Capital Investment Super-Cycle
Gas-Fired Power to the Rescue!
EPS CAGR’s TO RISE?
US Utilities –Capital Investment Super-Cycle-EPS CAGR’s to Rise?
Through nine months of 2025, the S&P 500 Utilities Index returned 17.7%, topping the S&P 500 Composite’s 14.8% return. Utilities strongly led the market in the first quarter, benefiting from their defensive appeal amid tariff concerns and recession fears. Momentum shifted in the second quarter as easing trade tensions and healthy economic data renewed investor appetite for growth. Utilities remain well positioned, with many raising EPS growth targets and benefiting from surging electricity demand. The massive AI build-out, which requires unprecedented power to run data centers, is reshaping demand profiles and creating opportunities for utilities to grow EPS through infrastructure investment and regulated returns.
Table 1 Utility Stock Performance Versus S&P 500
Within our universe of 60 regulated electric, gas, and water utilities, the median total return was a strong 15%, while the four publicly traded non-regulated power producers (CEG, VST, NRG, and TLN) produced a more volatile but impressive 71% average return. Renewable developers and wildfire-exposed utilities lagged, although third-quarter policy actions helped improve their outlooks. The July 4 OBBB and August Treasury guidance provide a renewable development runway through 2030. California’s three large regulated utilities, PCG, EIX, and SRE, faced pressure as investor confidence in the state’s wildfire liability fund weakened following the destructive January 2025 wildfires. While lawmakers implemented short-term fixes and pledged to pursue a permanent solution in 2026, investors remain wary of future catastrophic fire risk.
The utility investment thesis is increasingly compelling. U.S. electricity demand is rising at its fastest pace since the 1960s–70s, driven by AI-powered mega data centers, manufacturing reshoring, and transport electrification. Utilities are responding with record capital investments to expand generation and modernize grid infrastructure, often partnering with hyper-scalers such as Amazon, Microsoft, Meta, and Alphabet to secure long-term power capacity. Many utilities report waiting lists of large customers seeking to build facilities in their service territories, highlighting strong underlying demand. Rising consumption enables utilities to spread infrastructure costs across a broader customer base, helping mitigate affordability concerns, while supportive policymakers and regulators provide a favorable backdrop for unprecedented rate base and earnings growth.
Exhibit 1 STOCKS TO CAPITALIZE ON THE UTILITY INFRASTRUCTURE BUILD
APPRAISAL:
The utility sector is operating in an unusually favorable environment marked by surging electricity demand, heavy infrastructure investment, and supportive policies that could enable historically strong EPS and dividend growth. To translate record capital spending and rate base expansion into bottom-line growth, utilities must secure financing, execute large-scale projects, and manage costs effectively. Federal policy has eased several hurdles by supporting natural gas, extending coal plant operations, and reducing regulatory friction, although affordability concerns remain a challenge. Utilities can further mitigate bill increases by structuring agreements in which mega-load customers contribute to infrastructure funding, costs are spread over a larger sales base, and municipalities benefit from economic growth and tax revenues.
The August 19, 2025, merger announcement of Black Hills and Northwestern underscores the importance of scale in meeting rising demand and may revive a consolidation trend that had slowed under COVID and high interest rates. Private equity and infrastructure investors remain highly active, illustrated by Blackstone’s $11.5B pending acquisition of TXNM, Constellation Energy’s $29.1B pending purchase of Calpine, and Blackrock-GIP/CPP’s $6.2 billion pending acquisition of ALLETE. With demand growth, decarbonization, and grid needs accelerating, regulated utilities are scarce, highly valued assets, and further small-cap M&A activity (including AES, IDA, POR, AVA, MGEE, MDU, OTTR, AQN, PNW and UTL) appears likely.
In the third quarter of 2025, favorable developments included interest rate cuts, confirmation of renewable tax credits, California wildfire legislation, and the BKH-NWE utility merger.
- Fed Cuts Overnight rate: On September 17, 2025, the Federal Reserve lowered its overnight rate to 4.00–4.25% (from 4.25-4.5%), with markets expecting further cuts in 2025–27. The 10-year U.S. Treasury yield declined from 4.58% at the end of 2024 to 4.16% on September 30, 2025. A lower yield curve supports utility valuations, lowers financing costs, and provides rate relief to customers.
Exhibit 2 A Lower Yield Curve Would Help Utility Stocks
Source: Gabelli Funds
- Clean Energy Tax Credit: OBBB was passed on July 4, 2025, and on August 15, 2025, the Treasury issued guidance shortening the clean energy tax credit window to 2030, from at least 2032. Wind and solar projects completed by year-end 2027 or started by July 5, 2026, qualify, with four years to finish once construction begins, earning either 30% ITC or 2.8¢/kWh 10-year PTC. Effective September 2, 2025, Treasury clarified “start of construction,” dropping the 5% spend rule in favor of a stricter physical work test. Other technologies—battery storage, geothermal, nuclear—have until 2032 to begin construction. The guidance adds clarity, extends safe-harbor eligibility through 2030, and strengthens project economics.
- Key beneficiaries include NextEra Energy (NEE), AES (AES), Clearway (CWEN), Brookfield Renewable (BEP/BEPC), and XPLR Infrastructure (XIFR), as well as regulated utilities with renewable pipelines such as Alliant (LNT), Xcel (XEL), IDACorp (IDA), Ameren (AEE), and Portland General (POR). Despite shifting federal policy, renewable market share should keep rising through 2030, supported by the pulling forward of projects to be eligible for tax credits as well as falling costs, state mandates, and corporate net-zero standards.
