Page 43 – RTO Insider

August 26, 2024August 26, 2024

West Coast Truck Charging Corridor Wins $102M in Federal Funds

California ZEV infrastructure projects are receiving $150 million in federal funding, including $102 million for a tri-state charging network for medium- and heavy-duty trucks.

The money is from the Federal Highway Administration’s Charging and Fueling Infrastructure competitive grant program, which was created by the Bipartisan Infrastructure Law. U.S. Sen. Alex Padilla (D) announced the grant awards Aug. 26.

The bulk of the funding — $102.4 million — is going to the West Coast Truck Charging and Fueling Corridor project, a joint effort of the California, Oregon and Washington departments of transportation and the California Energy Commission (CEC). The corridor would stretch from border-to-border along the West Coast.

As described during a workshop last year, it would include 34 truck stations and five hydrogen fueling stations. The stations would be primarily along Interstate 5, with some locations on “key connecting corridors,” such as I-710 in the Los Angeles area. (See EV Charging Efforts Ramp up on West Coast.)

“To successfully meet California’s critical climate goals, we need to scale up our charging and fueling infrastructure up and down the state through transformative projects like the West Coast Truck Charging and Fueling Corridor project,” Padilla said in a statement.

The three state DOTs and the CEC applied for the Charging and Fueling Infrastructure grant funding in June 2023. California Democrats who supported the tri-state corridor described it as a $700 million project.

“This first-of-its-kind project will create a network of charging and hydrogen fueling stations and enable zero-emission trucking from Mexico to Canada, linking ports and major freight centers in California, Oregon and Washington,” Rep. Pete Aguilar (D) and other lawmakers said in a letter last year to Transportation Secretary Pete Buttigieg.

The West Coast Truck Charging and Fueling Corridor is seen as complementary to the $5 billion National Electric Vehicle Infrastructure (NEVI) formula program, which is also funded through the Infrastructure Investment and Jobs Act (IIJA). The NEVI program aims to establish EV charging networks throughout the U.S.

The IIJA provides $2.5 billion over five years for the Charging and Fueling Infrastructure program. The program funds projects on two tracks: charging and alternative fuel corridors and community charging.

Four other California projects are receiving Charging and Fueling Infrastructure funding, according to Padilla’s announcement. The awards are:

- $15.1 million to the Fort Independence Indian Community for EV charging along U.S. Route 395, a designated alternative fuel corridor.
- $15 million to the county and city of Los Angeles and the Los Angeles County Metropolitan Transportation Authority for 1,263 Level 2 chargers and eight DC fast chargers on curbside light poles, at community facilities and at park-and-ride lots.
- $14.1 million to the San Francisco Bay Area Rapid Transit (BART) District to install Level 2 chargers at all BART-managed parking facilities.
- $3.2 million to the Shingle Springs Band of Miwok Indians to install 70 EV charging stations on the reservation and along U.S. Route 50, a designated alternative fuel corridor.

August 26, 2024August 26, 2024

Cold Weather Standard Fails Second Ballot

A proposed reliability standard that would affect registered entities’ preparations for extreme hot or cold weather events was rejected by industry stakeholders for a second time last week, with some commenters criticizing the team behind the standard for failing to address their objections to the previous version.

The latest formal comment period for TPL-008-1 (Transmission system planning performance requirements for extreme temperature events) began July 16 and ended Aug. 22, slightly shorter than the standard 45 days. NERC’s Standards Committee authorized shortening the comment period at its meeting in March. (See NERC Standards Teams Pushing to Meet FERC Deadlines.) Stakeholders submitted votes over the last 10 days of the comment period.

A total of 314 industry stakeholders were part of the formal ballot pool, with 276 casting votes according to the industry segment they represent. Of these, 40 voted to approve the standard, while 200 voted against. One of the negative voters did not submit a comment, so it was not counted with the negative votes, while 36 stakeholders abstained.

After the results were weighted to account for segment participation, the standard received a vote of 18.17% in favor. A two-thirds majority is needed for approval. The final result represents a decline from the standard’s last ballot round that closed on May 3, when 37 voted for it and 216 against, for a weighted segment value of 18.69%.

Project 2023-07 developed TPL-008-1 in response to FERC’s Order 896, which directed NERC to submit a standard by December 2024 addressing performance concerns of transmission equipment in cold weather. The standard would require responsible entities to perform extreme temperature assessments based on benchmarks selected by them from a library maintained by the ERO for both extreme heat and extreme cold.

Entities also would be required to work with planning coordinators to develop a process for creating benchmark planning cases that include “seasonal and temperature dependent adjustments for load, generation, transmission and transfers to represent the selected benchmark temperature events.” In addition, responsible entities would have to develop corrective action plans when a benchmark planning case indicates their part of the grid cannot meet performance requirements for certain contingencies.

Criticisms of the standard in the first ballot included a lack of insight into the library of benchmarks to be used by entities when developing their extreme temperature assessments, and respondents in the second round asserted this still was not addressed. In a comment endorsed by several other stakeholders, Mark Gray of the Edison Electric Institute said the benchmark library “is being developed without industry review and approval, and as of this draft we continue to only have superficial insights into this library.”

In addition, Gray said, the latest draft “still does not contain any specific boundary limits that could guide responsible entities in their extreme weather assessments or otherwise limit what might be contained or added to the extreme weather event library, now or in the future.” Gray suggested adding language identifying data that entities could use — such as meteorological data for the past 20 years, or extreme temperature conditions with a specified probability within an entity’s area — while “intentionally [leaving] the specific boundaries to be set by the” drafting team.

Respondents also expressed dissatisfaction with the team’s changes to requirements R3 and R4, which outline how PCs are to coordinate with entities on the development of benchmark planning cases. John Brewer, writing on behalf of the National Energy Technology Laboratory, said the standard is unclear about who will decide which entities can participate in benchmark planning studies, and how conflicts will be resolved if PCs select different benchmark temperature events.

Jennifer Weber, writing for the Tennessee Valley Authority, recommended that designated study entities “be identified as part of the PC developed coordination process” in order to reduce confusion over how they are to be chosen. In addition, she argued that a section of R4 that “requires an increasingly more extreme scenario for purposes of a sensitivity analysis” is not credible, especially when applied to longer-term planning horizons when information about generation additions and retirements is not known.

The next comment and ballot period for TPL-008-1 has not been determined yet. However, the standard drafting team for Project 2023-07 is scheduled to meet Aug. 29 to consider the comments received in this round.

August 26, 2024August 27, 2024

PJM MRC/MC Briefs: Aug. 21, 2024

Stakeholders Reject Revised Cost of New Entry Inputs

VALLEY FORGE, Pa. — Consumers and electric distributors in PJM last week opposed a proposal to revise two financial parameters used to calculate the cost of new entry (CONE) input to the 2027/28 Base Residual Auction (BRA). (See “PJM Proposes Increased CONE Parameters,” PJM MRC Briefs: July 24, 2024.)

The measure would have increased the after-tax weighted average cost of capital (ATWACC) from 8.85% to 10% and set the bonus depreciation rate at 0% for the 2027/28 delivery year, rather than the 20% set through the Quadrennial Review. PJM and its consultant Brattle Group argued that the change would reflect higher costs typical PJM market participants face would face to borrow the capital necessary to construct the reference resource, a combined cycle generator.

The Markets and Reliability Committee rejected the increase during its Aug. 21 meeting, with only 57.46% sector-weighted support, short of the two-thirds threshold. End-use customers and electric distributors were each 93% opposed, while transmission and generation owners unanimously supported the proposal. The Other Suppliers sector supported the change with 75% support.

