Manual Revisions for Interconnection Process Overhaul Sent to MRC
PJM’s Heather Reiter updated the Operating Committee on the status of several manual revisions codifying the interconnection process overhaul during its July 13 meeting. Each manual was reviewed and endorsed by the relevant standing committee last week and will be moving on to the Markets and Reliability Committee on July 26. (See FERC Approves PJM Plan to Speed Interconnection Queue.)
The manuals were endorsed by the Planning Committee, Market Implementation Committee and OC by acclamation throughout the week with minimal discussion. During first reads in June, stakeholders praised the cooperative nature of the manual revision process.
The manuals lay out a cluster approach to studying the grid impacts of generation interconnection requests that will begin the analysis on a first-ready, first-serve basis. In addition to grouping studies together, the new paradigm aims to speed more projects through the interconnection process by having project developers pay deposits increasing in scale as their studies progress.
The transitional phase leading into the new way of studying projects also began last week with the aim of clearing the backlog of projects that accumulated during the previous serial methodology. PJM states that it plans to complete analysis on over 260 GW of projects studied over the next three years, many of which will be renewable generation.
On July 10, PJM opened a 60-day window for developers participating in the transitional queue to post readiness requirements, and it plans to begin processing projects with minimal system impacts through a “fast-lane” process in September.
System Operations Report
Wildfire smoke causing lower-than-expected temperatures and elevated load on the Juneteenth holiday contributed to forecast load error in June peaking at 2.82% and having an hourly error rate of 1.79%, according to the July systems operations report PJM’s Stephanie Schwarz presented to the OC. (See RTOs Report Diminished Solar Output, Loads as Wildfire Smoke Passes.)
The 6 p.m. day ahead forecast for June 19 had the highest deviation with an error of nearly 9% for the peak hour. Following high forecast error on Christmas Eve, which has been credited as being a contributor to the impact of the December 2022 winter storm, New Year’s Eve and Easter, stakeholders have been discussing the role of holidays in forecasting.
Following the spread of wildfire smoke across the northeast on June 5 and 6, PJM said a drop in expected temperatures led to decreased load, which offset diminished solar output. Forecast error for June 6 was just over 6%.
Stakeholders Endorse Quick Fix Manual Revisions to Conform to NERC Standards
The Planning Committee endorsed a quick fix proposal to rewrite portions of Manual 14B to align with NERC’s TPL–001-5.1 standard. The quick fix process allows for a problem statement, issue charge and proposed solution to be brought simultaneously and voted on in the same meeting.
The changes pertain to how PJM determines the maintenance outages in its planning horizon, its spare equipment strategy, planning and mitigation of single points of failure and administrative updates. The proposed language includes a target effective date of July 26.
PJM’s Stan Sliwa said NERC removed the requirement that outages of more than six months be included in the planning horizon and left it up to RTOs to select another rationale. PJM proposed to look at upgrades involving outages on the 230-kV grid or higher that would last more than five days.
Increased requirements around the spare equipment standards pertain to PJM’s process for reaching out to asset owners to see if they have a strategy for maintaining an inventory of equipment that could take a year or more to replace. If those owners don’t, PJM engages in a study to see what the impact would be if that equipment were to go offline.
The new NERC standards for single points of failure expanded the pieces that are considered part of a component protection system and expanded how RTOs study relays.
The quick fix solution was endorsed by the PC and is scheduled to be voted on by the Markets and Reliability Committee on July 26.
PJM Presents Recommended Load Model for 2023 RSS
PJM’s Patricio Rocha Garrido gave a first read of the recommended load model candidate to be used in the RTO’s 2023 Reserve Requirement Study (RRS). The analysis will be used to set the installed reserve margin (IRM) and forecast pool requirement (FPR) for the 2027/28 delivery year and inform any modifications to the previous three years’ values.
The selected load model includes data from 2003-09, which includes load levels that are higher than the model used in last year’s study.
Under all the shortlisted load models, the peak day for PJM would fall in July and overlap with the “world” — which it defines as MISO, NYISO, TVA and VACAR. PJM recommends the world peak be moved to a different week in July to avoid the overlap, which PJM historically has found unlikely and would lead to a decreased capacity benefit of ties (CBOT) value.
The PRISM software also treats each day as a week, which would present in the analysis as both PJM and its neighbors peaking for a week, exacerbating the effect.
Because of volatility in recent years’ CBOT values, PJM also is recommending taking the average of the past seven years.
Alongside the PRISM analysis, PJM will be using software developed for the hourly loss-of-load modeling used for ELCC studies in this year’s study. PJM says the ELCC software has the potential to produce better results and will generate two sets of data, which will be presented to stakeholders when the study is complete for endorsement of one set of outcomes. (See “Reliability Requirement Study to Use New Software,” PJM PC/TEAC Briefs: May. 9, 2023.)
The load model selection process is required only for the PRISM software, which requires normal distributions of data, whereas the PJM forecast data is empirical. The ELCC process models the monthly peak load uncertainty by deriving load scenarios and frequency weight for each delivery year between 2012 and 2021.
