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December 7, 2025

Tribes Urge FERC to Reject Wright’s Hydropower NOPR

Tribes asked FERC to reject a proposal from Energy Secretary Chris Wright to reverse a 2024 rule change that required consultation with them over hydropower projects proposed on their lands (RM26-5).

FERC rejected some pumped hydro facility applications that were for projects in Navajo Nation territory after tribal authorities opposed them and said it would start denying other projects on native lands whenever tribes opposed them. (See FERC Rejects Pump Storage Projects Over Navajo Objections.)

Wright told the commission that eliminating the rule was needed “for America to continue dominating global energy markets.”

“The commission’s longstanding policy has been to grant applications for preliminary permits over the opposition of third parties, such as federal land managers, similarly affected agencies or tribes, as applicable,” Wright wrote in an Oct. 23 letter. “The reason is simple. The commission views preliminary permits as ‘encouraging hydroelectric development by affording its holder priority of application (i.e., guaranteed first-to-file status) with respect to the filing of development applications for the affected site.’”

The preliminary permit only lets holders investigate the feasibility of a project; it does not give them any land-disturbing or other property rights, he added.

Recent orders denying preliminary permit applications because of objections from the Navajo created “an untenable regime whereby it has effectively delegated its exclusive statutory authority to issue preliminary permits to third parties,” Wright said. The letter was accompanied by a Notice of Proposed Rulemaking the secretary filed under Section 403 of the Department of Energy Organization Act that, if approved, would return the rules to the status quo ante.

The National Hydropower Association told FERC in comments filed Nov. 12 that it supports the NOPR because it preserves the ability for developers to protect their early investment in a proposed project, while developers consult with regulators, tribes and other parties on their projects.

“Recognizing the importance of protecting a developer’s critical investments early in the project development phase, years before any revenue stream from the project is secured, the commission should adopt the proposed NOPR and return to its longstanding policy that preliminary permits should be denied only if there is a permanent legal barrier to licensing the project,” NHA said.

Objections raised early in the process lack information on the project’s design, operating parameters and environmental effects, and FERC should not defer to the sentiments of other entities, whether that is a federal land manager, another agency or a tribe, the group argued.

The Navajo urged FERC to reject the NOPR and asked for another month to file more substantive comments.

“The 2024 policy resulted in developers engaging with the Navajo Nation, its political subdivisions and the local communities where the project would be located; obtaining non-invasive access authorization and permission to survey from the Nation under Navajo law; and reapplying for preliminary permits without opposition,” it told FERC. “At least two proposed projects are in the feasibility stages of project development.”

The Choctaw Nation of Oklahoma and Chickasaw Nation filed joint comments opposing the NOPR, saying it directly implicates their sovereign authority over tribal lands, waters and other cultural resources. They also complained about the comment deadline, which gave parties just 12 days to respond to the secretary’s proposal and asked for a 60-day extension and initiation of government-to-government consultation with interested tribes before moving forward.

“Nothing in Section 403 requires the commission to undertake a rulemaking or to adopt the secretary’s suggested regulatory text,” they said.

The proposal conflicts with the Department of Energy’s own “trust responsibilities” to tribes, they argued. The federal trust responsibility applies to all executive agencies and requires that federal actions avoid harming tribal lands and waters, they said.

“By requesting rule changes that would restrict the commission’s ability to consider tribal consent or protect tribal rights in preliminary-permitting decisions, the secretary is advancing an action that is inconsistent with those responsibilities,” the tribes told FERC. “DOE should instead consult with tribes before proposing any regulatory changes that could impact tribal lands or waters.”

While the secretary argued the 2024 policy allows “third parties” to veto permits, the two tribes argued that framing ignores fundamental law.

“Tribal nations are not ‘third parties,’” they added. “They are sovereign governments with federally protected interests in land, water, cultural and other trust resources. These interests are not speculative; they are legally recognized and enforceable.”

Considering a tribe’s authority to control access to its lands or use of its waters is not an improper delegation, but rather FERC performing its duty under the Federal Power Act and other federal law, they said.

The Ute Mountain Ute Tribe also argued that tribes are not third parties, but rather sovereign governments whose lands and resources are held in trust by the U.S. The 2024 policy correctly applied the law, it said.

“DOE’s proposed rule would compel the commission to disregard that obligation by forcing the issuance of permits even when tribes have explicitly withheld consent,” the tribe said. “Tribal opposition is not a ‘veto’; it is the exercise of sovereign authority. By denying permits in those circumstances, the commission honors its trust duty and promotes orderly, cooperative energy development.”

