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April 29, 2025

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Ontario Introducing Nodal Market May 1

After nine years of development and dozens of stakeholder meetings, the Independent Electricity System Operator (IESO) is poised to launch its new nodal market May 1, a change it says will save Ontario $700 million over the next decade through reduced out-of-market payments and increased efficiency.

The Market Renewal Program (MPR) is intended to improve the way IESO supplies, schedules and prices power by creating a financially binding day-ahead market (DAM) and creating almost 1,000 locational marginal pricing (LMP) nodes.

The IESO says nodal pricing — which is used in all seven U.S. RTOs and ISOs — is crucial to efficiently dispatching and providing market signals to renewables and new resource types such as distributed energy resources, storage and hybrids.

The current day-ahead commitment process is not financially binding, resulting in uncertainty for generators. The addition of a financially binding day-ahead market gives resources “much more certainty over what they will be paid, and it gives us much more certainty over what’s available and how we how we can schedule and commit those resources,” said Candice Trickey, director of the MRP, at an April 16 webinar attended by almost 600 people. “So, it gives much, much more clarity, transparency and certainty for both sides.”

Under Ontario’s current two-schedule market design, the initial schedule ignores system constraints and transmission losses to calculate the Hourly Ontario Energy Price. The second schedule incorporates transmission constraints to determine system dispatch, with uplift payments used to address differences between the two schedules.

Candice Trickey, director of IESO’s Market Renewal Program, explains the changes coming with the new nodal market at an April 16 webinar. | IESO

The new market will use a single schedule to dispatch the system and calculate LMPs at more than 970 generation, load and intertie nodes in the day-ahead and real-time markets, a number IESO says may increase as its system grows. The day-ahead market will have hourly pricing while the real-time market will continue to price in five-minute increments.

IESO says the improved price transparency should increase efficiency and lower costs.

The pricing granularity is “really important to sort of underpinning all of the changes that we’re making and giving us the ability to make those cost decisions, and it will also provide longer term signals for resources across the province in terms of where it makes the most sense to locate if you’re looking for future opportunities,” Trickey said. “It will also help better inform consumption decisions for loads that want to be responsive to price.”

Work Began in 2016

Work on the new design began in 2016, when IESO held a series of consultations with stakeholders. “Stakeholders have been a big part of this all along the way [with] literally hundreds of meetings covering all kinds of topics — committees, groups, working groups, you name it,” Trickey said.

The goal? “Making sure that we make the most of Ontario’s electricity supply resources — those that we have today and those that we know are coming in the future,” Trickey said. “It’s really about improving how we schedule the resources and ensuring that we make the most cost-effective scheduling decisions in all hours of the day.”

The IESO’s MRP business case predicted total 10-year benefits of $975 million, including $525 million in market efficiency improvements and $450 million from eliminating unnecessary congestion management settlement credit payments. After implementation costs, the IESO expects $700 million in net financial benefits for Ontario electricity consumers over the first decade.

Accounting for congestion in LMPs will reduce uplift payments. “That’s where a good chunk of the cost reduction comes from,” Trickey said.

Changes for Non-Quick Start Generators

A new Enhanced Real-Time Unit Commitment process will seek to optimize the scheduling of non-quick start gas generators over multiple hours versus the current system, in which dispatch is determined for individual hours.

Most non-quick start (NQS) generators need one to six hours to start up and synchronize with the grid and have limited flexibility because of minimum loading points, maximum daily starts and minimum runtimes.

The IESO will be “looking up to 27 hours ahead to schedule the least cost solution and make sure that we schedule all of the pieces together,” Trickey said.

Ontario’s major transmission interfaces, electrical zones and interties | IESO

IESO also will replace its Real-Time Generator Cost Guarantee (RT-GCG) program with a Generator Offer Guarantee program. The former program provided financial and operational guarantees to NQS generators on days when they may not be able to recover their costs through energy prices. But that allowed them to claim reimbursement for start-up costs greater than what they incurred, the Ontario Electric Board (OEB) concluded in a March 6 ruling dismissing the generators’ challenge to the MRP.

Under the new rules, NQS generators must provide a three-part offer, including energy costs, start-up costs and the cost of remaining connected to the grid while generating net-zero active power.

“The non-competitive nature of the RT-GCG leads to productive inefficiencies in the short run when demand is not met using the lowest cost resources, as offers do not accurately reflect generation costs,” the OEB wrote. “The RT-GCG program also suppresses market prices below efficient levels by removing the incentives for these generators, who are frequently market price-setters, to incorporate fixed start-up costs into their offer prices. The result is a weakened price signal and a reduction of incentives for other market participants to be available at these times.”

An analysis by the generators’ consultant, Power Advisory, found a 600-MW gas generator with a heat rate of 7.5 MMBtu/MWh would have had a net margin of $75.5 million from 2018 to 2023 under the new rules, a reduction of $21 million from the current rules. The analysis also found gas generators set prices in 41% of day-ahead hours and 62% of real-time hours in summer 2021.

Impact on Loads, Resources

Nodal pricing will be applied to dispatchable loads, price-responsive loads and generation, including dispatchable resources, self-scheduling and intermittent suppliers (wind and solar). Non-dispatchable loads will settle on one of 10 hourly zonal prices. Large industrial consumers can continue to pay an hourly Ontario-wide price or choose the LMP for their location.

Dispatchable loads — “a very, very small percentage” of loads, according to Trickey — must be able to respond to IESO instructions and reduce their consumption within five minutes.

2023 energy input (TWh) | IESO

Pricing for non-dispatchable loads will remain uniform across Ontario, but the new Ontario Electricity Market Price will be based on the hourly load-weighted average of all non-dispatchable load DAM LMPs plus a price adjustment to account for the cost of the differences between day-ahead and real-time schedules.

Although the calculations behind them will change, consumer bills will look the same, with an hourly province-wide price for electricity added to the Global Adjustment, which covers the cost of building and maintaining the electric system.

Intertie Transactions

The market will use dynamic settlement pricing on its interties with Quebec, MISO, NYISO and PJM.

IESO imported 4.1 TWh to meet its 137.1 TWh of demand in 2023, while exporting 16.5 TWh.

The real-time intertie border price will be used if there is no congestion in the final pre-dispatch run. For export-congested interties, the sum of the five-minute real-time intertie border prices and the pre-dispatch intertie congestion price will be used. For import-congested interties, the lesser of the pre-dispatch intertie LMP (which includes the intertie border price plus the intertie congestion price) or the five-minute real-time intertie border prices will prevail.

