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November 13, 2024

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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.”

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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. 

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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.

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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. 
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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. 

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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.

Cynthia Crane, ITC, and Arash Ghodsian, Invenergy | © RTO Insider LLC 

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.

GoSolar Energy CEO Gordon Baier | © RTO Insider LLC

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.

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NetZero Analysis: Industry Leaders Share Frank Views on the IRA at 2

The second anniversary of the Inflation Reduction Act on Aug. 16 passed pretty much as expected.  

The Biden administration spent the run-up to the anniversary sending out press releases and hosting a Department of Energy webinar focused on the achievements of the law to date — including the $25 billion in loans the Loan Programs Office has announced for 18 projects and the nearly 20,000 permanent jobs those projects could create.  

Energy industry trade associations, clean energy companies, state and local officials, and advocates released a fairly predictable set of statements, again, hailing achievements, while noting the work still ahead.  

To gain a deeper understanding of how the IRA is being implemented, NetZero Insider invited several industry leaders to share their views on the law on background but with the understanding that we would come back to them with quotes from these interviews and ask if we could publish them on the record.  

In each interview, we asked four main questions: 

    • From your point of view, what were the most important achievements or unexpected results of the first two years of IRA implementation? 
    • Were there specific pain or choke points, or frustrations, with implementation thus far? What are you hearing from the industry and/or your members? 
    • What might have been done differently? 
    • What needs to happen to ensure implementation continues so the law has its maximum intended effect, regardless of who is in the White House or which party controls Congress come January? 

Our original invitations went out to a broad range of individuals, including leaders with bipartisan and conservative views on climate and energy; however, those individuals and their groups either declined or did not respond to our requests for interviews. 

Those who agreed to the interviews were split between general clean energy associations and trade associations focused on specific technologies, both of which had lobbied hard to get certain provisions into the IRA or the Infrastructure Investment and Jobs Act. 

The general groups were represented by Harry Godfrey, managing director for policy at Advanced Energy United (AEU); Lisa Jacobson, president of the Business Council for Sustainable Energy; and Ray Long, CEO of the American Council on Renewable Energy. 

Jessie Stolark, executive director of the Carbon Capture Coalition, Paula Glover; president of the Alliance to Save Energy; and Blaine Collison, executive director of the Renewable Thermal Collaborative, rounded out our list of industry experts. 

Industrial Policy, at Last

When President Joe Biden signed the IRA on Aug. 16, 2022, the price tag for its energy tax credits, grants and other incentives was just shy of $370 billion. But the uptake of the tax credits and incentives has almost doubled that figure to $730 billion, according to recent estimates from the Congressional Budget Office. 

While the resulting boom in clean energy manufacturing has been extensively discussed and documented, Godfrey said the sheer scale has been surprising. 

“I don’t think anybody developing this law expected to see that significant of an uptick in [demand] and new factory starts,” he said. Rather, early expectations may have been formed by the more muted increase in manufacturing following passage of the American Recovery and Reinvestment Act of 2009, amid the Great Recession. 

The main difference between then and now “has everything to do with the fact that they got the mechanics of industrial policy right,” Godfrey said. “They have both the supply-side support for folks opening new factories … but then they coupled it with really stable, long-term and relatively generous demand-side proposals.”  

ACORE’s Long agreed that “for the first time in decades … we have a real industrial manufacturing policy; so, people are investing in manufacturing, in factories in the United States. … Stuff is actually getting built.” 

But beyond the announcements, Long said, “the policies that have been put in place have been designed to really level the playing field in terms of the opportunities for all Americans” to access the benefits of clean energy, which often have not reached disadvantaged or remote communities.  

Godfrey also talked about the IRA’s $5 billion in Climate Pollution Reduction Grants that are helping states develop climate action plans. EPA announced in March that 45 states, the District of Columbia, Puerto Rico and a number of individual cities have submitted plans. 

A potentially high-impact initiative that largely has flown under the radar, the plans from red, blue and purple states “really look across the entirety of their economies and go deep in this stuff,” Godfrey said. “There’s a great deal of variation, and variation in terms of granularity and specificity, but lots of states [took] the time to do that and really participate in that thought and lay out plans.” 

The law’s tax credits were another point of agreement, providing, as Godfrey said, both supply- and demand-side incentives.  

