Consolidated Edison claimed solid progress and reported solid results as it released its 2024 financials Feb. 20. It also said it’s gearing up for $38 billion in capital investments through 2029.
Clean energy progress was noted for 2024, with more than 352,000 customers assisted via energy-efficiency programs; 27,237 customers enrolled in the residential management EV charging program; and 14,868 heat pump installations supported.
Reliability in a system that largely is underground was outstanding, with the average number of service interruptions per customer in 2024 almost 90% lower than the state and national averages.
And Con Edison said it maintained a lower-than-average cost for its electric customers as compared with its peer average, both in total cost and percentage of median household income.
Con Edison serves New York City and adjoining Westchester County. Its subsidiary Orange & Rockland Utilities serves parts of two nearby counties in New York and a small area in northern New Jersey.
For 2024, Con Edison reported GAAP net income of $1.82 billion, or $5.26 per share. This compares with $2.52 billion and $7.25 in 2023.
But 2023 earnings were inflated by the $6.8 billion sale of Con Edison Clean Energy Businesses.
Adjusted (non-GAAP) earnings were $1.87 billion or $5.40 per share in 2024, compared with $1.76 billion and $5.07 in 2023.
The company expects adjusted earnings per share of $5.50 to $5.70 per share in 2025.
Con Edison declared itself a “Dividend Aristocrat and King” in its earnings presentation, noting that 2024 was its 51st consecutive year of dividend increases, with a compound annual growth rate of 5.59% thanks to its focus on long-term shareholder value.
Statements and numbers such as these seem likely to increase friction between the utility and the public officials and advocates representing ratepayers.
Con Edison on Jan. 31 proposed a rate case to the New York Public Service Commission that would entail average bill increases of 11.4% for electric customers and 13.3% for gas customers.
Gov. Kathy Hochul (D) on Feb. 11 called for the PSC to reject the proposed rate hikes and directed it to perform an audit of management compensation at Con Edison and other utilities statewide.
In another PSC filing, Con Edison reported that it ended 2024 with 496,007 residential customers in arrears more than 60 days for a total of $948.4 million, plus $539.1 million for 68,513 non-residential customers.
The 2024 presentation indicates that 466,000 customers of Con Edison and its subsidiary Orange & Rockland — about 14% of the total customer base — receive public assistance and about 14% of Con Edison’s customers are enrolled in the Energy Affordability Program.
CEO Tim Cawley said in a news release:
“We are optimistic about growth and are well positioned to continue to meet demand to power the electrification of buildings and transportation throughout our service territory with increased capital investments in grid infrastructure. This was underpinned by big wins last year, such as breaking ground and progressing construction of key substations and advancing a pair of new transmission lines under our Reliable Clean City program. We anticipate demand for electrification to grow steadily in 2025, driven by an increase in new construction downstate combined with policymaker’s requirements for clean heat in new commercial and residential buildings.”
FERC on Feb. 20 approved three proposed reliability standards addressing multiple aspects of inverter-based resource performance (RD25-1, et al.), along with another standard relating to entities’ planning for extreme hot or cold weather events (RD25-4).
NERC submitted the three IBR standards PRC-028-1 (Disturbance monitoring and reporting requirements for IBRs), PRC-002-5 (Disturbance monitoring and reporting requirements) and PRC-030-1 (Unexpected IBR event mitigation) in November. (See NERC Submits IBR Standards to FERC.) The ERO also submitted a proposed definition of IBRs, along with two other IBR-related standards, which were not included in FERC’s order; the commission is seeking comment from industry stakeholders on those standards.
PRC-028-1 applies to all generator owners that own NERC-registered IBRs, along with owners of IBRs that will be required to register under the registration criteria proposed by the ERO last June. (See FERC Accepts NERC ROP Changes, Drops Assessment Proposal.) The standard will require entities to install disturbance monitoring equipment on their IBRs in order to collect sequence-of-event recording, fault recording and dynamic disturbance recording data.
This information will be used to evaluate IBR ride-through performance during system disturbances and provide data for IBR model validation, NERC said in its proposal. GOs also will be required to fix any failures in disturbance monitoring capabilities.
PRC-002-5 updates PRC-002-4 to clarify its applicability to non-IBR grid elements, while also adding data collection and sharing requirements similar to those in PRC-028-1.
PRC-030-1 requires entities to develop a process for identifying “complete facility loss of output or certain changes of real power output” and to implement corrective plans to address performance issues when necessary.
The implementation plan for PRC-030-1 states that the standard will become effective on the first day of the first calendar quarter that is 12 months after either its approval or that of PRC-029-1 (Frequency and voltage ride-through requirements for IBRs), whichever is later. PRC-029-1 is one of the standards awaiting industry comment.
For PRC-002-5 and PRC-028-1, NERC requested the standards become effective on the first day of the first calendar quarter following their approval.
Standard Mandates Extreme Weather Planning
The final standard approved at FERC’s open meeting was TPL-008-1 (Transmission system planning performance requirements for extreme temperature event), which NERC submitted Dec. 17, 2024, following approval by the ERO’s trustees at their December meeting. (See “Standards Approved for FERC Submission,” NERC Board of Trustees Briefs: Dec. 10, 2024.)
