatmap of the hours that tend to have the highest risk for each month, Garrido said the bulk of summer risk is concentrated on July days between 5 and 7 p.m. In the winter, risk is split between around 6 to 10 a.m. and 5 p.m. to midnight in January and a smaller share in February following a similar distribution.

James Wilson, a consultant to state consumer advocates, said he was disappointed PJM did not update the resource mix in the modeling, which he said assumed a large increase in solar, inconsistent with the relatively low summer risk and reliability value in the results.

Wilson questioned why PJM has settled on using 1993 as the date to start its weather lookback and suggested the decision may have been made to include 1994 in the dataset and weight the risk modeling toward winter.

Graf said the year was chosen because it’s the starting point for lookback periods PJM uses for other parameters.

Constellation Responds to PJM Proposal

Presenting for Constellation Energy, Adrien Ford said several changes to PJM’s proposal would improve the construct, including using a prompt capacity market with a shorter timeframe between the auction and the corresponding delivery year or season, a minimum number of PAIs per delivery year and a rolling 20-year historical weather lookback.

Ford said the company is planning to update its own proposal in the matrix, but Tuesday’s presentation was meant to add to the wider discourse around other proposals and design components being considered.

A prompt auction design six months to a year forward of the period the capacity is being procured for would improve the data available to market participants, Ford said. That would include the potential for a more accurate forecast of supply and demand, and reflect changes in the amount of time it takes to build generators.

Ford also said Constellation is considering an earlier capacity performance proposal from PJM where a minimum number of intervals each year would be examined for performance, with the 10 highest load hours each season used to meet the threshold at the end of the year. The changes to the PAI trigger likely will reduce the number of emergencies generators experience, which she said increases the need for regular evaluation of resources’ contribution.

Constellation supports PJM’s proposal to derive the reliability requirement from EUE analysis, rather than the status quo loss of load expectation and using marginal effective load carrying capability for accreditation.

Vistra Suggests Changes to PJM Proposal

Vistra’s Erik Heinle said the company supports much of PJM’s proposal but is concerned with several provisions, including limiting bonus payments to committed capacity resources, generators’ ability to reflect the risk of being assigned penalties in their market seller offer cap and the ability for the CIFP process to result in an adequately fleshed-out seasonal auction model.

Not allowing a wider range of resources to receive bonus payment for overperforming reduces the incentive for investments that can support reliability and increases the risk for those considering whether to make upgrades to allow them to qualify as capacity resources. If such a resource makes significant reliability upgrades but doesn’t clear, Heinle said it would be deprived of both capacity revenue and the opportunity for bonuses.

While he said the hourly capacity obligation trading proposal improves the ability to mitigate risk and improve transparency, he also said more work is needed to ensure that generators can represent all the risks that come with taking on a capacity obligation. The company also supports PJM’s decision to maintain the current capacity performance penalty rate and stop loss limit, as well as exempting intermittent and storage resources from offering into the capacity market.

Heinle suggested that PJM include the seasonal capacity model in its filing but delay its implementation to allow more time to allow stakeholders to make changes and understand how the changes would play out.

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FERC Approves PJM Change to Emergency Triggers

FERC has approved PJM’s request to revise its tariff to tighten the triggers for a performance assessment interval (PAI), requiring that a primary reserve shortage be in effect paired with a set of emergency actions (ER23-1996).

In its May 30 filing, PJM argued that adding the primary reserve shortage would better align the timing of PAIs with their intended generator performance when it would be most beneficial to reliability. For a PAI to be declared, a shortage would have to be in place as well as a voltage reduction warning paired with any of the following actions: reduction of critical plant load, manual load dump warning, maximum emergency generation action or the curtailment of non-essential building loads and voltage reduction. The July 28 order stated that the changes would provide dispatchers with more certainty during stressed conditions.

The emergency actions necessary for the declaration of a PAI also were reduced to no longer include pre-emergency demand response, which PJM argued should be available for dispatchers to utilize without initiating a full emergency declaration.

“We also find that it is appropriate to remove the deployment of pre-emergency load response and emergency load response from the trigger for a PAI because PJM cannot verify the amount of response these resources are providing until 60 days after an event, and therefore it may be prudent for PJM operators to maintain load response even after capacity shortage conditions pass,” the order says. “As PJM explains, its proposed revisions will enable PJM operators to efficiently and effectively operate the grid without second guessing their decision to keep emergency procedures in place during non-capacity shortage instances, such as the hours between morning and evening peaks during extreme winter conditions.”

In directing the board to file the proposal, the PJM Board of Managers took one of three components of a package endorsed by stakeholders during the May 11 Members Committee meeting. The other two portions of the package would have based the penalty for resources that perform below their capacity obligation and the annual stop-loss limit on the Base Residual Auction (BRA) clearing price for the locational deliverability area (LDA) that the resource is located within. (See PJM Board Rejects Lowering Capacity Performance Penalties.)

Several organizations filed in support of the change to the trigger, but asked that the commission remain open to the possibility of changes to the penalty rate and stop loss in the future.

Though it supported the change to the trigger, the Independent Market Monitor argued that PJM did not make a satisfactory case for not including the full stakeholder-endorsed proposal and suggested that the commission should open a Federal Powers Act (FPA) 206 proceeding to evaluate if the charge rate is just and reasonable.

PJM filed a response stating that commission action is not needed as stakeholders are considering changes to capacity market design, including the penalty charge rate and stop loss limit, through the critical issue fast path (CIFP) process. American Municipal Power (AMP) argued in response that it’s unknown what the result of the CIFP process may look like, whether the commission will approve any resulting filing and whether changes will be effective for the next auction.

The latest version of PJM’s CIFP proposal, presented during the Aug. 1 stakeholder meeting, did not include changes to the penalty charge rate or stop loss limit.

The Public Service Commission of West Virginia protested the filing, arguing that the change to the trigger would create unbalanced obligations between load and generation. Under the proposed language, it said load will receive voltage reduction and load shedding warnings encouraging consumers to reduce their consumption, but capacity resources will not be notified that they need to be ready for dispatch.

Vitol argued that the tariff revisions would violate the filed rate doctrine and rule against retroactive ratemaking if it were to be applied to auctions that already have concluded. The company stated that market sellers include their expectations about the number of PAIs and how they will impact their generators when forming the capacity performance quantified risk (CPQR) component of their market offers, which goes on to influence their bids and the ultimate auction clearing price.

PJM responded that it is not aware of any unit with a CPQR component that did not clear in either auction which has been concluded for future delivery years that would be affected by the tariff language, nor did the marginal unit in either auction contain a CPQR component to its offer.

