US Utilities – Powering the Future Capital Investment Super-Cycle
The U.S. utility sector modestly outperformed the broader market in the first half of 2025, driven by strong investor interest in both regulated utilities and non-regulated merchant power companies leveraged to accelerating electricity demand. The S&P 500 Utility index rose 9.2% compared to the S&P 500’s 6.2% return. While generally insulated from tariffs, utility stocks experienced some volatility due to shifting inflation expectations and growing uncertainty around the future of clean energy tax credits. Defensive, rate-based utility stocks strongly outperformed the broader market during the first quarter, as tariff concerns and recession fears weighed on equity markets. However, risk appetite rebounded sharply late in the second quarter as tariff threats eased and economic data remained solid, fueling a broader rally.
Table 1 Utility Stock Performance Versus S&P 500
Our universe of 61 regulated electric, gas, and water utilities delivered a stable median total return of 9%, while the four publicly traded non-regulated power producers (CEG, VST, NRG, TLN) posted a more volatile—but strong—54% average return. In contrast, the three large-cap California regulated utilities (PCG, EIX, SRE) declined an average -25%, as investor confidence in the state’s wildfire liability fund weakened following the destructive January 2025 fires.
The utility investment thesis is increasingly compelling. U.S. electricity demand is accelerating at its fastest pace since the 1950s–70s, driven by the rise of AI-powered mega data centers, manufacturing reshoring, and transportation electrification. In response, utilities are investing record capital to expand generation and modernize grid infrastructure, with hyper-scalers (AMZN, MSFT, META, GOOG) actively partnering to secure long-term power capacity. Policymakers and regulators appear supportive, creating a favorable backdrop for the strongest rate base and earnings growth outlook the sector has seen in decades. Notably, rising electric demand enables utilities to spread infrastructure costs over a larger customer base, helping to mitigate affordability concerns. Still, execution risk remains as managements must raise funds, build infrastructure and manage costs to deliver targeted EPS growth.
Exhibit 1 A Lower Yield Curve Would Help Utility Stocks
Source: Gabelli Funds
Recent Federal policy adds further momentum, with initiatives to streamline nuclear permitting, expand gas-fired generation, extend coal plant lives and reduce regulatory friction. In addition, utilities would benefit from a lower interest rate environment. In 2025, the 10-year U.S. Treasury yield declined to 4.23% from 4.58% at the end of 2024, while the Federal Reserve overnight rate remained at 4.25–4.50%. The markets expect at least two 25-bp cuts in 2025 and additional cuts in 2026-27. A lower yield curve supports utility valuations, reduces capital-raising costs, and offers some relief on customer bills. Additionally, declining Treasury yields enhance the defensive appeal of utilities, whose median dividend yield stands at 3.5%, with total return expectations of 9–11%.
TOP TEN REASONS TO OWN UTILTIES: SUPPORTING THE POWER SURGE
- Electric demand growth to accelerate driven by data centers, electric vehicles and manufacturing onshoring.
- Policymakers (politicians, society) supportive of infrastructure investment because AI is considered a national security and defense issue.
- New Administration eases regulations and environmental rules.
- Societal push for clean energy to continue
- Long runway of rate base investment (infrastructure investment).
- Consolidation/Takeovers could accelerate due to existing assets being more attractive.
- Healthy earnings and dividend growth potential (5-7%) could ramp up.
- Reasonable valuation of 17x 2025 P/E multiple (historical range 10-23X).
- Competitive current return of 3.4%.
- Financial engineering opportunities.
- Potential for lower interest rates & economic slow-down.
- Defensive profile insulated from tariff impacts.
CONCERNS
- AI data center related electric demand growth proves to be too optimistic.
- Potential for higher interest rates.
- Equity raises to fund growth (In 2025, ETR, AEP, and more to come)
- Some utilities could mismanage growth.
- Weather event risks, particularly wildfires.
Exhibit 2 STOCKS TO CAPITALIZE ON THE UTILITY INFRASTRUCTURE BUILD OUT
Source: Gabelli Funds
HIGHER CAPITAL INVESTMENT = STRONGER RATE BASE GROWTH = HIGHER EPS GROWTH
We believe the utility sector is in the early innings of a prolonged cycle of electric demand growth and capital investment (super-cycle)—setting the stage for an extended period of earnings per share (EPS) growth. Following first quarter EPS results, most electric utilities publicly target annual EPS growth ranges of 5–7% or 6–8%, with some aiming higher at over 8% and a few others more conservatively at 4–6%. These growth rates are historically high and have trended upward over the past decade, driven primarily by rising capital expenditures, which translate into rate base growth.
In 2024, electric and gas utility EPS grew nearly 9% driven by stronger sales growth and rate relief. Based on LSEG T1 consensus EPS estimates, electric and gas utility median EPS CAGR is 6.9% over 2024-2027. Below we list the number of utilities by EPS target CAGR range:
Target EPS CAGR Number of Utes
4-6% CAGR – 4 utilities
5-7% CAGR – 18 utilities
6-8% CAGR – 15 utilities (includes WEC’s 6.5-7.0% target)
7-9% CAGR – 5 utilities (includes ETR’s 8.0%-plus and PCG’s 9%)
Non-regulated power producers NRG Energy (NRG) and Constellation Energy (CEG) are not included with the regulated table above, but target EPS CAGRs of 14% and 13%, respectively. Most regulated utility managements expressed an “upward bias” to EPS outlooks based on the on tailwinds of higher capital budgets and accelerated electric demand.
