FERC on Wednesday approved a PJM proposal to add about $925 million in transmission projects to its Regional Transmission Expansion Plan (RTEP), the bulk of which would address the retirement of the 1,295-MW Brandon Shores generator outside Baltimore (ER23-2612).
The 25 projects the commission signed off on include the $796 million Grid Solutions Package, which was determined to be an immediate-need reliability project to address the Brandon Shores deactivation, as well as $134 million in changes to existing projects — namely the New Jersey State Agreement Approach (SAA) projects — and a $4.69 million cancellation of a previously approved project.
PJM and Talen Energy are in talks to arrive at a reliability-must-run contract to extend Brandon Shores’ operations beyond the June 1, 2025, requested deactivation date; the approved RTEP projects have an in-service date of Dec. 31, 2028.
PJM’s proposal was protested by the Maryland Public Service Commission, the state’s Office of People’s Counsel and the Organization of PJM States Inc. (OPSI), each of which pushed against including the Grid Solutions Package. They argued the RTO improperly designated it to be an immediate need and therefore not holding a competitive process for a solution. The OPC asked FERC to reject the proposal and direct PJM to conduct a “transparent and thorough review of alternatives as well as to engage in a competitive project proposal window, where feasible, for some or all the segments of the Grid Solutions Package.”
The commission determined its review of cost allocation filings is limited to whether the relevant tariff language has been followed, which it found that PJM had, making the protests out of scope. Responding to the argument that OPSI and the PSC made that PJM’s planning process doesn’t adequately account for potential reliability risks posed by generation deactivations, the commission said the RTO and stakeholders are making encouraging steps to consider changes to generation deactivation and transmission planning processes. In recent months, stakeholders have begun discussions at the Deactivation Enhancements Senior Task Force and the Long-Term Regional Transmission Planning Workshop.
Commissioners Mark Christie and Allison Clements each concurred with the order, agreeing the protests were out of scope but noting they raised important issues.
Citing PJM’s “Resource Retirements, Replacements & Risks” report — which raised concerns there will be a significant number of generation deactivations through 2030 that will not be met by currently planned resources — Clements questioned whether there are additional retirements looming that will put ratepayers in a similar bind. She suggested PJM’s Multi-Driver Project planning process could be used to be more proactive and meet potential reliability risks posed by generation deactivations while providing economic benefits and keeping costs low.
“I wonder whether PJM’s extensive reliance on immediate-need reliability solutions such as those at issue in this proceeding is in part a symptom of the failure of the region to carry out proactive, scenario-based multi-value planning,” Clements wrote. “The record in response to the commission’s regional transmission planning proposal suggests that while some local and reliability needs may persist even with greater use of proactive planning, proactive multi-value planning processes can be leveraged to replace or defer reliability projects that would otherwise be needed, at significant value to customers.”
Christie wrote that the growth of state policies and legislation prompting the shuttering of generators raises cost allocation questions for neighboring states in the RTO that may be saddled with a portion of the cost to build transmission necessary to meet demand in the absence of those units. He suggested that such deactivations may be better viewed as public policy projects akin to the transmission being built to interconnect offshore wind under the New Jersey SAA.
“If the resulting transmission projects under protest in this RTEP filing are caused more by Maryland’s policy choices than by organic load growth and economic resource retirements, then a salient question that may be asked is whether these transmission projects are more accurately categorized as public policy projects, essentially the same as the transmission upgrades caused by New Jersey’s offshore wind projects,” he wrote.
While the concerns raised in the protests are valid, Christie said the commission’s hands were tied by the need to prevent potential reliability violations once Brandon Shores goes offline.
“So while I am deeply sympathetic to the concerns expressed by the Maryland PSC, OPSI and the OPC as to the impact on consumers, there is really no practical choice for us but to approve this filing. We simply cannot risk the potentially catastrophic consequences laid out by PJM in its filing. But the states in OPSI, as well as all states in multistate RTOs, may want to consider the broader questions this filing raises, as I have described above,” he wrote.
The Grid Solutions Package comprises a new 500-kV line between the Peach Bottom and Graceton substations and a 230-kV line from Graceton to a new 230-kV Batavia Road substation outside Baltimore. The project also includes one new 500-kV substation. The PJM Board of Managers approved the projects during its July 10 meeting.
The Brandon Shores deactivation is also being addressed by projects included in PJM’s recommended package of proposals submitted during the third competitive window of the 2022 RTEP, which is scheduled to go before the Transmission Expansion Advisory Committee for a second read Dec. 5. The $5 billion proposal also would address increasing data center load in Northern Virginia. (See PJM Recommends $5B in RTEP Transmission Projects.)
A California man has pleaded not guilty in federal court to charges of damaging two transformers belonging to Pacific Gas and Electric in December 2022 and January of this year.
He faces a sentence of up to 50 years in prison and a $500,000 fine if convicted, the Justice Department said.
Peter Karasev, a 36-year-old resident of San Jose, was arraigned in the U.S. District Court for Northern California on Nov. 7, according to a press release, after a federal grand jury indicted him Oct. 19 on two counts of damaging energy facilities and one count of using fire and an explosive to commit a felony. Court records show Karasev was remanded to custody following the arraignment. His trial is scheduled to begin Jan. 30, 2024.
“The FBI is laser-focused on protecting the essential infrastructure that Americans rely on every day, and we and our partners … will use every lawful means to hold anyone who targets that infrastructure accountable,” FBI Director Christopher Wray said in the release.
According to the indictment, Karasev carried out his attacks on Dec. 8, 2022, and Jan. 5, 2023, in San Jose. The first incident occurred at a PG&E facility near the Westfield Oakridge shopping center; the second occurred near Santa Teresa High School about three miles away. Both occurred during the early morning hours in commercial areas occupied by stores and businesses, the department said.
