PLUGGED INTO GROWTH
EPS CAGR’s RISE
Strong First Quarter 2026
In the first quarter of 2026, the S&P 500 Utilities Index gained 8.3%, significantly outperforming the broader market, with the S&P 500 declining -4.3% and the NASDAQ falling -7.1%. Most regulated utilities posted positive returns, with a median gain of 8%. The sector began the year with strong momentum, rallying 12% to an all-time high on February 27 before pulling back ~3% as macro conditions deteriorated. The escalation of the Iran war contributed to this shift, driving a sharp increase in oil prices and reinforcing utilities’ defensive appeal while simultaneously fueling inflation concerns and pushing the 10-year Treasury yield above 4.3%, creating a headwind for the group.
Table 1 Utilities Outperform In First Quarter
Despite this volatility, fundamentals remained the primary driver of performance. Utilities continue to deliver solid earnings growth, with most companies guiding to 6–8% EPS CAGR or better, supported by increasing electric demand, steady rate base expansion, and accelerating data center development. Although valuations have moved higher, the sector appears reasonably priced at roughly 18x 2027 EPS, reflecting the improved earnings outlook. In contrast, sentiment toward independent power producers weakened amid concerns about the durability of elevated power prices, particularly as new supply emerges and political scrutiny increases. This pressure was exacerbated by announcements of nearly 18 GW of new gas-fired capacity across Pennsylvania, Texas, and Ohio, funded by the U.S. and Japanese governments. At the same time, natural gas prices are likely to remain firm, supported by strong LNG demand and ongoing power sector growth, providing a favorable backdrop for midstream pipelines and gas utilities.
Looking ahead, we expect utilities to grow EPS at above historical rates through at least 2030, driven by continued strength in electric demand as large-load customers—including data centers and advanced manufacturing facilities—ramp toward full capacity. This demand requires robust energy infrastructure and rate base investment and appears supported by generally constructive regulatory policy. Utilities are proactively managing risks tied to AI-driven data center growth and customer affordability through long-term contracts, innovative tariff structures, and disciplined capital allocation, while benefiting from the scarcity value of regulated assets. Overall, we see compelling long-term opportunities across electric and gas utilities as well as midstream companies, with total return potential of 8–11%, driven by a 3.3% dividend yield and 5–8% EPS growth.
Exhibit 1 Stock to Capitalize on By Theme
Macro Outlook
From a macro perspective, the Fed’s outlook has turned more cautious amid the Iran war, which has heightened inflation uncertainty and delayed the path to lower rates. At the March 2026 FOMC meeting, policymakers maintained a modestly restrictive stance, revising both growth and inflation expectations higher. Chair Powell noted the economic impact of the oil shock remains uncertain and dependent on the conflict’s duration, while higher core inflation forecasts reflect both the energy shock and the ongoing AI-led investment cycle. Although the Fed cut rates by 75 basis points in 2025 to 3.50–3.75%, rising oil prices have pushed Treasury yields higher in 2026, with the 10-year at ~4.30%. Resolution of the conflict would likely ease oil prices, lower inflation expectations, and reduce Treasury yields—supportive for utility stocks.
Exhibit 2 Modest Rise in Ten Year Treasury Yield at 4.30% (was 4.18% at 12/31/2025)
The S&P Utility Sector – Third Best First Quarter 2026 Performance
Table 2 highlights the utility sector’s stable and solid multi-year performance relative to the S&P 500 eleven sectors. Year-to-date 2026, utilities were the third strongest sector behind only Energy (+38%) and Materials (+10%). The utility sector delivered double-digit returns in each 2024 and 2025, reflecting solid EPS growth but lagged faster-growing tech and cyclical sectors. In 2022, the utility sector was one of two sectors to generate a positive return (S&P 500 down -18%). The sector was the worst performer in 2023 (-7.1%) as the interest rate/inflation outlook remained elevated, recession fears faded, and growth sectors rebounded. Despite rising inflation and interest rates from 2022–2024, utility stocks continued to grow EPS and dividends at an accelerating pace. In 2025-26, clean-energy stocks outperformed strongly after several years of under-performance which we attribute to a better than anticipated outcome from the OBBB (tax credits through 2030) and recognition that renewables and battery storage will be a key part of meeting rising electric demand.
Table 2 Utilities Were Third Best Performing Sector in the First Quarter of 2026
While most regulated utilities generated a positive total return (8% median), the natural gas midstream pipeline stocks and large data center-oriented utilities were the best performers in the first quarter of 2026. ONEOK (OKE), Kinder Morgan (KMI), Williams (WMB) and National Fuel Gas (NFG) benefited from a resurgence in natural gas sentiment, higher gas prices and improving outlook for gas pipeline infrastructure development. Over the last several months, several large traditional electric utilities raised EPS growth rates, including AEP, ETR, and NEE or highlighted the prospect of higher EPS growth (PNW). We believe higher EPS growth profiles will continue to drive the sector over the next several years and discuss this on page 5.
Table 3 Best Performing Utility Stocks in First Quarter 2026
The non-utility independent power producers (see table 4) were the weakest performers after having led the sector in 2024 and 2025. The pullback reflects growing concern that the runway for outsized margins could be shortened by government intervention, new supply coming online and more creative supply (non-traditional behind the fence power). The wide range of 12-month highs and lows highlights the volatility of these non-utility power producers.
Table 4 Non-Regulated Merchant Power Companies Pull Back in Frist Quarter 2026
Notable First Quarter Events
During the first quarter of 2026, several notable developments reinforced the strong utility investment thesis: accelerating electric demand, rising capital investment, increased rate base growth translating into strong EPS growth.
- Consolidation continued: On March 2, 2026, AES Corporation agreed to be acquired for $15 per share in an all-cash deal led by Global Infrastructure Partners and EQT Infrastructure, alongside CalPERS and Qatar Investment Authority. The offer represents a ~13% discount to the prior trading close but a ~40% premium to the unaffected July 2025 share price, when takeover discussions first emerged. The transaction implies an enterprise value of $33.4 billion and a valuation of roughly 12.0x EV/EBITDA based on forward estimates. The transaction highlights increasing interest from large infrastructure investors in power and utility infrastructure and platforms.
- Nation’s First 5-GW Data Center Deal: On March 27, 2026, Entergy (ETR) announced a major expansion of its Meta (META) Hyperion data center development, which now totals $27 billion and could scale up-to-5GW in Richland Parish, LA. Meta is helping fund the infrastructure buildout, including ~5.2 GW of new gas generation, 240 miles of transmission, storage, nuclear upgrades, and up to 2.5 GW of renewables. The deal is expected to be materially accretive to the company’s already strong “greater than 8%” EPS growth target. Importantly, ETR expects the agreement to result in ~$2.65 billion in long-term customer savings. ETR is arguably the sector’s biggest data center beneficiary and secured massive deals with Meta, Google, and Amazon. More broadly, the Meta deal highlights the emerging U.S. utility-data center business model where large tech companies fund infrastructure investment to support their load growth. The ‘soon-to-be common’ template benefits utilities through rate base and EPS growth as well as customer affordability by spreading costs over larger base.