Strong EPS growth requires state Public Utility Commission (PUC) rate support and the ability to earn approved returns, particularly as capital investment surges. Some individual larger data center loads exceed 20% of a mid-size utility’s existing capacity. To manage risk and protect existing customers, utilities are adopting new “large load” tariffs, which push risk on the large customer and away from the existing customer base (discussed more in regulatory section on page 7).
Beyond regulatory dynamics, utilities must raise capital, manage complex construction programs, and control costs. Some are scaling so rapidly they are effectively doubling in size within five years. If executed well, this growth cycle could support elevated EPS and dividend growth for many years.
RECORD INVESTMENT (RATE BASE GROWTH) LEADS TO EPS GROWTH
In 2024, EEI member electric utilities invested a record $186.4 billion, up from $167.8 billion in 2023—marking the twelfth consecutive year of record capital spending. Over the next 5-10 years, we expect significant capital expenditure increases reflecting rising electricity demand and the need for base-load generation.
Exhibit 3 Record Capital Investment
Investment spans all major areas of the system, including distribution ($51 billion, or 33%), generation ($37 billion, or 24%), transmission ($32 billion, or 20%), gas-related infrastructure ($22 billion, or 14%), and other categories ($13 billion, or 8%). With nearly 70% of North America’s electric infrastructure over 25 years old (DOE), utilities are allocating more capital to grid modernization and resilience to better withstand hurricanes, wildfires, and other weather events.
Over the past decade, utility capital spending has been partially driven by climate policy, net-zero carbon targets, and the transition away from fossil fuels. The shift has led to coal plant retirements and a major buildout of wind & solar capacity. Spending has also been elevated by the need to prepare and repair systems after natural disasters and to harden the grid against future events. More recently, utility managements are ramping up capital budgets and rate base growth CAGR’s to historical highs to meet a surge in demand. Notably, mega-cap tech firms are aggressively partnering with utilities and power providers to secure long-term, reliable electricity for AI-driven data centers—some of which consume as much energy as small cities. This trend supports continued rate base growth and long-term earnings expansion for the sector.
AND MORE EQUITY ISSUANCES
Regulated utility rate base growth occurs when infrastructure investment outpaces depreciation, requiring ongoing external financing. Credit rating agencies account for utilities’ monopoly service territories, regulatory protections, and their public-good role. The industry’s average parent-level credit rating has remained at BBB+ since rising from BBB in 2014, reflecting strong access to capital. Utilities typically fund capital programs through a mix of operating cash flow, debt, and equity—often including forward and convertible equity issuance. These issuances can be accretive when executed above book value and when regulators permit returns on the invested capital.
Trump Administration Energy Policy: Slower Net-Zero, Stronger Reliability Bridge
Recent Trump administration actions to extend the life of coal plants and promote new gas and nuclear development will slow the pace of the net-zero carbon transition. However, they also provide a reliability and affordability bridge—giving emerging technologies time to mature and helping to moderate near-term rate pressures as demand surges. On May 23, 2025, President Trump signed four executive orders aimed at accelerating nuclear power development and securing domestic fuel supplies. Key measures include:
- Restructuring Nuclear Regulatory Commission (NRC) to cut permitting timelines to 18 months (from ~5 years)
- Launching pilot demonstration reactors by July 2026
- Deploying a military base reactor by 2028
- Setting a long-term goal of expanding U.S. nuclear capacity to 400 GW by 2050 (from ~100 GW today)
- Invoking the Defense Production Act to boost domestic uranium mining, enrichment, and fuel production
The administration’s energy strategy promotes baseload generation, including nuclear, natural gas, and coal life extensions, but ends the incentives for renewables (except offshore wind). After years of underinvestment, natural gas-fired generation is receiving renewed policy support. At the same time, pending legislation—the OBBB—would phase out renewable energy tax credits. The Senate’s most recent proposal requires that all new wind and solar projects must be placed in service by 2027 to receive the PTC/ITC tax credit, which is quite restrictive and compares to current IRA (start construction by 2032)
We believe the majority of planned utility renewable projects have been “safe harbored” (began construction by spending 5% of total project), which means projects could come on-line through 2029 and receive 100% tax credit. Importantly, the Senate version preserves credit transferability for the full life of the credit. In addition, battery storage, nuclear, geothermal, and other clean energy technologies would retain eligibility well into the 2030s. Despite shifting federal policy, we expect renewable energy to gain market share through 2029-2030, supported by falling costs, strong state-level mandates and corporate net-zero carbon standards.
ELECTRIC DEMAND GROWTH FASTER THAN INFRASTRUCTURE BUILD
After two decades of flat growth, most industry experts (consultants, investors, analysts, utilities) expect a rapid acceleration of electric demand—so much so that forecasts keep being revised upward as the scale and speed of data center and large industrial customer growth exceeds expectations (see Exhibit 4). Even with uncertain variables like double-counting data centers, “deep-seek” – related efficiencies, and economic strength/weakness, electric demand will likely outpace the industry’s ability to build infrastructure, but still results in historically high rate base growth.
Exhibit 4
Power Surge: More Than Just Hype
In its June 10, 2025, Short-Term Energy Outlook, the EIA raised its 2025 U.S. electricity demand forecast by about 1%, citing surging demand from data centers and manufacturing. Commercial sector electricity use is now expected to rise 3% in 2025 and 5% in 2026—up from the 2% average annual growth projected in May 2025. The agency noted particularly strong demand growth in the ERCOT (Electric Reliability Organization of Texas) and PJM markets. ERCOT will see the largest summer-over-summer increase, driven by data centers and new factories.