Stolark pointed to the IRA’s expansion of the industry’s 45Q tax credits for carbon capture technologies as a “critical milestone” for the industry, catalyzing new interest and project announcements. The law more than doubled the tax credit for carbon capture projects at power plants or industrial sites from its previous level of $40.89 per ton to $85 per ton. 

But, she said, the tax credits are only a first step toward creating sustainable markets for carbon capture. For these technologies to scale, “we need markets for products and services sourced from carbon management.” 

Collison praised the 45X advanced manufacturing tax credits, which cover thermal batteries, “a key industrial decarbonization and electrification technology,” as well as the clean hydrogen and storage credits. Thermal batteries store energy as heat and may provide long-duration storage. 

For Glover, the most significant IRA tax credits are 25C, 179D and 45L, which provide credits for energy efficiency measures on residential buildings, commercial buildings, and new single-family and manufactured housing, respectively.  

The Tax Credits

But the excitement about the tax credits has been tempered by the complexities of the IRA itself and the resulting long time frames and uncertainties still surrounding their implementation.  

The success of the energy efficiency tax credits depends on people knowing, first, that they are available and then, how to use them, Glover said. 

Her biggest challenge “really has been like, how do we communicate to the general public about what’s available to them,” she said. “And there’s not really money available to promote that kind of communication.” 

Many of the pain points surrounding the tax credits could be rooted in the speed with which the 274-page IRA was passed, and the pressure on federal agencies to get out proposed guidelines and respond to the hundreds of public comments they often receive.  

“There are a bunch of relevant technologies that are not explicitly included, like industrial heat pumps, which frankly are going to be a huge wedge of our collective decarbonization,” Collison said. 

In speaking about tax credit uncertainty and the Treasury Department’s slow rollout of final rules, our interviewees all qualified their concerns by acknowledging the herculean task Treasury has faced and praising its efforts to distill the law’s complexities into legal guidelines that consider a broad range of stakeholder input.  

Jacobson raised the public debate on the 45V clean hydrogen tax credit as a case in point. Treasury guidelines here will set the emission levels required for a project to be eligible for a credit of up to $3 per kilogram. A proposed rule was released in December 2023 but has yet to be finalized. 

“Whatever we end up with, these conditions are not as flexible as some in the industry would like,” she said. “That’s clear; it’s very public. But that will have an impact on how much we’re able to deploy and how we’re going to go forward.” 

Jacobson likened the ongoing uncertainties surrounding IRA tax credits to a playoff football game. “We have the opportunity to be on the field, and we’re playing, but we don’t have all the equipment. We don’t know all the rules.” 

“People thought they were going to eligible for these credits, and now they’re not sure,” she said. “That’s frustrating.” 

Domestic Content

Talking about the law’s domestic content provisions — another big flashpoint — Godfrey said Treasury may have “overengineered” the rules. 

“The initial proposal from Treasury required such complex and closely held information from companies to qualify that I consistently heard from members they’d likely have to bypass the credit — even if they would qualify in theory,” he said. 

The IRA provides “bonus” tax credits for clean energy products — from solar panels to electric vehicle batteries — that are made with domestically produced materials and components. Manchin has been a constant critic of Treasury’s guidelines, which have attempted to provide some flexibility for certain materials — such as graphite for batteries — based on industry feedback. 

Godfrey said AEU wanted to see the domestic content provisions work because the group views it as a sound approach. 

“Rather than having discriminatory policies that essentially raise prices for anything that’s coming in, let’s help lower prices and thus create an incentive for the consumption of domestically made content,” he said. “If you want to incentivize domestic manufacturing and incentivize consumption, an extra tax credit like this is actually the right way to do it.”  

Jacobson talked of the need to hit a “sweet spot” between building out domestic supply chains and growing domestic markets for clean energy technologies.  

“Both have to happen at the same time,” she said. “You have to have continued demand and market growth in the U.S. to attract investment for the domestic supply chains and workforce. They all have to align.” 

And if they don’t, Jacobson said, “[we’re] just going to have to live through it.” 

Long sees a possible resolution in two or three years, when he said, solar and other clean energy manufacturing will be “baked into our economy.” 

Home Energy Rebates

Stolark brought up yet another challenge: While waiting for final guidelines on some tax credits, inflation has already undercut their intended impact to reduce prices, she said. To build out the carbon capture projects needed to decarbonize heavy industry such as cement, steel and chemicals, even an $85/kg tax credit may not be enough, she said.  

Such bottom-line concerns could affect the buildout of not only carbon capture projects, but also the pipelines needed to transport the captured CO2 to storage sites, she said. 

