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November 15, 2024

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NYISO to Pause New Interconnection Requests for 3 Months in Order 2023 Transition

RENSSELAER, N.Y. — NYISO on Feb. 6 presented the Interconnection Issues Task Force (IITF) with its plan for transitioning to its new generator interconnection procedures under FERC Order 2023, including a nearly three-month pause on accepting new interconnection requests.

The pause would begin April 4, one day after NYISO’s deadline to file its full Order 2023 compliance proposal with FERC. The commission last month approved a partial compliance filing that allows developers to opt in to certain studies that will be eliminated under the new rules. (See FERC Approves NYISO Waiver on Interconnection Study Requirements.)

The ISO would then begin accepting applications into a transitional cluster July 1, until Oct. 15; work on processing the projects would begin Jan. 15, 2025, with a goal of finishing by April 20, 2026.

The “first official study” under Order 2023 would then begin on May 1, said Sara Keegan, NYISO’s assistant general counsel, “but we’re still looking at this start date and how to actually tie it into the end of the [transitional study], so this is still a bit of an unknown.”

Keegan highlighted the possibility of changes to the proposed transition timeline because of the “inherent risks” associated with any FERC filing. She said FERC “does not have a deadline by which they have to act,” so should the commission not issue a timely ruling or require additional compliance requirements, “things could unravel” and necessitate adjustments to the proposed dates.

NYISO is “approaching this filing carefully,” Keegan said, and it “appreciates the frustration” from developers who are apprehensive about the transition, especially those either with projects already in the interconnection queue as part of class year 2023 or considering having their projects participate in the transitional cluster.

Keegan discussed other adjustments to NYISO’s interconnection procedures during the IITF meeting, which will eventually be in tariff Attachment HH. This proposed attachment will consolidate existing interconnection requirements from Attachment S (rules to allocate responsibility for the cost of new interconnection facilities), Attachment X (standard large facility interconnection procedures) and Attachment Z (small generator interconnection procedures), along with the new processes. The attachments will remain in NYISO’s tariff for the limited purpose of completing CY23 projects and facilitating the transition.

The ISO also posted a redline of Attachment HH, incorporating stakeholder feedback since the last IITF meeting.

NYISO will return to IITF stakeholders multiple times before the April 3 filing deadline to review and finalize the proposed tariff language.

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PJM PC/TEAC Briefs: Feb. 6, 2024

Planning Committee

Stakeholders Endorse Revised RRS Values 

The Planning Committee endorsed a PJM proposal to reset the installed reserve margin (IRM) and forecast pool requirement (FPR) values for the 2025/26 delivery year to reflect the shift to marginal ELCC accreditation approved by FERC last month (ER24-99). The changes were approved with 57% support. 

Driven by several resource classes seeing reduced average accreditation, the FPR would decline 15% from the 1.1171 endorsed by stakeholders last year to 0.9440, while the IRM would remain static at 1.17%. The FPR formula was changed in the filing approved last month to multiply the IRM by the pool-wide average accredited unforced capacity factor, rather than the equivalent forced outage rates previously used, to determine the capacity required to meet forecast peak load. (See “Stakeholders Endorse Reserve Requirement Study Values,” PJM PC/TEAC Briefs: Oct. 3, 2023.) 

PJM’s Pat Bruno said the RTO continues to review the unit-specific performance adjustment before it can release generator’s accreditation values, which are calculated using the adjustment and class ratings presented to the PC. Those values are to be considered by the Markets and Reliability Committee and Members Committee for endorsement Feb. 22. The PJM Board of Managers is expected to establish the values by the end of the month. 

PJM’s Patricio Rocha Garrido said the FPR values PJM proposed Feb. 6 differed from preliminary estimates because of increased winter risk being identified because of the resource portfolio including a higher concentration of solar resources and fewer wind generators. Bruno said there also was a smaller number of generators that attested to their ability to provide dual-fuel capability than expected and those that did seek that classification had a wide range of historical performance, resulting in some being disqualified. 

Multiple stakeholders said there was too little information to understand how the new figures were being calculated and the effect they could have on unit-specific accreditation, raising a concern that the new values were being moved to a vote too quickly. 

“I am concerned about PJM pushing us to vote. Clearly there was very little transparency into the numbers that PJM has published. They have extraordinary commercial implications for all of your stakeholders. To try and cut off conversation is really inappropriate,” LS Power’s Marji Philips said. After the meeting, Philips said she appreciated PJM allowing more voices to be heard before moving to a vote. 

PJM Corrects Electric Vehicle Load Forecast

PJM updated its forecast for electric vehicle load growth with corrected figures from S&P Global, which PJM contracted to provide estimates for the first time for the 2024 Load Forecast. (See “PJM 2024 Load Forecast Sees Jump from EVs, Data Centers, Heat Pumps,” PJM PC/TEAC Briefs: Dec. 5, 2023.) 

The projected numbers were incorrectly offset to increase one year in advance, PJM’s Andrew Gledhill said, resulting in the EV forecast being inflated by 10% for 2030. The revised forecast resulted in varying outcomes across transmission zones, with the MedEd region seeing the largest difference with a summer peak forecast over 2% smaller in 2030. 

Vistra’s Erik Heinle questioned if PJM plans to continue using contractors for this portion of its forecast or if multiple vendors could be used to receive estimates that could be analyzed or averaged together. Gledhill said PJM sees value in getting an outside expert opinion on EV load growth and there has not been any decision to change course. 