- Politicians Support New PJM Generation: On January 16, 2026, the White House and several Democratic governors proposed one-time emergency intervention in the PJM Interconnection capacity market through a Reliability Backstop Auction (RBA). The intervention and structure is designed to accelerate new power supply to come on-line and would require hyperscalers to pay for new power capacity regardless of usage. By September 2026, FERC and PJM would conduct an auction where data center operators would be the sole bidders for 15-year fixed-price contracts to support an $15 billion of new generation (roughly 6–10 GW).
- US/Japan Announce $66B for ~19 GW of New Gas Generation: On March 19, 2026, the White House announced a $33 billion tranche of its $550 billion Japan–U.S. initiative. The second tranche would add ~9.5 GW of new power generation, including two gas plants—a $16 billion (~5.2 GW) plant in East TX and a $17 billion (~4.3 GW) plant in southwestern PA (linked to Marcellus/Utica supply and the PJM Interconnection grid). The plants would be built and operated by NextEra Energy and jointly owned by the US/Japan. This follows a separate $33 billion plan for a 9.2 GW gas plant in Portsmouth, OH led by SB Energy to support a 10 GW data center. Combined, the 13.5 GW in PA/OH represents ~7–8% of PJM capacity, while the Texas project is ~3% of ERCOT. The initiative also includes $40 billion for SMRs in TN and AL by GE Vernova and Hitachi (BWRX-300).
- The Ratepayer Protection Pledge: On March 4, 2026, Amazon, Google, Meta, Microsoft, Oracle, OpenAI, and xAI signed a “ratepayer protection pledge” committing to ensure that data center growth does not increase electricity bills for households and small businesses. The agreement emphasizes that hyperscalers will pay their full share by funding new generation, covering grid infrastructure upgrades, and securing dedicated rate structures, aligning new demand with new supply. The pledge aims to address rising political and public concern over power costs by preventing cost-shifting to existing customers and reinforcing that large technology companies—not ratepayers—will bear the incremental costs of their energy usage.
- FERC ROE On March 19, 2026, Federal Energy Regulatory Commission (FERC) lowered allowed ROE’s for New England transmission owners (ES, Avangrid, National Grid, UTL) to 9.57% ROE, from the 10.57% set in 2014. ES and the other owners will appeal based on long‑standing judicial precedent requiring FERC to set rates of return sufficient to attract the capital. We do not expect the lower ROE to be applied prospectively or to other owners because the controversial action was in response to a 15-year-old complaint/litigation and used data from October 2012-March 2013. At the same time, FERC denied the three related subsequent complaints, as the base ROE was within the presumptive just and reasonable ranges (up to 12.09%). FERC most recently set the MISO base ROE at 9.98%.
Year-end EPS Reports Higher and Guidance Tailwinds Indicate Higher for Longer
During the 2025 year-end reporting season (January/February), electric and gas utilities generally delivered solid results, with median 2025 EPS coming in ~7% above 2024 levels combined with higher or reinforced long-term growth targets. Over the past year, most utilities increased capital programs and rate base growth rates. Leading utilities now guide to 8–9% EPS CAGRs (PCG, NI) and 8%+ (NEE, ETR), while the majority fall in the 6–8% or 5-7% EPS range. Even those that maintained 5-7% CAGR’s generally pointed to the high-end. Further, most utilities continue to lay the groundwork for future increases and discuss robust backlogs of new data center and large-load customers. Rate base growth is now roughly 10%per annum, ranging from ~7% to ~16%-per annum. Overall, the sector is experiencing a sustained step-up in growth, with consensus EPS CAGRs above 7% through at least 2028 and visibility extending into 2030–2032, though execution and regulatory risks remain. Current EPS CAGR targets are distributed as follows:
- 4–6%: 4 utilities (including BKH and NWE; merger target of 5–7%)
- 5–7%: 12 utilities (LNT+, D, DUK, OGE, POR, ES, EXC, PNW, EMA, OGS, OTTR, UTL)
- 6–8%: 11 utilities (ATO, EVRG+, XEL+, AEE, PPL, CMS, FE, DTE, PEG, ED, MDU)
- 7-8% WEC
- 8%-+ 3-utilities (NEE, ETR, CPK)
- 7–9%: 6 utilities (CNP, AEP, AWK, SRE, AES, NJR)
- 9%-+: PCG at “at least 9%”
In Table 5, we show each utility’s formal management EPS CAGR targets and consensus EPS CAGR’s.
Table 5
ELECTRIC DEMAND “VERGE OF SURGE” THESIS PLAYING OUT
The US electric demand “verge of surge” thesis appears to be playing out and supports the strong EPS growth. Electric forecasts are being revised upward as actual data center and industrial project announcements exceed previous expectations. While precise national demand levels are difficult to quantify because of regional differences, project overlap, efficiency gains, and economic conditions, the trajectory is clear: electricity demand is rising faster than it has in decades.
Exhibit 3 Electric Demand Growth Strongest Since Central Air Conditioning Era
The Federal Energy Regulatory Commission (FERC) State of the Markets Report (March 19, 2026) forecast an acceleration in electric demand growth for most regions (excluding CA and NY) from previous forecasts and now project peak load growth of ~3% or higher beginning in 2026, with further acceleration in later years. FERC forecast the PJM region to grow at nearly ~4% CAGR and CAL/SPP near ~3% from 2028 to 2030, including ~3.7% CAGR for PJM over 2026–2030. ERCOT expects total peak demand to rise ~10% over the same period. These projections represent a significant upward shift from 2022 forecasts, when most regions expected closer to ~1% growth, underscoring a structurally stronger demand outlook.
Exhibit 4 FERC’s Forecast of Load Growth Increases Each Year
According to the GridStategies (leading power reliability consulting firm) November 2025 report, power demand forecasts were revised upward for the third consecutive year. US electricity usage is forecast to grow by an average of 5.7% per year over the next five years, with peak demand growth forecast at 166 GW, a 3.7% annual rate. Over the past three years, the 5-year forecast of utility peak load growth has increased by from 24 GW to 166 GW. (see exhibit 5)
Exhibit 5 Electric Demand Growth Forecasts Continue to Increase
GridStrategies emphasize that overall electricity use is forecast to grow even stronger than peak power demand due to the high load factors of data centers. Data centers are the largest driver of demand and require much larger load factor (meaning the demand is constant not just peaking). New load for industrial/manufacturing, oil & gas/mining, and other load types is also increasing compared to recent decades.
In March 2026, S&P Global (S&P GMI) forecast US data center demand reached over 60 GW in 2025 and would grow to over 80-GW in 2026 and 180-GW in 2030. FERC estimates that more than 50 GW of data center capacity was in service by year-end 2025, reflecting a rapid ~24% compound annual growth rate since 2020.