“What I am hearing from our members is that there will be interest eventually in transport, but right now the focus is on some of the other pieces,” Stolark said. “The projects that are moving forward right now, they’re looking at capturing CO2 at a site that is very close [to], if not on top of, appropriate geologic storage.” 

The IRA’s $8.8 billion in home energy rebates have also seen a slow rollout, with only two states — New York and Wisconsin — thus far opening programs to get the money to consumers. 

Part of the challenge here, Glover said, is that both the state energy offices that must plan and run the programs and DOE, which must approve those plans, are being “extremely careful.”  

“When they start talking about building community benefit plans and measuring the benefits of projects in communities, there’s so much legwork that goes into that to make sure you have a successful program,” she said. 

What’s Next

While the IRA contains no provisions related to permitting, many of our interviewees talked about the need to streamline and accelerate permitting as one of the must-haves to optimize the impact of the grants and programs the law has launched. 

Other items on the wish list of next steps included a tax credit for transmission, more federal dollars to help states and cities implement their climate action plans, long-delayed safety standards for carbon dioxide pipelines and a law that would index tax credits to inflation.  

But what could come next may depend on the outcome of the November elections, and who is in the White House and controlling the House, Senate or both come January. 

IRA funds that already have been awarded to specific projects and “committed” via a signed contract should be safe, as should tax credits, which appear to have bipartisan support. A group of 18 Republican representatives sent House Speaker Mike Johnson (R-La.) a letter Aug. 6 asking him to protect the tax credits that are drawing new industries and jobs to their districts. 

“There needs to be a clear commitment by the next president and congressional leaders that they are going to continue with these historic federal investments [and] make that clear to the private sector,” Jacobson said. 

She also encouraged industry and advocacy groups alike, “Don’t be afraid of the lack of clarity in certain areas. That shouldn’t turn people off.” 

Godfrey sees a growing role for state and local governments in the coming year. “States will be in the driver’s seat for IRA implementation … in no small part because we are continuing to see these grant dollars flow out the door, particularly from DOE and EPA.” 

But he also said it’s time to think about the future after the IRA. When the law’s incentives stop flowing, “when the stuff is already there, how do we make certain that it’s both creating bill savings and then there are real, sustainable markets that make certain you’re getting the maximum value out of all those distributed energy resources?” he said. 

What will be needed, Godfrey said, are “robust state [and] regional-level markets for capacity, the ancillary services, the generation services those DERs can provide back to the grid.” 

“My hope is that we figure out how we leave the rhetoric aside,” Glover said. “[If] we look at what these things are really trying to accomplish, and we’re honest … about things that work and don’t work, I would hope that it would not matter if we have a Trump administration or a Harris administration.” 

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MISO Predicts Painless Fall Despite Missouri Capacity Shortfall

MISO doesn’t believe autumn will prove much trouble for it to tackle, though it faces a capacity shortfall in Missouri.

According to its seasonal outlook, the grid operator likely will come the closest to calling on its load-modifying resources in September, when it predicts a 115.6-GW systemwide peak. Over the fall, MISO will have 115.8 GW of cleared capacity on hand. MISO noted that 124 GW was offered but didn’t clear the fall capacity auction.

Subsequent fall months don’t seem any cause for concern. MISO predicts a 95-GW peak in October and a nearly 94-GW peak in November, which should be handled easily by cleared capacity totals.

The systemwide numbers are despite a projected capacity shortfall in portions of Missouri for the season.

Per MISO’s capacity auction held in spring, Zone 5 — which contains local balancing authorities Ameren Missouri and the city of Columbia, Mo.’s Water and Light Department — should experience an 872-MW capacity deficit over the next few months. The zone came up short on its local clearing requirements in the auction and cleared at the $719.81/MW-day cost of new entry for generation in the fall and upcoming spring.

Ameren leadership has said the effects of the scarcity likely will go unnoticed, not impacting reliability nor customers’ bills. (See Ameren: MISO Missouri Capacity Shortfall Likely Inconsequential.)

July Peak Prediction Unfulfilled

Meanwhile, MISO reported its operators contended with a 118-GW peak in July, lower than the 123-GW peak it anticipated before the start of the season.

MISO’s peak occurred July 15, while MISO Midwest was under conservative operations as hot and stormy weather passed through. July’s peak registered lower than the 121-GW peak in July 2023. Load averaged about 86 GW per day in July, in line with last July’s average load. Real-time prices also closely tracked last year, coming in at $30/MWh compared to last July’s $31/MWh. Gas and coal prices were identical year-over-year in MISO, holding at $2/MMBtu apiece.

