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“Interconnection requests that are not valid and have not been assigned [a] queue position as of [May 1] will be withdrawn by the ISO without further opportunity to cure any deficiencies,” said Graham Jesmer, ISO-NE regulatory counsel.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.
MISO last week said it plans to handle four of the five recommendations this year from the Independent Market Monitor’s State of the Market report, putting a recommendation regarding transmission planning on hold.
The grid operator announced it’s deferring action on the IMM’s recommendation that it re-evaluate the future generation mix used to develop the long-range transmission plan (LRTP).
MISO Independent Market Monitor David Patton tied multiple State of the Market recommendations this year to reducing transmission congestion. He said most of the root cause of congestion can be tied to wind generation, which has little incentive to follow MISO’s dispatch instructions. (See MISO IMM Zeroes in on Tx Congestion in State of the Market Report.)
However, Patton also used this year’s report to criticize the future resource mix assumptions the RTO is using to shape a second LRTP portfolio for its Midwest region. It marked an unprecedented foray into transmission planning when the IMM typically focuses on MISO markets.
MISO said while it agrees with the IMM that it’s important to “evaluate the cost and benefits of transmission to avoid inefficient investments,” it disagrees that the fleet mix envisioned in its second of three 20-year transmission planning futures isn’t well-founded.
“MISO is still evaluating and will work with stakeholders to define LRTP scenarios, business case and alternatives to manage uncertainty,” Zhaoxia Xie, of MISO’s market design team, said during a Nov. 9 Market Subcommittee meeting.
Xie said MISO may not end up taking the IMM’s recommendation but will conduct more analysis and hold discussions with stakeholders.
Jeremiah Doner, MISO’s director of cost allocation and competitive transmission, said MISO still finds that Future 2A is a valid “anchor” to its LRTP. But he said as with any 20-year planning scenario, MISO could conduct more analysis and scrutinize uncertainties. He said the IMM’s recommendation likely can be tackled through the course of stakeholder meetings on the second portfolio of the LRTP.
Minnesota Public Utilities Commission staff member Hwikwon Ham said MISO should outright reject the IMM’s recommendation. He said the IMM’s view of the future resource mix is based on a pessimistic view that “MISO members’ goals aren’t real and that decarbonization isn’t going to happen.” However, he said the Monitor’s opinion is increasingly implausible, as evidenced by Michigan Gov. Gretchen Whitmer (D) preparing this week to sign a bill requiring the state to reach 100% clean energy by 2040.
“This is going to be a real deal,” Ham said. “MISO should not waste its time on this.”
Other stakeholders said the IMM’s recommendation blurs the line between the duties of MISO’s Market Subcommittee and Planning Advisory Committee.
Work in Progress on Other Four
MISO was more receptive to the IMM’s four other recommendations in this year’s report.
MISO said it agrees with the advice that it ratchet up its excess and deficient energy deployment penalty charges, which Patton said are not high enough to dissuade generators from deviating from MISO’s dispatch instructions.
Xie said the MISO operations team is working on the design of a “follow dispatch flag” that will be sent to generators when they’re being dispatched down so they get a clearer signal to wind down output. Xie said the flag system will be MISO’s first step, and it will consider upping penalties in the future for generation that fails to curtail.
“Further evaluation and discussion are ongoing for the settlement incentives for the following dispatch,” she said.
Patton also recommended MISO expand its transmission constraint demand curves so its market dispatch system can better manage network flows.
Xie said an expansion of those curves likely will be contained in a larger filing that also will elevate MISO’s operating reserve demand curve and value of lost load. She said MISO could file with FERC for those changes sometime next year.
Patton has said MISO is missing out on valuable unrealized transmission flows because it’s forced to manually redispatch resources to manage constraints, especially when wind generation fails to scale back production on MISO dispatch instructions.
He said his recommendations will reduce flow uncertainty on the transmission system.
MISO stakeholders over the summer said MISO should introduce a software flag to let units more clearly know when they are being curtailed. Some said it’s not always apparent when MISO expects curtailment. Multiple stakeholders also said MISO sends incorrect dispatch instructions or instructions that don’t align with individual market participants’ offer curves.
Patton also recommended MISO improve its near-term wind forecasting to better reflect the characteristics of wind generation output. He said MISO uses a “persistence” forecast that assumes wind resources will produce the same amount of output as it most recently observed.