NERC developed the standard in response to FERC’s Order 896, which directed the ERO to develop a standard to require entities to plan for extreme hot and cold weather.
TPL-008-1 will mandate that “planning entities in defined zones” work with each other to develop extreme temperature assessments at least once every five years. When such assessments identify instances where performance requirements would not be met during periods of extreme heat or cold, entities would need to develop and share corrective plans to address the problem.
Compliance dates for the standard will be phased over five years, a plan that NERC said would balance “the urgency in the need to implement the proposed [standard] against the reasonableness of the time allowed for those who must comply to develop the necessary processes and capabilities to perform these new wide-area extreme temperature studies.”
FERC approved the standards at its first monthly open meeting under Chair Mark Christie. Commissioner Judy Chang said she was “very pleased” with the cold weather standard, calling it “an incremental step, but … a step in the right direction.” Commissioner David Rosner agreed while pointing out that further work is needed to address the growing issue of extreme weather.
“While we’ve had really good progress so far on the cold weather front, the job is not done,” Rosner said. “Both FERC and NERC have repeatedly acknowledged the risk that extreme weather events pose to grid reliability, and NERC, at the end of last year, [released] an Interregional Transfer Capability Study that found that the [grid] is vulnerable to extreme weather. … I look forward to comments on that study and working with my colleagues here to make sure that we fulfill our duty … which is to ensure a reliable grid for American consumers.”
More than six months after the proposed August 2024 effective date for ISO-NE’s compliance with FERC Order 2023, generators seeking to interconnect in the region remain in limbo, and some stakeholders are concerned further delays could have detrimental effects on upcoming capacity auctions.
While FERC’s delayed response to the proposal already has affected certain aspects of ISO-NE’s compliance timeline, some stakeholders specifically pointed to an “inflection point” at the end of March 2025, and have expressed concern about increased complications if the delay extends beyond this date — especially if the order requires another substantial compliance filing.
FERC Orders 2023 and 2023-A require grid operators to adopt procedures for studying interconnection requests in coordinated cluster studies, instead of ISO-NE’s current process of studying projects sequentially. ISO-NE filed its compliance with the orders in May 2024 with unanimous support from the NEPOOL Participants Committee, after an extensive process of stakeholder feedback and amendments (ER24-2007, ER24-2009).
“Throughout this process and right up to the final vote, there was extremely robust stakeholder engagement in the compliance proceeding,” wrote a coalition of clean energy advocacy groups in comments to FERC supporting the filing. “ISO-NE’s Order No. 2023 reforms will mark an important first step in improving existing processes.”
The cluster study is open to projects with valid interconnection requests, while the CNR study would include projects that have completed system impact studies but need capacity interconnection rights or capacity network resource capability (CNRC).
For the subset of projects that just need CNRC, the delayed response is complicated by ISO-NE’s multiyear delay of its upcoming capacity auction, which is intended to facilitate a series of major reforms to the format and timing of the RTO’s capacity auctions.
Under existing rules, resources achieve CNRC by receiving a capacity supply obligation in the forward capacity auction (FCA), or in a reconfiguration auction for a previously held FCA. However, under ISO-NE’s Order 2023 compliance proposal, resources will receive CNRC through the cluster study process instead of the FCA qualification process.
The transitional CNR group study, which would begin before the transitional cluster study and take about six months, would enable eligible projects to receive CNRC without having to go through the full cluster study, which is proposed to last for about a year.
While the delayed response has prevented ISO-NE from aligning the CNR group study with the 2024 reconfiguration auction (RA) qualification process, ISO-NE has expressed interest in aligning the CNR study with the 2025 RA qualification, which is set to begin in April.
This would mean that “the entire transition schedule in the compliance proposal would need to shift by roughly one year,” ISO-NE noted in December.
In a FERC filing submitted Feb. 5, Flatiron Energy Development urged the commission to rule on ISO-NE’s compliance proposal “in no event later than March 2025,” arguing that a ruling after this date “greatly complicates the path to aligning the transitional CNR group study with the 2025 interim reconfiguration auction qualification process.”
Flatiron, which develops energy storage resources, expressed concern that delaying the CNR group study past the qualification for the 2025 RA could jeopardize the ability of participating resources to come online in time for the 2028/29 capacity commitment period (CCP 19). Delays to the transitional cluster study would mean an even tighter window for projects that are waiting on the results of this study to reach financial close and begin construction.
The company wrote that its storage projects in ISO-NE take about 18-30 months to come online after receiving final interconnection approval. Under this timeline, starting the transitional CNR study in April would enable resources to come online between 2027 and early 2028, just in time for CCP 19, which starts in June 2028.
“Each additional month of delay adds risk for projects planning to participate in ISO-NE’s proposed transition processes and decreases the likelihood that they will be able to offer capacity into [CCP 19],” Flatiron wrote. “Q1 of 2025 is an inflection point, where if a decision is not issued by then, the risk that many projects will not be able to complete the necessary processes in time to deliver their capacity through this auction substantially increases.”