Based on actual announcements, we forecast roughly ~50 GWs of data center demand will be added by 2030 with nearly 25-GWs already contracted. As a result, electric demand grows 2.0-2.5% in 2025 and accelerates to 3-4% in 2026-2028 driven by more and larger data centers, onshoring and electrification activity. Exhibit 5 highlights that the more recent US power demand forecast (55% over 2020-2040) have increased from previous forecasts.
Exhibit 5 Electric Demand Growth Forecasts Continue to Increase
Source: NextEra June 2025 Investor Presentation; Energy Information Administration: HIS Outlook; McKinsey
SOME EXAMPLES OF DATA CENTER / LOAD GROWTH UTILTIES
Entergy (ETR) targets 8%+ EPS CAGR and expects retail sales growth of 6-7%, including industrial sales growth of 12-13% through 2028. The multi-state utility has disclosed plans for at least three mega-datacenters. Meta plans for a $10 billion data center in Northeast LA; AMZN plans a $10 billion data center in MS; and an undisclosed hyperscaler plans a massive data center in Arkansas. The utility expects 35 GW’s of large load, including ~20 GWs of data centers and 15 GWs of other industrial customer growth. ETR plans to add 17 GW’s of generation by 2033, build three combined cycled gas plants (2,265 MWs of capacity) and 1,500 MWs of renewables to serve the Meta load.
Southern Company (SO) forecast electric load growth of ~8% (raised several times) from 2025 to 2028 driven by strong economic development, including a large load pipeline over 50 GWs (10 committed and 6 GWs contracted). SO targets EPS growth of 5-7% supported by projected state-regulated electric and gas utility rate base growth of over 8%. Georgia Power has an RFP for 13 GWs of generation, including 4.3 GW’s of solar/storage.
American Electric Power (AEP) forecasts 2025-27 retail sales growth of 8.8%, 8.4%, and 8.9%, including 24%, 19%, and 16% commercial. AEP has commitments for 20 GWs of load (13 GWs of data center) through 2029 and expects 2025-2034 resources needs of 28 GWs (6.0 GWs of solar, 5.0 GWs of wind, 1.2 GWs of storage, and 16 GWs of gas). AEP’s 2025-29 capital program totals $54 billion ($21 billion for transmission; $14 billion generation) and the company targets 6-8% EPS CAGR.
XCEL Energy (XEL) outlines 6-8% EPS CAGR, strong sales growth and 8,900 MWs of data center requests (2.6% sales CAGR). XEL highlights that 1 GW datacenter is equal to 1 million customers, ~ 3 GWs of renewable and firm dispatchable energy, $6-8 billion of investment requirement, $0.9-1.0 billion of incremental revenues and 10% customer savings. XEL’s base capital plan of $45 billion, reflecting 9.4% rate base growth, and could be increased by $10 billion, includes new CO generation (5-14 GWs from 2028-2031), MN generation (5 GWs 2025-2030) and TX (5-10 GWs).
Dominion Energy (D) added 6.1 GWs of new data centers over 2015-24, including 30 data centers (1,040 MWs) in 2024. D emphasized that data center-driven load growth in Northern Virginia shows no signs of slowing—in fact, Q4 2024 contracted capacity nearly doubled to around 40 GW, up from 21 GW in July 2024—prompting the company to boost its five-year capital investment plan to $50.1 billion through 2029 to support the demand surge
WEC Energy Group (WEC) raised its 2026-28 annual electric demand growth forecast to 4.5-5.0%, from 0.7%, to reflect data center and technology demand. Microsoft began construction of an at least $3.3 billion data center near a science/technology Innovation Park south of Milwaukee. WEC plans to add 1,400 MWs but will likely need more given expectations for a second major data center. WEC targets 6.5-7.0% EPS CAGR.
Exelon’s (EXC) $38.0 billion 2025-28 capital plan results in expected rate base growth of 7.4%, but a pipeline of 17+ GW of anticipated large load (data centers) will likely lead to another $10-15 billion of capital. EXC expects load growth of 1.3% over the next four years compared with a 0.4% decline over the previous eight years.
Alliant Energy (LNT) Over 2025-2030, LNT forecasts 9-10% electric sales growth driven by 2.1 GW’s of contracted data center demand at the Big Cedar Industrial Center Mega-site in Cedar Rapids, Iowa. The data centers are expected to come on-line in 2028 and boost IPL’s peak demand by over 30%.
IDACORP (IDA) raised its 2025-2029 load growth expectation to 8.3% and it could be higher pending two possible large high-energy users who have not finalized agreements. IDA does not provide EPS growth targets but expects a 16.1% rate base CAGR. Notable growth activity includes Micron’s expansion of its Boise headquarters and new $15 billion microchip fab facility (a Meta data center), and $415 million Lamb Weston potato processing facility.
PPL Corp (PPL)- PPL-PA has signed advanced stage agreements for 11 GWs of data center load, including many to come online in 2026-2028, representing potential transmission capital upside of $700 – $850 million ($400 million in the capex plan). The utility is in active discussion with 50-GWs (up from 48 GWs) of potential projects over 2026-2034. PPL notes that 1 GW connected reduces transmission costs on the retail customer bill by about 10% (~2% of total bill or $3 per month). In KY, the first 400 MW hyperscale data center campus in Louisville (announced in January) is progressing with the first 130-MWs online in 2026. PPL-KY has active data center requests of more than 6 GWs over 2026 – 2034.