The commission stated in its order that insufficient evidence had been provided that the proposed language would have had any impact on capacity offers. In considering the balance of settled expectations for those auctions, the order states that the commission found that the benefits of more accurately aligning PAIs with stressed grid conditions where generator performance impacts reliability outweighed market participants’ expectations based on the emergency action definition.

“There is insufficient record evidence, and no evidence from parties that raise such arguments, that such risk had a material impact on final capacity offers, especially given the other major uncertainties that affect suppliers’ assessments of PAI penalty risk, such as weather, fuel availability or equipment failures,” the order says.

In supporting the filing, the PJM Power Providers Group (P3) argued that it would allow PAIs to be more reflective of when emergency conditions exist on the grid and avoid “false positives” that have been seen in PJM’s history.

The order directs PJM to submit a compliance filing within 30 days to correct clerical errors and capitalize the phrase “Primary Reserve requirement” to more explicitly refer to the parameter defined in the RTO’s manuals by the same name.

The Ohio Federal Energy Advocate and Earthrise argued there was ambiguity in PJM’s filing around whether the primary reserve requirement by which a shortage is measured against referred to the manual defined reserve requirement or to the broader reserve requirement for primary reserves, which includes the extended reserve requirement. The primary reserve requirement is set at 150% of the synchronized reserve reliability requirement, which itself is based on the single largest contingency on the grid.

Earthrise argued that the filing should be read to refer to the primary reserve requirement without extended reserves and that PJM should be required to make a compliance filing specifying its intent. PJM filed that it preferred to include extended reserves in its definition and included new proposed tariff language in its response.

The commission’s order stated that the language of PJM’s original filing referred to the primary reserve requirement without the inclusion of extended reserves and its intent or preference to include extended reserves was not reflected.

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States, RTOs Caution DOE on Transmission Corridors

State officials, RTOs and public interest groups warned the Department of Energy last week not to let transmission developers dominate the development of National Interest Electric Transmission Corridors (NIETCs), saying the program should not overrun states’ interests and existing regional transmission planning processes.

DOE received 112 comments in response to its May Notice of Intent/Request for Information on the proposed designations, which DOE says would “unlock new financing and regulatory tools” as well as federal siting and eminent domain authorities. (See DOE Rolls out New Process for Designating Key Transmission Corridors.)

Public officials, RTOs and trade and environmental groups were generally supportive, although many asked DOE to ensure it chooses only projects that improve resilience, enable connection of renewable generators or produce cost savings. There was wide agreement that DOE should prioritize interregional projects, and some commenters said the department should also encourage use of grid-enhancing technologies (GETs).

But some commenters challenged the legality of DOE’s proposed “applicant-driven, route-specific” approach. Individual landowners were almost universally opposed, criticizing the potential use of eminent domain by “greedy developers.”

Below, based on a review of the comments, is a summary of concerns and questions raised.

Eligibility Questions, States’ Role

The Infrastructure Investment and Jobs Act (IIJA) created the Transmission Facilitation Program, giving DOE $2.5 billion for public-private partnerships to co-develop transmission projects located within NIETCs. The Inflation Reduction Act (IRA) created the $2 billion Transmission Facility Financing program, allowing DOE to offer loan support to transmission facilities designated by the Energy Secretary as being in the national interest.

DOE said it expects that most proposed routes will be “associated with specific transmission projects under active development, meaning that a potential applicant has progressed beyond the preliminary concept and has begun actively routing the project and engaging in community and landowner outreach, land surveys or initiation of environmental compliance work.”

Although DOE said it expects most NIETC applicants to be transmission developers with a project under development, “no particular stage of development is required” for designation. (See related story, What are National Interest Electric Transmission Corridors and Why Do We Need Them?)

Public interest groups including the Natural Resources Defense Council, Earthjustice, the Southern Environmental Law Center and Environmental Defense Fund said DOE “must exercise independent judgment” in evaluating developers’ proposed corridors, warning that DOE’s proposed approach “risks conflating developers’ commercial interests with the national interest.”

“Although developers’ NIETC proposals may reveal where there is the greatest commercial interest in transmission development, there is no guarantee that developers will propose corridors that are truly in the ‘national interest,’” they wrote. “For example, they may hope that a NIETC designation will unlock financing that makes a transmission project easier to build or more profitable.”

State regulators submitted comments ranging from supportive to highly skeptical, with many expressing concern that DOE’s proposal would make private companies the only entities capable of applying to have NIETCs recognized. DOE said it may also allow tribal authorities, states, transmission-dependent utilities, local governments, generation developers and others to submit proposals.

The Mississippi and Louisiana public service commissions expressed strong opposition, saying the Federal Power Act grants the designation authority to the Secretary of Energy only, and contains “no language that authorizes the DOE to allow independent developers to make the NIETC designations based upon those developers’ own economic self-interests.”

They said the NOI could harm ratepayers. “Construction of transmission … can have enormous cost consequences on affected transmission facilities. Those consequences … must be remedied and financed by the entities causing those impacts.”

The Pennsylvania Public Utilities Commission also questioned allowing “private transmission developers to be the driving force” in designating NIETCs, adding that the NOI’s route-specific approach could create a presumption that transmission lines are the best solution to congestion and discourage investigation of other alternatives.

California’s Public Utilities Commission and its Energy Commission supported the plan overall, but urged DOE to open the application process to states, tribes and transmission operators. They also suggested creating an “applicant-driven ministerial certification process” for projects that address the purpose and needs of a given NIETC, which would encourage developers to participate in such projects while leaving state authorities and FERC in charge of the permitting process.

‘Clear and Prominent Role’

The New England States Committee on Electricity said DOE’s designation process “should provide a clear and prominent role for states,” allowing them to file applications for potential routes “where one or more potential transmission projects have clear state support” as well as providing input on others’ proposals. “Such an approach would recognize the primacy of the states’ role in siting transmission infrastructure and their authority over investments made to satisfy their own mandates and legal requirements,” NESCOE said.

The National Association of State Energy Officials (NASEO) said that, in light of the role of state energy offices in facilitating transmission upgrades and expansion, DOE should allow them to apply for NIETC designation as well. NASEO said state energy offices “have the tools, resources and knowledge to identify potential corridors that would benefit their states, regions and the nation.”

In a joint comment, the utility commissions of Michigan, New Jersey, North Carolina and Virginia pointed out that because “a NIETC designation has the potential to boost a project’s chance of being constructed considerably,” there is a danger that transmission developers could use the designation “strategically” to gain an advantage over projects “that may be better or more cost-effective.” The commissions also feared that the designation might help “shovel-ready” projects lose ground to less prepared developers.

