Below is a summary of the agenda items scheduled to be brought to a vote at the PJM Markets and Reliability Committee meeting. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will cover the discussions and votes. See next week’s newsletter for a full report.
Consent Agenda (9:05-9:10)
B. Endorse proposed revisions to Manual 1: Control Center and Data Exchange Requirements to reflect NERC Standard EOP-8 and the PJM TO/TOP Matrix. The changes would update the Generation Scheduling Service table with data requests through the Generation Periodic eDART system and the Cold Weather Checklist.
C. Endorse proposed revisions to Manual 3: Transmission Operations drafted through the document’s periodic review.
D. Endorse proposed revisions to Manual 6: Financial Transmission Rights, Manual 11: Energy and Ancillary Services Market Operations, Manual 28: Operating Agreement Accounting and Manual 29: Billing to codify PJM’s market suspension rules as approved by FERC in ER23-1431. (See “First Reads on Manual Revisions,” PJM MRC/MC Briefs: April 23, 2025.)
E. Endorse proposed revisions to Manual 36: System Restoration written through its periodic review.
Endorsements (9:10-10:00)
2. ELCC Data Transparency and CETL (9:10-9:40)
A. PJM’s Dan Bennett and Josh Bruno will present a proposal aiming to make the RTO’s effective load-carrying capability (ELCC) process more transparent by publishing more information about data inputs and assumptions. (See “PJM Presents Proposal to Add Transparency to ELCC,” PJM MRC/MC Briefs: April 23, 2025.)
The committee will consider endorsing the proposed solution and corresponding manual revisions.
B. Tom Hoatson, of Rolling Hills Generating, is set to motion to defer consideration of an issue charge brought by LS Power seeking to align the winter-skewed risk modeling in ELCC with the summer-focused capacity emergency transfer limit (CETL) analysis. (See “LS Power Seeks Issue Charge to Align CETL Calculation with Winter Risk,” PJM PC/TEAC Briefs: Oct. 8, 2024.)
PJM’s Dave Anders will present a problem statement and issue charge that would open a stakeholder process to consider establishing rules for deploying battery storage as a transmission asset (SATA). (See “Stakeholders Resume Discussions on SATA,” PJM OC Briefs: March 6, 2025.)
Texas regulators have declined to respond to ERCOT’s request for an exemption from including certain loads without interconnection agreements in its forecasts and have asked the grid operator to fine-tune its methodology for estimating coming demand.
Public Utility Commission Chair Thomas Gleeson found the ISO’s proposed methodology, which would discount data center loads and those certified by a utility, makes sense “directionally” but could use some refinement (55999).
“I’ve asked them to kind of think through some other options of ways we can look at refining this number,” Gleeson said during the PUC’s May 15 open meeting. “I’ll be working with ERCOT to hopefully present other ways that we could look at refining this number, other than the methodology presented here.”
ERCOT staff briefed the commission on the latest changes to its ERCOT-adjusted load forecast after recent projections startled industry observers and lawmakers. CEO Pablo Vegas said in 2024 that demand would peak at 150 MW by 2031. In February, the grid operator released a capacity, demand and reserves (CDR) report that projected demand peaking at 140 GW in 2029.
The report also said planning reserve margins, currently 18.9% for peak load and 10.5% for net peak load, will drop into negative territory for the 2027/28 winter. (See ERCOT’s Revised CDR Report Met with Doubts.)
The latest CDR report, released May 16, results in an increase to peak demand of 218 GW by 2031. The grid operator’s current peak is 85.5 GW, set in August 2023.
Recent state legislation requires ERCOT to include any load in its projections that doesn’t yet have a signed interconnection agreement. The grid operator has aligned its protocols with the rule to define “substantiated load” as being supported by an executed interconnection or other agreement, an independent third-party load forecast deemed credible by ERCOT, or a letter from a transmission and distribution service provider (TDSP) officer attesting to the coming load.
“The vast majority of load included in the TDSPs’ forecasts are loads that were attested to in a letter from an officer of the TDSP, rather than being supported by an interconnection agreement between the TDSP and the customer,” ERCOT said in a filing with the PUC.
The ISO proposes a 49.8% reduction in data center loads and a 55.4% cut in officer-letter loads to “achieve alignment with historical realization rates.”
CenterPoint Audit Released
Certified public accountants Moss Adams shared the results of an audit it conducted of CenterPoint Energy’s management activities associated with the utility’s controversial $800 million lease and operation of mobile generation units that turned out to be only somewhat mobile (58049).
The Houston-based CPA firm found that CenterPoint followed best practices for competitive bidding and established specifications and requirements to meet business needs. However, it said the utility did not adhere to those practices for consistent completion of vendor risk assessments or adequate consideration of conflict of interest and that it “somewhat” met adequate documentation and record-keeping best practices.
Moss Adams made several recommendations related to procurement and emergency management, including implementing a more detailed framework for identifying, assessing and managing conflicts of interest, and ensuring that vendor risk assessments are completed for all procurements.
CenterPoint has responded by detailing how it already has addressed or will respond to each of Moss Adams’ findings and recommendations. The commissioners asked the utility to file updates on its progress and return to an open meeting after the findings are closed out.
The PUC engaged Moss Adams to perform the audit after customer and lawmaker outrage over CenterPoint’s recovery efforts following Hurricane Beryl in July 2024. The mobile generators were acquired to prepare for hurricane season, but the larger 30-MW units proved too unwieldy to move and sat unused during the weekslong recovery. (See Texas Politicos, Residents Bash CenterPoint.)
The 123-MW project is sponsored by EMPower USA, Emerging America Financiera and Integrated Gas Services de Mexico. Staff said the applicants have given an “indication of a binding equity” and an equity agreement and provided general acceptance to the term sheet.
The project boosts the TEF portfolio to 19 applications, $5.15 billion in requested loaned funds and 9.59 GW in potential new dispatchable generation. The PUC will release individual nameplate capacity and loan amounts for each project upon loan execution.
The low-interest loan program, designed to add 10 GW in gas generation, has seen eight projects drop out or be removed in recent months. (See 2 More Projects Fall out of TEF Loan Program.)
Former FERC Chair Willie Phillips, now a partner with Holland & Knight, says his old agency is in good hands with its current membership.
“My colleagues at the commission, they understand that FERC is an independent agency, and FERC works best when it’s at a full capacity,” Phillips told RTO Insider on May 16. “But I can say that the colleagues that I have there now, they are outstanding professionals. They’re exceptional regulatory leaders, and we have the team at FERC that we need right now to move forward with the important and complex matters that they’re dealing with.”
