Search
December 16, 2025

Posted on

Neb., Miss. Utilities to Pay $186K in Penalties

Utilities in the territories of the Midwest Reliability Organization and SERC Reliability will pay a total of $186,000 in penalties to the regional entities for violations of NERC’s reliability standards under two settlements approved by FERC.

NERC filed the settlements on July 31, along with an additional settlement for infringement of the ERO’s critical infrastructure protection (CIP) standards whose details were not made public in accordance with NERC and FERC’s policy on CIP violations. The commission said in an Aug. 29 filing that it would not further review the settlements, leaving the penalties intact.

MRO’s settlement involves the Grande Prairie Wind Farm (GPW), a 400-MW facility in Holt County, Neb., owned by Berkshire Hathaway Energy subsidiary BHE Renewables (NP25-14). Power generated at the wind farm is sold to Omaha Public Power District under a long-term power purchase agreement.

According to the settlement agreement, GPW notified MRO in a quarterly report on July 17, 2023, that it was in violation of FAC-003-4 (Transmission vegetation management) in its capacity as a generator owner. The utility had experienced a C-phase to ground fault on a 345-kV generation tie-line between the wind farm and a facility owned by another entity. The fault caused the main generator supply breaker at GPW, as well as two breakers at the other entity’s facility, to trip open, which cleared the fault on the tie-line.

GPW investigated the cause and discovered “a tree that demonstrated damage from contacting the overhead C-phase line.” The utility cut back the tree and other plants nearby, visually inspected the rest of the line, and returned it to service.

MRO attributed the violation to a lack of adequate controls to prevent encroachments into the minimum vegetation clearance distance of the tie-line that could cause a sustained outage, as required by requirement R2.4 of FAC-003-4. The RE assessed the risk as moderate because, while the vegetation encroachment caused a sustained outage and exposed the 345-kV transmission system to a fault, the facility is not a networked transmission facility or black start resource, so a trip “would not have a significant impact on the” electric grid.

After removing the tree and other encroaching plants, GPW’s additional mitigation actions include increasing the frequency of vegetation inspection at the wind farm to at least twice a year, with the 15-foot MVCD to be documented with photographs. The GO also updated its FAC-003 program to reflect the new inspection schedule and conducted training on the standard.

Mississippi Power Discovers Rating Mishap

In the other settlement approved by FERC, Southern Co. subsidiary Mississippi Power agreed to pay $86,000 to SERC (NP25-15). The penalty stemmed from violations of FAC-008-5 (Facility ratings) and its predecessor FAC-009-1 (Establish and communicate facility ratings) reported to the RE on June 3, 2022.

According to NERC’s monthly spreadsheet notice of penalty, where the settlement was filed, Mississippi Power discovered a discrepancy on Jan. 4, 2022, between its records of equipment installed at a 230-kV substation and those found in the field. The utility was examining the facility in response to a data request from SERC in advance of an on-site audit.

Mississippi Power’s drawings and database for the substation indicated the 230-kV line should be equipped with bundled aluminum conductor steel-reinforced (ACSR) cable jumpers rated at 2,808 amps, with the most limiting element (MLE) being the ACSR conductor, rated at 1,512 amps. However, the field verification found that one set of jumpers actually was single all-aluminum conductor (AAC) jumpers rated at 1,496 amps. This meant that the AAC jumpers should have been identified as the MLE, and therefore the facility rating was incorrect.

After discovering this issue and derating the facility, Mississippi Power conducted walkdowns of all 108 transmission substations, 106 of which were completed by March 31. During this time, Southern began a system-wide initiative to implement a common transmission facility ratings database across all operating companies. This involved a quality assurance review by each company of the data for the new database.

Because of the walkdowns and QA assessment, Mississippi Power found 15 total instances where incorrect element ratings resulted in an incorrect MLE, leading to incorrect facility ratings at eight different 115-kV and 230-kV stations. The misratings required derates of up to 44%. None of the stations were found to have operated above the correct ratings.

The utility also discovered 239 instances of incorrect element ratings on 115-kV, 230-kV and 500-kV facilities that did not impact the MLE or facility rating. Mississippi Power has committed to finishing the remaining walkdowns by Dec. 31.

SERC said the cause of the infringement was “inadequate change management controls and legacy equipment identification controls.” The violation began on June 18, 2007, when FAC-009-1 became enforceable, and should end Dec. 31, when the utility has completed the walkdowns and updated all incorrect equipment and facility ratings.

Posted on

Results Elusive in N.Y. Build-Ready Renewables Program

A state with plenty of brownfields and lots of ambition for clean energy is having trouble bringing the two together.

New York’s Build-Ready program was launched in October 2020 to develop a roster of turn-key plans that would place renewable generation on sites such as landfills, abandoned industrial sites and dormant electric-generating facilities.

More than four years of effort by state personnel at a cost of $15.5 million identified 480 potential sites for such projects through June 30. But for assorted reasons, all 480 were found to be unworkable.

The one success so far was the auction of a 12-MW solar project on a tailings pile at a defunct iron mine, and even that had to be scaled back from 20 MW to avoid the need for expensive grid upgrades. (See NY Sells First Build-Ready Site for Renewables.)

Requests for proposals are out for three more solar projects totaling 15 MW — two on a former municipal landfill and one adjacent to the infamous Love Canal toxic waste cleanup site.

The New York State Energy Research and Development Authority offered the details about Build-Ready in an annual progress report submitted to the Public Service Commission on Aug. 28.

NYSERDA told NetZero Insider that Build-Ready is an inherently challenging prospect — preparing what may be a blighted location for a clean energy system that private developers would not build on their own due to cost and risk.

“The fact that the Build-Ready program screened 480 sites shows the due diligence needed to find the right site for a successful project,” a spokesperson said.