Prosecutors said Karasev built, planted and ignited the explosives involved in each of the alleged attacks himself. Along with “experimenting” with explosives, the government said he also was making methamphetamine in his home during the months before the incidents. His alleged actions caused more than 1,500 San Jose homes and businesses to lose power.
San Jose Police Department officers arrested Karasev “on related state charges” in March, the government said, finding in his home multiple homemade explosive devices “in varying stages of completion,” 300 pounds of explosive precursor materials, firearms and other weapons, and “other hazardous substances.” According to media reports, the state charges include interfering with power lines, arson and child endangerment for conducting illegal activities with three children at home. He was transferred to federal custody to face the indictment.
Each count of damaging a power facility carries a maximum penalty of 20 years in prison, a $250,000 fine and three years of supervised release, while the charge of using fire and explosives carries a mandatory minimum penalty of 10 years to be served consecutively to any imprisonment ordered for the other two charges.
“Damaging our region’s critical infrastructure endangers innocent victims — including our most vulnerable citizens such as the elderly and the sick — and we will not tolerate it,” U.S. Attorney Ismail Ramsey said. “We will vigorously prosecute any malicious attempts to disrupt the power grid.”
Officials have not indicated what Karasev’s motive for attacking the substations might have been. Recent years have seen an increase in attempts to damage electric facilities, with some successful. The attackers’ reasons vary widely; some allegedly believed interfering with electrical service would serve their political ends, as with the group charged in February 2023 with planning to spark a race war by attacking the electric grid in Baltimore. (See Feds Charge Two in Alleged Conspiracy to Attack BGE Grid.)
Other incidents have more prosaic motivations, as with the rifle attacks on substations in Washington state last Christmas. In May 2023, one of the men charged in those attacks pleaded guilty, claiming he and his accomplice wanted to disrupt power as part of a burglary plot against local businesses and ATMs. (See Wash. Sabotage Suspect Pleads Guilty.)
FERC on Thursday rejected parts of a deal Tri-State Generation and Transmission Association had filed to allow the Colorado-based United Power to terminate its membership with the cooperative (ER23-2822).
The firm had signed up to get at least 95% of its needs met by Tri-State through 2050 under the wholesale electric service contract, and its bylaws provide that members seeking early termination must satisfy all of their contractual obligations to the wholesale co-op. Members have to give two years’ notice and make a contract termination payment before they leave.
FERC rejected an earlier attempt from United to conditionally withdraw in April 2022, and just eight days later, the Colorado co-op submitted a nonconditional two-year notice that it still wished to get out of the contract. (See FERC Rejects Conditional Withdrawals from Tri-State.)
Tri-State and United did not agree on the amount of the exit fee and its true-up, the latter of which is meant to protect both sides from over- and under-payments. They also disagreed on whether Tri-State getting the payment was a precondition for United to withdraw and whether Tri-State could terminate the withdrawal agreement if United fails to pay on time.
United argued that the fee is excessive and that because it is based on a pending proposal from FERC, true-ups could take years to come back to it as the case works its way through appeals. Even if FERC quickly approves a calculation leading to a lower fee, United claimed it may not get a refund because of risks to Tri-State’s finances.
FERC found that Tri-State had not proven the withdrawal agreement to be fully just and reasonable, basing that on some of the provisions under the deal.
Tri-State did not demonstrate that it is just and reasonable under the Federal Power Act to automatically terminate the withdrawal agreement and rescind United’s notice of withdrawal to the extent the generation and transmission co-op is found to be outside of FERC’s jurisdiction, which was the case before September 2019 — a decision that has been reaffirmed in court.
“We find that Tri-State has not demonstrated that it is just and reasonable under the FPA to automatically terminate the withdrawal agreement and to automatically rescind United Power’s notice of withdrawal based on a change in jurisdictional status,” FERC said. “We further find that Tri-State has not supported the provision stating that the parties ‘mutually agree’ to rescind the withdrawal notice given that United Power has not agreed to this provision.”
FERC agreed that the deal could be terminated for failure to pay, but it rejected language that would have denied United any chance to fix any late or deficient payment.
The commission agreed that United will have to pay the exit fee that is effective on April 24, 2024, when it is set to withdraw from Tri-State, which currently would be nearly $1.6 billion.
However, the withdrawal penalty calculation method could be changed by FERC in that pending case before that date. The deal also gives 90 days after April 24 for a FERC order on the new method, which would lead to a true-up to the new fee.
New Jersey’s Board of Public Utilities has released its long-awaited dual-use solar proposal designed to incentivize 200 MW of capacity in a three-year pilot program, with the first solicitation of the pilot to be launched in the middle of 2024.
The proposal anticipates the first project selection taking place in the fall of 2024 with the award of 30 MW of dual-use capacity. The proposal, which was released Nov. 10, calls for the award of 70 MW in the second year and 100 MW in the third year.
“Lessons learned from the pilot program and relevant research are intended to serve as the basis for the development of a permanent dual-use program,” the proposal says. And the pilot could be extended by two more years if necessary.
The BPU will hold a public hearing on the dual-use (also known as agrivoltaics) proposal Nov. 29 and will accept written comments until Dec. 13.
The proposal comes amid concerns in New Jersey, as in other states, that farmland could be lost to solar projects as struggling farmers find clean energy more lucrative than cultivating the land. Farms in New Jersey are under pressure as the development of residential and warehouse projects encroaches on rural areas, and dual-use projects are a way to combine farming and solar use, and so preserve farmland. (See NJ Solar Push Squeezes Farms.)
“Dual-use solar can provide farmers with an additional stream of revenue, contributing to farm financial stability and allowing for continued agricultural or horticultural production of land while increasing the production of clean energy,” the proposal states.
The New Jersey Agricultural Experiment Station (NJAES) and Rutgers University are midway through a $2 million study into the effect on crops and animals of solar projects and farming co-existing at three sites around the state. (See NJ’s $2M Agrivoltaics Study Advances.) The Rutgers Agrivoltaics Program helped design the BPU’s pilot proposal.