While preliminary permits do not allow developers to disturb any land, they do block tribal governments from pursuing their own developments at sites, which has tangible economic and jurisdictional consequences, the tribe said.

New York Suspends All-electric New Construction Law

Attorneys for the state of New York agreed in a federal court filing Nov. 12 to suspend the implementation of the All-Electric Buildings Act, which had been scheduled to go into effect in January.

The law would prohibit heating oil and natural gas from being used in new construction, including single-family homes and apartments shorter than seven stories. By 2029 the law would have applied to all buildings with limited exceptions.

The New York State Builders Association, the National Association of Home Builders and trade groups representing the propane industry along with building and plumbing trade unions sued the state in 2023, saying the law violates the federal Energy Policy and Conservation Act, which restricts states from regulating gas in appliances.

A federal court disagreed with the plaintiffs’ claims in July 2025, finding that EPCA did not pre-empt the All-Electric Buildings Act because the state law did not concern the “energy use” of products covered by the federal law. The court found that EPCA stipulated energy efficiency rules, not whether certain fuels were allowed.

The plaintiffs appealed to the 2nd U.S. Circuit Court of Appeals. The appellate court has yet to decide on the case.

New York Secretary of State Walter T. Mosley filed a stipulation agreement to suspend the effective date of the mandate “to avoid further litigation” and “uncertainty during the appellate process.” The plaintiffs in turn agreed to withdraw their motion for an injunction.

The suspension will remain in effect 120 days after the 2nd Circuit rules, if the Supreme Court does not take up the case.

Gov. Kathy Hochul (D) “remains committed to the All-Electric Buildings law and believes this action will help the state defend it, as well as reduce regulatory uncertainty for developers during this period of litigation,” wrote Ken Lovett, a spokesperson for the governor. “Gov. Hochul remains resolved to providing more affordable, reliable and sustainable energy for New Yorkers.”

The law is a key part of New York’s strategy under the 2019 Climate Leadership and Community Protection Act to reduce emissions from fossil fuels over the next 25 years. State energy officials have identified buildings as responsible for one-third of statewide greenhouse gas emissions.

The news comes within a week of the Hochul administration issuing permits for a natural gas pipeline in New York and air permits for a gas plant to power a cryptocurrency mine. (See Permits for Trump-Favored Gas Pipeline Approved by N.Y. and N.J.) Environmental groups have accused the governor of backtracking on climate issues.

“We are deeply discouraged by this unnecessary delay and look forward to this appeal being resolved in a timely manner so this cost-saving, common-sense affordability and clean energy measure can move forward,” John Lindsay, spokesperson for the Building Decarbonization Coalition, said in an emailed statement. “Every day of inaction slows progress toward safer and more affordable new homes and buildings.”

“Gov. Hochul is backsliding on one of New York’s most important affordability and climate laws,” said Michael Hernandez, New York policy director for Rewiring America. “Now, she’s using litigation as cover to delay the All-Electric Buildings Act.”

MISO to Include Southeastern Texas in South Long-range Tx Planning

MISO announced it will honor a request from Texas regulators and include southeastern Texas in its first long-range transmission study for MISO South.

The grid operator earlier said it would start the process of drawing up planning studies for areas of Louisiana with heavy load pockets, marking the first long-range transmission plan for MISO South. (See MISO Kicks off South’s Long-range Tx Plan with More Restrained Approach.) Now a portion of Texas will be part of the equation.

MISO Executive Director of Transmission Planning Laura Rauch confirmed that Texas regulators approached MISO to request that part of the state be included in the study and that MISO agreed.

Speaking at a Nov. 11 Entergy Regional State Committee meeting, Rauch told South state regulators that MISO’s approach to South long-term system planning would differ from the planning conducted in MISO Midwest.

Rauch said MISO Midwest had several years of membership before MISO proposed the first, $10 billion long-range transmission portfolio in 2022 followed by the second, $22 billion portfolio in 2024.

“That journey took many, many years in the Midwest. … While I can’t guarantee the outcome, I know the outcome will look very, very different in the South than in the Midwest,” said Rauch, who emphasized different planning needs in MISO South.

Rauch said that over the course of 2026, MISO will assemble a study scope for Louisiana and Texas, build system models and hold discussions around potential needs in the South.

“It’s very likely that we’ll need to do additional analysis,” Rauch said. “Really, the goal is to practice the conversation around long-term needs.”

Rauch said MISO “may have to divide and conquer on” which issues to tackle first and could focus first on Louisiana before turning its attention to possible projects in southeastern Texas.

“My goal is for information at this point, not necessarily a certain amount of transmission approved,” Rauch said.