Phillips left FERC in April, saying that he wanted to move on after nearly three and a half years there and seven years at the D.C. Public Service Commission. He chaired FERC for two of those years and the PSC for his last three. (See Commissioner Willie Phillips Announces his Resignation from FERC.)
He is now at Holland & Knight in its Public Policy & Regulation Group. Coming with him from FERC is his former chief of staff, Ronan Gulstone. Both are now partners at the firm.
“For me, it was time for change,” Phillips said. “It was time for a new set of challenges after spending three years at FERC and really accomplishing one of my top priorities, which was transmission reform.”
He said three orders issued under his chairmanship — FERC Order 1920, on regional transmission planning and cost allocation; Order 2023, on generator interconnection queues; and Order 1977, implementing backstop transmission siting authority — represent the biggest reforms on transmission policy in a generation and can help the country build the transmission system it needs. (See FERC Issues Transmission Rule Without ROFR Changes, Christie’s Vote and FERC Updates Interconnection Queue Process with Order 2023.)
Order 1920 is on appeal at the 4th Circuit Court of Appeals, but Phillips said he believes FERC will ultimately be successful in that case because it builds on Order 1000, which was upheld in the courts. With the amount of load growth and new generation that needs to come online in the coming decade, the regional transmission expansion that he said Order 1920 will enable is needed.
“If we had all of the generation that we need — and we don’t,” Phillips said, “we don’t have a way to connect it to the users, to the stakeholders, to our homes and businesses. It’s like a train without a track. And so, this is something that I believe the industry needs. It’s something that all Americans need, and we can’t move fast enough to get transmission built in this country.”
FERC Chair Mark Christie initially voted against the order but voted in favor of Order 1920-B, as on rehearing the commission made changes to ensure states would have their voices heard on cost allocation.
“He was central in advocating for changes that I believe improved Order No. 1920 and allow for even more participation by the states,” Phillips said. “We can’t do this without the states. We have to have state regulators at the table, and I believe we made the order stronger.”
One of the criticisms Christie and others have had of Order 1920 is that it was aimed at the Biden administration’s goal of expanding renewables to address climate change. Phillips pushed back on that.
“The commission is resource neutral, and that means that we don’t pick and choose winners and losers when it comes to the resources that are connected,” Phillips said. “And I personally had an all-of-the-above approach when I was at FERC, and I firmly believe that we need generation resources of all kinds.”
With the pace of load growth accelerating around the country, both generation and transmission expansion are needed to keep pace with that. That is the main reason Phillips said he believes Order 1920 will be successful over the long term.
The regional transmission plans in Order 1920 are going to take years to see any actual infrastructure development, but Order 2023 is already being implemented around the country now. FERC has processed all of the non-RTO region compliance filings for Order 2023, but it still has a few left to vote out from the organized markets. (See CAISO, PacifiCorp, PSCo All Close on Order 2023 Compliance.)
“We started with 2023 because we believe that it is the most pressing and the lowest-hanging fruit to get more generation and get more transmission built for the grid,” Phillips said.
On average it takes a generation project five years to get through the queue, and Phillips said that is unacceptable. That is just starting to improve, and FERC’s reforms should continue to reduce the wait time, which will be a major improvement as demand growth has returned in a way not seen in decades, he said.
“It’s going to take all hands on deck to make sure that we can provide the energy that our country needs in a reliable and efficient way,” Phillips said.
So far, the load growth has contributed to a tightening supply-demand balance and driven up prices, which has contributed to more criticism of the organized markets that FERC has championed for the last quarter century. The commission has focused on that issue through a joint task force with the National Association of Regulatory Utility Commissioners and technical conferences on ISO/RTO markets, while responding to rule changes in those markets.
“We’ve seen more change in the past decade in our industry than we have in the previous 50 years,” Phillips said. “If everything is changing in the industry, then you also have to take a look at regulation to see what changes need to be made. Industry is moving fast. Innovation is moving fast.”
It makes sense to look under the hood at markets and make sure they are capable of handling that pace of change, he said.
“If you look at this as almost like a 20-year experiment, I think on balance, RTOs and ISOs, they’ve been beneficial when it comes to reliability, building transmission and bringing on new resources,” Phillips said. “Now, is there room for improvement? Absolutely, absolutely. But I joined Chairman Christie at my last open meeting in praising RTOs and in particular the leadership, because they have a very difficult task right now. But it’s my belief that we can make changes that can improve the situation, and I’m supportive of even expanding the RTOs where possible around the country.”
FERC on May 15 partially approved CAISO’s Order 2023 compliance filing, directing the grid operator to address mostly minor issues in the document (ER24-2042).
The commission issued Order 2023 in July 2023 in to help unclog highly congested generator interconnection queues across the U.S.
The rulemaking requires public utility transmission providers (including RTOs and ISOs) to adopt a package of “reforms” to streamline their interconnection procedures, including implementing a “first-ready, first-served” cluster study process; taking measures to accelerate interconnection processing; and incorporating “technological advancements” into the process.
To implement the changes, Order 2023 directs all transmission providers to revise their pro forma Large Generator Interconnection Procedures (LGIP), Large Generator Interconnection Agreement (LGIA), Small Generator Interconnection Procedures (SGIP) and Small Generator Interconnection Agreement (SGIA) to a standard that either meets or exceeds those set out in the order.
FERC’s most substantive rejection in the CAISO order dealt with requirements around the allocation of costs for specific network upgrades.
In this area, the commission accepted CAISO’s provisions for allocating the cost of interconnection facilities because the ISO had adopted FERC’s pro forma LGIP provisions without modification, while also approving the ISO’s proposed independent entity variation (or deviation from the pro forma language) not to adopt definitions of “substation network upgrades” and “system network upgrades” in its LGIP because those are defined elsewhere in the ISO’s tariff.
But the commission also found that, with respect to substation network upgrades (called Interconnection Reliability Network Upgrades — or IRNUs — in CAISO’s tariff), the ISO’s filing failed to address Order 2023’s requirements to define a “proportional impact method” for calculating upgrade costs, nor did it propose a method for allocating the costs in a manner consistent with the pro forma LGIP.
“The pro forma LGIP states that ‘substation network upgrades, including all switching stations, shall be allocated first per capita to interconnection facilities interconnecting to the substation at the same voltage level, and then per capita to each generating facility sharing the interconnection facility,’” FERC wrote. “CAISO’s tariff states that ‘interconnection customers assigned IRNUs in their cluster study will be allocated the full cost of the IRNUs in their maximum cost responsibility.’ CAISO’s tariff, therefore, does not explain how IRNUs will be allocated to interconnection customers, as required by Order No. 2023.”
