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July 23, 2024

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EPA Announces $4.3B in Climate Pollution Reduction Grants

Pennsylvania will use its $396.1 million Climate Pollution Reduction Grant (CPRG) on a statewide initiative to cut greenhouse gas emissions from industrial buildings through incentives for energy efficiency and emission-reduction technologies. 

Montana’s plan for its $49.7 million CPRG will focus on improving forest management across the state, expanding urban and community forests, mitigating wildfires and coal seam fires, and reducing pollution from agriculture. 

And in Connecticut, New Haven will get $9.4 million to build a networked geothermal system that will provide clean power and heat to Union Station, the city’s transit hub, with carbon-free electricity also going to a neighboring mixed-income housing development. 

EPA on July 22 announced these and 22 other projects that have been selected to receive more than $4.3 billion in CPRG funds from the Inflation Reduction Act, all aimed at reducing emissions, promoting clean energy and creating jobs. 

Announcing the grant awards at a concrete and asphalt plant in Pittsburgh, EPA Administrator Michael Regan said the federal dollars will “fund investment-ready projects targeting climate pollution from transportation, the electric power sector, commercial and residential buildings, industry, agriculture, natural lands, [and] waste and materials management. … These investments are going to change lives.” 

Combined, the 25 projects could reduce U.S. GHG emissions by 971 MMT by 2050, which, according to EPA, is the equivalent of the emissions from the energy used by 5 million average U.S. homes per year for more than 25 years. 

The IRA funds will “empower local ownership … and local solutions to help solve a global problem,” John Podesta, White House senior adviser on climate innovation and implementation, said during an advance press call July 19. “The climate crisis looks different in every community, from Colorado to Connecticut to Lincoln, Nebraska. More bike lanes and public transit may be the best way for one city to reduce emissions, and making a local steel plant more energy efficient might be the best path for another.” 

Lincoln Mayor Leirion Gaylor Baird agreed. “Local initiatives, when combined with federal funding, can transform ideas into tangible solutions,” she said. 

“Here in Lincoln, the planning phase of this grant program showed us that some of the greatest opportunities for emission reductions lie in enhancing the energy efficiency of homes and commercial buildings. Our analysis indicates that investing in energy efficiency and electrification could reduce Lincoln’s emissions by a whopping 77% from our baseline metrics by the year 2050.” 

The money will also be used for “critical home repairs for low-income members of our community” as part of the city’s efficiency and electrification efforts, she said. 

Lincoln’s programs are just one element of Nebraska’s plans for its $307 million in CPRG funding. The money will also go toward accelerating the adoption of climate-smart and precision agricultural practices and reducing agricultural waste from livestock. 

Precision agriculture uses digital tools and automation to improve farming efficiency and crop yields. 

EPA received nearly 300 applications for the grants, with funding requests totaling $33 billion, Regan said July 19. The 25 awardees were “the cream of the crop,” with projects offering “maximum penetration of greenhouse gas pollution reduction. But also, we wanted to be sure we saw the diversity across various industries, whether it be transportation, building, agriculture [or] the power sector.” 

Community benefits and job creation were additional priorities in evaluating applications, he said. “We have a very stringent program. These recipients also have demonstrated that not only could they identify the pollution reduction targets, but they could put metrics in place to prove it.” 

The CPRG funding contains an additional $300 million for emission-reduction projects submitted by tribes and territories, to be announced this year. 

Asked if the grants announced July 22 could be affected by a change in administration, Regan said all the funds would be “obligated” to the awardees by early fall, once all legal and administrative requirements are met. 

“We know these recipients are ready to receive these dollars and will be off to the races immediately,” he said. 

State Climate Plans

The grant announcements are the second phase of the CPRG program, which began last year, when EPA awarded $250 million in noncompetitive IRA funds to help state, city and tribal governments develop climate plans. Individual grants ranged from $1 million to $3 million. 

Plans were due March 1 for states and cities and April 1 for tribes and territories. 

Forty-five states and dozens of cities and tribes ― covering 96% of the U.S. population ― now have plans in place, according to EPA. While five states ― Florida, Iowa, Kentucky, South Dakota and Wyoming ― did not submit plans, cities in those states did. Rapid City, S.D., and Cheyenne, Wyo., submitted plans, as did Des Moines, Cedar Rapids and Iowa City in Iowa. 

Updated, comprehensive plans will be due around the middle of 2025, according to EPA. 

The second-phase grants are intended to help a small group of states and cities implement those plans and provide models that other states, cities and businesses can replicate. 

Pennsylvania Gov. Josh Shapiro, joining Regan in Pittsburgh, said the state’s $396.1 million CPRG is the second-largest federal grant in its history and will be used for its Reducing Industrial Sector Emissions in Pennsylvania (RISE-PA) program. 

Administered by the state’s Department of Environmental Protection, RISE-PA will issue grants “to manufacturing companies across this commonwealth,” Shapiro said. “These grants can be used for … improving energy efficiency, reducing emissions, implementing carbon capture … and replacing equipment with electric power options,” such as swapping out coal-powered smelters used to make steel for electric smelters. 

“I have always said we have got to reject the false choice between protecting our planet and protecting our jobs,” Shapiro said. “We can and we must do both.” 

Multistate and Regional Projects

Other award winners included several multistate and regional projects. 

Maine, New Hampshire, Connecticut, Massachusetts and Rhode Island are partnering on a New England Heat Pump Accelerator, which snagged $450 million, one of the largest grants announced. In states heavily dependent on winter heating oil, the project aims to install cold-climate air-source heat pumps, heat pump water heaters and ground-source heat pumps in 500,000 single-family and multiunit homes. 