- Black Hills–NorthWestern Merger: On August 19, Black Hills Corp. (BKH) and NorthWestern Energy (NWE) announced an all-stock merger of equals (0.98x exchange ratio, 4% premium). The combined utility will serve 2.1M customers across eight states, double its rate base to $11.4B ($7.0B electric, $4.4B gas), and target 5-7% long-term EPS growth with immediate accretion. The merger creates synergies from contiguous territories, a stronger balance sheet, and enhanced scale support execution of larger infrastructure projects.
- Wildfire Legislation: On September 19, 2025, CA enacted new Wildfire and Affordability legislation (SB 254) to strengthen the state’s $21 billion Wildfire Fund by creating an additional $18 billion “Continuation Account,” equally split between ratepayer-backed bonds ($9B, extending customer charges to 2035) and utility shareholder contributions ($9B, through extended annual payments). It also allows securitization of certain wildfire claims and $6 billion in utility wildfire mitigation costs (allocated across EIX, PCG, and SRE), while prohibiting equity returns on those expenditures. SB 254 requires a comprehensive state report by April 1, 2026, to recommend further reforms for wildfire liability and risk reduction. For California’s utilities, the legislation provides near-term financial stability and wildfire coverage, while setting up broader, longer-term reforms to be debated in the next legislative session. Other states, including TX, MT, WY, UT, HI, and others have enacted some form of legislation to shield electric utilities from strict liability when they implement approved wildfire mitigation plans.
TAILWINDS OF HIGHER SALES, CAP_EX, RATE BASE CAGR’S = HIGHER EPS GROWTH
As third-quarter and year-end 2025 EPS reporting approaches, several electric utilities are positioned to lift long-term growth targets. As of September 30, most companies guided annual EPS growth ranges of 5-7% or 6-8%, with some aiming higher at 7-9% and a few remaining conservative at 4-6%. These levels far exceed historic utility growth (1990–2020) and reflect a decade-long acceleration in infrastructure spending and rate base expansion. Current targets are distributed as follows:
Target EPS CAGR | Number of Utilities
- 4–6%: 5 utilities (includes BKH and NWE, but the merger targets 5-7%)
- 5–7%: 13 utilities
- 6–8%: 14 utilities (incl. WEC’s 6.5-7.0%)
- 7–9%: 8 utilities (incl. CPK at 8%, ETR at “8%-plus” and PCG at “at least 9%”)
On September 29, CenterPoint Energy (CNP) raised its 2025-2030 EPS CAGR target to 7-9% (from 6-8%), citing Houston load growth and 11% rate base CAGR, while PG&E (PCG) extended its industry-leading “at least 9%” EPS CAGR through 2030 (previously 2028).
The industry is in the early stages of a prolonged demand and investment “super-cycle.” Utilities report accelerating capital budgets and rising power needs, though guidance remains conservative given public sensitivity to affordability. Achieving outsized growth will hinge on supportive regulatory frameworks, particularly PUC approval of higher rate bases and returns. In some regions, individual data center projects exceeding 1 GW represent “mega-loads” that can add 20–30% to a mid-sized utility’s existing capacity—underscoring both the scale of opportunity and the execution risk. To mitigate risk, utilities are increasingly implementing “large load” tariffs, shifting financial responsibility to the new customer base rather than existing ratepayers (see regulatory section, page 8).
Sector performance already reflects this momentum. In 2024, electric and gas utilities posted nearly 9% EPS growth, supported by strong sales and constructive rate outcomes. Consensus estimates (Thomson One) project a median sector EPS CAGR of over 7% for 2024-2027.
Table 2 Historically High EPS CAGRs; Who Could Go Higher?
RECORD INVESTMENT (RATE BASE GROWTH) LEADS TO EPS GROWTH
In 2025, U.S. electric and gas utility capital expenditures (47 investor-owned utilities tracked by S&P Global Market Intelligence) are projected to rise 24% to $214.7 billion, up from $173 billion in 2024 ($164 billion in 2023; $146 billion in 2022). The 10.5% CAGR over the past three years reflects a decade long trend of steady growth, driven by climate policy, net zero targets, and the transition from fossil fuels. This has accelerated coal retirements, expanded wind and solar development, and increased spending on aging infrastructure, disaster recovery, and grid hardening.
More recently, utilities have pushed capital budgets and rate base growth to historic highs to meet surging demand. Mega cap technology companies are securing long term power for AI data centers, some using as much energy as small cities, supporting sustained rate base expansion and long-term earnings growth.
With nearly 70% of North America’s grid infrastructure older than 25 years (DOE), utilities are directing capital toward system replacement, renewable mandates, modernization, and resilience against extreme weather. S&P Global Market Intelligence projects utility capex will rise to $227.8 billion in 2026 and $233 billion in 2027, with continued growth over the next decade as rising demand and the need for new baseload generation drive investment.
Exhibit 3 Record Capital Investment
Investment spans all major areas of the system, including distribution (33%), generation (24%), transmission (20%), gas-related infrastructure (14%), and other categories (8%).
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.