Greg Poulos, executive director of the Consumer Advocates of the PJM States, said each of the parameters feeding into the variable resource requirement (VRR) curve interacts with each other, and that pulling individual pieces out for after-the-fact modifications would undermine the purpose of the holistic Quadrennial Review.

He said consumer advocates would have concerns with the proposal regardless of the direction it shifted the parameters in, but they would be amplified when costs would increase at a time when capacity auction prices are reaching new highs. (See PJM Capacity Prices Spike 10-fold in 2025/26 Auction.)

Carl Johnson, of the PJM Public Power Coalition, said it’s unclear how complete the review that Brattle conducted was and whether its ATWACC values would accurately reflect developer costs given the spike in capacity prices. He also argued there’s a disconnect between the reference resource used in the Quadrennial Review and the resources that have been proposed for construction through the interconnection queue, which is largely composed of renewables and storage.

“It’s pretty clear that the reference resource doesn’t exist in the queue and making a change … that can only drive the price up doesn’t make sense,” he said.

John Rohrbach, of the Southern Maryland Electric Cooperative (SMECO), questioned whether PJM has considered pausing the proposal given how close the entire region came to clearing at point “a” on the VRR curve, which results in the price cap being reached at 1.5 times net CONE. Two regions, BGE and Dominion, hit the price cap in the auction because of insufficient internal generation and transmission constraints.

PJM’s Skyler Marzewski said the RTO’s focus is on ensuring that the parameters accurately reflect the costs to construct the reference resource and that the change would further that aim.

Calpine’s David “Scarp” Scarpignato said price signals should be determined through the balance of supply and demand — a balance that would be disrupted if stakeholders write auction rules with a target price in mind. An accurate CONE value prompts not only new generation development, but also encourages existing generation to remain in the market, potentially by investing in upgrades that bring new supply online, he said.

Stronger Know Your Customer Checks Endorsed

Stakeholders endorsed by acclamation a proposal to expand the data PJM collects when conducting due diligence checks on key leadership among its members through its Know Your Customer (KYC) process. The proposal was also endorsed by the Members Committee as part of its consent agenda. (See “Vote on Enhanced Know Your Customer Deferred,” PJM MRC Briefs: July 24, 2024.)

The proposal would expand the tariff definition of member principals subject to KYC to include beneficial owners, which are a “natural person who, directly or indirectly, alone or together with such person’s family members, owns, controls or holds with power to vote 10% or more of the outstanding securities in the participant.”

Members would be responsible for providing a list of principals meeting the new definition and supplying government-issued identifications. Individuals holding seats on boards of directors would also need to be identified under the changes. The effort is currently focused on PJM members that are not publicly traded, and therefore not required to report ownership information to the U.S. Securities and Exchange Commission.

Since the June 27 first read of the proposal, language was added to specify that ownership split across family members includes spouses, domestic partners, parents, children and siblings. The principal definition was also revised to add the phrase “corporate-level strategy” regarding the control individuals have over the member entity’s operations. The vote on the changes was originally scheduled for July 24, but that was deferred to allow stakeholders to review the changes more thoroughly.

The proposed definition of “principals” also was revised to add the phrase “corporate-level strategy” regarding the control individuals have over the member entity’s operations. PJM Assistant General Counsel Eric Scherling said the change is meant to address feedback that the definition could be too broad and capture staff with day-to-day operational control over assets.

Stakeholders Greenlight 2 New Energy Market Parameters for DR

The MRC endorsed by acclamation a proposal to add two energy market parameters for demand response resources in the day-ahead and real-time markets. The changes are set to go before the MC during its Sept. 25 meeting. (See “New Economic DR Parameters Discussed,” PJM MRC Briefs: July 24, 2024.)

The maximum down time would allow DR providers to define a “maximum number of continuous hours” for resource commitments, while the minimum down time would require a defined number of hours to pass between deployments.

The proposed Manual 11 language states that the new energy market parameters do not override any capacity market obligations on the same resource. Independent Market Monitor Joe Bowring repeatedly voiced concerns throughout the stakeholder process that without such language, it may not be clear to market participants that they would be subject to Capacity Performance penalties if they followed their energy parameters and curtailed instead of remaining online according to a capacity deployment.

During the Aug. 21 meeting, Bowring said the proposal would improve DR flexibility and more accurately reflect its capability in the PJM markets, but he argued it should be one small change in a larger consideration of DR’s role in the market. Bowring noted DR’s inability to be dispatched on a nodal basis, which he argued is critical for it to be an effective resource.

PJM Discusses 2025/26 Auction Results

Changes to planning parameters and a redesign of components of the capacity market drafted through the Critical Issue Fast Path (CIFP) process last year were driving factors in the increase of capacity prices in the 2025/26 BRA, according to an analysis the RTO presented to the MRC. (See PJM Market Participants React to Spike in Capacity Prices.)

PJM’s Tim Horger said the revised planning parameters led to the installed reserve margin (IRM) increasing because of load forecast uncertainty, the price cap being redefined from 1.5 times net CONE to gross CONE, a decrease in net CONE from $293/MW-day to $229, and the peak load forecast increasing by 3,243 MW.

PJM’s Patricio Rocha Garrido said part of the impetus behind the planning changes was to identify and incorporate potential correlated outage into risk modeling. Following the December 2022 winter storm (“Elliott”), PJM also abandoned its practice of excluding the 2014 polar vortex data from risk modeling.

Dominion Energy participating in the Reliability Pricing Model, rather than using the fixed resource requirement (FRR) alternative, also pushed supply and demand closer together, Horger said.

The most significant CIFP changes were a requirement that generation owners planning to complete projects ahead of the start of the 2025/26 delivery year submit a binding notice of intent in order to offer into the auction; reliability risk modeling that captured more extreme weather, particularly winter storms; and marginal effective load-carrying capability (ELCC) for resource accreditation.

The results of the changes were lower accreditation for many resources, meaning they could offer less supply, and more capacity being required to meet reserve margins. Horger said only 43 MW of capacity did not clear in the rest-of-RTO region, and the auction cleared 660 MW over the reliability requirement, compared to 7,754 MW in the prior auction.

“Pretty much everyone who offered in the auction cleared,” he said.

PJM Vice President of Market Design and Economics Adam Keech said most of the factors tightening supply and demand would have occurred regardless of the CIFP changes. About 16 GW of excess unforced capacity (UCAP) was available in the 2024/25 auction, of which 12 GW were lost because of generation deactivations, higher expected peak loads and the increased IRM. The CIFP changes are credited with reducing available UCAP by a further 2.7 GW.

“There’s a lot of moving parts before we even get there that have an impact on the supply and demand balance on the system,” he said.

Keech defined excess capacity as the total supply offered into the auction minus the reliability requirement. The UCAP values in the analysis were measured according to the rules for the 2024/25 auction.

He said some of those dynamics are on track to continue in the 2026/27 BRA, for which the load forecast and reserve requirement are set to increase. That auction will be the first to use a combined cycle unit as the reference resource, which carries a gross CONE 55% higher than the combustion turbine used in past auctions. A higher CONE value could lead to the price cap also being higher.

“We’ve got a tight system and one where the demand for capacity is going up,” he said.

Bruce Campbell, of Campbell Energy Advisors, said the CIFP changes led to an administrative degradation of DR capability through the implementation of marginal ELCC accreditation, the effect of which remains unclear to many stakeholders a year after an endorsement vote on the approach. In the future, he said the Board of Managers should hold PJM accountable for providing more transparency regarding capacity market changes to reverse a history of DR being treated as an afterthought in market design.