To protect farmland, the proposal requires dual-use pilot projects to be located “only on lands that have had at least three most recent years of continuous agricultural or horticultural use.”
The plan also requires that land hosting a dual-use project continue to be used for agriculture or horticulture and that projects include “a method of ensuring that the presence of the solar electric generation equipment does not result in a substantively negative change or reduction in the quality of the land that would impair its agricultural or horticultural usage.”
“Staff proposes that any pilot program participant that does not maintain active agricultural or horticultural use of the land would risk forfeiture of future dual-use incentive payments,” the proposal states.
Size Diversity
The pilot is based on the guidelines for an agrivoltaics program in the state set out in a bill signed by Gov. Phil Murphy (D) in July 2021. The bill, A5434, required that the BPU, in consultation with the New Jersey Department of Agriculture, adopt rules and regulations for the pilot program within 180 days, or by the end of January 2022.
The proposal provides incentives for dual-use solar projects in the form of New Jersey Solar Renewable Energy Certificate under the state’s Successor Solar Incentive (SuSI) program. So the incentives for dual-use projects smaller than or equal to 5 MW would be set administratively by the BPU and incentives for projects greater than 5 MW would be determined by a solicitation held under the Competitive Solar Incentive part of the SuSI program.
BPU staff suggests the state limit dual-use project sizes to 10 MW, but adds that if several projects of the maximum size are proposed, the agency should select projects that provide a variety of size, location or interconnection points.
It adds that a minimum size of project may be needed because smaller projects likely would not offer much helpful information that could be used in the program evaluation.
The projects also will be judged on the developer’s plan for the project at the end of its life cycle, the proposal states.
“Staff envisions the evaluation of pilot project proposals will take into account the extent to which applicants plan to follow an established set of guidelines or best practices that facilitates farming following decommissioning,” the proposal states.
ISO-NEoutlined how FERC’s time extension for Order 2023 compliance will affect its proposal, at a meeting of the NEPOOL Transmission Committee on Nov. 9.
The RTO plans to file on April 1 with a proposed effective date of May 31, upon which it would issue study agreements to interconnection customers that are due 60 days later, followed by the beginning of the cluster study. Customers with valid interconnection requests as of May 1 would be able to enter the transitional cluster.
“Interconnection requests that are not valid and have not been assigned [a] queue position as of [May 1] will be withdrawn by the ISO without further opportunity to cure any deficiencies,” said Graham Jesmer, ISO-NE regulatory counsel. “The ISO will not accept any interconnection requests submitted after [May 1] until the first cluster entry window opens in 2025.”
Interconnection requests in the system impact study (SIS) phase as of May 1 will continue through the May 31 effective date. “Results of those studies will be provided for information purposes only and will not affect a project’s status with respect to the transitional cluster study,” Jesmer said.
Alex Rost, ISO-NE manager of resource qualification, discussed how Order 2023, along with the delay of Forward Capacity Auction 19, will affect new resources looking to establish capacity network resource capability (CNRC) and capacity network import capability (CNIC). Complying with Order 2023 means moving the process for gaining CNRC and CNIC from the Forward Capacity Market to the cluster study process.
Rost noted that under ISO-NE’s proposal to delay FCA 19, resources lacking a capacity supply obligation (CSO) would be able to submit their qualification materials using the original capacity qualification schedule, referred to as “supplemental qualification.” (See NEPOOL Votes to Delay FCA 19.) The current process for achieving CNRC and CNIC would apply until Sept. 1, 2024.
“After Sept. 1, 2024, resources subject to the ISO’s interconnection procedures can still obtain a CSO in FCM auctions but will not be able to establish CNRC/CNIC by obtaining CSO in FCM auctions,” Rost said.
Stakeholder Proposals
Representatives of the clean energy development companies New Leaf Energy and Cypress Creek Renewables also presented recommendations to ISO-NE on its Order 2023 compliance at the meeting.
Cypress recommended the RTO require complete site control for interconnection and generator facilities at the time of executing interconnection agreements to reduce speculative projects.
The company also said ISO-NE should take steps to preserve flexibility around “electrically proximate” points of interconnection, allow interconnection customers to make transition study deposits via letter of credit, and stagger the start of subsequent clusters to increase the amount of information available to interconnection customers.
New Leaf expanded upon the recommendations it made to the MC in October, stressing the importance of allowing late-stage interconnections studies to proceed for as long as possible to prevent project delays and limit the number of projects in the transitional cluster study. (See ISO-NE Provides More Detail on Order 2023 Compliance.)
“We respectfully ask ISO-NE to provide the committee with an assessment of which queue positions with an SIS in-progress have an estimated SIS completion date prior to the commencement of the transitional studies … and whether ISO-NE could somehow ‘commit’ to completing those studies,” New Leaf said.
ALBANY, N.Y. — The New York State Reliability Council Executive Committee last week approved for industry comment interconnection standards for inverter-based resources larger than 20 MW (Proposed Reliability Rule 151).
“The need for [IBR standards] has grown since April,” said Roger Clayton, chair of the NYSRC’s Reliability Rules Subcommittee, who noted that renewable projects in NYISO’s queue grew from about 57 GW in spring to 120 GW on June 30. “This is an urgent need.”
The committee, which approved PRR 151 at its Nov. 9 meeting, has been working with the Reliability Rules Subcommittee to fill gaps in NYISO’s current interconnection criteria for IBR resources. The proposed rules would take effect in all interconnection projects following, excluding the current Class Year 2023. The rule, which aligns with the recently approved IEEE Standard 2800-2022, guides the ISO to incorporate specific performance criteria, databases and model validation methods for IBRs within its authority. (See “Inverter-based Resources Standard,” NY State Reliability Council Executive Committee Briefs: June 9, 2023.)
IBRs are pivotal because they convert direct current from solar and wind into alternating current, the standard form of power for the grid. IBRs also manage the flexible charging and discharging of batteries and allow very fast ramping and frequency response.