MISO said average generation outages in July totaled 31 GW per day, a 2-GW improvement over last year.

MISO leadership and stakeholders are set to review summertime performance during a quarterly MISO Board Week meetup in mid-September in Indianapolis.

Ramp Deficit Triggers VOLL

MISO and stakeholders dissected a mid-June price spike due to inadequate ramping at an Aug. 22 Market Subcommittee meeting.

MISO’s system-wide energy price shot up to $3,500/MWh for two intervals on June 16 after several units powered down around 9 p.m. MISO said the ramping ability available on its remaining dispatchable resources “was insufficient to meet emerging risks.”

Stakeholders asked how MISO didn’t see the ramp needs coming when the units’ exit that night was planned. They also questioned how prices could soar to the $3,500/MWh value of lost load briefly then almost instantaneously settle back to the usual, approximately $25/MWh.

“We’ve seen a number of these real-time price spikes related to operating reserves and not having enough ramp,” Market Evaluation Manager Dustin Grethen said. “We ended up in a situation where available dispatchable generation was insufficient.”

Grethen said the value of lost load was necessary because ramping capability went into a deficit and demand couldn’t be met systemwide.

Grethen said multiple times this summer, MISO has been “trying to run lean” and use reserves. However, he said in this instance MISO experienced an under-forecast in wind output paired with some uninstructed deviation on the part of other generators.

“Things are tighter than they used to be. Some of these risks that before went under the boat are now bumping the bottom,” Grethen said.

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CPUC Approves Plan to Procure 10.6 GW of Clean Resources

California regulators have approved a plan for the state to buy up to 10.6 GW of long-lead time clean energy resources, including 7.6 GW of offshore wind along with geothermal energy and long-duration energy storage.

The California Public Utilities Commission voted Aug. 22 to approve the central procurement plan. It is seen as a way of transforming the market for emerging technologies that will help the state meet its greenhouse gas reduction goals.

“With this new tool, California has the opportunity to jumpstart clean energy technologies and bring them to scale,” CPUC President Alice Reynolds said in a statement after the vote.

The CPUC will ask the state’s Department of Water Resources (DWR), through its Statewide Energy Office, to buy up to 10.6 GW of nameplate capacity including:

    • 6 GW of offshore wind.
    • 1 GW of geothermal generation.
    • 1 GW of multi-day energy storage.
    • 1 GW of energy storage with a discharge period of at least 12 hours.

The plan excludes long-duration storage that uses lithium-ion batteries. Pumped storage hydroelectric projects will be eligible only if they’re 500 MW or less and received state funding before 2023. The geothermal generation may be of any type.

The procurement will be on behalf of all energy providers within the CPUC’s jurisdiction, including investor-owned utilities, community choice aggregators and direct access providers. The benefits and costs will be split up among energy providers.

Solicitations will start in 2026 for long-duration storage and in 2027 for offshore wind and geothermal resources, with the resources coming online by 2037.

The resource quantities in the procurement are “up to” amounts. DWR or CPUC could decide to not buy the resources if they cost too much. The CPUC is expecting multiple rounds of solicitations in which costs would fall over time.

Assessing Need

The centralized procurement strategy is a component of Assembly Bill 1373 of 2023. Under AB 1373, resources eligible to be included in the strategy are those that don’t use fossil fuels or combustion to generate electricity and that have a lead time of at least five years for development and construction. (See New California Law to Give State Power to Procure Renewable Energy.)

The bill set a Sept. 1, 2024, deadline for the CPUC to determine if there’s a need for centralized procurement. To make that assessment, the CPUC evaluated utilities’ integrated resource plans and looked for gaps in certain resource types.

The CPUC saw a need for geothermal generation and long-duration storage but plans to ask DWR to solicit only about half the projected amount needed to meet renewable and zero-carbon energy targets.

This will “facilitate a down payment” on the technologies, “while still leaving room for LSEs to procure the technologies individually, after costs are reduced and market transformation is underway,” the agency said in its decision.

For offshore wind, the CPUC said 7.6 GW is enough to signal “a strong interest in developing the resource,” while going beyond that amount might be riskier for ratepayers.