The current day-ahead commitment evaluates import and export legs of wheel-through transactions as linked transactions while pre-dispatch assesses both as separate transactions. In the new market, both the DAM and pre-dispatch will assess import and export legs as linked transactions.

No Virtuals or FTR Markets

With a system-wide price and the lack of a binding day-ahead market, IESO’s current system has no virtuals market for arbitraging between day-ahead and real-time prices.

And while there is a financial transmission rights market for hedging import and export risks, there is no FTR market for hedging internal congestion.

The MRP will create a virtuals market at the zonal level, like those in NYISO and ISO-NE. Market participants will be able to submit hourly bids and offers in any of nine virtual transaction zones in the day-ahead market. The Bruce zone has a low load relative to supply, so it was combined with the Southwest to create a more balanced zone, according to IESO.

MISO and PJM began their virtuals market at the zonal level until they became more established, and SPP’s Markets+ virtuals market also will begin on a zonal basis when it launches, noted Emily Merchant, a director of product at Yes Energy.

Merchant said nodal virtual markets require significant trading activity to ensure prices accurately reflect market conditions. “Given all the changes rolling out with the MRP, the market operator may have wanted to de-risk this new virtuals market by starting off zonal,” Merchant wrote in a Yes Energy blog post on preparing for the nodal market.

The introduction of LMPs also creates the “framework to support FTRs” said Merchant, although the IESO says it has no current plans for such an expansion.

Average weighted hourly Ontario energy price | IESO

“There are no internal nodal transmission rights like there are in some other markets,” said Warren Hill, a senior adviser for market development at IESO. “We are not going in that direction.” (See IESO’s Introduction to Virtual Traders.)

Yes Energy power market analyst Tim Hough said the zonal virtual market may be most attractive to asset operators looking to hedge against volatility.

“Since there’s only nine different nodes you can virtually transact on, there is just a lot less opportunity for traders to find a couple little nodes and a special little weather pattern to make a lot of money on,” he said.

Market Power Mitigation

IESO will change from an ex-post to an ex-ante approach to market monitoring, employing a “conduct and impact” test to mitigate market power before prices and schedules are determined.

If a market participant fails the conduct test — or is found to have made an offer significantly above that expected under competitive conditions — IESO will apply an impact test to determine the difference in market outcome between the higher offer and the reference level offer. If the MP fails both tests, its offer will be replaced with reference levels.

Implementation Plan; Potential for Delays

The MRP will result in about 36 new public reports from IESO and updates to more than a dozen others, while more than 20 will be retired. The MRP also will include a new four-zone demand forecast, “so you’ll be able to see demand in different areas with a more accurate view than what we would provide today,” Trickey said.

IESO will provide updates on the status of the launch beginning the morning of April 30 and continuing through completion of the launch, expected May 2.

“There is always a small chance that something could happen in between now and then that would impact that — likely to be something in terms of system conditions,” Trickey said. “If there was some sort of reliability event — you know, weather event, or something that impacted us — we may need to change that.”

If the launch is delayed, IESO will not go forward until the first of a subsequent month, Trickey said, ruling out a launch on July 1 or Aug. 1 because of holidays. “[We] may not want to necessarily launch in the heat of the summer as well, when system conditions can be more challenging.”

Market participants will need to submit dispatch data into both the legacy and renewed market systems on April 30 because existing bids and offers will not be moved to the new system. There will be no day-ahead market for the May 1 and 2 trade dates as IESO establishes the new real-time market and monitors dispatch results.

“There will be bumps along the way as we transition, because it is a very large and complex change, and one that depends on people from across the sector,” said Trickey. “I know there’s going to be bumps coming, but we’re in a good position to weather through those.”

Although IESO is making the changes to improve operational certainty and reduce system costs, initial market results may not show immediate improvements, said Yes Energy’s Hough. “It’ll be a very big change for a lot of people. So, I would expect some volatility there. If you’re a battery asset operator — which there isn’t much of in Ontario — you will probably be raking it in early on.”

For More Information:

Editor’s note: RTO Insider is a wholly owned subsidiary of Yes Energy.

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RWE Sets Conditions for Further U.S. Renewables Investment

RWE, which put a two-year pause on its U.S. offshore wind development efforts when President Donald Trump was re-elected, now is setting a higher bar for building renewables in the United States.

The German power company is looking for greater certainty and less risk before it makes any new decision to invest in a U.S. project.

All federal permits must be in place, tax credits must be safe harbored, all tariff risks must be mitigated and — for solar and onshore wind projects — offtake agreements must be secured.

“Only if these conditions are met will further investments be possible, given the political environment,” the company said.

The update came in remarks prepared for delivery by CEO Markus Krebber to shareholders at the company’s April 30 annual general meeting.

The remarks were released publicly April 25 and cover the range of challenges facing the company and how it is meeting them as it operates in more than 20 countries.

RWE surpassed 10 GW of U.S. installed capacity at the start of 2025 and plans the construction of 4 GW more.

Demand for electricity is higher in the United States than almost anywhere else, the company said, and renewables and storage are able to meet this demand relatively quickly, so the market environment is positive.

But uncertainties have expanded in the U.S. as in the rest of the world: Political tensions are palpable, tariffs are straining trade, supply chains are more fragile, and inflation and interest rates have risen.

So the company is being more cautious, raising its required return on investment from 8% to 8.5% and projecting lower earnings in 2025 than in 2024. Net investment will be reduced from 45 billion to 35 billion euros from 2025 to 2030; RWE invested a net 10 billion euros in 2024 alone.

Renewables are by far the largest source of electricity for RWE, and the CO2 emissions it creates while generating power continue to fall as it pursues net-zero status by 2040.

Nearly 150 generation projects with a combined 12.5 GW of capacity are under construction globally, and the majority of its newest assets are in the United States.

But the world’s No. 2 offshore wind developer appears unlikely to be erecting any of the giant wind turbines in U.S. waters anytime soon.

The U.S. offshore wind sector, which had enjoyed four years of strong support from President Joe Biden, was cast into doubt by the Nov. 5 election of Trump, who had said on the campaign trail he would halt wind turbine development.

RWE announced the two-year pause Nov. 13, citing the risk and uncertainty raised by his election, and other companies have made similar decisions. (See RWE Pauses Investments in US Offshore Wind.)

Just hours into his presidency, Trump followed through on his threat Jan. 20, directing a halt to future offshore wind leasing and a review of existing permits. The chilling effect this had on the industry was ratcheted up three months later with a stop-work order slapped on Equinor’s fully permitted Empire Wind 1 project.