NYSERDA said, however, that its upcoming five-year report will provide a more complete overview of the program and offer recommendations for moving it forward. That report is due Oct. 1.

Build-Ready began as part of the Accelerated Renewable Energy Growth and Community Benefit Act of April 2020.

In October 2020, it became one of the many initiatives launched from the wide-ranging proceeding the PSC initiated in 2015 to implement a large-scale renewable program and a clean energy standard (Case 15-E-0302).

Build-Ready calls for NYSERDA to look for potentially suitable sites; assess their suitability; secure rights to the site; evaluate environmental needs and interconnection options for a renewable generation project; design a project; seek necessary permits; and then offer the package to the private sector in a competitive sale, bundled with a long-term contract for renewable energy certificates.

Each of these steps can take months or years on their own — the final package is about as close to “build-ready” as one could hope for.

But the process has reached completion exactly once so far, at the defunct iron mine in a remote wilderness area; $56.3 million of the $71.8 million allocated to Build-Ready remains unspent.

The 480 rejections break down to:

    • 166 for insufficient buildable land area;
    • 91 for lack of landowner cooperation;
    • 64 because interconnection options were not viable;
    • 51 due to agriculture activity, which since 2024 has been ranked as a higher priority than Build-Ready;
    • 46 because of commercial development potential, also a higher priority;
    • 40 to avoid competition with a potential private-sector renewable developer; and
    • 22 due to wetlands or other significant environmental constraints on site.

NYSERDA’s report goes into detail on several of the sites that reached advanced stages of review — four landfills, an airport and a huge post-industrial scar sprawling from the city of Utica into a neighboring town.

One by one, they all got crossed off the list.

The Utica site stands out as a lost chance to repurpose a site with a tortured history.

Thousands once worked there, cranking out guns and later computer parts in one of the massive brick-and-concrete industrial complexes that once dotted upstate New York. The factory died, was reborn as a retail outlet complex, lost its luster, was converted to a mixed-use office and commercial facility, died again, was partly demolished and partly left to rot, was gutted in a massive fire, stood as a skeleton for two years, then finally was demolished in 2022 by the EPA, which removed nearly 30,000 tons of debris, asbestos and drums of hazardous substances.

Build-Ready would have placed batteries on the concrete foundations left on site, and there would be few residents in the surrounding industrial zone to be worried about them.

But during its assessment, NYSERDA determined that the amount of site preparation and electrical upgrades that would be needed for a 20-MW standalone BESS — including a three-breaker ring bus — would be so expensive as to make the project unviable.

There is no mention in the report of another factor that may make future projects unviable: President Donald Trump and his Republican allies in Congress.

Posted on

Power Play: Political Intermittency is Now the Biggest Threat to the Grid

When a government’s word is no longer its bond, investors get nervous, and investors in clean energy generation plants in the United States are very nervous indeed. For good reason: The administration is threatening wind and solar generation projects with tactics ranging from revoking permits to trimming tax credits to reneging on grants.  

Capriciousness is the Market’s Kryptonite

Project developers are, by nature and necessity, risk averse. There’s no reward if a project gets derailed by a desert tortoise after years of planning, permitting and perfecting the capital stack to fund its construction. But how can the industry do due diligence when a political wild card can be dealt at the last minute? 

A recent example, where the Bureau of Ocean Energy Management halted the Revolution Wind offshore project for belated and questionable “national security concerns,” is the wildest wild card yet. After all, if this can happen to an 80% complete project that underwent more than a decade of studies and hearings to obtain permission, no project seems safe.  

political grid

Dej Knuckey

As Nancy Sopko, vice president of external affairs for a U.S. Wind project off the coast of Delaware, another project under threat, said, the permits the administration is threatening to revoke for that project were “secured after a multi-year and rigorous public review process” and were legally sound. But a drawn-out legal battle, even if the project team prevails, is just another cost that will make a project difficult to pencil out. 

The market is becoming increasingly cautious about investing in clean energy generation and is re-evaluating projects already in the planning stage. Already, the pipeline of generation projects is pre-emptively narrowing as investors and developers seek safer shores. 

Putting aside the why of the political agenda, it’s essential to ask how this will impact electricity supply in a time of rising demand. The grid may face capacity and reliability challenges if clean energy generation projects are shelved, whether voluntarily or otherwise.  

AI, Data and the Demand Crystal Ball

In a steady state, cancellation or delay of major projects would be problematic, but unlikely to lead to shortages. However, in the past two years, the rise of AI and the related proliferation of data centers have sent energy analysts scrambling to rework demand projections. 

In early 2023, consulting firm ICF International projected a 1.3% annual growth rate through 2030. Two years later, it more than doubled the projected growth rate to 3.2%. And thanks to the joy of compounding, those small annual increases result in 25% growth in U.S. electricity demand by 2030 and 78% by 2050, compared to 2023 levels.  

Peak load growth projections also have been revised upward; however, with data centers’ “always-on” load profile, the result is a more feasible 14% by 2030 and 54% by 2050. While data centers providing cloud computing and AI account for most of the growth in demand, it also is coming from a rise in manufacturing, cryptocurrency mining and building electrification. 

One trend that may offset some of the increase in demand is the administration’s shift away from electrifying transportation, which still may grow, but at a lower rate than previously predicted. Other actions seem performative: For example, the move to eliminate or privatize the Energy Star program is not going to lead white goods manufacturers to flood the market with less efficient appliances. 