Xie said MISO will explore releasing more recent data through its interface to its forecasting vendors.
Finally, Xie said MISO agrees with the Monitor that it should establish a way for suppliers to submit annual offers instead of just seasonal offers in the new, seasonal capacity auction and rework some of its 31-day outage limit for generators per season.
Patton said MISO’s 31-day limit on non-exempt generation outages is causing some distortion in the capacity market because many suppliers this year deliberately adjusted their longer unit outages so they straddled seasons, thereby dodging penalties.
Xie said MISO plans to discuss with stakeholders a more “comprehensive participation model for resources looking for more flexible participation in the Planning Reserve Auction.”
She also said MISO will investigate modifying its outage penalty provisions and mitigation measures.
CARMEL, Ind. — In its third annual Regional Resource Assessment, MISO again found planned generation retirements continue to outstrip additions.
MISO said though this year’s condensed RRA showed a slightly improved capacity picture, the survey still indicates a “continued capacity risk, highlighting the immediate importance of additional investment.”
MISO said beyond what members are planning, the footprint likely needs an additional 13 GW of accredited capacity in 2027, 27 GW by 2032 and 34 GW in 2042 to fulfill demand.
“Major trends from MISO members’ publicly announced plans remain unchanged compared to past RRAs, with wind and solar driving planned additions and coal comprising the bulk of planned retirements,” Laura Hannah of MISO’s strategy team said during a Nov. 7 Resource Adequacy Subcommittee meeting. Hannah said MISO also sees battery storage plans picking up steam since last year.
MISO expects to have lost about 60 GW worth of installed capacity from mostly coal and gas resources through retirements by 2042, with retirements gathering speed around 2026.
Over the same time frame, members told MISO they will add about 120 GW of wind, solar, battery storage and natural gas resources. However, the 120 GW of installed capacity will be whittled down to 50 GW in unforced capacity. MISO further qualified that its plans for a new, marginal-style capacity accreditation could further shrink that amount.
“There’s a lot of moving pieces on accreditation,” Hannah said.
According to MISO, its gas fleet won’t see much change by 2042. The grid operator said installed capacity of its natural gas resources is predicted to be about static, with an equivalent megawatt amount of planned investment and retirement announcements.
Members serving a total 80% of the footprint’s load responded to the survey, up from approximately 75% last year.
Through last year’s RRA, MISO said its members may need to build 200 GW in new installed capacity by 2041 to meet reserve requirements and achieve renewable targets and emissions-cutting goals (See MISO: 200 GW in New Capacity Necessary by 2041.)
Hannah said the RRA analysis was “scaled back this year,” with MISO subbing its second transmission planning future for resource expansion modeling instead of performing a separate full-scale resource expansion modeling.
Hannah said this year’s RRA was a “broad-brush” approach when compared to the previous two years’ reports. She said even though the resource expansion piece is an estimation, MISO remains confident in the long-term trends that this year’s and previous RRAs have exposed. She also said members reported only “modest year-over-year changes” in their generation plans.
Some stakeholders asked if MISO would begin prioritizing generator interconnection requests that can sustain reliability and provide accredited, readily available capacity instead of simply installed capacity.
Bill Booth, consultant to the Mississippi Public Service Commission, asked if MISO may consider linking its System Support Resource agreements with the footprint’s capacity needs; MISO’s SSR designations — where it orders retiring resources to remain online for the sake of reliability — are geared only toward the reliability of the transmission system. Booth said MISO is fast approaching “the iceberg” and asked if it was simply going to rely on states and load-serving entities to fill the planning gaps MISO foresees.
Hannah said those ideas were beyond the scope of the RRA. Other staff said MISO’s ongoing work to quantify and prescribe specific amounts of resource attributes will deal with Booth’s and other stakeholders’ concerns. (See MISO Charting Course on Stimulating Generating Attributes.)
MISO will collect stakeholders’ written reactions to the 2023 RRA through Dec. 31.
The Texas Public Utility Commission and Carrie Bivens both confirmed Thursday that she is resigning as ERCOT’s Independent Market Monitor.
It could be the first of several changes among those responsible for governing and monitoring the Texas grid operator. According to an article by Bloomberg, Will McAdams is “expected” to resign from the commission before the year is up. Rumors swirling in Austin indicate fellow Commissioner Lori Cobos could soon follow him out the door.