Advanced capabilities of IBRs, such as fault ride-through and voltage regulation, also ensure the reliability and quality of power. Yet IBR integration presents new challenges due to their variability and the need for innovative control strategies, as revealed in numerous NERC disturbance reports since 2016. PRR 151 addresses this reliability risk by requiring developers to attest that their plants meet the IEEE 2800-2022 standards to ensure these resources perform reliably. (See “Inverter-based Resources Standard,” NY State Reliability Council Executive Committee Briefs: June 9, 2023.)
Clayton said, “we’re at the leading edge of this,” adding it was important that New York “get something on the books” because the interconnection queue keeps growing and the projects seeking interconnection keep getting larger.
The NYSRC says adopting PRR 151 will safeguard the New York Control Area’s reliability as it pivots toward renewable resources, protecting the state from potential system supply disruptions that were seen in other states like Texas, Utah or California where IBRs failed during routine transmission disturbances.
“We’ve gone through this with NYISO in a very detailed manner,” Clayton said, in reference to how the ISO has been integral in making PRR 151 “very focused and very clear. In addition, the changes were sensitive to other stakeholder comments received during the initial posting.”
Chris Sharp, senior compliance attorney with NYISO, said the rule would be applied by the ISO “on a rolling basis,” with projects examined for compliance when submitting an interconnection application.
Zach Smith, vice president of system and resource planning at NYISO, said ISO staff does not anticipate any tariff revisions will be necessary to implement PRR 151. “Coincidentally, this is coming at a handy time,” he said, referring to the ISO’s efforts to reconfigure its interconnection processes to comply with FERC Order 2023. (See NYISO Stakeholders Question Proposed Interconnection Timelines, Deposit Rules.)
Michael Mager, a partner at Couch White who represents Multiple Intervenors, a group of large industrial, commercial and institutional energy consumers, opposed the approvals, saying the changes under the new model for external emergency assistance were excessive.
The NYSRC will consider the final study report as part of its deliberations on the IRM for the next capability period at its December meeting.
CAISO is moving quickly to gain approval for a proposed transmission line that would allow California to meet targets for tapping Idaho wind resources and help both states bolster their resource adequacy profiles.
The ISO is seeking to acquire enough entitlements on the Southwest Intertie Project–North (SWIP-N) to import 1,000 MW of wind energy from Idaho, aligning with the plans to access Idaho wind that have been set out in utility integrated resource plans filed with the California Public Utilities Commission.
“Transmission development is needed to access out-of-state wind resources and this project is the only known transmission project that can enable access to Idaho wind resources,” CAISO said in a slide presentation shown during a Nov. 7 stakeholder meeting to discuss SWIP-N, which is being developed by LS Power subsidiary Great Basin Transmission (GBT).
SWIP-N would link to the One Nevada (ON) line at Robinson Summit in Nevada and run north 285 miles into Idaho, providing 2,070 MW of transfer capacity southbound and 1,920 MW northbound. The ON line is connected to the Desert Link, which extended CAISO’s operational boundary to the Harry Allen substation north of Las Vegas when it went into service in 2020.
The entitlement structure for SWIP-N would provide GBT with 1,117.5 MW of north-to-south capacity and 1,072.5 MW of south-to-north capacity, with the balance in both directions allocated to Nevada-based NV Energy.
CAISO is considering a proposal to leverage a transmission use and capacity exchange agreement (TUA) between NV Energy and GBT that would allow the ISO to acquire most of GBT’s entitlements on the SWIP-N line and ON line rather than building a new, roughly 500-mile transmission line to reach Idaho’s resources. Under the plan, Idaho Power would assume 500 MW of south-to-north capacity on the line to support winter RA needs.
The plan was spelled out in a Nov. 1 letter Idaho Power sent to CAISO CEO Elliot Mainzer expressing interest in partnering with the ISO to fund SWIP-N as a “joint regional policy-driven project.” It would also give the Boise-based utility access to the Desert Southwest wholesale power market.
Under the plan, CAISO and Idaho Power would share the more than $1 billion cost for the line — or about $3.8 million per mile, which the ISO said is close to the per-mile costs for other competitively procured transmission projects in the region. The ISO would fund 77.2% of the project, with Idaho Power picking up the rest. Based on the TUA, CAISO would pay no additional costs for assuming GBT’s entitlements on the ON line.
“Transmission infrastructure is a primary key enabler to a cost-effective, reliable and clean energy future. Idaho Power believes that cost effective transmission is a no-regret investment,” Idaho Power said in the letter. “All feasible scenarios related to electric grids of the future will continue to heavily utilize interregional transmission infrastructure.”
During the Nov. 7 meeting, CAISO told stakeholders SWIP-N will help Idaho and California meet their resource portfolio needs while sharing project costs, reducing the cost to California ratepayers. The ISO also said the project has the advantage of being shovel-ready.
Still, construction of SWIP-N is contingent on Idaho Power and GBT reaching an agreement that is conditioned on CAISO’s approval of the project, FERC’s approval of the agreement between Idaho Power and GBT, and an Idaho Public Utilities Commission (IPUC) determination that the project will provide sufficient benefits to Idaho Power to justify the cost.
If CAISO approves the project, Idaho Power will file for approval with the IPUC by year’s end and the project could begin operating by 2027.
Stakeholder Feedback
CAISO stakeholders participating in the Nov. 2 meeting generally supported the SWIP-N proposal.
“We appreciate the CAISO’s due diligence in exploring these opportunities to reduce the overall project cost to California ratepayers,” said Pushkar Wagle, managing consultant at Flynn Resource Consultants. However, Wagle questioned whether the project’s cost estimates were being downplayed.
“You presented the numbers in terms of dollars per mile; that’s clearly one metric to look at it. Another metric is what’s dollars per megawatt or dollars per kilowatt-year?” Wagle said. “The way the models are run is basically they’re trying to minimize the overall cost of procurement, so if you plug in these numbers, you might get totally different answers.”