RWE has a greater breadth of exposure to the U.S. offshore wind market than most companies, holding lease areas on the East, Gulf and West coasts — areas that have distinctly different technical challenges and political environments.

RWE’s most mature concept sits off the New York-New Jersey coast, where it and National Grid Ventures jointly hold a lease area and repeatedly have bid their Community Offshore Wind proposal into the two states’ various solicitations.

The latest iteration of Community — with a nameplate capacity of up to 2.8 GW and an early 2030s commercial operation date — was one of four proposals submitted for New York’s 2024 solicitation. (See NY Receives Largest OSW Proposal Yet.)

The proposed Attentive Energy was soon withdrawn, but the other three — Long Island Wind, Excelsior Wind and Community — still are listed as live proposals.

The state has limited its publicity about in-progress solicitations and plans to release no updates before completion of contract negotiations, which it had targeted for the first quarter of 2025.

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California Lawmakers to Discuss Amendment Requests to Pathways Bill

The Utility Reform Network (TURN) is finding some success in getting California state lawmakers to address the group’s concerns about what the Trump administration might do if the Golden State moves forward with plans to hand over control of CAISO’s energy markets to an independent regional organization.

Democratic Sen. Josh Becker, who introduced the Pathways bill, has said he will convene a group to address the consumer advocacy organization TURN’s concerns with the proposed legislation. In its public comments on the bill, TURN submitted a position of opposition that stands unless the bill is amended.

Kathleen Staks, executive director of Western Freedom and the co-chair of the West-Wide Governance Pathways Initiative’s Launch Committee, provided the update during the committee’s monthly meeting April 25.

Staks said there has been no commitment to addressing all of TURN’s requests for amendments.

“I think we have to figure out as a group, how do we continue to honor the recommendation that … came out of the Launch Committee, ensure that whatever recommended amendments are something that our coalition can continue to live with,” Staks said.

Senate Bill 540, or the Pathways bill, is the product of the work of the Pathways Initiative, the nearly two-year effort to support the expansion of CAISO’s Western Energy Imbalance Market (WEIM) and soon-to-be-implemented Extended Day-Ahead Market (EDAM) to entities outside California by shifting governance of the markets from the ISO to a proposed independent RO.

Writing in opposition to the bill, Matthew Freedman, staff attorney for TURN, wrote that handing power over CAISO’s wholesale energy markets to an independent RO while opening the door to other market actors in the West “may expose California customers to new risks that could prove difficult to mitigate.”

In an email to RTO Insider, Freedman said: “Our goal is to ensure that the scope and role of Regional Organization is clearly defined in state law and that California has the right to withdraw under a variety of circumstances. We are extremely concerned about the potential for the federal government to make changes to the regional energy markets that would undermine California’s clean energy and decarbonization goals.”

The group asked for amendments to address the following points:

    • Ensure the RO’s tariffs permit California to withdraw utilities from the regional market without penalties or need for approval by FERC.
    • Clarify that the RO cannot set “any requirements relating to resource adequacy, reserve margins or reliability.” Additionally, the RO should not be allowed to rely on a centralized capacity market or separate markets for dispatchable, firm and intermittent resources. This is to prevent the federal government from intervening in wholesale markets to provide incentives for coal and gas generation.
    • Give the California Public Utilities Commission power to direct investor-owned utilities to withdraw from the RO if it violates any of the obligations under SB 540 or implements changes that could harm consumers.
    • Require utilities to withdraw from the RO if a court rules that California resource planning policies discriminate against out-of-state resources.
    • Similarly, utilities must withdraw if the federal government takes action that would lead to California consumers subsidizing fossil fuels.
    • Require utilities to withdraw “if a Joint Concurrent resolution is passed by the State Assembly and State Senate.”
    • Clarify that the Renewables Portfolio Standard “requirements relating to energy delivery from resources outside of a California Balancing Authority must satisfy strict standards including the use of dynamic scheduling, pseudo ties or firm transmission rights.”

Staks noted during the April 25 meeting that participation in the market is voluntary, and participants can withdraw “if something does not work for them.”

The Pathways bill passed California’s Senate Energy, Utilities and Communications Committee unanimously April 21. Though the committee voted in favor of the legislation, some lawmakers referenced TURN’s letter, saying they are concerned about whether the bill contains sufficient consumer protections. (See Calif. Senate Committee Backs Pathways Initiative Bill.)

The bill will go to the Senate Judiciary Committee for a hearing April 29. But TURN’s request for amendments will not be completed before then, according to Randy Howard, general manager of the Northern California Power Agency and Launch Committee member.

“We’re still working on dates to try to get the group together face to face,” Howard said during the meeting.

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APS to Keep Cholla Plant Closed Despite Trump Order Backing Coal

Arizona Public Service (APS) officials said they’re looking to a non-coal future for the recently closed Cholla coal-fired power plant, despite President Donald Trump’s calls to keep the facility running. 

APS discussed the Cholla power plant April 24 during a summer preparedness workshop hosted by the Arizona Corporation Commission. APS stopped running the Cholla plant on March 17. 

Jeff Allmon, associate general counsel with APS parent Pinnacle West Capital, said the utility started planning for the closure more than 10 years ago, when APS made a deal to keep the plant running until 2025 without “very expensive” pollution control equipment. Without the agreement, the pollution-control equipment would have been required by 2017 to comply with EPA’s regional haze regulations, Allmon said. 

To keep Cholla running long-term as a coal-fired plant, pollution controls now would be needed. 

“And those would be of a significant scale — selective catalytic reduction — which would come at a significant cost to our customers,” Allmon said. 

And because APS had been planning a “phasedown” of the facility, capital investments and deferred maintenance would be necessary for safe and reliable long-term operation, he added. 

Allmon said APS was preserving infrastructure at the plant, which is being eyed as a potential site for nuclear power. 

“[While] all options are on the table, including gas, the nuclear generation option is really the one that we think offers the most promise,” he said. 

After the workshop, ACC Chair Kevin Thompson and Vice Chair Nick Myers issued statements that highlighted the impacts to ratepayers of keeping the Cholla power plant running. 

“Trying to re-open Cholla at this point would result in significantly higher rates for customers,” Myers said. “The utilities have already been planning for this retirement, and replacement costs are already being borne by the utility customers.” 

“Bringing the Cholla plant into compliance with Obama-era EPA requirements will require the installation of costly scrubbers on the coal-fired units that would cost ratepayers hundreds of millions of dollars,” Thompson said. 