Transmission Expansion Advisory Committee
2023 RTEP Window 1 to Open this Month; 2022 RTEP Window 3 Selections in September
PJM’s Sami Abdulsalam discussed the timeline for the opening of the first window of the 2023 Regional Transmission Expansion Plan (RTEP), which is slated for July 24 and will remain open for 60 days. The window will focus on reliability constraints outside of the region currently being addressed by the 2022 RTEP window 3, which was opened in March 2023 to address concerns that available transmission may not be adequate for the pace of load growth in the Data Center Alley in Northern Virginia.
All individual proposals submitted in window 3, which closed on May 31, have been screened and baseline scenarios are under evaluation.
Supplemental Needs and Project Proposals
Commonwealth Edison said the majority of its oil circuit breakers in operation on its 345-kV Goodings Grove substation in Illinois are 44 to 57 years old and in deteriorating condition. One breaker failure has the potential to take out seven 345-kV lines and two autotransformers.
Dominion proposed three new 230-kV substations in Loudoun County, Va., to serve growing load in the region, which includes the data center alley near Dulles International Airport. The Lunar substation would be connected to the existing Sycolin Creek facility by two 230-kV lines at a $28 million total cost and an August 2026 in-service date. The proposed Starlight substation would be cut into the envisioned lines between Sycolin Creek and Lunar at a $28 million cost and a June 2028 in-service date. The third substation, Apollo, would be connected to Lunar by two 230-kV lines at a $28 million price tag with a January 2027 in-service date.
Public Service Enterprise Group (PSEG) said its Pierson Ave. substation in Perth Amboy and Meadow Road in Edison have run out of capacity, each serving more than 14,000 customers, while the Keasbey substation, serving more than 5,600 customers in the Perth Amboy region, is in poor condition and not in compliance with New Jersey construction codes.
Vote on Rules for Generation with Co-located Load Deferred
VALLEY FORGE, Pa. — The Market Implementation Committee delayed voting on five competing proposals to allow generators that provide a portion of their output to co-located load to retain their capacity interconnection rights (CIRs).
The discussion — brought by Brookfield Renewable and Exelon, later Constellation — explores the creation of rules allowing a generator to serve highly interruptible load not directly interconnected to the grid, while still being available to switch to serving PJM when called on to meet its capacity obligations. (See “Discussion Continues on Capacity Offers for Generators with Co-located Load,” PJM MIC Briefs: June 7, 2023.)
MIC Chair Foluso Afelumo made the determination to delay the vote based on stakeholder input and not hearing any objections during Wednesday’s meeting.
Constellation Vice President of Market Development Bill Berg said the company has been engaged in outreach with other package sponsors in the hopes that a compromise can be reached between the five options. The Advanced Energy Management Alliance (AEMA), PJM, the Independent Market Monitor and Exelon are the other four sponsors.
“I do think that it is in our stakeholders’ best interest to give it one more month to try to reach some compromise, because my fear is that this will end up at FERC,” Berg said. “…we are reaching out to anyone and everyone we can talk to, particularly some of the package sponsors to see if there’s a path forward on at least some of these issues.”
Exelon’s Sharon Midgley also supported delaying the vote for an additional month, saying she’s continuing to field questions from stakeholders about how the Exelon package would function.
PJM’s Tim Horger said he hadn’t heard of any specific changes being considered for any of the packages and would have been comfortable moving forward with a vote last week, but was supportive of any consensus building that could be done.
Four of the packages include two versions, addressing both co-located load without receiving direct service from the PJM grid and a second for interconnected loads, each of which would have required a second vote with the possibility of the end result being components from two different sponsors being selected. The AEMA proposal does not recognize a distinction between co-located load with or without grid service and would treat both the same.
First Read on Reactive Power Compensation Proposals
During the MIC’s first read last week, stakeholders discussed four packages that would revise the compensation structure for reactive power.
Danielle Croop, PJM’s facilitator for the Reactive Power Compensation Task Force, said the status quo system uses the “AEP methodology,” which identifies equipment at generators that support reactive capability, and each generator is required to make a cost-of-service filing at FERC, many of which result in “black box” settlements.
PJM Assistant General Counsel Thomas DeVita said FERC attorneys have said PJM reactive filings make up a significant portion of their caseload and the commission may seek a resolution of its own.
“If we don’t end this process with a solution there is a significant risk that FERC will act on its own and we will be here again in short order,” he said.
Croop said compensation also is not tied to generators’ performance in supplying reactive power and it sometimes has to provide make-whole and opportunity cost payments. The proposals aim to create uniform compensation — both for providing reactive service and associated opportunity cost payments, reduce administrative burden and draft new market rule changes to replace the existing procedures in Tariff Schedule 2.
A December 2022 poll at the task force found support among members was strongest for the Clean Energy Coalition proposal, at 63%, followed by the PJM package with 28% support. Two packages from the Monitor received 17% and 16% member support. The poll also found that 62% of responding members did not believe that change to the Schedule 2 compensation method is necessary. The poll received 280 member responses, 37 of which were unique.
The proposals are limited to new generators or facilities entering new compensation agreements, with the task force’s scope precluding changing existing reactive rates. The MIC voted down a proposal to expand the task forces’ scope to include existing service rates last month. (See “Stakeholders Reject Proposal to Expand Reactive Power Task Force Scope,” PJM MIC Briefs: June 7, 2023)
The CEC proposal is based on applying the AEP methodology to resources on a class-wide basis by forming a separate rate for each type of generator. The rates would be posted on PJM’s website, but only the underlying formula would be included in the tariff.