ELECTRIC DEMAND GROWTH FASTER THAN INFRASTRUCTURE BUILD
After two decades of flat growth, U.S. electricity demand is accelerating rapidly, driven by AI, cloud computing, and large-scale industrial loads. Forecasts are being revised upward as actual data center and industrial project announcements exceed expectations. This surge is comparable to the 1960s–70s, when widespread adoption of air conditioning and household appliances reshaped electricity consumption. While precise demand levels remain difficult to quantify because of project overlap, efficiency gains, and economic conditions, the trajectory is clear: electricity demand is rising faster than infrastructure can be expanded.
The EIA’s September 2025 Short-Term Energy Outlook (STEO) projects U.S. power generation growth of 2.3% in 2025 and 3.0% in 2026, well above initial forecasts of 1.5% annually and the 0.8% average from 2020–2024. We highlight well above-average growth in ERCOT (11% annually in 2025-26) and PJM (4%), with notable activity in Pennsylvania, the Southeast, Arizona, Idaho, and the Midwest. Constraints such as grid capacity, permitting, and costs will limit expansion in New England, Alaska, and Hawaii. Greenfield data centers typically come online in 2–3 years, whereas grid upgrades require 4–8 years and likely longer in the Northeast.
Exhibit 4 Electric Demand Growth Forecasts Continue to Increase
Based on announced projects, we loosely estimate ~60 GW of incremental U.S. data center demand by 2030, with ~30 GW already contracted. This supports 2.0-2.5% demand growth in 2025 and accelerates to 3-4% annually through 2028 and is even higher in 2029-2032. Bain & Company estimates that hyperscalers and colocation providers will collectively spend $1.8 trillion on U.S. data center capex from 2024-2030, with the majority concentrated in the U.S. Hyperscalers—Amazon, Microsoft, Meta, and Alphabet—will drive 60% of this growth, increasing their share of global data center demand from 35% to 45%. Average facility size is projected to expand from 40 MW to 60 MW, with roughly one-third of campuses exceeding 200 MW.
Exhibit 5 Electric Demand Growth Forecasts Continue to Increase
High-profile projects illustrate the scale of investment and power requirements. OpenAI’s partnership with Oracle claims a $300 billion, five-year commitment, adding 4.5 GW of capacity starting in 2027 across sites in WY, PA, TX, MI, and NM. The broader Open AI, Oracle, Softbank $500 billion Stargate initiative, headlines 10 GW of AI computing capacity across five U.S. sites (Shackelford County, TX; Doña Ana County, NM; Milam County, TX; Lordstown, OH; and an undisclosed Midwest location), representing over $400 billion in investment and 25,000 onsite jobs. Google plans $75 billion in AI and cloud infrastructure, including $25 billion in PA over two years, while Microsoft is pursuing a $100 billion AI supercomputing and data center initiative to launch by 2028. U.S. data center consumption reached 47 GW in Q4 2024, up 9 GW from the previous year, and is expected to nearly double to 60 GW by 2030.
Exhibit 6 Electric Demand Growth Forecasts Continue to Increase
BOTTOMS UP: DATA CENTER/LOAD GROWTH UTILTIES
From a bottoms-up perspective, and to emphasize utility stocks positioned to benefit from significant growth tailwinds, we highlight several of the fastest-growing utilities experiencing strong load growth across the nation.
ENTERGY (ETR) targets 8%+ EPS CAGR and 6-7% retail sales growth through 2028, including 13% industrial growth, supported by agreements with at least three hyperscale data centers. Meta is investing $10 billion in a Northeast Louisiana complex, Amazon plans a $10 billion Mississippi facility, and another hyperscaler is developing in Arkansas. Entergy forecasts 35 GW of large-load growth—~20 GW from data centers and 15 GW from other industrials—and plans 17 GW of new generation by 2033. In August 2025, the LPSC approved 2,265 MW of combined-cycle gas (2028-29) designed for future carbon capture and 1,500 MW of renewables to serve 2-GW at Meta (but can be expanded to 5-GW). The $40 billion 2025-2028 capital plan drives a 15% annual rate base CAGR. Meta will fund new generation, transmission upgrades, and its ongoing share of Entergy’s costs, while both parties will explore carbon capture and storage.
DOMINION ENERGY (D) D targets 5-7% EPS CAGR from 2025 EPS and is currently the largest data center provider in the US. D added 6.1 GWs of new data centers, 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 with over 10-GW’s contracted and 40 GW’s in queue. D expects to update its 5-year $50.1 billion capital plan on the year-end call. D’s pending $10.9 billion (75% complete) Coastal Virginia Offshore Wind projects dominates investor concerns.
WEC ENERGY GROUP (WEC). WEC targets an above-average EPS CAGR of 6.5-7.0% with 2026-28 annual electric demand growth forecast to 4.5-5.0%, from 0.7% in 2025. WEC forecast only reflects the $7.3 billion MSFT data center in Mt Pleasant, WI. Phase one is estimated at $3.3 billion and scheduled to open in early 2026. Phase 2 is similar size and scale and scheduled for 2027. The load is expected to total 1.8 GW’s and is in the current capital plan. In August 2025, Vantage Data Centers $8 billion data center (Oracle) in Port Washington, WI was approved and needs 1.3 GWs (can be phased to 3.5 GW’s) of power. Clean Energy Wisconsin claims that two data centers, Microsoft’s Mount Pleasant and the Vantage data center in Port Washington would use 3.9 GW’s (enough to power 4.3 million Wisconsin homes). There are 2.82 million housing units in Wisconsin, according to U.S. Census data. We expect an updated capital plan by year-end to put upward pressure on WEC’s targeted growth rate.
