U.S. Residential Electricity Prices on the Rise

Residential electricity prices rose sharply across much of the U.S. between 2021 and 2025, with a meaningful number of utilities recording compound annual growth rates (CAGRs) well over general inflation. This Insight analyzes residential electricity price changes across approximately 100 investor-owned U.S. electric utilities using FERC Form 1 financial data, revealing a striking structural pattern. The utilities with the largest residential price increases over the analysis period are concentrated predominantly among transmission and distribution (T&D) utilities operating in restructured wholesale electricity markets, particularly in the NYISO and PJM regions. The utilities with the smallest increases are drawn almost entirely from the vertically integrated utility (VIU) sector and largely operate in the Midwest and Southeast. Only three utilities in this analysis, Southwestern Electric Power, El Paso Electric, and Black Hills Power, all of which are VIUs, recorded modest price declines over the period.

Key Takeaways

• T&D utilities dominate the high-increase list. Of the top 14 utilities by residential price CAGR, 12 are T&D-only companies. The top four are all T&D utilities, led by New York State Electric & Gas (16.2% CAGR) and Baltimore Gas and Electric (16.0%).
• The low-increase list is made up of almost exclusively VIUs. Of the 25 utilities with the smallest residential price CAGRs, 23 are VIUs.
• Wholesale market structure appears to be a primary driver. The concentration of high-CAGR utilities in NYISO and PJM points to capacity-market cost escalation and competitive supply procurement costs as key contributors, which are effectively acting as pass-through mechanisms that bypass traditional rate case scrutiny but flow directly into residential bills.
• Residential customers face real affordability pressure regardless of cause. These are material impacts on household budgets that regulators and politicians are increasingly unlikely to ignore.
• Regulatory-risk framing matters for investors. Utilities with persistently high residential-price increases are accumulating affordability exposure that is likely to manifest in more contentious rate proceedings, heightened political scrutiny, and potentially constrained future rate recovery, irrespective of whether the utility itself or wholesale market dynamics are the proximate cause.

Methodology

All data is sourced from FERC Form 1 annual filings. Form 1 provides standardized, audited financial data, including revenue and electricity sales volumes by customer class, making it a consistently structured source available for cross-company comparison at the utility level.

Instead of using a single posted tariff rate, the effective residential price used for each utility is calculated as residential revenue (in dollars) divided by residential electricity sales (in GWh), converted to cents per kilowatt-hour. This approach captures all revenue collected from residential customers, including base distribution rates, fuel and purchased power pass-throughs, capacity cost riders, renewable energy surcharges, and any other components billed to this customer class. The result is a measure of what residential customers actually paid on average.

Price growth is measured as the compound annual growth rate (CAGR) from 2021 to 2025, a four-year period that captures the full arc from a pre-inflation baseline through the energy price shock of 2022 and its aftermath. The CAGR formula represents the average annual rate of price change needed to produce the observed endpoint-to-endpoint change and is the appropriate summary metric for comparing price trajectories across utilities with different starting levels.

A small number of utilities were excluded from the ranked results due to identified FERC Form 1 reporting anomalies, primarily related to how customers and electricity sales volumes are classified in competitive retail markets. In certain restructured states, some utilities report only bundled standard-offer customers and volumes on Form 1, rather than total delivery customers and volumes, which would materially distort the effective rate calculation. Where such anomalies were identified, the affected utilities were removed from the ranked tables rather than presented with potentially misleading figures.

Utilities are classified as T&Ds or VIUs based on the restructuring history of their home state. Utilities in states that required generation divestiture, including New York, Pennsylvania, Illinois, Ohio, Texas, and the New England states, are classified as T&Ds. Utilities that retain ownership of material generation portfolios are classified as VIUs.

Results: Ranked Residential Price CAGR, 2021–2025

The T&D/VIU Divide

The most striking feature of the ranked results is the near-complete separation between utility types across the two lists. Of the 25 utilities with the largest residential price CAGRs, 18 are T&D companies. The low-increase list runs almost entirely in the opposite direction: 22 of the 25 utilities with the smallest increases are VIUs, predominantly in the Midwest and Southeast.

This structural pattern is not coincidental. It reflects a fundamental difference in how costs flow through to residential customers under the two business models.