The company estimated that up to 3 GW of capacity is eligible to participate in the CNR group study. It stressed that preventing a substantial amount of capacity in the interconnection queue from participating in CCP 19 could lead to more expensive capacity prices, reliability risks, and higher emissions.
Alex Lawton of Advanced Energy United agreed the region appears to be “approaching a juncture” for its Order 2023 timeline.
“It seems pretty clear now that the [transitional cluster study] and CNR group study are linked to the interim RA [qualification] process, which begins with a SOI [show of interest] window mid-April, so I think it’s a legitimate concern about whether the one-year implementation delay approach will still work if FERC misses the SOI,” Lawton noted.
ISO-NE spokesperson Randall Burlingame said the RTO’s ability to align the CNR group study with RA qualification “would be difficult if we don’t receive an order this quarter,” adding that the substance of the order, and the extent to which additional compliance word will be needed, also will affect the RTO’s ability to align its compliance with external processes.
Delays to the interconnection process in New England would almost entirely affect renewable and storage resources; of the more than 39 GW of potential new generation tracked by ISO-NE, wind and battery storage each make up about 43% and solar accounts for about 13%. Natural gas, oil, and fuel cell generation account for less than 1%.
The states also have expressed concern about an extended delay to Order 2023 implementation. In a letter to FERC in late November, the New England States Committee on Electricity (NESCOE) wrote that the delay “has resulted in ambiguity for generators as to when and by which process their projects will be interconnected and has left ISO-NE unsure as to how best to posture ISO-NE staffing and other internal resources.”
NESCOE noted that the uncertainty also affects distribution-level affected system operator studies, which will need to coordinate with ISO-NE cluster studies.
“This uncertainty undermines one of the principal tenets of Order 2023 around which there is general agreement — the efficient and timely interconnection of new resources,” NESCOE added.
In a filing submitted Feb. 19, the New Hampshire Office of the Consumer Advocate wrote that it agrees with Flatiron’s concern that a delay beyond the first quarter of 2025 could lead to a “very significant difference” in capacity prices for upcoming auctions.
“Should cost-competitive capacity not be able to efficiently interconnect, there will likely be both cost and reliability impacts to the region, including to the residential utility customers of New Hampshire,” the office wrote.
In the meantime, ISO-NE continues to process interconnection requests under the existing sequential rules, which may help some projects in the late stages of their interconnection studies avoid needing to participate in the transitional cluster study.
The RTO’s interconnection queue remains closed to new interconnection requests and would not reopen to new requests until fall 2026 if the entire process is simply pushed back by one year.
“Depending on the content of an order on the Compliance Proposal, the ISO is open to evaluating whether it is possible to shift the Order No. 2023 established eligibility date to allow for a limited reopening of the ISO Interconnection Queue,” ISO-NE said in December.
ERCOT set a new winter demand peak Feb. 20 with its first-ever mark above 80 GW, a number once reserved for summer months.
Demand peaked at 80.63 GW at 7:25 a.m. Feb. 20 as a late-winter Arctic blast sent temperatures plunging below freezing in much of the state and as far south as Houston. ERCOT had projected demand to reach 83.7 GW but overshot the mark. The grid operator had a healthy margin of nearly 7 GW of operating reserves during the peak.
The new mark broke an instantaneous peak of 79 set at 11:25 a.m. Feb. 19. Demand averaged 78.72 GW during the hour interval ending at noon.
The peaks are not official until ERCOT completes the settlement process for the operating days. The current winter demand mark is 78.35 GW, set in January 2024. The grid operator set an all-time peak demand record of 85.46 GW in August 2023.
Renewable energy, particularly solar and batteries, has played a key role in meeting that demand. Renewables provided 35% of the need during the Feb. 19 peak, and energy storage set a record (4,587 MW) during the Feb. 20 record. Solar resources produced 22.92 GW of energy Feb. 20, second only to the record 24.31 GW set Feb. 16.
During a Feb. 18 press conference, ERCOT CEO Pablo Vegas said there was enough supply to meet demand. He pointed out that the ISO has added more than 13 GW of new supply since last winter.
“That supply is going to continue to be helpful in these cold events. A lot of it is solar and batteries, both of which are going to help us when the sun comes up on a cold day,” Vegas said. “The batteries help us as a bridge in the morning. That’s what helps us keep the reliability high as we get through this event.”
With the exception of five, 15-minute intervals that exceeded $1,000 in the Lower Colorado River Authority load zone, real-time prices have been relatively stable, briefly reaching a high of $457 Feb. 19-20.
ERCOT declared a weather watch Feb. 17 for Feb. 19-21 because of the forecast extreme cold weather, higher demand and potential for lower reserves. It expected grid conditions to be normal.
Temperatures in Houston, which is near the Gulf of Mexico, still have highs forecast in the 40s through Feb. 22, before the normal warmth returns.
Beacon Wind has paused its efforts to build an underwater transmission line into New York City.
Its Feb. 19 filing with the New York state Public Service Commission (Case 22-T-0294) withdraws the application for a certificate of environmental compatibility and public need for the 320-kV HVDC line it proposed in May 2022.