PINNACLE WEST (PNW) PNW targets 5-7% annual EPS CAGR, expects 1.5-2.5% customer growth, 4-6% sales growth over 2024-2027 and PNW has committed to adding 4,500 MW’s of large load by 2030 with an additional 20 GW’s in queue (recently freed up by Transwestern gas contract). In March of 2025, Taiwan Semi-Conductor raised its expected investment in the Phoenix area to $165 billion, including 6 fabrication plants, 2 packaging facilities and a research and development facility. The investment is expected to add 70,000 jobs Fab 1 started in 2024; Fab 2 – the box is built and will full ramp in 2027-28; All 6 fabs is part of 4,500 MW’s by 2030 (also MSFT and META)
CENTERPOINT ENERGY (CNP) On September 29, 2025, CNP raised its 2025-2030 EPS CAGR to 7-9%, from 6-8%, to reflect Houston load growth and higher capital investment (11% rate base CAGR). Strong EPS growth is driven by Houston electric load growth from 21 GW’s in 2024 to 31 GWs by 2021 and 42 GW’s by 2035. Load growth is underpinned by 2% annual residential customer growth plus Port of Houston electrification, data centers, medical center expansion, the energy sectors. The company announced a new higher and revised 5- and 10-year capital plan of $33 and $65 billion.
SOUTHERN COMPANY (SO) SO targets EPS growth of 5-7% supported by projected state-regulated electric and gas utility rate base growth of over 8%. On its second quarter call, SO raised its 5-year capital plan by $13 billion to $76 billion with an additional $5 billion opportunity. The three-state utility (GA AL, MS) 50-GW large load pipeline continues to grow. Georgia Power filed to certify 10 GW through the All-Source RFP process (8 GW) and a supplemental process (2 GW). SO forecast electric load growth of ~8% from 2025 to 2028 driven by strong economic development, including a large load pipeline over 50 GW’s (10 committed and 6 GW contracted).
AMERICAN ELECTRIC POWER (AEP) AEP targets 6-8% EPS CAGR based on “stale” 2025-29 capital program ($54 billion), but expects to announce a new, 5-year capital plan of ~$70 billion during third quarter 2025 earnings call. The higher budget is meet ~24-GW’s of a peak demand growth (18-GW’s of data centers; 6 GW’s of industrial) to 60 GW’s (from 37-GW’s in 2024). The utility has 190-GW’s of interconnect requests in various stages of development across it 11-state footprint. AEP forecasts 2025-27 retail sales growth of 5.7%, 8.4%, and 8.9%, including 8.5%, 12.2%, and 12.3% commercial and industrial sales. AEP expects 2025-2034 resources needs of 28 GWs (6.0 GWs of solar, 5.0 GWs of wind, 0.5 GWs of storage, and 16 GWs of gas).
NISOURCE (NI) NI targets 6-8% annual EPS CAGR based on 8-10% annual rate case CAGR. In its 2024 IRP, NIPSCO projected ~2.6 GW of new demand over 2028-35 with potential for an additional ~6 GW (8.6 GW of new load in total), primarily from >30 data center customers. On September 18, 2025, NI agreed to provide electric service to undisclosed data centers in 2027 and increasing annually to the end of 2032. NI expects to add new dispatchable generation which requires external funding. On September 24, 2025, NI received Indiana regulatory approval to form a non-regulated GENCO designed to serve mega-load customers.
XCEL Energy (XEL) XEL targets 6-8% EPS CAGR, strong sales growth and 8,900 MWs of data center request. 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 $15 billion, including new CO generation (5-14 GWs from 2028-2031), MN generation (5 GWs 2025-2030) and TX (5-10 GWs).
IDACORP (IDA) IDA does not provide EPS growth targets but expects an industry-leading 16.1% rate base CAGR. The 2025 integrated resource plan (IRP) filed in June, reaffirmed a 5-year retail sales CAGR of +8.3% (annual peak +5.1%), but growth will likely be higher. IDA management explained that the pipeline of prospective customers (incremental to the IRP) exceeds IDA’s record peak load of 3,800 MW’s. Notable growth activity includes Micron’s expansion of its Boise HQ’s and new $15 billion microchip fab facility, a Meta data center, and $415 million Lamb Weston potato processing facility, Chobani expansion and $225 million Tractor Supply facility. In June 2025, Micron announced a second large fab facility equal to the size of the first.
PPL CORP (PPL) PPL expects to earn the top-end of its 6-8% annual EPS CAGR through 2028 driven by rate base growth from rising PA and KY data center demand, along with a new JV with Blackstone to develop long-term contracted, non-regulated gas power plants in PA. At the PA Energy Summit, PPL highlighted the state’s pro-business environment, shale resources, and need for $17–19B of new generation as demand surges and IPPs face little incentive to build. PPL is advocating for regulated utility-owned generation while also pursuing non-regulated projects with Blackstone. 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). Its PA data center pipeline totals 14.4 GW (4.8 GW announced), requiring $750M–$1.25B in transmission (vs. $400M currently planned). Additional active requests exceed 50 GW through 2034. In KY, load growth projections include 8.5 GW of new demand (6 GW data centers, 3 GW manufacturing) from 2026–2032, with ~2.5 GW expected by 2032. To meet demand, PPL is building the 600-MW Mill Creek Unit 5 CCGT (2027) and seeking approval for two 645-MW CCGTs in 2030-31, plus extending coal operations. PPL’s 2025-28 capital plan totals $20B ($4.3B in 2025), supporting 9.8% base growth over 2024-2028.