New Jersey, Connecticut, Delaware and Maryland have formed the Clean Corridor Coalition, which will receive $248.9 million to install electric charging stations for medium- and heavy-duty trucks along Interstate 95, a major East Coast freight route. 

Maryland is also part of the Atlantic Conservation Coalition, joining Virginia and the Carolinas for a $421.2 million grant to be used to restore coastal habitats and peatlands, plant trees and improve forest management in Appalachia. 

The state’s slice of the two projects will total around $130 million, according to a press release from Gov. Wes Moore. 

“It isn’t enough to ask people to see themselves in the consequences of climate change — they also need to see themselves in the progress of climate action,” Moore said. “By moving in partnership with leaders at the local, state and federal levels, we are creating new green jobs, driving economic growth and building new pathways to prosperity for all, while protecting our planet.” 

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PJM Presents Revised Reserve Requirement Study Values

PJM presented its Planning Committee with revisions to the 2023 Reserve Requirement Study (RRS) to reflect the marginal effective load carrying capability (ELCC) analysis approach the RTO uses for most resource accreditation.

During the July 16 special meeting, PJM’s Patricio Rocha Garrido said the results of the reanalysis recommend increasing the installed reserve margin (IRM), which sets the targeted capacity level above expected loads, to 18.6%, up from the 17.6% stakeholders endorsed in the original study last year. The forecast pool requirement (FPR), which accounts for generator accreditation, would decrease from 11.65% to 9.37%. (See “Stakeholders Endorse Reserve Requirement Study Values,” PJM PC/TEAC Briefs: Oct. 3, 2023.)

The majority of resource classes saw a relatively minor change between their 2025/26 ELCC ratings and the 2026/27 target year for the 2023 RRS, with most increasing or decreasing within 2%. Gas combustion turbines saw the largest change, increasing 6% due to the number of CTs that have announced their deactivation. The overall impetus for rating changes across resource types was a small shift towards risk being concentrated in the winter.

The new values are being brought to the July 24 Markets and Reliability Committee and Members Committee meetings for a same-day first read and endorsement vote.

The marginal ELCC approach was one of several capacity market redesigns drafted through the critical issues fast path (CIFP) process last year and approved by FERC in January 2024. (See FERC Approves 1st PJM Proposal out of CIFP.)

The CIFP filing also revised three formulas central to the RRS analysis, including:

    • calculating the IRM by reducing total installed capacity (ICAP) by the capacity benefit of ties (CBOT);
    • determining the FPR by multiplying the IRM by the pool-wide average accredited unforced capacity (UCAP) factor, rather than forced outage rates; and
    • making the average accredited unforced capacity (UCAP) factor the ratio of UCAP to installed capacity (ICAP).

Stakeholders endorsed an earlier round of revisions to the RRS to reflect the impact of those design changes earlier this year. (See “Revised Reserve Requirement Study Values Endorsed,” PJM MRC/MC Briefs: March 20, 2024.)

Garrido said PJM also updated the assumed resource mix to include planned resources that submitted a notice of intent to offer into the 2026/27 Base Residual Auction. Gas generators that submitted dual fuel attestations were sorted into the corresponding ELCC classes, and resources that are scheduled to deactivate prior to the start of the delivery year were removed from the analysis. Generators expected to operate on reliability-must-run (RMR) contracts through the delivery year were included in the resource mix.

Paul Sotkiewicz, president of E-Cubed Policy Associates, said some RMR contracts do not require the generator to respond to PJM capacity deployments and should not be included in the resource mix.

“I think we’re actually overstating the amount of capacity that’s going to be there,” he said, adding it would distort market signals.

Sotkiewicz also questioned the assumption that outside capacity could be available for import during emergencies, saying that PJM has been consistently exporting during “emergency events and high load days.”

Garrido said PJM aims to model the system as it’s expected to exist in the target delivery year and that RMR resources should be included if they’re contracted to remain in operation. He stated any impact on the reliability requirement would be small.

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NERC Submits Final Performance Assessment

NERC has submitted its final performance assessment to FERC, reviewing a turbulent five years in which NERC managed “significant collaboration” among the ERO Enterprise, stakeholder groups and government authorities that “resulted in high and improving grid performance.” 

The performance assessment covers the years 2019 to 2023, a period that saw the outbreak of the COVID-19 pandemic, several major severe weather incidents, the emergence of serious cybersecurity threats to multiple aspects of the electric grid and the ongoing shift from traditional thermal generation to renewable resources.  

In the report, NERC sought to highlight “the continued viability and effectiveness of the ERO model” at using “broad technical expertise across diverse stakeholder groups and [ensuring] the independence and agility required to advance reliability in a changing world.” 

FERC regulations require NERC to file an assessment of its performance every five years as a prerequisite to recertifying it as the ERO, and the commission approved the last assessment in 2020. (See NERC Wins Another 5 Years as ERO.) Three years ago, FERC floated a proposal to shorten this timeline to three years, but the commission withdrew the proceeding this year after NERC and the regional entities warned that a three-year assessment cycle might not allow it to conduct the same level of review that the current schedule allows.  

NERC posted a draft of this report in April, seeking stakeholder comments. (See NERC Makes Case for Recertification in Performance Assessment.) The finished assessment, filed July 19, “reflects feedback from [regional entities], industry stakeholders and commission staff,” NERC said, along with input gathered from stakeholders throughout the assessment period.  