Transmission Expansion Advisory Committee

Supplemental Needs and Project Proposals

    • Exelon presented a $175 million project to build a new Keslinger Substation and several lines in its ComEd zone to serve a new customer with an ultimate load of 210 MW. Keslinger would include four new six-mile lines cutting into the Waterman-Crego Road and Crego Road-Glidden 138-kV lines, as well as two new 345-kV lines spanning 0.7 miles to cut into the Nelson-Electric Junction lines. The project is in the conceptual phase with an envisioned in-service date of Dec. 31, 2027.
    • Exelon revised the scope of a prior project to build a new Navy Yard 230-kV substation to serve growing load in Philadelphia, bringing the cost from $71 million to $82 million. The original design would have configured the facility as a breaker-and-a-half. Limited space led the utility to shift to a ring configuration. The project is in the conceptual phase with a projected in-service in 2029. 
    • Public Service Enterprise Group revised a project to upgrade communications equipment on 500-kV lines running between its Deans, East Windsor and New Freedom substations, increasing the cost from $20 million to $39 million. The new proposal would replace 68 miles of static wire with fiber lines and upgrade line relay equipment. The original proposal would have replaced the static wire with optical guide wire. The project, which is in the conceptual phase, would complete work on the Deans-East Windsor line in December 2025 and finish the East Windsor-New Freedom line in June 2027. 
    • PPL presented a customer service need to add 1,275 MW served by a 138-kV source in New Kingston, Pa. The load is expected to come online in the summer of 2026 starting at 40 MW and grow to 1,275 MW in 2032. 
    • Dominion Energy presented several distribution requests to serve data center loads in Northern Virginia. 
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SPP Board of Directors/Members Committee Briefs: Feb. 5-6, 2024

SPP senior management rolled out its top 2024 corporate goals for its Board of Directors and stakeholders, cautioning they don’t reflect all the important work the grid operator will take on this year.

“While we believe that every one of these goals [either is] … mission critical or [provides] significant strategic value, we’ll also strive to be as affordable as we can be as we undertake these efforts,” COO Lanny Nickell told the board and Members Committee Feb. 6 during their virtual meeting.

Topping the list, of course, is resource adequacy — “one of our greatest risks,” Nickell said —and mitigating those risks. “We’re continuing to see increasing amounts of intermittent generation,” he said. “At the same time, we’re seeing thermal generation being retired, [and] we’re experiencing extreme load growth, and also an increasing threat of extreme weather.”

SPP has listed 15 initiatives that reflect the priorities the Resource and Energy Adequacy Leadership (REAL) Team established in 2023. They include a winter resource adequacy requirement, value-of-lost-load metrics and usage policy, an improved outage policy, and winter and summer planning reserve margin (PRM) revision requests. (See ‘Therapy Session’: SPP REAL Team Reviews Draft LOLE Study.)

Nickell noted the three severe storms that swept across the SPP footprint during the past four winters and said it should not be a surprise the grid operator wants to “continue to enhance our readiness for extreme weather” as its second goal.

He said reports filed after winter storms Uri and Elliott contain 33 recommendations for improvements. Staff plans to close out the remaining open items from the reviews and bring back a final report to the board next January.

“We expect that will complete development of our market policies and will enhance our transmission planning processes to address extreme weather scenarios,” Nickell said.

The other three goals are:

    • optimizing the generator interconnection (GI) queue’s processing;
    • advancing innovative transmission policies; and
    • continuing the western expansion’s progress.

All five goals come with specific milestones designed to chart progress and gauge success at year’s end.

“We know priorities will likely change throughout the year. … These could very well get rearranged as we go through the year,” Nickell said. “We know that some of these are going to take years in order to fully effectuate and realize the benefits of the policies and requirements that are being proposed.”

To drive the message home to staff, CEO Barbara Sugg said SPP has, for the first time she could remember, developed a theme for the year: EMBRACE 2024. It’s an acronym for Expansion, Mission, Branding, Reliability, Affordability, Community and Engagement.

“EMBRACE is an acronym, because it’s the world we live in,” she said. “We’re going to see the word ‘EMBRACE 2024’ plastered throughout the [SPP headquarters] building. We really want the employees at every level of the organization to come together under this particular theme as we work on addressing the challenges and the opportunities that we face in 2024.”

Congestion-hedging Policies’ Implementation

SPP’s board and regulators approved the implementation of a package of eight congestion-hedging policies they signed off on in July 2023. The proposals are designed to increase equity, fairness and financial transmission rights awards among market participants. (See SPP Board/Members Committee Briefs: July 24-25, 2023.)

Stakeholders have since added language for the annual long-term congestion rights (LTCRs) analysis performed during each round of the auction revenue right (ARR) nomination process. This ensures nominated candidate ARRs do not violate any transmission-line thermal ratings under normal system conditions.

They also revised the policies to distribute ARR surplus. This includes an iterative approach to the ARR allocation’s first round and the distribution of excess auction revenues. Once approved by FERC, SPP would allocate 50% of the excess revenue in one year under the old method and 50% under the new method. After that, the new process would take over.

Board votes are not disclosed, but the Regional State Committee approved RR591 by a 10-2 vote, with South Dakota’s and North Dakota’s commissioners both casting dissenting votes.

North Dakota’s Randy Christmann said some members have invested the time to make the policies work for them, while others “maybe did less of that.”

“So now we’re just going to socialize it, and I just don’t find that right,” he said.

The board also approved without discussion RR583, which allows SPP to nominate LTCRs for federal service exemption and grandfathered agreement carveouts to further mitigate the load’s exposure to the day-ahead market’s congestion costs.

The rule change became necessary when SPP added the northern portion of the Western Area Power Administration, a federal power marketing agency. WAPA brought with it grandfathered transmission rights that caused some loss of congestion opportunities for other market participants.