Biju Gopi, CAISO senior manager of transmission interface coordination, emphasized that the cost shouldn’t be a significant concern. “Resource choices are generally stable and cost is not so much a factor as compared to other elements like resource potential limits [or] transmission limitations,” he said.
But Kanya Dorland, senior analyst with CPUC’s Public Advocates Office, echoed Wagle’s comments.
“SWIP-N has been studied for almost 10 years as both a public policy and economic project and each time it’s determined that its costs outweigh the benefits,” Dorland said. “It sounds positive that Idaho Power would contribute, but is the benefit-cost ratio greater than one with this new arrangement, or would it be better with a [Department of Energy] loan?”
CAISO requested that GBT pursue a DOE loan to finance construction of the project, but Gopi was not aware if it was awarded.
Gopi again highlighted that the goal of the project — to access Idaho’s wind resources — outweighs potential costs.
“We’re pursuing this project not as an economic-driven project but as a policy-driven project,” Gopi said. “CPUC requirements do require us to plan for integrating wind resources from Idaho into California.”
CAISO expects to seek conditional approval for SWIP-N from the board by early December. Full approval is conditioned on Idaho Power receiving IPUC approval for the line by June 2024, GBT applying to become a participating transmission owner in the ISO by July 1, 2024, and FERC’s acceptance of GBT’s transmission owner tariff and transmission revenue requirement rate structure.
Stakeholder comments on the proposal are due to CAISO by Nov. 21.
LITTLE ROCK, Ark. — SPP has its strategic priorities, as do all grid operators, and resource adequacy is one of them.
It is also the RTO’s No. 1 strategic priority.
“It’s all over your agenda today,” SPP CEO Barbara Sugg said in opening the recent meeting of the Regional State Committee (RSC), which comprises the RTO’s state regulators. “It’s been a No. 1 priority for us, particularly since Winter Storms Uri and Elliott.”
The Resource and Energy Adequacy Leadership (REAL) Team, a cross-section group of regulators, directors and stakeholders, is the answer. After inside jokes during the team’s first few months (“Yes, we will really be meeting soon.”), the team has set an aggressive schedule in assessing SPP’s current resource adequacy construct and providing guidance and policy recommendations to ensure sufficient energy is available to meet load requirements.
The group, led by Texas Public Utility Commissioner Will McAdams, and its subgroups brought two key resource adequacy policies for approval during the October governance meetings. Next year, it plans to present a maintenance outage policy, value-of-lost-load and expected unserved energy metrics and associated usage policies, and a winter planning reserve margin.
“I am particularly pleased with the REAL Team,” Sugg said. “What really excites me about this is it is a joint committee, if you will, with seats at the table for the RSC and the board and the stakeholders. I personally would love to see this continue as a longstanding committee in the future because I think there is tremendous value to be gained by us sitting around the table and working together.”
During what RSC President and Kansas Corporation Commissioner Andrew French called a “lively meeting with lots of opinions shared,” the regulators on Oct. 30 approved two revision requests brought forward by the REAL Team that lay out a performance-based accreditation (PBA) policy (RR554) for conventional resources and effective load-carrying capability (ELCC) accreditation (RR568) for wind, solar and storage resources. The Board of Directors approved the RRs the next day.
“It’s been a real innovative and valuable approach to problem solving,” Sugg said during the RSC meeting. “I’m sure there are other problems we can solve together, and I look forward to that. The team has a work plan, and we’ll be bringing more resource adequacy policies in the coming quarters as well. That collaboration is outstanding.”
“The key thing from the REAL Team is to improve the cycle time between the key working groups and the committees to ensure we move through these very critical decisions as quickly as possible,” SPP Director John Cupparo said. “I would encourage the key folks involved in the REAL Team and around the team to take the opportunity to kind of clarify the relationships between the working groups, because [that] will ultimately benefit all of us as these decisions continue to come forward.”
RR568 is a response to FERC’s rejection earlier this year of SPP’s first attempt to add ELCC (the amount of incremental load a resource can dependably and reliably serve during peak hours). The revision reduces a three-tiered structure to just two, firm and non-firm transmission service. Staff will study only firm service in its ELCC analysis. (See FERC Grants Rehearing of SPP Capacity Accreditation Proposal.)
RR554 was approved after restoring the use of seven years of historical data, rather than 10, in calculating conventional resources’ accredited capacity. The Markets and Operations Policy Committee had rejected the seven-year figure and endorsed 554 with 10 years of historical data.
SPP’s Market Monitoring Unit had initially proposed five years of historical data but settled on the seven-year compromise during a September meeting with the REAL Team. (See SPP REAL Team Compromises on PBA, ELCC Revisions.) Smaller utilities have sided with the 10-year figure, saying it would give them and their smaller fleets more time to meet resource requirements.
The board also approved a Supply Adequacy Working Group (SAWG) policy paper on demand response and its planned direction on fuel assurance, both of which previously were endorsed by the RSC and MOPC. They will be converted into RRs and brought back to the board for final approval.
The first policy will facilitate diverse DR programs by considering the potential for increases in large loads that may claim its accreditation. SAWG members say the grid operator must accurately accredit DR resources according to their reliability contribution and develop qualification standards to drive consistency.
The fuel assurance policy will incorporate PBA weighting based on critical system periods and considers modifications to the out-of-management-control exceptions related to fuel-related outages. The SAWG also will consider a policy for PBA and ELCC adjustments to reflect new reliability investments and recommends SPP improve operational dispatch strategies to start units before extreme cold weather and keep them online.
RSC, Board OK Sunflower Waiver
Sunflower Electric Power finally was given some potential relief for congestion from renewable resources in its pricing zone when regulators and the directors both approved RR584, directing SPP to make a Federal Power Act Section 205 filing at FERC that would regionally allocate four Sunflower upgrades on a prospective basis.