Reliability on the Rails

To ensure a reliable supply during peak demand, utilities and grid operators strive for a reserve margin of at least 15%. While today there’s a larger reserve margin, ICF warns, “mapping demand growth estimates against generating capacity online today, including the impact of firm builds and retirements, shows that much of the U.S. will experience below-target reserve margins as soon as 2030.” 

political grid

U.S. regional electricity demand growth and peak demand growth (2025-2035) | ICF

These analysts, however, use the phrase “firm builds and retirements,” but planning is being done now in an environment where many “firm builds” have been demoted to “likely build unless the technologies being targeted by the administration.”

If there’s continued proactive withdrawal by developers, the reliability risk may grow. It will vary by region, but in New England, the offshore wind farm that now is in suspended animation was critical to manage winter power costs, Jon Lamson reported this week. In other regions, the peak summer load is a bigger worry, as longer and hotter heat waves drive up the cooling load. 

The question of whether this changed environment will be able to supply enough electricity with acceptable reliability isn’t really about the newsworthy disruptions to offshore wind and the ability for other renewables to survive without tax credits; it’s about the ripple effect. Will the pipeline of planned clean energy projects dry up further, and what will fill the void? 

Project Finance is Self-deporting

There are echoes of the administration’s immigration policies in the project development world: Make the development environment untenable and the developers will halt their projects without the Interior Department ever issuing a stop-work order. Until those behind a project are sure that their hard-won approvals will be honored, preemptive withdrawal is an increasingly prudent option.   

Given the choice between investing time and money in a project that the political rug could be pulled out from under it before it’s ever commissioned or putting the project on ice today, some renewables developers and investors are choosing the latter. 

BloombergNEF reports “the U.S. saw the greatest drop in new renewable energy investment in 1H 2025, with committed spending down $20.5 billion (36%) from the second half of 2024.” Some of the drop is attributable to the artificial bump caused by the rush to start projects before the end of 2024 to lock in tax credits. Still, worsening policy conditions also contributed to it. 

The capital is, in essence, self-deporting, and the E.U. is the beneficiary, with an uptick in the number of low-carbon generation projects in its development pipeline. The EU-27 saw a 63% rise in investment in the first half of 2025 compared to the last half of 2024. 

“These numbers support the idea that companies are reallocating capital out of the U.S. and into Europe — particularly in offshore wind, where several developers refocused to North Sea sites over U.S. projects,” BloombergNEF said. 

One Foot on the Gas, the Other on the Brakes

It’s not all bad news for capacity: Fossil fuel generation, primarily gas, is benefiting from the administration’s focus. Global Energy Monitor’s tracker shows almost 100 GW of capacity in preconstruction, up from 15 GW a year earlier. The focus on fossil fuel-powered generation puts the United States at odds with its OECD counterparts. Close to 40% of pre-construction projects in the U.S. now are fossil, compared with less than 6% in the balance of the OECD countries. 

A rush to build new fossil capacity won’t add to capacity or reliability if the projects can’t come online rapidly, and these newly planned plants are just beginning to navigate the yearslong interconnection queues. It’s no wonder that data center giants want to skip the grid altogether by building dedicated capacity and energy storage. 

Even those projects, however, face a literal pipeline problem unless there is an existing gas supply they can tap into. And if their pipeline crosses state borders, FERC gets involved. “Currently, depending on size and jurisdiction, a pipeline project could take anywhere from eight months to five years,” Norton Rose Fulbright said. “The federal government has been working on natural gas pipeline permitting reform that would allow pipeline projects to be built more expeditiously.”  

Similarly, some fossil plants that were scheduled to close are receiving a stay of execution, such as the emergency order from the U.S. Department of Energy to keep two units of the Eddystone Generating Station in Pennsylvania in operation. (See related story: Eddystone Ordered to Remain Operational for PJM 90 More Days.) The surge in fossil projects may offset some of the decline in renewables. However, even if you assume hydro and geothermal are left alone, there’s still a significant portion of planned new generation capacity at risk.  

Of the 57 GW of power capacity under construction in North America in August, 23 GW is solar, and 17 GW is wind, according to Global Energy Monitor, meaning more than two-thirds of all power capacity under construction may be at risk. And of the 253 GW in pre-construction? Even after the sharp uptick in fossil plants in pre-construction, utility-scale solar and wind account for 114 GW, or 45%, of capacity in pre-construction. 

The critical question is how much of that pre-construction and construction is one revoked permit away from being halted. Some developers — or the project financiers that enable them to exist — aren’t waiting around to find out.  

What Do We Want? Clarity! When Do We Want It? Now!

The sooner clear and consistent policies are communicated, the faster the markets can start to rebuild trust. If the administration’s goal is to prevent all offshore wind projects and allow onshore wind and solar projects to flourish and grow as long as they can pencil out without tax credits, say so.  

Investors already fear the worst, and moving to more stable markets but knowing how profound these market shocks will be and how long they will last will enable everyone — developers, investors, utilities, grid operators and regulators—to get back to working out how to build the capacity and reliability electric consumers will need in the coming decades. 

Power Play Columnist Dej Knuckey is a climate and energy writer with decades of industry experience. 

Posted on

CPUC OKs Large Increase to PG&E Energization Cost Cap

The California Public Utilities Commission approved a plan to increase Pacific Gas and Electric’s cost cap for customer energization projects in 2025 and 2026 by more than $1.5 billion, despite acknowledging the utility did not provide data to support its forecast growth in energization applications during those years. 

The increased cap amounts are mountainous: PG&E can seek to recover costs for up to about $1.1 billion in 2025 and $1.7 billion in 2026 for certain customer energization projects, according to the decision. In a 2024 decision, the CPUC approved cost caps of about $619 million in 2025 and $669 million in 2026 for these types of projects. 

Increasing the cost caps will allow PG&E to “complete additional energization work in 2025 if it is able to accelerate its energization activity or in 2026 if activities are delayed,” the CPUC said in the approved decision. 