Exhibit 6 Electric Demand Growth Forecasts Continue to Increase
Major technology companies (Amazon, Microsoft, Meta, and Alphabet, Oracle) continue to commit substantial capital to AI and data center expansion. (exhibit 7) Alphabet, Amazon, Meta, Microsoft and Oracle forecast combined capital expenditures of $650-700 billion in 2026, up from $359-381 billion in 2025. Amazon plans $200 billion, Alphabet $175-185 billion, Meta $115-135 billion, and Microsoft around $97-105 billion. Spending targets AI infrastructure including data centers, GPUs, servers, and power systems.
Exhibit 7 Major Tech Companies Spending More
What is the State of US Electric Demand Growth and AI Data Centers?
According to GridStrategies, 16 giga-scale data center projects representing ~30 GW of incremental load are scheduled to come online in 2026–2027. Facility size continues to expand meaningfully, with typical projects growing from roughly 40 MW to ~100 MW, and an increasing share of campuses exceeding 200 MW. OpenAI, Oracle, and SoftBank’s Stargate initiative outlines plans for up to 10 GW of AI computing capacity across multiple U.S. sites over time. Several large developments are pursuing on-site or co-located generation solutions, including the ETR-META site in LA, Homer City redevelopment in PA, Joule projects in Utah, Crusoe’s Stargate facilities in TX, and xAI’s Colossus project in TN. Exhibit 8 highlights the national breadth of the data center buildout.
Exhibit 8 Huge Data Centers Scheduled for 2026-2027
Data Center Backlash But They Are Coming
Data center growth is increasingly facing local opposition, with communities raising concerns about land use, electricity costs, and grid reliability. By mid-2025, more than 20 projects had been delayed or canceled, and nearly 200 activist groups had formed nationwide. In response, lawmakers in states including NY, SC, OK and ME have proposed measures to restrict or pause development, while smaller municipalities—particularly in MI and IN—have already enacted temporary moratoriums. Major cities like Denver and Detroit are also considering limits.
Large Load Tariffs Designed to Protect Customers
To address concerns, state regulators and utilities are implementing “large load tariffs.” which are designed to protect customers and force the “large-load customers” to pay for system upgrades. Definitions of “large load” have increased, from around 5–25 MW a few years ago to 50 MW or more today, reflecting the much larger scale of modern data centers. These tariffs have a few key characteristics:
- Higher upfront costs: Large users pay for the grid upgrades (new transmission or substations) needed to serve them.
- Long-term commitments: Minimum contract lengths and guarantees that the customer will pay for the power even if not used.
- Risk protections: If the project is delayed, scaled back, or canceled, the customer may owe fees or penalties.
- Operational requirements: Some include ramp-up schedules or incentives to reduce usage during peak times.
According to the Smart Electric Power Alliance, there are now about 77 large load tariffs proposed or in place across 36 states, with 29 approved in 2025. These tariffs are required to assure the public and the utility that rapid data center growth will not cause overall system rates to rise and ensure new large loads pay their fair share of grid costs.
BOTTOMS UP-UPDATE: DATA CENTER/LOAD GROWTH UTILTIES
From a bottoms-up perspective, we highlight several of the faster-growing utilities, bigger data center announcements and more significant backlogs, including AEP and PPL’s 56 GWs and 29 GWs. Given the affordability narrative, utilities more clearly stated hyperscalers are funding growth and some like NI, ETR, and SO note direct customer benefits. Many utilities extended strong EPS growth visibility though 2030 as large loads ramp capacity higher.
NEXTERA ENERGY (NEE) On January 27, 2026, NEE reported 2025 EPS of $3.71, up 8.2% from $3.43 in 2024 and affirmed its 2026 EPS guidance of $3.92-4.02 and expectation to grow EPS at an 8%-plus CAGR from 2025 – 2035. At its December 8, 2025, Analyst Day update, NEE raised its EPS CAGR targets to 8%-plus, from the high-end of 6-8% driven by numerous opportunities to capitalize on the secular change in electric demand, including regulated and contracted non-regulated investments. The Florida utility’s new four year rate plan includes a large load tariff, and the state recently passed legislation to allow data centers under customer protective measures. As such, we expect some large data center announcements from NEE over the near-term. The company’s non-regulated power business is the industry leader and will also likely see positive announcements over the near-term.
ENTERGY (ETR) On its February 12, 2026 EPS call, ETR affirmed its target of “greater than 8% EPS CAGR” and 8% retail sales growth 2025-2029, including 15% industrial growth, supported by agreements with at least three hyperscale data centers. We expect the company to further raise these targets due to its March 27, 2026 announcement of a major expansion of its Meta (META) Hyperion data center development, which now totals $27 billion and could sale up-to-5GW in Richland Parish, LA. Meta is funding the full infrastructure buildout, including ~5.2GW of new gas generation, 240 miles of transmission, storage, nuclear upgrades, and up to 2.5GW of renewables. ETR is arguably the sector’s biggest data center beneficiary and secured massive deals with Meta, Google, and Amazon. Amazon plans a $10 billion MS facility, and Google plans $4 billion in Arkansas. ETR forecasts 50 GW of large-load growth ~20 GW from data centers and 15 GW from other industrials—and plans 18 GW of new generation by 2034. The $43 billion 2026-2029 capital plan drives a 14% annual rate base CAGR. Meta and Google plan to fund new generation, transmission upgrades, and the ongoing share of Entergy’s costs. ETR – EPS growth expected to be “well over” 8%; ETR provides annual guidance with 2026-29 CAGR over 11%
DOMINION ENERGY (D) D targets 5-7% EPS CAGR from 2025-2030 (with a bias to upper half 2028-30) and is currently the largest data center provider in the US (with ~7 GW in service). It emphasized that data center-driven load growth in Northern Virginia shows no signs of slowing with over 10-GW’s contracted and 48.5 GW’s in queue. Dominion updated its 5-year capital plan to $64.7 billion (from $50.1 billion) on the year-end call. D’s $12 billion (75% complete) Coastal Virginia Offshore Wind Project (2.6 GW) expects to deliver initial power in the first quarter of 2026 and cull completion in early 2027.
WEC ENERGY GROUP (WEC). WEC targets an above-average long-term EPS CAGR of 7-8% (upper half 2028-2030) with 2028-2030 annual electric demand growth forecast to 6.0-8.0%, from 0.7% in 2025. WEC forecasts two data centers totaling 3.9 GWs of demand (45% increase from current peak demand) over 2026-2030. The $20 billion MSFT data center in Mt Pleasant, WI (Phase one-early 2026/Phase 2 scheduled for 2027) and the $8 billion Vantage Data Centers (1.3 GW) data center (Oracle) in Port Washington, WI. WEC expects a decision regarding the Very Large Customer Tariff (VLC) which dedicates new power sources (excluding rate cases) based on a 10.48-10.98% ROE with early termination fees. WEC’s 2026-2030 capital plan totals $37.5 billion and results in 11.7% rate base CAGR. WEC expects toad 6.5 GW of renewables and 3.3 GW of gas fire power.