PJM CEO Manu Asthana said DR played a critical role in ensuring that the RTO met its reliability requirement in the 2025/26 auction.

Susan Bruce, of the PJM Industrial Customer Coalition, said there is little time for new generation to come online ahead of the 2026/27 auction, which is scheduled to be conducted in December. Given that short timeline, she said DR could play an especially large role if market rules recognize its full value, especially for industrial loads in the winter that are less sensitive to weather than residential load.

Bowring argued DR ELCC values are overstated because of assumptions about performance that are not supported by the data. He said DR is playing an increasingly pivotal role in the capacity auction — meaning that the auction would not have cleared reliably without DR — and argued that the exercise of market power by DR is correspondingly becoming a growing concern that will need addressing.

He said the Monitor is planning to publish its own analysis on the 2025/26 auction as it does not agree with all the conclusions PJM has drawn, including the assertion that the prices primarily reflected changes in supply/demand fundamentals.

Bruce said one of the goals underlying the CIFP changes was to create a market signal that would slow thermal deactivations, but one of the major causes of the high prices in the 2025/26 auction was coal, gas and oil deactivations.

Keech said some resources were already planning to retire, while others are in a stage of their deactivation that they still have an ability to re-enter the market.

PJM Proposes Sunsetting Electric Gas Coordination Senior Task Force

PJM brought a proposal to close the Electric Gas Coordination Senior Task Force (EGCSTF) and continue efforts to harmonize how PJM’s markets interact with gas supply through existing working groups, such as the Reserve Certainty Senior Task Force (RCSTF) and a possible new subcommittee with more flexibility in its scope.

Susan McGill, PJM senior manager of strategic initiatives and chair of the task force, said the group’s working areas were completed when stakeholders endorsed a proposal to align day-ahead energy commitment cycles with the daily gas nomination deadlines in order to give gas generators more certainty on when they should procure fuel. (See “Stakeholders Endorse Revised Proposal to Align Energy, Gas Schedules,” PJM MRC/MC Briefs: June 27, 2024.)

The task force was envisioned to spend a year working toward proposals, a timeline that was extended after Elliott.

Hourly Notification Times

PJM’s Joe Ciabattoni presented proposed revisions to the tariff, Operating Agreement and Manual 11 to use hourly notification times when considering unit commitment in the day-ahead market.

Hourly notification times can only be used in the real-time market, leading to discrepancies in reserve eligibility and capability when resources are offline, Ciabattoni said.

The RTO intends to bring the proposal for endorsement votes during the Sept. 25 MRC and MC meetings, with a targeted implementation date on Dec. 1.

First Reads on Several Manual Revision Packages

PJM presented first reads on three sets of revisions to Manual 6: Financial Transmission Rights, Manual 14B: PJM Region Transmission Planning Process and Manual 15: Cost Development Guidelines.

The Manual 6 revisions would add a deadline for auction revenue right (ARR) trades on noon ET of the business day before the relevant auction opening and a deadline for relinquish requests on noon of the business day prior to the opening of stage 2 of the annual ARR allocation.

The revisions also would disqualify transmission customers with firm services to charge energy storage or hybrid resources from receiving an allocation of ARRs to conform with FERC orders (ER19-469 and ER22-1420). (See RTOs Move Closer to Full Order 841 Implementation.)

The changes to Manual 14B would revise the inputs to the light-load case that the RTO uses in its Regional Transmission Expansion Plan load forecast. (See “Manual 14B Revisions Include Change to Light Load Model,” PJM PC/TEAC Briefs: Aug. 6, 2024.)

The case is meant to reflect load growth with flat profiles unaffected by weather and season by scaling load down to 50% of the summer forecast peak using bus-level data provided by transmission owners. PJM’s Stan Sliwa said the growth of non-scaling load, such as data centers, is changing how load shifts over the course of the year. The revisions would remove non-scalable load from the light-load case.

The Manual 14B changes would also expand the NERC Transmission Planning standards examined during generator deliverability analysis to match current practice, updating the system operating limit definition and adding new standards created by the ERO.

The Manual 15 revisions are aimed at correcting formulas throughout the manual and would remove a table displaying variable operations and maintenance (VOM) costs. Pulling the table from the manual is intended to avoid giving the impression that the values are fixed; the manual would instead point to the PJM website, where the VOM costs are updated annually to account for inflation. (See “Several Corrections to Formulas Included in Proposed Manual 15 Revisions,” PJM MIC Briefs: Aug. 7, 2024.)

August 26, 2024

Single Western Market Best for Reliability Needs, Panelists Say

A single Western market is one of the safest bets to address the region’s reliability and cost issues in the face of extreme weather events, proponents of the West-Wide Governance Pathways Initiative said during a panel discussion Aug. 22.

Representatives from CAISO, Western Freedom and California Strategies participated in a webinar hosted by the Climate and Energy Policy Program at the Stanford Woods Institute for the Environment. The panelists discussed the findings of a new report issued by the institute, which found, among other things, that expanding cooperation in the West through a single market footprint could reduce the number of hours at risk for outages by as much as 40% during a monthlong, high-stress condition.

The report examines the reliability impacts of three market configurations: two in which the Western Interconnection is divided into two separate RTOs with different footprints and one consisting of a single RTO comprising 11 Western U.S. states and the Canadian provinces of Alberta and British Columbia.

It comes as the Pathways Initiative works to advance efforts to grant the Western Energy Markets (WEM) Governing Body increased authority over CAISO’s Western Energy Imbalance Market (WEIM) and Extended Day-Ahead Market (EDAM). The initiative also plans to establish an independent Western “regional organization” (RO) that would eventually assume more of the ISO’s market functions, including exercising sole authority over decisions related to the two interstate markets. (See California Energy Officials Pitch Pathways Plan to State Senators.)

Stacey Crowley, CAISO vice president of external affairs, argued Aug. 22 that recent events, such as the Jan. 12-16 cold snap, showcased the WEIM’s ability to find energy and transfer it to where it was needed in the West. (See WEIM Q1 Benefits Report Adds to NW Cold Snap Debate.)

However, “there is deeper coordination that could occur to assist with reliability in the long term, either long-term transmission planning and resource planning that recognizes the benefits of that large geographic footprint and the diverse resources that we have,” Crowley added.

Marybel Batjer, partner at California Strategies LLC and former president of the California Public Utilities Commission, said an RTO is one of the few tools available to address increasing transmission costs and wildfire mitigation efforts in the West.

“It’s already been proven with the EIM that we have a cost savings throughout the West, and it’s only by these regionalized efforts, if you will, that we can perhaps hold down the ever-increasing costs borne almost entirely by the ratepayer,” Batjer said.

With states having different priorities, the initiative’s Launch Committee has worked hard to keep the Pathways proposal nonpolitical, according to Kathleen Staks, executive director of Western Freedom and co-chair of the Pathways Initiative. Staks noted that the committee has strived to build a governance structure that “respects each individual state’s ability to set its own energy priorities and its own energy goals.”

Staks said reliability and affordability are the two primary nonpolitical drivers of the initiative.

“Keeping the power going and having a reliable system is fundamental to survival and to our economy,” Staks said. “And so I think that is something that really is a transcending priority across all the 11 Western states.”

Staks also pointed out that current regionalization efforts have attracted interest from data centers and other tech businesses with aggressive clean energy goals to set up shop in the West.