The CEC presentation states that applying the AEP process on a technology-wide basis avoids requiring unit-specific FERC filings and treats all generation comparably. Creating a cost-based compensation structure would incentivize investments in reactive capability that caps payments at the cost of the proxy unit. PJM’s proposal would limit compensation to generators that are capable of providing reactive service on the transmission grid, excluding those that can provide it at the distribution grid level. Payments would be based on demonstrated or tested capability and would seek to recognize that all reactive power (VARs) is the same.
Calpine’s David “Scarp” Scarpignato said existing testing for reactive capability often is difficult to complete given technical limitations on the grid, requiring some generators to schedule multiple tests before one can be successfully administered.
Wade Horigan, a principal of Tangibl, said he believes the PJM proposal would create an incentive for PJM and transmission owners to not change voltage during testing and that running only two tests would not reflect generators’ actual capability to respond to a voltage excursion.
PJM’s Glen Boyle said if generators exceed their capabilities, their parameters and compensation would be increased. If generators don’t perform, their revenues would be withheld for that month and future expected capability would be reduced. He estimated the proposal would require an 18- to 24-month implementation period.
Market Monitor Joe Bowring said the AEP method is archaic and illogical and was designed in 1997 to maximize the allocation of costs to reactive for a utility that was fully cost-of-service regulated. Bowring said a recent FERC order on the same issue in MISO required that all such payments for reactive power be terminated.
“There is no need for a cost-of-service approach in a system that relies on markets. This payment of more the $380 million per year in side payments is unnecessary and should be eliminated,” he said.
The first of the Monitor’s proposals — Package F under the matrix — would immediately eliminate separate cost-of-service payments to all resources and would also remove reactive revenues from the energy and ancillary services offset, resulting in an increase in capacity market revenues. All resources currently are required to provide reactive as a condition of their interconnection service agreements (ISA).
The second proposal — matrix Package H — would start with a flat-rate design, similar to PJM’s, but would fully phase out all cost-of-service payments over a short period and would use the same performance penalty as PJM.
Bowring said doing away with the current settlement process and using the AEP method for all resources, as recommended by the CEC, would result in an approximate doubling of the $380 million per year in reactive costs borne by load. He said the FERC order in the MISO reactive compensation case was clear and there also are additional cases in front of FERC that address the fundamental issues of cost-based rates in a market structure.
Stakeholders Question Scope of Distributed Resources Subcommittee
During an update on the work the Distributed Resources Subcommittee (DISRS) is engaged in, PJM’s Ilyana Dropkin noted that Voltus introduced a problem statement and issue charge in which the demand response provider said it could bring a stronger response to the market if offers could reflect operational parameters such as limits in curtailment duration and a need for downtime between curtailments.
Several stakeholders questioned if the DISRS is the best forum for such discussions and whether it’s appropriate for non-voting committees to consider such topics. Scarpignato said subcommittees have the potential to take up subjects that can result in PJM staff being devoted to topics that may not have support at the standing committee level. He predicted the matter brought by Voltus ultimately will result in an issue charge being approved for discussion at either the DISRS or cost development subcommittee (CDS), but it presents procedural questions.
NYISO has started the process of considering energy storage resources as transmission assets, according to a presentation given to the Installed Capacity Working Group/Market Issues Working Group on July 11.
The ISO will assess existing procedures to evaluate whether ESRs can be treated as regulated transmission assets and what potential rules would be required to operate storage as transmission.
NYISO already identified several issues to the effort, however, including what size or duration of ESRs should be allowed to participate and how “dual-use” storage — resources that could both participate in the markets and act as transmission — should be treated.
Glenn Haake, vice president at renewable energy operator Invenergy, sought clarification on what NYISO’s deliverable would be for this year.
Katherine Zoellmer, market design specialist at NYISO, responded, “This issue discovery will conclude with a recommendation for moving forward, and that is what would be taken into next year’s project.”
Haake also asked if storage will be included as a standalone solution in future public policy transmission need assessments.
“This is something we are considering and working through at the moment,” Zoellmer answered.
NYISO said it will return in a month or two with more information on how the project will proceed and asked that any additional questions, comments, concerns or recommendations be sent to KZoellmer@nyiso.com.
The D.C. Circuit Court of Appeals on Friday upheld FERC’s decision to approve PJM’s financial transmission rights forfeiture rule without ordering refunds under previous rules implemented without commission approval.
But the court remanded the case to FERC to provide a fuller explanation of why it did not order a forfeiture exemption for non-leveraged transactions — when a trader’s FTR gains do not exceed the losses incurred from that trader’s virtual transactions (22-1096).
FTRs are financial instruments that allow load-serving entities to hedge the risk of transmission congestion costs and permit financial traders to arbitrage day-ahead and real-time congestion. PJM originally implemented the forfeiture rule in 2000 to prevent market participants from using virtual transactions to create congestion that benefits their FTR positions.
The commission ruled in May 2021 that PJM’s previous 1-cent FTR impact test, which determines whether the net flow impacts the absolute value of an FTR by 1 cent or greater, to be unjust and unreasonable. FERC approved PJM’s replacement rule in January 2022 (ER17-1433). (See FERC Accepts New PJM FTR Forfeiture Rule, Without Refunds.)