US POWER EQUATION – CAN SUPPLY KEEP UP WITH DEMAND
As of 2024, U.S. power capacity totaled ~1,250 GW: 500 GW gas, 310 GW renewables, 170 GW coal, 125 GW hydro, and 97 GW nuclear. In 2024, natural gas represented 42% of output, nuclear 19%, coal 16%, wind 11%, hydro 6% and solar 7%. In 1985, coal accounted for over 50% of U.S. electricity generation. Since 2010, the U.S. has retired approximately 100 GW of coal-fired power generation capacity with another 80 GW more to retire by 2030 (~10 GW being converted to natural gas). Over the past few years, new capacity additions have been dominated by renewables. In 2024, a total of 46.2 GW came online and 94% of it was renewable (34 GWs) or storage (10 GWs). See table below
(Not including rooftop solar)
Source: S&P Global Market/Company Documents/Gabelli estimates/Timeline
The current power development pipeline reflects net-zero carbon policies. Over 2025-29, developers plan 251 GW of solar and 72 GW of wind and 165 GW of storage by 2030. In the near term, the renewable buildout is driven by both urgency and incentives. Projects can be completed within 18–36 months and benefit from significant IRA tax credits. A large pipeline is already in motion and will likely be hurried along to meet potential 2027 tax credit cliff.
However, net-zero policies previously dampened demand for gas turbines and major manufacturers such as GE Vernova, Mitsubishi, and Siemens reduced production capacity. Now, with the surge in electricity demand and policy shifts, gas turbine orders have surged, but supply is constrained. According to the Electric Power Research Institute (EPRI), wait times for new gas turbines in the U.S. can stretch up to seven years, and costs are climbing. GE Vernova currently holds a 29 GW backlog of turbine orders, with an additional 21 GW in slot reservations expected to convert into firm contracts.
Exhibit 6 Planned New Renewable and Natural Gas Capacity
Source: NextEra Energy June Presentation; Bloomberg New Energy Outlook 2024 – Energy Transition Scenario
Nuclear power appears to be the best power option because it offers “around the clock reliability and zero carbon emissions,” but new projects are costly and take years to bring online. Renewable energy is clean, quick to deploy, and has a low marginal cost, but suffers from intermittency. Combined-cycle natural gas plants provide high-capacity factors but emit carbon and can be exposed to volatile fuel prices. Utility-scale battery storage is emerging as a complementary solution to balance intermittent renewables and help mitigate peak demand.
Political and economic realities suggest the U.S. is heading into three distinct phases of power supply expansion over the next decade. Three phases are shaping U.S. power development:
- 2024–2028: Renewables and storage dominate buildouts.
- 2028–early 2030s: Gas-fired capacity expansion as turbines arrive.
- Early–mid 2030s: Next-gen nuclear emerges as cost and policy improve.
TECH GOES NUCLEAR:
Meta, Google, Amazon, and Microsoft are projected to spend over $200 billion in 2025 on data infrastructure. Each has aggressive clean energy goals—including 24/7 carbon-free energy or net-zero targets by 2030—making nuclear power increasingly attractive for its reliability and zero-carbon output. Ideally, the hyper-scalers would prefer to contract directly with nuclear plants for 100% of a plant’s output. In early 2024-25, a few landmark megatech-nuclear deals were announced:
Amazon & Talen Susquehanna Plant: On March 4, 2024, Talen (TLN) and Amazon agreed to a deal that would allow the 960-MWs of TLN’s Susquehanna Nuclear plant (2,500 MWs) near Berwick, PA, to be sold directly to Amazon Web Services (AWS). TLN plans to sell its adjacent digital infrastructure campus (data center and crypto mining facilities), to AWS for $650 million. The agreement highlighted the value of merchant power plants (especially nuclear) as hyper-scalers are less price elastic and contract directly. On June 11, 2025, TLN and AMZN upsized the agreement, but altered it to be a 1,920MW front of the meter (FTM) power purchase agreement (PPA). The companies were challenged to receive FERC and other approvals for a behind-the-meter (BTM) deals.
Microsoft & Three Mile Island (CEG): On September 20, 2024, CEG and Microsoft announced a landmark 20-year power purchase agreement (PPA) to bring the shuttered Three Mile Island Unit 1 nuclear reactor (Harrisburg, PA) back online by 2028. Renamed the Crane Clean Energy Center, the facility was closed in 2019 but will now undergo a $1.6 billion revitalization to serve MSFT’s expanding data center load in the Mid-Atlantic. This marks the first-ever commercial effort to restart a previously retired U.S. nuclear reactor.
Meta & Clinton Nuclear Plant (CEG): On May 16, 2024, CEG and Meta announced a 20-year, 1,092 MW front-of-the-meter power purchase agreement (PPA) for the entire output of the Clinton Nuclear Station in southern IL. Beginning in June 2027, the agreement supports plant relicensing, and a planned 30 MW capacity uprate. CEG will also consider the site for potential small modular reactor (SMR). Meta will procure the plant’s clean energy attributes to help meet its goal of matching 100% of electricity use with carbon-free energy.
In the United States, most of the 94 nuclear reactors are owned by regulated utilities, limiting direct procurement options for hyperscalers to the 23 nuclear plants that operate as merchant plants in deregulated markets like PJM, where direct deals are possible. However, political and regulatory hurdles, particularly around grid cost allocation, have made it difficult to dedicate output from existing nuclear plants to tech companies. As electricity demand surges, the value of uncontracted, non-regulated nuclear generation has risen sharply, making these assets increasingly strategic and scarce. In the near term, unregulated power plants and particularly nuclear plants (and their owners) stand to benefit, including:
- Constellation Energy (CEG)-owns all or portions of 14 nuclear plants (26 units) totaling 22 GWs; 6 plants in IL; 2 in PA; 3 in NY; 1 in NJ, TX, and MD.