The Edison Electric Institute said DOE’s process is “reactive” and would “unnecessarily limit DOE’s evaluation of corridors to only the areas, or indeed projects, submitted by applicants.”

Rather, it said DOE should, “proactively identify the geographic areas exhibiting the most significant or persistent need for immediate transmission development.”

The American Public Power Association said DOE should also allow transmission-dependent utilities to apply for NIETC designation and participate in joint ownership of projects, which it said could save ratepayers money and help win local support.

“The diversity gained by including public power in joint ownership arrangements can help with the acquisition of rights-of-way and permits, by having a broader and more diverse set of utilities advocating for projects at the state level. Engaging more rural communities and helping to bridge urban-rural division, as well as being more inclusive of rural communities, are additional public policy benefits of joint ownership arrangements that include public power,” APPA said.

Respect Existing Planning Processes

CAISO, PJM and the MISO Transmission Owners were among those insisting that any procedures the DOE settles on should complement existing transmission planning efforts.

WIRES, a trade association representing transmission providers, developers, customers and regional grid managers, cautioned DOE against allowing the NIETC designation process to “inject unhelpful uncertainty into regulated transmission planning processes.” It said ongoing planning initiatives like MISO’s long-range transmission planning shouldn’t be undermined by DOE “potentially elevating” inefficiently planned projects over those contemplated in FERC-approved planning processes.

“That situation could slow progress and erode stakeholder support for these plans and/or make it more difficult to move ahead with regionally planned portfolios that have been in the works for years,” WIRES said.

WIRES, state regulators and PJM said DOE should require projects be included in a regional transmission plan before they can receive a NIETC designation.

“The NIETC process should not be used to circumvent [RTOs’] transmission planning processes. If a project is proposed as part of the RTO planning process and does not meet RTO planning or benefit criteria, then [its] proponent should not have recourse to the NIETC process to push that project into construction,” regulators from Michigan, New Jersey, North Carolina and Virginia said in a joint comment.  “Both are federal processes — one subject to a FERC-accepted tariff, the other this application process. Having two conflicting federally approved processes would deter, rather than promote, responsible transmission planning.”

APPA agreed. “Failure of a proposed project to participate in a regional, interregional or even local planning process should weigh heavily against NIETC designation, particularly since a NIETC designation (and the prospect of FERC backstop approval) might otherwise encourage transmission developers to circumvent regional transmission planning and/or interregional coordination,” APPA said.

PJM said that without an “orderly, sequential NIETC process” that recognizes the authority of RTOs and ISOs, “DOE could find itself having to referee among developers/applicants who are seeking to end-run the detailed RTO/ISO analyses and competitive planning processes … Absent such a clearly-defined and sequential process, the roles of an RTO/ISO as a Planning Authority could be blurred with DOE potentially granting a NIETC designation that is at odds with the reliability, market efficiency and state public policy analyses undertaken by the RTO/ISO in choosing among competing projects.”

Invenergy said DOE should solicit interregional merchant transmission projects, “which have the potential to solve critical interregional needs while largely avoiding contentious discussions on cost allocation, but which face unique barriers and hurdles.”

“DOE must ensure that the process is equally accessible to transmission developers and transmission projects regardless of their business model and inclusion (or not) in a FERC-approved regional transmission planning process. Since many of the FERC-approved regional transmission planning processes exclude from consideration merchant transmission projects, as well as any other transmission projects not seeking cost allocation, inclusion in such a plan must not be a criteria in the NIETC process. … FERC-approved regional planning processes tend to be narrowly focused, considering only benefits that accrue to that particular region and specific needs identified by the region.”

ERCOT meanwhile made clear it wants no part of NIETC, saying DOE should ensure that “a proposed NIETC does not include any portion of the ERCOT region.”

Metrics and Priorities

EEI criticized the NOI/RFI for lacking information on how DOE will compare and prioritize NIETC applications. “Section 216 of the Federal Power Act does not limit the number of national interest corridors that DOE may designate, but reason demands that DOE cannot designate every submitted application (or even many applications) as a NIETC,” EEI said. “… An explanation with respect to how DOE will evaluate the magnitude and effects of the transmission needs in proposed corridors would ensure that DOE designates the corridors of greatest need. This would further ensure prudent management of the financing tools created by the Infrastructure Investment and Jobs Act and Inflation Reduction Act.”

Idaho Power said DOE should use available transmission capacity as an indicator of areas with constraints. “The amount of transmission service requests that entities receive for a given corridor and the cost of required transmission upgrades identified in transmission service request studies is also a potential metric,” the company said.  LMP data from the Western Energy Imbalance Market could be used to identify areas with large reoccurring price spreads in the Western Interconnection, it added.

The New York Transmission Owners said DOE’s pending Transmission Needs Study should incorporate existing transmission planning processes rather than relying solely on National Renewable Energy Laboratory modeling for projecting future transmission expansion. DOE issued a draft Needs Study in February and expects to issue the final study later this summer.

“It is important that the study’s findings are reconciled with existing transmission planning, including existing planned project solutions, in DOE’s consideration of NIETC designations,” the TOs said.

NRDC and the other public interest groups said DOE should favor proposals that “provide the greatest and most immediate benefits in terms of increasing interregional transfer capacity and diversification of regional resources to speed the development of wind, solar and storage resources …” and “highly prioritize GHG reductions.”

The groups said interregional transmission has shown strong benefit-to-cost ratios and cited calculations by MIT researchers who found that “interstate coordination and transmission expansion [including across regions and interconnections] reduces the system cost of electricity in a 100%-renewable U.S. power system by 46% compared with a state-by-state approach, from $135/MWh to $73/MWh.”

“Because [interregional] projects provide great benefits but face great obstacles, they provide the best opportunity for DOE to maximize the positive impacts from NIETC designations,” the groups added.

Broad or Specific Designations?

The Rail Electrification Council and NextGen Highways, which suggested NIETC designations for existing railroad or highway rights of way, praised DOE for focusing on narrower areas and specific projects than in the first NIETC effort, “an ambitious approach in 2006 that set itself up for rejection by the courts.”

In 2011, the Ninth Circuit Court of Appeals vacated the first National Electric Transmission Congestion Study and its designation of the Mid-Atlantic Area national corridor and the Southwest Area corridor.

“The regional breadth of prior designations … made adequate identification and consultation with stakeholders extraordinarily difficult because of the volume and variety of landowner, environmental, economic and other issues involved,” the groups said.

Largest congestion value of new transmission is across the interconnects and during extreme weather events. | Lawrence Berkeley National Lab

However, Power From the Prairie, a proposed, 4,000-MW interregional HVDC line from southern Wyoming to northwestern Iowa, asked DOE to define NIETC corridors “broadly,” not tying them to any established routes. It also said DOE could consider establishing a separate “promising NIETC candidate project in-waiting” category for lines in the early stages of development.