After FERC rejected rehearing requests from FTR trader XO Energy, the traders sought relief in the D.C. Circuit, arguing that the commission’s decision approving the new rules and denying refunds under the old rules was arbitrary.
The D.C. Circuit said XO’s arguments were “ultimately unpersuasive” and that the commission “adequately justified” its decision not to order refunds.
“It considered record evidence submitted by PJM, which explained that calculating refunds would be a difficult task requiring ‘considerable software development and testing work that would take months to complete,’” the court said.
The court was more sympathetic to XO Energy’s contention that the new rule should exempt “non-leveraged” positions from forfeiture because they provide no economic incentive to engage in manipulative conduct.
While it declined to overturn the ruling, the court said FERC had provided only “a brief … inadequate, explanation of why it declined to order a forfeiture exemption for non-leveraged transactions.”
“Although the commission acknowledges that leverage might be one way to determine cross-product manipulation, it states that it opted to allow PJM to employ other means to detect this conduct rather than require exemptions based on leverage,” the court said. “That is the extent of the commission’s explanation. It does not address XO Energy’s position that market manipulation cannot occur when the net losses of a trader’s virtual transaction portfolio exceed the net profits from its FTR portfolio. Nor does it explain why the exclusion of this requirement strikes the appropriate balance between preventing manipulative conduct and not hindering legitimate hedging activity.”
But the court declined to vacate the order, saying instead that FERC could “redress the deficiency of its reasoning by providing a more fulsome explanation for its decision not to order PJM to account for leverage.”
Grid-enhancing technologies (GETs) could offer significant savings, but an industry that is conservative when it comes to grid operations and planning needs to get used to them first, regulators heard Sunday at the Joint Federal State Task Force on Electric Transmission in Austin, Texas.
The motivation for expanding the use of GETs is clear, with the electric industry undergoing a massive transformation that will see its share of total energy use expand from 21% today to 39% by 2050, while decarbonizing power generation, said Andrew Phillips, vice president of transmission and distribution infrastructure for the Electric Power Research Institute.
“There are about 400,000 miles of transmission lines 100 kV and above in the United States,” Phillips said. “We’ve been building them at a rate of about 2,000 miles per year; we are going to have to double that rate to meet that goal to integrate all of those lower-cost and also carbon-free renewables.”
Getting more use out of transmission lines and related infrastructure such as substations and transformers through GETs — such as dynamic line rating (DLR), advanced conductors or topology control — would make that work easier, he said. Different technologies would have different uses because the issues around the grid vary depending on the exact infrastructure.
Short lines (30 miles or fewer) are the ones that are impacted by temperature the most and would benefit from DLRs that take into account actual temperatures, wind speed and other conditions, Phillips said. Generally, the industry allows only as much power through such transmission lines as would work on the hottest day of the year with low wind speeds, but more often than not, they could handle more electricity.
Advanced conductors also would benefit such transmission lines because traditional transmission can operate only up to 93 degrees Celsius, while newer technologies can run more than twice as hot. Such new conductors have been available for a decade, but the industry has longer timeframes than that, with utilities needing to know they will last for many decades.
“For the last 10 years, EPRI has been doing tests on all of these new advanced conductors, and developed a test that can be put into a specification, so that utilities can acquire these conductors with confidence and knowing that they will last for 40 or 50 years,” Phillips said.
Shorter lines would also benefit from DLRs, but the industry needs to get accurate data on a range of things that impact transmission capacity, including temperature, wind speed and the amount of sunlight hitting them. Many technologies are available to measure those factors, with EPRI and its industry partners determining what works best and where, Phillips said.
“If it’s going to become a day-to-day thing, where we’re going to incorporate these things, we need standards and specs, just like we’ve got standards and specs for transformers, insulators [and] conductors,” Phillips said.
The changing capacity of transmission lines is something grid operators are not used to, and it implies a greater risk, so they will have to familiarize themselves with that before it becomes common, he added. It only makes sense that grid operators are conservative.
“Why are they conservative? Because you want to make sure the lights stay on, right?” Phillips said. “But that conservatism is a challenge when you’re trying to incorporate a new technology and increase the risk. … Maybe a reasonable risk, but a higher risk.”
While such technologies offer savings, they cannot replace transmission expansion entirely, FERC Commissioner Mark Christie said. DLR is “dynamic,” which he said means it is always changing; sometimes it can free up more capacity, but other times not.
“From a planning standpoint, how do you work in a dynamic [system]?” Christie asked. “We know there’s tremendous potential — we know they can save a ton of money — where and when they work.”
From a long-term planning point of view, predicting the wind in 10 years is just not feasible, but DLRs can be very useful in a more immediate, economic way, where they can be used to bring cheaper supply to customers, Phillips said. Long-term planners still have to use the static rating of the line because the grid will experience times when it is hot and the wind is not blowing.
Real-time operators have some leeway when it comes to DLR because of conductors’ “thermal lag,” so that if the wind stops blowing, they have a couple of hours to update power flows over dynamically rated transmission, Phillips said.
In MISO, the planning process does not account for GETs, and planners are skeptical about factoring them in for the long term, but the grid operator is much more open to them when it comes to operations, said Michigan Public Service Commission Chair Dan Scripps.