EVERGY (EVRG) On its second quarter call, EVRG raised its growth pipeline to 15 GW’s (from 12.2 GW’s), including 1.1 GWs under active construction (Meta opened $1 billion/1.4 million square feet data center in August 2025). The utility is finalizing agreements for 1.0-1.5 GW’s from data center projects (KS and MO expansion) with an additional 2.0-3.5 GW’s in advanced discussion. The final 10-GW’s are in various stages of discussions. Larger customers include ~$1 billion Meta and GOOG data centers, $4 billion Panasonic EV battery plant (expected COD 2026/4,000 new jobs) and a $100 billion hyperscale data center campus (6-data centers) near the KCI airport. EVRG’s current (but stale) 2-3% load growth CAGR through 2029 is based on 500-MW’s of new load, but an additional 1.0-1.5 GW’s (actively building or finalizing agreements) are not in the stale forecast so we see upside to 4-5% CAGR beginning as early as 2027. EVRG currently targets 4-6%, Given growing demand and a forecast 8.5% rate base growth rate, we expect the 4-6% EPS growth rate to increase to at least 5-7%.
ALLIANT ENRGY (LNT) LNT targets 5-7% annual EPS CAGR driven by 9-10% electric sales, including 2.1 GW’s of contracted data center demand (GOOG and QTS) at the Big Cedar Industrial Center Mega-site in Cedar Rapids, IA (2028). The load would boost IPL’s peak demand by over 30% from 2024 base of ~6 GWs. LNT plans to add 1,500-MW’s of gas, 800-MW’s of batteries and 1,200 MW’s of wind. QTS is exploring another massive data center in the greater Madison WI area.
AMEREN (AEE) Continues to target upper half of 6-8% EPS growth target in latter part of 2025-29; large load tariff proposal in MO assumed in ESAs with data centers; decision by Feb2025. Over 2025-2029, AEE expects load growth to accelerate to 5.5% (from less than 1%) driven by data centers and manufacturing. Cumulative 2.3 GW’s of signed data center are conditioned upon MPSC approval of a modified tariff. AEE expects the electric demand to begin ramping-up in late 2026, includes 1,600 MW (800 MW in 2027 and 800 MW in 2028) of gas-fired power by 2030 and 3,700 MW by 2035 as well as 2,700 MW ($6 billion) of renewables by 2030 and 4,200 MW ($9.0 billion) by 2035; and 1,000 MW ($1.5 billion) of batteries by 2030 and 1,400 MW ($2.0 billion) by 2035.
US POWER EQUATION – CAN SUPPLY KEEP UP WITH DEMAND
As of 2024, U.S. power capacity totaled ~1,300 GW: 560 GW gas, 310 GW renewables, 200 GW coal, 102 GW hydro, and 104 GW nuclear. (See Table 3) 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.
Exhibit 7 US Power Generation Fuel Mix-Coal Declines
So far in 2025 (through June), the US added more than 19.4 GW (compared to 18.7 GW January – June 2024) of new power capacity, led by 14.6 GW of solar (14.4 GW in same period 2024), 3.1 GW (2.4 GW) of wind and 1.7 GW of gas (0.4 GW) based on FERC’s monthly infrastructure report (June 2025). We note that the FERC data and update do not include battery storage. The storage market is expected to add ~125 GW of new capacity through 2035.
Table 3 In 2025, US Plans to Add 117 GW’s of Primarily Solar to Existing 1,300 GWs (Installed)
In 2024, a total of 46.2 GW came online and 94% of it was renewable (34 GW) or storage (10 GW). See table below
Table 4 US Power Capacity Added in 2024
(Not including rooftop solar)
Source: S&P Global Market/Company Documents/Gabelli estimates/Timeline
New Renewables; Navigating a Changing Environment
The near-term power development pipeline reflects net-zero carbon policies, state and corporate mandates well as tax incentive urgency. As of September 18, 2025, S&P Global market Intelligence (SPGMI) data identifies roughly 350-GW’s of renewable (wind and solar) power planned through 2030, including:
- Utility-scale solar of 269 GW (40.3 GW under construction and 8-GW in advanced development)
- Wind of 79.2 GW (21.5 under construction and 9.6 GW in advanced development)
Projects can be completed by 2030 benefit from significant IRA tax credits. The large pipeline is already in motion, and a significant portion of solar capacity (combined with battery storage) will be pulled forward as project developers, utilities and large customers (hyperscalers) seek to capitalize on tax credits and meet growing electric demand. The wind outlook is less certain due to regulatory uncertainty and other barriers. The administration has also taken some actions to hinder renewable energy development on federal lands.
Table 5 Largest Renewable Developers
As of September 18, 2025, the largest renewable owners and developers have broken ground on 10.8 GW of solar and 12.8 GW of wind capacity. NextEra Energy (NEE) is the largest owner of planned solar capacity through 2029 and also has the third-largest wind pipeline, Market Intelligence data shows. In total, NextEra’s solar and wind pipeline of planned capacity additions over the next five years is approximately 18.4 GW. As of September 2025, NEE presentation, NEE plans to develop 36.5 to 46.5 GW of wind (9-11.5 GW), solar (18.5-22.4 GW) and storage (7.8-10.7 GW) over 2024-27.
Exhibit 8 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.