“This is certainly not a fix to congestion-hedging issues, but it’s a good small step forward,” said Minnesota Commissioner John Tuma, the RSC’s chair.

Sarah Martz, a member of the Iowa Utilities Board, cast the lone opposing vote against the change during the RSC meeting over concerns it will create more scarcity of LTCRs should congestion-hedging rights be reset.

Compliance Deadline Met

The board and directors approved urgent proposed tariff changes (RR606) setting the PRM to meet a FERC compliance deadline. The change includes explanations of the loss-of-load expectation study methods, assumptions and approval process, and the timeline for the PRM’s approval and implementation process.

Staff met the deadline with a Friday filing, asking for an effective date of April 10.

The proceeding stems from FERC’s rejection in 2023 of several members’ attempt to overturn SPP’s 2022 tariff change raising the PRM from 12% to 15%. The commission in September 2023 denied a rehearing request, modified the discussion and directed the grid operator to make a compliance filing (EL23-40). (See FERC Rejects Protest of SPP PRM Increase.)

American Electric Power, Oklahoma Gas & Electric and Xcel Energy are the SPP members that protested the original order. Stacey Burbure, an AEP vice president, said AEP doesn’t believe the tariff change goes “quite far enough” and is not certain it “fully complies with a directed revisions directed by FERC and its order.”

“Our concern has always been, and remains, having an appropriate level of detail and the tariff to ensure that the process is transparent,” she said. “We fully support the need for flexibility and increasing the planning reserve margin to meet reliability needs, but we also recognize that there needs to be an appropriate balance with respect to the level of the detail and the tariff.”

AEP and Arkansas Electric Cooperative Corp. opposed the measure, which passed the Members Committee’s advisory vote 16-2, with three abstentions. AECC’s Andrew Lachowsky said the cooperative already is adding a 900-MW generating resource but is worried the PRM will be increased again before the unit goes online.

During the RSC’s discussion of RR606, Oklahoma Corporation Commission Chair Todd Hiett offered an amendment that, should the PRM need to be increased by more than a percentage point, the new value would not be effective until at least a year after the regulators’ and directors’ approval.

“Just to ensure we don’t do too much too fast,” Oklahoma Municipal Power Authority’s Dave Osburn said.

The amendment failed, 2-10. The RSC then unanimously approved the measure.

Board Approves Appeal

The board approved renewable interests’ appeal of a revision request (RR592) approved in January by the Markets and Operations Policy Committee, siding with their request to endorse an amendment that failed during that meeting.

The Advanced Power Alliance and nine other members asked directors in a letter to reduce the risk of further GI study delays by adopting the amendment or adding a later cluster study. The amendment would have approved RR592, effective with 2022 and 2023 Phase 2 studies. Instead, MOPC endorsed a fuel-based dispatch adjustment beginning with a 2021 Phase 2 study.

Transmission Working Group Chair Derek Brown, with Evergy, told the board MOPC’s decision could add six to 18 months to the GI backlog mitigation effort. As passed by MOPC, RR592 includes nonfirm, nonlegacy Integrated Transmission Planning generators as prior-queued in steady-state analysis dispatch tables.

David Kelley, SPP’s engineering vice president, said staff supported implementing the measure with the 2022 study.

“It gives us more time to work on any issues that we may see and allows us to complete [the 2021 study], and it wouldn’t prevent us from hopefully completing the goal that we’ve set for completing 2022 [studies] this year,” he said. “I think that sufficiently buys us enough time that we would be comfortable as staff if the board were to adopt the amendment.”

The Members Committee’s advisory vote to the board endorsed the appeal, 10-8, with three abstentions.

Western Expansion ‘Ramping Up’

Bruce Rew, SPP’s senior vice president of operations, said during the quarterly joint stakeholder briefing that the RTO’s western expansion is “ramping up” and “continuing to move forward.”

He said staff has completed drafting tariff changes for RTO West and created 15 revision requests. The first six tariff changes were approved unanimously by the Markets and Operations Policy Committee during January’s meeting, and the full package, including membership agreements and bylaw changes, will be brought to the board’s April quarterly meeting.

Several of the seven utilities in the Rocky Mountains region that are interested in joining the RTO have embedded entities within their balancing areas. SPP is working with the entities to determine how they would participate in the market or pseudo-tie out of the system to join another BA. Staff are preparing the entities to declare their intent by April 1, Rew said.

SPP plans to file its tariff changes May 31, even as systems development begins in April. Go-live is targeted for April 2026.

“We’re pleased with the progress so far,” Rew said.

SPP RTO West could add four states to SPP’s footprint: Arizona, Colorado, Utah and Wyoming.

3rd 100-year Storm in 4 Years

“What would the new year be if we hadn’t already had some kind of an extreme weather event?” Sugg asked rhetorically. “We all know that they’re no longer called 100-year storms when you have three of them in four winters. We might start calling them holiday storms, though, because they all are tied to some national holiday.”

Sugg said SPP experienced its highest 24-hour winter load during the January winter storm and its sixth-highest overall, just missing a seasonal peak by about 400 MW. The grid operator was able to import 6.7 GW from its neighbors at one point, exceeding the 6 GW of imports during the February 2021 storm.

“We were certainly thankful for our interconnections and our interregional transfer capacity,” Sugg said, thanking the RTO’s neighbors. “There is no way that we could have been successful with that winter event if not for our member companies and your system operators.”