On April 8, Trump signed a series of executive orders aimed at keeping existing coal-fired power plants running, removing state laws that hinder the industry, and easing regulations and permitting for coal mining. (See Trump Seeks to Keep Coal Plants Open, Attacks State Climate Policies.) 

During a signing ceremony for the executive orders, Trump instructed Energy Secretary Chris Wright to save the Cholla coal plant in Arizona. 

Peak Load Record

APS hit a record peak load of 8,210 MW in 2024, a year in which Phoenix experienced a record-breaking heat wave. That followed a peak load of 8,162 MW in 2023, which was a record for APS at the time, according to Tim Rusert, APS’s director of power supply services. 

For 2025, APS is adding about 1,550 MW of solar-plus-storage or standalone storage through power purchase agreements, Rusert said during the ACC summer preparedness workshop. 

Rusert said APS will dispatch over 2,100 MW of battery storage this summer, compared to the 600 MW it had last year. 

“We’re confident in this battery storage because … we’ve had a lot of experience working with it,” Rusert said. “It’s a dependable resource. It’s quick reacting. With effective planning, it’s there when you need it.”  

Also during the ACC workshop, Tucson Electric Power (TEP) representatives said the company will retire units 1 and 2 at the coal-fired Springerville power plant in 2027 and 2032, respectively. TEP is exploring whether it can repurpose the Springerville plant for nuclear or gas generation.  

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Xcel ‘Optimistic’ It Will Handle Tariffs, Trade War

Xcel Energy CEO Bob Frenzel tried to reassure the investment community during the company’s first-quarter earnings call that it is better prepared for the trade war that may or may not be coming and the tariffs — not the ones utilities are accustomed to — that already have arrived. 

“The sentiment meter has definitely changed over the last 45 days, but I don’t think we’ve seen a lot of change in actual activity yet, either,” Frenzel told financial analysts during the April 24 call. “What you see here in this earnings season from a lot of people, whether it’s banks or industrial manufacturers … is a thoughtfulness around capital right now.” 

Frenzel said Xcel is “cautiously optimistic” it will work through the months ahead as it manages more than $10 billion in its incremental investment pipeline. He said the company has taken steps to diversify its vendors and materials, noting its $45 billion base capital plan has about a 2 to 3% exposure to tariffs. 

CFO Brian Van Abel said Xcel has been talking with its large oil and gas customers in the Permian Basin, where prices have been teetering at the point where the economics don’t make sense to drill. He said they are watching tariffs and their effects on companies. 

“But so far, we haven’t seen that impact on us,” Van Abel said. “One month doesn’t make a trend.” 

Xcel reported first-quarter earnings of $483 million ($0.84/share), compared to $488 million ($0.88/share) for the same quarter a year ago. The change was driven by higher operations and maintenance expenses and depreciation and interest charges, partly offset by increased recovery of infrastructure investments. 

The Minneapolis-based company’s earnings failed to meet the Zacks consensus estimate of $0.96/share.  

Frenzel made it clear that Xcel expects clean energy to be part of its fuel mix going forward. He said management sees a need for batteries and other energy storage assets, with a “relatively rapid evolution” of the battery supply chain similar to what it has seen with solar panels the past few years. At the same time, the company has been retiring a coal plant a year, he said. 

Xcel also has engaged with the Trump administration and federal lawmakers about the executive orders and tariff actions and the need for policies that allow cost-effective and rapid adoption of new energy resources, Franzel said. The key is preserving “tech-neutral tax credits” for wind, solar, storage and nuclear and the credits’ associated transferability provisions in various loan and grant programs.  

“Xcel Energy anticipates that we will need to deliver between [15,000] and 29,000 MW of new generation by year-end 2031,” he said. 

Still, Frenzel said Xcel “remains confident” in its ability to meet its earnings guidance for the 21st year in a row. “One of the best track records in the industry,” Frenzel said. 

Xcel’s share price closed the week on April 25 at $69. It has declined $2.55/share since the April 23 close, a drop of 3.6%. 

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MISO Debuting Flag System to Curb Deviations from Dispatch

MISO said it will debut a new flag system within weeks to give stronger signals to generation owners when their units deviate from their dispatch instructions. 

The flag, planned for rollout June 3 in MISO’s unit dispatch system, would let operators know when their resources appear to be disregarding the RTO’s dispatch instructions. Along with the flag, MISO plans to provide a reason code, detailing the reliability reason its five-minute setpoint instructions should be followed.  

In an April 22 question-and-answer session for stakeholders, MISO’s John Harmon said the new codes behind uninstructed deviations should bring “clarity and context” to resource operators.  

RTO staff said units not sticking to MISO instructions create balancing and frequency issues that sometimes require out-of-market actions in the control room. Staff have said that modeled flows in MISO’s dispatch system are diverging more and more from actual flows, resulting in system operating limit violations, balancing issues and frequency deviations. (See MISO: Flag, Penalties Needed to Address Generators’ Uninstructed Deviation.)  

Harmon said the flag would apply to all generation resources except energy storage. Historically, MISO and its Independent Market Monitor have said wind generation sources are among the worst offenders when they’re ordered to dispatch down. 

The new system requires MISO to make software changes to its unit dispatch system. In addition to the flag, the RTO eventually plans to levy penalties in market settlements for units that ignore dispatch instructions. 

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Texas PUC Approves 765-kV Transmission Option for Permian Basin

In what is being labeled a “landmark” and “historic” decision by the industry, the Texas Public Utility Commission approved a plan that allows ERCOT to authorize the region’s first extra-high-voltage transmission lines and meet the petroleum-rich Permian Basin’s rapidly growing power needs. 

The PUC on April 24 unanimously endorsed staff’s recommendation to build three 765-kV import paths into the Permian Basin, where oil and gas electrification and data center announcements have increased load projections significantly. The 765-kV option, while 22% more expensive than the 345-kV option, will carry more than twice the voltage of existing infrastructure. (See PUC Staff Urges Approval of 765-kV Lines to West Texas.) 

ERCOT and the transmission service providers (TSPs) have said the 765-kV lines can carry more power and meet higher demand levels as the state continues to grow. They can reduce congestion on existing transmission lines and could save money in the long term by eliminating the need to build additional lines. 

The TSPs have been preparing certificates of convenience and necessity applications for the projects approved in the plan. “Now that the voltage decision [has been] made, they can begin filing those applications to get the process started,” spokesperson Ellie Breed said in an email. 

“Our priority now is ensuring utilities execute these projects quickly and at the lowest possible cost to Texas consumers,” PUC Chair Thomas Gleeson said in a statement. 