Notably, the commission agreed with CAISO’s argument that it be exempted from the Order 2023 requirement that it implement a transition to a cluster study process because the ISO already has such a process in place.
CAISO last year won FERC’s approval for a plan to accelerate the ISO’s interconnection queue by reducing the number of projects it must review in its queue cluster study process through use of a new screening procedure that prioritizes projects based on transmission availability and commercial viability. Those changes will apply to the outsized interconnection Cluster 15 and all subsequent study clusters. (See FERC Approves CAISO Plan to Streamline Interconnection Process.)
“CAISO is proposing procedures to effectuate its Cluster 15 transitional process that align the proposed Order No. 2023 interconnection study schedule with CAISO’s transmission planning process, thereby ensuring future clusters can consider new transmission capacity before submitting interconnection requests,” the commission wrote.
The ISO must submit revisions to its compliance filing within 60 days.
PacifiCorp, PSCo Mostly Comply
FERC also largely approved the Order 2023 compliance filings of PacifiCorp (ER24-2017) and Xcel Energy subsidiary Public Service Company of Colorado (PSCo) (ER24-2030).
In both rulings, the commission said it assumed many of the deviations from Order 2023’s pro forma language it found in the filings were typographical or “minor errors” the utilities “inadvertently” included in their submissions, which the commission directed them to correct.
In the PacifiCorp ruling, FERC rejected the utility’s proposed proportional impact method for allocating network upgrade costs for short-circuit-related system network upgrades in its LGIP. PacifiCorp had proposed to allocate those costs within “cluster areas,” effectively comprising subgroups within cluster studies.
But the commission pointed out that Order 2023 explicitly states that the transmission provider cannot change how it allocates network upgrade costs even if it opts to study in subgroups. The provider must follow the requirement “to use a proportional impact method to allocate system network upgrade costs among all interconnection customers in the cluster regardless of subgroup.”
“In other words, a transmission provider’s proposed proportional impact method must allocate system network upgrade costs among all interconnection customers in the cluster, even when the transmission provider proposes to use subgroups in its cluster studies,” the commission wrote. “Here, PacifiCorp proposes to allocate proportionally the costs of short-circuit-related system network upgrades among the interconnection customers within a particular cluster area (i.e., a subgroup), rather than across the entire cluster.”
In the PSCo ruling, FERC rejected the utility’s proposal to require interconnection customers to submit a $7.5 million commercial readiness deposit, noting that it is 15 times the $500,000 maximum set out in the pro forma LGIP.
“We acknowledge that the commission accepted this amount as consistent with or superior to the Order No. 2003 pro forma LGIP; however, in the context of the reforms adopted in Order No. 2023, we find that PSCo has not demonstrated that this amount is consistent with or superior to the Order No. 2023 pro forma LGIP,” the commission wrote. “Order No. 2023 adopted a package of requirements to enter and proceed through the interconnection queue and reduce or eliminate the submission of speculative or non-viable projects that lead to delays in the interconnection process as they withdraw and create the need for restudies.”
“By significantly increasing the financial showing that an interconnection customer may make to proceed with its interconnection request, PSCo’s $7.5 million financial readiness deposit strikes a fundamentally different balance than Order No. 2023 prescribes. We are not persuaded, based on the current record before us, that PSCo’s deviation, even when coupled with additional non-financial readiness criteria, is consistent with or superior to Order No. 2023’s requirements,” the commission concluded.
The California Public Utilities Commission has rejected a project proposed by Pacific Gas and Electric to convert wood biomass to natural gas, finding that the company had failed to demonstrate that it would reduce greenhouse gas emissions and benefit ratepayers.
The utility did not account for fugitive methane emissions from the transmission, storage, distribution and production of biomethane at the project site, the commission found. PG&E also did not account for the GHG emissions caused by transporting biomass to the project site.
PG&E had proposed adding a methanation system to Woodland-based West Biofuels’ existing gasification facility in Burney as part of the CPUC’s renewable natural gas rulemaking, issued in February 2022. Each utility in the state was required to propose at least one woody biomass gasification pilot project as part of the commission’s effort to procure 18 Bcf of biomethane by this year and 73 Bcf by 2030. (See California PUC Sets Biomethane Targets.)
The commission had directed PG&E to set aside $16.936 million in revenue from the state’s cap-and-trade program to fund the project. But the commission found that, along with not properly estimating the GHG reductions from the project, “no analysis has been provided by PG&E to demonstrate the estimated benefits to ratepayers from the project in concrete terms.”
“Our growing understanding of California’s affordability crisis has heightened our scrutiny of programs that add costs to ratepayer bills,” Commissioner John Reynolds, who was assigned the proceeding, said at the CPUC’s voting meeting May 15. “I am wary of continuing to add programs that place substantial above-market costs on ratepayers for initiatives primarily aimed at achieving broader societal or global benefits with the expectation that ratepayers will pay for those broader societal and global benefits.”
Over recent decades, California ratepayers have been asked to fund numerous climate and policy initiatives through their energy bills, Reynolds added. This approach has proven “regressive … and has contributed significantly to our current affordability crisis,” he said.
Reynolds recognized that many of the investments in climate policies and programs have produced real societal benefits that have been important for society at large. “But it is increasingly important that we be very careful about which programs we fund on ratepayer bills,” he said.
The commission’s Public Advocates Office had protested the application, arguing that PG&E has “not demonstrated that the project will be able to offset emissions from the commercial hydrogen used in the methanation process, 95% of which produced in the United States involves the use of fossil fuels.” The Center for Biological Diversity and the Sierra Club also jointly protested.
The CPUC directed PG&E to return the cap-and-trade revenue it had set aside to ratepayers.
New York is tweaking its approach to clean energy development as it works to get its lagging decarbonization ambitions back on track.
The Public Service Commission approved an order that will, among other things, change onshore and offshore renewable solicitations, revise the credits that subsidize those renewables, consider whether to continue nuclear generation subsidies and open a dialogue to better inform the question of whether to allow utility development and ownership of renewable generation.
The May 15 decision came as part of the biennial review of New York’s Clean Energy Standard (CES) submitted as a draft July 1, 2024. (Case 15-E-0302)
The draft acknowledged that the state’s clean energy transition is likely to miss its first mandated target — 70% renewables by 2030 — by a potentially wide margin and suggested ways to address the slow progress.
The 6-0 vote by the PSC finalizes that draft, with some of the suggested changes adopted and some rejected.