Consent Agenda Passes

The board’s consent agenda approval included the Corporate Governance Committee’s review of stakeholder group rosters to ensure members’ expertise and geographic locations yield a “widespread and effective representation of the membership”; modification of a notification to construct (NTC) issued to Western Farmers Electric Cooperative for a 20-MVAR capacitor bank; withdrawal of an NTC issued to Southwestern Public Service Co. for a $1.1 million, 115-kV line upgrade; an out-of-cycle re-evaluation of a Northwestern Energy 115-kV project after a new power plant was added to models; the 2024 Transmission Expansion plan; and the 2023 Integrated Transmission Plan’s (ITP) short-term reliability project report.

The consent agenda also included three RRs that:

    • RR560: move operating criteria language to the system operating limits (SOLs) methodology.
    • RR597: document the day-ahead market’s high-level process used for effective limit application.
    • RR598: remove planning criteria portions outlining the methodology to develop SOLs and interconnection reliability operating limits in the planning horizon. This aligns with NERC’s retirement of Mandatory Reliability Standard FAC-010-3.
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PJM MIC Briefs: Feb. 7, 2024

Stakeholders Endorse Real-time Temporary Exception Manual Revisions

VALLEY FORGE, Pa. — The Market Implementation Committee endorsed revisions to Manual 11 to codify the real-time temporary exception paradigm approved by FERC on Nov. 30. This replaces PJM’s real-time values process for generators to submit any change in their ability to perform to their unit-specific parameters. (See “Real-time Temporary Exceptions Manual Revisions Proposed,” PJM MIC Briefs: Jan. 10, 2024.) 

The temporary exceptions process is designed for short-term events and repeat or long-term constraints over 30 days that should be reported to PJM and the Independent Market Monitor as period exception requests, PJM’s Lauren Strella Wahba said. Generation owners should notify PJM and the Monitor when the resource has returned to being able to operate at full capability. 

During the Feb. 8 Operating Committee meeting, PJM’s Chris Pilong said temporary exceptions led to an uptick in outages being reported at least a day in advance of the unit being scheduled. However, only 22% of gas generators reported outages despite all pipelines seeing constraints that warranted notifying PJM. 

PJM Discontinues Market Certification Exam

Citing low participation and difficulties keeping exam materials up to date with the rate of market design change, PJM has retired its market certification exam with the aim of replacing it with a certification of training completion which signals that an individual is competent with the procedures in place at that time. 

PJM’s Don Kujawski said it typically takes two to three years to develop new exams, introducing the possibility that questions may be outdated by the time trainees are in the classroom. Enrollment also has been significantly lower than the other certification programs PJM administers. About 60 people have taken the markets exam since its inception, whereas around 1,000 have taken the generation and transmission exams. 

The new paradigm will be put into practice with the market optimization workshop scheduled for the third quarter of 2024. 

Other Committee Business:

    • PJM provided additional detail on its quick fix proposal to revise Manual 11 to reflect its approach to interface pricing points, a mechanism that groups buses together when calculating LMPs for energy transfers between external areas. Delivering the second first read, PJM’s Zhenyu Fan said the proposal is a response to a recommendation from the Independent Market Monitor that PJM adjust the weighting of the component interfaces to maintain congruity between prices and system conditions and also conduct annual reviews of the mapping of neighboring balancing authorities to individual interface pricing points. The manual revisions would add a definition for interface pricing points and establish an annual review looking at power flow impacts on each interface. Fan said similar language already included in the governing documents and the manual changes, which are set to be considered for MIC endorsement March 6, would memorialize existing practices. (See “Quick Fix Proposal on Interface Pricing Points,” PJM MIC Briefs: Jan. 10, 2024.) 
    • PJM’s Pete Langbein told the committee that an increase in load forecasting will prompt demand for about 3,000 MW of additional capacity in the third Incremental Auction, which is set to open Feb. 27. 
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PJM OC Briefs: Feb. 8, 2024

Stakeholders Endorse TO/TOP Matrix Revisions 

The Operating Committee endorsed revisions to the Transmission Owner/Transmission Operator (TO/TOP) Matrix, which defines the tasks TOs and PJM are accountable for to comply with NERC reliability standards. Gizella Mali, TO/TOP Matrix Subcommittee chair, said the changes reflect several new NERC reliability standards including EOP-011-4 (Emergency operations), FAC-014-3 (Establish and communicate system operating limits), IRO-017-1 (Outage coordination) and TOP-001-6 (Transmission operations). (See NERC Board Approves Cold Weather Standards.) 

Operating Metrics

PJM’s daily peak forecast error exceeded its targeted 3% two days last month, with actual loads Jan. 9 and Jan. 12 being between 3% and 4% higher than forecast, according to Markets Coordination Manager Stephanie Schwarz. The RTO experienced one shared reserve event and three spin events in January, and the winter storm that spread across the region in the middle of the month led to one conservative operations alert, two cold weather alerts and 22 post-contingency local load relief warnings. 

Security Update

PJM Director of Enterprise Information Security Jim Gluck urged members to keep computers and networked devices, particularly home routes for out-of-office employees, updated to reduce the risk that attackers can use old vulnerabilities to gain access to critical infrastructure and remain dormant. He said attacks from the Volt Typhoon group have targeted critical infrastructure software and attempted to fly under the radar by not installing malicious software to instead take advantage of any existing vulnerabilities. One of the group’s tactics has been using unsecured routers of employees working from home. 

A separate recent attack he highlighted used a company’s software development sandbox environment to gain access to a wider range of internal systems, including a portion of the company’s email accounts. He also gave the perennial advice that members be wary of suspicious communications that may be attempting to gain sensitive information or designed to trick employees into opening malicious files.  