Staff said the current options have increased to $10.11 billion for 765 kV and $8.28 billion for 345 kV. 

“This is really exciting for Texas, when you look back on monumental decisions that affect Texas,” Commissioner Kathleen Jackson said during the open meeting. “This will fit in those benchmarks, and we will look back and say this was one of those decisions.” 

The PUC’s decision came after a monthslong review process that included three public workshops and three rounds of stakeholder feedback. Commission staff conducted a full analysis of the costs, equipment supply chains and project-completion timelines for both voltage options, gathering input from the public, equipment manufacturers and the transmission companies that will build and operate the new lines. 

The commission’s order does not apply to ERCOT’s plans to add an EHV backbone to the rest of its system. The grid operator said it will work with the PUC and stakeholders to include the higher voltage in its study process. 

ERCOT included a 765-study as part of its annual Regional Transmission Plan (55718). (See 765-kV Lines in West Texas Inch Closer to Reality.) 

The Texas Advanced Energy Business Alliance (TAEBA) applauded the PUC’s decision, saying in an email the “historic vote” ushers in a “new era of grid modernization for the Lone Star State.” 

“This decision brings ERCOT into the 21st century,” TAEBA Executive Director Matthew Boms said. “As electricity demand surges, we need a grid that’s built for the future — reliable, efficient and cost-effective. Today’s vote is a strong step toward that goal.” 

American Electric Power trumpeted the fact that its Texas subsidiary will build one of the three import paths into the Permian Basin as part of a jointly assigned project. The 300-mile line will run from Fort Stockton to San Antonio. 

AEP energized its first 765-kV operational transmission line in 1969 between Kentucky and Ohio. It now owns 2,110 miles of 765-kV facilities, more than any other system in North America, it said. 

The commission also endorsed a petition approving assignments to the TSPs to own, construct and operate the Permian Basin projects (57441). 

“I want to further clarify the commission is not deciding in this proceeding any requirement for a TSP’s CCN,” Gleeson said. “Those will be decided in the future.” 

At the PUC’s direction, ERCOT filed its reliability plan for the Permian Basin in July 2024. The plan included the 345- and 765-kV import paths and a 2038 need date. The commission approved the plan in October 2024 but reserved a decision on the voltage level by May. (See Texas PUC Approves Permian Reliability Plan.) 

4 Projects Added to TEF

The PUC approved staff’s recommendation to advance four generation projects, totaling more than 1,900 MW of capacity, to the Texas Energy Fund’s due diligence review. 

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 (56896). (See 2 More Projects Fall out of TEF Loan Program.) 

The projects belong to independent power producers Invenergy and Nightpeak Energy. Invenergy proposed two projects totaling 1,369 MW of capacity, and Nightpeak has applied for loans to cover 565 MW. That raises the TEF In-ERCOT Program portfolio to 18 projects, promising 9,218 MW and requesting $5.04 billion in loans. Texas lawmakers have already set aside $5 billion for the program. 

“These are taxpayer dollars, and this is our program. We set the rules, and at the end of the day, you have to have the ability to repay, and you have to have the ability to execute,” Gleeson said. “Inherent in getting public funds is a trust from the public that they’ll be spent correctly, and I think our due diligence process is helping to ensure that.” 

The commission also approved the first recipient of the TEF’s Completion Bonus Grant Program, which awards grants to companies that add at least 100 MW to the ERCOT grid through new construction or by expanding dispatchable generators that meet the TEF’s requirements. 

The Lower Colorado River Authority is seeking $22.5 million in loans to help build the first of two 188-MW gas-fired units at its Timmerman Power Plant. The PUC can award LCRA a maximum of $120,000/MW (up to $22.5 million) if the unit connects to ERCOT before June 1, 2026. The facility will be tracked annually for 10 years and must meet specific performance and reliability measures and is available to ERCOT dispatch. 

The unit is scheduled to reach commercial operations in 2025. 

“It’s just good to see LCRA coming forward and taking advantage of this,” Jackson said. “It’s 10 years of oversight and performance, incentivizing them to be able to get the full grant.” 

Braunig RMR Work Delayed

ERCOT staff told the commission that a crack in Braunig Unit 3’s boiler superheater header will require that the header be replaced, “significantly extending” the unit’s potential return to service as late as spring 2026 (55999). 

CPS Energy found the crack during its maintenance outage, which began March 3 as part of the unit’s reliability must-run agreement with ERCOT. The San Antonio municipality announced in 2024 it would be retiring the 55-year-old gas unit along with Braunig’s other two units, but the Texas grid operator said it still was needed for reliability reasons. (See “RMR Contract for CPS Energy Unit Faces Increased Costs, Delays,” ERCOT Board of Directors Briefs: April 7-8, 2025.) 

David Kezell, ERCOT’s director of weatherization and inspection, said a new superheater will have to be built specifically for Braunig 3. Ideally, he said, the unit could be operational for the 2025/26 winter. The superheater is expected to cost about $3 million but is within the outage’s current $25 million budget, Kezell said.

“The budget is in reasonable shape,” he said.

ERCOT and the market already are on the hook for $45.85 million under the terms of Braunig 3’s RMR. 

Kristi Hobbs, vice president of system planning and weatherization, said ERCOT conducted another analysis to determine whether to proceed with the investment in Braunig. Staff updated their models with load growth and generation studies since their previous study and came to the same result. 

“We found that even with a delay, even if it’s delayed into February of next year, there is still more benefit than cost to moving forward with maintaining the Braunig unit,” Hobbs said. “We see the potential benefit really comes next summer in the July and August time frame … so we still see that benefit of moving forward with the work.” 

ERCOT counsel Nathan Bigbee told the PUC that ERCOT had reached an agreement with LifeCycle Power, which owns 15 mobile generators that it has leased to CenterPoint Energy, and is proceeding with plans to move the units to San Antonio over the summer. He said cooperation is needed between CenterPoint and CPS to “make this all work.” 

“Having a fundamental structure in place for ERCOT and the LifeCycle arrangement will help facilitate those agreements as well,” Bigbee said. “This is not like anything else we’ve had before. We are leveraging the RMR framework for the dispatch, the settlement and the performance metrics for these generators.” 

The generators, which can produce nearly 40 MW apiece, will be moved to San Antonio in groups of three. They then will be connected in strategic sites to the CPS distribution network. 