Rich Parsons, the PUC’s communications director, said McAdams and Cobos both continue to “serve at the pleasure” of Gov. Greg Abbott (R).
In a call to RTO Insider, McAdams expressed frustration with the Bloomberg story, which cited sources that requested anonymity. It comes as he is focused on preparing the ERCOT and SPP grids for winter; McAdams leads a senior leadership team assessing SPP’s current resource adequacy construct and making policy recommendations.
“I continue, as I have been, to serve at the pleasure of the governor,” he said.
Thomas Gleeson, the commission’s executive director, confirmed Bivens’ pending resignation in a statement.
“Carrie has done a great job as the Independent Market Monitor at a critical time for our state, balancing the urgent need for greater reliability in a way that protects our unique, competitive market,” he wrote, thanking her for her service.
Bivens told RTO Insider the news of her departure was true but declined to comment further.
Potomac Economics’ David Patton said in an email that Bivens resigned from the eight-person IMM to “pursue other opportunities.” He said the deputy director will manage the team while Potomac searches for a new director, but that day-to-day monitoring work will not be affected.
“She was an outstanding director, and we all wish her the best,” he said.
Potomac currently holds ERCOT’s market monitoring contract, which expires in December. The consulting firm is the only respondent to the PUC’s request for proposals to a four-year contract that begins in January.
Parsons said the commission is proceeding through the RFP process and cannot comment on specific details unless or until a contract is signed.
“Let me just say that during her time as the IMM director, Carrie has had to deal with way bigger and thornier issues than either Dan [Jones] or I dealt with,” said Beth Garza, Bivens’ predecessor. Dan Jones preceded Garza, who, like Bivens, resigned her position.
Bivens tangled with both the PUC and ERCOT leadership in recent years. She cast doubt on the performance credit mechanism pushed by former PUC Chair Peter Lake. Last month, she defended an IMM report before the ERCOT board that said its newest ancillary service “likely” raised the real-time market’s energy value by at least $8 billion. (See ERCOT Board, IMM Debate Ancillary Service Costs.)
A departure by either McAdams or Cobos could be more problematic. According to sources in Austin political circles, both have been frustrated with their roles on the commission and the amount of work the state’s lawmakers have sent their way.
“The magnitude and complexity of the PUCT’s responsibilities have increased significantly,” said energy consultant Alison Silverstein, a former PUC and FERC adviser. “If McAdams feels it’s time to move on, then that’s a big loss for the people of Texas and the electric industry. That loss would be compounded if … we lose [Cobos] and her experience and expertise.”
The two commissioners said reports of their departure are false.
“I deeply value and rely on the strong working relationships I have with state leadership and members of the Texas Legislature,” McAdams, a former staffer at the Capitol, said in a statement. “The legislature’s guidance has been and remains invaluable in strengthening the ERCOT grid. I’m also grateful for the additional funding and resources the legislature has granted the PUCT, which allows us to grow and take on more responsibility to ensure Texans have the reliable electric grid they expect and deserve.”
“I remain fully committed to serving on the [PUC] and serving the people of Texas to ensure a reliable, resilient, and affordable supply of electric power,” Cobos said. “I greatly value the important work that the Texas Legislature has accomplished over the past two legislative sessions to help ensure grid reliability in our state and look forward to continuing to work with the Texas Legislature to implement their important legislation.”
However, the PUC said lawmakers have provided it with additional funds for a 49-person staff increase, effective Sept. 1. That includes full-time staff devoted to legislation passed during the 2023 session. Salaries account for the bulk of the 56% budget increase for the 2023-2025 biennium.
The commission has added 25 positions since the end of the last session in May, growing its headcount to 225.
“The PUC will continue to add [staff] over the course of the biennium, but it will take time to complete the expected growth,” the commission’s Ellie Breed said in a statement. “In addition to the time it takes to post and fill positions, we need to allow time for onboarding and training new employees in the PUC’s complex subject matter.”
Stoic Energy CEO Doug Lewin said the rumors surrounding the PUC just add to the state’s uncertain regulatory environment.