The cooperative last year submitted the waiver request from SPP’s base-plan allocation methodology for upgrades between 100 and 300 kV, or byway projects. The process allocates one-third of the cost of byway projects to the RTO’s full footprint, with customers in the transmission pricing zone where the project is built being allocated the rest. “Highway” projects — those larger than 300 kV — are allocated RTO-wide.
The Members Committee’s advisory vote to the board passed 9-8, with six abstentions. Members argued against the waivers as they did during the MOPC meeting, saying deconstructing the allocation process with one-off reassignments sets a troubling precedent for future requests.
Al Tamimi, Sunflower’s COO of transmission, thanked the RSC for debating the issue before it came to the board, saying it will buy time until a more comprehensive solution can be developed.
“This issue started back in 2018 and 2019. It did not come out of nothing,” he said of one of the Holistic Integrated Tariff Team’s (HITT) major recommendations. “We had years in the HITT discussing this issue, and we came up with two solutions for cost allocation to maintain the fairness of highway/byway. The one-off thing really needs to be one-off, at this point, until we figure out the whole big plan because the highway/byway fundamentals don’t work in Sunflower … when you’re exporting 80 to 90% of massive amounts of power while you’re paying 70% of the cost.”
The four upgrades will provide $13 million in annual revenue requirement.
French addressed comments from members who noted the committee appeared to be sidestepping MOPC.
“One of the motions that we passed sent some direction to the [RSC’s Cost Allocation Working Group] and the SPP staff, where previously the REAL Team had sent some very similar direction to the [Supply Adequacy Working Group],” French said. “I don’t know that the intent of the RSC was to cut anybody out, and I hope there will still be collaboration and cross-pollination between all those groups working together to give us the most informed feedback we can get.”
In July, FERC unanimously reversed a 2022 decision that established a process for SPP to allocate “byway” transmission projects on a case-by-case basis without prejudice. SPP plans to look at the more comprehensive process and make a filing early next year. (See FERC Reverses Course on SPP Byway Cost Plan.)
Sunflower, a “wind-rich” cooperative that long has felt unduly burdened with transmission costs for renewable energy that benefits others, has filed a rehearing request with FERC and asked the D.C. Circuit Court of Appeals to review the case (ER22-1846).
MEAN Appeal of ITP Fails
The board and members approved SPP’s 2024 Integrated Transmission Plan and its 10-year assessment, but it didn’t take up an appeal from the Municipal Energy Agency of Nebraska (MEAN) over a project that had its notification to construct (NTC) withdrawn from the portfolio.
MEAN’s Brad Hans argued the $92 million, 48-mile, 115-kV joint economic project in Nebraska between the Western Area Power Administration’s Rocky Mountain Region and the Nebraska Public Power District was necessary. He noted the ITP identified the western half of Nebraska as a problem area and the public agency, with only two load nodes, has seen day-ahead prices as high as $200/MW, popping to $300 to $600 during congested periods.
“This has a direct impact on the communities we serve in western Nebraska,” Hans said. “When you see the congestion, as we’ve seen in past three years, elevating to the levels and to the extent it has, it just compounds the rate pressures in this area.”
Hans apologized for the appeal, saying he realized it was not the “preferred way” to keep the project’s NTC.
“I can assure you, MEAN is just an acronym. It’s not our disposition,” he said.
David Kelley, SPP’s vice president of engineering, said staff don’t disagree with MEAN’s concerns.
“We agree there is an issue that warrants attention. We think it requires a little more time to bake,” Kelley said, saying the project will be studied again during the 2024 ITP cycle. “I’m pretty confident we’re going to find something that addresses the solution.”
“We’ve gotten a clear indication that there’s a need here. That doesn’t appear to be in dispute,” the Advanced Power Alliance’s Steve Gaw said. “I worry about this setting a precedent, where a variety of entities, not liking the result, can come into a [working group] and push back hard. Then, we’re sitting here with another delay, when that’s costing us money.”
SPP since has pulled another economic project from the ITP portfolio, a 38-mile, 345-kV line north of Oklahoma City with projected costs of $110 million. The project had an NTC with conditions (NTC-C) but has upgrades that would qualify as competitive upgrades and other upgrades that won’t.
Staff will re-evaluate the project’s refined cost estimates to determine whether the competitive upgrades can be authorized for construction.
The 2023 ITP addresses reliability and economic issues on its seams. It recommended NTCs for 44 projects before the Oklahoma line had its NTC-C pulled. The portfolio included 150 miles of new transmission — 51 miles for 345-kV lines — and 93 miles of rebuild for a total engineering and construction cost of $735.5 million and a reduced 40-year adjusted production cost of nearly $3 billion.
The assessment indicates the footprint’s wind growth continues to outpace ITP projections. The 2023 ITP’s emerging technologies case projects 46.1 GW of in-service wind in 10 years, a nearly 25% increase from the 10-year assessment just two years ago. SPP had just over 37 GW of in-service wind resources when 2023 began.
Celebrating $464M DOE Grant
Staff and stakeholders celebrated the U.S. Department of Energy’s recent $464 million grant for the SPP-MISO Joint Targeted Interconnection Queue (JTIQ) portfolio with a round of applause and thanks to stakeholders involved in the application.
“I think this is such a great thing for SPP and for MISO, and for the DOE and NERC to see the value at these two regions working together to solve some of these seams issues,” she said. “There’s a lot of work that goes into receiving federal money; there’s a lot of work that goes into the ask; and then there’s a lot of work that goes into the receipt of it and the spending on it.”
Sugg singled out Minnesota Public Utilities Commissioner John Tuma and other Gopher State staffers for “helping us pave the way.” The Minnesota Department of Commerce and the Great Plains Institute took the lead on the JTIQ’s submission, one of 700 that DOE received. Kelley thanked regulators, governor’s offices and other stakeholders for providing letters of support.