Other Committee Business

    • Stakeholders endorsed revisions to Manual 38, which pertains to operations planning identified by PJM during the document’s periodic review. The new language would specify that the studies conducted by the Operations Assessment Task Force will use generation outage data selected from three previous seasons rather than comparable seasons. The changes are scheduled to be voted on by the Markets and Reliability Committee on Feb. 22. 
    • The committee endorsed revisions to Manual 40, which defines training and certification requirements, to update the titles of programs that have changed, clarify the responsibilities of different PJM positions and add detail to how rollover hours are calculated. The MRC is set to consider endorsing the changes Feb. 22. 
    • Stakeholders endorsed a PJM quick-fix proposal to remove the Compliance Bulletin 14 in Manual 3A and add language pointing to NERC’s bulk electric system (BES) element definitions. The compliance bulletin details how PJM members are to notify the RTO of any changes to BES elements resulting from NERC’s BES definition. The proposal is set for an endorsement vote at the MRC on Feb. 22 and at the System Operations Committee on March 1. 
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Report Outlines Cost Savings of All-electric Buildings in Mass.

New all-electric buildings will likely save Massachusetts homeowners thousands because of increasing gas system maintenance costs and the effects of a shrinking gas rate base, according to a report released Feb. 8 by Groundwork Data. 

The report said construction costs for all-electric residential buildings are now within 1% of buildings that rely on fossil fuels, while electric heating operating costs are lower than those for oil and propane but slightly higher than natural gas. 

“All-electric new construction is poised to quickly become much more cost-effective than gas under expected emissions regulations and increasing average gas delivery costs,” the report said. 

The analysis was commissioned by ZeroCarbonMA, a climate advocacy group that has pushed to ban fossil fuels in new buildings in the state. 

The report estimated that the state will hit an inflection point around 2030, when electrified heating customers will start to see cost savings relative to gas customers, with the savings steadily increasing in the coming decades, reaching $4,000 annually around 2055. 

Projected GSEP capex costs to ratepayers | Groundwork Data

“The three key drivers behind this inflection in energy costs are the increasing cost of gas pipeline maintenance (largely to manage leak-prone pipe), the declining consumption expected with even modest levels of heating electrification and potential efforts to regulate emissions,” the report said. 

While building electrification is likely to shrink the gas rate base, maintenance costs are projected to accelerate because of the state’s Gas System Enhancement Program (GSEP), which encourages gas utilities to replace leak-prone pipes to reduce methane emissions. 

In an analysis presented to the state in 2023, Groundwork estimated that GSEP investments between 2022 and 2039 will cost ratepayers more than $34 billion, with costs peaking around 2040. (See Mass. Gas Working Group Finalizes Recommendations to Legislature.) 

Increasing gas rates will likely be most burdensome for low- to moderate-income ratepayers who have less ability to switch to electric heating when gas rates accelerate, the report noted. Because a portion of the costs associated with new hookups is spread throughout the rate base, new gas connections could exacerbate affordability issues for existing customers. 

Groundwork’s Mike Walsh, the author of the report, said there is limited public data about how much of the cost of new gas hookups is covered by the general rate base. The formulas utilities use to determine the breakdown of costs between new customers and the rate base assume that these costs will eventually be recovered from customers over the extended life of their gas connection, he said. 

Walsh noted that the researchers did find data from one of the state’s smaller utilities that indicated that the rate base was on the hook for about 80% of the cost of a pipeline extension to connect a new customer. 

“Most of these homes that are being built in new construction, whether it’s commercial or residential, are for more affluent customers,” Walsh said. He added that if the new customers leave the system before the full costs can be recovered, “that’s an equity concern. We don’t know if that’s happening here because we don’t know what those formulas are.” 

For customers looking to electrify and exit the gas system, retrofitting existing buildings is not cheap. Electrification retrofits could cost $16,000 to $17,000, which could be avoided entirely if the building was built all-electric in the first place, the report said. 

“The state is going to be on the hook for more and more retrofits,” said Lisa Cunningham of ZeroCarbonMA. “We’re going to have to spend even more money retrofitting the gas infrastructure that’s going in today.” 

Cunningham emphasized that as gas costs accelerate, the costs of maintaining the system could increasingly fall on ratepayers who can’t afford the expensive retrofits needed to exit. 

The scope of retrofits looming over the state is significant. The final 2021 report from the state’s Commission on Clean Heat estimated that the state will need to electrify 500,000 residential homes by 2030 and 1.3 million homes between 2030 and 2050. 

Over the past few years, the state has passed several laws encouraging fossil fuel-free buildings. In 2021, the legislature created a municipal opt-in specialized energy code that incentivizes the construction of all-electric buildings, and in 2022 it created a pilot program to allow 10 municipalities to ban fossil fuels in most new buildings. 

However, all-electric buildings are far from a mandate for most of the state, and gas utilities have continued to add new connections in recent years. In the current legislative session, top lawmakers have been hesitant to expand the 10-town pilot program to include additional municipalities, citing the need to evaluate the data from the pilot. 

At the Feb. 7 deadline for the joint committees to report on bills, the legislature’s Telecommunications, Utilities and Energy (TUE) Committee declined to favorably report several bills to expand the pilot. 

The Senate side of the committee did favorably report several bills targeting the gas system, including S.2105, aimed at promoting and facilitating the transition to clean heating technologies, and S.2135, which would establish a moratorium on new or expanded fossil fuel infrastructure in the state. (See Mass. Lawmakers Aiming for an Omnibus Climate Bill in 2024.) 