The line was to run 115 nautical miles through Long Island Sound to the Astoria Gateway for Renewable Energy, a point of interconnection (POI) at the northwest tip of Long Island where a gas-fired power plant once stood.
In a Jan. 31 PSC filing, Beacon Wind LLC indicated it was considering alternative POIs as the project evolves, in part due to feedback it received during the NYISO interconnection process.
In the same filing, it indicated a pause would be useful “given the uncertainty with respect to federal permitting for offshore wind.”
Just 11 days earlier, President Donald Trump in an executive order halted awards of new offshore wind leases and cast uncertainty over existing leases and projects.
Beacon Wind is being developed by oil supermajor bp, which has scaled back its investment in renewables in the past year. The U.S. public relations staff for bp told NetZero Insider via email:
“On Feb 19, Beacon Wind withdrew its New York Article VII application — the state’s transmission interconnection application — and NYISO offshore wind queue position. This decision was made to allow for more time in the evaluation of the project’s design and configuration. Since the project submitted its application and queue position, New York’s approach to offshore wind project interconnection has evolved in the direction of coordinated offshore transmission. We support the Public Policy Transmission Need project approach sponsored by NYISO which is designed to help reduce the cost of electricity delivery from offshore wind projects to the New York grid.”
Beacon Wind has had some challenges.
Bp was pursuing Empire Wind and Beacon Wind as a joint venture with fellow oil and gas producer Equinor. The two also proposed the Astoria Gateway and a large port facility in Brooklyn.
They won New York offtake contracts for Empire 1 and 2 and for Beacon 1, but not Beacon 2.
Then the U.S. offshore wind industry stumbled, just as it was starting to build real momentum in the third year of the Biden administration, thanks to soaring costs, supply chain constraints and insufficient infrastructure. Most developers holding offtake contracts along the Northeast coast canceled them, including Equinor/bp.
The two companies also dissolved their partnership, with Equinor taking full ownership of Empire and the port and bp taking Beacon and the Astoria Gateway. (See Offshore Wind Reset Complete in New York.)
Equinor since has won a new state offtake contract for the 816-MW Empire Wind 1 and has begun construction of the port. The PSC on Feb. 13 gave final approval for construction of the portion of Empire Wind 1’s transmission line in state waters (Case 21-T-0366).
Empire Wind 2, on the other hand, is on indefinite hold. On Sept. 12, after more than two years in the works, Equinor withdrew its request for the Certificate of Environmental Compatibility and Public Need that would allow it to construct an export cable. (See Equinor Yanks Request for Empire Wind 2 Export Cable.)
In June 2024, after reports that bp was refocusing toward fossil fuels and away from offshore wind, a U.S.-based spokesperson told NetZero Insider the developer was taking the time to fully evaluate the Beacon Wind project and had not come to a decision. (See Bp Says It is Still Evaluating Beacon Wind.)
That was four months before Trump was elected president and seven months before he followed through on a campaign pledge and moved to thwart offshore wind development in U.S. waters.
In December 2024, bp and Japan’s largest power generation firm, JERA, announced they would form JERA Nex bp, an offshore wind joint venture. They said they expected to finalize the deal before October and would pursue “highly disciplined, capital efficient growth.”
The assets listed by JERA and bp total 13 GW of potential generating capacity. Beacon — at 2,580 MW, the largest facility on the list, and the only one in U.S. waters — was listed not as a development project but as a secured lease.
The new partners said they expected to concentrate on existing projects in Europe, Australia and Japan and to continue to pursue longer-term opportunities.
FERC Chair Mark Christie ran his first open meeting Feb. 20 and addressed President Donald Trump’s executive order on independent regulatory agencies.
Trump on Feb. 18 had ordered that independent agencies “submit for review all proposed and final significant regulatory actions to the Office of Information and Regulatory Affairs” before they can be published in the Federal Register. (See related story, Trump Claims Authority over Independent Agencies in Executive Order.)
“A lot of this in the EO is basically putting in one place past practices that have been going on for years,” Christie told reporters at a press conference after the meeting. “Let me just give you examples. We already submit our budget to OMB [the White House’ Office of Management and Budget]. We’ve been doing that for years. They can approve it or not approve it. We already submit our strategic plan to OMB, and we’ve been doing it for years, and they can question it. So that’s not new.”
FERC and its predecessor agencies have submitted major regulations with an economic impact to the White House for a century, he added.
The commission also has complied with executive orders issued by past presidents regularly, and previous chairs have consulted with the White House. Christie noted that he already has had a meeting with the secretaries of energy and the interior, updating them on business before the commission.
“The consultation part has been going on for years, as of course, it should,” Christie said. “It’s fanciful to think that if a president can appoint a chair, the president is going to appoint a chair who’s going to do something 180 degrees opposite of what the general policy of the administration is. I mean, it’s just ludicrous to think that … and that has never been the case.”
Two of FERC’s main goals under Christie are for the power grid to be reliable and to accomplish that affordably, which are in line with the president’s policies, he said.