The California Energy Commission in 2022 adopted the nation’s most ambitious long-term offshore wind goals, targeting a buildout of up to 5 GW by 2030 and 25 GW by 2045. (See California Adopts Country’s Most Ambitious OSW Targets.)

Utility Cost-sharing

The benefits and costs of centrally procured geothermal and offshore wind energy will be divided among energy providers within CPUC jurisdiction based on their annual load share. For long-duration storage, benefits and cost shares will be based on 12-month coincident peak demand.

More details of cost and benefit sharing will be worked out before any contracts are signed.

Although publicly owned utilities aren’t within CPUC jurisdiction, the agency recommended that DWR ask those utilities if they want to voluntarily participate in the centralized procurement.

The CPUC will reevaluate the need for additional centralized procurement of long-lead time resources in future IRP cycles. Previous need determinations won’t be reduced in that process, according to the CPUC decision.

CPUC Commissioner John Reynolds said approval of the procurement strategy “issues a challenge to the industry.”

“We want to see developers deliver on the immense potential of these technologies to deliver tangible ratepayer benefits and cost efficiencies with the economies of scale we are enabling here,” he said in a statement.

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BPA to Delay Day-ahead Market Decision, Sources Say

The Bonneville Power Administration will delay its Western day-ahead market choice beyond a scheduled Aug. 29 announcement date and likely will extend the decision-making process into 2025, multiple sources told RTO Insider.

The sources, who are not authorized to speak on behalf of their organizations, shared those details a week after BPA Administrator John Hairston said he was “evaluating” the timeline for choosing between SPP’s Markets+ or CAISO’s Extended Day-Ahead Market (EDAM).

“There’s a lot of factors at play. There’s more to come in the next week or two,” one source said.

Speaking during the agency’s Aug. 15 Quarterly Business Review, Hairston said the agency was “balancing the need for a deliberate, transparent process with the urgency created by the decisions of our neighbors.”

Two of those neighbors, the six-state utility PacifiCorp and Oregon’s Portland General Electric, have signed implementation agreements with EDAM, while the Balancing Authority of Northern California, Idaho Power, the Los Angeles Department of Water and Power, and NV Energy have signaled their intent to join the CAISO-run market.

BPA staff in April issued a “leaning” recommending the agency choose Markets+ over EDAM, citing the SPP market’s independent governance and overall design as primary factors in the opinion. (See BPA Staff Recommends Markets+ over EDAM.)

The agency previously cited Aug. 29 as the date it would issue a “draft letter to the region” on a decision whether to join a day-ahead market and which market it would select, followed by a “final” letter in November. Two sources said a decision now could be delayed by as much as six months.

BPA spokesperson Doug Johnson told RTO Insider the agency still is evaluating the timeline and expects to provide more information the week of Aug. 26.

During the Aug. 15 call, Hairston acknowledged the progress the West-Wide Governance Pathways Initiative has made in “improving” CAISO’s state-run market governance without the need for legislative changes, but he also pointed to the legislative changes still needed to bring greater independence to the ISO’s EDAM and Western Energy Imbalance Market (WEIM), in which BPA is a participant. (See CAISO, WEM Boards Approve Pathways ‘Step 1’ Plan.)

“As I’ve said from the outset, BPA seeks to participate in a market that has a durable, effective and independent governance structure [that] provides fair representation to all market participants and stakeholders,” Hairston said. “I fully appreciate the magnitude of such a decision, and you have my commitment to continuing our deliberate, transparent process, with the aim of making a decision that is right for our customers and the region.”

Hairston and his agency face pressure on multiple fronts over the day-ahead market decision. Environmental and industry groups that favor development of a single West-wide market that expressly includes California, such as the Northwest Energy Coalition, have urged BPA to join EDAM to help maximize the “diversity benefit” of the West’s geographically distributed emissions-free resources through a market with the largest possible footprint.

Northwest utility regulators, who have no oversight authority over BPA, also signaled their preference for a single market based on EDAM when they helped launch the Pathways Initiative last summer. In separate letters earlier this year, Washington Gov. Jay Inslee cited the importance of a single West-wide market that includes California to meet state targets for emissions reductions, while Oregon Gov. Tina Kotek warned that “fragmentation will drive unnecessary costs, create new reliability risks and prevent fully utilizing the resources that customers across the region have paid for.”

The most significant political pressure materialized in a July 25 letter addressed to Hairston from the four U.S. Democratic senators representing Oregon and Washington.