Arkansas Public Service Commission consultant Keith Berry asked if MISO has considered how to divide the costs of the projects.

Rauch said cost allocation negotiations “realistically” arise only when transmission needs are named. However, she said the first MISO South long-range planning — being limited to Louisiana and Texas — likely won’t require the region-wide postage stamp to load cost allocation used in MISO’s other long-range transmission portfolios.

“I will say with a focus on two states, I don’t see a need for a multivalue project cost allocation,” Rauch said.

Rauch said she doubted that “engineering studies won’t show sufficient value spread” across the entire South region.

Texas utilities Commissioner Courtney Hjaltman previously said she intended to ask the MISO board to include Entergy’s Texas footprint when it begins work on a long-range MISO South plan.

“My request will be to include Texas, as we obviously have load growth that we need to have included in that study,” Hjaltman said at the Oct. 23 Texas Public Utility Commission meeting.

Asked by an audience member why MISO’s focus is on Louisiana, she said, “They are trying to really home in on certain areas and include Louisiana, and specifically New Orleans, which obviously had a load shed event this past summer, and that might be why, but there’s just no reason that Texas shouldn’t be included.”

At the Entergy meeting, Berry asked where MISO stands on launching a planning study aimed at increasing transfer capability between MISO South and MISO Midwest.

Rauch said at this point, MISO believes operational fixes and increased coordination on the transmission contract path are the best way forward. MISO no longer talks about a fourth long-term transmission plan portfolio, which it once said might result in an expansion of Midwest-South transmission.

IMM Advises Better Constraint Management After MISO Tx Emergency

MISO’s Independent Market Monitor said a MISO South September transmission emergency shows the RTO needs a better handle on constraint management within its markets.

MISO declared a local transmission emergency around 1 p.m. ET on Sept. 16 after a 500-kV transmission line was forced offline in MISO South. The IMM said the sudden outage forced two constraints into violation and congestion costs rose to $12 million.

“MISO was successful in avoiding a load shed,” MISO Independent Market Monitor staffer Robert Sinclair said during a Nov. 11 Entergy Regional State Committee meeting. He said MISO “successfully utilized the available supply to maintain reliability through the event.”

MISO confirmed that a local transmission emergency occurred in MISO South on Sept. 16.

Sinclair said MISO manually dispatched some generation to manage violated constraints and made additional resource commitments that sent some resources into their emergency ranges to increase supply by more than 700 MW.

However, Sinclair said the IMM is finding in its initial investigation that MISO should improve its transmission constraint demand curves so that the market dispatches generation instead to manage constraint violations. He said while MISO’s manual dispatch actions were effective, they are more expensive than letting the market take the wheel.

Outages of 500-kV lines in MISO South “have increased in frequency in 2025 and triggered more frequent transmission emergencies,” Sinclair added.

He promised a fuller report on the events and the IMM’s recommended course of action at the upcoming MISO Board Week in December in Indianapolis. There, MISO leadership can respond to the recommendation.

MISO Re-examining Monthlong Outage Limit for Capacity Resources

MISO has signaled an openness to alter its 31-day planned outage rule for units that signed up to be capacity resources.

MISO said it experienced significantly more outages in summer 2025 compared to recent years, “which contributed to tight system conditions.” The upsurge has MISO revisiting its generator planned outage rules.

MISO expects capacity resource owners to either procure replacement capacity or pay penalties if they are offline for more than 31 days in a season. They must notify the RTO 120 days in advance of planned outages to be exempt from capacity accreditation reductions.

Davey Lopez, manager of market design resource planning, said MISO will examine whether its outage rules are rewarding availability, as MISO intended, and determine if they need an overhaul. At a Nov. 12 Resource Adequacy Subcommittee meeting, Lopez said MISO now has three planning years of data to evaluate the impacts of its move to seasonal capacity auctions and outage rules.

The RTO’s 31-day outage rule has been in effect since FERC approval in August 2022.

WEC Energy Group’s Chris Plante said he believes generation owners aren’t as concerned about their forced outage rates anymore under MISO’s availability-based capacity accreditation. Other stakeholders agreed that unit owners are less worried about their forced outage rate and more preoccupied with being available during the predefined risky hours in a season, which MISO has placed a premium on per its availability-based accreditation.

Lopez said MISO’s evaluation would look for “unintended consequences” and assess whether the ruleset “continues to provide the proper incentives for resources to be available during the periods of highest reliability risk and prudent planned outage scheduling.” He stressed that MISO doesn’t yet have any revisions in mind.

Lopez said he would appear before the RA Subcommittee in early 2026 for more discussion.