“Regulatory uncertainty is a is a major problem in ERCOT right now,” he said. “If you look at the huge amount of money in the market, particularly this year, but last year too, these were big years for generators. If you had a strong regulatory signal that the competitive market is going to continue to share it … I think you would be seeing a lot more investment. But I think a lot of what’s happening is they’re like, ‘Is [the market] going to be bad? Is it going to be something we’ve never heard of before? What is this performance credit mechanism?’ So, I do think that regulatory uncertainty is a drag on investment.”
[This story was updated Nov. 11 to add comments from Commissioners McAdams and Cobos.]
FERC commissioners and the industry and state witnesses before them at the commission’s annual reliability technical conference Nov. 9 were split on whether EPA’s latest greenhouse gas rule for power plants can be implemented reliably and affordably.
Chair Willie Phillips opened up the afternoon’s panels focused on EPA’s proposal under Clean Air Act Section 111(d) by noting that FERC’s first job is to maintain reliability. (See EPA Power Plant Proposal Gets Mixed Reception in Comments.)
“For half a century, EPA has set and enforced the emission standards that apply to every power plant in the nation,” Phillips said. “We remind ourselves again, at the outset of this conference, that our piece of the electric power puzzle is defined by the Federal Power Act. We do not build, certificate or authorize the construction or retirement of power resources. That responsibility lies with the states. We also do not have the authority to second-guess EPA’s regulatory choices.”
FERC’s task was to better understand how the rule would impact the grid going forward, with the knowledge that predicting future outcomes is a “fraught task,” he added.
Joseph Goffman, principal deputy assistant administrator for EPA’s Office of Air and Radiation, laid out the details of the rule, which he noted was still under development and would likely change before it is finalized.
“The proposed carbon pollution standards are in fact crucial to addressing the urgent need to reduce climate-destabilizing carbon dioxide pollution from the power sector,” Goffman said, “and an important part of the agency’s broader efforts to address the multiple health and environmental impacts of the power sector, while supporting the continued delivery of reliable and affordable electricity.”
The proposal includes varying compliance levels for coal and gas plants that depend on how long they plan to keep running and how often they are actually dispatched by grid operators, Goffman said. The rules will allow the industry to keep building uncontrolled combustion turbines needed to meet peak demand, while the only coal plants facing the strictest requirements are those that keep running past 2040.
The rule will also be implemented by states’ environmental agencies, and they will have some flexibility to make the rules workable. EPA is also proposing a transparent exemption process for units critical to reliability that cannot comply with the rule — as it did for the Mercury and Air Toxics Standards (MATS) a decade ago, Goffman said.
“I like to think about us as being maybe in the fifth inning of this process,” Goffman said. “We haven’t even gone to the bullpen yet. So, there’s a lot of work that we still understand that we must do on the path to finalizing these rules. And we are committed to engaging with reliability stakeholders as we develop the final rule.”
The last half of the game will involve EPA iteratively refining its rule and turning to FERC, state regulators, the industry, grid operators and others to get their expert opinions on any changes, he added.
The rule would require the longest-lived and most used fossil power plants starting in the 2030s to use carbon capture and storage (CCS), or clean hydrogen at scales that have yet to be proven for either technology. Their lack of viability has been a common criticism, and Phillips asked Goffman to address it.
EPA has designated those technologies as the “best system of emission reduction,” but states will ultimately get to pick the strategies that work for them. Both CCS and clean hydrogen have significant federal backing under the Inflation Reduction Act as well, Goffman said.
“We’ve had reports from various RTOs, in fact, almost all of them, that they’ve had unexpected retirement rates that they didn’t anticipate,” said Commissioner James Danly. Coupled with the difficulty of fully using all the incentives from the IRA and issues around interconnection, it is likely that law will not fully spur the massive growth in new clean energy some have predicted, he argued. Thus, the process of replacing the emitting plants with new clean capacity will not be as robust as EPA might think.
FERC Commissioner James Danly questions EPA Assistant Administrator Joseph Goffman at Thursday’s technical conference. | FERC
“You’ve laid out a lot of issues that I think we are going to have to address in terms of how we account for potential retirements,” Goffman replied.
Even without EPA’s rule, those issues are going to be facing FERC as the industry is transitioning away from fossil fuel to renewables and other cleaner resources because of other policies and market forces, said Commissioner Allison Clements.
“We face the need for markets to evolve to send the right signals to provide resources with the revenue certainty and to provide services we need,” Clements said. “That’s within FERC’s jurisdiction and is in need of change before we even get to this policy.”