PINNACLE WEST (PNW) PNW targets 5-7% annual EPS CAGR, expects 1.5-2.5% customer growth, 5-7% long-term sales growth (4-6% is C&I customers) 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.
CENTERPOINT ENERGY (CNP) On its year-end call, CNP extended its 7-9% EPS CAGR through 2035 and raised its load growth forecast to 10 GW or 50% by 2029 to reflect Houston load growth and higher capital investment (11% rate base CAGR. Load growth is underpinned by 2% annual residential customer growth plus Port of Houston electrification, data centers, medical center expansion, the energy sectors.
SOUTHERN COMPANY (SO) On its year-end call, SO raised its 2026-30 EPS growth rate to 8%, from previous 5-7% range. Strong growth is driven by 9% rate base growth from its $81 billion 5-yearcapital plan and strong load growth. SO has 10 GW of contracted large load under construction, and another 10 GW likely to be signed. The utility forecasts 10% sales growth in 2026-30 and 13% in GA over same period. In addition, SO expects to add at least 10 GW of new generation..
AMERICAN ELECTRIC POWER (AEP) AEP targets long-term growth of 7-9% and at least 9% CAGR by 2030 off 2025, driven by its $72 billion capital plan for 2026-30 ($47 billion for T&D; $13 billion for gas generation and $8 billion for renewables). Data center-related growth opportunities now total 56 GW of incremental load by 2030, but only 28 GW is in its plan. And generally good or improving regulatory frameworks support a rising earned return. AEP holds the largest backlog of major load contracts at 56 GW and boasts the largest transmission network, supporting its growth potential. Additionally, AEP benefits from improved regulatory tools in Ohio and Texas, which could lead to higher earned ROEs.
NISOURCE (NI) NI targets 8-9% annual EPS CAGR over 2026-2033 (6-8% annual EPS CAGR over 2026-2030) based on 9-11% annual rate base CAGR over 2026-2033 (8-10% annual rate case CAGR over 2026-2030). NI has agreed to a partnership with Amazon for 3 GW of power capacity (plans to add 2.6 GW of combined cycle gas and 400 MWs of batteries for $6-7.0 billion) ramping from 2027-2032 under a special electric service agreement. NI formed a non-regulated GENCO designed to serve mega-load customers, including Amazon. In addition, AMZN will pay a system charge under the special contract which will return $1 billion dollars to existing customers. NIPSCO residential customers are expected to receive a monthly bill credit beginning in 2027, reaching $7-9 per month in 2033.
XCEL Energy (XEL) XEL targets “6-8%-Plus” EPS CAGR, from “6-8%” to reflect 11% rate base growth driven by a $60 billion 2026-30 capital plan (with $10 billion upside) to support 20 GWs of data center pipeline, including 2 GW undre construction and 6 expected by 2027. 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 raised its base capital plan to $60 billion, reflecting 11% rate base growth.
IDACORP (IDA) IDA does not provide EPS growth targets but expects an industry-leading 16.7% rate base CAGR 2026-30. The June 2025 integrated resource plan (IRP) affirmed 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. On December 30, 2025, the ID PUC approved a constructive rate plan based on a 9.6% allowed ROE.
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. In PA, PPL operates in a favorable energy environment, sits on the Marcellus/Utica shale, and benefits from rising demand in the PJM market. PPL-PA has a 25.2 GW advanced-stage data center pipeline, including 10 energy service agreements (ESAs) and 5 GW under construction, along with a $3.5 billion manufacturing investment from Eli Lilly in Allentown. PPL’s ESAs include strong customer protections such as prepayments, credit support, and minimum load requirements (80% of forecast load) until infrastructure costs are recovered. Additional active data center requests exceed 50 GW through 2034. PPL is also pursuing new generation opportunities in PA, including a JV with Blackstone Infrastructure to develop long-term contracted non-regulated gas-fired plants. In Kentucky, PPL has a 9.3 GW development queue (2026–2032), including 8.2 GW of data center requests and 1.1 GW of manufacturing projects (Toyota, Foxconn, GE, and Anthro Energy). PPL-KY’s updated forecasts call for ~2.8 GW of new load by 2032, requiring new generation capacity. PPL is building the 600-MW Mill Creek Unit 5 CC plant scheduled for 2027, and two additional 645-MW CCGT units for 2030 and 2031, along with extending the life of certain coal plants.PPL’s 2026–2029 capital plan totals $23 billion (vs. $20 billion previously), including $4.3 billion in 2025, and supports 10.3% rate base growth through 2029 (up from 9.8%).
EVERGY (EVRG) EVRG raised its long-term EPS CAGR to 6-8%+ (including 8%+ beginning in 2028) off a 2026 EPS base of $4.24. EVRG set 2026 EPS guidance at $4.14-4.34. In February 2026, the utility signed 4 electric service agreements (ESAs) with hyperscalers (Google, Meta and Beale Infrastructure) for 1.9 GW of load, which represents a 20% increase in peak load. As a result, EVRG’s overall electric load is expected to grow ~6% annually 2025-30 and ~7% from 2026-2030. The company rolled forward and raised its 5-year capital plan by 24% to $21.6 billion which results in higher rate base CAGR of 11.5%. EVRG is building three new gas plants (1.860 MW’s; 2029-2031) and three solar farms (325-MW’s; 2027-28) and evaluating another 2,100 MW options for 2029 and beyond. The 2025-2035 IRP totals 6.600 MW’s, including several gas plants in early-2030s not in current plan. EVRG has outlined a strong pipeline of 10-GW large-load customers in active negotiation and MO and KS jurisdictions benefit from recently authorized large-load tariffs.
ALLIANT ENRGY (LNT) ) LNT affirmed its ‘5-7%-plus’ long-term EPS CAGR as well as its expectation to earn 7%-plus EPS growth 2027-2029. LNT continues to advance 3 GW (4 projects) of contracted data center load, which represents over a 50% increase from 2025 peak load (5.5 GW) through 2031 and ~11% electric sales 2025-31 CAGR. Construction on the first three large data centers is underway and demand ramps between 2027-2030. The Big Cedar Industrial Center Mega-site in Cedar Rapids, Iowa will house the two mega-data centers for QTS and Google while the Meta (260-370-MW) complex is on 500 acres in Beaver Dam, WI. Further, LNT remains in active negotiation for an additional 2-4 GWs and has various development-ready sites throughout Iowa. The 2026-2029 capital expenditures to $13.4 billion, including $4.1 billion for gas generation (1.6 GW new gas and 400 MW increased capacity), $5.0 billion for renewables (1.3 GW’s of wind/solar and1.0 GW of batteries) and $4.3 billion for electric and gas distribution. The investment results in 12%-plus rate base CAGR ($16.9 billion rate base in 2025 to $26.5 billion in 2029).