The recommended bills from the House side do not include much to “move the needle on building emissions. … It’s more in the Senate,” Larry Chretien, of the Green Energy Consumers Alliance, told NetZero Insider. “Things like the report coming out of ZeroCarbonMA, I hope, will inform that discussion.” 

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SPP Regulators Settle Their Leadership Structure

SPP state regulators last week filled a leadership vacancy within the Regional State Committee by approving the Nomination Committee’s selection of Oklahoma Corporation Commission Chair Todd Hiett as its vice president.

He replaces Minnesota Commissioner John Tuma, who was to serve as the commission’s vice president this year until incoming President Will McAdams resigned from the Texas agency and the RSC last year. McAdams was elected as president during the state regulators’ October meeting, but Tuma said McAdams called him three hours after the meeting and told him he was planning to resign.

“I was elected vice president but immediately became president,” Tuma mused during the committee’s Feb. 5 meeting.

The Nebraska Power Review Board’s (NPRB) Chuck Hutchison remains the RSC’s treasurer and secretary, with Texas Commissioner Lori Cobos replacing McAdams.

McAdams officially resigned from the Texas commission in December and has since joined an Austin, Texas-based lobbying firm. He also agreed to consult with the RSC, focusing on the Resource and Energy Adequacy Leadership (REAL) Team under its chair, South Dakota Public Utilities Commissioner Kristie Fiegen. If time allows, McAdams also will work on interregional planning issues.

“He’s rolled up his sleeves and dived right into work already,” Tuma said. “I know that for a fact, because I’ve already approved the first invoice a couple of days ago.”

“I sincerely appreciate the work of the RSC leadership and of the REAL Team to allow me to continue to work on these important issues for the [load-resource entities], those utilities and stakeholders,” McAdams said. “I look forward to being able to work with you and members of the REAL Team to continue to address our large and important calendar.”

Revised RCAR Endorsed

The RSC approved the lessons learned from SPP’s third regional cost allocation review (RCAR), long a bone of contention by Missouri utilities that have felt the review’s methodology results in their benefit-to-cost ratio being unreasonably high.

The most recent RCAR, completed in 2022, left City Utilities of Springfield and Empire District Electric with B/C ratios of 14.87 and 7.99, respectively. Post-review adjustments lowered those ratios to 3.82 and 3.82, respectively.

Fiegen, who chaired the Regional Allocation Review Task Force, said after the first two reviews used “future theoretical models,” RCAR III used actual market data and compared it to the market without highway/byway projects.

“It had some unique opportunities to probably get more precise, but it also created some challenges,” she said.

Fiegen said the task force dug into years of daily market data to analyze the issue. Eventually, it determined the production cost runs in the base case and change case were accurate, but those liable for the costs were not as accurate as they were in the actual market.

The task force adjusted some of the benefits for the two utilities that “felt their benefits were overstated in our original report … to be more realistic,” Fiegen said. “Both of those entities have acknowledged these changes and found that they meet their needs.”

Commissioners unanimously approved seven recommended changes to the RCAR’s methodology and the updated RCAR 3.1.

JTIQ Backstop Funding OK’d

The committee unanimously agreed to a policy that the Department of Energy’s Grid Resilience and Innovation Partnerships (GRIP) funds be applied to offset capital costs’ allocation to load for SPP’s Joint Targeted Interconnection Queue (JTIQ) transmission portfolio with MISO. Using the DOE funds to cover the 10% allocation to load, with the balance going to generator interconnectors, the RTOs’ interregional load share will be eliminated.

NPRB’s John Krajewski, speaking for the RSC’s Cost Allocation Working Group, said subscriptions to fully fund the JTIQ projects are inadequate. He said conversations he’s had with transmission owners reveal a risk — and who bears it — if there’s not enough JTIQ participation.

“If the subscriptions don’t materialize, it’s the region that will be the backstop for any shortfalls that may occur,” he said. “For the first time, this would be a situation where we’re building projects without a guarantee of funding. The way that the tariff is currently written, the risk ends up falling back on the customers of this transmission owners who are building the projects.”

The DOE in October awarded $464.5 million in GRIP funds to MISO and SPP for their JTIQ portfolio. (See DOE Announces $3.46B for Grid Resilience, Improvement Projects.)

Last January, the RSC approved proposed cost allocations for the five projects in the portfolio. (See “Commissioners Approve 90-10 Split on JTIQ Cost Allocation,” SPP Regional State Committee Briefs: Jan. 30, 2023.)

The RSC also endorsed a pair of policy proposals related to availability and outage policies to avoid “paper resources,” Tuma said.

“We’re trying to … make sure that units that are in the workbooks, or outages that are done, are done in a way that we know what’s happening,” he said, “and that we have actual resources we know that we can count on when we’re doing our planning.”

SPP staff and the CAWG are collaborating on an “availability” definition (RR605) requiring load-responsible entities submitting deliverable or firm capacity to meet their resource adequacy requirement to certify the resource will be available and ready to perform at the accredited capacity level for the applicable season.

The REAL Team recommended prioritizing an outage policy for the winter planning resource margin while delaying additional components. The proposed policy will require any outage that is either taken or extended into the resource adequacy season without SPP’s approval to harm the LRE’s performance-based accreditation.

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NEPOOL Markets Committee Briefs: Feb. 6, 2024

Resource Capacity Accreditation Impact Analysis 

ISO-NE on Feb. 6 presented the NEPOOL Markets Committee with the initial results of the RTO’s Resource Capacity Accreditation (RCA) impact analysis modeling, providing a preliminary look at how the changes will affect the accreditation values and capacity market revenues of different resource classes. 