“The second point I want to make is there’s a lot of detail yet to be known about the parts that aren’t obviously what we’ve been doing,” Christie said. “I want to get more detail. We’re going to ask the appropriate places for more detail and see how this plays out.”
Christie said he doubts the White House would want to weigh in on the bread-and-butter cases brought to FERC under the Federal Power Act and Natural Gas Act. He argued that any additional oversight from the EO probably would be aimed at larger policy cases it launches at its own discretion. But FERC does not have that clarification yet, he said.
“Why would any commission initiate a big, sweeping regulation that’s contrary to what the presidential administration wants?” Christie said. “And by the way, I can’t think of an example in my history of watching administrative law where that’s ever happened.”
Historically, FERC and other agencies have initiated substantial rulemakings that are in line with the president’s policies, Christie said. He pointed to how the commission’s greenhouse gas policy statement for natural gas infrastructure and Order 1920 on transmission dovetailed with former President Joe Biden’s policy, as laid out in an executive order setting a goal.
Christie clarified that FERC will hold the line and not violate ex parte rules on pending cases.
“We do not allow ex parte communications; that would violate the [Government in the] Sunshine Act,” Christie said. “It would also violate everything I know about due process in contested proceedings going back to being a state regulator. We didn’t allow it in Virginia, so we’re not going to start allowing ex parte communications.”
One worry flagged by FERC watchers, speaking to RTO Insider about Trump’s order, was that it could open the door to more politicization of the commission’s regulatory process, which eventually could affect the cost of capital in major infrastructure investments.
“We live in a democratic system, and we live in a political world in the sense of politics, with a small ‘p,’ Aristotelian version of politics,” Christie said. When people talk about the politicization of FERC, he continued, they are referring to letting special interests get their way, regardless of the law and facts before the commission. With 2024’s Order 1920, Sen. Chuck Schumer (D-N.Y.), who was majority leader at the time, submitted a letter before the original version was issued — which Christie said was likely ghost-written by lobbyists — calling for FERC to enact reforms that wound making up the bulk of the order. (See FERC Issues Transmission Rule Without ROFR Changes, Christie’s Vote.)
“We don’t live in a parallel universe in some pristine vacuum,” Christie said. “And it’s totally appropriate for senators … to write us a letter and say, ‘Here’s what I want to see.’ The bigger danger at FERC and other regulatory agencies is the danger of regulatory capture, and it’s the influence of special interests.”
FERC always has been more open to listening to parties informally when it does not violate ex parte rules than the Virginia State Corporation Commission. During a rulemaking, lawyers and other experts for parties commenting on rulemakings can come in and talk to commissioners, and they do so regularly.
“That’s been going on for decades; query whether it should,” Christie said. “You know, the [Securities and Exchange Commission] has had a rule where any lobbyist or lawyer that comes and talks to you has to sign a form, and it’s publicly published at the end of every month.”
Christie has looked into whether FERC should adopt that practice from the SEC, he added.
“In a contested proceeding, they cannot do that because ex parte communications in a contested proceeding are totally inappropriate,” Christie said. “And that ain’t gonna happen on my watch.”
Other Business at Christie’s First Meeting
In addition to addressing the executive order, Christie also announced that the next meeting of the FERC-State Current Issues Collaborative, which the agency runs with the National Association of Regulatory Utility Commissioners, will be at the commission’s headquarters April 30.
The commission also announced a major technical conference covering resource adequacy issues in all of the ISOs and RTOs that will take place June 4-5 at FERC headquarters.
“For years I have been warning that rising demand forecasts and the failure to retain existing generators or build adequate new power generation is threatening resource adequacy and the reliability of our power grid,” Christie said in a statement. “I look forward to addressing this important topic with my colleagues and others who can contribute important information and give their views on how we move forward on this critically important issue.”
The technical conference will cover current and impending risks to resource adequacy; issues capacity markets have had ensuring reliability at an affordable cost; performance comparisons between the different capacity markets; alternative resource adequacy constructs; and states’ desired roles in dealing with resource adequacy.
Page 50 of the 2025 Sustainable Energy Factbook absolutely nails the unevenness of electricity demand growth across the U.S. The two charts on the page show that demand growth in ERCOT is concentrated in the far west and northern parts of Texas, while in PJM, the spike is almost exclusively in Northern Virginia.
The jump in demand in Texas is due to “the electrification of the oil and gas sector in the far west predominantly; also, bitcoin mining has contributed,” said Tom Rowlands-Rees, head of research for North America at BloombergNEF, which compiles the annual report. “In PJM, it’s data centers.”
“A lot of people’s expectations of power are that it is growing … [but] this load growth is concentrated in certain regions typically,” Rowlands-Rees said, during an advance media briefing on the report, released Feb. 20 by the Business Council for Sustainable Energy. “That nuance is important. It’s not everywhere.”
The 13th edition of the BCSE Factbook comes, as always, packed with charts, figures and industry insights, many of which stand in sharp contrast to President Donald Trump’s focus on fossil fuels and U.S. energy dominance. Rowlands-Rees called it “a snapshot of where things were at the end of the previous administration; so, that as we talk about what’s going to be happening in the future with a new administration, we actually have a benchmark against which to compare, a true picture of where things were and where they weren’t.”