“RTOs are in many cases able to institute reconfigurations when there is a pressing reliability issue in real time but are more hesitant to act in a proactive way that is only focused on economic benefits,” Scripps said.
That could change going forward, especially with the ability to use different transmission line ratings for the summer and winter in planning going forward. When the conditions for DLRs are not right, it might make sense to use topology control, with which grid operators can tweak the system by, for example, shutting down one piece of infrastructure that frees up more power flow overall, Scripps said.
A major issue to getting GETs rolled out around the grid is the financial incentives for utilities, which are biased toward spending more capital and thus earning more returns, FERC Commissioner Allison Clements said.
“The short answer to how do you better integrate it is for the commission to require utilities to consider whether or not to use them, and then to align the financial incentives so that they’re encouraged when they’re considering them,” she said.
It is also important to dispel the “myth” that GETs are new technologies that are rife with risks when deployed.
“The existence of those risks shouldn’t stop us from starting to require consideration of deployment, and certainly the many cases we’ve heard so far about entities that have used dynamic line ratings to the benefit of customers have found ways to manage those,” Clements said.
Acting FERC Chair Willie Phillips offered an analogy for how GETs will impact the industry by comparing them to the change from road atlases to GPS programs on smartphones.
“When you think about how to use GPS, you don’t use it like a map,” Phillips said. “You don’t set it on time and forget about it.”
The software will reroute drivers around traffic jams and to quicker routes to their destination, with drivers using GPS at every turn throughout their journeys.
“I think that’s exactly how we should use GETs,” said Phillips. “We should use it an interconnection queue phase; we should use it during construction — I say ‘use,’ [but] I mean ‘consider.’ We should consider it during the construction phase. We should consider it after construction and during implementation.”
Just before the task force meeting, Grid Strategies released a report showing growing congestion costs around the country, with $12 billion in RTO markets during 2022 and more than $20 billion around the country, Phillips noted.
“If we can use GETs to bring that number significantly down, I think it’s incumbent upon regulators to do just that,” he added.
After rehearing arguments raised by several SPP members, FERC last week unanimously reversed an October decision that established a process for SPP to allocate “byway” transmission projects on a case-by-case basis.
In a July 13 order, the commission rejected SPP’s proposed methodology without prejudice and dismissed a November compliance filing as moot (ER22-1846).
FERC said the grid operator failed to prove its proposal to regionally allocate 100% of a byway facility’s costs on a postage-stamp basis would result in outcomes that are just and reasonable and not unduly discriminatory or preferential.
SPP currently allocates one-third of the cost of byway projects — lines rated at 100 to 300 kV — 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. Its proposal would have allowed entities to seek exceptions, which would be approved by the RTO’s Board of Directors, to the cost allocation process for byway facilities. (See FERC Approves SPP Cost-allocation Waiver Plan.)
Transmission-owning members Southwestern Electric Power Co., Public Service Company of Oklahoma, Southwestern Public Service, Oklahoma Gas & Electric, City Utilities of Springfield (Mo.), Kansas City Board of Public Utilities and Missouri Joint Municipal Electric Utility Commission filed rehearing requests in November.
The TOs argued that the board’s secret votes, which are conducted after the Members Committee votes publicly, raised the risk that it would approve or deny waivers on a discriminatory basis.
FERC agreed, saying SPP’s proposal continues to grant the board “too much discretion” in allocating byway facilities’ costs because it doesn’t require the directors to approve a reallocation request if it doesn’t meet three criteria.
“The SPP board could deny a requested reallocation where SPP staff has determined that the criteria are met or, conversely, approve a reallocation where SPP staff has determined that the criteria are not met,” the commission said. “The SPP board’s discretion to make decisions that are potentially inconsistent with whether the criteria set forth in the tariff are met could result in unduly discriminatory outcomes.”
FERC said the discretion provided to the SPP board “is not similar” to cost allocation waivers under SPP’s transformer waiver process. It said the RTO’s proposal would make all byway transmission projects eligible to request waivers, leading to an “expansive” list of eligible facilities and a “far-reaching scope.”
Commissioners James Danly and Mark Christie, who dissented in the original 3-2 decision in October, concurred this time in separate opinions.
“SPP sought to arrogate to itself unfettered discretion in socializing the costs of ‘byway’ transmission projects,” Danly wrote. “As today’s issuance acknowledges, the directives in the underlying order failed to render an otherwise unjust and unreasonable proposal just and reasonable.”
Christie noted that he dissented from the original order and that state support for the new cost allocation proposal was “not uniform,” with four states being on the record as opposing SPP’s suggestion.
“Should SPP seek to file another version of its cost allocation for these types of projects, it is my hope that any such new cost allocation will earn the support of all states to which costs could be allocated,” he said.
FERC on Friday approved Northern Indiana Public Service Co.’s (NIPSCO) request for transmission incentives on two lines it is building under the MISO Transmission Expansion Plan (MTEP).
NIPSCO is building the Indiana portions of Project 15 and the entirety of Project 16, both of which were approved under MTEP 2021. In the order Friday, the utility won approval of 100% of prudently incurred construction work in progress (CWIP) and the abandoned plant incentive, allowing it to collect costs if the projects are canceled for reasons outside the utility’s control.