AMEREN (AEE) AEE affirmed its 6-8% EPS CAGR (upper-end), rolled forward/raised its 5-year capital program, raised its rate base CAGR to 10.6% and signed an additional 2.2 GW of large-load customers. Strong EPS growth is driven by AEE’s updated $31.8 billion 2026-30 capital program, which results in 10.6% rate base CAGR. Over 2026-2030, AEE expects 6.2% sales CAGR at Ameren Missouri under the assumption that 1.2 GWs of new load is on-line by end of 2030. In February 2026, AEE executed 2.2 GWs of electric service agreements (ESAs) with large load customers, representing sales and earnings upside to the current plan. AEE’s large load construction agreements totals 4.3 GW, including AEE-MO.4 GWs and Ameren Illinois total 850 MWs. On November 24, 2025, the MoPSC approved AEE’s Large Load Customer Rate Plan (+75 MW) with current base rate of (~$0.062/kWh). The plan includes an earnings sharing mechanism (65% for customers) and protections in case of reduced revenues from force majeure event.
CAN GRID HANDLE IT? NATIONS RELIABILITY COUNCIL CONCERNED
The North American Electric Reliability Corporation (NERC) January 2026 reliability assessment indicates concern that electric demand could outpace supply. NERC finds that 13 of 23 regions face resource adequacy challenges over the next decade, with reserve margins (cushion between peak demand and supply) under increasing pressure due to lagging infrastructure development, ongoing retirements of dispatchable fossil-fired generation, and a generation mix increasingly dominated by solar and battery storage.
Exhibit 9 North American Electric Reliability Corporation (NERC) Supply-Demand Concerns
Most regions remain adequate under normal conditions, but rising peak demand (including ~20 GW year-over-year increases) and greater reliance on weather-dependent resources (solar and battery storage) elevate the risk of supply shortfalls during extreme events, particularly in regions such as the Midwest, PJM, MISO, SPP, Texas, the Southeast, and the Northeast. Over the next decade, winter peak demand is expected to rise significantly, and without greater investment in firm capacity, transmission, and grid flexibility, many regions could face tighter operating margins and reliability risks.
Power Prices High So Capped by Politicians
The upcoming July 14, 2026 PJM Base Residual Auction (BRA) is once again in focus. The annual capacity auction has become a “lightning rod” for the affordability-data center debate. Most expect that capacity prices for the June 1, 2028–May 31, 2029 planning year will clear at the price cap of $333/MW-day set by the regions governors to minimize customer bill increases. Recent auctions have seen prices rise sharply, from ~$29/MW-day in 2024/25 to ~$270 in 2025/26 and ~$330 in 2026/27. The 13 state region has seen total capacity costs rise from $2.2 billion to $16.4 billion. The December 2025 auction (2027/2028 delivery year) cleared at the $333.44/MW-day cap as the system remains structurally tight. The auction saw PJM clear134,479 MW to serve over 67 million customers, but achieved only a 14.8% reserve margin—6.6 GW below the 20% target. Peak load increased 5,250 MW year-over-year, with ~5,100 MW attributable to data center demand. PJM estimates uncapped prices near $530/MW-day and has recommended raising future caps toward ~$550/MW-day.
The primary drivers of higher prices are accelerating data center/AI load growth and persistent interconnection delays, which have constrained new supply. The generation mix remains dominated by gas (43%), nuclear (21%), and coal (20%), reinforcing the scarcity value of existing dispatchable assets. Supply costs represent only ~20% of overall residential bills, with the remainder driven by transmission, distribution, and policy-related charges. Even so, utility bills have risen since 2023 due to inflation, higher interest rates, and rising power prices.
Table 6 PJM Auction Prices Sky Rocket From $29/MW-day to $333/MW-day Over Two Years
In response, policymakers are moving toward further intervention. In January 2026, the White House and several Democratic governors proposed a Reliability Backstop Auction (RBA) to accelerate new capacity. The framework would require large data center operators to fund new generation through 15-year fixed-price contracts, targeting ~$15 billion of investment (6–10 GW), with implementation expected by September 2026. The proposal underscores growing urgency around reliability and affordability as broader market reforms are considered.
The non-regulated or merchant power companies, Constellation Energy (~60 GW), Talen Energy (13 GW), Vistra (45 GW), and NRG (28 GW), have been significant beneficiaries and have locked in strong capacity revenues through 2028. In addition, they benefit from contracting and selling output These companies are the most leveraged to power supply shortages. Capacity ownership is shown below and includes pending and recently closed acquisitions.
Table 7 Largest Publicly-Traded Merchant Power Plant Owners (And Recent Acquisitions)
Source: Thomson One Consensus estimates, Company documents
However, the distribution utilities including Exelon, First Energy, PPL, Eversource, and Unitil must buy power from power pools like PJM and pass higher costs to consumers While the T&D utility earnings do not directly benefit or get hurt from the spike in the capacity or energy prices, they are obligated to recover these expenses from customers, which sets up the issue of “total bill” affordability.
US POWER EQUATION – ALL OF THE ABOVE POWER
At the end of 2025, the US had 1.352 GW total installed electric generation capacity, including 571 GWs natural gas (42%), 193 GWs of coal (14%), 161 GW of wind, (12%), 163-GW of solar (11%), 104 GW of nuclear (8%), 102 GW hydro (8%), 36 GW of oil (3%), and other resources at 2%. In 2025, the U.S. power output was led by natural gas roughly 40%, coal at ~17%, nuclear 18%, wind 11%, solar 7%, hydro 6% and other 1%. In 2024, natural gas represented 42% of output, nuclear 19%, coal 16%, wind 11%, hydro 6% and solar 5%.
Exhibit 10 US had 1.352 GW total installed electric generation capacity
For 2026, EIA/FERC expect ongoing structural shifts with natural gas at ~41%, coal declines further to ~14%, renewables rise to ~27% driven primarily by solar capacity additions and steady wind growth, and nuclear remains broadly stable near ~19%.
Exhibit 11 US Power Generation Fuel Mix-Coal Declines
Source: Gabelli Funds; FERC; EIA
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.
Looking forward, FERC identifies 131 GW of high-probability capacity additions from December 2025 November 2028, led by solar (86.5 GW), wind (20.0 GW), and gas (22.8 GW), against 39 GW of retirements. These figures exclude battery storage, which is expected to add roughly 125 GW by 2035 and is increasingly paired with solar.
Table 8 US Plans to Add 131 GW’s of Primarily Solar to Existing 1,352 GWs (Installed)
According to FERC, the U.S. added 36 GW of new capacity, primarily solar (26.5 GW), followed by wind (5.7GW) and gas (4.2 GW). Batteries added another 15 GW. In 2026, developers plan to add 86 GWs of power capacity, including 43 GW of solar, 12 GW of wind, 7 GW of gas and 24 GW of utility-scale battery storage to the grid this year. U.S. battery storage capacity has grown exponentially over the last five years with more than 40 GW added to the grid during this period. Projects in three states make up the bulk of planned battery storage capacity in 2026, accounting for about 80% of the new U.S. battery storage capacity: 53%, or 12.9 GW, in Texas; 14%, or 3.4 GW, in California; and 13%, or 3.2 GW, in Arizona.