With demand growth forming the backdrop for the U.S. clean energy industry at this point, BCSE President Lisa Jacobson stressed the need for a broad, all-of-the-above portfolio. “Energy efficiency, natural gas and renewable energy are the growth sectors of the U.S. economy, and as we move into a phase of anticipated increased energy demand, this portfolio is ready to meet this demand. We need more energy now.”
The key federal policies that are needed include maintaining energy tax credits and strong funding levels for technology research, development, demonstration and deployment, Jacobson said. Congress and the Trump administration also should “enact federal permitting and siting reforms, and … work with states and localities to provide the resources that they need at the community level to expand and modernize energy infrastructure,” she said.
As federal energy policies and agencies remain in flux — with Trump even challenging the independence of FERC and similar regulatory commissions — RTO Insider dug into other major trends reflected in charts across the Factbook.
US energy overview: Electricity generation mix | Bloomberg NEF
Electricity Generation Mix
The U.S. already appears to be enjoying some level of energy abundance, generating a record amount of electricity in 2024 ― 4,393 TWh — a 3.3% jump over 2023. At first glance, it looks like natural gas is the dominant source of power, accounting for 43% of generation. But with renewables growing to 24% and nuclear holding steady at 18%, carbon-free power is neck-and-neck at 42%.
BNEF also notes that as coal plants have closed, natural gas and renewables together are filling the gaps, generating “67.1% of the generation mix by the end of 2024, compared with 41.1% just a decade ago.”
Even the American Gas Association is calling for all-of-the-above energy policies.
“We need a robust energy portfolio, inclusive of not just natural gas, but of all the different technologies and supply sources and demand-side management approaches,” said Richard Meyer, AGA vice president for energy markets, analysis and standards. “We’re going to need that to ensure affordable and reliable energy for Americans.”
Policy: US progress toward emissions goals | Bloomberg NEF
US Progress Toward Emissions Goals
However, the growth in carbon-free power has not translated into major cuts in greenhouse gas emissions. Even before Trump ordered the U.S. withdrawal from the United Nations Paris Climate Accords, the U.S. had veered off course in its efforts to cut greenhouse gas emissions 50-52% by 2030, a goal set by former President Joe Biden.
The country’s modest drop in emissions overall has been driven primarily by the power industry’s switch from coal to natural gas, BNEF said. Emissions from all other sectors in the economy have fallen only 4% since 2007, and non-power emissions grew 0.24% in the past decade.
As Energy Secretary Chris Wright bluntly discounts Biden’s target for emissions cuts, it is unlikely the U.S. could meet the 2030 goals. According to BNEF, power sector emissions would have to fall 11% per year and economy-wide emissions would have to drop 6% per year.
US energy overview: Retail and wholesale power prices | Bloomberg NEF
Wholesale and Retail Power Prices
Power prices have been another component in Trump’s plans for U.S. energy dominance and abundance, with campaign promises to cut electricity bills in half.
The challenge here is that a sharp divide has opened between wholesale and retail electricity prices, according to BNEF. Spiking capacity auction prices in PJM notwithstanding, wholesale power prices rose only 0.1% in 2024. But “beneath this calm, regional shifts tell a more complex story,” the Factbook says. “California and Texas saw wholesale prices plummet by 45.9% and 51.4%, thanks to high renewable output, while New York and New England experienced increases of 11.1% and 6.1%, driven by reliance on natural gas and constrained supply.”
Similar regional differences were seen in retail electricity prices, which fell modestly by 0.68% on average in 2024. Retail prices dropped 2.5% and 2.4%, respectively, in Texas and New England, while California and New York saw increases of 7.6% and 4.8%, reflecting higher transmission and distribution costs.
Such regional variations could, at least in part, account for the difference between BNEF’s figures showing modest overall decreases in electricity prices and consumer perceptions of higher electricity bills. But BNEF found that energy accounted for only 3.82% of consumer spending in 2024, a 0.3% drop from 2023, and electricity accounted for only about a third of that total, while motor fuel made up 2%.
US energy overview: Jobs in select segments of the energy sector | Bloomberg NEF
Jobs in the Energy Sector
One of the strongest arguments for continued federal support for the energy industry has been its recent record of job growth, with the auto industry remaining the top job generator and energy efficiency a surprising second. But the growth in jobs for transmission, distribution and storage also has been significant, rising from 1.3 million in 2020 to 1.43 million in 2023.
When it comes to the jobs breakdown by fuel type, solar remains far ahead of the pack, with 364,544 jobs.
Finance: Energy transition investment | Bloomberg NEF
Energy Transition Investments
While Wright may not believe there is an energy transition, China committed $818 billion to its transition in 2024, a significant jump from the $684 billion it invested in 2023. By comparison, U.S. transition investments have stagnated, barely rising from $336 billion in 2023 to $338 billion in 2024.
Whether slapping tariffs on Chinese imports will improve U.S. competitiveness in global clean energy markets remains an open question.