We expect most new generation to be wind/solar/battery storage over the next four years, but an increasing amount of gas-fired generation each successive year. Renewables have the fastest development and construction time, and we anticipate that they will continue to be cost-competitive with other sources of new build. In addition, some coal-fired power plants will extend retirement dates and the Palisades, Crane Energy Centers (Three Mile Island) and Duane Arnold nuclear plants could come online by 2029-2030. In 2029 and beyond, we expect a lot of gas, some nuclear and renewables to be part of the equation to meet growing power demand.
Previous Goal of 30 GW’s of Offshore Wind by 2030 No More
The Trump administration’s actions targeting offshore wind have ended the Biden administration’s goal of 30-GW’s by 2030. In August 2025, the Bureau of Ocean Energy Management (BOEM) ordered Ørsted A/S to stop construction (an injunction allows for construction to continue) of its 704-MW Revolution Wind Offshore project (80% complete; COD 2026) and moved to revoke approval of US Wind Inc.’s 2.2-GW offshore project and reconsider approval of SouthCoast Wind (MA; Engie-EDP) as well as cancel $679 million in grants for offshore wind ports. Major facilities under construction include Revolution, Sunrise, Vineyard Wind, and Dominion Energy Inc.’s nearly 2.6-GW Coastal Virginia Offshore Wind project, planned for completion in 2026.
Trump Administration Energy Policy: Slower Net-Zero, Stronger Reliability Bridge
Recent Trump administration moves to extend coal plant life, expand gas pipeline infrastructure, and promote nuclear development will slow the net-zero transition but provide a reliability and affordability bridge as demand grows. The strategy prioritizes baseload generation—nuclear, natural gas, and coal extensions—while offering little support for renewables.
After years of underinvestment, natural gas-fired generation is regaining policy backing, but prior net-zero policies had suppressed demand for gas turbines, leaving major manufacturers (GE Vernova, Mitsubishi, Siemens) with reduced capacity. Now, surging demand and policy shifts have spiked turbine orders, but supply remains tight: EPRI reports U.S. wait times up to seven years with rising costs.
Natural Gas to the Rescue
In early July 2025, S&P Global Market Intelligence (SPGMI) raised its estimate of fossil-fired capacity that the US planned to add to more 106 GW, from 80-GW’s, by 2030. The data shows nearly 200 natural gas-fired power plants, in some form of development. More than a quarter of the new capacity (29-GW’s) would be built in ERCOT , with projects planned for 39 other states (17.5 GW’s MISO, 13.8 GW’s PJM, and 10.6 GW’s in SPP). The exhibit below appears to show a decline in 2029 and beyond, but we expect the number to continue to grow as more projects show up in the data.
Exhibit 9
Some recent examples of developers rushing to meet growing demand include the massive 4.5-GW Homer City CC plant (PA). The plant is expected to be the largest natural gas plant ever built and scheduled to come online in 2027 at the site of a former coal plant to serve a 3,200-acre campus of hyperscale datacenters. In addition, the retired 2.5–2.7 GW Bruce Mansfield coal plant in Shippingport, PA, is being redeveloped by Frontier Group into a modern natural gas facility expected to exceed the site’s original capacity and come online in phases beginning later this decade. The plant will directly power a co-located data center campus, with more than 1 GW of surplus output exported to the PJM grid.
Nuclear Renaissance Coming 2030-Plus
Nuclear power is regaining prominence as a solution to meet the U.S.’s accelerating electricity demand. With capacity factors above 90% and zero direct carbon emissions, nuclear offers dependable, carbon-free power increasingly attractive to policymakers and major corporate buyers, including Microsoft, Google, Amazon, and Meta.
Despite limited domestic reactor construction over the past four decades due to high costs, long build times, and regulatory hurdles, momentum for a nuclear resurgence is growing. President Trump has signed four executive orders to accelerate development and secure domestic fuel supplies, including restructuring the Nuclear Regulatory Commission to cut permitting to 18 months, launching pilot reactors by 2026, deploying a military base reactor by 2028, targeting 400 GW of U.S. nuclear capacity by 2050 (from ~100 GW today), and invoking the Defense Production Act to boost uranium mining, enrichment, and fuel production. On September 15, 2025, the U.S. and UK signed an agreement to accelerate advanced modular reactor deployment, including for new data centers, streamlining licensing and permitting through shared safety assessments.
Corporate demand is driving new nuclear deals. Meta, Google, Amazon, and Microsoft have 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: In June 2025, TLN updated its landmark power purchase agreement (PPA) with Amazon Web Services (AWS) where TLN’s Susquehanna nuclear plant will supply 1,920 MW’s of carbon-free nuclear power through 2042 to AWS’ data center campus adjacent to Susquehanna and other sites throughout PA. The original 2024 interconnection deal was “behind the meter” meaning sold directly to the AWS campus but was blocked by FERC. To streamline regulatory considerations, the revised PPA transitions from “behind-the-meter” to a “front-of-the-meter” configuration, meaning Talen generates power into the PJM grid, acts as the retailer/marketer to buy for AWS, and relies on PPL Electric Utilities for transmission and delivery.
Microsoft & Three Mile Island (CEG): On September 20, 2024, CEG and Microsoft announced a 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 and is undergoing 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.
Most of the US 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 GW’s; 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). On September 29, 2025, one unit of Comanche Peak entered into a contract with an undisclosed customer.
- 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)
Due to cost concerns, new large-scale U.S. plants are unlikely before 2035, shifting focus toward restarts and SMRs. Potential restarts include Palisades (800 MW, MI; shut 2022), Duane Arnold (600 MW, IA; closed 2020), and Three Mile Island Unit 1 (820 MW, PA; closed 2019). In September 2025, Holtec announced Palisades returned to operational status and is authorized to receive nuclear fuel, slightly ahead of the previously planned Q4 2025 restart.