In other actions that the PUC crammed into just over an hour before adjourning, the commissioners: 

    • Sided with staff’s recommendation to delay the first procurement for the proposed firm fuel supply service (FFSS) until the 2026/27 winter season. The generation service is going through ERCOT’s stakeholder process; staff also were leery of “competing interests” coming out of the Texas Legislature, which ends in early June (56000).
    • Approved a joint application by CPS and South Texas Electric Cooperative for certificates of convenience and necessity for a proposed 345-kV project south of San Antonio. The PUC modified the proposed order by changing the project’s route, which is estimated to cost between $274 million and $390 million. The project is one of several that are part of the San Antonio South Reliability Project addressing a transmission constraint that led to the Braunig RMR. It will be built and owned 50/50 by CPS and STEC (57115).
    • Accepted CenterPoint’s request to recover more than $400 million in restoration costs from a series of storms in May 2024. The PUC approved $28.9 million in restoration costs and an additional $396.3 million in expenses to be securitized (57271). (See Texas Public Utility Commission Briefs: May 23, 2024.)
    • Agreed to AEP Texas’ $318 million, three-year system reliability plan that the company says will save about $71 million in projected restoration costs. About 80% of the plan involves replacing aging infrastructure with newer equipment designed to a higher standard that can better withstand extreme weather events, AEP said (57057).
    • Welcomed the city of Caldwell, between Houston and Austin, into the ERCOT system by approving an order integrating its 14 MW of load from MISO. The city reached an unopposed agreement with PUC staff, LCRA Transmission Services, Entergy Texas and the Office of Public Utility Counsel. ERCOT did not oppose the settlement (56164).
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Stakeholders, NERC Respond to FERC Large Loads Investigation

NERC joined a wide range of industry stakeholders responding to FERC’s investigation of co-located large loads and their effect on grid reliability and costs for customers, while other stakeholders provided feedback on PJM’s suggested approaches to co-location (EL25-49, AD24-11).

FERC launched the inquiry in February after rejecting an agreement the previous November between Amazon Web Services and Talen Energy to expand a data center co-located with the Susquehanna nuclear plant in Pennsylvania by modifying the generator’s interconnection service agreement to reduce its output to PJM. (See FERC Launches Rulemaking on Thorny Issues Involving Data Center Co-location.)

Along with ordering PJM and its transmission owners to determine whether the RTO’s tariff needed updates to accommodate the arrangements, the commission also sought comments on the larger issues. FERC is concerned the arrangements could be developed in a way that is not fair for other customers, and that co-location could cause issues for reliability and resource adequacy similar to an event in July 2024 in which a transmission line fault in Virginia led to 1,500 MW of load reduction, all from data centers. (See NERC Report Highlights Data Center Load Loss Issues.)

In its comments, NERC highlighted the ERO’s efforts to address the reliability challenges of co-located large loads. The organization cited its report on the 2024 event as well as its creation of the Large Loads Task Force (LLTF) in August 2024. Reporting to the Reliability and Security Technical Committee, the LLTF has a goal of creating two research papers and one reliability guideline before June 2026 on the identification and mitigation of risks, along with guidance for “improvements in modeling, analyses, coordination and data collection, real-time monitoring and event analysis.”

Discussing the recent testimony of NERC Chief Engineer Mark Lauby at FERC’s April open meeting, where topics included the 2024 incident as well as similar events in Virginia and Texas, NERC observed that co-located large loads may provide benefits to reliability as well as risks. The presentation was attached to NERC’s filing as an appendix.

“Proximity between large loads and power generation sources can reduce energy loss while improving transmission reliability [and fostering] improved coordination, leading to better load management and reduced strain on the” grid, NERC said. “Grid stability may also be enhanced if the proximity created flexibility to adjust demand during critical conditions.”

The ERO’s filing also mentioned the risks posed by co-location, such as the possibility that system operators may not have visibility into a co-located large load, leaving them unable to perform reliability analysis. This could lead to “risk of thermal overloads and voltage or stability issues.” Large loads can also experience fluctuations during faults or switching that operators may not be able to anticipate.

NERC noted that its Board of Trustees solicited input from the Member Representatives Committee and industry stakeholders ahead of a panel on large loads at its February meeting. In response to the panel discussion and input, the board directed NERC to develop an action plan to identify and address the risks of large loads. This action plan will be due at the board’s next meeting May 8.

Other respondents shared NERC’s reliability concerns. Consumers’ Research, a nonprofit consumer advocacy group, cited NERC’s 2025 Long-Term Reliability Assessment, which said many parts of North America could face resource adequacy challenges in the next 10 years, along with FERC Chair Mark Christie’s warnings that “America is facing a reliability crisis driven by the dangerous pace of retirements of dispatchable generation units.”

The group urged FERC to ensure that co-location is accomplished without exaggerating these reliability issues. Measures to achieve this goal could include requiring the parties involved to maintain a reserve capacity of dispatchable power for ratepayers, and that they “have no targets or commitments for net zero or any related low-carbon goals.” CR said such commitments “harm consumers by artificially weakening the market for dispatchable power.”

A joint comment by Suzanne Glatz of Glatz Energy Consulting and Abraham Silverman, a research scholar at Johns Hopkins University, referred to NERC’s 2023 Reliability Risk Priorities Report, which warned that “new loads,” including data centers, cryptocurrency mining and artificial intelligence, “can emerge and grow faster than generation and transmission can be built.” They suggested FERC “strongly consider a co-location ‘safety valve’ that ensures that co-location does not drive PJM into shortage conditions.”

Modifications Suggested to PJM’s Approaches

PJM filed its initial response to FERC’s investigation in March, laying out three approaches to co-locating load already permissible under the RTO’s tariff and outlining five more that could be developed under more possible configurations or limitations imposed by state laws.

Multiple stakeholders responded to PJM’s comments with their own takes on the RTO’s plans, or on the theme of co-location in general. The Data Center Coalition commented that co-located load configurations can allow large consumers to avoid long interconnection delays by not relying on congested transmission infrastructure. It argued that many of the issues raised around co-location are more related to tightening capacity supply and demand.

“Co-location can reduce transmission congestion, avoid costly infrastructure buildouts and enable the more efficient interconnection of new resources. But amid tightening margins, it has become a stand-in for deeper anxiety about supply adequacy and planning accuracy,” the coalition wrote.

It requested the commission initiate settlement judge proceedings to allow for more thorough discussions and stay the investigation for 90 days. It also recommended PJM make several changes to its load forecasting, including verifying the commercial readiness of large load additions and increasing transparency to ensure that such additions do not create reliability issues.