Exhibit 12
U.S. Power Supply Outlook
Political and economic realities suggest the U.S. will expand power supply in three phases over the next decade:
- 2026–2030: Renewables (primarily solar) and battery storage dominate new build.
- 2028–early 2030s: Gas-fired capacity expands as turbines come online.
- Early–mid 2030s: Next-generation nuclear emerges as costs and policy improve.
New Renewables; Navigating a Changing Environment
The near-term power development pipeline reflects net-zero carbon policies, state and corporate mandates as well as tax incentive urgency. S&P Global market Intelligence (SPGMI) data identifies roughly 350-GW’s of renewable (wind and solar) power planned through 2030, including 269 GW if utility-scale solar and 79-GW of wind. Much of this capacity is being accelerated to qualify for OBBB/IRA tax credits, with solar and storage favored due to faster development timelines and cost competitiveness.
NextEra Energy remains the dominant U.S. renewables developer, currently owning 37.5 GW and planning 71–90 GW of new wind, solar, and storage through 2032 (wind 9–15 GW, solar 32–42 GW, storage 32–43 GW). At its December 2025 Analyst Day, NEE outlined a broader long-term development opportunity of ~285 GW, spanning renewables, storage, gas, and nuclear, highlighting “bring-your-own-generation” solutions for hyperscalers managing affordability. Berkshire Hathaway Energy 15.7 GW.
Nearly 6-GWs of Offshore Wind to Come On Line 2025-2027
Several large-scale U.S. offshore wind projects totaling nearly 6-GWs of power capacity have either recently come online or are expected to reach completion between 2025 and 2027.
- South Fork Wind: (NY/RI)-full operation in 2024 with 132 MW of capacity.
- Vineyard Wind 1: (15 miles south of Martha’s Vineyard), completed in 2025, 800 MW of capacity.
- Revolution Wind (RI/CT) expect completion in second half of 2026, 704-MW
- Sunrise Wind, a 924 MW project located east of Montauk Point completion in 2027.
- Empire Wind 1 (south of Long Island) late 2026 and reach full commercial operation in 2027, 810 MW
- Coastal Virginia Offshore Wind 2.6 GW of capacity and expected full operation first half 2027.
The Biden administration target to deploy 30 GW of offshore wind by 2030 as part of its broader net-zero carbon goals was challenged by rising costs, supply chain challenges, and permitting delays. More recently policy direction has shifted and U.S. offshore wind buildout is likely to pause for an extended period. Recent Trump policies—extending coal plant life, expanding gas infrastructure, and supporting nuclear—slow the net-zero trajectory but improve near-term reliability and affordability.
Exhibit 13 Planned New Renewable and Natural Gas Capacity
Source: NextEra Energy December 2025
Gas Generation to the Rescue
After years of underinvestment, natural gas-fired generation has regained prominence. We expect at least 20 GW of gas-fired power capacity by 2028, 60-GWs by 2029 and 100-GW’s by 2030. In the fourth quarter of 2025, the GEV’s cumulative backlog totaled 83 GW, up 21 GW from the previous quarter. GEV reiterated its guidance for 20 GW of annualized turbine production by mid-2026 and said it could stretch production at its two existing facilities to annualize production of 24 GW by mid-2028. The “big three” (GE Vernova, Siemens, Mitsubishi) all highlight backlogs stretching to ~2030.
Exhibit 14 Planned New Renewable and Natural Gas Capacity
Source: NextEra Energy December 2025
Midstream Operators
Natural gas remains central to meeting rising energy demand, with consumption projected to grow significantly through 2030. Between 2025 and 2030, demand is expected to increase by about 29 Bcf/d, driven by LNG exports, pipeline flows to Mexico, and growth in industrial and power sectors. This surge is creating substantial expansion opportunities for North American pipeline operators.
Exhibit 15
Kinder Morgan (KMI) KMI highlights a $10 billion project backlog, about $9.1 billion tied to natural gas infrastructure, including $5.7 billion for power and $2.1 billion for LNG. Key projects include the Trident Pipeline (2.0 Bcf/d from Katy to Port Arthur), South System Expansion 4 (adding 1.3 Bcf/d for Southeast power demand), and Mississippi Crossing (2.1 Bcf/d from the Haynesville to the Southeast). The company is also tracking an additional $10 billion of similar “shadow backlog” opportunities.
The Williams Companies (WMB) is evolving from a traditional pipeline operator into an integrated energy provider. Its backlog includes 13 major projects, adding 7.1 Bcf/d of capacity (about 20% growth) by 2030, largely along the Transco corridor. Notable projects include the Southeast Supply Enhancement (1.6 Bcf/d) and Louisiana Energy Gateway (1.8 Bcf/d by 2026). WMB is also expanding into behind-the-meter (BTM) power, building gas-fired plants at data centers to bypass grid constraints. Leveraging its 33,000-mile network, this approach offers faster deployment, with its $7 billion Power Innovation portfolio led by Project Socrates in Ohio.
Enbridge (ENB) has a $39 billion backlog focused on linking natural gas and power demand, particularly for data centers. Key projects include the 4.5 Bcf/d Rio Bravo pipeline serving LNG exports and the $1.1 billion Ridgeline Expansion supplying the Kingston Energy Complex. ENB is also developing BTM solutions that pair gas with renewables, including the 600 MW Clear Fork solar project in Texas and the Cowboy Phase 1 project in Wyoming, combining solar and battery storage to support large data center customers.
ONEOK (OKE) is building a fully integrated midstream platform with over $8 billion in projects. Major developments include the 2.8 Bcf/d Saguaro Connector to Mexico and the 3.7 Bcf/d Eiger Express Pipeline linking Permian supply to the Katy hub. The company is leveraging its 60,000-mile system to provide dedicated gas supply for data center microgrids, helping customers bypass grid constraints. It is also seeing strong demand for its 57 Bcf of storage, used by power generators to manage volatility. Through acquisitions such as Magellan, EnLink, and Medallion, ONEOK has expanded across the full value chain from production to export.
NUCLEAR IS THE FUTURE BUT WHEN?
Nuclear power provides 24/7 zero-carbon generation, and highly valued by policymakers and hyperscalers. While new large-scale reactors are unlikely before 2035, momentum is building through restarts, life extensions, and small modular reactors (SMRs). Policy support (NRC permitting streamlining, domestic fuel supply measures, and international partnerships) provides confidence and backing the future of nuclear for long-term capacity growth. Corporate demand is reshaping the market: Amazon, Microsoft, Google, and Meta are pursuing PPAs to meet 24/7 carbon-free targets. Landmark deals include:
- Amazon/TLN/Susquehanna (PA): 1,920 MW through 2042, transitioned to front-of-the-meter for PJM delivery.