- Vistra Corp. (VST)-owns four nuclear power plants: Comanche Peak (TX; 2,400 MW’s), Beaver Valley (1,800 MW’s), Davis-Besse (900-MW’s), and Perry (1,300 MW’s; OH)
- NextEra Energy (NEE) -owns Seabrook (1,100 MW’s; NH), Point beach (1,200 MW’s; WI) and Duane Arnold (600-MW’s; Iowa; closed in 2020)
- Talen Energy (TLN)-owns Susquehanna (2,600 W’s’ PA)
- Public Service Enterprise Group (PEG)-owns three nuclear plants Hope Creek (1,172 MW’s; NJ, Salem (owns 57% of 2,285 MW’s; NJ), and Peach Bottom (50% of 2,449 MW’s; PA)
Despite growing utility interest in nuclear, the U.S. is unlikely to see new large-scale plants before 2035 due to cost overrun fears stemming from past failures, pushing the industry instead toward restarts of retired reactors and investment in SMRs as a more scalable, lower-risk alternative. Potential restarts include: Palisades (800-MWs; Michigan; Shut down in 2022), Duane Arnold (600-MW; IA; Closed 2020), and Three Mile Island Unit 1 (820-MWs; PA; Closed 2019).
NERC ONGOING WARNING: POWER DEMAND TO EXCEED SUPPLY
More than one-half of North America faces a risk of energy shortfalls in the next 5-10 years as data centers and electrification drive electricity demand higher and retirements threaten resource adequacy, according to the North American Electric Reliability Corp 10-year outlook (2024 Long-Term Reliability Assessment – December 2024) and further reinforced by its May 2025 Summer Assessment.
Exhibit 7 North American Reliability Council (NERC) Raises Concern About Supply
NERC’s forecast peak reserve margins (the cushion between supply and peak demand) fall to concerning levels across the US. Further, more frequent and extreme weather events impact record peak demands in many regions. NERC notes that
30 GW of solar and 13 GW of battery storage have been added recently, but lack the flexibility and dependability needed during peak demand hours. NERC warns that many regions, including MISO, PJM, and SPP, face mounting reliability risks as dispatchable resources decline and extreme weather events become more frequent. On June 23-24, PJM peak load reached 161/159 GWs, which was the highest since July 2011 (all -time record of 165.6 GWs in 2006).
May 2024 Power Auction Saw Record Prices
In May 2024, PJM Interconnection’s capacity auction for the 2025/2026 delivery year resulted in record-high clearing prices of $269.92/MW-day—nearly 10 times higher than the previous year’s $28.92/MW-day. The surge was driven by tightening supply and rising electricity demand.
Exhibit 8 The May 2024 PJM RTO Capacity Auction Saw Record High Prices
The next PJM Interconnection Base Residual Auction (BRA) is scheduled for mid-July 2025 covering the 2026/2027 delivery year (June 1, 2026 – May 31, 2027). To address concerns over soaring capacity prices, FERC approved a temporary price collar for the next two BRAs (2026/2027 and 2027/2028 delivery years). This collar sets a price cap of $325/MW-day and a price floor of $175/MW-day. PJM has scheduled the BRA for the 2027/2028 delivery year for December 2025.
Texas is experiencing strong electric demand growth, with ERCOT projecting peak load to rise from 86 GW in 2024 to 130–148 GW by 2030. Over 30% of the state’s capacity is intermittent and subsidized renewables. To address tightening reserve margins, Texas created a $5 billion Texas Energy Fund (TEF) in 2023 to support new gas-fired generation. Regulators approved 17 of 72 projects, totaling nearly 10 GW, with 11 in the interconnection queue by 2028—including ~450 MW plants from VST, NRG and CEG. In 2025, the state doubled TEF funding, but a number of projects have withdrawn and been replaced.
WHO HAS “NON-REGULATED POWER’ TO SELL?
Regulated electric utilities are actively adding generation—primarily gas, renewables, and battery storage. Supported by state regulators and rate recovery mechanisms, regulated utilities can plan and build new capacity with more certainty than merchant generators. Over the 5-to-10 years, US regulated utilities have filed resource plans with the intention of adding significant amounts of renewables and gas-fired power and the investment has led to higher forecasted EPS CAGRs.
However, non-regulated states include major markets like Texas, Illinois, New York, and Pennsylvania. The four pure-play publicly-traded independent power producers (IPPs), or merchant generators, (Constellation Energy, Vistra, NRG Energy & Talen) own power plants in non-regulated markets like PJM (Northeast/MidAtlantic), ERCOT and CA. See Table 2 These companies are the most leveraged to power supply shortages. Capacity ownership is shown below and includes pending acquisitions for CEG, VST and NRG.
Table 4 Largest Publicly-Traded Merchant Power Plant Owners(And Pending Acquisitions)
Source: Thomson One Consensus estimates, Company documents
Since 1995, the sub-sector of IPPs has experienced “boom-bust” periods and bankruptcies of key players, including AES, Enron, Dynegy, Mirant, Calpine, NRG, and Talen. Over the past 20 years, private equity firms and infrastructure funds had been major buyers of non-regulated (merchant or competitive) power plants in the U.S. LS Power, Energy Capital Partners (ECP), ArcLight Capital, Blackstone Energy Partners, Global Infrastructure Partners (GIP), Brookfield Asset Management.
MORE RATE CASES TO SUPPORT HIGHER CAP_EX
As utility capital spending reaches record levels, a utility’s ability to grow earnings increasingly depends on how its state’s Public Utility Commission (PUC) regulates rates—and whether the utility is given a fair opportunity to earn its authorized return on equity (ROE). Because PUCs are political bodies, rate decisions are shaped not only by financial metrics but also by public pressure to keep customer bills affordable. To help evaluate this dynamic, we provide a Regulatory Research Associates (RRA’s) ranking of electric and gas rates across utilities (Appendix and Exhibit 9), along with an assessment of how constructive each state’s regulatory environment is—specifically, how effectively it supports utilities in earning their allowed ROE.