“We all know that load growth today is looking very different than just a few years ago,” CPUC President Alice Reynolds said during the Aug. 28 voting meeting. “Utilities are receiving more energization requests that require substantial electricity capacity. These requests are coming from industries central to California’s electrification goals — EV charging infrastructure, high-tech campuses.” 

The scale and speed of these projects is “leading to the need for significant upgrades and on timelines the utilities have not historically had to meet, leading to delays and backlogs,” Reynolds said. 

Commissioner Darcie Houck voted “no” on the proposal, questioning whether the decision gives “sufficient consideration to affordability concerns,” specifically because it omits estimated bill impacts. 

“This is a difficult case and requires balancing of critically important issues,” Houck said. “When considering just and reasonable rates, we as economic regulators must balance many factors, including affordability.” 

“The proposed decision states that it cannot estimate the proposed bill impact due to not being able to calculate potential [electricity] sales,” Houck said. “However, this … has not been a barrier for the commission in past decisions authorizing funds for projects and programs that result in increased sales including in our general rate case process.” 

“There are real dollars that real customers will be paying once the work is performed,” Houck added. “In other words, there will be real bill impacts to customers. … I do not make my determination here lightly.” 

Energization project costs include connecting new customers to the distribution grid, upgrading capacity for existing customer sites and building additional capacity for forecast load, the CPUC said in the 2024 decision. The CPUC is required to accelerate energization processes for investor-owned utility customers per Assembly Bill 50 and Senate Bill 410. 

External Labor Versus Internal Labor

PG&E needs to increase energization cost caps in part because it plans to hire external contractors for 45% of projects in 2025 and 2026, according to the decision. In 2024, PG&E projected 22% of work would be performed by external contract laborers.  

The utility estimates the cost for external contractors to perform energization project work will be about $137,000 per unit in 2025, compared with $67,000 per unit for internal labor, the decision says. 

“There is not adequate time for PG&E to hire and train an internal workforce … to complete all of the energization projects in its backlog in 2025 and 2026,” the CPUC said in its decision. 

Another factor behind the cost cap increase: PG&E says it needs to spend about $74 million to increase customer outreach and improve customer notifications for its energization process over 2025/26. 

According to the decision, PG&E projected an 8% increase in energization applications in the coming years. However, the utility did not provide data that supported its forecast growth in energization applications over 2025/26, the decision says. Comparatively, from 2021 to 2024, PG&E’s data showed a 1% increase in energization project applications, the decision says. 

The average time for large electric utilities to complete energization projects should be 182 days, according to the decision.

While PG&E said the increased cost cap would translate into a 1.8% rate increase for an average residential customer, the CPUC countered that the “evidence does not support” this projected amount. The Utility Reform Network (TURN) estimates proposed cost cap increases would cost $72.50/year for a residential customer that uses 500 kWh/month. 

Energization project costs will be tracked in PG&E’s Electric Capacity New Business Interim Memorandum Account (ECNBIMA). PG&E can seek recovery of costs in this interim memorandum account only if the costs exceed what the utility was authorized to recover in its 2023 General Rate Case, the decision says. The CPUC will review PG&E’s costs tracked and recovered in its ECNBIMA in the utility’s 2027 GRC. 

Energy Efficiency Goals Set

At the voting meeting, the commission also approved energy efficiency and energy savings goals for 2026-2037 for California’s large IOUs. Energy savings goals are tracked in a metric called Total System Benefit (TSB), which includes the lifecycle energy, capacity and greenhouse gas benefits of an efficiency or fuel substitution measure.  

The 2028-2031 TSB goal is about $1 billion for PG&E, $646 million for Southern California Edison and $300 million for San Diego Gas & Electric. 

“Today’s decision reflects changes in efficiency opportunities and market conditions, including growth in fuel substitution, such as switching from natural gas to electric appliances, a decline in traditional efficiency measures in industrial and agricultural sectors, and a more rigorous cost-effectiveness threshold,” the CPUC said in a press release. 

Posted on

Pathways Initiative Unveils RO Proposed Name, Bylaws

The West-Wide Governance Pathways Initiative is preparing to file the incorporation documents for the independent “regional organization” (RO) that will govern CAISO’s energy markets, while funding challenges remain. 

The committee plans to file the incorporation documents for the RO in early 2026 under the proposed name Regional Organization for Western Energy (ROWE). The RO will be incorporated as a Delaware non-stock corporation and will qualify as a public benefit corporation, Evie Kahl, chief policy officer at California Community Choice Association and Pathways Launch Committee member, said during a committee meeting Aug. 29. 

Kahl also presented the draft bylaws, which detail the policies that will guide the RO and future committees such as advisory, public policy and audit and finance committees. 

The Launch Committee, consisting of members from several Western states, was formed with the task of establishing an independent RO to oversee CAISO’s Western Energy Imbalance Market (WEIM) and Extended Day-Ahead Market (EDAM) in an effort to expand energy markets. (See Pathways Initiative Approves ‘Step 2’ Plan, Wins $1M in Federal Funding.) 

The draft bylaws specify that the “independent governance shall be provided to and for entities and persons operating within the markets, consumers and affected stakeholders while acting in the public interest, and after consideration of consumer interests and the policies of all participating states.” 

The bylaws also go into the public interest functions of the RO. For example, the RO will establish a public policy committee to engage with states, local authorities, federal power marketing administrations and advocacy organizations about potential impacts of policy initiatives. 

Additionally, state authority “has been something that’s been important all along,” Kahl said. 

“We’re developing a regional organization, so we need to make sure that we don’t trample the rights of the states in the process,” Kahl added. 

Specifically, the draft bylaws state, “the board shall consistently acknowledge and, where practicable, develop tariff changes, rules or business practices that respect and accommodate participating states’ achievement of state or local policy objectives, including procurement, resource adequacy, environment, reliability and other consumer interests.” 