In the letter, the senators urged the agency to delay its decision until more developments play out around Markets+ and EDAM and made clear they think the Northwest would see more benefit from one organized electricity market than two. They also directed BPA to answer 14 detailed questions about its “leaning” by Aug. 25 — a Sunday. (See NW Senators Urge BPA to Delay Day-ahead Market Decision.)

Further complicating matters for BPA: A week after the arrival of the senators’ letter, FERC issued SPP a deficiency notice covering multiple sections of the Markets+ tariff that the RTO filed in March, a concern cited by the senators. (See FERC Finds SPP Markets+ Tariff ‘Deficient’ in Several Areas.)

‘Lasting Consequences’

BPA also faces pressure in the other direction from many — although not all — of the publicly owned utilities that constitute its base of “preference” customers, who have advocated firmly for the agency to join Markets+. (See Northwest Public Power Group Endorses Markets+ over EDAM.)

On Aug. 21, a sizable cohort from that group sent their own response to the Northwestern U.S. senators, asking them to consider the impact of BPA’s day-ahead market decision on the region’s consumer- and tribal-owned utilities. Among the 47 signatories were Tacoma Power, Clark Public Utilities and the Snohomish, Chelan, Douglas and Grant county public utility districts in Washington; and Salem Electric, Umatilla Electric Cooperative and the Clatskanie, Emerald and Northern Wasco County people’s utility districts in Oregon.

“BPA’s decision will have lasting consequences for our ratepayers and your constituents,” the utilities wrote. “Although we support West-wide collaboration, the fiduciary obligation to our ratepayers drives our evaluation of day-ahead market options — as it should BPA’s decision.”

The letter reiterated BPA’s oft stated concern about EDAM’s California-run governance, saying “governance drives major policy outcomes and, therefore, the allocation of economic outcomes among the communities served through the market,” echoing a point made in a recent “issue alert” released by a group of entities that helped fund the “Phase 1” tariff development stage of Markets+. (See Governance is ‘Key Consideration’ for West, Markets+ Backers Say.)

While the utilities contend it was competition from Markets+ that motivated the effort to address CAISO’s market governance, they also doubt the Pathways Initiative can achieve “meaningful change” to California law because previous efforts “have always failed.” The utilities also argue EDAM was designed and approved under CAISO’s current “flawed governance,” and that it would take years to “unwind” the impact of that on a market design that disfavors Northwestern interests.

“Forcing BPA to delay participation in Markets+ and forgo a market with superior governance and market design frameworks on account of hopes that the West-Wide Governance Pathways Initiative may succeed would be irresponsible and harmful to our ratepayers,” they wrote.

But the utilities’ most notable concern is that pressure from the senators could delay BPA’s decision to help fund the “Phase 2” implementation stage of Markets+, which, they contend, would take pressure off the efforts to alter the WEIM/EDAM governance structure.

“BPA’s ongoing funding commitment to Markets+ is essential to the continued development of a day-ahead market that respects the policy, economic and regulatory interests of our ratepayers,” they wrote.

The Portland, Ore.-based Public Power Council (PPC) made a similar point in an Aug. 15 letter addressed to Hairston, which encouraged BPA to commit to funding Phase 2 of Markets+ to ensure the market “remains a viable option for BPA and other stakeholders in the West.

“This commitment should be formalized in a letter to the region, capturing the agency’s evaluation of market options to date,” the PPC wrote. “We acknowledge that this may result in a timing difference between BPA’s decision to fund the next phase in Markets+ and BPA’s overall decision on day-ahead market participation.”

Such a commitment would represent a significant financial investment for BPA. The cost for Phase 2 implementation —scheduled for 2025 through the first quarter of 2027— will run to about $150 million, SPP told RTO Insider. Whatever the actual figure, BPA will be on the hook to cover 17.4% of the funding costs, second only to Powerex’s 23.2% share, according to an SPP document.

BPA’s original share for funding Phase 1 was 15.2%, but all Phase 2 funders will face higher shares now that NV Energy, Western Area Power Administration’s Desert Southwest Region, Liberty Utilities and Arizona Electric Power Cooperative have pulled their support from Markets+.

During an Aug. 13 Markets+ Participants Executive Committee meeting, SPP staff told stakeholders they have SPP board approval to engage with lenders over Phase 2 funding agreements, which will be extended to participants by the end of the year. (See SPP Dispels Concerns over Markets+ Deficiency Letter.)

SPP expects its administrative costs to operate Markets+ to range between $65 million and $70 million annually.