Exhibit 9 State PUC Rankings – AL, FL, GA, PA Constructive; CT, MD Not So Much
In recent years, utilities have needed to file more rate cases due to higher capital investment, higher interest rates and greater policy demands. In addition, utilities have implemented more riders or inter-period adjustments. In the first quarter of 2025, the median ROE authorized in all electric utility rate cases was 9.75% versus 9.70% in full year 2024. For gas utilities, the median was 9.78% in the first quarter of 2025 and 9.70% in full year 2024.
Exhibit 10 Heavy Rate Case Activity – Allowed ROE’s ~9.75% Over Past Twelve-Months
Source: S&P Global; RRA
Looking at the last 12 months ended March 31, 2025, the average ROE authorized in all electric utility rate cases was 9.75%, and the median was 9.75%. For gas utilities, during the 12-month period ended March 31, 2025, the average authorized ROE was 9.73% and the median was 9.75%.
Between 1990 and 2020, interest rates declined faster than authorized ROEs leading to a widening spread between authorized ROEs and the average yield on 30- year US Treasurys. This spread increased from just over 400 basis points in 1990 to nearly 800 basis points in 2020 when rates were near 1.0%. Since 2020, allowed ROE’s have ticked up modestly, but regulators are more reluctant to raise profit levels given affordability issues. The current spread is 545 basis points.
Exhibit 11 PUC’s Reluctant to Raise Profits Despite Higher Treasury Yields
Source: S&P Global; RRA; US Treasury
In today’s environment, where a single new hyperscale data center customer (e.g., Microsoft, Google, Amazon, or Meta) may require load equivalent to 20% or more of a utility’s existing system, the stakes are much higher. Serving these massive loads often requires significant investment in transmission, distribution, and generation.
To protect existing customers and shareholders from the risk of stranded costs or customer abandonment, utilities are increasingly seeking to isolate these large customers through “new large load” tariffs, including WI (LNT and WEC), MO (AEE), LA (ETR), MS (ETR) and many others. These structures often include minimum take-or-pay provisions, cost-based pricing, and termination fees. While affordability concerns persist, regulators generally support these efforts due to the substantial local economic development and grid reliability benefits. Spreading fixed costs over a growing customer base can help moderate rate impacts for other users.
CAN UTILITIES EARN THE ALLOWED ROE?
In Table 6, we ranked the top utility earning subsidiaries by average earned ROE over the years 2022-24.
Table 6 Highest Earning Electric Utilities Based on ROE’s
Source: S&P Global and RRA
PG&E, Southern Company, NextEra Energy, American Electric Power, Duke, Entergy, and CenterPoint Energy stand-out as top performers. Not surprisingly, the states they operate are among the most the more constructive PUC’s tend to regulate the higher-earning utilities. First Energy (FE) has the top three earning subsidiaries, but also several of the lowest.
Ranking Electric Utilities by State PUC and Affordability
Electric rates vary significantly across the United States, with the highest costs typically found in California and the Northeast, and the lowest in regions like the Midwest, Southeast, and Pacific Northwest. States with lower rates often benefit from less restrictive regulatory environments, greater reliance on lower-cost fossil fuels like coal and natural gas, and access to abundant legacy hydroelectric resources, particularly in the Northwest. In contrast, high-cost regions often have more aggressive climate mandates, higher renewable penetration, and more costly transmission/distribution systems.
Table 5 Ranking Electric Utilities by Affordability
Source: S&P Global; RRA;
In California, for example, utilities must recover wildfire mitigation costs, high rooftop solar subsidies, and long-distance transmission investments—all of which add pressure to customer bills. Politically, utilities operating in lower-rate jurisdictions tend to face less backlash from consumers and regulators, making it easier to gain approval for future rate increases or capital investment programs. Conversely, when rates are already high, public utility commissions are more hesitant to approve full cost recovery, increasing regulatory risk.
Other Policy Support: Several State Legislative Bills Help Utilities
In response to rising wildfire risks and potential utility liabilities, a growing number of states—including Texas, Montana, Wyoming, Utah, Hawaii, Washington and others have enacted or proposed legislation to shield electric utilities from strict liability when they implement approved wildfire mitigation plans. Some policies include legal safe harbors, liability caps, expanded vegetation management authority, and securitized funding mechanisms to support grid resilience. Many of these
efforts draw from California’s landmark 2019 legislation, AB 1054, which created a $21 billion wildfire fund, capped utility exposure, and tied cost recovery to certified safety plans. However, with recent large-scale fires threatening to deplete the fund, most observers expect new legislation in 2025 focused on replenishment and reform. The destructive January 2025 fires and the absence of legislation in the spring 2025 has led to weakness in PCG, EIX and SRE.
Utility and Energy Infrastructure Becoming More Valuable!
Since 1995, the U.S. electric and gas utility sector has been consolidating with over 155 acquisition announcements and 124 completed deals. Further consolidation is being pushed by even higher capital investment budgets and the benefits of economies of scale. The combination of accelerated energy demand and decarbonization results in double digit rate base growth and material debt and stock issuance. Smaller utilities with smaller balance sheets need help undertaking larger projects. Exhibit 12 lists the major electric utility mergers over the past ten years.