NRDC and its allies supported DOE making NIETC designations not associated with a project under development. “DOE is well-situated to identify corridors that are in the national interest but where private development alone may be too challenging,” they said.

EEI said DOE should reconcile an apparent conflict in the NOI/RFI between the department’s assurance that it “does not intend to identify preference for specific projects within the corridors” and its assumption that proposed NIETCs will likely be “route-specific.”

PJM said if DOE opens NIETC applications to generation and merchant transmission developers it should limit it to those with executed interconnection agreements.

But Con Edison said DOE should not reject projects in the early stages of development that lack details on routing and environmental impact. “Projects in the conceptual or preliminary stages of development may have significant value and stakeholder support to address emerging clean energy needs, and therefore should be accommodated and not overlooked or delayed through the DOE process due to their nascent status,” the company said.

Balancing Climate and Conservation

The Arizona Game and Fish Department said while DOE is on the right track to include state, tribal and local authorities in NIETCs planning, it should also explicitly state that applicants consult with state wildlife agencies and other natural resource agencies to select routes that minimize habitat damage.

“State wildlife agencies can provide specific recommendations and information from subject matter experts on sensitive resources, species occurrence and distributions, areas of concern, wildlife connectivity, and more, as well as advise on potential conservation measures to avoid, minimize or offset potential impacts,” the Arizona agency said.

Conservation organization the Land Trust Alliance urged the DOE to write in explicit protections for conserved lands; incentivize proposals that utilize existing rights of way and minimize the land use footprint of transmission corridors; and only accept route-specific applications for consideration to avoid “orphaned NIETCs that are never built out due to conservation needs being identified too late in the process.”

“We must not undermine our nation’s investments in and future needs for conservation by siting energy transmission infrastructure in such sensitive environmental areas as conserved lands or lands with high conservation or agricultural values. For our nation to achieve its climate goals, there must be a balance of planning for clean energy through smart siting that recognizes conservation goals.”

A group of cities and communities across PJM and MISO called on DOE to develop a replicable and transparent  designation process with community workshops and roundtables. They also asked DOE to require applicants to submit community benefits plans and address equitable siting issues.

“The process should seek to balance the need for timely transmission and infrastructure development with community priorities,” the PJM and MISO communities said.

Legal Questions

Several commenters raised legal questions over DOE’s proposed approach.

The sponsors of the Southeastern Regional Transmission Planning Process (SERTP) — including Southern Company, Duke Energy and Louisville Gas and Electric Co./Kentucky Utilities Co. — said the applicant-driven, route-specific NIETC designation is “inconsistent” with the Federal Power Act and could override state resource plans or regional transmission planning.

EEI challenged DOE’s contention that the NIETC process is only guidance, saying the department must adhere to the notice-and-comment rulemaking requirements of the Administrative Procedure Act.

“DOE has taken the position that the designation of NIETCs constitute informal adjudications under the APA, not informal rulemakings. While that may be a defensible interpretation as to any given designation of a specific NIETC, that is not what DOE intends to accomplish in the planned ‘guidance’ that the NOI lays the groundwork for,” EEI said. “Rather, the planned ‘guidance’ would establish a prospective, broadly applicable framework for the designation of all route-specific NIETCs. DOE must do so through a rulemaking.”

Farm bureaus from multiple states — aware that their members may have lands seized through eminent domain — argued that the DOE doesn’t have the authority under the FPA to prescribe applicant-driven, route-specific framework for corridors, which would “put the cart before the horse,” they said.  Rather, they said the DOE should “solicit input regarding specific geographic areas that should be designated as NIETCs, but not specific projects needed to alleviate congestion or constraints in those areas.”

DOE cannot solicit projects that are already under development and draw a corridor around them, the farm bureaus said. Instead, they said the department must defer to states and regional planning authorities.

Some commenters questioned DOE’s proposal to limit applicants’ “Affected Environmental Resources and Impacts Summary” to 20 single-spaced pages, not including maps. The filing is required to detail engagements with “Communities of Interest,” the status of regulatory approvals and whether the project has been included in any local or regional transmission plans. DOE also asks applicants to explain if they are using transmission technologies such as advanced conductors  that allow more capacity in smaller corridors.

The Arizona Game and Fish Department said the limit should be removed.

Next Steps

DOE’s NOI/RFI doesn’t say how soon it will finalize its guidance on the NIETC program after reviewing comments. It has said it expects to post the final Needs Report in late summer 2023.

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American Clean Power Tallies Potential Impact of IRA at $270B

Private-sector investment in clean energy has exceeded $270 billion in the past year, more than eight times as much as in the previous eight years combined, a new report states.

The report also tallies 83 new or expanded manufacturing facilities, 30,000 new manufacturing jobs and 185 GW of new nameplate capacity in the past year.

“Clean Energy Investing in America,” released Monday by the American Clean Power Association, is among a wave of reports being issued on the effects of the Inflation Reduction Act as the anniversary of its becoming law nears.

The IRA’s infusion of hundreds of billions of dollars’ worth of open-ended federal incentives arrived with state and federal policy directives in place to help those incentives attract takers, a transformational combination that has resulted in the spending documented in the ACP report.

Many of the details in the report are best-case scenarios conditioned on multiple factors falling into place, and there are potential obstacles to that happening.

As American Clean Power CEO Jason Grumet noted in his introduction to the report: “We are still not on course to create a sustainable energy economy by mid-century. … we must not lose sight of the challenges in infrastructure permitting, clean energy transmission and distribution, and the frailty of key global supply chains.”

But the tone of the report is decidedly celebratory.

“The past year has sown the seeds of nothing short of a clean energy revolution,” Grumet said.

Clean energy projects announced since Aug. 16, 2022. | American Clean Power

The ACP based the report on public announcements between Aug. 16, 2022, and July 31, 2023. It focuses on the clean-energy manufacturing sector, in which it counts 83 major construction or expansion plans: 52 for solar, 14 for utility-scale battery storage, 11 for onshore wind and six for offshore wind.

This is expected to result in an annual increase in production capacity from 4 GWh to 62 GWh for batteries; 7 GW to 62 GW for solar modules; 3 GW to 35 GW for solar cells; 0 GW to 10 GW for solar ingots and wafers; and 22 GW to 29 GW for polysilicon. Wind power component data was not available.

This all comes with a price tag of more than $22 billion and is expected to create 29,780 new jobs.