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 10 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 significant solar and 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.
July 2025 Power Auction Saw Another Record
In July 2025, PJM Interconnection’s capacity auction for the 2026/2027 delivery year resulted in record-high clearing prices of $329.17/MW-day, 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.
Table 6 The May 2025 PJM RTO Capacity Auction Saw Record High Prices
Source: PJM
PJM’s capacity auction prices have surged dramatically—from about $28.92 per MW-day in 2024/25 to $269.92 in 2025/26, and further to $329.17 in 2026/27—a roughly ten-fold jump within two years. This has translated to an increase in region-wide capacity costs from $14.7 billion to $16.1 billion, which consumers will shoulder through higher electricity bills in 2026–2027. Key factors driving these spikes include skyrocketing demand—especially from data centers and AI infrastructure growth. Compounding the problem, delays and backlog in PJM’s interconnection queue have stalled new energy builds—many of which are renewable projects—further tightening supply.
Politicians Not Happy With Power Prices And Could Intervene Further in the Power Markets
State leaders across the PJM footprint have expressed concern, including PA. Governor Josh Shapiro filed a formal complaint with FERC. Shapiro is pushing for reforms and a lower auction cap. In addition, nine governors (from states such as Virginia, New Jersey, Maryland, and Illinois) expressed alarm over record-high prices and PJM’s governance. As a result of his concerns, PJM implemented a temporary cap of $329/MW-day and further ongoing discussion continues on how to improve the supply-demand-affordability dynamics. 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.
THE MERCHANT POWER ROCK STARS – CEG, VST, TLN, NRG
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 (Electric Reliability Council of Texas), and CA. See Table 7 These companies are the most leveraged to power supply shortages. Capacity ownership is shown below and includes pending acquisitions.
Table 7 Largest Publicly-Traded Merchant Power Plant Owners (And Pending Acquisitions)
Source: Thomson One Consensus estimates, Company documents
MORE RATE CASES TO SUPPORT HIGHER CAPEX
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 11 State PUC Rankings – AL, FL, GA, PA Constructive; CT, MD Not So Much
Source: Regualtory Research Associates: June 2025:
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 half of 2025, the median ROE authorized in all electric utility rate cases was 9.70% (1Q was 9.75%; 2Q was 9.60%) versus 9.70% in full year 2024. For gas utilities, the median was 9.78% in the first half of 2025 and 9.70% in full year 2024.
Exhibit 12 Heavy Rate Case Activity – Allowed ROE’s ~9.75% Over Past Twelve-Months
Source: S&P Global; RRA
In the first half of 2025, the highest authorized ROE was 10.2% for CPK’s Florida Public Utilities in Florida awarded March 2025 and the lowest was Versant at 9.35% in Maine also in March of 2025.
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 13 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, Alphabet, 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.
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.
In Table 8, RRA ranks the publicly-traded electric utilities from lowest ultimate (or average retail) rate per kWh. Ottertail Power has the lowest rate followed by MDU, OGE, ETR, AVA, IDA, and ALE. All tend to serve rural population centers and benefit from low-cost hydro or gas generation, higher cost utilities are in HI, CA, and the Northeast. 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.
Table 8 Ranking Electric Utilities by Affordability
Source: S&P Global; RRA
Utility and Energy Infrastructure Becoming More Valuable!
Since 1995, the U.S. electric and gas utility sector has seen over 155 acquisition announcements and 124 completed deals. Consolidation is driven by higher capital investment budgets and economies of scale, as accelerated energy demand and decarbonization create double-digit rate base growth and require significant debt and equity issuance. Smaller utilities with limited balance sheets need partners to finance larger projects. Large global infrastructure players see acquisitions as a way to access valuable existing assets and participate in growth.
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) has become increasingly valuable and development opportunities abound. Some recent announcements:
Exhibit 14
Source: Company reports, Gabelli Funds
Recent Announcements:
- Black Hills Corp. and NorthWestern Energy to Merge: On August 19, Black Hills Corp. (BKH) and NorthWestern Energy (NWE) announced an all-stock merger of equals (0.98x exchange, 4% premium). The combined utility will serve 2.1M customers across eight contiguous states, double its rate base to $11.4B ($7.0B electric, $4.4B gas), and target 5–7% long-term EPS growth. Pro forma EPS: $4.10 (2025), $4.35 (2026), $4.55 (2027). The deal, expected to close in 12–15 months pending shareholder and regulatory approvals, highlights renewed sector consolidation after slowing during COVID and rising interest rates. Both stocks traded at discounted multiples due to wildfire risk and limited data center exposure, but scale and synergies are increasingly critical. Likely future targets: IDA, POR, AVA, MDU, OTTR, AQN, UTL.
- TXNM Energy: On May 19, 2025, TXNM Energy agreed to be acquired by Blackstone Infrastructure for $11.5B ($61.25/share, 23% premium), at 11.8x EV/EBITDA, 20.4x 2026 EPS, and 1.8x rate base.
- Calpine: On January 10, 2025, Constellation Energy (CEG) agreed to acquire Calpine (27 GW gas-fired capacity) for $29.1B ($4.5B cash, $16.4B stock, $12.7B assumed debt). Adjusted multiple: 7.9x 2026 EV/EBITDA. Calpine was previously taken private in 2017 by Energy Capital Partners for $17B (9.1x EV/2017 EBITDA).