In the final assessment, NERC focused on its accomplishments through four key areas: 

    • Energy: addressing challenges arising from the changing resource mix, providing sufficient energy and essential reliability services, improving system performance during extreme weather and adding transfer capability; 
    • Security: addressing cyber and physical security risks; 
    • Agility: becoming nimbler in risk identification and standards development; and 
    • Sustainability: investing in automation, eliminating single points of failure, and strengthening the ERO Enterprise’s long-term stability and success. 

The organization devoted a significant part of the report to its internal development and efforts to modernize and streamline its committee structure. These include the creation of the Reliability and Security Technical Committee in 2020 through the combination of several existing committees and the Regulatory Oversight Committee in 2023 to give NERC’s Board of Trustees “committee-level oversight of standards development.”  

NERC also discussed its efforts to improve cyber and physical security across the ERO Enterprise. It said that during the assessment period, it “zeroed in on structural cybersecurity challenges” to the grid, including supply chain vulnerabilities and information technology and operational technology system monitoring.  

In addition, the ERO highlighted its work developing the Energy Information Sharing and Analysis Center (E-ISAC), which “continues to play a vital role in securing the [grid] through sharing information on cyber and physical security threats and vulnerabilities with industry members, the vendor community, and government and cross-sector partners.” 

NERC received a single comment from the Edison Electric Institute, which it posted as an appendix to the assessment. EEI suggested that “it would be helpful if the [final] assessment explored the use and value of [self-certification and spot checks as] alternatives to full on-site audit engagements.” In response, the ERO asserted that it “has increased its use of self-certification and spot checks to support compliance monitoring and intends to continue to significantly leverage those methods.” 

NERC said that during the first quarter of this year, only 15% of its compliance monitoring engagements used full on-site audits. Among such engagements, 77% used self-certifications, while 8% used spot checks. NERC pledged to “continue coordinating across the ERO Enterprise to support consistent rationale in tool selection through its risk-based approach to” compliance monitoring and enforcement. 

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Manchin-Barrasso Permitting Bill Would Give FERC Transmission Siting Authority

Sens. Joe Manchin (I-W. Va.) and John Barrasso (R-Wyo.) on July 22 introduced long-planned legislation on energy project permitting that would increase FERC’s power to approve new electric transmission.

The two senators are chairman and ranking member, respectively, of the Senate Energy and Natural Resources Committee, and their Energy Permitting Reform Act of 2024 is meant to accelerate the permitting process for critical energy and mineral projects of all types.

“The United States of America is blessed with abundant natural resources that have powered our nation to greatness and allow us to help our friends and allies around the world,” Manchin said. “Unfortunately, today our outdated permitting system is stifling our economic growth, geopolitical strength and ability to reduce emissions.”

After over a year of hearings and negotiations, Manchin added that he and Barrasso put together the bill that is meant to provide more certainty for energy and mineral projects going through the permitting process without bypassing protections for the environment and impacted communities.

“For far too long, Washington’s disastrous permitting system has shackled American energy production and punished families in Wyoming and across our country,” Barrasso said. “Congress must step in and fix this process. Our bipartisan bill secures future access to oil and gas resources on federal lands and waters.”

The bill would permanently end President Joe Biden’s pause on processing natural gas exports, which was already stayed by a federal court decision. (See Federal Judge Stays Biden’s LNG Export Application.)

On electric transmission, it would reform the existing backstop siting authority for interstate transmission lines and require interregional transmission planning.

The law would let transmission developers ask FERC for permission to site lines that are in the national interest, in a process similar to how the commission already sites natural gas pipelines. The lines have to be used in “interstate commerce,” which includes connecting offshore wind on the outer continental shelf to a state. States would still get one year to respond to siting applications before firms can go to FERC for siting.

FERC would have to find that such transmission lines are in the public interest, will cut congestion, benefit consumers, and provide improved reliability. The transmission lines FERC sites will have to be consistent with national energy policy and will enhance energy independence.

States, Tribes, private property owners, and other interested parties would have to have a reasonable opportunity to present their views and recommendations on transmission siting before FERC, the bill said.

FERC would also have to approve proposals for allocating the costs of such lines to beneficiaries of the resulting improved reliability, lower congestion, lower power losses, greater carrying capacity, reduced operating reserve requirements and improved access to cheaper generation. Customers who get no benefits from transmission lines cannot be allocated any of their costs.

FERC would be able to approve utility compensation to communities where transmission lines are located. The commission would have to prioritize using existing rights-of-way and the use of advanced conductors.

Interregional Planning Requirement

The bill also requires interregional transmission planning between neighboring transmission planning regions, including RTOs/ISOs and those set up to comply with FERC Order 1000’s regional requirements. The neighboring regions would need to use a common set of input assumptions and models on consistent timelines to pick projects based on a list of benefits around reliability and affordability.

Interregional plans would have to be submitted to FERC within two years of the process’ enactment and then every four years.

The bill specifically exempts ERCOT from the interregional planning and siting requirements.

Beyond the transmission provisions, it would require FERC and NERC to assess any future federal regulations that impact reliability and file comments with the agency working on them.

The Secretary of the Interior would be required to hold one offshore wind sale lease and one oil and gas lease sale per year from 2025 to 2029, which would not happen under current law.

The bill shortens the timelines before, during and after litigation for all federal authorizations on energy and mineral projects. Opponents would have to file lawsuits within 150 days after final agency action, courts would be required to expedite such cases, and agencies would have a 180-day deadline to deal with any remands from the courts.

Industry Groups Support Permitting Legislation

Americans for a Clean Energy Grid welcomed the permitting legislation, with Executive Director Christina Hayes saying it would bolster grid reliability by allowing for the timely deployment of transmission infrastructure.