Constellation Energy argued that requiring data centers to be classified as network load in front of generators’ meters has led to interconnections taking years to complete and has exposed data centers to moratoriums on new load interconnections, as seen in Ohio. While many consumers will prefer the reliability offered by PJM in exchange for being subject to transmission charges, the company said many are willing to forgo the reliability of full grid service in exchange for speedier interconnection.

In some cases, Constellation said, those customers might be willing to accept backup service from the grid once network upgrades have been completed.

Responding to several paradigms PJM laid out for the commission to explore in the RTO’s comments, Constellation said it is opposed to the “bring your own generation” route, which would prioritize generation interconnections part of a co-located load configuration. The company argued that would discriminate against existing generation and undermine capacity market incentives.

Under options in which the load is behind the generator’s meter, Constellation said it may be appropriate for it to pay some ancillary services, such as regulation and black start, but subjecting the load to network integration transmission service charges would require it to use services it would not otherwise. (See PJM Responds to FERC Co-located Load Investigation.)

The company asked the commission to either accept modified variants of the co-located options proposed by PJM or initiate a time-limited settlement judge proceeding to consider alternatives.

PJM stressed in its March filing that while the options it presented are routes the commission could explore, it does not view them all as equal or feasible. It was particularly skeptical of two configurations exempting co-located load from transmission charges when protective mechanisms have been installed to prevent the load from receiving energy from the grid. Such mechanisms could fail, the RTO wrote, and the load nonetheless would continue to consume ancillary services, such as regulation.

Echoing the Data Center Coalition, Constellation said co-located load is being blamed for broader issues with PJM’s capacity market and generation interconnection process. It said the RTO’s Reliability Resource Initiative bolsters resource adequacy by adding 50 projects to the next queue cycle that can bring capacity to market quickly, and further improvements can be made to the interconnection study process.

“The commission should determine whether there are additional tools to address near-term capacity needs while reinforcing PJM’s capacity market, which is already sending strong signals for new entry (or for delaying retirement of existing resources),” it wrote.

Constellation encouraged the commission to establish a flexible set of rules for developers to follow when pursuing co-located configurations, saying there are many ways that load and generation can be combined.

“Allowing load to select a configuration that best serves its needs will enhance national security and national economic competitiveness by speeding connection for those new customers who need to connect quickly and will save existing customers money by minimizing system upgrades,” the company wrote.

Generation developer BrightNight said the commission should establish a pro forma agreement and process for co-located configurations that allows flexibility for the three configurations that may be pursued: fully islanded generation and load; flexible load or demand response; and load that may rely on the grid for backup service when on-site generation is unavailable.

“Data center developers, generation developers and system planners cannot make long-term decisions without understanding what co-location arrangements the commission will accept,” BrightNight wrote. “Standardizing procedures and agreements would give developers and planners certainty, reduce opportunities for undue discrimination or preference, reduce disputes and, hopefully, expedite the development of data centers and needed generation.”

Public Interest Organizations Warn of Consumer Costs

Several public interest organizations jointly argued that certain co-location configurations could push network upgrade costs to consumers and cause reliability issues if they fall through cracks in PJM’s load forecasting.

The comments were signed by Appalachian Voices, Clean Air Task Force, Earthjustice, the Environmental Defense Fund, PennFuture and the Sierra Club.

They wrote that the three processes PJM uses to identify transmission violations prompted by co-located configurations — necessary studies, TO load integration studies and the Regional Transmission Expansion Plan — fail to take a holistic look at projects’ impacts. The necessary studies exclusively look at changes to the generator’s interconnection service agreement, while the latter two assign any identified upgrades to network load.

They also highlighted that PJM has not allowed batteries to go through the necessary studies process because the charging cycle can act like load, but the RTO has proposed to apply it to co-located configurations.

The organizations wrote that accelerated data center load is expected to cause wholesale costs to rise significantly, and co-located load configurations sought by developers would further shift costs to consumers. They also argued it could create opportunities for generators to engage in market power manipulation by withholding capacity from PJM to supply co-located load.

“The commission cannot ignore the current realities in PJM: already sky-high capacity prices, as well as an extremely backlogged interconnection queue, supply chain issues for new resources (both generation and transmission) and limited available transmission capacity that further drives up the cost of interconnection,” they wrote.

“Each of these conditions makes new entry challenging, and if left unaddressed, very expensive. Allowing the key drivers of the tight supply margins — large load customers — to avoid and exacerbate these challenges and associated costs by sequestering access to existing generation would be a cost shift of extreme magnitude.”

TOs, cooperatives and municipal providers opposed changes to PJM’s tariff, jointly commenting that existing processes may not be preferable for co-located configurations, but they are not discriminatory or unjust and unreasonable and therefore changes cannot be compelled by FERC using a Federal Power Act Section 206 investigation. The comments were submitted by Exelon; American Electric Power; the city of Hamilton, Ohio; Southern Maryland Electric Cooperative; Duke Energy; and Dominion Energy, among others.

“Those end-use load connection processes, governed by the states and fully consistent with the PJM tariff, are available to all, and those processes work. Moreover, the transmission service provided to co-located load under the PJM tariff is available to all on a non-discriminatory basis,” they wrote. “Nowhere in the record is there an allegation —let alone evidence — that the current PJM tariff impedes the development of or service to any load, co-located or otherwise.”

They also argued that co-located configurations should be prohibited from being classified as behind-the-meter generation, citing PJM’s statements that the ruleset was designed for smaller configurations and the load would not be properly measured by the RTO, even though it uses the transmission system.

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Gas Soars, Wind Slumps for GE Vernova

GE Vernova’s gas turbine sales pipeline grew 39% and its onshore wind orders dropped 42% in the first quarter of 2025 amid sweeping changes in the U.S. energy landscape. 

The company reported solid financials April 23 and provided details on its business segments. 

Natural gas again was a focus as CEO Scott Strazik spoke to financial analysts on a conference call. 

In the first quarter, GE Vernova booked 7 GW of orders and 7 GW of slot reservations that are expected to convert to orders, bringing the total gas turbine pipeline to 50 GW. 

Strazik said GE Vernova expects to ship 10 GW worth of gas turbines and take orders for 20 GW through the remainder of 2025, ending the year with a 60-GW backlog that will book up production capacity through 2028. 

Already, the company is signing agreements for gas turbines to be delivered in 2029, setting the stage for infrastructure investments that will shape the power sector for decades. 

A day after the earnings report, GE Vernova and Duke Energy announced agreement on a purchase of up to 11 of GE Vernova’s 7HA gas turbines — in addition to the eight recently secured. 