Why T&Ds Show Higher Price Growth

T&D utilities in restructured markets do not own generation assets. Instead, they acquire electricity on behalf of customers who have not selected a competitive retail supplier, a function typically called default service, basic generation service, or standard offer service. The cost of this procured electricity flows directly through to residential bills via pass-through mechanisms that, by design, do not require a traditional rate-case proceeding for each adjustment.

Several factors drove default service costs sharply higher over this period. Natural gas price spikes following Russia's invasion of Ukraine in early 2022 pushed wholesale electricity prices in gas-dependent markets, particularly NYISO and PJM, to multi-year highs. While gas prices have since normalized at the Henry Hub level, the impact on residential bills proved sticky: rate-case timing, the mechanics of multi-year supply procurement contracts, and the lag in pass-through true-up mechanisms meant elevated costs continued to flow through even as natural gas spot prices declined.

More durably, PJM capacity-market prices escalated dramatically over this period, driven by generation retirements, load growth from data center development, and changes to capacity auction rules. The 2024 PJM capacity auction for the 2025/2026 delivery year produced clearing prices that were dramatically higher than prior years, and these costs are passed through directly to default service customers, which are the majority of residential customers in PJM states. Unlike fuel costs, capacity-market prices are not mean-reverting in the near term; they reflect structural supply/demand dynamics in the PJM market that are expected to persist.

New York utilities face additional policy-driven cost pressures through the state's Clean Energy Standard, which requires utilities to procure renewable energy certificates and offshore wind capacity at above-market rates. These costs are recovered through delivery rate riders that appear on residential bills, regardless of whether a customer is on default service or competitive supply, and they have grown substantially as New York's clean energy targets have escalated.

Why VIUs Show Lower Price Growth

Vertically integrated utilities own their generation assets and recover generation costs primarily through base rates set in traditional rate cases, supplemented by fuel adjustment clauses for variable fuel costs. This structure produces more gradual and regulated cost recovery. Base-rate increases require formal regulatory proceedings with evidentiary hearings, customer advocacy, and commission approval. As such. this process is slower and more politically visible than automatic pass-through mechanisms, and that creates natural friction against rapid price escalation.

The geographic concentration of low-increase VIUs in the Midwest and Southeast reinforces this dynamic. These utilities operate in regions with lower power prices, less dependence on natural gas at the margin, and regulatory environments that have historically emphasized cost discipline. Several of the utilities at the very bottom of the increase distribution, Southwestern Electric Power, El Paso Electric, and Black Hills Power, all of which recorded slightly declining residential prices from 2021 to 2025, operate in regions with favorable generation mixes and limited exposure to the wholesale-market cost pressures that drove increases in NYISO and PJM.

The Affordability and Political Dimension

The structural explanation for why T&Ds show higher price growth than VIUs is analytically coherent, but it does not insulate those utilities from regulatory and political pressure. From a residential customer's perspective, the relevant fact is that the electricity bill increased substantially over the analyzed timeframe. Whether that increase reflects a capacity-market auction outcome, a clean-energy mandate, or a base-rate increase approved after a formal proceeding is unlikely to affect how customers or their elected representatives interpret the experience.

Regulators in virtually every area under NYISO’s and PJM’s jurisdiction have registered increasing concern about residential electricity affordability. Rate-case outcomes in states that have already experienced large increases have increasingly reflected affordability as a primary consideration, with commissions scrutinizing utility cost structures more intensively and, in some cases, denying or deferring substantial portions of requested increases. The political environment has amplified this pressure, with residential electricity prices becoming a visible consumer cost issue in state legislative debates.

Conclusion

For utilities that appear in the high-CAGR list, the investment implication is not simply that past price growth has been high, but that the affordability exposure accumulated over 2021–2025 creates a more challenging regulatory environment going forward, especially since the underlying cost drivers (capital-investment needs, capacity-market costs, policy mandates) have not yet moderated. Utilities that can demonstrate meaningful cost control in the components they do manage, like non-fuel operating and maintenance expenses, in particular, are better positioned to earn constructive regulatory outcomes than those presenting high cost levels alongside high customer bill growth.

Be sure to check back in for more Energy Market Insights as we continue to cover shifts in the utility regulatory space.

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