The initial results showed that the accredited capacity value of the entire resource mix decreased by about 17%. The resource classes generally boosted by the RCA updates include wind, energy efficiency and hydro. Accreditation values also increased slightly for dual-fuel gas and oil resources, as well as for a broad category of nonintermittent resources including nuclear, coal, wood, municipal solid waste and landfill gas. 

In contrast, the RCA changes would significantly decrease the accredited capacity of oil-only, battery storage, active demand response and solar resources. Gas-only resources would also take a modest hit. 

ISO-NE’s Dane Schiro noted that the resource class impacts are aggregations. He highlighted some of the main factors that could impact an individual resource’s accredited capacity. 

For thermal resources, having a high rate of historical forced outages was generally a significant factor in the loss of accreditation. Resource size also plays a role: Smaller thermal resources typically have higher accreditation values, because a forced outage of a smaller resource is less likely to cause shortfalls. 

The accredited capacity of storage resources depends largely on duration, Schiro said. For intermittent resources like solar and wind, higher accreditation values will go to resources that typically produce energy during the times it is most needed. 

As the resource mix and the timing of reliability concerns continue to shift, the capacity values and revenues for different resource classes will also shift. While ISO-NE assessed that about 80% of the loss-of-load risk occurs in the summer, the shift in risk toward winter will likely increase the annual accreditation values of resources that perform better in that season. 

In March, ISO-NE is planning to present to the MC the results of modeling sensitivities related to the resource mix and load profile and will detail how these factors affect accreditation values. 

Nonfirm Gas Modeling Concerns

Pallas LeeVanSchaick of Potomac Economics, ISO-NE’s External Market Monitor, outlined for the MC some concerns about the RTO’s proposed approach to accrediting non-firm gas capacity. 

ISO-NE said at the previous MC meeting that a “market constraint approach” that would limit the total amount of capacity available to gas resources would be its preferred method, but it said this method “is not implementable” for Forward Capacity Auction 19. (See NEPOOL Markets Committee Briefs: Jan. 11, 2024.) 

LeeVanSchaick said ISO-NE’s proposed interim “derating approach” will likely overaccredit nonfirm gas resources, reducing the incentives for firm fuel contracts that would increase winter reliability. 

He proposed that ISO-NE should instead “estimate the marginal reliability impact (rMRI) of nonfirm gas-fired units in the same manner as other resource types,” and accredit capacity using an rMRI floor “that would be sufficiently high to ensure available nonfirm gas is fully utilized in periods of reliability risk.” 

The Massachusetts Attorney General’s Office expressed concerns in a January letter to the RTO that its proposal would overaccredit nonfirm gas resources while showing interest in expediting work on a market constraint approach. 

“The opportunity to bypass ISO’s transitional derating approach would be a substantial benefit to the development of a seasonal capacity market proposal for FCA 19,” the AGO wrote. 

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OMS, OPSI Urge MISO, PJM to Invigorate Interregional Planning

The state regulatory organizations for both MISO and PJM have sent a letter to the RTOs asking them to redouble efforts around interregional transmission planning.   

The Organization of MISO States (OMS) and the Organization of PJM States, Inc. (OPSI) penned a joint letter to MISO and PJM, telling them the time is right to initiate long-term interregional transmission planning. The letter was signed by the presidents of OMS and OPSI and addressed to the RTOs’ Interregional Planning Stakeholder Advisory Committee. MISO South state agencies didn’t participate in the letter.  

“The transition from dispatchable thermal generators to intermittent, clean energy resources, and a surge in electric demand raise challenges to PJM, MISO and their interconnected neighbors’ ability to reliably and cost-effectively support one another when called upon,” OMS and OPSI wrote.  

The organizations said their concerns are heightened by increasingly common severe weather. They said MISO and PJM were “heavily dependent” on one another’s resources while importing and exporting to other neighboring regions during the December 2022 arctic blast. They also said last August’s heatwave forced MISO to import roughly 8.5 GW from PJM and Manitoba.  

“While these events were managed, the growing frequency of these events and shrinking capacity reserves in each footprint [have] the potential to disrupt electricity supplies, which in turn disrupts the economy and may put public health and safety at risk. Expanding transfer capacity between regions can help to improve grid resilience and minimize the negative impacts of extreme weather events,”  

OMS and OPSI pointed to the U.S. Department of Energy’s recent National Transmission Needs study, FERC considering a rule to establish a minimum transfer capability between regions and Congress tasking NERC with studying interregional transmission capacity.  

“With these factors in mind, OPSI and the OMS urge PJM and MISO to begin to explore joint long-term interregional transmission planning between their footprints while maintaining a focus on affordability and identifying optimal solutions,” the organizations wrote. 

The two said MISO and PJM should jointly model their systems, work with state regulators to agree on reliability and policy objectives, and borrow from their existing long-term planning to devise an interregional process.  

“Both of our organizations have a renewed focus on interregional planning,” OMS Executive Director Marcus Hawkins said during a Feb. 7 MISO Advisory Committee teleconference. 

RTOs Respond

MISO responded that it’s always looking to improve its planning processes, including interregional planning.  

“MISO has a long history of performing coordinated interregional transmission planning with its neighboring grid operators. Interregional planning helps us identify projects that improve the system’s ability to mitigate constraints, respond to extreme weather and increase interregional transfer capability,” spokesperson Brandon Morris said in an emailed statement to RTO Insider.  

Morris said MISO appreciates the regulators’ input and looks forward to “enhancing our work with our neighboring transmission planning partners while balancing our staffing needs to identify and move forward the regional and interregional solutions needed to respond to the evolving resource mix.”  