FERC Commissioner Allison Clements and DOE both heaped praise recently on the JTIQ, which is designed to ease transmission limitations along the RTOs’ seam by interconnecting new generating resources.
Clements, in her concurring opinion to Order 2023, said the “promise of a forward-looking approach” to a streamlined interconnection process is “becoming clear” through the “pioneering” work by SPP and MISO. A draft DOE report on transforming interconnection says the JTIQ study shows that “proactively studying a larger set of generation interconnection requests offers substantial cost and time savings, identifies more optimized network upgrades and reduces uncertainty for the resource developers.”
“The real work begins now because $464 million is not coming with no strings attached,” Kelley said.
Staff over 700 with Budget Approval
The Finance Committee’s recommended 2024 operating budget passed easily, resulting in a $192.1 million net revenue requirement and a 2.5% increase in the administration fee, from 44.8 cents/MWh to 45.9 cents/MWh.
The budget projects $275.3 million in operating expenses next year and $17 million in capital allocation. SPP’s headcount will increase to 707, primarily because of work on resource adequacy, responding to the December 2022 winter storm and western expansion. The grid operator’s staff numbered 676 in 2022.
Several members said the growth of stakeholder groups addressing increasing responsibilities has put a strain on their staffs and will affect their ratepayers. SPP staff responded with an overview of the methodology used to reduce spending and the rigorous senior management review and analysis that led to the final recommendation.
Golden Spread Electric Cooperative’s Mike Wise, a longtime member of the FC, said the group’s questions of the budget to senior staff was “probably greater than in any other year.”
“I felt very comfortable with their responses and their concerns,” he said. “The operating environment that SPP is in right now is really difficult. We are asking them to do a whole lot of things with less and less. The RTOs are fighting trying to get engineers … and raising the salaries. For SPP to hold on to its senior staff and its educated and experienced engineering force is a real testament.”
Consent Agenda Flies
The board’s consent agenda approved the 2023 annual violation relaxation limits (VRLs) analysis; a more than $16 million baseline decrease (20.2%) for a 230-kV Basin Electric Power Cooperative project in North Dakota; a 47% baseline increase of $12.3 million for a 345-kV American Electric Power-Oklahoma Gas & Electric project in Oklahoma; the Generation Interconnection Advisory Group’s conversion from a user forum; and several recommended appointments to stakeholder committees:
Nebraska Public Power District’s Laura Kaputska to the Finance Committee.
Omaha Public Power District’s Joe Lang to the Human Resources Committee.
Evergy’s Denise Buffington and Arkansas Electric Cooperative Corp.’s Andrew Lachowsky to the Strategic Planning Committee.
The consent agenda also included a pair of RRs:
RR572: updates the planning criteria with a definition for “qualified change” that reflects the new NERC mandatory reliability standard FAC-002 (Facility Interconnection Studies).
RR579: adds language to the market protocols to clarify that in the event of a 0-MW effective limit, those constraints will have the highest VRL value ($/MW).
Below is a summary of the agenda items scheduled to be brought to a vote at the PJM Markets and Reliability Committee and Members Committee meetings on Nov. 15. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will be covering the discussions and votes.
Markets and Reliability Committee
Consent Agenda (9:05-9:10)
The committee will be asked to endorse:
B. proposed revisions to Manual 3: Transmission Operations to update references to generation interconnection agreements and email addresses as part of the document’s periodic review.
C. proposed revisions to Manual 3: Transmission Operations to allow PJM to delay energizing a line if certain data have not been submitted by the relevant transmission owner. The changes pertain to cut-in projects. (See “Quick-fix Manual Changes to Transmission Facility Cut-in Process Approved,” PJM OC Briefs: Nov. 2, 2023.)
D. proposed revisions to Manual 10: Pre-scheduling Operations seeking to clarify that resources entering their available output or outages should report their nameplate capability unless there is a physical derate that reduces its output. (See “Clarifying Revisions to Manual 10 Endorsed,” PJM OC Briefs: Nov. 2, 2023.)
E. proposed revisions to Manual 11: Energy and Ancillary Services Market Operations to update that supporting documentation for offer verification exceptions should be submitted into Markets Gateway starting with the 2023/24 winter. Data have previously been submitted via Sharepoint.
F. proposed revisions to Manual 11: Energy and Ancillary Services Market Operations to specify that intermittent capacity resources should offer their economic maximum value equal to or larger than their hourly forecast, based on either PJM’s forecast or an equivalent forecast the generation owner has developed. (See “Other Committee Business,” PJM MIC Briefs: Nov. 1, 2023.)
G. proposed revisions to Manual 11: Energy and Ancillary Services Market Operations that would correct references to manual sections throughout the document.
H. proposed conforming revisions to Manual 11: Energy and Ancillary Services Market Operations, Manual 27: Open Access Transmission Tariff Accounting and Manual 28: Operating Agreement Accounting to implement the second phase of PJM’s rules for hybrid resources as laid out in FERC docket ER23-2484.
I. proposed revisions to Manual 11: Energy and Ancillary Services Market Operations to codify the performance assessment interval (PAI) triggers FERC approved in ER23-1996. (See “Manual Revisions for New Performance Assessment Interval Triggers Endorsed,” PJM MIC Briefs: Nov. 1, 2023.)
J. proposed revisions to Manual 13: Emergency Operations to reflect the same changes to the PAI triggers.
K. proposed conforming revisions to Manual 18: PJM Capacity Market that would update several definitions and references in the manual.
L. proposed revisions to Manual 19: Load Forecasting and Analysis to reflect the change to an hourly model, add clarity around the price-responsive demand forecast procedure and provide typographic fixes.
PJM’s Vincent Stefanowicz will present proposed revisions to Manual 14D: Generator Operational Requirements that would add a requirement that generation owners prepare for cold weather operations and expand its cold weather checklist. (See “Generation Winterization Requirements Endorsed,” PJM OC Briefs: Nov. 2, 2023.)