Exhibit 12
Many large private equity funds, including Blackrock (owns Global Infrastructure Partners) highlight infrastructure as one of the most exciting investment opportunities owing to structural shifts, including de-carbonization, energy independence, domestic industrial capacity and on-shoring. Given accelerated power demand, energy infrastructure, (power generation, renewables, transmission, gas pipelines) have become increasingly valuable and development opportunities abound. Large global infrastructure players value the existing infrastructure, and an acquisition represents a ticket to participate in the growth potential. Some recent announcements:
On May 19, 2025, TXNM Energy (TXNM) agreed to be acquired by Blackstone Infrastructure for an enterprise value of $11.5 billion, or $61.25 per share in cash. The purchase price of $61.25 per share represents a 23.0% premium and represents an EV/EBITDA of 11.8X, P/E 2026 EPS of 20.4x, and 1.8x rate base.
On January 10, 2025, CEG agreed to acquire Calpine, the largest gas-fired company in the US (27 GWs) for $29.1 billion ($4.5 billion in cash and $16.4 billion in stock (50 million CEG shares) from Energy Capital Partners plus the assumption of $12.7 billion of Calpine net debt. After adjustments, CEG considers the acquisition multiple to be 7.9x 2026 EV/EBITDA. Calpine was taken private in 2017 by Energy Capital Partners for $17 billion or EV/2017 EBITDA multiple is 9.1X.
On May 6, 2024, GIP and the Canada Pension Plan Investment Board agreed to acquire ALLETE (ALE) for $67.00 per share in cash (18% premium), or $6.2 billion including the assumption of debt. ALE owns/operates/develops renewables and multi-billion opportunities to build transmission assets.
On December 23, 2024, Iberdrola, (Madrid, Spain) closed on the acquisition of the last 18.5% ownership of Avangrid (AGR) for $35.75.
On December 12, 2024, Energy Capital Partners closed on the purchase of Atlantica Sustainable Infrastructure PLC (AY) for $2.56 billion.
Power Plant Consolidation
Since 1995, the sub-sector of IPPs has experienced “boom-bust” periods and bankruptcies of key players, including AES, Enron, Dynegy, Mirant, Calpine, NRG, and Talen. Over the past 20 years, private equity firms and infrastructure funds had been major buyers of non-regulated (merchant or competitive) power plants in the U.S. LS Power, Energy Capital Partners (ECP), ArcLight Capital, Blackstone Energy Partners, Global Infrastructure Partners (GIP), Brookfield Asset Management.
More recently, the pendulum shifted and private equity firms are selling power plants and portfolios to IPPs. CEG and VST emphasized during first-quarter earnings calls that the cost of building new generation is prohibitively high, enhancing existing assets’ values. Building new power generation in deregulated states like NY, IL, MA, CT and CA is extremely challenging due to stringent environmental regulations, lengthy permitting processes, transmission constraints and local opposition. Further, the price tag (replacement value) of new gas fired power has risen to $2,800/kw, from $800/kw in 2021. The dynamics imply significant new baseload supply will not come on-line until 2030 to 2035. The hyper-scalers want to move faster.
On May 15, 2025, VST announced the acquisition of 2,557-MWs of gas-fired plants for $1.9 billion, or $743/kw from Lotus Infrastructure. The acquisition includes five combined-cycle plants and two combustion turbines (peakers) located across PJM, New England, NY and Ca. The largest plant, Farless Works (1,355 MWs) in Bucks County, PA, and Manchester Plant (510-MW’s) in RI. Vistra said the Lotus portfolio is priced at approximately $743/kw.
On May 12, 2025, NRG agreed to acquire 13 GW of gas generation and 6 GW of virtual power plant capacity from for $12.4 billion comprised of $6.4 billion of cash, $2.8 billion in stock to LS Power (24.25 million shares of NRG $114.98), $3.2 billion of net debt NRG considers the acquisition price to represent 7.5x 2026 EBITDA, less than $1,000/kw and less than 50% of replacement value. On April 10, 2025, NRG acquired six Texas gas plants totaling 738 MW from Rockland Capital LP for $560 million ($760/kw) in a deal that closed April 10.
In February 2025, Brookfield Asset Management agreed to buy National Grid Renewables 3 GW of projects renewable portfolio for a $1.74 billion. The transaction includes solar and battery projects in ERCOT, MISO, PJM and SPP, and one wind project in SPP. On January 8, 2025, AQN completed the sale of its non-regulated renewable energy business (excluding the Company’s hydro fleet) to a wholly owned subsidiary of LS Power. AQN considers the transaction multiple to be 12.5x. In December 2024, Energy Capital Partners closed on the $2.6 billion ($22 per AY share) Atlantica Sustainable acquisition for $2.555 billion. The acquisition included 2.2 GWs of renewable energy ($1,180/kw).
In late March 2024, VST closed on the acquisition of Energy Harbor’s nuclear (~4 GW) and retail businesses (~1 million customers). Energy Harbor owns the Beaver Valley 1 and 2, Perry, and Davis Besse nuclear plants and retail businesses. VST’s 2024 Adjusted EBITDA guidance is $3.7-4.1 billion (Energy harbor to add $700-900 million).
In February 2024, GIP agreed to buy 50% of the South Fork and Revolution offshore wind (NY) projects from Eversource for $1.1 billion.
In November 2023, CEG acquired a 44% stake in the South Texas Project Electric Nuclear Plant (STP), a 2,645 MW, dual-unit near Houston, TX, from NRG. Price implied 11.7x EV/EBITDA.
Utility Stocks Trade at Reasonable Valuations
In 2024 and the first half of 2025, the merchant power producers, CEG, VST, NRG and TLN, have been absolute “rock stars” rising on average 52% and 59%, respectively. The companies are highly leveraged to the power supply shortage theme. We believe the thesis has considerable runway given electric demand growth through at least 2030 and the challenges bringing new supply on-line. We also believe that many electric and gas utility stocks will benefit from the infrastructure build out with above historical average EPS and dividend growth. In addition, their defensive characteristics could appeal in the event of an economic slow-down. Please see Table 7 for Utility Subgroup Metrics and appendix for more utility stock financials.