- Microsoft/CEG/Three Mile Island (PA): 20-year PPA for the 820 MW restart by 2028.
- Meta/CEG/Clinton Nuclear (IL): 1,092 MW PPA starting 2027, a 30 MW uprate, and SMR potential.
- GOOG/NEE/Duane Arnold (IA): 630-MW PPA starting in 2028
Most U.S. nuclear plants (94) are regulated, limiting hyperscaler procurement to 23 merchant reactors in deregulated markets like PJM. Rising demand and limited unregulated supply are increasing their strategic value. Restarts include Palisades, MI (800 MW, restarted 2025); Duane Arnold, IA (600 MW/2028 restart); Three Mile Island Unit 1, PA (820 MW/2028 restart).Key unregulated operators positioned to benefit include Constellation Energy (22 GW, 14 plants), Vistra Corp (6.4 GW, 4 plants), NextEra Energy (2.9 GW, 3 plants), Talen Energy (2.6 GW, Susquehanna), and PSEG (5.9 GW, 3 plants). These assets provide scarce, carbon-free generation as electricity demand and corporate procurement accelerate.
SMR deployment in North America is progressing but remains a “five-years out” story, with most meaningful commercialization expected around 2030–2035. TerraPower received its first NRC construction permit in 2026 for its 345 MW Natrium reactor in WY and is targeting operations by 2031, one of the clearest near-term timelines. NuScale Power—the only company with an NRC-approved design—continues advancing projects like its Romania deployment, where first-module operation is expected around 2033. Meanwhile, Oklo remains earlier-stage, progressing through licensing and site development with commercial deployment likely in the early 2030s. Utilities and developers such as Tennessee Valley Authority and Ontario Power Generation are advancing SMR plans this decade, but most projects are still in permitting, design, or early construction phases. While AI-driven power demand and corporate partnerships are accelerating interest, long lead times, regulatory processes, and financing needs mean SMRs are unlikely to contribute materially to power supply before 2030, with broader scale deployment expected in the early-to-mid 2030s.
Interconnection updates (PJM + national context)
New power plants need permission and capacity to use transmission lines and there is a waiting list to use them. Interconnection queues remain the binding constraint on U.S. power system expansion, as highlighted in FERC’s March 19, 2026 State of the Markets report and the January 2026 NERC Long-Term Reliability Assessment. Across organized markets, more than 2,000 GW of generation and storage is estimated to be awaiting interconnection nationwide, reflecting a backlog that has more than tripled over the past several years. In PJM specifically, roughly 170 GW of interconnection requests have been processed since 2023, with about 30 GW still in transition queues targeted for review in 2026.
Despite recent reforms, average interconnection timelines now range from approximately 3 to 5+ years in major ISOs, driven by the need for detailed system impact studies, transmission upgrade requirements, and limited engineering capacity. FERC and NERC both emphasize that these delays are increasingly misaligned with accelerating large-load growth—particularly data centers—and are now a primary factor constraining capacity additions and contributing to tightening reserve margins across multiple regions.
Bring Your Own Power
Many developers are increasingly turning to behind-the-meter power solutions to accelerate time to electricity. Rather than waiting years for combined-cycle plants or transmission upgrades, developers are prioritizing speed by deploying modular, on-site generation that can be installed in months. The first phase typically relies on reciprocating gas engines and mobile generator units and/or followed by aeroderivative gas turbines. Together, these modular systems allow developers to stand up meaningful capacity well before traditional plants can be completed, effectively creating temporary or semi-permanent “power campuses” co-located with demand. At the same time, newer technologies such as fuel cells from Bloom Energy are gaining traction. Fuel cells offer fast deployment and continuous, on-site power.
Supply – Demand Equilibrium
As outlined in the individual company comments, regulated electric utilities are actively adding generation—primarily gas, renewables, and battery storage. Supported by state regulators and rate recovery mechanisms, regulated utilities can 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. The US funded and accelerated supply combined with significant additions planned by utilities and other developers as well as various creative supply (hundreds of CAT generators; Bloom Energy fuel cells) of behind the meter cause concern that supply could meet demand earlier than expected.
RECORD INVESTMENT (RATE BASE GROWTH) LEADS TO EPS GROWTH UPDATED
In 2026 and 2027, S&P Global Market Intelligence projects utility capital expenditures will rise to $227.8 billion and $233 billion, respectively, with continued growth over the next decade driven by rising demand and the need for new baseload generation. Capital spending for this peer group of 44 North American electric utilities increased 15% nominally in the first three quarters of 2025 compared with the same period in 2024.
Exhibit 16 Record Capital Investment
Full-year 2025 capex is projected to rise 19% year over year (16% real) to $215 billion, up from $173 billion in 2024, $164 billion in 2023, and $146 billion in 2022, implying a 10.5% three-year CAGR. This represents a sharp acceleration from the 7% nominal (4% real) CAGR of the prior decade, which was driven by climate policy, net-zero targets, fossil-fuel retirements, renewable development, infrastructure replacement, disaster recovery, and grid hardening. More recently, utilities have pushed capital budgets and rate base growth to historic highs to meet surging demand, including long-term power contracts with mega-cap technology companies for AI data centers that can consume energy at the scale of small cities. The larger utility capital plans are listed below:
Table 9 Utilities Raise 5-Year Capital Plans
Nearly 70% of North America’s grid infrastructure is more than 25 years old (DOE), driving investment in system replacement, renewable mandates, modernization, and weather resilience. Investment spans all major areas of the system, including distribution (33%), generation (24%), transmission (20%), gas-related infrastructure (14%), and other (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 are accretive when executed above book value and when regulators permit returns on the invested capital.
MORE RATE CASES TO SUPPORT HIGHER CAPEX-MEDIAN ROE 9.7%
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). With mid-term elections coming later this year, 36 states and the District of Columbia will be conducting gubernatorial elections in 2026, while legislative elections will be held in 46 states and Washington, DC. 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 17), 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 17 State PUC Rankings – AL, FL, GA, PA Constructive; CT, MD Not So Much
In 2026, RRA raised the ranking of California regulation to Average/1 from Average/2 (improving treatment of incremental wildfire liabilities) and raised Arizona’s to Below Average/1 from Below Average/2, reflecting constructive recent rate case decisions and implementation of previously approved generic rules for alternative ratemaking plans. RRA lowered the ranking of Montana regulation to Below Average/1 from Average/3 to reflect incremental risk associated with recent rate case developments and personnel changes at the Montana Public Service Commission and lowered the designation of Alaska regulation to Below Average/2 from Below Average/1 due to the absence of innovative or proactive developments.
During January 2026, eight base rate cases were completed, with a net $433.8 million in increased revenue authorized. The authorized ROEs for the five proceedings that disclosed cost-of-capital parameters ranged from 9.40% in New York to 10.00% in Missouri. In 2025, the highest authorized ROE was 10.95% for Florida Power & Light (FPL) in Florida, awarded November 2025 and the lowest was Yankee Gas 9.32% (53.9% equity ratio) in CT also in November of 2025.