The good news in job creation carries with it a complication of its own: As Grumet pointed out, recruiting, training and supporting these new workers will take a significant investment of time and money. And the 30,000 manufacturing workers are just the start — sectorwide, 550,000 new hires will be needed by 2030, he said.

ACP said other hurdles to overcome include political and local opposition to new clean energy projects; permitting delays; inflation; transmission congestion; and government policy.

ACP is a trade organization representing 750 utility-scale solar, wind, storage, green hydrogen and transmission companies.

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FERC Approves Updates to ISO-NE Inventoried Energy Program

FERC on Friday approved a series of updates to ISO-NE’s Inventoried Energy Program (IEP), replacing the IEP’s fixed forward and spot rates with indexed rates intended to reflect natural gas price changes (ER23-1588).

The commission sided with ISO-NE over the protests of the official consumer advocates for Massachusetts, Connecticut, New Hampshire and Maine, as well as a group of environmental nonprofits, which argued that the changes would increase electricity costs for consumers.

“The revisions maintain the overall structure of the commission-approved Inventoried Energy Program, while updating the tariff to help ensure that the Inventoried Energy Program can fulfill its purpose of incenting resources to maintain inventoried energy during periods when reliability is most threatened,” the commission wrote, making the revisions effective Aug. 4, as requested.

The goal of the IEP is to pay generators — mostly oil and gas power plants — to keep up to three days of stored fuel on-site during the winter to ensure reliability for the region.

FERC agreed with ISO-NE that the updated rates more accurately reflect market conditions, noting that the changes will do away with fixed payment rates based on 2019 fuel price data. (See Gas Volatility Leads ISO-NE to Seek Update to Inventoried Energy Program.)

“Current fuel prices exceed these fixed payment rates, which could reduce incentives to participate in the Inventoried Energy Program,” FERC said.

In joint comments to FERC opposing ISO-NE’s IEP proposal, the Sierra Club, the Conservation Law Foundation and the Union of Concerned Scientists argued that the changes to the program would lead to substantially increased costs for ratepayers. The organizations noted the IEP updates could increase the total cost of the program from $300 million to $800 million over two years according to the upper-bounds analysis of ISO-NE, “all for suggested, but deeply uncertain, benefits to consumers.”

The state consumer advocates pressed the commission to consider the high costs of the Mystic cost-of-service agreement before authorizing the likely increase of costs related to the IEP. (See Public Power Groups Seek Information on Mystic Agreement.)

“The commission cannot and should not ignore the magnitude of impact that the Mystic COSA has had on consumers in determining the justness and reasonableness of the IEP Redesign,” the consumer advocates wrote. “The IEP Redesign includes very little support despite imposing potentially massive costs on ratepayers, which is especially egregious in the context of the COSA’s similarly massive costs.”

The commission said it had already settled many of the issues the protestors raised.

“The proposed revisions at issue here reflect only narrow modifications and provide no basis to revisit past findings related to the Inventoried Energy Program’s core structure, which will remain unchanged,” it said.

FERC also disagreed with the contentions that ISO-NE did not adequately demonstrate the need for the IEP, that the IEP could result in windfall payments for oil generators and that the costs to consumers would likely outweigh the benefits.

‘Funny Fuel Supply’

ISO-NE applauded the commission’s ruling.

“With the commission’s acceptance, we’re moving forward on promptly implementing these updates into the upcoming winter,” the grid operator said in a statement to RTO Insider, adding that the updates “will align the program with current market conditions.”

Meanwhile, the Sierra Club, the Conservation Law Foundation and the Union of Concerned Scientists expressed displeasure with the ruling.

“CLF is disappointed by the commission’s decision, which approves changes to an ISO-NE program that extends our region’s overreliance on expensive, imported and polluting fossil fuels at a time when we need to be deploying clean energy resources,” Phelps Turner, senior attorney for the Conservation Law Foundation, told RTO Insider.

“The fossil-fuel-fired generators that it seeks to incentivize appear to already have a legal obligation to be fuel-ready and, in any event, they have substantial economic incentives to be ready and to perform, without the need for consumer subsidy,” Turner added.

Casey Roberts, senior attorney for the Sierra Club, said the FERC-approved changes could ultimately amount to a handout to the gas and oil generators covered in the IEP.

“A major vulnerability of gas and oil generators … is that they have this funny fuel supply situation that it can be challenging to get their fuel during the times it matters most,” Roberts said. “FERC is basically compensating them for that, instead of having those generators bear that risk and pay those true costs.

“That really distorts the market.”

Roberts and Turner said the environmental groups are still considering next steps, including whether to file a request for rehearing.

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ERCOT: Normal Ops as Demand Hits Records

The ERCOT grid continues to operate under normal conditions, the grid operator said Monday, even as this summer’s peak demand is 4.3% higher than last summer’s.

The Texas grid operator recorded a new high for hourly peak demand average of 83.59 GW on Aug. 1. On Saturday, it recorded an unofficial high for weekend peak demand when load averaged 83.46 GW during the interval ending at 5 p.m.

In comparison, ERCOT set a then-record for peak demand of 80.15 GW last summer. Average hourly demand has exceeded that mark 90 times this summer, through Sunday.

ERCOT on Monday extended through Friday a weather watch, its fourth of the year, that it had issued for Sunday and Monday because of forecast higher temperatures and demand and the potential for lower reserves. It projected demand to break 86 GW on Monday and peak demands above 84 GW and higher through Friday.

Weather watches are issued when possible significant weather is expected along with high demand. They do not require public conservation. However, several utilities have been asking customers to reduce their usage.

“Grid conditions are expected to be normal,” ERCOT tweeted.

“Copy and paste. More heat and more sun,” Space City Weather said Friday in warning that Texas’ oppressive heat won’t break until next week at the earliest. “Any changes that take place in the weather pattern would not materialize before next weekend. So, buckle in.”

The sprawling Houston region finds itself underneath the brutal heat dome that is causing abnormal problems for vehicles. The National Weather Service issued excessive heat warnings for several counties in the region Friday as heat indexes soared as high as 113 degrees Fahrenheit.

In an email response to an interview request with ERCOT staff, the grid operator said it was not scheduling interviews and pointed to its new Texas Advisory and Notification System as a way to stay updated. (See “New Grid Notifications Added,” ERCOT Monitor Recommends New Market Design in Report.)

However, during a recent presentation last month in San Antonio to the Texas Public Power Association, ERCOT CEO Pablo Vegas said he is concerned about the grid’s long-term reliability, given the continued influx of wind, solar and storage resources. At the same time, he credited renewable energy with helping staff meet record demand.

“Peak demand kept growing,” Vegas said. “We’re in a place now where we are dependent upon renewables to meet demand.”