- Electric utility valuation multiples have declined from 23x forward earnings in early 2020 and trade at 17.5X 2025 earnings estimates. Over the past twenty-five years, utility forward multiples have ranged between 10x and 23x earnings with a median of 16.8x.
- Independent Power Producers (IPPs), or merchant power companies, are highly leveraged to potential supply shortages. IPPs/merchants own power plants in non-regulated power markets, including PJM (Northeast/MidAtlantic), ERCOT (Electric Reliability Council of Texas), and CA, and provide marketing/power management services to customers. In 2023-25, the share prices of CEG, NRG, VST and TLNE rose dramatically and driven by electric power demand and power shortages.
- Gas utility performance reflects improved investor sentiment and ongoing consolidation but likely does not reflect potential increased gas demand. Gas utilities currently trade at 16.8x 2025 earnings estimates.
- Water utility two-year under-performance reflects the impact of higher interest rates on higher multiple stocks. Water utilities trade at the highest multiples due to their scarcity, small size, takeover premium, ESG value, and long-term growth potential through consolidation and privatization.
- Canadian electric and gas utilities have lower growth rates and higher current returns. Canadian provincial regulatory environments are more challenging (lower allowed ROEs and equity ratios) than many US utility jurisdictions.
Table 7 Utility Subgroup Statistics
Valuation
Over the past twenty years, electric utility multiples climbed from roughly 10x forward earnings to over 23x, driven by improving fundamentals, higher growth rates and lower interest rates from 2000-2022 (Exhibit 13). Electric utilities trade at ~17.5x consensus forward earnings estimates which is above (but near) the historical median (16.8x).
Exhibit 13 Absolute P/E Multiple Range
Source: Thomson One, Company documents
We consider the multiple attractive given higher utility earning growth rates and strong fundamentals. Given that long-term interest rates (specifically the 10-year Treasury yields) have risen to 4.3% following a long-term secular decline since the late 1980’s, we measure the earnings yield (1/P/E) as a percentage of the 10-Year T- Bond Yield to gauge interest rate adjusted valuations. As can be seen in Exhibit 14 the current ratio of 130% indicates the sector P/E is modestly higher than its historical median relationship (195%) with the 10-Year T-Bond Yield.
Exhibit 14 Utility Earnings Yield as a Percent of 10-Year T-Bond Yield
Source: Thomson One, Company documents
Interest Rates and the Fed
Utility stocks are not bond proxies, and share prices are a function of earnings and dividend growth rates, but higher (lower) rates negatively (positively) impact stocks, given that future cash flows are impacted by the discount rate. In addition, current utility dividend returns become less compelling when returns on other investments increase, including Treasury yields. Short-term Treasuries yield over 4.5% and US Treasuries hold even greater defensive appeal than utilities. The factors below mitigate the negative impact of higher rates.
- Annual dividend hikes: Utilities target annual dividend increases, which serve to mitigate the negative impact of higher rates. In 2024, electric utilities increased the annual dividend by a median of 4.9%.
- ROE is set based on interest rates: A utility’s cost-of-capital, including equity returns (ROEs), is set by state PUCs and increases (decreases) as interest rates rise (fall).
- Annual riders minimize inflation risk: State PUCs and FERC regulatory principles have improved to include more frequent rate adjustments, which mitigate inflation risk.
- Utility stocks pay higher dividends than other sectors: The present value of a higher near-term dividend stream is less impacted by changes in interest rates than a lower near term dividend stream.
While utility dividend yields and 10-year U.S. Treasury yields are highly correlated and will likely remain so in the future, utility dividends have risen over time (most on annual basis) while the Treasury yield remains fixed. Utility stock prices, unlike Treasury bond prices, are likely to rise should earnings and dividends grow over time.
Conclusion
The utility sector offers a 3.4% current return and many utilities managements target 5-8% annual earnings and dividend growth. The utility business model represents a safer haven in the face of an economic slow-down, tariffs and/or inflation fears. In addition, accelerated electric demand provides support for EPS CAGR and the potential for even higher growth. We believe that the combination of strong utility fundamentals, and the potential for accelerated electric demand bode well for the relative performance of utilities.
Timothy M. Winter, CFA
(314) 238-1314
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This whitepaper was prepared by Timothy M. Winter, CFA. The examples cited herein are based on public information and we make no representations regarding their accuracy or usefulness as precedent. The Research Analysts’ views are subject to change at any time based on market and other conditions. The information in this report represent the opinions of the individual Research Analysts’ as of the date hereof and is not intended to be a forecast of future events, a guarantee of future results, or investments advice. The views expressed may differ from other Research Analyst or of the Firm as a whole.
As of March 31, 2025, affiliates of GAMCO Investors, Inc. beneficially owned 7.17% of RGC Resources, 4.50% of National Fuel Gas, 2.69% of Southwest Gas, 2.19% of Northwest Natural, 1.48% of TXNM Energy, 1.48% of York Water, 1.03% of Black Hills, and less than 1% of all other companies mentioned.
One of our affiliates serves as an investment adviser to Hawaiian Electric or affiliated entities and has received compensation within the past 12 months for these non-investment banking securities-related services.
Funds investing in a single sector, such as utilities, may be subject to more volatility than funds that invest more broadly. The utilities industry can be significantly affected by government regulation, financing difficulties, supply or demand of services or fuel and natural resources conservation. The value of utility stocks changes as long-term interest rates change
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