Two years ago, New York had a large portfolio of contracted renewable projects, but soaring prices made those contracts untenable and many were canceled. More recently, a president highly supportive of renewable energy was replaced by a president who is highly supportive of fossil fuels and is actively working to hinder renewables development.
The order cites seven key factors — mostly negative — affecting New York’s progress toward the goals mandated by the landmark Climate Leadership and Community Protection Act of 2019:
Global interest rates, inflation and supply chain pressures;
federal initiatives including IRA funding and tariffs;
siting and permitting processes that are long and complicated and likely to get more so; and
expected increase in the statewide electric load.
Marco Padula, director of the Department of Public Service Office of Markets and Innovation, summed up the situation as he presented the DPS staff recommendations to the PSC members:
“The draft order recognizes that New York is in a pivotal moment where we have not seen the expected level of success from our current processes and are faced with massive amounts of new load growth and rising need for new clean firm electric capacity on the grid.”
The changes suggested in the draft drew a wide array of comments giving support, explaining opposition and suggesting tweaks.
The PSC rejected some proposed changes to the CES, including strike-price adjustments due to certain black swan events, those risks unforeseen at time of contract awards.
But it directed several notable changes:
The New York State Energy Research and Development Authority can increase the average annual solicitation of Tier 1 RECs (renewable energy certificates for large-scale onshore facilities) from 4,500 to 5,600 GWh, and its procurement authority is extended to 2029.
NYSERDA will establish a minimum maturity threshold in all RFPs to attract projects far enough advanced that they have a higher likelihood of achieving commercial operation in a relatively short period of time; at a minimum, they must have completed NYISO’s Phase 1 cluster study and be eligible for the final phase.
The maximum term of offshore REC contracts is extended from 25 years to 30; NYSERDA will be allowed to extend Tier 1 REC contracts from the current maximum of 20 years to 25 on a case-by-case basis.
NYSERDA is authorized to take greater flexibility on commercial operation milestone dates with Tier 1 and offshore projects and no longer is required to include a right of termination for failure to come online by a certain date.
DPS staff will develop separate criteria for repowering baseline hydroelectric resources and submit a recommendation to the PSC.
While it still supports the rationale for banning utility ownership of generation during deregulation in the mid-1990s — fostering competition and preventing vertical market control — the PSC also said much has changed in 30 years, and utility ownership of generation now must be reconsidered as a way of accelerating the renewables market. The PSC took only the first tentative steps in this direction, however, laying out 15 questions that would help frame what is certain to be a contentious debate.
DPS staff will create a process to define and identify “clean energy zones” that can be incorporated into the PSC’s planning processes and renewable procurements. The zones will be a way to align generation development with planned transmission expansion and economic development as a means of cost and risk reduction.
DPS staff will prepare a white paper evaluating how the zero-emission credit program that subsidizes nuclear plants would be structured if it is continued.
Moving Forward
There is a disconnect between the amount of policy support New York provides to renewable energy development and the amount of renewables connected to the grid.
Only 23.2% of customer load statewide was met with renewable energy in 2023, down from 25.1% in 2022 — and most of that came from decades-old hydropower facilities, rather than the new solar and wind generation the state has been trying so hard to encourage.
Generation and transmission development in New York is slow and expensive in the best of times, and there always is concern about heaping additional costs onto ratepayers who already pay some of the highest electric rates in the nation.
Then there are other factors beyond PSC control to consider.
At the May 15 meeting, PSC Chair Rory Christian quoted boxer Mike Tyson:
“Everybody has a plan until they get punched in the face.”
Christian was speaking about another matter before the PSC that day, but his point applies equally to renewable energy development, which has been rocked back on its heels by President Donald Trump.
How best to foster renewable energy development in New York in this environment remains to be seen, but there is room to adapt — the next biennial review of the CES is only a year away.
With the 2024 biennial review finalized, two advocates for energy developers and operators shared their thoughts with RTO Insider.
Marguerite Wells, executive director of Alliance for Clean Energy New York, said she is cautiously optimistic that the CES update will move the needle on New York renewables.
There have been three primary friction points, she said: interconnection, permitting and offtake.
NYISO and the new Office of Renewable Energy Siting largely have addressed interconnection and permitting, respectively; the CES update will help address offtake in a few ways, Wells said, but questions remain.
Uncertain in her mind are which black swans will be eligible for price revision and which ones will not.
Increasing the size of procurements is good, provided there are enough projects to fill the list.
The project maturity threshold potentially is a solution to the issue of developers not familiar with New York bidding proposals at unrealistically low prices and winning contracts, then not being able to follow through once the cost of doing business in the state becomes apparent.
To address this, ACE NY had advocated reducing the weight NYSERDA assigned to bid prices as it awarded contracts, but the PSC opted to retain the emphasis on low prices to protect ratepayers.
Developers that go through Phase 1 cluster studies presumably will have a better sense of what their costs will be, Wells said, so that might discourage lowball bids.
She also is aware of the passage of time.
“I was waiting for this report with bated breath since last July,” Wells said, and when it finally arrived, after 10.5 months, it only kicked the can down the road on some questions, such as utility ownership of generation.
She thinks of the phrase “analysis paralysis” at times, but said, “I do think it’s meaningful. … I think they’ve done what’s in their own scope to fix for now, and we will just keep tweaking. I’m also looking forward to the fact the next CES review is just next year.”
Independent Power Producers of New York CEO Gavin Donohue saw many positive aspects in the decision, including the movement toward continued nuclear subsidies, the increased procurement targets and the repowering of hydropower.
But the fact that the PSC did not open generation ownership to utilities — only sought to frame a possible future discussion — was the most important single aspect of the order for IPPNY and its members, Donohue said.
He feels there were missed opportunities as well.
“The fact that they recommitted to having zero-emitting resources and clean energy into the future is a positive outcome, but the complexities, the details about reliability, affordability, are really important today,” Donohue said.
The 2019 climate law mandated 100% zero-emissions resources by 2040, but the PSC still has not defined zero-emissions, making investment decisions much more complicated. How does an investor approach a project that might be threatened with a phaseout a few years after it goes online?
“I’m frustrated because that’s really, to me, where the rubber meets the road on the practicality of this law,” Donohue said.
“To me, that is a bigger hurdle, in some ways, than building the renewables because of the capacity factor and the amount of megawatts involved. And also the magnitude of change that has to occur in the overall infrastructure of pipelines in the transmission system to make that happen.
“One of the things you can’t do is legislate or regulate economics and physics.”
FERC has refused MISO’s proposed special pathway in its interconnection queue for generation projects labeled necessary by state regulators.