PJM spokesperson Jeffrey Shields said PJM already engages in healthy collaboration with its neighbors to identify congestion-relieving and reliability-boosting projects, as outlined in the MISO-PJM joint operating agreement.  

In an emailed statement to RTO Insider, Shields said PJM has significant export capability, as evidenced by the 12 GW in exports PJM flowed to neighbors at the height of the mid-January arctic blast.  

“At the same time, PJM is committed to working with MISO and others to determine if more should be done with interregional transmission. That discussion is ongoing,” Shields said. “PJM believes that the best way forward is with analysis on how best to define whether and what level of transmission solutions are needed to ensure sufficient interregional transfer capability. We need to understand very clearly what the problem is that we’re solving for before committing significant investments that will be borne by customers.” 

Shields said while a minimum transfer capability is “sensible,” interregional planning should not become a substitute for RTOs maintaining adequate reserve margins.

“If all of our regions are hit with the same winter storm, the results could be very harmful to consumers,” he said.  

The grid operators will address the regulatory organizations’ request again at the March 1 teleconference of their Interregional Planning Stakeholder Advisory Committee.  

MISO and PJM have approved one large interregional market efficiency project in 2020 and four sets of smaller transmission projects aimed at relieving congestion since 2017. The two haven’t completed an interregional transmission planning study since 2022.  

In a report last year, the American Council on Renewable Energy concluded MISO and PJM could save their ratepayers $15 billion over a little more than a decade if they dedicated more resources to planning interregional transmission. (See New Report Finds MISO, PJM Could Save Billions Through Interregional Tx Expansion.)  

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Early MTEP 24 Designates $5.5B in Transmission Spending

MISO revealed last week that its draft 2024 Transmission Expansion Plan calls for $5.5 billion in projects, with the South region again accounting for some of this year’s most expensive projects.

MISO has a $5.5 billion, 453-project portfolio in its hands thus far under MTEP 24, stakeholders learned over a series of subregional planning meetings last week. The draft MTEP 24 represents a more typical investment amount for MISO’s annual transmission cycle on the heels of the record-breaking, $9 billion MTEP 23.

However, MISO South transmission owners are continuing last year’s trend of recommending costly local projects.

MTEP 24 contains $793 million in generator interconnection projects, $904 million in baseline reliability projects needed to meet NERC criteria and almost $3.8 billion in “other” projects, or projects needed to address load growth, the age and condition of existing facilities and transmission owners’ self-imposed reliability criteria.

Draft MTEP 24 spending | MISO

MISO said the 10 most expensive projects account for 26% of the total proposed MTEP 24 costs, with seven located in MISO South.

MTEP 24’s costliest baseline reliability projects either rebuild or construct lines and substations in the South. The portfolio also includes projects to meet load growth in central Mississippi. The central part of the state is positioned for even more load growth, with Entergy announcing it will power two data centers totaling $10 billion for Amazon Web Services, Amazon’s cloud technology subsidiary.

“Again, we have a big year in the South,” Trevor Armstrong, manager of MISO South’s expansion planning, said during a Feb. 8 South Subregional Planning meeting.

Armstrong said most of the generator interconnection upgrades in the South region are intended to connect new solar farms.

Amanda Schiro, MISO senior manager of expansion planning, attributed some of the continued uptick in MISO South projects to load growth while working around the South’s webbing of load pockets.

Schiro said MISO will select some projects for project alternatives study, though it hasn’t decided which projects warrant further analysis. She said MISO will keep stakeholders informed on which projects are getting a second look.

“We are looking for more efficient solutions, potentially larger solutions to replace some local projects,” Schiro said during a Feb. 5 Central Subregional Planning meeting.

However, at a Feb. 6 West Subregional Planning meeting, Expansion Planning Manager Zheng Zhou said there are “limited opportunities” to devise alternatives for some project categories, such as load growth, age and condition replacements, and smaller projects, such as breaker replacements.

Some stakeholders urged members to upgrade to advanced conductors when completing age and condition projects. They said using state-of-the-art conductors on replacement projects will save money in the long run.

MISO will continue to evaluate part of a project Entergy submitted last year to meet load growth in the Amite South load pocket in southeast Louisiana under MTEP 24. MISO made a substitution on the first section of Energy Louisiana’s nearly $2 billion, three-part Amite South reliability project during MTEP 23 and delayed approval of the third portion of the project until it can vet project substitutes. (See MTEP 23 Catapults to $9.4B; MISO Replaces South Reliability Projects.)

So far, MISO hasn’t landed on a satisfactory alternative to part three of Amite South project, but it’s still searching.

“At this point, we’re performing longer-term studies to see how it fits in with the phase one and two portions of the project,” Armstrong said.

Schiro said last year’s MTEP represented the largest investment in the South region since its integration 11 years ago. She also said MTEP 23 saw a record-breaking number of generator interconnection queue applications.

Over 2023, MISO developers struck generator interconnection agreements for 69 projects and withdrew 145 projects.

More withdrawals are all but certain. For the 2021 cycle of generation projects wishing to connect in MISO South, MISO’s studies show $14.5 billion in network upgrade costs is needed. MISO said South region generation projects currently face around $100 million apiece in interconnection costs.

MISO’s current generator interconnection queue consists of 1,379 projects totaling 237.1 GW. Those figures don’t yet include the 2023 class of project submittals. MISO has put those entries on hold until March while it implements new, stricter queue rules meant to discourage speculative generation projects. (See MISO to Try Again for Interconnection Queue MW Cap, Open Window for 2023 Requests.)