Former FERC Commissioners Ask Supreme Court to Preserve Agency Independence

Eleven former FERC commissioners filed a brief with the Supreme Court arguing it should uphold Humphrey’s Executor or carve out an exception for ratemaking agencies.

The court is poised to hear oral arguments in Trump v. Slaughter on Dec. 8, in which former Federal Trade Commissioner Rebecca Kelly Slaughter is arguing President Donald Trump overstepped his authority in firing her in March.

The case comes 90 years after the Supreme Court found that Congress could limit the president’s authority to fire members of regulatory agencies in another case involving an FTC commissioner, which has helped guarantee agency independence since then. In an order overturning an injunction in a related case earlier this year, a majority on the court seemed poised to overturn the precedent but noted it would benefit from briefing on the issues. (See Will the Supreme Court End FERC’s Independence?)

“Overturning Humphrey’s Executor would bulldoze the structural supports that Congress built into ratemaking commissions to protect its price-setting power from abuse,” according to the brief, which was prepared by the Harvard Electricity Law Initiative’s Ari Peskoe.

The amici curiae in the brief are a bipartisan group of former FERC commissioners who were nominated by all but one of the presidents from Ronald Reagan through Trump’s first term: Elizabeth Anne Moler, Donald Santa, Linda Breathitt, Pat Wood III, Nora Mead Brownell, Joseph T. Kelliher, Jon Wellinghoff, John Norris, Cheryl LaFleur, Neil Chatterjee and Richard Glick.

Congress has given ratemaking authority to multimember bipartisan commissions dating back to 1887 and limited the president’s power to fire members only for “inefficiency, neglect of duty or malfeasance in office.”

“By shielding agency action from political control, for-cause removal protections allow ratemaking commissions to sustain stable policies for the long-term benefit of regulated companies and American consumers,” the brief says.

If the court decides to overturn or clarify Humphrey’s Executor, the brief urged it to consider the “special historical status” it has indicated the Federal Reserve has in the Seila Law decision in 2020, in which the court found the president had unchecked authority to fire the director of the Consumer Financial Protection Bureau.

Ratemaking agencies wield “legislative power” to set prices for investor-owned companies, the brief argues, and among all multimember agencies, only the Federal Reserve Board plays such a direct role in the economy, doing so with similar “legislative discretion.”

“Overturning Humphrey’s Executor without acknowledging ratemaking commissions’ special status would greenlight one-party ratemaking bodies and allow presidents to eliminate staggered terms by firing holdover commissioners nominated by a previous president,” the brief says. “Permitting the president to seize control over ratemaking could adversely affect how regulated companies perceive FERC and therefore increase the risk of financing pipelines and power lines. Ultimately, American consumers would pay higher energy prices.”

Eliminating for-cause removal protections risks turning FERC into a partisan political body whose priorities flip every election cycle, and the resulting volatility would conflict with its historic focus on the long-term interests of consumers and the industries it regulates, the brief argues. Congress affords ratemaking commissions with wide discretion as they balance competing interests to find just and reasonable rates, and their bipartisan composition is an antidote against abuse of that discretion, it says.

“For-cause removal protections, staggered terms and partisan limits temper agency discretion by ensuring that decisions are informed by diverse and balanced perspectives,” the brief says.

The Massachusetts legislature was the first body to set up a ratemaking commission in 1869 to regulate what railroads charged in the state, and it was quickly followed by other states. The court upheld their creation in an 1877 decision.

A decade later, after the court found those state ratemaking commissions could not regulate interstate commerce, Congress set up the Interstate Commerce Commission to check the power that railroads exerted over the economy. The ICC had to have five commissioners with no more than three from one party; commissioners served staggered terms, could not hold other jobs, were forbidden from investing in regulated companies and had for-cause removal protections.

The ICC’s structure remained durable and was adopted for other agencies over the years, including when Congress passed the Department of Energy Organization Act in 1977. Congress specifically rejected President Jimmy Carter’s proposal to give DOE the old Federal Power Commission’s ratemaking authority, with members arguing the power should go to a “collegial” body and not the department, where only the president’s policies would guide its decisions.

“The age of the kings expired with the French Revolution,” Rep. John Dingell (D-Mich.) said at the time, according to the Congressional Record. “I plead with this body, do not set up a new king here in Washington.”

Dingell’s “rhetorical flourish focused his colleagues on threats to liberty,” which are a core concern in separation of powers cases, the brief says.

“By seizing ratemaking authority, ‘one of the great functions conferred on Congress by the federal Constitution,’ the president would secure vast direct control over the economy,” the brief says. “Price-setting power would allow the president to increase profits of favored companies at the expense of consumers, who would face higher prices for goods and services. The president could also punish companies that oppose his policies or even raise energy prices in states that support his political rivals.”