“The board likewise shall minimize any adverse impacts of revisions to its tariff, rules, and business practices on participating states’ policy objectives,” according to the draft bylaws. 

Meanwhile, the committee has enough money in the bank to cover expenses through the end of 2025, according to Jim Shetler, general manager of the Balancing Authority of Northern California and co-chair of the committee’s Priority Administrative Work Group. 

The initiative needs roughly $2 million for 2026 and about $4.8 million for 2027. 

“To date, we have basically gone through pledges and donations to try to fund this effort,” Shetler said. “We acknowledge that $7 million is going to be tough to do that way, but we’re going to at least start there.” 

The work group has issued an updated pledge form and a draft funding agreement to solicit additional funding, Shetler explained. The work group also is considering debt financing as an option, Shetler said. 

The group, which has estimated a $7.1 million budget for all three of its phases, hit a financing snare early in 2025 when the Trump administration paused nearly $1 million in funding as part of a larger spending freeze on projects previously promised support by the Biden administration. (See Pathways Initiative Seeks $7.1M to Fund RO.) 

“Bottom line is, pledge form should be ready here in the next month, and we will be coming out and soliciting funding,” Shetler said. “We’re setting this up where people could fund over time. We’re not necessarily asking for a full commitment Day 1. But we do need to get some funding in place starting in January of next year in order to support the 2026 budget.” 

Posted on

MISO Seeking Realistic Gen Buildout for Tx Planning Futures

MISO said its set of 20-year transmission planning futures must be further fine-tuned after the Trump administration’s repeal of tax credits for renewable generation.  

The grid operator said introducing the constraints of the One Big Beautiful Bill Act into its capacity expansion modeling returned a build rate that cannot be achieved.  

MISO announced it would take a few months to rework the capacity assumptions in its four 20-year transmission planning futures after passage of the sweeping law in July. (See MISO Revising Transmission Futures After Repeal of Tax Credits.)  

But Director of Economic and Policy Planning Christina Drake said MISO’s modeling using the confines of the law is building too much capacity too fast before the full phaseout of renewable tax credits. Drake said models included an infeasible amount of generation in the first five years.  

MISO’s modeling contemplates a 20-year expansion period and builds according to economic conditions and incentives. 

“We need to have a reasonable band for what can be built in the near term,” Drake told stakeholders at an Aug. 29 workshop to discuss the futures.  

MISO now is looking for “practical limitations to near-term build-out,” Drake said. She said MISO is assessing its queue delays and sluggish supply chains alongside the rollback of incentives for renewable energy to figure out what developers realistically can build. Drake said MISO’s historical build rate with recent supply crunches factored in results of only 9 GW built per year.  

MISO plans to hold more workshops Sept. 24, Oct. 29, Nov. 18 and Dec. 17. MISO added the last two dates after it realized it would need to modify its capacity expansion estimates.  

Drake said MISO did a “hard pivot” in its futures after the passage of the bill.  

The four futures will be used when MISO resumes its long-range transmission planning in 2026.  

Posted on

CAISO’s EDAM Scores Simultaneous Wins at FERC

CAISO’s Extended Day-Ahead Market clinched a set of wins Aug. 29 when FERC approved the market’s revised congestion revenue allocation model and authorized participation for the EDAM’s first two members — PacifiCorp and Portland General Electric, which will join the market in 2026. 

The three decisions are interlinked in that PacifiCorp’s EDAM membership tariff filing to FERC triggered the events that prompted CAISO to revise the EDAM’s congestion revenue allocation rules. 

Shortly after Portland, Ore.-based PacifiCorp submitted the filing to FERC in January, Powerex, the energy trading arm of Canadian utility BC Hydro, issued a paper contending EDAM contained a “design flaw” in how it treated firm transmission rights and congestion. Powerex argued the design would leave the market’s non-CAISO participants exposed to charges for constraints occurring outside their systems while not providing them the ability to recover or hedge against those costs. (See Powerex Paper Sparks Dispute over EDAM ‘Design Flaw’.) 

Powerex’s argument centered on the possible impact of “parallel” — or loop — flows in EDAM. As an example, the company’s paper cited how an energy delivery scheduled between PacifiCorp’s East and West balancing authority areas could produce a parallel flow that causes congestion in the CAISO BAA. EDAM then would apply the charge for that CAISO congestion to the PacifiCorp transaction but not provide the PacifiCorp transmission customer with an adequate ability to hedge for that charge, including through an allocation of congestion revenues.  

CAISO and PacifiCorp initially defended EDAM’s congestion revenue allocation (CRA) design, noting FERC already implicitly endorsed the model when it approved the day-ahead market’s tariff in December 2023. But after a broader group of stakeholders expressed similar concerns, the ISO in March launched an “expedited” initiative to address the issue. (See Fast-paced Effort will Address EDAM Congestion Revenue Issue.) 

Under the new design coming out of that stakeholder process — and now approved by FERC, certain congestion revenues stemming from parallel flows would be allocated to the BAA where the energy is scheduled rather than where the constraint is located. Those revenues would be allocated based on a transmission customer’s eligible firm Open Access Transmission Tariff transmission rights submitted and cleared as day-ahead balanced self-schedules. (See CAISO Approves New EDAM Congestion Revenue Allocation Design.) 

In its decision (ER25-2637), the commission found the revised rules to be “just and reasonable” because “they will allocate a portion of certain congestion revenues associated with a binding constraint to the EDAM BAA where market participants paid congestion costs associated with the constraint, rather than to the EDAM BAA where the constraint occurs.” That will ensure “eligible” firm transmission customers can hedge against day-ahead congestion charges by submitting their self-schedules, the commission said. 