The commission said MISO’s proposal lacked direction to advance resource adequacy, and the fast lane ran the risk of becoming inundated with an unlimited number of generating facilities (ER25-1674). FERC said it rejected the proposal without prejudice, leaving MISO free to file for another express lane design in its queue.
MISO filed in mid-March for the temporary measure to usher generation projects crucial to an adequate supply through its interconnection queue faster. MISO’s intention for a 90-day processing for “shovel-ready” projects with a stamp of approval from state regulators would have been far removed from the upward of three years that most interconnection customers must wait in the regular queue.
New capacity seeking expedited treatment would have had to come equipped with a permission slip from its relevant regulator; a $100,000, nonrefundable deposit; a refundable milestone payment of $24,000/MW; a designated commercial operation no more than three years from its interconnection request; and proof of land rights.
Opponents of the plan said it effectively would have allowed vertically integrated utilities’ gas plants to cut the interconnection line while hindering independent power producers’ proposals. They also raised concerns over how the proposal would include Illinois and Michigan’s retail choice areas. (See MISO Fast Lane Proposal Disadvantages IPPs, Retail Choice States, Critics Tell FERC.)
Eight former FERC commissioners even warned sitting commissioners via a joint letter that greenlighting the plan would threaten FERC’s open access transmission tenet and would have provided an opportunity for self-dealing among utilities to advance their affiliated generation.
The commission in its May 16 order said MISO’s decision not to place any limit on the number of projects or specify a megawatt maximum could culminate in an oversaturated process with lengthy processing times, eventually resembling MISO’s existing, beleaguered queue. The commission said MISO would be hard-pressed to meet resource adequacy and reliability targets with a bogged-down fast track.
FERC said MISO itself acknowledged the “shortcoming” of unlimited projects by stating it “could not guarantee the timeline … if multiple requests are submitted in the same quarter in the same area of the grid due to the serial nature” of the specialized studies.
The commission said MISO’s plans to open up to 14 quarterly submission windows across the handful of years the fast lane would be in operation opened the door for a “volume” of interconnection requests “untethered to reliability or resource adequacy needs.” It said it questioned whether MISO’s proposal could get critical resources interconnected on an expedited schedule and whether the design was “narrowly tailored to fix the problem.”
Beyond that, FERC said MISO didn’t establish how the process would assemble and study only key interconnection requests for projects that would aid reliability.
FERC said similar proposals like PJM’s Reliability Resource Initiative and CAISO’s Interconnection Process Enhancements were more custom-built to address resource adequacy in their regions. PJM proposed to study no more than 50 projects on a one-time basis with stipulations on location and deliverability, the commission said, while CAISO laid out system needs criteria to determine which projects advance to study zones that are capped.
FERC said MISO failed to strike a similar balance that would have projects that improve resource adequacy and reliability processed in a timely manner.
“MISO has not demonstrated that the proposed tariff language is tailored to ensure that only those resources capable of addressing identified near-term resource adequacy or reliability needs are eligible for expedited study,” FERC said.
The commission said while it’s appropriate for regulatory authorities to size up their resource adequacy needs and throw support behind certain projects, MISO must ensure that its fast track respects FERC’s “open access principles in an objective and transparent manner in order to meet the [Federal Power Act’s] requirements that rates be just and reasonable and not unduly discriminatory or preferential.”
“MISO has not done so with this proposal,” FERC wrote.
Christie Willing to Trade Vagueness for Desperately Needed Megawatts
However, FERC Chair Mark Christie said he was ready to give MISO the benefit of the doubt in exchange for an uptick in resource adequacy.
Christie said though he “fully” understood other commissioners’ qualms with a lack of detail and personalization in MISO’s proposal, he was willing to “extend to both the states and MISO a trust that they would implement the … proposal in a manner that would promote the construction of badly needed generation capacity that serves resource adequacy and reliability.”
“One thing we know with no need for further proof: This country, including MISO, is heading for a reliability crisis caused by early retirements of dispatchable resources coupled with the failure to construct sufficient equivalent capacity, all while demand rises at an unprecedented pace largely driven by data center growth,” Christie warned in a dissent.
Throughout the order, FERC invoked NERC’s 2024 Long-Term Reliability Assessment, which shows MISO could confront a 4.7-GW capacity shortfall by 2028 if resource generations go off as planned.
Christie furthermore said he didn’t think FERC should “block the states” from designating priority generation plans to ensure resource adequacy within their borders. He noted that states “are sovereign entities with the inherent police power under our constitutional structure to regulate the utilities in their state.”
Two commissioners, however, wrote separately to say that MISO’s omissions were too glaring to ignore.
Commissioner David Rosner said while rejection wasn’t an “easy decision,” MISO’s expedited lane as described “risks replicating the same backlogs and delays plaguing MISO’s existing generation interconnection queue, which are what put MISO in its current situation in the first place.” He also said that MISO’s insufficient limits on study requests risked a court finding that the fast lane is unjust and discriminatory and striking it down, “leaving MISO worse off than taking no action.”
“While MISO clearly intends to design a process that considers only ‘tens’ of interconnection requests per year, there is no guarantee that interest” will be limited, Rosner said.
Rosner said he believed FERC’s order of rejection provided MISO enough direction to draft a second attempt.
Commissioner Lindsay See likewise encouraged MISO to bring FERC a more workshopped proposal.
See said she couldn’t overlook that MISO’s plan left out retail choice states Illinois and Michigan and would bestow undue preference on resources connecting in vertically integrated states.
“Because the commission should remain evenhanded when it comes to our state partners, a proposal that discriminates among the states themselves gives me serious pause,” See said.
See also said MISO should require the states to explain how they decided certain projects are essential for reliability or resource adequacy. See said although MISO promised its fast lane would be “‘open, competitive [and] technology/fuel agnostic and … not involve MISO favoring or selecting certain projects over others,’ nothing in the tariff explains how it will live up to those goals.”
“Simply put, the commission cannot evaluate criteria that do not yet exist, that will vary state-by-state when they do and that MISO does not plan to police,” she wrote.
MISO Prepped for Positive Outcome
Meanwhile, MISO had begun preparations to start project acceptance.
MISO posted an informational guide on the fast track in anticipation of a favorable FERC order. Through an email to stakeholders, MISO said if the proposal was not accepted by the commission, it would remove the guide from its website.
MISO planned to open an application window for the first quarterly fast-track study treatment through May 22. It planned to accept submissions for the first expedited cycle through an email dedicated to interconnection issues, and launch a submission portal this summer for upcoming cycles.
MISO planned to process quarterly study classes until the end of 2028. The next application deadline would have come due in mid-August.