Solar resources produced a record 13.46 GW of energy Wednesday and, with wind, accounted for more than 31 GW of energy last month, according to GridStatus. ERCOT has more than 55 GW of solar and wind capacity and an additional 3.5 GW of battery storage.

Thermal outages have averaged around 6 GW in recent weeks. Still, prices settled as high as $2,886 at 5 p.m. Friday and didn’t drop from quadruple digits until after 8 p.m. Prices briefly reached $26.25 Sunday evening.

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FERC Sets Niagara Mohawk Transmission Rate for Hearings

FERC on Friday partially approved new rates from Niagara Mohawk for its portions of the AC Transmission Public Policy Transmission Project, which is designed to increase transfer capability across central east New York.

To pay for its share of the project (LS Power and the New York Power Authority are building most of it), the National Grid subsidiary proposed to include a new rate in its transmission service charge, called Rate Schedule 20.

The project, which is expected to be completed later this year, includes changes to some of Niagara Mohawk’s facilities. The firm plans to spend between $38 to $55 million upgrading a substation and reconductoring some transmission.

FERC accepted the firm’s cost-allocation proposal, which is in accordance with the 25/75 method used in NYISO where 75% of the costs go to zones that directly benefit from such lines and the last 25% is allocated across the entire market.

The much larger, $1.2 billion project mostly involves new infrastructure, but utilities retain the right to add any upgrades to their systems required by such projects. While FERC already had found that utilities had that right back in 2019, the NYISO tariff did not include language to implement generally, so the developers executed the “Segment A” agreement with Niagara Mohawk to make the required upgrades.

The cost-allocation method is in line with what FERC has approved for public policy lines, but the commission said the rest of the proposal has not been shown to be just and reasonable and set the matter for hearing procedures to gather more information.

The charges Niagara Mohawk proposed went into effect Aug. 5 but are subject to change and refunds based on the outcome of the hearings.

The utility said its proposed charges would lead to the same returns on all its other transmission investments under its transmission service charge (TSC). But since its Segment A charges were on top of those, the revenue from it would be credited to the standard TSC to avoid double counting.

FERC sent a deficiency letter to the utility seeking answers on its proposal, including whether ratepayers would continue to pay a return on investment once the facilities are fully depreciated.

Niagara Mohawk said its carry charge uses average systemwide cost ratemaking, and that leads to ratepayers paying a return as calculated over its useful life. The method is not precise, but the utility said tracking and calculating the costs of specific low-capital assets (like the $38 million it would spend on Segment A) can be administratively burdensome and lead to higher costs for ratepayers.

In the order Friday, FERC still questioned why the carrying charge included retirement obligations, which generally are not permissible in transmission rates. The utility said it would make another filing removing the retirement fees, but FERC said it was not clear whether that approach was appropriate.

The fact that the small segments Niagara Mohawk is building will be recovered using an average of its entire transmission base means that Segment A will never fully depreciate for rate purposes, and the utility failed to show it would ensure its costs are recovered in a systematic and rational manner.

While FERC set the matter for hearing, it encouraged a settlement and will wait to pick an administrative law judge for 45 days to give a chance for settlement talks to occur.

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Dominion Earnings Dinged by Issues with Mild Weather and Millstone

Dominion brought in $599 million in net income during the second quarter, despite mild weather and some unexpected outages at the Millstone Nuclear Plant in Connecticut, the firm reported Friday.

While Dominion reported on some of the recent issues its business faced, it also said it is wrapping up a business review, with plans to host an investor day by the end of September laying out a new long-term plan.

“I’m pleased with the progress we’re making toward delivering a compelling repositioning of our company to create maximum long-term value for shareholders, employees, customers and other stakeholders,” CEO Robert Blue said. “As I’ve said before, I’m as excited as ever for the future of our company.”

The second quarter had some of the mildest weather Dominion has seen in half a century, enough to cut into its earnings by 8 cents/share, said CFO Steven Ridge.

“With regard to Millstone, we experienced both an increase to the duration of a planned outage at Unit 2 and an extended, unplanned outage at Unit 3, which taken together amounted to an additional 8-cent headwind during the quarter,” Ridge said. “These outages are uncharacteristic for Millstone, which has a strong history as the largest zero-carbon electricity resource in New England, exemplary safety and reliable performance.”

Dominion recently hired Eric Carr from PSEG Nuclear as its new chief nuclear officer, and senior leadership are working on a review of the plant’s operating procedures to ensure it is reliable in the years to come, Ridge added.

Dominion Virginia Power last month implemented a rate cut for customers — with the average monthly bill dropping $14 — that was authorized as part of legislation passed earlier this year in Virginia that changed how the utility is regulated. (See Virginia Legislature Passes Utility Regulation Bills Backed by Dominion.)

The firm is seeking to spread out recent unrecovered fuel costs to avoid swamping that recent rate cut with a $15/month bill increase, Blue said.

The 2.6-GW Coastal Virginia Offshore Wind project remains on track and on budget, despite some of the issues other major offshore wind developments are running into.

“We continue to work closely with the Bureau of Ocean Energy Management and other stakeholders to support the project’s timeline,” Blue said. “BOEM received comments from all agencies on the draft of the final EIS [environmental impact statement] and is on schedule to deliver the final EIS by the end of September and the record of decision by the end of October. We continue to be encouraged by the administration’s timely processing of offshore wind projects.”

The Virginia State Corporation Commission recently approved an updated rider for the project, which will pay the utility $271 million for its efforts for a year. The project’s costs, excluding contingencies, are now 90% fixed, said Blue. Procurement processes are well underway, and the first monopoles should be delivered to the Port of Virginia by the end of the year.

“Despite trends we see elsewhere in the offshore wind market, we do not see anything that changes our confidence in delivering the project on time and on budget,” Blue said.

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In Contest for the West, Markets+ Gathers Momentum — and Skeptics

PORTLAND, Ore. —  It’s taken CAISO’s Western Energy Imbalance Market (WEIM) nearly nine years to expand to cover about 80% of the load in the Western Interconnection since being launched with PacifiCorp as its first participant.

But after a little more than a year of outreach, SPP is contesting much of that ground as it hustles to attract participants to Markets+, a fast-rising competitor that is drawing strong interest in the West just as CAISO moves to broaden the real-time WEIM into the long-awaited Extended Day-Ahead Market (EDAM).

The near-term issue for the region’s electric industry participants is which day-ahead market to choose, but their decisions likely will set the course for the eventual development of a Western RTO — or multiple RTOs.