“They need to be able to access a much bigger footprint of zero-carbon resources than they are probably able to get from any one sort of small utility footprint,” Staks said. “So, for them, this is a really important part of the reliability, affordability and sustainability. It really hits all three of those goals.”

August 26, 2024

Proposal to Limit Participation at New Hampshire PUC Spurs Backlash

New rules proposed by the New Hampshire Public Utilities Commission would “unduly exclude” companies and organizations from participating in its proceedings, according to a coalition of power generators, consumer advocates and environmental organizations.

The comments came in response to a pair of initial proposals that would overhaul how the commission undertakes proceedings. The proposals are intended to codify the delegation of responsibilities between the PUC and the state’s Department of Energy, which was established in 2021 (DRM 24-085, DRM 24-086). (See NH Poised to Merge Utility Regulator into New Dept. of Energy.)

The proposals drew widespread backlash for changes that appear to limit which organizations can participate in PUC proceedings. The concerns stem from how the new proposed rules would define an organization’s “standing” to participate in a proceeding. The groups wrote that the proposed definition — which limits standing to parties that face “direct injury” as the result of the proceeding — is “far too restrictive.”

“The proposed rules might bar many parties, like those in this joint letter, with clear, substantial interests; legitimate grounds for intervening; expertise on certain matters before the commission; and a long history of constructive participation in commission proceedings,” the groups wrote.

The changes could conflict with New Hampshire laws regarding intervention in utility proceedings, the coalition wrote. It proposed eliminating the definition of standing from the new rules, arguing that it is unnecessary.

“Because the proposed rules would drastically change the nature of commission proceedings, we urge the commission to engage in a more deliberative process before taking any action to finalize these rules,” the groups added.

The New England Power Generators Association (NEPGA) highlighted the “extraordinary coalition” that signed the joint comments, including the Conservation Law Foundation, the Consumer Energy Alliance and the Community Power Coalition of New Hampshire.

“This is pretty simple right vs. wrong in how these regulatory dockets should function,” NEPGA wrote in a statement. “We hope the New Hampshire PUC recognizes the error of this proposal and rethinks how dockets are dealt with for the benefit of all.”

The New Hampshire Office of the Consumer Advocate (OCA) raised similar concerns in comments submitted to the PUC in July, writing that standing to participate in a proceeding “should simply not be defined in the commission’s rules” and that the definition included “is vastly too narrow.”

The OCA also expressed concern that the proposed rules “seek to appropriate a significant degree of policymaking authority to the commission that rightfully belongs to the Department [of Energy].” The proposed changes would shift the PUC toward “a paradigm in which the tribunal and its presiding officer are not simply neutral decisionmakers but are also assuming a prosecutorial role,” it said. Increasing the role of the PUC in the discovery and development of evidence could undermine its statutory role as a neutral arbiter while deciding cases, it added.

The office also urged the commission to use the rulemaking as an opportunity to promote transparency in public utility proceedings, arguing that information submitted by utilities in PUC proceedings is frequently treated with a broad stamp of confidentiality.

“We respectfully suggest a reexamination of the assumptions underlying confidential treatment of commission records, a subject of particular interest to the OCA because our enabling statute requires us to maintain the confidentiality of all information so designated by the commission in adjudicative proceedings,” the office wrote.

Concerns about the rulemaking appear to be shared by the state’s utilities. At a public hearing on the proposal in July — which was not attended by the PUC commissioners, according to testimony by the OCA — Eversource Energy requested a “a more collaborative and participatory process.”

“The changes proposed by the commission are substantial and extensive,” said David Wiesner, Eversource senior counsel. “Some are long overdue and welcomed logistical updates to account for the creation of the Department of Energy, while others are significant revisions or entirely new procedures altogether that would change core regulatory processes that currently exist.”

A representative of Unitil echoed these comments and added that the rules limiting who can participate in proceedings appear to be “essentially unconstitutional.”

August 26, 2024August 30, 2024

Court Sides with PG&E in Long-running San Francisco Dispute

The D.C. Circuit Court of Appeals on Aug. 23 ruled in favor of Pacific Gas and Electric (PG&E) in the latest twist in a nearly two-decade dispute with San Francisco over a distribution system wheeling contract between the two entities (No. 23-1041).

At issue in the case, which was remanded back to FERC, is PG&E’s application of its wholesale distribution tariff (WDT) to the municipal electricity customers of the San Francisco Public Utilities Commission (SFPUC), a city-operated utility. (See FERC Refuses Rehearing of PG&E-San Francisco Dispute.)

SFPUC, which operates a hydroelectric project in California’s Hetch Hetchy Valley, supplies electricity to individual consumers, schools, public housing tenants, libraries and municipal departments using the distribution system PG&E owns and operates in San Francisco — making it both a customer and competitor of PG&E.

Since 2014, San Francisco has argued to FERC that PG&E has unreasonably denied distribution to many of SFPUC’s approximately 2,200 metered delivery points, under section 212(h) of the Federal Power Act.

That section prohibits forcing a utility such as PG&E to deliver another utility’s power through its distribution lines, but it also exempts cities and counties where “such entity was providing electric service to such ultimate consumer” on the date the subsection was enacted: Oct. 24, 1992.

PG&E has countered that it wasn’t obligated to provide service to any delivery point where SFPUC didn’t provide service as of October 1992.

In 2019, FERC issued an order disagreeing with an initial decision by a FERC administrative law judge (ALJ) who had supported San Francisco’s argument by citing the commission’s November 2001 orders under Suffolk County Electric Agency (96 FERC ¶ 61,349). In that set of decisions, FERC said section 212(h) grandfathered classes of customers, not individual customers at specific delivery points.

In overruling the ALJ, FERC’s 2019 order found Suffolk to be inapplicable to the San Francisco dispute and said PG&E had not been unreasonable in denying service to some SFPUC customers. The commission found that PG&E’s “point of delivery” approach to determining which customers were entitled to service under the WDT was just.

In January 2022, the D.C. Circuit reversed FERC’s 2019 ruling, sending the case back to the commission on remand after finding that the WDT’s reference to “points of delivery” does not imply that only specific points of delivery may be grandfathered under the agreement.

In its October 2022 order on remand, the commission followed the court’s direction and agreed with the city that FERC’s precedent didn’t limit grandfathering to a fixed location, concluding that any of San Francisco’s load associated with “customer classes” being served on Oct. 24, 1992, were entitled to grandfathered service under the WDT.

The commission in March 2023 rejected PG&E’s request for a rehearing (EL15-3).

‘Ultimate Consumer’

But the D.C. Circuit’s Aug. 23 ruling vacated the October 2022 order and again remanded the case back to FERC.

PG&E’s petition to the court focused on the FPA’s definition of an “ultimate consumer” and the risks to PG&E of FERC conflating that concept with “customer class.” The utility argued that the commission’s October 2022 ruling would force it to use its facilities “to serve a potentially unlimited number of [future such] customers” and that it must “incur … costs to acquire and maintain the facilities necessary to serve those customers.”

PG&E further contended that FERC’s “broad class-based” interpretation of the WDT’s grandfathering clause could not be reconciled with the plain meaning of “ultimate consumer” under the FPA.

The court agreed, finding that FERC “cannot order PG&E to wheel electricity to ‘an ultimate consumer’ of SFPUC unless SFPUC ‘was providing electric service to such ultimate consumer on Oct. 24, 1992.”

“Considering the text and structure of section 824k(h)(2), as well as the broader statutory context, we conclude that ‘ultimate consumer’ does not refer to an atextual class or group of consumers,” the court found. “FERC’s orders are therefore contrary to law.”