The commission noted that commenters in the proceeding “largely support” the proposal as an “interim measure” until CAISO comes up with a permanent solution through its stakeholder process. 

“CAISO frames the instant proposal as a ‘transitional measure,’ and, after EDAM goes live, CAISO states that it intends to begin a stakeholder process, informed by operational data, to identify near-term and long-term revisions for congestion revenue allocation under EDAM,” FERC wrote. “We note, however, that the instant proposal does not contain a sunset date. As such, although some commenters are concerned that future tariff revisions might again expose their firm transmission use to congestion charges, such concerns are outside the scope of the instant proceeding.” 

The commission acknowledged the concerns of some commenters that the rule changes could incentivize increased use of self-schedules among EDAM participants as a means to hedge against congestion charges but said that practice is not “inherently undesirable” because it could make supplies available to CAISO’s markets. 

“In any case, even if CAISO’s proposal may further incentivize self-scheduling, we note that, under EDAM’s current market design, the ability to self-schedule helps participating transmission providers respect their transmission customers’ firm transmission service rights, a consideration that must be balanced against any potential market impacts. We find that the likely benefits of EDAM’s market dispatches will still incentivize market participants to economically bid into EDAM,” the commission wrote. 

The commissioners disagreed with commenters — including Powerex — which argued CAISO should allocate congestion revenue directly to transmission customers based on their transmission rights and allow those customers to opt their transmission service rights out of EDAM altogether, as provided for in SPP’s Markets+. 

“The commission has already accepted in the EDAM order CAISO’s allocation of congestion revenue to EDAM entities, who in turn sub-allocate the congestion revenue as provided for in their OATTs. Similarly, with respect to transmission carveouts, the EDAM order approved the CAISO tariff section that provides EDAM entities the discretion to determine the criteria for such carve-outs,” FERC wrote. 

The commission also rejected various requests that CAISO be required to: “immediately begin a stakeholder process to identify near-term solutions to the issues of the asymmetry between EDAM BAAs” and the incentive to self-schedule; delay EDAM’s implementation until a long-term solution for CRAs is identified; or submit CRA rule revisions within two years. 

“We disagree with protesters that a deadline for further deliberation should be mandated as we find that CAISO’s current allocation methodology for congestion revenue is just and reasonable. Moreover, we will not direct CAISO to delay the go-live date of a market expansion that the commission has already found to be just and reasonable,” FERC wrote. 

Orders Pave Way for PacifiCorp, PGE to Join EDAM

The CRA issue appeared prominently in the FERC orders approving the utility tariff revisions required for PacifiCorp (ER25-951) and PGE (ER25-1868) to participate in the EDAM, particularly around the sub-allocation of the congestion revenues back to load-serving entities in the utilities’ BAAs. 

Over the protests of multiple commenters, the commission approved each utilities’ two-step process for sub-allocating those revenues.  For both utilities, Step 1 of the process seeks to use EDAM’s congestion revenue allocation to reverse day-ahead congestion price differentials arising for self-scheduled energy transfers relying on firm monthly and longer-term transmission service rights. Step 2 will distribute the rest of the allocation to BAA load and exports not already included in the step one allocation. 

Using similar language in both rulings, FERC said it found the Step 1 allocation just and reasonable because “it first reverses day-ahead congestion charges on balanced self-schedules associated with long-term transmission service rights to the greatest extent possible, providing long-term firm customers that choose to self-schedule “an opportunity to hedge against day-ahead congestion charges associated with their use of” the transmission system “by submitting balanced self-schedules in the day ahead.” 

In the PacifiCorp decision, the commission noted that “[w]hile protesters argue that firm transmission customers may not be able to reverse their day-ahead congestion charges if PacifiCorp is not allocated sufficient congestion revenue, we agree with CAISO and PacifiCorp that these issues are outside the scope of the instant proceeding because they pertain to tariff provisions that the commission accepted in the EDAM order.” 

Both utilities’ orders point to the concurrent CAISO CRA order, noting the ISO’s tariff revisions “may help to address some of the concerns” raised by protesters in the two proceedings. 

Both orders also reject arguments by future participants of SPP’s Markets+ that the commission reject tariff provisions around transmission scheduling because they don’t accommodate the ability of transmission rights holders to contribute their transmission to Markets+. In both orders, FERC found the revisions do “not bar firm point-to-point transmission customers from contributing their transmission rights to Markets+, insofar as they are able to meet all of the requirements of” the utilities tariff. 

FERC found “there is no obligation under the commission’s regulations, or the pro forma OATT” for either utility “to accommodate transmission contributions to Markets+.”  

Posted on

ERCOT Stakeholders Endorse 2026 AS Methodology

AUSTIN, Texas — ERCOT stakeholders, while raising concerns over the grid operator’s use of conservative operations, have endorsed staff’s recommendations for computing minimum ancillary service quantities for 2026. 

The proposed methodology was opposed by the Technical Advisory Committee’s six-person consumer segment. They argued in filed comments that the “over-procurement” of ancillary services “starves the energy market of resources” just when it is poised to respond to scarcity conditions. 

ERCOT has been using its conservative operations approach as a response to 2021’s disastrous Winter Storm Uri. The ISO sets aside larger amounts of operating reserves, one of several out-of-market actions that consumers said “inhibit” the energy market. 

“We believe conservative operations undermines efficiency in the energy market,” Mark Dreyfus, who represents several public power entities, said during TAC’s Aug. 27 meeting. “We all understood after the winter storm here the need for conservative operations, but we are in such a dynamic industry, and we’ve seen so many changes since then. We’re somehow stuck with this policy adopted for a [different] world.” 