“Of particular importance, FERC gaining plenary authority for transmission siting — just like it has for natural gas — would represent an important change in how the federal government permits transmission infrastructure in a timely and transparent manner,” Hayes said in a statement. “In combination with Order No. 1920 and the commission’s responsibility for ensuring reliability for customers, FERC is well positioned to center our nation’s efforts to build out the energy grid.”

Advanced Energy United also wants to see Congress move permitting legislation based on the Manchin-Barrasso bill.

“It has long been too difficult to build some of the critical energy infrastructure America needs, and this bipartisan proposal provides a good foundation on which to build a comprehensive package of legislative reforms,” AEU Managing Director Harry Godfrey said in a statement. “Both parties agree that unreasonable timetables and fragmented planning processes are making it too difficult to invest and build, providing Congress a unique opportunity to pass legislation that unlocks America’s innovative industries and improves grid reliability and energy costs for households and businesses.”

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SPP Markets and Operations Policy Committee Briefs: July 16-17, 2024

TULSA, Okla. — SPP’s Markets and Operations Policy Committee endorsed recommended revision requests from two stakeholder groups as part of the RTO’s effort to strengthen resource adequacy. 

A fuel assurance policy (RR621) that further emphasizes conventional resources’ performance during a season’s most critical hours and reduces the socialization of the planning reserve margin’s capacity allocation passed easily with 92% approval during the July 16-17 meeting. 

However, a second revision request (RR622) that establishes base planning reserve margins (PRMs) for summer 2026 summer and winter 2026-27 passed with three-fourths approval, but only after MOPC rejected an amendment to the motion that would have set the winter PRM at 36% instead of 33 (ironically, with only 33% approval). The summer PRM would be raised to 16% from 15. 

During its June meeting, the Resource Energy and Adequacy Leadership (REAL) Team approved a 36% PRM over stakeholders’ concerns that the requirement was too soon and unrealistic to meet. (See SPP’s REAL Team Approves Base PRMs, Sufficiency Value Curve.) 

SPP staff pointed out that the 33% PRM brought forward by the Supply Adequacy Working Group (SAWG) technically meets a 1-in-10 reliability standard; they intend to bring both PRMs to state regulators and the RTO’s board during their August meetings. 

Omaha Public Power District’s Colton Kennedy, the SAWG’s chair, said the PRM’s requirement is intended to ensure that load-responsible entities are appropriately planning for capacity in both seasons. SPP’s 2023 loss-of-load study was the first in which staff directly analyzed seasonal risk beyond summer; it found a 15% PRM would not meet a 1-in-10 LOLE in either season. 

“The complexity, the scope and the extent of questions by SAWG members by far surpassed all previous studies,” Kennedy said. “We didn’t previously have that in the historical [record] with an [LOLE] model. The inclusion of correlated outages, the inclusion of winter peak variability are the driving factors and are very reasonably supported. Very demonstrable, very objective in the work that we’re doing.” 

Advanced Power Alliance’s Steve Gaw (third from left) discusses issues with other renewable interests. | © RTO Insider LLC

He said SPP staff was very consistent with the 36% winter PRM recommendation, which created debate and discussion within SAWG related to the transition to a higher PRM by entities without sufficient capacity. 

“They’re concerned about the generation interconnection process and being able to study resources and get them through this process [quickly],” Kennedy said. 

Regardless of the final number, individual entities will have to step up, said Bill Grant, formerly with Southwestern Public Service and back on MOPC as a representative for XO Energy. 

“The resources are out there. That doesn’t mean that there’s not some entities that have to scramble to meet this requirement,” Grant said. “Remember, if you approve these numbers, you are impacting utilities’ ability to get generation connected before any individual changes. There is an impact, and it’s kind of hidden.” 

“For a regulated investor-owned utility, there’s not enough time to get new generation in,” Oklahoma Gas & Electric’s Brad Cochran said. 

The fuel assurance policy stems from the 2021 winter storm, when SPP was forced to shed load for the first time in its 83-year history. Casey Cathey, the grid operator’s engineering vice president, said several heavily vetted approaches to fuel assurance failed before stakeholders coalesced around what he said is effectively “somewhat of a weight towards conventional resources during capacity critical hours in the winter season, in particular.” 

Under the policy, an “after-the-fact” weighting will be applied to performance-based accreditation resources, based on critical system periods. The mechanism is designed to encourage increased performance by those conventional, or thermal, resources by quantifying their contributions to system reliability.  

Noting that there can be a 100-degree differential between the northern and southern states in SPP’s footprint, Cathey said one thought holds that nonperforming resources should be targeted for their failures rather than raising the PRM. 

“This revision request and this policy [help] directly address that socialization of planning reserve margin,” he said. “So rather than kind of go down this path of potentially having separate zonal planning reserve margins … this particular revision request and policy [help] to address that in a different way such that the northern resources that may already have winterization during extreme conditions and perform during those types of extreme conditions do not necessarily have to carry additional planning reserve margin accredited capacity beyond where the regional risk is.” 

DISIS Waivers Endorsed

The committee endorsed staff’s proposal to file waiver requests with FERC that delay the start of the 2024 generator interconnection (GI) study’s first phase and pause the opening of the 2025 study cluster, easing conflicts with the RTO’s effort to clear the GI queue’s backlog and transition to a new planning process. 

SPP staff said delaying the 2024 definitive interconnection system impact study (DISIS) cluster’s first phase will save customers up to $3 million by avoiding additional studies and will allow more accurate information for customer decisions. The 2024 DISIS first phase would begin after the 2023 DISIS second phase’s restudy is completed and posted in August 2025; without the waiver, it would start before the second phase of the 2022 and 2023 clusters and likely lead to unplanned restudies, staff said. 