Meanwhile, the company continues to wind down its exposure to offshore wind, fulfilling its two remaining commitments — turbines for the Dogger Bank and Vineyard Wind projects — and recording a $70 million loss on termination of the last of the supply agreements for the 18-GW offshore turbine it decided not to bring to market. 

The company’s wind sector reported a net loss. Individually, onshore wind delivered its fifth straight profitable quarter. New orders were 43% lower than in the first quarter of 2024, however. 

“We remain cautious on the timing of an onshore order inflection in North America as customers continue to navigate growing interconnection queues, policy uncertainty and higher interest rates,” CFO Ken Parks said. 

The numbers reported April 23 reflect the rapid and sizable shift in energy priorities that came with the transition from President Biden to President Trump. 

“I continue to see this market normalizing to a higher-for-longer gas market,” Strazik said. “The world needs more dispatchable power generation to support economic growth and national security. Gas power will provide a significant amount of the incremental dispatchable power while also being the force multiplier for more renewables where wind and solar resources make sense.” 

Strazik drilled down a bit on the 50 GW of turbine orders and slot reservations: About 60% of them are from the United States, but the more recent ones are more heavily in the United States and more heavily associated with data centers. 

He said the 29 GW backlog is firm but there was more chance of fluctuation within the 21 GW of slot reservations, despite the large deposits that accompany them. “I see very little quote, unquote, cancellation risk, but there will be some movement that our supply chain will have to be nimble with, as the slot reservation agreements turn to orders and final dates get finalized.” 

An analyst asked for further insight about onshore wind, historically a strong U.S. market for corporate predecessor General Electric. 

Strazik said GE Vernova is highly confident in securing market share when onshore wind begins to rebound, but does not know when that inflection point will come, and when the 200 GW-plus of U.S. onshore wind projects in early stage development start to move forward. 

“We continue to see there be an important role for wind to play, but we need to see progress on permitting,” he said. “I think there is a real question on the price embedded in those projects that are in the interconnect queue. Where are the tax incentives going? I think clarity on permitting process today and ultimately incentives [is] going to be important in … those projects getting to closure.” 

GE Vernova projected solid financial performance for 2025 but acknowledged the moving pieces that could impact its bottom line. 

“While our end markets remain strong, we are not immune to the complexity of play, given the current outline of tariffs and resulting inflation,” Strazik said. “We do expect our cost to go up $300 [million] to $400 million in 2025.” 

GE Vernova reported net income of $264 million, or $0.91 per share, on total revenue of $8.03 billion for the first quarter of 2025, compared with a net loss of $106 million or $0.47 per share, on revenue of $7.26 billion in the same quarter of 2024. 

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Firm Fuel Proposal Continues to Confuse NYISO Stakeholders

NYISO returned to the Installed Capacity Working Group with more modifications to the tariff language and general structure of its firm fuel capacity accreditation proposal, though based on the conversation at the meeting April 21, stakeholders are still skeptical of it.

The ISO made the changes in response to the criticism it received from stakeholders, including the Market Monitoring Unit. (See NYISO’s Firm Fuel Proposal Criticized.)

But stakeholders peppered staff with hypothetical questions about how penalties and FERC referrals would be triggered and when. There were several times throughout the meeting that attendees asked for others to slow down so that they could follow their line of questioning.

The firm fuel capacity accreditation project is an effort to incentivize generators to secure firm fuel contracts with their suppliers before winter, when the ISO and the New York State Reliability Council are worried about fuel shortages.

Generators wishing to elect as firm would commit to being able to run for 56 hours over any consecutive seven-day period in December through February. They would declare Aug. 1 of the prior capability year that they are opting to be firm. Failure to perform because of lack of fuel would result in a financial sanction. (See NYISO Business Issues Committee OKs Firm Fuel Accreditation Concept.)

Nikolai Tubbs, associate market design specialist for NYISO, explained the adjustments to the structure of the penalties, while Zachary Smith, senior manager of capacity and new resource integration market solutions, fielded questions from stakeholders.

For any given “winter performance month,” the financial sanction would be assessed at a 1.5 multiplier if the reason for failure was within the generator’s control. Generators would lose their firm fuel accreditation (i.e., adjusted down to non-firm) via the “settlement adjustment modifier” if failures occurred outside of the generator’s control, or if the generator failed to have an operating plan or fuel contract in place for the whole month.

Generators would be required to notify NYISO by Dec. 1 if they were unable to secure firm fuel contracts. If something goes wrong during the winter, such as a fuel contract getting canceled, the generator is also obligated to inform the ISO. This reverts their status to “non-firm” by applying the settlement adjustment modifier.

If NYISO learned that a generator failed to provide the required notice, the generator would be subject to the sanction with the 1.5 modifier and be referred to FERC. The ISO would also report to FERC if a generator supplied operating plans or fuel contracts that were “false or misleading.”

In response to a question about what would happen if a generator had no contracts by Dec. 1 but did for January and February, Smith said that it would get the settlement adjustment (be compensated as non-firm) for all three months.

“There’s no ability to cure,” Smith said. “You potentially have the worse multiplier if you also fail to perform. If you have the contracts in place for December and January, but they are not in place for February, only February gets the settlement adjustment absent any of the other failures to perform.”

Doreen Saia, a stakeholder representing generator interests, said that this implied that a failure in December would cause a settlement adjustment no matter what, but a generator might want to have contracts in place because if it didn’t, it would get hit with the worse financial sanction if it failed to perform.

“I think part of the problem is that this has been through so many iterations at this point that it would be a small miracle if the tariff said anything cogently or coherently,” Saia said.

The conversation turned toward hashing out when NYISO would refer a generator to FERC. Smith explained that after a failure to perform, the ISO had the ability to ask to review a generator’s contracts and plans, but that it might not always do so.

“If the entire gas system went out, I don’t think we’d need to get to reviewing your contracts,” Smith said as an example. “At that point it clearly didn’t matter what your contract said.”

But in other cases, Smith said NYISO would need to open an investigation into whether the failure to perform was in the generator’s control. Even in the case of an investigation, Smith would not state that the ISO would need to review contracts or plans in all cases. The ISO was reserving the right to look into plans and contracts in the event of a failure to perform.

“The NYISO is not making a judgment call on anyone’s plans, to whether or not they should have a penalty apply, absent a failure to perform,” Smith said. After some further discussion, Smith said NYISO did not want to be in the position of approving people’s operating plans; it just wanted to audit plans if there was a concern.

“There’s a lot of ‘ifs’ and ‘thens’ here,” one stakeholder said at one point during the meeting. “Might I suggest you put this into a flow chart?”