Congress wanted ratemaking power to be exercised in the “coldest neutrality” rather than unilaterally by the executive branch, the brief says.

“Elevating executive control over bipartisan deliberation, as petitioners urge, misunderstands Congress’ ratemaking statutes and threatens to destabilize an economic model that has stood the test of time,” the brief says.

The Supreme Court has repeatedly called the commission’s ratemaking authority “legislative,” so the commissioners urged the court, even if it overturns Humphrey’s Executor, not to foreclose the possibility that ratemaking commissions remain immune from direct executive control. Separation of powers ought to allow Congress to create deliberative ratemaking bodies.

“FERC plays a direct role in our economy that, among the multimember agencies, is matched only by the Federal Reserve Board,” the brief says. “Prices set by FERC are essential inputs across the economy that directly affect the cost of living and doing business. Maintaining for-cause removal protections for ratemaking commissions exercising legislative power would appropriately defer to Congress’ powers over interstate commerce.”

The brief also examines FERC’s economic impact. It regulates 200,000 miles of interstate natural gas pipelines, 120,000 miles of high-voltage transmission and 85,000 miles of interstate crude pipelines, which transport more than $1 trillion worth of commodities per year.

That work remains important as artificial intelligence and reshored manufacturing grow the demand for electricity, and the oil and gas industry works to increase shipments of LNG abroad.

“FERC is more important than ever to American energy producers and consumers,” the brief says. “Any change to FERC’s structure should follow careful deliberations in Congress that weigh the potential benefits of reform against the possible harms caused by transforming FERC into a politically partisan body.”

The commission’s authority over energy markets gives it a direct and central role in the economy, like the Federal Reserve. The brief quotes former Federal Reserve Chair Alan Greenspan as saying, “Energy markets will remain central in determining the long-run health of our nation’s economy.”

“Like interest rates set by the Federal Reserve Board, energy prices impact costs across the economy and have material effects on total investment and consumption,” the brief says. “Congress charged FERC and the Federal Reserve with promoting stable prices, which provide households and businesses with confidence to invest.”

NERC Manager Shares Outlook on Long-term Assessments

NERC is working to enhance its Long-Term Reliability Assessments and make them more useful for industry stakeholders amid a rapidly changing energy environment, Mark Olson, the ERO’s manager of reliability assessments, said in an online workshop Nov. 12.

Speaking to the 2025 Planning and Modeling Virtual Seminar, hosted by NERC, the North American Transmission Forum and the Electric Power Research Institute, Olson said NERC’s LTRAs “are critical to talking to stakeholders about what the concerns are … and we rely on industry information to make these reports credible.” But he also said the ERO has noticed “limitations” in its current approach to the assessment that make the resulting document less informative in this environment.

“For a long time, we were managing the risks that were associated with a changing resource mix and new resource types,” Olson said. “In recent years, as you’re all well aware, with data centers and electrification and the speed [at] which load can request to come onto the system, the resource adequacy challenge has changed.”

NERC publishes the LTRA each December based on information collected from the regional entities, with the goal of “identifying trends, emerging issues and potential risks during the upcoming” 10 years. Olson observed that the LTRA originally was “designed around capacity-based methods,” with heavy emphasis on planning reserve margins.

The ERO introduced probabilistic assessments to the development process, which “have become more and more energy-based [to] take into account the energy limitations of resources,” Olson said. However, methods of performing probabilistic assessments can vary between regions, which means the resulting LTRA can be inconsistent and confusing to stakeholders.

To bring more consistency to the LTRA, Olson said the REs for the Eastern, Western and Texas Interconnections are collaborating this year on interconnection-wide energy assessments. The REs used off-the-shelf software to create a common platform and standardize the assumptions that would go into their reports.

Olson emphasized that this is a pilot program that is “about building the capability to do the work” rather than providing a “reliability takeaway” for this year, and the results will not be published in the 2025 LTRA. Nevertheless, he praised the REs’ work for setting the foundation for future interconnection-wide assessments.

“This is really something we’re pretty proud of,” Olson said. “In the past, some [REs] would perform an assessment over their entire … footprint. But for this work, each [RE] was coordinating with their neighbor regions across the interconnection and coming with the same assumptions … and resolving challenges as they went. All of these regions working off of a common tool, and a common model of the interconnection, is a pretty big step.”

Olson said NERC also has benefited from the Interregional Transfer Capability Study, which the ERO filed with FERC in 2024 as ordered by Congress in the Fiscal Responsibility Act of 2023. Not only were the REs’ interconnection-wide assessments based in part on the models used for the ITCS, but the 2025 LTRA could make use of the data collected for the study.