Natasha Henderson, senior director of grid asset use for SPP, said that if the 2024 DISIS Phase 1 began on schedule, it would assume $35 billion of transmission upgrades would be built from previous studies. “We know that’s not likely,” she said. 

SPP’s current timetable for transition to a consolidated planning process. | SPP

Pausing the 2025 DISIS’ open window will allow “additional optionality” for the grid operator’s transition to the consolidated planning process (CPP), scheduled to begin in late 2026 after a transition period. SPP said opening the 2025 DISIS would mean the cluster’s generation would “significantly” overlap with the CPP’s transition study and first annual assessment. 

Golden Spread Electric Cooperative’s Mike Wise, who arrived for the MOPC meeting from the NARUC Summer Policy Summit, said FERC Chair Willie Phillips’ comments made it apparent he favors quickly connecting generation and building out transmission to support the new resources. Wise said words such as “delay” and “waiver” send the wrong message and could make commission approval difficult. 

Staff said they believe they have agreed on messaging that should gain FERC’s signoff if the waivers are submitted as a package. They are also planning to schedule a meeting with commission staff. 

“I think it’s going to be important that we convey the fact that this is not a pause,” Cathey said. “The message here is we can do things a little bit more efficiently. We’re not asking to pause the DISIS … it’s to try to accelerate and actually reduce the churn of the restudies.” 

MOPC Chair Alan Myers struggled to get a second for the waiver requests from members who had previously expressed concerns about not having enough time to consider the proposal. Eventually, Evergy’s Derek Brown bravely raised his name tent to second the motion. It passed with 80.6% approval. 

FERC’s approval of the waivers would enable the timely completion of backlog studies and allow time to further develop CPP. SPP in June posted its second study of the DISIS 2017-002 cluster, clearing the way for the 2018 DISIS’ second restudy. 

The grid operator has 416 requests in the GI queue totaling about 84 GW in proposed capacity. That’s down from the original backlog of 1,139 requests for 221 GW of capacity. The backlog will be cleared when the 2023 cluster’s second restudy is posted in September 2025. 

SPP staff and stakeholders have been working on the CPP and its associated cost-sharing mechanism since 2021. (See SPP’s Consolidated Tx Planning Just Beginning.) 

MOPC in April approved a task force’s recommended policy for the CPP’s entry fee. A transition study to the new process, comprised of SPP’s current 20-year assessment and the first annual CPP analysis, is slated to begin this year and will set the first $/MW entry fee. The study is intended to align technical assumptions and scopes, yielding a “more robust” cost-sharing model that sets a specific frequency to avoid late charges. 

SPP Adds Context on April Event

SPP told MOPC members that it is recommending several changes to its operational procedures following an April emergency event in Southwestern Public Services’ (SPS) New Mexico region that resulted in a 150-MW load shed lasting about two hours. (See “SPP, SPS Reviewing April Outage,” SPP Board of Directors/MC Briefs: May 7, 2024.) 

Staff said they saw contingencies begin to develop April 28 as wind dropped from 16 GW to nearly 5 GW and load began to increase. Derek Hawkins, the RTO’s director of system operations, said that shortly after 7 p.m., an exceedance occurred on an SPP-SPS tie line.  

Jarred Cooley, Southwestern Public Service, offers comments on April load shed event. | © RTO Insider LLC

Hawkins said his operators exhausted all available options within the constrained time frame in trying to address potential instability and were forced to shed load because of “immediate circumstances” and “evolving conditions.” SPP directed SPS to drop 150 MW of load at 7:43 p.m. to mitigate the unsolved contingencies. Load was restored by 9:41 p.m. 

Hawkins said a post-event analysis revealed the importance of clear communication, robust coordination agreements and improved data integrity practices. He said operators were rebuffed twice when requesting energy from switchable units with ERCOT, which was dealing with its own tight conditions. 

The recommendations include emphasizing timely and clear communications, evaluating improvements to operating procedures with ERCOT, and discussing coordination plans with neighboring entities.  

SPS’ Jarred Cooley, director of strategic planning, said his own conversations with Hawkins and C.J. Brown, SPP’s senior director of system operations, policy and performance support, were beneficial and useful for the entire RTO footprint. 

“We’ve met multiple times, had pointed, real in-depth discussions, and those were really useful for where we are with the recommendations,” Cooley said. “Obviously, it’s up to all of us to help support staff to have the tools that they need in real time so they act appropriately and that we can ensure good reliability for the system.” 

Storage Self-charging Change

Members approved a pair of tariff revisions recommended by the Market Working Group related to storage and system dispatch. 

RR635 would ensure market storage resources’ self-charging is identified and charged appropriately. The MWG said the change will increase alignment with FERC Order 841’s requirements for identifying and charging equitably for self-charging and will ensure that MSRs are subject to unreserved use when self-charging. 

The FERC order found that energy storage resources should not be charged transmission costs when providing a market service. SPP currently dispatches MSRs based on economics and resource parameters; if the MSR is providing a market service, no transmission service is required. 

RR628 would dispatch the system based on the system’s true obligation and price by removing load shed and emergency purchases. It would restore the load shed amount’s requested congestion prices from each forecast area to reduce the effects. 

The RR635 and RR628 passed with 90 and 95% approval, respectively. 