“Once we move to a day-ahead market, that is a much larger footprint [of energy transactions]. It is much harder to transition from one day-ahead market to a separate [market] to get to an RTO/ISO,” Alex Swerzbin, director of transmission and markets for PNGC Power, a Portland-based generation and transmission cooperative, said during a July 14 meeting to kick off the Bonneville Power Administration’s (BPA) effort to choose a day-ahead market.

The deep interest in Markets+ was evident at a packed June meeting SPP hosted at BPA’s Portland headquarters.

Attending the two-day event were about 60 people representing utilities and other organizations from across the West, including Arizona Public Service, Black Hills Energy, BPA, Portland General Electric (PGE), Puget Sound Energy, Salt River Project, Tacoma Power, The Energy Authority, Renewable Northwest and Northwest Energy Coalition (NWEC), among others.

Notably absent was PacifiCorp, which already has committed to CAISO’s EDAM. The Portland-based utility controls more than 17,000 miles of transmission and 11,500 MW of generation in six states.

SPP officials running the meeting quickly got deep into the weeds, with the first day consisting of exhaustive lessons on organized market concepts (such as reliability unit commitment, co-optimization, settlements and virtual transactions), peppered by back-and-forth among participants about what they would seek in the early stages of a rollout. An outside observer could be excused for assuming Markets+ already was a going concern.

“I sent some information to CAISO saying, ‘Hey, you know, they’re so interested in this stuff that they’re considering virtuals as a starting proposition,’” Scott Miller, executive director of the Western Power Trading Forum, told RTO Insider in an interview shortly after the meetings.

“I think it has a lot of momentum,” said one meeting participant, who is not authorized to speak on behalf of their employer, a Western utility. “They may not beat WEIM to a day-ahead market, but they have more momentum for a Western RTO.”

“I think if there was one word to describe the Markets+ zeitgeist, it’s ‘momentum,’” Miller agreed.

“SPP is making a lot of progress,” he said. “Its stakeholder process has so charmed people that it’s added to that momentum.”

Not all attendees were caught up in the zeitgeist.

“I can’t see how we can have two markets in the West, particularly with PacifiCorp going with EDAM — and possibly PGE,” one attendee said on the sidelines. That attendee also pointed out that California is by far the region’s biggest player and that two competing markets would put “a big seam” in the West.

But as Miller pointed out, governance continues to be a stumbling block for CAISO’s effort to expand into a Western RTO. Under California law, the ISO’s governing board must be appointed by the state’s governor, an unacceptable political arrangement for other Western states that bristle at prospect of yielding control of their grids to the biggest state in the nation.

SPP presented to a packed meeting room at BPA’s Portland headquarters in June. | © RTO Insider LLC

California lawmakers have three times failed to pass bills authorizing an independent board, and yet another bill to address the issue has stalled in committee during the current session.

The governance problem took on a new sense of urgency last month when BPA launched its day-ahead market stakeholder process, committing to making a decision in the first quarter of next year.

“With EIM, we watched that market develop for several years before we even began our process of evaluating whether to join,” Russ Mantifel, BPA director of market initiatives, said at the July 14 kick-off meeting. “That is very much explicitly and intentionally not what Bonneville is doing here. Our intent here is to try to be proactive, as much as possible, both in the development of these markets, and in terms of making a decision at an earlier point, in order to position ourselves to join a market earlier in the lifecycle of these markets.”

In other words, with 15,000 miles of transmission and nearly 17,500 MW of generating capacity in the Northwest, BPA wants a seat at the head of the table for planning a market that likely will become the foundation for a full RTO. And for statutory reasons, CAISO’s state-run governance is a clear non-starter for the federally operated BPA.

Changing Expectations

But even if California lawmakers do act on governance, Miller said, that no longer may be the pivotal issue for BAs considering a commitment to CAISO. Market participants will seek deeper cultural shift in the ISO, one that would transform its staff-driven policy process into a stakeholder-driven one like those in other multi-state RTOs such as SPP, MISO and PJM.

“Now they’ve been exposed to a stakeholder process that the stakeholders run, and there still hasn’t been a stakeholder process [in CAISO] that is developed much differently, even in the context of the EIM,” Miller said. “So, CAISO hasn’t figured out that everybody’s expectations have changed, because they haven’t had a chance to yet because they’ve been so focused on writing their [EDAM] tariff — understandable — and trying to work with the legislature to see if they can get the governance change.”

But not every Western stakeholder is so charmed by SPP’s stakeholder process. Vijay Satyal, deputy director of Western energy markets at Western Resource Advocates (WRA), a Colorado-based environmental non-profit, thinks that process doesn’t give fair play to perspectives from outside the electric sector.

“They’re taking all the feedback of market participants, but the definition of market participants for SPP is the people who bring generation or load or both — that are utilities or customers,” Satyal said in an interview. “But in the Cal ISO process, anybody can bring any issues to the table and they get addressed, and then we get responses back.”

Satyal pointed out that the WEIM’s Regional Issues Forum (RIF), a stakeholder body he chaired last year, will exercise new authority under EDAM “to deliberate on trending issues before they become stakeholder proposals” in CAISO.

“Can you find me a RIF design in Markets+? There isn’t one conceived yet. That’s an area we want to push,” he said.

Satyal also offered a more generous take on CAISO’s existing governance, pointing out that the WEIM’s Governing Body consists of five members who are not selected by California’s governor but elected by stakeholder sector committees.

“That’s independence. That’s parallel authority. That has truly not yet been appreciated,” he said.

Furthermore, Satyal questioned the independence of the Markets+ Independent Panel (MIP), the body SPP established earlier this year as “the highest level of authority for decisions related to Markets+.” He noted that the five-member MIP includes two SPP board members: Steve Wright, a former BPA administrator, and John Cupparo, previously a senior executive with Berkshire Hathaway Energy and PacifiCorp. MIP decisions are, in turn, still subject to approval by the full SPP board.

Echoing Satyal’s concern was Fred Heutte, a senior policy associate with the Northwest Energy Coalition.

“Are we the only ones who are concerned about the fact that Markets+ has a process going forward where the Markets+ board and the SPP board, neither of which have had any voice whatsoever in their selection from the West, will be actually making the decisions in this initial phase?” Heutte said at BPA’s July 14 meeting. “Are there governance issues on both sides?”

The Matter of Seams

NWEC and WRA share another key concern: the impact of dividing the West into two separate markets that potentially would be cut through by a tangle of seams, depending on where various BAs choose to put themselves.

Both organizations have long been advocates for creating a single West-wide RTO that includes California to realize the full potential of sharing renewables across the region, in order to avoid curtailments and ensure a maximum reduction of greenhouse gas emissions. In that scenario, California’s daytime solar surpluses are seen as a complement to a potentially vast buildout of wind energy resources in other parts of the West, as well as the existing hydro resources in the Northwest.