During an Organization of MISO States’ Resource Adequacy Summit May 13, MISO CEO John Bear said the RTO didn’t yet have projects lined up for the fast lane and said he couldn’t offer an overview of the resource mix that would have become the first entrants in the express lane.
“Fixing the queue is not a challenge. Clearing the queue is a challenge. You’ve got a 130-GW system with 350 GW in the queue. … You can’t even model that,” Bear said of the regular queue lineup. He predicted it would take MISO about three years to get a handle on its stockpile of proposals.
In response to an audience question on whether some of the queue volume would drop off naturally, Bear said he didn’t want to guess how many generation projects might not be realized. He said developers have put a lot of money and planning behind their projects, and MISO’s newly higher fees, stricter land use requirements and stepped-up withdrawal penalties mean projects have been subjected to more scrutiny than in the past.
Win for Clean Energy Groups
Clean energy organizations are likely to rejoice at the ruling.
In a statement, Earthjustice said the proposal would “sideline generation projects that have been waiting years to connect and send everyday consumers the bill for fast-tracking projects hand-picked by special interests.” The group said the expedited process would discriminate illegally against competitive clean generation developers. It also said MISO risked backsliding into “inefficient, serial interconnection studies.”
“FERC rightly rejected the proposal from MISO to fast-track connection of utility-owned methane gas projects over the queue of clean energy projects that have been waiting years to connect to the grid. FERC’s role as an independent agency is to protect consumers and ensure reliable affordable energy. The best way to do that is [to] let clean energy compete fairly and openly,” Earthjustice attorney Christine Powell said in a statement following the decision.
Clean Grid Alliance similarly criticized the proposal in a blog post prior to FERC’s ruling: “The trouble with [the Expedited Resource Addition Study (ERAS)] is, in short, ERAS as currently proposed doesn’t play by the rules. At least not the rules everyone else must play by. There doesn’t seem to be any other reason to allow this process than to create a pathway for adding new natural gas and enable ‘queue jumping,’ which allows certain projects to bypass the current interconnection queue process and skip ahead of projects that have been waiting in the queue for years.”
States outside of Michigan and Illinois, however, had urged FERC to approve the expedited queue lane.
In similar, recent letters to FERC, Mississippi Gov. Tate Reeves (R) and Arkansas Gov. Sarah Huckabee Sanders (R) called the proposal “essential” and cited the risks posed by rising load.
Indiana has a new law aimed at motivating new capacity in the state to serve rising load and restricting when utilities can shut down plants.
The legislation expedites the Indiana Utility Regulatory Commission’s approval process on utilities’ generation plans to serve large-load customers like data centers. It also creates cost recovery processes for utilities to recover the projects to accommodate big-need customers and makes it more difficult for utilities to retire their existing generation.
Finally, the law provides for a 20% state tax credit for in-state producers that manufacture small nuclear reactors.
Gov. Mike Braun (R) signed the bill into law May 6. House Republicans advanced the bill April 22 in a 63-23 vote along party lines (HB 1007).
The law defines a large-load customer as one requesting new electricity demand greater than 5% of the utility’s peak load or 150 MW.
The law mandates customers requiring a big grid buildout to make “significant and meaningful financial assurances” for the projects they need, covering at least 80% of costs and shielding other customers from picking up the bill.
It also compels public utilities to annually report to the IURC any generating units of at least 125 MW that they plan to retire. The IURC then would initiate an investigation into the withdrawing generation. If the commission finds that a utility cannot reliably meet demand without the unit or is unable to meet its planning reserve margin requirement, it would block the plant closure or direct the utility to acquire or build equivalent capacity. The law dictates that utilities must have replacement plans of “approximately the same accredited capacity” as the retiring unit within their RTO.
Per Indiana’s existing law, any utility not meeting at least 85% of its peak load must provide the IURC with capacity projections for the next three years.
A fiscal analysis from the legislature found that the SMR state tax credit could cost taxpayers about $280 million. It also found that the new retirement investigation provisions will increase the IURC workload. Indiana lawmakers are not dedicating more resources to the IURC to handle the added work.
Indiana’s Republican representatives said the law is necessary to incentivize capacity additions. Democratic representatives voiced concerns the measures would keep coal plants online longer and have taxpayers spending too much to subsidize small modular reactors.
The Sierra Club said the law would “increase electric bills and spew more pollution throughout the state.”
Rep. Ed Soliday (R-Valparaiso), who authored the bill, told local news outlets that Indiana is in competition with other states to entice large-load customers.
ROSEMONT, Ill. — MISO CEO John Bear put a positive spin on the grid operator making do with little cushion in its supply.
During the Organization of MISO States’ annual Resource Adequacy Summit on May 13 in Chicagoland, Bear said it’s not necessarily a bad thing that MISO has only thin excesses on top of its margins. Other speakers posed ideas on how to beef up supply.
Bear said even though NERC and the industry might say MISO is “on fire” in terms of resource adequacy, MISO is managing nicely while operating ever closer to its planning reserve margins.
Bear said last year, the RTO and the Organization of MISO States’ joint resource adequacy survey “gave us some warning lights” and members reacted accordingly to avert a potential 2.7-GW capacity deficit the survey showed arriving as soon as summer 2025. (See OMS-MISO RA Survey: Potential 14-GW Capacity Deficit by Summer 2029.)
Nevertheless, Bear said MISO and the stakeholder community must get comfortable with enacting market and planning changes swiftly to continue to be resource sufficient.
“Eighteen months to redo the futures is incredible. We’ve got to do it in six,” Bear said, referencing the several months MISO has set aside to update the set of 20-year scenarios it relies on to chart big-ticket transmission projects.
MISO Vice President of System Planning Aubrey Johnson said MISO was inspired to add its supply-constrained fourth future to its existing trio of scenarios because staff noticed a few years ago that generation was not coming online as scheduled. (See MISO Forming 4th Tx Planning Scenario Based on Supply Chain Barriers.) Johnson said to finish the futures, MISO needs to “move,” meaning MISO gets its futures information in front of stakeholders and makes sure they understand and are mostly comfortable with them before finalizing them.
“Those that are not quite there, we can’t let them hold up the pace of change,” Johnson said.
Bear acknowledged that achieving the cooperation to move fast is “tough” across the country right now. But he added that MISO would be challenged even if load growth continued at a docile 1% per year and data center projections didn’t jump exponentially.
“We’ve got a lot of old power plants that aren’t performing well. That’s changing, by the way, thankfully,” he said. “We’re going to have to get more energy on the system … even if the data centers don’t show up.”