The unanimously approved consent agenda included nine other tariff changes that, if necessitating approval from the Board of Directors, would: 

    • RR595: Allow make-whole payments for instructed real-time incremental energy costs for day-ahead market committed and self-committed resources for offers under FERC Order 831 (adds changes after original MOPC approval in April 2024). 
    • RR602: Add process structure, tracking and improved criteria for evaluating potential transmission reconfigurations. 
    • RR610: Allow third-party cost estimate information and/or engineering judgment when creating a conceptual cost estimate to be used during a project study. 
    • RR615: Changes the RTO’s credit policy to introduce a portfolio-level mark-to-auction mechanism within the transmission congestion rights collateral requirement, thus mitigating default risk by updating collateral requirements to reflect the portfolio’s most recent valuation. 
    • RR619: Add application programming interfaces as an acceptable submittal process. 
    • RR623: Deploy a compensation mechanism to incentivize continued operation of resources whose studied retirements have identified one or more network upgrades as necessary to address reliability impacts that are unable to be completed prior to the projected retirement date. A unique contract will be developed for each retiring resource that details the eligible costs and a new schedule will be created detailing the allocation of the contract costs. 
    • RR627: Clarify that the turnaround ramp rate factor applies to energy and contingency reserve. 
    • RR631: Ensure consistent governing language and address corrections to previously published settlement calculations in RR613, RR556, RR578 and RR596. 
    • RR633: Clarify how SPP recalculates real-time balancing market outages and extends the repricing notifications. 

The consent agenda also included the retirement of a remedial action scheme near Rapid City, S.D., upgrades to terminal equipment at one 115-kV and two 345-kV substations, and cost increases for a Western Farmers’ and an Omaha Public Power District’s projects.

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FERC Approves Icahn Deal for AEP Board Seat

FERC on July 19 approved granting voting rights to a member of American Electric Power’s board of directors who was appointed by investment firm Icahn Group (EC24-60).

The commission is required by Federal Power Act Section 203 to approve appointments of investment company officers to public utilities’ boards. AEP told FERC that it had agreed in February to add Hunter Gary, Icahn senior managing director, to its board, but that he was unable to vote until the commission gave its approval. Icahn, founded and controlled by investor Carl Icahn, was also able to appoint a new independent director and a non-voting observer to the board under the deal.

The commission found the arrangement met its rules around mergers; would not have any impact on competition, rates or regulation; and would not result in cross-subsidization.

Public Citizen filed a protest against the deal, arguing that the non-voting board members had already forced a change of control at AEP with their role in the “involuntary termination” of former CEO and board Chair Julie Sloat. (See Interim CEO Fowke Explains AEP Leadership Change.) The consumer group argued that FERC should find that the deal and subsequent firing of Sloat violated Section 203, which also requires public utilities to seek commission approval before any attempted change in control.

AEP argued that it met FERC’s public interest requirements, and that Public Citizen’s “inflammatory and unsupported allegations” should be dismissed. Icahn Group itself did not execute the removal of Sloat, which was in compliance with the law and the company’s bylaws, AEP said.

FERC agreed with AEP, saying the issues Public Citizen raised “do not impact the factors addressed by the commission in evaluating” such deals. “Public Citizen does not present other evidence that the proposed transaction fails to satisfy our public interest criteria,” it said.

But the commission did chide AEP for its late request, filed March 15, after Gary had already been appointed.

“Contrary to the requirements of FPA Section 203, AEP failed to file a timely request for approval of the appointment of the Icahn Group designee to the AEP board,” FERC said. “AEP is reminded that it must submit required filings on a timely basis or face possible sanctions by the commission.”

The order drew a concurrence from Commissioner Mark Christie, who agreed that the application met FERC’s policies and regulations, but that investors’ impact on public utilities is a growing area of concern that might warrant some changes in those rules.

Christie has said in other proceedings that utilities are not typical for-profit, shareholder-owned companies, and it is essential for regulators to ensure investors’ interests do not conflict with utilities’ public service obligations.

“Where there is the potential for a conflict — and there always is — it is the commission’s responsibility, under Section 203, to ensure that transactions are consistent with the public interest,” Christie said. “In my view, this must involve balancing consumer protection and potential impacts to reliability with the interests of investors in addition to evaluating traditional market power concerns.”

Christie argued that the only reason investors seek board seats on public companies is to exert influence on their decision-making and actions. Even directors “independent” of firms like Icahn take actions to benefit utility shareholders, including those who got them the position, he said.

“Investor influence on public utilities and public utility holding companies continues to grow, and in ways that may conflict with public utility service obligations. It is incumbent on the commission to account for and address this influence,” Christie said. “These issues are ripe for action, and I look forward to continued consideration of them with my colleagues.”

Commissioners Lindsay See and Judy Chang, who recently joined FERC, did not participate in the order.

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California PUC Proposes Procurement of Advanced Clean Energy

The California Public Utilities Commission proposes to authorize procurement of emerging clean energy technologies with a combined nameplate capacity of up to 10.6 GW.

The CPUC issued the proposed decision (Rulemaking R.20-05-003) on July 19 and will consider it as soon as it its Aug. 22 business meeting.

The decision focuses on long lead-time resources — emerging technologies that have yet to achieve economies of scale and presently are not being procured by individual load-serving entities (LSEs) in amounts sufficient to achieve cost reductions.

It would authorize procurement starting in 2026 of up to 1 GW of multiday long-duration energy storage (LDES) and up to 1 GW of 12-hour LDES to come online in 2031-2037; procurement starting in 2027 of up to 1 GW of enhanced geothermal systems to come online in 2031-2037; and procurement of up to 7.6 GW of offshore wind to come online in 2035-2037.

Lithium-ion batteries and pumped storage hydropower would not qualify for either category of LDES.

The proposal stems from Assembly Bill 1373, which was signed into law in 2023 and seeks to make it easier to procure emerging technology energy resources through centralized procurement. The Division of Water Resources would lead the procurement process.