Exhibit 18 PUC’s Reluctant to Raise Profits Despite Higher Treasury Yields
Source: S&P Global; RRA; US Treasury
Authorized returns have generally followed the overall direction of interest rates, with a lag. However, the magnitude of the year-over-year change in authorized ROEs is generally much smaller than interest rate changes. 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 540 basis points (9.7% vs 4.3%)
Affordability Becomes a Political Issue But More So in Some States Than Others
Rising electricity costs have pushed affordability into the political spotlight, particularly in PJM regions where capacity auction spikes drove notable bill increases in 2024–2025. This has prompted political and regulatory responses, including action from Pennsylvania’s governor and heightened scrutiny in states like New Jersey and Georgia. In parallel, utilities are using large-load tariffs and long-term contracts to serve data centers while protecting existing customers by assigning costs and risks directly to new demand. Despite political rhetoric, regulatory outcomes have remained largely constructive, with supportive rate decisions and manageable risk across most jurisdictions. Importantly, higher bills reflect multiple factors—including inflation, infrastructure investment, and supply constraints—not just data center growth. While affordability pressures vary by region and remain a recurring political issue, regulators continue to balance customer impacts with utility financial health, and the overall environment remains stable.
In Table 13, 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,
Table 10 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:
Table 11 Recent Acquisitions
Source: Company reports, Gabelli Funds
Recent Announcements:
- AES CORP: On March 2, 2026, AES Corporation agreed to be acquired for $15 per share in an all-cash deal led by Global Infrastructure Partners and EQT Infrastructure, alongside CalPERS and Qatar Investment Authority. The offer represents a ~13% discount to the prior trading close but a ~40% premium to the unaffected July 2025 share price, when takeover discussions first emerged. The transaction implies an enterprise value of $33.4 billion and a valuation of roughly 12.0x EV/EBITDA based on forward estimates. The transaction highlights increasing interest from large infrastructure investors in power and utility infrastructure and platforms.
- ALLETE (ALE): On December 15, 2025, GIP and Canada Pension Plan Investment Board acquired ALE for $67/share (18% premium to May 5, 2024 closing price), or $6.2B including debt. ALE owns and develops renewables and transmission assets
- BLACK HILLS CORP/NORTHWESTERN ENERGY: On August 19, 2025, 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 rate base to $11.4B ($7.0B electric, $4.4B gas), and target 5–7% long-term EPS growth. 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.
- 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 7, 2026, Constellation Energy (CEG) closed on the acquisition of 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).
The implication is that other smaller companies will consider opportunities to be part of a larger utility, including IDA, POR, OGE, AVA, MDU, OTTR, AQN, UTL, PNW, MGEE, and SWX.
Utility Stocks Trade at Reasonable Valuations
We believe the utility EPS growth supported by capital investment in utility infrastructure (rate base) 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 12 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 18.2X 2026 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. After roughly 30% pull-backs from extraordinary stock price and EBITDA/EPS growth in 2024-2025, the sector trades at ore reasonable EV/EBITDA multiples of ~8.0X.
- Gas utility performance reflects improved investor sentiment and ongoing consolidation but likely does not reflect potential increased gas demand. Gas utilities currently trade at 18.0x 2026 earnings estimates.
- Water utility two-year under-performance reflects the impact of higher interest rates on higher multiple stocks. Water utilities trade no longer trade at the highest multiples and are more attractively valued than they have been in recent years. They are unique investments 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, but Fortis, Emera and Algonquin have more assets and earnings power in the US than Canada. Canadian provincial regulatory environments are more challenging (lower allowed ROEs and equity ratios) than many US utility jurisdictions.
Table 12 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 20). Electric utilities trade at ~18.0x consensus forward earnings estimates which is above (but near) the historical median (16.8x).
Exhibit 19 Absolute P/E Multiple Range Near Historical Median Despite Stronger EPS CAGR
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 3.5-3.75% 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 2025, electric utilities increased the annual dividend by a median of 5.4%.
- 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.
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 21 the current ratio of 129% indicates the sector P/E is modestly higher than its historical median relationship (190%) with the 10-Year T-Bond Yield.
Exhibit 20 Utility Earnings Yield as a Percent of 10-Year T-Bond Yield (near Historical Median)
Source: Thomson One, Company documents
Conclusion
Over the next five years, the electric demand visibility is strong as large-scale data centers continue to ramp through phased buildouts, supporting sustained load growth and increased utility capital investment. This is driving higher earnings power across the sector, with limited perceived counterparty risk given the financial strength of hyperscalers such as Microsoft, Meta, Amazon, and Google, as well as chip manufacturers. Utilities have effectively secured high-quality customers and are now entering an execution phase, with the current build cycle expected to run through 2026–2029 before transitioning to the next wave of investment. Many utilities are positioned to sustain strong EPS growth. Affordability challenges are more acute in deregulated regions exposed to wholesale price volatility, whereas traditional regulated utilities continue to benefit from data center-driven demand growth and maintain their role as defensive investments. The utility sector offers a 3.3% current return and many utilities managements target 6-8% annual earnings and dividend growth. The utility business model represents a safer haven in the face of an economic slowdown, geopolitical issues, tariffs and/or inflation fears. 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
Source: Public data, Gabelli Funds estimates
Appendix 2 Canadian, Power, Midstream, & Gas Utilities Selected Statistics
Source: Public data, Gabelli Funds estimates
Appendix 3 Water Utility & Utility Construction Selected Statistics
Source: Thomson One
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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 December 31, 2025, affiliates of GAMCO Investors, Inc. beneficially owned 7.09% of RGC Resources, 4.10% of National Fuel Gas, 2.56% of Southwest Gas, 2.19% of Northwest Natural, 1.80% of TXNM Energy, 1.45% of York Water, and less than 1% of all other companies mentioned.
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
Investors should carefully consider the investment objectives, risks, charges and expenses of the Fund before investing. The prospectus, which contains more complete information about this and other matters, should be read carefully before investing. To obtain a prospectus, please call 800 GABELLI or visit www.gabelli.com
Returns represent past performance and do not guarantee future results. Current performance may be lower or higher than the performance data quoted. Investment return and principal value will fluctuate so, upon redemption, shares may be worth more or less than their original cost. To obtain the most recent month end performance information and a prospectus, please call 800-GABELLI or visit www.gabelli.com
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This whitepaper is not an offer to sell any security nor is it a solicitation of an offer to buy any security.
For more information, visit our website at: www.gabelli.com or call: 800-GABELLI
914-921-5000 • Fax 914-921-5098 • info@gabelli.com
Gabelli Funds, LLC is a registered investment adviser with the Securities and Exchange Commission and is a wholly owned subsidiary of GAMCO Investors, Inc. (OTCQX: GAMI).