Bear said MISO is poised to double its 13-GW solar fleet over the next two years. However, he cautioned that MISO must be thoughtful about balancing its inverter-based resources. He said the risk posed by inverter-based resources is very real, exemplified by the frequency issues that likely were the culprit behind the late April blackout in Portugal and Spain.
MISO has noticed it increasingly encounters challenging operations in spring and fall on days when renewable energy output is high, Bear said. He said MISO is keeping tabs on its changing needs and will investigate adding frequency products or accrediting resources differently around frequency and inertia.
Bear said MISO has devoted considerable time to planning transmission so wind and solar can be dispatched efficiently across the footprint. He pointed out MISO doesn’t need to track a significant number of curtailments, like the graph CAISO maintains.
MISO Independent Market Monitor David Patton asked the audience if anyone was surprised by the capacity auction’s $666.50/MW-day clearing price for the upcoming summer. MISO’s capacity auction left all but 300 MW of offers unused. (See MISO Summer Capacity Prices Shoot to $666.50 in 2025/26 Auction.)
He was met with silence.
“If you haven’t been tuned in, capacity prices went up manyfold from past years,” Patton said.
Patton said MISO buying 2% beyond the absolute summer minimum capacity standards is good for the health of the system.
“It was a bargain to buy it. … It’s not a bad thing that we bought beyond the minimum requirement,” he said. Patton also said states were instrumental in getting the auction clearing on a sloped demand curve.
“We saw how powerful I was, recommending this for 10 years,” Patton joked.
However, Patton said the “full” signal to build generation won’t arrive until MISO institutes its new, availability-based capacity accreditation beginning in mid-2028. He said the accreditation will deliver a final puzzle piece and allow the footprint to better meet long-term resource adequacy objectives.
Under the new accreditation, most resources’ capacity values are set to fall, as evidenced by MISO’s evaluation of this year’s supply had the accreditation been in place.
“It’s going to change how people plan, it’s going to change how merchant generation is built, how [integrated resource plans] are made,” Patton said.
IMM: Problem Remains with ‘Not Real’ DR
However, Patton said he remains deeply concerned about demand response gaming MISO’s markets. He said MISO’s recently filed suite of stricter rules should close some loopholes that allow DR to collect payments for doing nothing. (See Stakeholders Ask FERC to Soften MISO’s Proposed DR Accreditation.)
He said MISO is right to “aggressively” confirm that DR resources are genuine. He said if MISO does that, DR should function more like MISO traditional generation, which responds when called upon. Patton said MISO carrying only authentic and responsive DR ultimately should reduce costs.
Patton hinted at more referrals to FERC’s Office of Enforcement. He said an audit of MISO’s DR fleet turned up a retail customer that was registered under multiple market participants and a data center that has offered demand reductions and collected payments for about two years despite not yet being built.
“If you look at the site, it’s a really pretty greenfield with weeds,” Patton said. “We cannot allow people to sell us something that’s not real.”
Other Perspectives
Other speakers at the OMS meetup had plenty to say with resource adequacy risk at MISO’s doorstep. Alliant CEO Lisa Barton struck a decidedly graver tone in her keynote address.
Barton said she was sure the audience “was glued to their phones on April 28,” tracking the Iberian outage as it unfolded. She said she was sure attendees are focused on “making sure what happened there doesn’t happen here.”
Barton said industry players should be dedicated to at least holding up or bettering today’s levels of reliability and resiliency. She said “one of the unfortunate things” is people eventually forget grid disasters like Winter Storm Uri.
“We need to remind ourselves that’s out there,” Barton said.
Barton said there’s value in assessing events that “might not have happened in our backyard” and committing to learning from them. She said Spain and Portugal are dealing with a $1.7 billion fallout and a handful of deaths from just “one day of the lights not being on.”
Barton said the event should reinforce the idea that resource adequacy takes all kinds of generation, with some types more consequential than others.
Barton praised MISO for proposing an interconnection queue fast lane to get select generation online faster.
“I know it’s not a universally popular decision, but it’s action,” Barton said, adding that “not acting is a far greater risk.
“I remember saying to my daughters, ‘Not making a decision is a decision.’”
Barton said it can’t be ignored the U.S. population is benefiting and living on grid investments made decades ago. She said no matter your politics, nearly all can agree the industry needs to expand generation to support American innovation.
“What I think we can agree on is, we have to win the technology war,” she said.
Barton said MISO members should be insistent on striking flexible load arrangements to handle incoming large loads. She warned that it “all can’t be fixed with transmission.”
Finally, Barton said it’s not a good idea for data centers to strike out on their own and secure their own generation construction. She said data center developers likely would seek components that utilities also are vying for, likely exacerbating supply chain problems. Barton said independent generation construction is reminiscent of a pre-RTO world, where utilities planned in isolation and transmission and generation redundancies existed. It’s possible, Barton said, to work in protections for ratepayers while still offering attractive rates to data centers.
Data Center DR?
Despite the IMM’s indication to expect more enforcement against DR double-dealing, some are bullish that data centers are a new frontier.
Duke University fellow Tyler Norris said the idea that data centers are strictly inflexible and need firm service 24/7 isn’t true, as evidenced by a 2024 report from the Secretary of Energy’s Advisory Board. He said there could be some load flexibility found when the system needs it most.
“Outside of the 15 to 20 hours across the year … during cold snaps or heat waves, there’s a lot of headroom” on the system, Norris said.
He said Duke’s recent research found that if data centers could curtail load annually at just 0.25% of their potential maximum use, it could allow the existing grid to support about 76 GW of new load across the U.S., with 11.6 GW of that in MISO. (See US Grid Has Flexible ‘Headroom’ for Data Center Demand Growth.) Some in the industry are skeptical those figures can be achieved without co-located generation.
Norris pointed out that the country’s grid is built around the “few hours per year of extreme demand” and outside of demand peaks, about half of generation capability can go unused. Norris said while regulators might think data centers are running at a 100% utilization rate, they’re more likely to be running in the order of 40 to 50%. He said some of the unrealized use stems from data centers’ tendency to overstate interconnection needs.
“There’s a lot of potential there,” Norris said, but added that the flexibility from data centers will look different from traditional DR. He said grid operators will need to “get creative” to design different service tiers of DR to accommodate them.
He also said flexibility tradeoffs are being hammered out between data center developers and power suppliers.
“We know that those negotiations are happening, but on a purely bilateral basis, without a tariff,” Norris said. He said regulators might decide to outline some regulations for use agreements.
Nevertheless, Norris acknowledged the industry is in a “real crunch for the next five to seven years” to get generation built. He said construction probably will be more difficult because of the Trump administration’s repeal of Biden-era tax credits.