Increasing clean energy supplies would help the state reduce greenhouse gas emissions and maintain a reliable power supply, a CPUC fact sheet states.

Other details:

    • Future central procurements would be assessed regularly within the integrated resource planning (IRP) process, and may consider other technologies, as well.
    • The 10.6 GW is a ceiling; the CPUC could follow through with smaller procurements or none, if costs are too high.
    • To support these efforts, the proposal suggests exploring funding streams other than customers’ electricity bills.
    • The longer time frame allows the opportunity to achieve cost reductions through scaling of these new technologies; while they may cost more than the dominant commercial resources that LSEs procure today, these newer technologies frequently are part of the state’s least-cost planning analysis.
    • The cost and risks of these centralized procurements would be spread among all LSEs — they would not be permitted to opt out.
    • Publicly operated utilities (POUs) may opt in, however, and the CPUC hopes they would, because they serve roughly 25% of customers in California and it is “inherently discriminatory and unfair” for them to benefit from the investments paid for by other Californians but not contribute themselves.

The CPUC said in its proposal it’s attempting to spur a market transformation, in the same manner that early investor-owned utility ratepayer investments in solar, onshore wind and battery storage in California helped bring down the cost of those technologies.

“Herein,” they write, “we are explicitly asking LSE ratepayers, through the central procurement mechanism, again to take on the responsibility for making an initial investment in several promising emerging technologies that may prove to be important for achieving [Senate Bill 100 greenhouse gas emission] reduction goals in the electricity sector, as public goods on behalf of all ratepayers under our IRP purview, regardless of their specific LSE.”

They add: “But right now, the resources we are selecting are inherently more expensive and would be unlikely to be selected in volumes high enough to lead to market transformation by an individual LSE in a least-cost procurement solicitation.”

The higher figure for offshore wind — up to 7.6 GW, all of it the more complex and expensive floating-turbine variant — is intended to show the CPUC’s interest in building a still-developing technology and nonexistent U.S. industry as a resource for California. Also, 7.6 GW is the maximum transmission capacity for the Morro Bay and Humboldt offshore wind buildout.

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DC Circuit Finds for SPP in Wind Farm Dispute

The D.C. Circuit Court of Appeals on July 19 rejected a wind farm’s challenge of FERC’s decision to allow SPP to charge more than $100 million for upgrades needed to connect the facility to the grid operator’s system.

In a unanimous ruling, court found the commission’s decision to assign mitigation costs to Tenaska Clear Creek Wind to be reasonable because the project caused operational issues for SPP that would not have existed but for the facility itself (22-1059).

Clear Creek’s appeal stems from a September 2022 order in which FERC ruled that SPP correctly assigned the facility about $66 million in network upgrade costs during a restudy of a Missouri wind project. The commission denied in part a rehearing request in December 2022, although it directed the RTO to restudy the project with different planning models. (See “Split Decision for Tenaska in SPP Complaint,” FERC Rules in Three SPP Disputes.)

The network upgrade costs eventually were set at $102 million.

The appeals court said it was “unpersuaded” by Clear Creek’s challenges in its review request. The wind farm argued that FERC’s order violated its cost-causation principle; that SPP’s cost allocation was inconsistent with the commission’s “but for” policy; and that FERC ignored the RTO’s interconnection study and allocation practices used firm service when the facility was not taking service or seeking deliverability.

The D.C. Circuit said FERC was able to show its finding “comports with its precedent and the cost-causation principle,” thus proving the order was based on reasoned decision-making. It said the commission’s reasoning was “simply that the project caused operational issues for SPP that did not arise prior to its operation, so it is reasonable to assign the costs of mitigation to Clear Creek.”

The court also concluded SPP’s methodology aligns with the “but for” principle and the commission’s determination was consistent with “reasoned decision-making.”

“Substantial evidence supports the commission’s determination here that the disputed upgrades were not intended to address regional transmission planning, as opposed to interconnection, needs,” the appeals court wrote.

Finally, the court said FERC “reasonably” explained why Clear Creek couldn’t meet the burden of demonstrating that SPP’s use of firm service, or network resource interconnection service (NRIS), was unjust, unreasonable, unduly discriminatory or preferential. It said the commissioned identified precedent that was just and reasonable and that it “expertly pointed out” how Clear Creek’s NRIS request supported SPP’s justification for conducting its interconnection study at the NRIS level.

Clear Creek is a 242-MW facility that is interconnected to SPP neighbor Associated Electric Cooperative, Inc.’s transmission system. The upgrade costs were assigned as part of an affected system study.

The facility became operational in May 2020.

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NYISO BIC/OC Briefs: July 2024

Ancillary Service Manual Updates

NYISO’s Business Issues and Operating committees met last week to discuss and vote on updates to the ISO’s Ancillary Services manual. Both committees approved the proposed revisions unanimously. 

The revisions consist of changes to the Voltage Support Service section of the manual. “Qualification Package” was given its own subsection with clarifying language under section 3.2, and “Identical Treatment Units,” “Testing Periods” and “Testing Coordination” were broken out into their own subsections under section 3.6. 

SIS for Cryptomining Expansion

The committee also unanimously approved the system impact study scope of a project to expand Digihost Technology’s cryptocurrency mining facility in North Tonawanda. 

The facility has drawn fire from local residents for noise and air pollution. On July 16, two days before the OC’s meeting, the city’s Common Council approved a two-year moratorium on new data center operations and the expansion of existing facilities. 

The controversy did not come up during the committee’s meeting. Digihost has proposed an in-service date in December, according to the scope. 

The OC also approved five interconnection study reports, most of which were for solar and wind projects. 