The committee will be asked to endorse the manual revisions.
Clean Attribute Procurement Senior Task Force (CAPSTF) Sunset (9:25-9:40)
PJM’s Scott Baker will present the final report on the CAPSTF and a proposal to sunset the group, as discussions have been taken up by a state-led working group outside the PJM stakeholder process. (See “Stakeholders Mixed on Sunsetting Clean Attribute Procurement STF,” PJM MRC Briefs: Oct. 25, 2023.)
The committee will be asked to endorse sunsetting the task force.
Performance Impact of the Multi-schedule Model on the Market Clearing Engine (9:40-10:05)
PJM’s Keyur Patel will review two proposals that would narrow the number of offers from combined cycle and storage resources that are modeled by the market clearing engine to allow multi-schedule modeling to be incorporated into the market clearing engine (MCE) without causing infeasible increases in computation times. (See “Multiple Proposals Considered for Incorporation of Multi-schedule Modeling,” PJM MRC Briefs: Oct. 25, 2023.)
The committee will be asked to endorse one of the two proposed solutions and corresponding revisions to the tariff and Operating Agreement.
Members Committee
Consent Agenda (1:05-1:10)
The committee will be asked to:
B. endorse the recommended values in the 2023 Reserve Requirement Study for the installed reserve margin and forecast pool requirement, which would both increase over last year’s values. (See “Recommended Values for 2023 Reserve Requirement Study,” PJM MRC Briefs: Oct. 25, 2023.)
C. approve proposed revisions to Manual 34: PJM Stakeholder Process to add deadlines for adding an item to the agenda of a senior standing committee, standing committee and other stakeholder groups. (See “3 Changes to Stakeholder Process Proposed,” PJM MRC Briefs: Oct. 25, 2023.)
D. approve proposed revisions to Manual 34: PJM Stakeholder Process seeking to clarify that the senior standing committees hold final authority over issues considered by lower stakeholder groups and that the lower standing committees set the order that proposals will be voted on by the MRC and MC. (See “3 Changes to Stakeholder Process Proposed,” PJM MRC Briefs: Oct. 25, 2023.)
E. approve proposed revisions to Manual 34: PJM Stakeholder Process that would change the truncated voting structure so that if a main motion fails, any alternatives are considered simultaneously, as opposed to the current system of voting on them one by one until one receives sector-weighted support or all have failed. (See “3 Changes to Stakeholder Process Proposed,” PJM MRC Briefs: Oct. 25, 2023.)
CARMEL, Ind. — MISO says it won’t place conditions on either queue entrants or generation retirements in its quest to maintain system reliability by prescribing generating attributes.
MISO has defined six system reliability attributes as necessary, including availability, rapid start times, the ability to deliver long-duration energy at a high output and providing voltage stability, ramp-up capability and fuel supply certainty. The RTO is studying what role it can play in maintaining those increasingly scarce reliability attributes from generation in the long term. (See MISO Charting Course on Stimulating Generating Attributes.)
MISO has committed to publishing by year’s end an action plan on attributes that will detail what changes it thinks might be necessary. It revealed a few ideas last week.
At a Nov. 8 Resource Adequacy Subcommittee, Director of Policy Studies Jordan Bakke said there should be several options to stimulate attributes to solve MISO’s reliability problems. However, he said there’s no need to account for reliability attributes in MISO’s generation interconnection queue or generator retirement study process.
Still, Bakke said MISO faces near-term reliability risks for “up to 10 years.” Bakke said MISO foresees not having enough energy because of generator availability, fuel constraints, time-limited resources and resources limited by their locations.
Bakke said solutions are best served through bumping up capacity requirements, revamping capacity accreditation and devising other market solutions to “let a broad range of resources compete to meet required demand.”
“The idea is not to attract certain types of resources, but attract capabilities in aggregate,” he said. The “complex interactions between different resource types makes it difficult” to prescribe quantities of generator availability, energy duration, fuel requirements and other adequacy attributes.
Bill Booth, consultant to the Mississippi Public Service Commission, urged MISO to reconsider its belief that it doesn’t need to attempt to delay generator retirements to retain reliability attributes preparing to depart the system.
Booth said since MISO isn’t willing to place stipulations on generation retirements, it’s left with two choices: “reduce the load or increase construction.” However, he said if MISO doesn’t advise what kinds of generation it needs, utilities will be in the dark on what to build, and if MISO is trying to encourage some resources attributes, then it isn’t technically resource neutral.
Booth also asked if MISO would consider assigning costs to load-serving entities whose fuel mixes are creating attribute deficiencies in the fleet. MISO staff took notes on Booth’s comments.
Bakke said MISO will need to draw on its system flexibility — rapid start time and ramping — more often. He said for that, MISO could expand its market participation models to increase the types of resources eligible to provide services and expand its selection of ancillary service products to let a broad range of resources compete to meet need.
MISO expects to have enough aggregate flexibility, Bakke said, but the challenge is sending it where it needs to be because of growing operational uncertainty. The good news, he said, is that small, regional flexibility deficiencies can be solved inexpensively and brought to market within a few years. He also said more system flexibility could be achieved through responsive load.
Bakke said to address voltage stability, MISO is simply going to need to add more resources that can provide it. He said MISO isn’t planning on creating new market products tailored to voltage stability because stability issues usually are local in nature. However, he said MISO could add generator interconnection voltage performance requirements for critical reliability capabilities “as needed.”
MISO is accepting stakeholders’ feedback to its early solution ideas on reliability attributes through the end of 2023.
The RTO used its middle-of-the-road transmission planning future to run analyses to quantify its future needs related to rapid start-up and ramp-up capability, generator availability, fuel and energy assurance, and voltage stability.
The generation fleet predicted under MISO’s second planning future largely is based on MISO members’ announced plans and predicts MISO will have a total 471 GW in installed capacity by 2042.