Finalizing compliance with Order 2023 will help on that front, and FERC could also take up issues around retirement notifications to help remedy that issue, she added.
Less Room for Error
PJM released a paper early this year, before EPA released its proposal, projecting it would see 40,000 MW of retirements by the end of 2030, but it has already seen some announced retirements since then that it was not expecting, so the actual numbers could be bigger, said Mike Bryson, the RTO’s senior vice president of operations.
“We look at certainly the impact of the IRA, which I appreciate has a lot of stimulus in there,” Bryson said. “But we also look at the Ørsted announcement about Ocean Wind 1 and Ocean Wind 2 — 7,500 megawatts, which was supposed to be replacement megawatts.” (See Ørsted Cancels Ocean Wind, Suspends Skipjack.)
While PJM’s markets worked to help reliably transition its fleet from the MATS rule, which led to significant retirements of coal plants, its markets are different now. The reserve margin is thinner, and there is less room for error this time around, Bryson said.
Other industry speakers were more blunt, with Eastern Kentucky Power Cooperative CEO Tony Campbell, who was testifying for the National Rural Electric Cooperative Association, calling the rule “unlawful, unworkable, beyond salvage and disastrous for grid reliability.”
“Even if we put aside the enormous cost involved, the proposed rule relies on CCS and clean hydrogen, neither of which are ready at levels and scales for a sound economy that requires certainty, and not in all regions of the country,” Campbell said. “The infrastructure needed for both technologies is not now and will not be in place at the scale to meet EPA deadlines.”
Beyond the costs, both technologies need pipeline infrastructure, which has not been easy to build for natural gas, and that at least has an established regulatory regime, he added.
Campbell was not alone in questioning the rule’s legality, but Edison Electric Institute Vice President General Counsel Emily Sanford Fisher said that issue would ultimately be decided in the coming years in the courts.
EEI’s investor-owned utility members have embraced the clean energy transition, with Fisher noting the industry has met the goals of the Clean Power Plan even though it never it went into effect, and 2022 saw emissions equal to 1984’s.
“Regardless of any final EPA regulations addressing greenhouse gas emissions from … the fossil generating fleet, the clean energy transition is not going to be easy,” Fisher said. “Challenges do not mean, however, that this transition is impossible, or that our larger goals about a resilient equitable, affordable, clean energy future should change.”
Those challenges will require working across myriad stakeholders to address them, and the industry and policymakers should be prepared for some “bumpy” progress occasionally, she added.
EPA is likely paying close attention to the legal issues around its rule, given its experience with the Clean Power Plan being overturned, noted Analysis Group Senior Adviser Susan Tierney, who had released a paper before the technical conference explaining how the industry could meet the proposed rule’s requirements reliably. It echoed arguments she made for other EPA rules issued under the Obama administration.
“In each instance in the past dozen years, the industry and other stakeholders predictively stepped up to ensure that actual reliability was not compromised,” Tierney said.
Some of the particulars this time are different than in the past, but there are also reasons to be assured that a final EPA rule will not jeopardize reliability, she added.
Colorado is well underway to deep decarbonization, pushed by state policy and being one of the few states to benefit from plentiful wind and solar without the need for massive transmission lines, said its Energy Office’s executive director, Will Toor. It expects all coal plants to be retired before EPA’s requirements kick in, while its natural gas fleet will operate at low capacity factors, balancing a growing share of wind and solar.
“We do believe that it will be important as the EPA finalizes the rules to ensure maximum flexibility for states to comply in the most cost-effective manner,” Toor said. “We urge EPA to maximize the ability of states to use trading, massive rate-based averaging and other approaches. This should include an ability for states to recognize the changing use of existing gas plants over time.”
By 2030, only one gas unit in the state is expected to approach a 20% capacity factor, which falls to 11% before the end of that decade, he added.
“I’ve got to believe that before you get investors in, a 20% capacity unit is going to be rate based, and therefore the owners are going to be guaranteed cost recovery,” said FERC Commissioner Mark Christie.
Toor answered yes, and Christie noted that no investors are going to want to build additional natural gas plants that run so rarely. But Toor said his state has found that is the cheapest way to operate the grid going forward, even including the total costs of natural gas plants.