Project 15 involves upgrading an existing single-circuit 138-kV line to a double-circuit 345/138-kV line and upgrading a related substation. Project 16 spans northern Indiana and increases transmission capacity in both directions. Both projects are expected to be done by June 1, 2029, at a total cost of $280 million, which represents a 21% increase in the utility’s current transmission plant value.
NIPSCO said FERC has granted such incentives to similar regionally planned projects in the past. The CWIP incentive will help improve cash flow, enhance rate stability and lower rate shock concerns.
“We find that NIPSCO has demonstrated that the requested incentive is tailored to the risks and challenges faced by the projects,” FERC said. “We also find that the approval of the CWIP Incentive will bolster NIPSCO’s financial metrics, help ensure its current credit rating, and enable its participation in the projects.”
The record indicates that completing the projects will put pressure on the utility’s finances and CWIP will ease that, FERC said.
A group of industrial customers had asked the commission to deny the CWIP request, arguing that FERC’s transmission notice of proposed rulemaking is considering changes to CWIP. But the commission rejected their reasoning, saying the potential rule change still was prospective and thus had no impact on NIPSCO’s request.
In approving the abandoned plant incentive, FERC said NIPSCO made the case that the projects face certain regulatory, environmental and siting risks that are outside of the company’s control and could lead to project abandonment. FERC said approval will address those risks and protect NIPSCO if the lines are canceled.
The order drew a concurrence from Commissioner James Danly, who wrote only to sympathize with a lengthy dissent from Commissioner Mark Christie who wants to see changes in how FERC awards the CWIP incentive.
“I would have set NIPSCO’s transmission rate incentives filing for hearing before an [administrative law judge], as the evidence industrial customers have presented casts serious doubt on whether NIPSCO’s requested CWIP Incentive and Abandonment Incentive are tailored to address the risks and challenges of the projects,” Christie said.
In other transmission incentive orders, Christie has questioned whether granting CWIP, abandoned plant incentive and other incentives had become “nothing more than a check-the-box exercise” and the NIPSCO order realized those concerns.
The industrial customers noted that NIPSCO’s owner, NiSource Inc., has sold 19.9% of the firm to Blackstone for $2.15 billion, which includes $250 million in working capital — or about 89% of the estimated cost for the two transmission projects. The utility argued that the customers failed to show how the minority sale proceeds would offset the financial pressure of building the lines.
“NIPSCO appears to ask this commission to pay no attention to the big pile of money that would result from the proposed sale,” Christie said. “I fail to see how the answer as to whether a planned $250 million infusion in working capital would mitigate NIPSCO’s financial risks should not be of interest to this commission or potentially affect the commission’s calculus on whether NIPSCO’s requested incentives are tailored to meet its risks and challenges.”
Setting the case for hearings before an ALJ would have given FERC a chance to explore the financial status of NIPSCO in greater detail, he said. The CWIP incentive turns customers into a bank for the project while the abandoned plant incentive makes them an insurer, but they do not get any benefits from that, he added.
“Revisiting all these incentives is imperative at a time of rapidly rising customer power bills,” Christie said.
New York City faces a reliability margin shortfall of up to 446 MW in 2025 due to plant retirements and the delayed completion of the Champlain Hudson Power Express, NYISO said Friday in its Short-Term Assessment of Reliability (STAR) for the second quarter.
The STAR report for the five-year period ending April 15, 2028, forecasts rising loads due to increased electrification of transportation and buildings, continued economic growth following the pandemic and the expected retirement of generators under the state Department of Environmental Conservation’s “peaker rule,” which took effect in May.
NYISO CEO Rich Dewey told the New York State Reliability Council Executive Committee Friday that the ISO is projected to fall short of its transmission security margin, a measure of the power system’s ability to withstand disturbances such as short circuits or unanticipated loss of a generator or transmission line, while continuing to supply and deliver electricity. Dewey said the CHPE, which will deliver hydroelectric power to New York from Quebec, “would solve this problem, but its in-service date slipped to the spring of 2026.”
DEC’s peaker rule, approved in 2019, is intended to limit nitrogen oxides (NOx) emissions from simple-cycle combustion turbines.
As of May, 1,027 MW of affected peakers have deactivated or have limited capacity, while an additional 590 MW of Zone J peakers are expected to be impacted by the DEC’s rule beginning May 1, 2025.
Under baseline weather conditions (95 degrees Fahrenheit) in 2025, the ISO said the higher bound of expected demand will result in a deficiency of 446 MW over nine hours. The deficiency would be “significantly greater” if the city experiences a heat wave (98 F) or an extreme heatwave (102 F), the ISO said.
If the CHPE experiences further delays, more fossil fuel plants become unavailable, energy demands exceed forecasts or significant extreme weather events elevate loads, reliability margins could “continue to be deficient for the 10-year planning horizon,” the report said.
New York state’s growing electric system demand threatens future security margins. | NYISO
Because the DEC anticipated that peakers may need to remain online longer than required, it authorized NYISO to order a two-year extension through 2027 and an additional two-year extension through 2029, should these plants be needed for reliability.
Both Dewey and the report, however, emphasized that keeping the peakers online is a “sub-optimal solution” and would be used only after NYISO exhausts all other possibilities.