FERC “must apply the plain meaning of [FPA] section 824k(h)(2) consistent with this opinion and determine which of SFPUC’s consumers qualify for wheeled service under” the WDT, it concluded.

August 26, 2024August 27, 2024

PJM Stakeholders Endorse Elimination of EE Participation in Capacity Market

VALLEY FORGE, Pa. — The PJM Markets and Reliability Committee voted to eliminate energy efficiency from the capacity construct, adopting a proposal from the Independent Market Monitor during its Aug. 21 meeting. (See Stakeholders Endorse PJM EE Measurement and Verification Proposal.)

The proposal would eliminate all references to EE from the governing documents and manuals, excising EE from the market rules. It was endorsed with 70.9% sector-weighted support.

Stakeholders rejected three proposals, including a Market Implementation Committee endorsed package that would tighten the measurement and verification (M&V) process and require a causal link between capacity market revenues and the viability of an EE project. Two alternatives offered by Exelon and the New Jersey and Illinois consumer advocates also were voted down.

The Monitor’s proposal was offered as an alternative by Paul Sotkiewicz, president of E-cubed Policy Associates, representing J-Power USA. During the Aug. 7 MIC meeting, he stated that permitting energy efficiency to continue offering into capacity auctions runs afoul of the Reliability Assurance Agreement (RAA), which permits its participation only as long as EE is not captured in the load forecast. He argued that EE participation effectively asks states without their own programs to subsidize EE programs offered by other states. During the MIC meeting, PJM’s Tim Horger stated the RTO could support the Monitor’s proposal as well as its own.

Monitor Joe Bowring said the proposal simply would remove governing document and manual references to EE, reflecting that PJM has recognized EE is included in the peak load forecast since 2017 and EE is not a capacity resource under the tariff as a result.

“Rather than being a capacity resource, it is fact that under the existing rules EE is a subsidy paid for by customers and has cost customers half a billion dollars to date. It is not PJM’s role to decide to subsidize EE as a matter of policy,” Bowring said.

The Monitor has filed two complaints with FERC arguing that PJM’s EE rules are in violation of its tariff and against several EE providers it contends have not met the capacity market participation requirements. Bowring said if the Monitor’s M&V proposal is filed and accepted by FERC, he would drop his complaint against PJM. However, the complaint against private EE providers will stand. (See Monitor Alleges EE Resources Ineligible to Participate in PJM Capacity Market.)

Ahead of the same-day Members Committee endorsement vote on the Monitor proposal, CPower’s Ken Schisler called on stakeholders to approach the outright elimination of a resource class to be done in a cautious and deliberative manner. He objected to substituting the rejected MIC package with the Monitor’s proposal on the MC agenda and questioned whether there was an adequate quorum for the vote as discussion stretched past the normal workday.

A motion made by Sotkiewicz to suspend the rules and add the Monitor’s proposal to the agenda received 67.8% sector-weighted support. He argued the consideration given to the procedural objections ran contrary to precedent in the stakeholder process.

Schisler said such a significant vote should not be made under such circumstances and without corresponding revisions to the governing documents being available. After his comments, PJM presented redlines drafted during the meeting that removed sections detailing how EE functions in the capacity market.

“This is a very serious decision. We don’t even have redlines before us and we’re doing it under a suspension of rules,” Schisler said.

The strongest support for the proposal at the MC came from the electric distributor and generation owner sectors, with 88.9% and 86.7% support, respectively. Three-quarters of transmission owners supported the changes, as did two-thirds of other suppliers. Only end-use customers were in opposition, with 16.7% support coming from the Indiana and Kentucky consumer advocates.

PJM Proposal Would Tighten M&V Rules

The MIC-endorsed proposal, which was sponsored by PJM, would have required contracts with end-use consumers demonstrating the EE provider holds the capacity rights to energy savings associated with a project, removed EE from the Capacity Performance construct and required a causal link showing a project was conducted exclusively because of capacity market revenues.

Schisler said he agrees with PJM that EE providers should own the exclusive capacity rights to any savings they offer into the market — a requirement he said already exists in the status quo rules. Instead, he argued the proposal is driven by an ideological goal of eliminating EE as a resource class. He said no EE resources would be able to meet the new requirements.

On the causal requirement, Schisler compared EE participation in capacity markets to the wholesale blood market that allows a needed supply to move between hospitals. The reasons individuals donate don’t necessarily line up with market revenues and there is no requirement it be demonstrated a donation was made to receive wholesale revenues to be paid.

He also pushed back against a component of PJM’s proposal that would curtail the period an EE project could be offered as capacity from four years to one, which he said would concentrate collateralization, auditing and M&V costs on a single year and further degrade the viability of EE programs.

PJM’s Pete Langbein responded that PJM’s focus is on identifying the benefit consumers receive when paying for EE resources and ensuring that value is being realized.

“I don’t think that’s an ideology thing. I think that’s just a principle we should agree on,” he said.

Langbein justified the shortened eligibility period by stating there could be a one-year lag in energy savings resulting in a corresponding decline in capacity costs, after which he said consumers participating in an EE program would be benefiting twice.

Greg Poulos, executive director of the Consumer Advocates of the PJM States (CAPS), said the MIC proposal would mark a step backward in EE participation and innovation, effectively removing a way for consumers to respond to capacity costs at a time when those costs are increasing rapidly. (See PJM Capacity Prices Spike 10-fold in 2025/26 Auction.)

Exelon Seeks Differentiation Between State and Third-Party EE

Exelon’s Alex Stern sought to add a friendly amendment to the MIC endorsed package that would have added language to PJM’s definition of an EE resource to differentiate between state-sponsored programs administered by utilities and third-party programs. The changes assert that utility EE programs have M&V responsibilities to their states in addition to the capacity market participation requirements.

Stern said it’s unlikely any utility EE programs would meet PJM’s causality threshold. However, he said the distinction remains significant given there are five pending complaints regarding how EE participates in PJM’s markets.

He said the amendment would not take away from PJM’s proposal and the intention is to address something implicit in PJM’s governing documents and make that explicit: that utility EE has a different role than third-party programs and they have their own cost recovery and M&V requirements to their states. It also would recognize the utility programs would continue irrespective of how the resource class is treated in the PJM markets.

The Exelon friendly amendment was objected to by Luke Fishback, of Affirmed Energy, who said it would be discriminatory and contrary to past FERC decisions. He argued there is no purpose to making the amendments if it’s recognized that no utility EE would be eligible under the proposed rules.

Once Affirmed objected to Exelon’s amendment as “friendly,” Stern offered the PJM package plus the Exelon amendment to differentiate state EE programs from EE offered in the market by third parties, as an alternative proposal. The MRC also rejected the MIC-approved package with the Exelon amendment included. Stern succeeded in having the Exelon amendment incorporated into the proposal offered by the consumer advocates, but it was rejected for incorporation into the Monitor’s proposal by Sotkiewicz.

Consumer Advocate Proposal Seeks Elimination of Addback

Acting on behalf of the New Jersey Division of Rate Counsel, Poulos introduced an alternative built off an earlier package drafted by CPower during the MIC process. It would revise the language to exclude EE resources from CP penalties and bonuses. It also would eliminate the addback, a process that adds the amount of EE that clears in an auction to the corresponding load forecast, increasing the amount of capacity that must be procured through the auction.

Poulos said the addback has segmented EE from the rest of the Reliability Pricing Model, preventing it from acting as a reliability resource and creating an uplift payment system through the addback. By relying on EE forecast data from the Energy Information Administration, he said PJM’s forecast accounts only for overall trends in adoption of more efficient devices while missing EE prompted by capacity market revenues.