Harika Basaran, director of market analysis for the Public Utility Commission, reminded TAC of the PUC’s 2024 report on ancillary services. The report found the grid operator’s use of conservative operations should be maintained to balance system improvements made since the winter storm until additional data is available.  

Michele Richmond, Texas Competitive Power Advocates’ executive director, reminded members that any decision on conservative operations lies with the Public Utility Commission.  

“It seems like we keep going round and round with the same debate about conservative operations, when that’s a policy call at the commission,” she said. “We keep having the same conversation, and it keeps holding up a lot of the meetings about whether conservative operations is the right call or not. It just seems kind of an exercise in futility to continually have this debate when that’s not a decision that anybody in this room or in this building has the ability to make or change.” 

Staff said the AS methodology’s focus is not on scarcity days or hours, but to ensure sufficient services are procured when capacity is available but otherwise may not be online or available in time to cover risks. 

TAC agreed with staff’s proposal to continue using the regulation service methodology approved in December 2024, but after removing feedback from fast-responding reg service. That service will be retired when the real-time co-optimization plus batteries (RTC+B) project is deployed later in 2025. 

ERCOT also wants to use a probabilistic model to establish quantities for ERCOT contingency reserve service (ECRS) and non-spinning reserve service. The model is designed to establish sufficient ECRS plus non-spin reserve quantities for those non-scarcity days when capacity is available but otherwise may not be online or available in time. 

Finally, staff recommends that minimum responsive reserve service from primary frequency response be updated to 1,377 MW, aligning with NERC standards.  

TAC approved the methodology, 19-7, with three abstentions. The consumer segment was joined by AP Gas & Electric in voting against the measure. 

The Independent Market Monitor, which has said the ISO’s use of ECRS has created artificial supply shortages, proposed an alternative approach: using a three-hour load forecast error and a one-hour energy storage resource duration to reduce procurement but still maintain reliability. 

Requirements for IBRs 

Committee members approved revisions to the Nodal Operating (NOGRR272) and Planning guides (PGRR121) that establish new advanced-grid support requirements — including model-quality tests and unit validation requirements — for inverter-based ESRs with a standard generation interconnection agreement (SGIA) executed on or after April 1, 2025. 

TAC’s Reliability and Operations Subcommittee granted NOGRR272 urgent status at staff’s request. Staff submitted the measure to provide greater support for system resiliency and to maintain stable operations with the prevalence of wind and solar IBRs. ERCOT says it has created and enforced in real time more than 20 generic transmission constraints, most of which are related to IBRs, and the monthly interconnection report says more than 100 GW of IBRs could join by grid by 2026. 

“We’re going to be talking about this for a long time,” ENGIE North America’s Bob Helton said, noting that a market-based approach would be more efficient by targeting grid-forming resources. 

ROS Chair Katie Rich, with Vistra Operations, said the changes do not “close the door” from looking at market aspects and noted ERCOT staff has committed to further developing a market-based approach. 

“I just want folks to know this is not the end-all be-all. You’re taking a vote on what’s before you today, but there is still more work to be done on this,” she said. 

ERCOT filed late comments to both the NOGRR272 and PGRR121 approach to target grid forming resources where needed. 

Members unanimously approved the combined measures, 27-0. Jupiter Power, Shell Energy and Vistra all abstained. 

$827M in Tx Projects OK’d

Members endorsed staff recommendations for a pair of regional transmission projects with projected capital costs of more than $827 million. Both projects require board approval because of their costs. 

CenterPoint Energy’s Baytown Area Load Addition project costs $545.3 million, as recommended by ERCOT’s Regional Planning Group. CenterPoint submitted a $141.7 million estimate to address reliability issues caused by proposed new load in a region thick with petrochemical facilities. 

The project involves only about 45 miles of 138-kV lines and adding capacitors. However, staff said its analysis found additional temporary work would be required for all structure replacements, accounting for about 45% of the capital costs, maintenance-outage issues and the expense of rebuilding 138-kV lines among industrial facilities increased the project’s costs. 

“All consumers in Texas are being asked to spend a half a billion dollars for CenterPoint to be able to upgrade their system,” said Beth Garza, representing residential consumers.  

Garza voted against the proposal, as did the Office of Public Utility Counsel and retailer Rhythm. 

CenterPoint expects to complete the upgrades in January 2028. 

The Texas A&M University System RELLIS Campus reliability project has an estimated capital cost of $282.1 million and a projected October 2029 completion date. 

The project includes 40 miles of new 345-kV double-circuit lines to the RELLIS campus, constructing or rebuilding about 10 miles of 138-kV lines, and expanding the campus’ existing 138-kV substation with four additional 138-kV breakers in the existing 138-kV ring bus and four 345-kV breakers in a ring bus configuration. 

The RPG shortlisted three options, choosing one that it said performs “significantly better” serving a 1,200-MW load with a formal interconnection request in the study area. Texas A&M is working with four developers to build small modular nuclear reactors at the RELLIS campus. 

The project was submitted by Bryan Texas Utilities. Dreyfus, who represents BTU among other public power entities, abstained from the vote. 

“As a [University of Texas] grad, I find it hard to vote for this,” Reliant Energy Retail Services’ Bill Barnes cracked. “One possible solution would be to make Kyle Field (Texas A&M’s football stadium) an interruptible load.” 