Dewey said NYISO will work with transmission owner Consolidated Edison to develop solutions and will evaluate proposed solutions that will be solicited from developers throughout the summer. NYISO will review submissions, which could include generation and demand response, in the fall and decide on the best way forward during November.
Dewey confirmed that NYISO likely would return to the July 25 Electric System Planning Working Group with a more comprehensive statement regarding the near-term reliability need.
Con Ed said it is reviewing the STAR report and “remains committed to providing reliable, safe service for to customers, and supporting the state’s important clean energy transition.”
The report notes that although CHPE will help reliability in the summer, “the facility is not expected to provide any capacity in the winter.”
Statewide Shortages?
The Q2 STAR also found that New York could face a statewide deficiency of up to 145 MW by 2025, which could remain through 2033, because of the assumed unavailability of power plants complying with the peaker rule.
The ISO said additional large load interconnection projects in western and central New York are expected to increase 2025 demand by 764 MW. “If CHPE does not begin operation, the statewide system margin is projected to be deficient for all years 2025 through 2033 when considering the additional large loads,” according to the report.
During the NYSRC EC meeting, attendees worried about the Q2 STAR’s findings and questioned how projected deficiencies might impact NYISO’s future planning considerations.
Two attendees inquired about the peaker rule and whether it was simply easier or more economically viable to allow these emissions-producing plants to stay online.
Zach Smith, NYISO vice president of system and resource planning, again confirmed that extending the peaker rule was a “last resort,” and responded that this option would be selected only after “NYISO considers the backstop solution Con Ed is required to provide and reviews all solicited proposals.”
Mark Younger, president of Hudson Energy Economics, asked if NYISO has been providing adequate market demand signals to its resources and would reconsider current price signals to be based on more long-term forecasts.
Forecasted energy demands for NYC | NYISO
Dewey responded, “I think that that will be the subject of a lot of discussion over the next year and as we undergo the next demand curve reset.” The DCR occurs every four years and updates the assumptions that determine the installed capacity demand curves. (See FERC Accepts NYISO’s 17-Year Amortization Period Proposal.)
Roger Clayton, chair of the NYSRC’s Reliability Rules Subcommittee, asked whether NYISO would give greater consideration to nuclear resources.
Dewey responded that the Climate Leadership and Community Protection Act’s scoping plan included a notice on how nuclear energy should be investigated. “Nuclear development could be solution for these challenges … but I am curious to see if [nuclear] gets any additional traction in discussions at the … Public Service Commission,” he added. The PSC recently ordered staff to identify technologies, like nuclear or hydrogen, which could keep New York in CLCPA compliance. (See NY Renewable Portfolio May Come up Short on Getting to Net Zero.)
Wes Yeomans, an NYSRC consultant, asked about the STAR’s statewide findings and if that future reliable marginal deficiency requires any immediate action by the ISO.
Smith answered that “the statewide margin is for informational purposes at this point and there is no action to take at this time,” adding, “we’re providing this as information of basically a need possibly to come.”
Gavin Donohue, CEO of the Independent Power Producers of New York, released a statement on the STAR’s findings, saying, “the pace of play is not keeping up with pace of promises, and this report makes that clear.”
“There have been repeated cautions from the NYISO regarding grid reliability, and this report highlights the reality that generator retirement cannot outpace the addition of new generation with the attributes needed by the NYISO to maintain reliability,” he added.
The Massachusetts Joint Committee on Telecommunications, Utilities and Energy (TUE) held hearings last week on several bills that would expand the state’s 10-municipality demonstration project allowing cities and towns to ban fossil fuels in new buildings and major renovations.
The TUE Committee also took public testimony on a range of bills promoting building electrification and targeting fossil fuel consumption in buildings more broadly as the state looks to cut building sector emissions and meet its statutory climate goals.
Climate, public health and environmental justice advocacy groups spoke in favor of bills promoting electrification, while they opposed bills that would promote the use of biomethane or blended hydrogen in buildings.
Representatives from the gas, biofuel, heating oil and real estate industries, along with labor groups representing gas workers and plumbers, generally opposed the electrification bills and supported the inclusion of alternative and low-carbon fuels in building decarbonization programs.
The committee helped to craft an omnibus climate bill in 2022 that created a demonstration project allowing 10 municipalities in Massachusetts to ban fossil fuel combustion in nearly all new buildings. State law prohibits most towns from implementing all-electric building codes, based on a ruling by former state Attorney General Maura Healey (D), who is now governor.
Clean energy advocates are now pushing to expand the 10-town program, with many hoping to expand the option, or even pursue an all-electric code for new buildings, statewide. The 10-town limit agreed upon in the previous session was a political compromise between the legislature and then-Gov. Charlie Baker (R). Advocates hope the changing political makeup of the state, along with the ever-increasing need to reduce emissions, will spur the program’s expansion.
“We all know the urgency of action,” said Northampton City Councilor Alex Jarrett. “On Monday, I stood next to a farmer as she watched her equipment and her crops get washed away by what looks to be the third-highest flood event since 1950 on our local Mill River. All of her effort for the season was gone in a few minutes.”
Representatives of cities including Northampton, Salem, Somerville and Worcester expressed their desire to join the demonstration project, but they worried they will be unable to if it is not expanded. The demo gives priority to the 10 municipalities that pursued local bans prior to the 2022 law. Nine of the 10 municipalities are likely to be included in the project, leaving one open spot for additional applicants. And Boston also has expressed its interest in joining.