Contending that market-driven EE is not counted in PJM’s load forecast, he said eliminating the addback would not result in consumers participating in EE programs benefiting twice from lower capacity costs and RPM revenues. The double counting concern was the impetus for establishing the addback after PJM incorporated EIA Annual Energy Outlook data into the load forecast in 2015. (See Model Change Results in Lower Load Forecast for PJM.)

David “Scarp” Scarpignato said PJM has presented backcasts of the EIA-derived EE forecasts during past Load Analysis Subcommittee (LAS) meetings, which showed the forecast has been accurate in past years. If market-driven EE is not being counted, he said the 2025/26 delivery year forecast will undercount load by about 6 GW, the approximate amount of EE that did not participate in the 2025/26 Base Residual Auction (BRA) due to a guidance document PJM released that changed the participation requirements.

Bowring and PJM Executive Vice President of Market Services & Strategy Stu Bresler said removing the addback without any additional governing document language detailing how EE would be compensated would remove the payment mechanism for the resource class, effectively removing them from the market.

Bresler said the load forecast is built from expectations of technology adoption that builds load from the ground up. It does not forecast the load as if customers are using inefficient appliances and then do a top-down adjustment for adoption of more efficient technology. The only way EE would be eligible to participate in the capacity market without the addback would be if they could demonstrate the load reduction they’re claiming is not in the forecast, a prospect he said he does not believe could be done under existing language.

For those supporting the removal of EE from the capacity market, Bowring said the consumer advocate proposal is too convoluted of a way to arrive at the same result as the Monitor’s proposal.

Schisler disputed the interpretation offered by Bresler and Bowring, saying nothing exists in the manuals stating the forecast captures all EE, and the implication that the addback removal by definition removes EE from the forecast is a false premise.

August 26, 2024August 26, 2024

ERCOT Board of Directors Briefs: Aug. 19-20, 2024

Bifurcated NOGRR245 Approved; 2nd Change to Add Details

ERCOT’s long-delayed and now-bifurcated rule change to the Nodal Operating Guide (NOGRR245) that imposes voltage ride-through requirements on inverter-based resources (IBRs) has been partly approved, but much work remains to hammer out a final agreement on its decoupled section.

The grid operator’s Board of Directors endorsed the change Aug. 20, as recommended by the Reliability and Markets Committee and as revised by ERCOT comments. The board also directed that a second, high-priority NOGRR be developed that clarifies the bifurcated hardware modification requirements and exemption standards and processes.

The subsequent rule change will address more details around NOGRR245’s exemption process, including the ability to supplement information if a resource entity makes an exemption request by April 1, 2025; appropriate criteria for some level of hardware upgrades for a “vintage” resource to meet relevant ride-through performance requirements or whether it be granted an exemption; and details about the reliability assessment process.

Under NOGRR245, new IBRs that come online after July 24 must meet relevant parts of the Institute of Electrical and Electronics Engineers’ standard for IBRs interconnecting with the grid by maximizing software, firmware, settings and parameterization to the “fullest extent equipment allows” by 2026. Resource entities must submit by April 1, 2025, a notice of intent to request an exemption if they cannot meet the new requirements. Resources that can meet the new requirements, but not by the deadline, must request an extension.

The board’s approval ends a process that began last year and resulted in months of negotiations between staff and stakeholders representing the Technical Advisory Committee. The committee endorsed NOGRR245 in June with potential modifications that would not become effective until April 2025. (See ERCOT TAC Endorses Rule for Inverter-based Resources.)

The directors later that month tabled the measure to give staff and stakeholders additional time to agree on the rule change by bifurcating or decoupling parts of the exemptions and extension process for legacy assets unable to meet ride-through requirements. (See “NOGRR245 Bifurcated, Delayed,” ERCOT Board of Directors Briefs: June 17-18, 2024.)

“I’m here today to say that we do have a version … the joint commenters do not object to,” ERCOT Assistant General Counsel Andy Gallo triumphantly told the R&M Committee on Aug. 19. He said the goal was to retain the near-term benefits in the TAC-approved version while removing the details and criteria surrounding the exemption process and moving them into the subsequent NOGRR.

ERCOT first filed comments Aug. 12 to clarify and address the joint commenters’ concerns and set the stage for the measure’s bifurcation. Four days later, it filed additional comments that introduce a “notice of intent to request an exemption” concept into the exemption process and make clarifying revisions related to memory upgrades when maximizing equipment ride-through capabilities.

The joint commenters, comprising primarily renewable developers and consumer interests, said they did not oppose ERCOT’s comments. However, they did note key concerns that could affect the development and implementation of new ride-through standards in the second NOGRR.

“I think it’s a very fast timeline. It will take a lot of work to get to consensus,” TAC Chair Caitlin Smith, with Jupiter Power, warned the board. “We’ve been discussing NOGRR245 at TAC for almost a year. We’re looking at the main issues of defining the process of exemptions and how requirements for hardware will apply after maximization. I think there’s some fundamental disagreements on applying the reliability risk systemwide or on a resource.”

Texas PUC Chair Thomas Gleeson | ERCOT

“We felt like fundamentally, the principles are still the same that were in the June TAC recommended version,” General Counsel Chad Seely said. “The main issue raised by the joint commenters was kind of the bifurcation process and the hardware issue that we have decoupled, and we’ll have another opportunity to work with the stakeholders through the subsequent NOGRR.”

ERCOT is targeting February for the board’s consideration. It wants to meet the April 1 deadline for submitting the notices requesting exemptions.

Following the board vote, Thomas Gleeson, chair of the Texas Public Utility Commission, said regulators have pushed some “larger policy discussions” to ERCOT that are “more appropriately done at the commission.”

“I think [NOGRR]245, the parts that have been severed out, are [a] good case for this,” Gleeson said. “I’m fine with ERCOT moving forward with urgent status on this, but I think we should have a discussion at the commission [whether] this is more suitable to be done through a rulemaking. And so I don’t have the answers to this at this time, but I think we need to have those discussions.”

Gleeson said he has had sideline discussions with ERCOT leadership, several board members, PUC executive staff and TAC leadership to determine where those policy conversations should be held. He said he will look to stakeholders and others to “help inform where we end on this.”

New Peak Demand Mark

ERCOT CEO Pablo Vegas flashed his prognostication skills, warning that Aug. 20 “could be one of the peak periods that we will experience this summer.”

He was right. The grid operator set an unofficial new mark for peak demand that evening when it averaged 85.56 GW during the hour ending at 6 p.m. That broke the record set last August at 85.51 GW, a minimal 0.06% increase over last year’s peak, which was 6.6% higher than 2022’s mark.

ERCOT CEO Pablo Vegas briefs his Board of Directors on the grid operator’s summer performance so far. | ERCOT

Vegas said that without the heat dome that sat over Texas much of 2023’s summer, operating the grid has been a “different experience” this year — even as excessive heat warnings led to temperatures as high as 113 degrees Fahrenheit (in Abilene) in the state, according to the National Weather Service.

“The weather profile for the summer … differed significantly,” he said. “We’ve also seen the resource mix continue to evolve. We’ve seen significant additions of energy storage resources, solar resources and wind resources, with a few additions also on the thermal side. … All of that has helped to contribute to more consistent, less scarcity conditions during the peak periods of the summer, like we experienced last year.”

Solar resources contributed almost 13 GW of energy during 2023’s demand peak. This year, they provided 20.8 GW of energy Aug. 20, just short of the 20.83-GW record for solar. Batteries provided a record 3,927 MW at 7:35 p.m., when solar was dropping.