Certainly, BNEF says the election and policy uncertainty put a dent in U.S. investments in certain sectors last year, with clean energy falling from $110 billion in 2023 to $97 billion in 2024.
But other investments signaled growth in key sectors like building electrification and grid expansion — both of which could cut consumer electric bills. Private dollars for electrified heat rose from $27 billion in 2023 to $32 billion in 2024 and investments in the power grid jumped from $85 billion in 2023 to $95 billion in 2024.
However, beyond investment, China also leads the world in installations of long-duration energy storage, a key technology for grid flexibility, with 2.5 GW in 2024 versus 625 MW in the U.S.
Economics: US levelized costs of electricity for unsubsidized new build, 2H 2023 | Bloomberg NEF
US LCOE for Unsubsidized New Energy Projects
In 2024, the levelized cost of electricity for natural gas edged below solar and wind, due largely to falling prices for natural gas. But the LCOE for new, unsubsidized generation and flexibility — what could be built to meet demand growth — presents a different picture, underlining the potential costs and benefits of a broad, diversified portfolio.
Unsubsidized solar is competitive with natural gas but will be cheaper if tax credits are maintained. Looking to new nuclear for clean, dispatchable power is going to be expensive, with a top LCOE of $523/MWh, and demand flexibility, storage and carbon capture will all come with higher costs.
President Donald Trump on Feb. 18 issued an executive order that seeks to bring independent regulatory agencies like FERC under greater White House control.
Trump said in “Ensuring Accountability for All Agencies” that “so-called” independent agencies’ minimal supervision from the elected president goes against the Constitution, and they “shall submit for review all proposed and final significant regulatory actions to the Office of Information and Regulatory Affairs (OIRA)” before they can be published in the Federal Register.
It is unclear how much of an impact this, or any of Trump’s executive orders that stretch the interpretation of existing laws, are going to have on FERC. Established in 1980, OIRA reviews the regulations from cabinet agencies like EPA or the Department of Energy, but historically, it has exempted independent agencies’ decisions from substantive review, according to a report from the Congressional Research Service.
Regardless of its actual effects, the executive order in and of itself is “an unprecedented effort” to curtail the independence of regulatory agencies, Ari Peskoe, director of Harvard Law School’s Electricity Law Initiative, said in an interview.
“It depends on what the administration thinks it’s going to do here: whether it’s going to dictate policy, which is not quite possible for FERC since it still has a majority of Democratic commissioners; whether the administration is going to take it even further and continue firing commissioners and independent agencies, as it already did for the” National Labor Relations Board, Peskoe said. “So again, it’s just a lot of questions.”
“My biggest fear is if the Supreme Court makes this broad determination about the separation of powers and Congress’ ability to set up independent agencies, because that would last forever, or at least until a future Supreme Court changed that, which usually takes decades to happen,” Grid Strategies President Rob Gramlich said. “So, unlike a lot of other changes right now that might last four years, that would do damage forever. And we really need independent regulatory agencies to have regulatory certainty and investor certainty about how to do business in electric power.”
“Capital-intensive business models require a degree of certainty that independent agencies bring,” former FERC and Pennsylvania Public Utility Commissioner Nora Mead Brownell said. “When I became a PUC commissioner, I realized how critical it is for those kinds of agencies to truly be independent and base their decisions on the facts.”
Moving away from that kind of independence, where decisions are based on a public record that lays out the facts and follows legal precedent, will at least make infrastructure investments more expensive, she said. “Why would you want to invest in something that is so subject to the whims of a leader who does not actually have a basic understanding of the economy?”
Project 2025, which was authored by Trump appointees including Office of Management and Budget Director Russell Vought and Federal Communications Commission Chair Brendan Carr, has a section on independent agencies calling them “constitutionally problematic” using the same logic in the executive order. But it focuses more on the higher-profile agencies like the FCC and Securities and Exchange Commission.
FERC is rolled into the same chapter as the Department of Energy, which was written by former Commissioner Bernard McNamee, nominated by Trump in his first term. It calls for FERC to refocus on reliability and affordability, with more specific suggestions including ensuring “sufficient dispatchable on-demand generation” and reforming RTO markets to pay such generators “reliability pricing.” (See Plan for GOP President: Cut Climate Programs, ‘Re-examine’ RTOs.)
While Project 2025 and Trump’s executive order are based on the logic that independent agencies are not democratically accountable because of the president’s limited oversight, Peskoe pointed out that they combine functions from across all three branches.
“They are somewhat legislative, somewhat executive and somewhat judicial, that they sort of combine all three aspects, and that’s what kind of makes these agencies unique in our government,” Peskoe said.
Congress would be well within its powers to set rates for utilities in interstate commerce, but it just lacks the bandwidth to do that, so it created FERC to handle those issues, he continued.
“These types of agencies have been around for a very long time,” Peskoe said. “They don’t really cite any particular problems with these agencies. It’s just this sort of constitutional accountability issue, which, again, hasn’t really come up in generations. So, it’s just a naked power grab by this administration.”
The White House does get to influence FERC by picking commissioners and naming the chair. Brownell said President George W. Bush picked her and former Texas Public Utility Commission Chair Pat Wood, whom Bush appointed as chair of FERC, because both had pushed forward electric competition in their respective states, and the president wanted to expand its role at the wholesale level.