“It doesn’t make sense to build new buildings that will need to be retrofitted before the useful life of their heating, cooling and cooking infrastructure is through,” Jarrett said.
Advocates argued that it is unfair to allow disproportionately wealthy, white communities to participate in the demonstration project while lower-income communities of color are excluded.
“We’re a major environmental justice community; we shouldn’t have to wait,” said Worcester City Councilor Etel Haxhiaj, noting that the impacts of climate change disproportionately impact vulnerable low-income, nonwhite and disabled residents.
“Without state authorization to restrict new fossil fuel infrastructure in our city, we are completely unable to address our most significant source of emissions: our buildings,” Haxhiaj said.
Along with the need to reduce emissions, advocates for expanding the program cited the public health risks of burning fossil fuels like natural gas and propane in buildings.
Climate advocates from Mothers Out Front and Gas Transition Allies testify to legislators. | Massachusetts Joint Committee on Telecommunications, Utilities and Energy
“The evidence for the harms of gas stoves in homes related to pediatric childhood asthma is robust and has been well known for quite some time, with an increased risk of 42% in children that live in homes with gas stoves,” said Dr. Wynne Armand, associate director of the MGH Center for the Environment and Health and assistant professor at Harvard Medical School.
Armand highlighted a recent study that found gas stoves release significant levels of the carcinogenic chemical benzene during combustion, as well as a 2022 study that found uncombusted gas in the Boston area contained 21 chemicals known to be toxic to humans.
“This is an equity issue,” Armand said, speaking about her experience practicing primary care in Chelsea. “I see this every day, where my community has one of the highest rates of asthma in children, as well as the worst asthma outcomes and higher [emergency department] visits.”
Sen. Mike Barrett (D), chair of the TUE Committee, expressed his support for expanding the demonstration project and said he was in favor of allowing more towns to join during last year’s legislative session.
“Ten isn’t arbitrary, and it wasn’t the number favored by original proponents; it was what we could get,” Barrett said, adding that the legislation promoting the demonstration project originated in the Senate and that proponents may face greater opposition in the House of Representatives.
Meanwhile, those opposing the demo’s expansion include National Grid; the Propane Gas Association of New England; the Massachusetts Energy Marketers Association; the real estate association NAIOP; the Homebuilders and Remodelers Association of Massachusetts (HBRAMA); the Northeast Hearth, Patio and Barbecue Association; Plumbers & Gasfitters UA Local 12; and United Steelworkers Local 12012.
“We urge you to think twice and go slow before expanding the 10-community fossil fuel ban program because of the difficulties that already homebuilders are running into trying to electrify our homes,” said Benjamin Fierro, a lobbyist testifying on behalf of HBRAMA.
Fierro highlighted the results of an industry-sponsored report from the Wentworth Institute of Technology, Massachusetts Institute of Technology and HBRAMA that found that the state’s ‘municipal opt-in specialized stretch energy code’ — which features strict energy-efficiency standards but stops short of mandating electrification of new buildings — could increase the total costs for the construction of single-family homes by 1.8 to 3.8%.
Andrew D’Angelo, executive director of the Greater Boston Plumbing Contractors Association, argued that his organization was not coming to legislators “as shills to the fossil fuel industry or large corporations. We come here as working people and contractors that employ those people with concerns that some legislation, while well intended and altruistic, will come with some unintended consequences for families across the state.”
Tim Fandel of Local 12 advocated for an “all-of-the-above approach” to reducing emissions.
“In the absence of utilizing every option we have at our disposal, there is a real risk in not achieving the intended objectives — and yes, natural gas will play a role in our energy portfolio for many years to come,” Fandel said.
Kevin O’Shea, director of government affairs at National Grid, echoed this position, opposing the expansion of the 10-town demonstration project along with legislation that would impose a clean heat standard on the state’s gas utilities. The proposed standard would not allow utilities to comply using fuels like biomethane or blended hydrogen.
“It is too early to take viable decarbonization off the table that may be needed to meet the 2050 net-zero targets,” O’Shea said.
Ben Butterworth, director of climate, energy and equity analysis at the Acadia Center, argued that blending biomethane — also known as renewable natural gas (RNG) — and hydrogen into the gas network “would significantly impair the state’s ability to cost-effectively decarbonize the building sector.”
Citing the “optimistic” estimates of the American Gas Foundation, Butterworth said biomethane from waste sources could cover only about 5% of current U.S. gas demand.
“Increasing RNG production beyond this level would require the use of highly controversial resources including energy crops and gasification of agricultural and forest residues. These forms of RNG production that rely on the intentional production of methane simply shouldn’t be on the table,” Butterworth said, citing the “lack of any clear GHG-reduction benefit and tradeoffs associated with land, water use and food production, to name a few.”
As legislators consider a clean heat standard bill, the Massachusetts Department of Environmental Protection (DEP) has also begun developing a clean heat standard while soliciting public feedback featuring many of the arguments that played out in the TUE hearings. (See Mass. Stakeholders Debate the Scope of Clean Heat Standard.)
Opponents of the legislation argued that the development of the standard should be left to the DEP, while advocates said the bill would provide important guardrails for which compliance pathways are included in the standard.