When “the solar ramp comes down, the wind ramping back up is one of the more significant variables that we look to,” Vegas said.

Over the last 30 days, according to Grid Status, wind resources have averaged 17 GW to 18 GW at midnight, dipping to 7 GW during the middle of the day.

ERCOT Extends MRA Timeline

ERCOT has extended the timeline for proposals to must-run alternatives to its reliability-must-run contract for three retiring CPS Energy units, from Sept. 9 to Oct. 7.

Seely said staff received fewer than 10 responses to its request for proposals, “which is not a good sign, as far as the industry being engaged potentially to try to respond to this reliability situation.” Two previous ERCOT requests for additional capacity have failed. (See “2nd DR RFP Canceled,” ERCOT Board of Directors Briefs: June 17-18, 2024.)

The grid operator issued the RFP on July 25, saying CPS’ plan to retire three aging coal-fired units, with a combined summer seasonal net maximum sustainable rating of 859 MW, would have a “material impact on identified ERCOT system performance deficiencies.” ERCOT staff have said the units’ retirement would load existing transmission facilities above their normal ratings under pre-contingency conditions. (See ERCOT Evaluating RMR, MRA Options for CPS Plant.)

Staff amended the RFP’s governing documents and issued a market notice Aug. 21. The timeline extension likely pushes the board’s consideration to December.

“We are going to amend the governing documents, which is consistent with the scope, because we really are looking for cost-effective alternatives that can be competing against the RMR resources,” Seely said.

Complicating the situation is the $57 million CPS says it will take to inspect, repair and prepare Braunig Power Station’s three units to remain in service past March 2025. The 54-year-old Unit 3 — the largest, at 412 MW — will cost $22 million alone.

ERCOT staff will continue to work with CPS on the pre-RMR costs, including a methodology on lost opportunity costs, and prepare additional reliability analysis to determine the probability of increased risk without the Braunig units. They will update the PUC during its Aug. 29 open meeting.

CPS is upgrading its transmission infrastructure to relieve a constraint south of San Antonio, but the work isn’t expected to be completed until the middle of 2027.

CFO Taylor to Retire

The board and ERCOT staff recognized CFO Sean Taylor, who has announced his retirement after more than 11 years of employment at the grid operator and more than 25 in finance.

“His leadership has helped to ensure the financial health of ERCOT throughout many consequential periods of time. Thank you for putting us in a fantastic position. … We’re going to miss you,” Vegas said.

Taylor joined the ISO as controller in 2013 from the Lower Colorado River Authority. He was named CFO in 2019 and chief risk officer this year. Previously, Taylor was a consultant performing mergers and acquisition advisory services at PricewaterhouseCoopers in New York City.

Directors OK $272.6M Project

The board unanimously approved a $272.6 million regional transmission project in Central Texas that addresses thermal violations and was endorsed by TAC during its July 31 meeting.

Staff said the project will improve long-term load-serving capability, is the least-cost solution, and requires the least amount of a certificate of convenience and necessity for the options that meet all ERCOT and NERC reliability criteria. (See “$272.6M Project Endorsed,” ERCOT Technical Advisory Committee Briefs: July 31, 2024.)

The directors also approved a pair of revision requests that were met with opposing votes at TAC. (See “Changes to CDR’s Methodology,” ERCOT Technical Advisory Committee Briefs: July 31, 2024.)

NPRR1219 was opposed by the consumer segment over concerns about using effective load-carrying capability for renewable resources and a rushed process and potential implications of changing the reporting methodology. The protocol change modifies the methodologies for the capacity, demand and reserves report’s preparation and incorporates a report release schedule. The NPRR also includes new definitions to support the methodology changes and revisions to address outdated terms and add clarity to the methodology descriptions.

The cooperative segment opposed NPRR1230, which establishes a shadow price cap for congestion affecting interconnection reliability operating limits.

The board’s consent agenda included four other NPRRs, an Other Binding Document revision request (OBDRR), a change to the Planning Guide (PGRR) and two modifications to the Verifiable Cost Manual (VCMRRs) that will:

- NPRR1216, OBDRR051 and VCMRR039: align the protocols with the Texas PUC’s order establishing an emergency pricing program for the wholesale market. During an emergency offer cap (ECAP) effective period, the systemwide offer cap is set to the ECAP, with a value equal to the low systemwide offer cap.

- NPRR1217: remove the requirement for load resources and emergency response service resources to be deployed with a verbal dispatch instruction from ERCOT.

- NPRR1231: provide clarifications and improvements to the firm fuel supply service product.

- NPRR1233: add a flat fee for federally owned generation units and adjust the weatherization inspection fee for transmission service providers.

- PGRR106: clarify which transmission projects are included in the Transmission Project Information and Tracking report.

- VCMRR040: remove the need for ERCOT to buy an annual coal price index subscription for use in calculating the quarterly coal fuel adder. The revision describes a methodology for a qualified scheduling entity to submit “actual coal fuel adders,” similar to the current process for natural gas resources.

August 26, 2024

SPP Issues EEA 1 as Heat Scorches Midwest

SPP issued a Level 1 energy emergency alert Aug. 26, saying widespread high temperatures in the Great Plains led to tightening reliability conditions in its 14-state balancing authority area (BAA).

With all available generation dispatched to meet regionwide demand, the grid operator issued the EEA 1 at 12:30 p.m. (CT). It did not say when the alert would be over.

The RTO said that while it has enough generation available to meet demand and fulfill its reserve obligations, conditions existed that could put reserves at risk if they worsened. Declaring an EEA 1 does not require energy conservation or indicate a need for load shed, it said.

Kansas, in the middle of SPP’s footprint, was under a heat advisory into Aug. 27, with heat index values rising up to 100 to 110 degrees Fahrenheit.

SPP previously declared a conservative operations advisory for the BAA Aug. 26, effective 11 a.m. CT until an anticipated end at 8 p.m. CT., and a resource advisory from 11 a.m. Aug. 26 to 8 p.m. Aug. 27.

The RTO has called or extended 21 various advisories since March.

Demand was just over 51 GW at 3 p.m. Aug. 26, according to Grid Status, with prices at about $29/MWh. SPP’s record for peak demand is 55.89 GW, set in August 2023.

The grid operator last declared an EEA 1 in August 2019.

SPP neighbor MISO was operating under a maximum generation warning Aug. 26. It was expecting scarce conditions into Aug. 27.

August 25, 2024

MISO Queue Critiques Take Focus at Infocast Midcontinent Conference

INDIANAPOLIS — Infocast’s inaugural Midcontinent Clean Energy summit last week provided panelists a pulpit for critiquing MISO’s interconnection queue setup as it strains under the weight of hundreds of gigawatts intended to further the clean energy transition and match load growth.

Engie Director of Engineering Ruchi Singh said “there needs to be a more holistic view” at MISO on how to streamline its interconnection queue, rather than proposing ideas that only serve to discourage developers from submitting queue projects.

She was referring to MISO’s stepped-up queue requirements that involve higher study fees, more definitive proof of site control and automatic penalties that grow more expensive the longer projects have stayed in the queue before withdrawing. Beyond those, MISO still hopes to cap the projects that may enter the queue each year at 50% of the footprint’s annual peak load. (See MISO Sets Sights on 50% Peak MW Cap in Annual Interconnection Queue Cycles.)

Singh questioned whether that last rule would be the best method for getting the queue under control. She said the footprint might be better served by volumetric price escalation rules, in which MISO raises interconnection customers’ fees and penalties as individual developers submit more projects to the queue for study. She said MISO should explore that more equitable method rather than “chasing a number.”