“This is really about adding to our LTRA a level of information that helps us understand how non-firm transfers can help resolve risks. It also brings in transmission adequacy or transfer capability into our assessments … on an interconnection-wide scale, and we haven’t had that in the past,” Olson said. “It will really set the stage for scenarios where [if] you want to look at, say, fuel outages, fuel events or wide-area cold weather [or] heat domes, those kind of things, we’ll have an interconnection-wide energy analysis model that would allow us to study that.”

IEA World Energy Outlook 2025 Quantifies Rising Global Power Demand

The International Energy Agency released its World Energy Outlook 2025, which found new emerging economies are poised to drive the near-term future of energy.

China accounted for half of oil and gas demand growth and 60% of electricity demand growth for the past decade, but in the future the markets will be driven by what happens in India, Southeast Asia and countries in the Middle East, Africa and Latin America. No country, or even group of them, is expected to come close to replicating the scale of China’s energy-intensive rise.

The world continues to face security risks to oil and gas supplies, but IEA said China’s dominance of rare earth minerals vital to power grids, batteries and electric vehicles now accompany those much older risks. China is the dominant refiner for 19 out of 20 energy-related strategic minerals, with average market share across those of around 70%.

“When we look at the history of the energy world in recent decades, there is no other time when energy security tensions have applied to so many fuels and technologies at once — a situation that calls for the same spirit and focus that governments showed when they created the IEA after the 1973 oil shock,” IEA Executive Director Fatih Birol said in a statement. “With energy security front and center for many governments, their responses need to consider the synergies and tradeoffs that can arise with other policy goals — on affordability, access, competitiveness and climate change.”

Electricity is at the heart of modern economies, and its demand grows faster than overall energy demand in all scenarios that IEA ran for its report. In 2024, the group said the world was moving into the “Age of Electricity”; that already has arrived, it said in the latest report.

“In a break from the trend of the past decade, the increase in electricity consumption is no longer limited to emerging and developing economies,” Birol said. “Breakneck demand growth from data centers and AI is helping drive up electricity use in advanced economies too. Global investment in data centers is expected to reach $580 billion in 2025. Those who say that ‘data is the new oil’ will note that this surpasses the $540 billion being spent on global oil supply — a striking example of the changing nature of modern economies.”

With the growing importance of electricity and pressures from growing demand adding to higher prices, electricity bills are rising to the top of the political agendas in many countries, the report said.

“This shift underscores a growing tension: While electrification offers long-term efficiency gains and emissions reductions, it also increases the sensitivity of movements in electricity prices, which are shaped by a complex mix of fuel costs, infrastructure investment, market design and policy choices,” the report said.

Electricity is becoming a larger share of household energy spending around the world because of electrification. The report expects average household demand to grow by 25% by 2035 and 60% by 2050, with significant variations by region.

Advanced economies have a decadelong trend of demand stagnation, but households there should see it grow by 15% by 2035 and 35% by 2050.

“While increases in energy efficiency moderate consumption for appliances, the electrification of transport is a major driver of expanding electricity use in regions with supportive policy frameworks and increasing EV sales shares,” the paper said. “This shift underscores the need for grid readiness and demand flexibility solutions like smart charging to manage peak demand and to improve affordability.”

Developing countries will see even higher household demand growth – 30% by 2035 and 90% by 2050 — because of air conditioning that comes from rising incomes and higher average temperatures.

“Rapid growth in electricity demand brings with it a need for substantial investment across the power sector,” the report said. “Grid infrastructure, in particular, is seeing a marked increase in capital spending to connect new loads, integrate new sources of electricity and enhance resilience. While rising investment does not necessarily translate into higher average system costs — especially if demand rises in parallel — the financing conditions and timing of the investment are critical.”

Some things are working to lower prices, with IEA saying natural gas prices should drop in many markets as more LNG becomes available and the growth in renewable power helps bring down wholesale electricity prices.

“As electricity demand rises, the fixed costs of new infrastructure can be spread across a larger volume of consumption, potentially reducing the cost per megawatt-hour,” the report said. “In some cases, this dynamic may even lead to lower electricity prices in real terms despite rising investment levels, highlighting the importance of well designed policies and market frameworks that enable efficient investment recovery while protecting consumers.”

How ERCOT’s RTC+B is a Game-changer for Market Operations

Portia Gilman

ERCOT is preparing to launch its Real-Time Co-Optimization + Batteries (RTC+B) initiative, perhaps the most sweeping market redesign in its history.