Combo Ballot Approved

TAC’s combination ballot included six nodal protocol revision requests (NPRRs), single NOGRR and PGRR changes, and a system change request (SCR) that, if needing board approval, will: 

    • NPRR1265: Implement procedures for distributed generation (DG) reporting by clarifying DG’s definition and defining the new term, “unregistered distributed generators (UDGs).” The NPRR would establish procedures for UDG reporting to ERCOT and reporting requirements from the ISO. 
    • NPRR1266: Specify that a transmission-voltage customer that is a securitization uplift charge opt-out entity may not transfer its status to other entities. The measure adds a requirement that a transmission service provider (TSP) associated with an electric service identifier originally granted opt-out status must compare at least monthly the names of transmission-voltage customers originally granted the status and inform ERCOT of any changes. The TSP requirement excludes those that are securitization uplift charge opt-out entities. 
    • NPRR1279: Enables generation resources to file exceptional fuel costs that include contractual and pipeline-mandated costs and strengthens the process for ERCOT and the IMM to verify the costs. 
    • NPRR1283: Require that any necessary subsynchronous resonance (SSR) studies be complete and mitigation be in place before the initial synchronization of an ESR, new generation resource or a settlement-only generator before the initial energization. 
    • NPRR1290, NOGRR278: Address several gaps and clarify protocol language to support the RTC+B initiative’s implementation. 
    • NPRR1291: Incorporate the PUC’s substantive rule setting a goal for average total residential load reduction into the protocols, specify data exchange methods and formats, and extend the deadline for posting the annual demand response report. 
    • PGRR129: Establish requirements for posting the Grid Reliability and Resiliency assessment and update a list illustrating data sets and classifications. 
    • SCR832: Discontinue and eventually retire a report not being used by market participants. 
Posted on

SPP MMU: Average WEIS Energy Prices Up in Spring

SPP’s Market Monitoring Unit says in its latest report that the Western Energy Imbalance Service (WEIS) market’s average load energy prices rose “significantly” during the spring quarter (March-May). 

The increase was driven primarily by elevated natural gas prices in March, the MMU said in its quarterly State of the Market report for the WEIS market, published Aug. 29.  

Spot prices for natural gas at the Cheyenne hub started the quarter at $2.85/MMBtu and closed at $2.18/MMBtu. Gas prices averaged $2.342/MMBtu during the quarter, about 45% higher when compared to the same quarter in 2024. Settling additional generation out of the market also increased gas prices. 

Energy prices averaged $34.93/MWh in March, up from $19.78/MWh a year ago. Prices dropped to $22.83/MWh in April, slightly higher than a year ago ($19.19/MWh), before averaging $23.09/MWh in May, up from $13.05/MWh in 2024.  

The MMU noted coal generation continues to be the primary fuel type for the WEIS market, accounting for about 33% of total generation during the quarter. It said the WEIS market is a voluntary imbalance market. The price volatility is strongly associated with the supply — or lack thereof — of interval-by-interval rampable capacity, it said. 

The frequency of negative intervals started at 3.25% in March and increased to 7.43% in April and 9.16% in May, making it difficult for market participants to sell energy to the market and earn revenue. Negative price intervals can be caused by many factors, usually including high amounts of renewable generation and associated subsidies, a lack of dispatchable range and external impacts, the MMU said. 

The WEIS market’s total generation nameplate capacity grew by 579 MW. The market added 405 MW of solar, 162 MW of gas and 12 MW of “other.” 

This quarter provided a total revenue neutrality uplift credit to the WEIS market of just over $700,000. The uplift was mostly composed of revenue inadequacy surpluses in April and May and uninstructed resource deviations and out-of-merit energy in March. 

SPP operates and administers the WEIS market, a price-based, centralized real-time energy imbalance service market. The market gives participants the ability to submit offers and bids for imbalance energy, settling the net supply or obligation for an asset owner.  

The grid operator plans to terminate the WEIS market April 1, 2026, when it integrates Western balancing authorities into its Western Interconnection expansion. The MMU said market improvements supporting reliability, transparency and operational efficiency should continue to be implemented as needed. 

Posted on

FERC Approves ISO-NE Follow-up Compliance Filing for Order 2023

FERC has approved a follow-up filing for ISO-NE’s compliance with Orders 2023 and 2023-A, authorizing variations from the final rule related to interconnection point modifications, cost allocation and commercial readiness deposits (ER24-2009-001). 

Order 2023 requires grid operators to adopt cluster processes to study interconnection requests on a first-ready, first-served basis. (See FERC Updates Interconnection Queue Process with Order 2023.) 

The commission accepted the bulk of ISO-NE’s first compliance filing for Order 2023 in April but required ISO-NE to make a series of minor changes and clarifications in a follow-up order, which the RTO submitted in early June. (See FERC Approves ISO-NE Order 2023 Interconnection Proposal.) The second filing was supported by NEPOOL and was not protested before the commission. 

FERC has accepted this subsequent filing in its entirety, effective Aug. 12, 2024.  

In its approval, FERC ruled that ISO-NE can allow interconnection customers to modify their interconnection points during a cluster study. The commission wrote that this change “provides flexibility … to adjust the point of interconnection in the event that unexpected results show that the originally selected point of interconnection is not technically feasible.” 

ISO-NE wrote in its filing that providing this flexibility should reduce risks of withdrawals from the cluster study process. 

FERC also approved ISO-NE’s clarification of how it will allocate costs of network upgrades for “reactive devices or any substation additions beyond the point of interconnection.” 

ISO-NE proposed to allocate these costs proportionately “based on the type of violation and each facilities’ impact to that violation,” FERC noted.  

Regarding commercial readiness deposits, ISO-NE clarified it was to begin accepting surety bonds as of Sept. 1.  

“This means that interconnection customers seeking to participate in the transitional cluster study will be able to submit surety bonds to secure commercial readiness deposits for that study,” ISO-NE wrote in its filing.  

The follow-up filing also included variations related to site control, interactions between cluster studies and ISO-NE cluster enabling transmission upgrade studies, modeling and ride-through requirements for non-synchronous generators, and a series of “minor clean-up revisions,” including amendments to typos and unintended errors.