Surplus Interconnection Service and Batteries
GridLab’s Casey Baker said in MISO, there’s a possible “double-digit energy and capacity” solution in MISO in the form of using surplus interconnection across the sites of the RTO’s approximately 50 GW of renewable energy. He said members could build companion battery storage across those sites or, conversely, build wind or solar resources at some of MISO’s seldom-used and aging peaker plants to make the most of their little-used interconnection service.
Baker said building to use more interconnection service wouldn’t require network upgrades or the intense study and permitting that greenfield construction would require.
“We have this perception that the grid is tapped out, and that’s true in certain hours, but that’s not true in most hours,” Baker said.
Baker called batteries the “Swiss Army knife” of resources and said they can bolster resource adequacy, work as a transmission asset and provide inertia and grid-forming services, if customers are willing to pay for those models.
Mia Adams, of Ulteig Engineering and a MISO alum, added that MISO needs better participation rules for energy storage. She said though most believe that lithium-ion batteries have a four-hour limit, some can last up to 16 hours now.
“If you have the need, there’s a solution if you’re willing to pay for it,” she said. However, she added that most storage projects “in MISO don’t pencil out because of the market design.”
Adams said a 100-MW battery could be built within four months. Along with companion wind and solar generation, Adams said the footprint could host inexpensive, dependable new generation quickly.
Adams asked the audience to embrace new technologies sooner. She warned that data centers aren’t the only ones lining up for load treatment, nothing that heavy industry like aluminum smelters and steam crackers are looking to electrify.
And Adams said political instability in the form of will-they-won’t-they tariffs is upending plans for new generators.
“It’s not just batteries that come from China. It’s a very intermingled supply chain,” she reminded the audience.
Laura Schepis, an executive director at the National Electrical Manufacturers Association, agreed the volatility wrought by tariffs is anathema to planning and building resources.
Electric Power Research Institute’s Director of Power Systems Aidan Tuohy agreed that data centers aren’t the only growth the industry is facing, invoking increasingly electrified transportation, electrification of heat and reshoring of manufacturing.
“We know we can’t necessarily build fast enough to meet that demand,” he said and offered demand flexibility and grid-enhancing solutions as ways to maximize the grid and get a breather on adding new generation.
Sparkfund CEO Pier LaFarge said the industry is navigating a moment not seen since the Industrial Revolution, where the data center explosion is coinciding with geopolitical tensions.
Xcel Energy Vice President of Supply Chain Murray Sanderford seconded the echoes of the Industrial Revolution.
“In my career, I’ve never seen something so daunting from a supply chain standpoint,” Sanderford said. He said he and his peers estimate that just 60 to 70% of planned generation won’t get built due to lack of labor and lack of equipment.
MISO’s Aubrey Johnson reminded attendees that about 30 GW of MISO’s 53 GW in generation projects that have signed generator interconnection agreements but have yet to come online are more than two years behind their commercial operation deadlines.
Johnson also noted the industry is grappling with a growing shortage of technicians specializing in inverter-based relay systems, another obstacle to meeting demand and reliability targets simultaneously.
ROSEMONT, Ill. — MISO Independent Market Monitor David Patton addressed the recent controversy surrounding his longstanding criticism of MISO’s latest, $22 billion long-range transmission portfolio at the Organization of MISO States’ Resource Adequacy Summit.
Patton began a May 13 unscripted talk to regulators by joking that the “ominous” red light background on stage wasn’t doing him any favors. He told regulators that he was on their side despite some states being disappointed that he condemned many of the underpinnings of MISO’s second, $21.8 billion long-range transmission plan (LRTP) portfolio.
Patton said he was only trying to “weaponize the markets” to spur the most reliable and economic dispatch decisions while respecting states’ policies.
“By the way, I love transmission,” he joked. At another point, Patton teased that he “wasn’t allowed” to speak out on transmission planning, referring to MISO leadership asking FERC whether it’s appropriate for the IMM to analyze the value of proposed transmission portfolios in addition to markets. (See MISO Intent on Answers as to IMM Role in Tx Planning.)
Patton’s comments come about a week after MISO petitioned for the declaratory order with FERC (EL25-80). The RTO’s stakeholders are split on whether the IMM should independently assess the value of transmission projects. Patton continues to take issue with several of MISO’s estimates of the second LRTP portfolio, including its underlying capacity expansion modeling and the value of resolved reliability benefits, the amount of new generation that can be avoided and environmental benefits through the new transmission.
MISO anticipates a benefit-to-cost ratio of between 1.8:1 and 3.5:1 over the first 20 years of the LTRP projects’ lives through reliability improvements, production cost savings, capacity that won’t have to be built and environmental benefits. The IMM has pinned the value of LRTP II closer to a 0.3:1 benefit-to-cost ratio and has advocated for a condensed portfolio.
Patton said transmission planning and functioning markets are intrinsically linked and should be evaluated interdependently.
“We have to understand that when we make bad planning decisions, we undermine the market,” Patton told attendees. He again said the 20-year future MISO relied on to recommend the portfolio of mostly 765-kV lines is impractical and doesn’t represent the resource mix that will be built.
Patton said MISO is overbuilding the transmission system at the cost of the market incentivizing the construction of battery storage and developing other dispatchable technologies. It’s “very important” that MISO be realistic about the generation mix that’s on the horizon, Patton said, pointing out that many utilities remain committed to building new gas generation despite MISO allowing for very little in the future it used to plan the second LRTP.
“If we plan for a fictional system … we’re going to either pay higher costs or have an unreliable system,” Patton said.
In its filing, MISO asked FERC to “confirm” that the IMM’s “unsolicited transmission planning and monitoring activities are outside the scope” of its engagement rules with the IMM under its tariff and that it “has no obligation to reimburse Potomac [Economics] for such unsolicited transmission planning and monitoring activities at the expense of tariff customers.”
MISO’s Board of Directors in mid-February directed RTO leadership to freeze all payments to the IMM for work related to transmission planning.
MISO said its request did not preclude it from relying on an independent transmission monitor in the future. It also said it wasn’t seeking to “limit the activities of Potomac, such as participating in stakeholder processes, separate and apart from its role as the hired IMM for MISO.” Essentially, MISO said the IMM should size up transmission, pro bono and on the side as an interested stakeholder.
MISO said it needed to “remove uncertainty” around the IMM’s authority and figure out which services its customers should be paying the IMM for.
The grid operator ended by saying it plans to hire an independent, third party to assess the benefit estimates of future LRTP portfolios and the 20-year scenarios it devises to justify them.