Market Reports for June

Rana Mukerji, NYISO senior vice president of market structures, presented the BIC with the monthly market performance report for June. 

The average locational-based marginal price was $39.68/MWh, exceeding both May’s $28.36/MWh and the $29.85/MWh for June 2023. Day-ahead and real-time load-weighted LBMPs were both higher compared to the previous month. The average daily send-out of 455 GWh/day is also up from last month and the year before. And the average year-to-date monthly cost of $40.78/MWh is 4% higher than last year’s. 

Aaron Markham, NYISO vice president of grid operations, presented the OC with the monthly operations report. He said high temperatures in June resulted in higher-than-average demand for the month. 

“Peak load was mitigated by demand response activations,” Markham said. “The heat moved through the state. It was hotter upstate early in the period, and then the heat moved downstate. Not having simultaneous high temperatures across the state mitigated the peak load.” 

Peak load for the month occurred June 21 at 28,245 MW, about 90% of the baseline forecast, Markham said. 

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CAISO Kicks off Storage Bid Cost Recovery Stakeholder Initiative

Batteries may be receiving excessive or inefficient bid cost recovery (BCR) payments in CAISO, an issue that could be exacerbated by the ISO’s recent move to increase its soft offer cap to allow for higher bids by storage resources.  

The issue was highlighted by CAISO’s Department of Market Monitoring and Market Surveillance Committee on July 8 during the first workshop of a new Storage Bid Cost Recovery and Default Energy Bids initiative.  

CAISO staff launched the effort to address concerns related to a rule change pending before FERC that would alter ISO rules related to FERC Order 831 by raising the soft offer cap from $1,000/MWh to $2,000/MWh, in part to accommodate opportunity costs and bidding strategies for storage resources. (See CAISO, WEIM Boards Approve Proposal to Raise Offer Cap.) 

“BCR, as [with] many other elements of the CAISO tariff and the market, was initially designed with a thinking of conventional assets,” Sergio Dueñas Melendez, storage sector manager at CAISO, said during the workshop. “This was something that was not developed in a manner or outlined with potential new technologies that could be integrated into the CAISO market en masse, particularly with storage.” 

BCR is intended to eliminate the incentive for resources to add a risk premium to their offers, which drives up bids, leading to higher overall energy costs and inefficient market outcomes. But the DMM noted that BCR payments to storage resources have materialized — specifically related to the buy- and sellback of day-ahead schedules — despite not being aligned with the intent. 

“Assets might be incented to bid and operate in the [real-time] market in a manner that would trigger buy- or sellbacks of their [day-ahead] energy schedules in order to capture outsized BCR payments,” Dueñas Melendez said. 

Generating units can receive BCR payments if total market revenues earned throughout the day don’t cover the sum of the unit’s acceptable bids, which includes bids for startup, minimum load, ancillary services, residual unit commitment availability, day-ahead energy and real-time energy. Because batteries don’t have startup, shutdown, minimum load or transition costs, they “lack the traditional drivers of BCR,” according to a DMM report on battery storage from July 2023. 

Batteries, however, can be subject to BCR because of their opportunity costs, incurred when a battery discharges during a particular time of the day, usually from weather-related grid conditions. Discharging energy during low-demand hours, for example, could preclude discharging during hours of high demand, and the difference in market prices between low and high demand hours represents the opportunity cost of discharging in lower-priced hours. 

“In the past, battery energy storage has received disproportionate amounts of BCR,” Dueñas Melendez said. “In their comments, throughout the Order 831 process of bidding above the soft offer energy bid cap, DMM highlighted once more that those changes could exacerbate the challenges that they’ve identified regarding BCR. This perspective was also echoed by the Market Surveillance Committee, who recommended that ISO staff engage with stakeholders to review and restructure current BCR provisions for batteries, particularly given the changes around Order 831.” 

The July 2023 report highlighted that in 2022, batteries received nearly $30.5 million in payments, primarily in the real-time market, despite making up only 5% of CAISO’s capacity. 

‘Aggressive Timeline’

Stakeholders expressed confusion about the root of the problem, specifically related to why batteries, in some cases, don’t have the state-of-charge to fulfill a schedule. 

“What caused the real-time state-of-charge to put us in the position of a buyback or a sellback? Was it the result of price or modeling issues? Was it the result of not co-optimizing in real-time ancillary services? Was it because of bidding behavior, and are there rules that need to be put around that?” asked Don Tretheway, managing director of EES Consulting and representing the California Energy Storage Alliance. “I don’t think making these high-level statements helps anybody in terms of trying to understand where the solution is, especially given the speed at which you plan to make these changes.” 

Stakeholders also expressed concern about the “aggressive timeline” of the initiative, which Dueñas Melendez said is on an expedited schedule because of its “sensitive nature.” Track 1, dedicated to refining BCR provisions for storage, initially gave stakeholders only three days to submit comments, but after significant pushback, the ISO extended the deadline to July 18. 

“The fact that CAISO committed to working on this stuff in 2022 and didn’t do anything for two years, and now we’re going to do this in two months, it seems a little inconsistent with comments made to FERC about taking this as a priority,” Tretheway said.  

Alva Svoboda, principal of market design integration at Pacific Gas and Electric, echoed the concerns.  

“This is obviously a very aggressive timeline, and in my mind, it implies only one kind of solution feasible for CAISO … which is to essentially trigger periods in which batteries are not eligible for BCR and hence are completely unhedged against any price outcome in the market.” 

Rather than meeting to discuss the straw proposal scheduled for publication July 17, the ISO added an additional workshop July 22 to continue working through the issue with stakeholders.