Gramlich was a staffer for Wood, and he recalled visiting the White House — but not to take directions.
“We’d be briefing them on what’s happening so they could understand the impacts and guide legislation, but they were never telling us what to do,” Gramlich said.
Former FERC Chair Rich Glick, appointed by President Joe Biden, took some flack from The Wall Street Journal’s editorial page for meetings with the White House, but Gramlich said those were similar to what he and Wood did 20 years earlier. (See Glick Denies Taking Directions from Biden Admin.)
“Even if a chairman wanted to take cues from the White House, that’s always been sort of up to them,” Gramlich said. “But this would be structural. I mean, you could have the White House essentially overturning and approving actions that don’t reflect the votes of the commission.”
If the executive order is allowed to go into effect, and the courts wind up siding with the White House, some in the utility business might think of it as a win for a while, but politics change more quickly than the lifespan of much of the infrastructure FERC oversees, Brownell said.
“You have four years of an administration with everybody and their brother tinkering in the business without understanding it, and you create an instability that is very dangerous, particularly at a time that we desperately need new infrastructure.”
FERC on Feb. 18 approved PJM’s annual update to its tariff’s cost responsibility assignments for transmission projects set to be completed in 2025. The approval came despite protests regarding the use of the 1% de minimis threshold and the inclusion of a project that was the subject of a $6.6 million civil penalty imposed by the commission last year (ER25-775).
The update, filed Dec. 20, allocates costs for dozens of projects in the RTO’s Regional Transmission Expansion Plan, but the one that attracted the greatest attention was Public Service Electric and Gas’ 230-kV Roseland-Pleasant Valley (RPV) line. The commission approved a settlement between its Office of Enforcement and the utility on Dec. 5, 2024, subjecting the utility to a $6.6 million civil penalty to resolve allegations of it “failing to fully and accurately provide information” to PJM staff about the project (IN21-5). (See FERC Fines PSE&G $6.6M for Inaccurate Info on Transmission Line.)
In protest of the update, Public Citizen argued that RPV included imprudently incurred expenses and requested that component of the cost assignment filing be set for evidentiary hearing. The New Jersey Division of Rate Counsel said PSE&G should be required to demonstrate that its project and the scope of work were appropriate, which it argued could not be done through formula rate proceedings that lack the opportunity for a full prudence review. The agency also asked that FERC review PJM’s process for reviewing similar projects.
The utility answered that Public Citizen was improperly attempting to transform the cost allocation process into a prudence inquiry, which it said is outside the scope of the proceeding and should be done through a separate, standalone complaint. It also argued the organization had not identified any specific costs that were improper and had not met the standard for initiating such an inquiry. The commission agreed, finding both protests out of scope.
The Long Island Power Authority (LIPA) and Neptune Regional Transmission System argued PJM’s continued use of the 1% de minimis threshold and netting provisions of its solution-based distribution factor (DFAX) is in violation of the D.C. Circuit Court of Appeals’ ruling in Consolidated Edison Company of New York v. FERC, under which they said it is unlawful to base peak loads in the DFAX analysis on the threshold. They also protested that PJM had not provided evidence of how costs align with their derived benefits and had not detailed the drivers behind significant cost allocation changes. (See Paper Hearing Opened on PJM DFAX Method.)
PJM responded that the issues raised by Neptune and LIPA are the subject of other pending FERC litigation, and in the meantime, it is obligated to apply the effective tariff language. The commission wrote that PJM had applied its tariff properly and adequately provided detail regarding DFAX and its cost allocation methodology, which it noted permits challenges to the inputs.
The Bonneville Power Administration on Feb. 18 kicked off the last public contract development workshop series under its “Provider of Choice” initiative, allowing stakeholders to provide input on the agency’s long-term power contracts that it will issue later in 2025.
BPA will hold three workshops this week, with the last one scheduled for Feb. 20. The final workshops indicate BPA is wrapping up development of the draft long-term contract that will go into effect in 2028 and set the conditions under which the agency sells federal power to customers. Following a public comment period, the goal is to have final templates ready by June 18 and signed contracts by December 2025, according to BPA presentation material.
Michelle Lichtenfels, program manager of the Provider of Choice initiative, noted that BPA has hosted dozens of workshops on the issue, saying “this feels like a big week.”
Lichtenfels thanked the participants, adding, “This is really a momentous time for being our last contract workshop series, but also the last chance we get to engage before we get into that public comment period.”
The Feb. 18 meeting focused on ironing out details on several topics related to the contracts, including day-ahead markets, planning reserve margins and charges related to the Western Resource Adequacy Program, among other issues.
Bonneville delivers power to regional public power customers under contracts executed in 2008. The agreements provided approximately 76% of BPA’s power services’ revenue requirement in 2022, according to a Provider of Choice concept paper.
The long-term contracts by statute cannot exceed a 20-year term, and BPA launched the provider of choice initiative to begin contract discussions with stakeholders before the current agreements expire in 2028, according to the paper.