If MISO ultimately finds that it needs a megawatt cap, Singh said it should establish a “transparent and fair” process for calculating the megawatt threshold beyond throwing out a percentage.

Strata Clean Energy’s Michael Russ said MISO should be careful formulating annual queue caps because the nameplate capacity of projects are not their eventual accredited capacity values. He implied MISO could inadvertently risk its resource adequacy.

Russ also said developers tend to flood the queue with projects “because there’s so low certainty because of the four to five queue cycles in front.” They attempt to anticipate an “almost infinite” number of interconnection scenarios for their projects as higher-queued projects drop out and affect subsequent submittals in the queue.

“It’s nearly impossible. It’s probably why I’ve lost most of my hair,” he said. He recommended MISO devote itself to confirming study results sooner and more definitively.

Chris Lazinski, head of strategy and origination at BayWa r.e. Americas, said MISO’s interconnection process has become the “long tent pole” in getting projects to commercial operation, replacing permitting as the biggest hurdle. He said MISO may want to introduce new “gradations” of interconnection service for generators that cannot meet the full requirements for participation as capacity resources. He suggested more levels of interconnection service to match generators’ service level with their output abilities.

Sergio Garcia, executive director of project finance at Rabobank, which invests in projects in the MISO queue, said it would be nice to close a deal with guaranteed network upgrade costs. He said currently, network upgrade costs in MISO are not finalized until much later in the process than in other RTOs because the costs remain contingent on other queued projects, with upgrade costs spread on a pro rata basis.

“Most projects die on interconnection costs,” Garcia said.

“The numbers fluctuate so wildly based on who drops out of the queue,” said Kristina Shih, a partner at private equity fund Segue Sustainable Infrastructure. Shih said investment firms will lean on supplemental studies outside of MISO or consultants to figure out if it makes financial sense to keep paying the RTO’s milestone fees to remain in the queue.

Prudential Private Capital Senior Vice President Ty Bowman said it is understandable under the current queue atmosphere that developers with more means would add queue positions to mitigate attrition rates of other projects.

Heath Norrick, director of Deriva Energy’s renewable business development (formerly Duke Energy Renewables), said MISO’s higher queue fees and withdraw penalties will “unquestionably” tamp down competition over time, driving out smaller generation developers and leaving larger developers with most queue slots.

Queue Cap a Sound Idea?

Brad Pope, the Organization of MISO States’ head of regulatory and legal affairs, said that though an annual megawatt cap on the queue might be a “crude instrument,” it appears necessary for MISO’s planning engineers to be able to overcome the study complexities of too many projects.

“We are getting to a point that’s second only to the Industrial Revolution,” Pope said of the explosion in data center development and the new electricity needed to serve them.

SB Energy’s Karl Brutsaert said that even quality clean energy projects today are threatened by MISO’s massive annual queue cycles, in which the collective nameplate capacity rivals the RTO’s annual peak load. He said MISO seems to be struggling to separate the “wheat from the chaff.” He said that while there is “tons of demand,” it remains “very difficult to meet that demand.”

EDF Renewables’ Erik Ejups said that even with MISO planners doing what they can to propose long-range transmission portfolios to accommodate future generation, it appears developers are poised to “blow their faces off again” with a flood of queue submittals year after year. “It’s kind of a loop.”

Triple Oak Power COO Ryan Leonard said it would likely be valuable for MISO to simultaneously analyze new load and any companion generation proposed to exclusively serve it.

Jonathan Pike, vice president of corporate development at Earthrise Energy, said developers are not expecting MISO to be able to complete studies and move to interconnection agreements in a matter of a few months. He said developers know that some amount of uncertainty and wait times will always be a feature of interconnection queues. But he said the current level of unknowns in the MISO queue are untenable.

“What we need is a manageable amount of risk and uncertainty,” he said.

Time-limited Leases

Wells McGiffert, vice president of business development at PRC Wind, which has been developing projects in MISO for about 30 years, said site control requirements can become tricky when some jurisdictions limit the span of land lease agreements.

“We have to be very genuine to our landowners and say, ‘We can only sign this lease for five years, but this project is going to take eight years to develop.’ … When it can take eight to 10 years, they can be along for a ride,” he said.

Gordon Baier, CEO and co-founder of GoSolar Energy, recommended developers be upfront about timelines and warn landowners who agree to host projects that renewable energy development is a yearslong process. He said landowners can become frustrated with delays and want to break leases and sell land.

Baier advised developers to secure long-term leases when they can to account for queue study delays.

“That is a risk for us because we have all the ingredients on the table, but we’re in two to three years of backlog. … This is a massive risk,” he said.

Baier recommended developers first hold “one-to-one discussions with key landowners” to get them comfortable with projects before holding community sessions on utility-scale renewable projects. He said that when developers approach landowners individually, they should ask landowners about their inheritance plans for their land and try to convince them to replace “conventional farming with sun farming.”

“They think they’ll agree to a project, and it will be built the next year,” agreed McGiffert. He advised managing expectations and taking a gentle approach where developers don’t come in assuming a project is a foregone conclusion.

“It’s not our land. We try to ask permission to come to the community. … We don’t want to force and pit neighbors against each other,” McGiffert said.

Transmission Planning and Remaking the Grid

More than $35 billion across two major transmission portfolios is being readied for MISO’s Midwest region, which stands to ease interconnection backlogs. However, that help is still years away.

ITC Holdings’ Cynthia Crane asked the audience to remember that MISO’s first, $10 billion Long Range Transmission Planning (LRTP) portfolio, and the second, potentially $25 billion LRTP portfolio face a multiyear process studded with permitting and siting challenges, supply chain issues and labor shortages.

“It’s fabulous that we’ve gone through this planning cycle and got the projects approved, but now we have to get to work,” Crane said.

“We’re behind on transmission — almost a decade — if you think about how long it’s going to take to build [LRTP] Tranche 1, by 2030, and Tranche 2 sometime around 2040,” said Arash Ghodsian, Invenergy vice president of transmission and policy.

Ghodsian said given that development has lagged, MISO should seriously consider proposing HVDC lines in upcoming LRTP portfolios or its regularly scheduled annual planning.

“If you wait for cost allocation, you’re never going to build anything,” Ghodsian said. However, he said he thought MISO South, long allergic to major, regional projects, is beginning to warm to the idea of intensive planning, with some southern members asking for planning.

Ghodsian said he’s optimistic that FERC’s recent Order 1920, which seeks to make long-term planning more standard and commonplace, will spur a boom in interregional planning.

“The hope is that 1920 can set the groundwork for these kinds of coordination,” Ghodsian said.

David Mindham, EDP Renewables’ director of regulatory and market affairs, said nationally the zeitgeist of load growth and fleet transformation means that there has never been a better time to remake the grid. He said for maybe the first time, there are “coherent national strategies” to guide buildout.

Mindham said MISO should shift some focus from making it more challenging for generation developers to enter the interconnection queue to making sure its transmission owners complete timely network upgrades for projects.

While it’s “impressive” that MISO’s long-range transmission planning is set to total more than $30 billion soon, he continued, in-service dates are still years away. In the meantime, MISO and its TOs could become better at implementing near-term solutions to open up capacity on the transmission system, like reconfiguration plans and grid-enhancing technologies. He said developers are willing to pay for the costs of reconfiguring flows if it means their projects don’t have to wait additional years for commercial operation.

“We need to be better at getting projects online and reducing curtailment,” Mindham said.