“We want one large market in the West,” Satyal said. “There is tons of evidence that one large market will eliminate extra transaction costs, information management and different business practices where the different definitions exist in two markets.”

WPTF’s Miller said the seams issue could be managed by an enforceable agreement between the two markets.

“FERC would force whatever entities there are to have a joint operating agreement so that you could still sell either day-ahead or energy imbalance into each other’s systems,” he said.

But Heutte is skeptical about such an arrangement.

“The evidence from the East is very strong: that seams agreements are big, complicated things that never reach perfection, require a considerable amount of attention [and] include transaction costs and so forth,” he told BPA officials at their July meeting.

For Satyal, the economic case for a single RTO can be found in the 2021 state-led market study that estimated that the U.S. portion of the Western Interconnection could realize $2 billion in savings a year by 2030 if it adopted one market. The study’s two-market scenarios yielded considerably lower savings for the region as whole. (See Study Shows RTO Could Save West $2B Yearly by 2030.)

But results from a company-specific study, conducted by the Western Markets Exploratory Group (WMEG), paint a more complicated picture, industry sources have told RTO Insider. Those findings, released last month to individual entities, remain confidential, but the sources said they indicate California would be the biggest beneficiary of a single market, while others — but not all —actually could reap greater economic benefits from a two-market solution.

Individual utilities are expected to make those results public at their own discretion, with some required to disclose the data to their regulators before a public release, one source said. Andy Meyer, a public utility specialist with BPA, told attendees at the July 14 meeting that BPA might begin to “trickle out” its own study results starting in September, but he offered no guarantee.

“The state-led market study had a very thorough public review,” Heutte said at the meeting. “Given the nature and potential impact of this decision, we hope that Bonneville will put all your cards on the table, not just the ones that lead one way or the other, whichever way, because it’s really important for us to have a full understanding of what the consequences could be.”

Lifeline for CAISO?

With CAISO stymied on governance, it’s unclear whether the proposal last month by a group of Western utility commissioners to create an independent RTO based on the ISO’s operating framework will gain traction. (See Regulators Propose New Independent Western RTO.)

Under the plan, laid out in a July 14 letter to the chairs of the Western Interstate Energy Board (WIEB) and the Committee on Regional Electric Power Cooperation (CREPC), “a non-profit entity governed by representation from across the West would be formed” to contract for RTO services with CAISO, “including eventual assumption of the Extended Day-Ahead Market (EDAM) and the Energy Imbalance Market (EIM).”

The letter, signed by regulators from Arizona, California, New Mexico, Oregon and Washington, emphasized the transaction cost benefit of avoiding seams. Among the signatories was Washington Utilities and Transportation Commission member Anne Rendahl, who sits on the Markets+ State Committee and formerly chaired the WEIM’s Body of State Regulators. Rendahl declined to comment for this story, saying her commission may be asked to weigh in on the market proposals in future utility proceedings.

Washington Commissioner Ann Rendahl (front), a member of the Markets+ State Committee, at the June SPP meeting in Portland. | © RTO Insider LLC

The Western utility source who spoke to RTO Insider not for attribution said some industry participants outside California are skeptical that their interests would have equal footing with those of the most populous U.S. state under the arrangement.

That’s a view apparently shared by former WPTF head Gary Ackerman, who in the July 21 edition of his widely distributed Friday Burrito newsletter wrote: “An independent entity with a contractual link to the CAISO will not easily satisfy multi-state governance issues because of the lopsided weight of the CAISO load relative to all the other balancing authorities outside of the CAISO. Sure, it’s worth trying but expectations must be kept in check.”

“The more diversity, the fewer seams you have, the more effective [a market is] going to be — I can’t disagree with that,” BPA’s Mantifel said. “I think … the other reality is what it takes to get there, and sort of the sacrifices and compromises people are willing to make in order to achieve that, and whether that’s ultimately viable.”

SPP will hold meetings of its MIP and Markets+ Participants Executive Committee Aug. 8-9 in Portland. CAISO, along with the Balancing Authority of Northern California, NV Energy, PacifiCorp and Southern California Edison, will host an EDAM forum in Las Vegas on Aug. 30. BPA’s next set of day-ahead market meetings will be held at the agency’s Portland offices Sept. 11-12

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NEPOOL Approves ISO-NE DASI Proposal

NEPOOL approved a set of tariff changes related to ISO-NE’s Day-Ahead Ancillary Services Initiative (DASI) proposal at the August Participants Committee (PC) meeting, held virtually Thursday. The vote gave final NEPOOL approval of the DASI proposal, as the changes previously had been approved by the Market, Reliability and Transmission Committees.

“ISO New England has been working with stakeholders on … DASI for almost a year and we’re pleased NEPOOL approved DASI,” ISO-NE told RTO Insider in a statement following the vote. “We plan to prepare and file our DASI proposal with FERC in October of this year. Our plan is to have DASI integrated into New England’s wholesale markets by March 1, 2025.”

The DASI proposal is intended to procure and price ancillary services to ensure the reliability of the day-ahead market. (See ISO-NE Plans 2025 Launch for Day-Ahead Ancillary Services Initiative.)

In a July memo, ISO-NE wrote that the current Day-Ahead Energy Market, which clears just one energy product based on supply offers and demand bids, leaves gaps when unforeseen generation and infrastructure issues arise and when the market clears less supply than forecasted load.

“The DASI proposal creates a Day-Ahead Ancillary Services Market that, together with today’s Day-Ahead Energy Market, creates a single, jointly optimized Day-Ahead Market,” ISO-NE wrote. “These new day-ahead ancillary services will encourage reliable resource performance and prepare the system on a day-ahead timeframe with the flexibility needed to manage operational uncertainties.”

While approving the proposal, members of the Markets Committee have asked ISO-NE to reassess the strike price adder when more data is available following implementation. NEPOOL members also have raised concerns related to the DASI’s effects on peaker plants, as well as concerns about the elimination of the Forward Reserve Market (FRM). ISO-NE plans on removing the FRM when DASI takes effect in March 2025.

“The FRM is no longer necessary in its suite of markets, given the development of the new Day-Ahead Ancillary Services and in light of the significant transmission and market improvements that have been made over the last decade to relieve locational constraints and reward resource flexibility and performance,” ISO-NE said.

Also at the August PC meeting, the committee voted to approve ISO-NE’s proposed Order 881 compliance changes drafted in response to a June 15 FERC order (ER22-2357), as well as tariff changes related to FERC’s request for further compliance with Order 2222 (ER22-983). (See FERC Gives ISO-NE Homework on Order 2222, Order 881 Timelines Need Explaining, FERC Says.)