- ALLETE (ALE): On May 6, 2024, GIP and Canada Pension Plan Investment Board agreed to acquire ALE for $67/share (18% premium), or $6.2B including debt. ALE owns and develops renewables and transmission assets.
- Avangrid (AGR): On December 23, 2024, Iberdrola (Spain) acquired the remaining 18.5% stake in AGR for $35.75/share.
- Atlantica (AY): On December 12, 2024, Energy Capital Partners acquired Atlantica Sustainable Infrastructure PLC for $2.56B.
The implication is that other smaller companies will consider opportunities to be part of a larger utility, including AES, IDA, POR, OGE, AVA, MDU, OTTR, AQN, UTL, PNW, MGEE.
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.
Valuing Power Plants
More recently, the pendulum shifted and private equity firms are selling power plants and portfolios to IPPs. The cost of building new generation is high, particularly in the deregulated states like NY, IL, MA, CT and CA where developers face stringent environmental regulations, lengthy permitting processes, transmission constraints and local opposition. The price tag (replacement value) of new gas fired power has risen to over $2,400/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 July 17, 2025, TLN agreed to buy two highly efficient heat rate) combined cycle gas fired power plants with 2,880 MW’s of capacity for $3.8 billion ($3.5 billion adjusting for estimated tax benefits). The plants Caithness Energy’s (CE) Moxie Freedom Energy Center (1,035 MW’s; 2018) in PA and CE and BlackRock’s Guernsey Power Station (1,836 MW’s; 2023) in OH are important power plants in the overall stack in the PJM market. The purchase price reflects an acquisition multiple of 6.7x 2026 EV/EBITDA and $1,300/kw, which is a material discount to current new-build CCGT costs of roughly $2,400/kw. Both transactions are expected to close in the fourth quarter of 2025 (need FERC approval).
On January 10, 2025, CEG agreed to acquire Calpine, the largest gas-fored company in the US (27 GW’s) for $29.4 billion in cash and stock from Energy Capital Partners. valued at an equity purchase price of approximately $16.4 billion, composed of 50 million shares of Constellation stock and $4.5 billion in cash plus the assumption of approximately $12.7 billion of Calpine net debt. After adjustments, CEG considers the $26.6 billion net purchase price to be an acquisition multiple of 7.9x 2026 EV/EBITDA. Calpine was taken private in 2017 by Energy Capital Partners for $17 billion (9.1X).
On May 12, 2025, NRG agreed to acquire 13 GW of gas generation from LS Power 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.
On May 15, 2025, VST announced the acquisition of 2,557-MW’s 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 MW’s) in Bucks Conty, PA, and Manchester Plant (510-MW’s) in RI. Vistra said the Lotus portfolio is priced at approximately $743/kW.
Table 9 Recent Gas-Fired Generation Sales
Date Buyer Seller Value Capacity (MW’s) EV/2026 EBITDA
1/10/2025 Constellation Energy Calpine $29.4 billion 25,700 7.9X
5/12/2025 NRG Energy LS Power $12.5 billion 12,900 7.5X
5/15/2025 Vistra Corp Lotus $1.9 billion 2,600 7.0X
7/17/2025 Talen Energy Caithness $3.8 billion 2,900 6.7X
Source: Company reports, Gabelli Funds
In February 2025, Brookfield Asset Management agreed to buy National Grid Renewables 3 GW of projects renewable portfolio for $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 $2.6 billion ($22 per AY share) Atlantica Sustainable acquisition for $2.555 billion. The acquisition included 2.2 GW’s 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 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 first nine-months of 2025, the merchant power producers, CEG, VST, NRG and TLN, have been absolute “rock stars” rising on average 59% and 71%, respectively. The company’s 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 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 10 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 TLN 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
- 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 10 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 15). Electric utilities trade at ~19x consensus forward earnings estimates which is above (but near) the historical median (16.8x).
Exhibit 15 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 4.2% 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 16 the current ratio of 125% indicates the sector P/E is modestly higher than its historical median relationship (195%) with the 10-Year T-Bond Yield.
Exhibit 16 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 3.5-4.0% 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 slowdown, 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.
Appendix 1 Electric Utilities Selected Statistics
Appendix 2 Canadian, Power, Midstream, & Gas Utilities Selected Statistics
Appendix 3 Water Utility & Utility Construction Selected Statistics
Source: Thomson One
TOP TEN REASONS TO OWN UTILTIES: SUPPORTING THE POWER SURGE
- Electric demand growth to accelerate driven by data centers, electric vehicles and manufacturing
- Policy makers (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
- Long runway of rate base investment (infrastructure investment).
- Consolidation/Takeover could accelerate due to existing assets being more
- Healthy earnings and dividend growth potential (5-7%) could ramp
- Reasonable valuation of 19x 2025 P/E multiple (historical range 10-23x).
- Competitive current return of 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
- Abrupt policy changes
- Equity raises to fund
- Some utilities could mismanage
- Weather event risks, particularly wildfires.
Timothy M. Winter, CFA
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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 June 30, 2025, affiliates of GAMCO Investors, Inc. beneficially owned 7.17% of RGC Resources, 4.39% of National Fuel Gas, 2.68% of Southwest Gas, 2.19% of Northwest Natural, 1.58% of TXNM Energy, 1.48% of York Water, 1.03% of Black Hills, and less than 1% of all other companies mentioned.
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