This transformation, scheduled to launch Dec. 5, will touch virtually every aspect of the market, from energy to ancillary services, introducing a more dynamic, efficient and integrated approach to market operations.

For battery operators in particular, RTC+B is a game changer. The redesign recognizes batteries not as separate charging and discharging assets but as unified energy storage resources (ESRs), allowing operators to more easily participate simultaneously in energy and ancillary services markets. This shift will enable batteries to capture more value, optimize dispatch and contribute to overall market efficiency in ways that were impossible under ERCOT’s legacy design.

ERCOT’s RTC initiative has been years in the making. It initially was focused solely on creating a real-time, co-optimized market that simultaneously would clear energy and ancillary services, accounting for each resource’s capabilities and system conditions to determine the most efficient dispatch. Following ISO-NE’s introduction of a co-optimized market in March 2025, ERCOT will be the last ISO to make this shift.

ERCOT paused its RTC initiative in the wake of Winter Storm Uri. The project was restarted in 2023, adding the battery (+B) component to reflect the rapid growth of battery energy storage capacity in ERCOT.

Texas is one of the fastest-growing battery storage markets in the country, second only to California in terms of installed capacity. In fact, ERCOT nearly doubled its battery capacity between 2023 and 2025 and is now approaching 10 GW.

Even more capacity is in the pipeline. Yes Energy is tracking more than 1,100 battery projects, totaling 180.5 GW, under construction or in development across the region.

Market Design Overhaul

RTC+B fundamentally reshapes how ERCOT manages energy and ancillary services, creating a market that’s more dynamic, efficient and aligned with modern resources like batteries.

At the heart of the redesign is the replacement of legacy constructs such as the operating reserve demand curve (ORDC) with ancillary services demand curves (ASDCs). These curves provide product-specific pricing for reserves — including regulation up ECRS and spinning reserves — enabling batteries and other flexible resources to see relative value signals and prioritize offers accordingly.

The RTM – Before (Pre-RTC) | Yes Energy

Under RTC+B, energy and ancillary services are co-optimized in real time, meaning ERCOT simultaneously clears energy and reserves through the SCED rather than relying on a separate ORDC process to clear reserves. Co-optimization already exists in the day-ahead in ERCOT and will continue after RTC+B.

This real-time co-optimization ensures that resources are dispatched efficiently across both markets, with the goals of improving overall market efficiency, reducing real-time energy costs and narrowing day-ahead to real-time price spreads over time.

ERCOT also will introduce virtual offers for ancillary services in the day-ahead market, which will increase liquidity by allowing more resources, including batteries, to participate flexibly.

To prepare for these changes, ERCOT conducted market trials in three stages: open-loop testing, closed-loop testing and final go-live validation. These trials allow participants and market operators to observe clearing prices, test new reports and ensure that the transition to RTC+B will be as seamless as possible.

Batteries Take Center Stage

Under ERCOT’s legacy framework, batteries were split between charging and discharging functions, treated as two separate resources with separate datasets in ERCOT’s systems. This “combo model” created extra complexity for resource owners, requiring manual processes to achieve consistency across operating plans, telemetry and bid curves. RTC+B eliminates this dual structure, replacing it with a single energy storage resource (ESR) designation that unifies a battery’s operations into one resource type.

Batteries will submit a combined energy bid-offer curve (EBOC), which integrates both charging and discharging into a single market signal. Negative EBOC values represent charging, allowing batteries to signal both their willingness to consume and supply energy. A low sustained limit (LSL) will replace the maximum power consumption (MPC) parameter, enabling operators to define realistic operational constraints within the unified framework.

This structure allows batteries to participate dynamically across both energy and ancillary services markets, supporting real-time co-optimization. Battery operators also can adjust day-ahead awards in real-time based on updated system conditions, pivot quickly between market products and respond to five-minute reserve updates.

RTC+B will transform how participants interact with ERCOT through data and operational reporting. Under the new framework, resources, including batteries, will integrate EBOCs, LSLs and regulation signals into ERCOT’s new market-clearing and settlement processes.

These capabilities not only give operators unprecedented flexibility and revenue potential, but also should improve market liquidity, enhance competition and help moderate price spikes for both energy and ancillary services.

The RTM – After (Post-RTC) | Yes Energy

In other words, with RTC+B, batteries no longer are just flexible resources. They become central drivers of ERCOT’s next-generation market efficiency.

Looking Ahead

With RTC+B, batteries move from being supporting players to central drivers of ERCOT’s next-generation market. By unifying charging and discharging into a single energy storage resource, introducing realistic operational bids and offers through the new EBOC, and integrating along with real-time co-optimization across energy and ancillary services markets, the redesign unlocks new operational flexibility and revenue potential.

As the Dec. 5 go-live approaches, battery operators who understand and use these changes will be well positioned to capture value, enhance market efficiency and shape the future of the Texas electricity system.

(For more information, see this on-demand webinar.)

Portia Gilman manages the Yes Energy market monitoring team. RTO Insider is a wholly owned subsidiary of Yes Energy.

NEPOOL Committees Support ISO-NE Prompt Capacity Auctions

WESTBOROUGH, Mass. — NEPOOL technical committees voted in favor of ISO-NE’s proposal to adopt a prompt capacity auction and update the RTO’s resource retirement process, indicating broad stakeholder support for the first phase of ISO-NE’s capacity market overhaul.

In a joint meeting Nov. 12, the NEPOOL Markets Committee voted 97.9% in favor of the proposal and approved one of three amendments proposed by stakeholders. The NEPOOL Transmission Committee voted to support the associated transmission-related changes.

The proposal encompasses the first phase of work in ISO-NE’s Capacity Auction Reform (CAR) project. The RTO began stakeholder discussions in September on the second phase of the project, which centers around accreditation changes and shifting to a seasonal capacity market. (See ISO-NE Kicks off Talks on Accreditation, Seasonal Capacity Changes.)

While ISO-NE plans to file the two phases separately, both are intended to take effect for the 2028/29 capacity commitment period (CCP).

Under the proposed changes, ISO-NE would hold capacity auctions about a month prior to the start of each CCP, compared to the more than three years that historically have separated Forward Capacity Auctions and CCPs.

The proposal also would decouple resource deactivation from the auction process. ISO-NE has said processing resource deactivations in the immediate leadup to prompt auctions would not give it enough time to address any issues triggered by retirements. In the Forward Capacity Market, resources submit delist bids more than four years before the relevant CCP.

ISO-NE proposes to require resources to submit deactivation notifications one year before the start of the relevant CCP. It has said the one-year deadline balances the tradeoffs between a longer timeline, which would give ISO-NE and market participants enough time to respond to retirements, and a shorter timeline, which would enable resources considering retirement to make a better informed decision.

While the changes received widespread support from NEPOOL members, several stakeholders outlined lingering concerns about the risk that ISO-NE will not be able to obtain FERC approval of the second phase of CAR changes in time for the 2028/29 CCP, leaving the Phase 1 changes to stand alone for the first prompt auction.

Stakeholders also expressed concern that the shorter retirement notification period will increase the risk of out-of-market resource retentions. They emphasized the need to encourage bilateral transactions to protect against price volatility.

The MC also voted 83.3% to adopt an amendment by the New England Power Generators Association (NEPGA) to maintain ISO-NE’s current rules allowing capacity supply offers to reflect resources’ physical limitations in high ambient temperatures.

ISO-NE had proposed to eliminate its option for resources to submit ambient air delist bids associated with capacity it would not be able to provide when ambient temperatures exceed 90 degrees Fahrenheit. These delist bids are not subject to cost review by the Internal Market Monitor.

NEPGA made the case that, without the amendment, market participants would “unnecessarily be required to submit a cost workbook for megawatts it is physically unable to produce at those high ambient temperatures.” It proposed “technical conforming language” extending the existing exemption to the new design. ISO-NE indicated it would adopt the changes into its proposal.

The MC rejected a pair of proposals related to the competitive offer price threshold (COPT), which sets the price above which offers are subject to Monitor review.

Under ISO-NE’s proposal, the RTO would continue to calculate the threshold based on the previous capacity auction clearing price and forecasting for the upcoming auction.

Several stakeholders have expressed concern that relying on four-year-old prices to set the threshold in the transition to a prompt auction could create issues related to stale data, pointing to higher prices in recent annual reconfiguration auctions and a recent increase in Pay-for-Performance penalties.

Calpine and LS Power each offered amendments to the threshold methodology. Calpine proposed basing the threshold on a calculation of the opportunity cost associated with scarcity revenues, while LS Power proposed a one-year fixed price for the 2028/29 CCP based on the outcomes of recent reconfiguration auctions.

Both proposals fell short of the 60% voting threshold for MC support. Calpine’s proposal received 53.8% support, and LS Power’s received 56.7%.

ISO-NE acknowledged the concerns about stale data and said it plans to take a more in-depth look at the threshold in the second phase of the CAR project.

If the second phase of CAR is not approved prior to the 2028/29 CCP, “the ISO anticipates that it would make further updates to the [Phase 1] design, which would include an assessment of the COPT given the latest information available,” the RTO noted in a memo published prior to the meeting.