The significance of the 34 million megawatt-hours figure becomes clearer when placed in historical context. In the mid-1990s, before the wave of market restructuring that began under the Federal Energy Regulatory Commission’s Orders 888 and 889, virtually no commercial or industrial customer outside of self-generation arrangements could select a non-utility power supplier. The study’s finding that even states without organized wholesale markets or retail competition now host substantial customer choice volumes illustrates how policy innovation can fill gaps left by stalled restructuring. When market reform efforts largely halted in the early 2000s—following the California energy crisis, rising wholesale prices, and persistent political resistance in the western and southeastern regions—many observers assumed that customer choice would remain confined to the restructured states. Hybrid policies such as utility green tariffs and direct access provisions demonstrate a middle path: rather than opening entire retail markets to competition, states can grant choice to targeted customer classes or for specific resource types while preserving the traditional regulated utility framework.

Utility green tariffs deserve particular attention as a policy instrument. These tariffs allow large customers to contract with their incumbent utility for renewable energy supplies, typically through long-term agreements tied to new renewable projects built on the customer’s behalf. For utilities, green tariffs offer a way to retain large loads that might otherwise seek alternative suppliers or relocate to states with more flexible markets. For corporate customers, they provide the contractual certainty needed to make public commitments to renewable energy procurement, since many corporate sustainability accounting frameworks require evidence of long-term, attributable renewable energy contracts. The roughly 17 million megawatt-hours of renewable energy procured through hybrid pathways in the 18 states studied suggests that sustainability demand—driven largely by corporate climate commitments, investor expectations, and disclosure requirements—has been a primary engine of hybrid choice policy development, sometimes ahead of explicit state legislative intent.

The timing of this research is notable given the demand growth projections facing the U.S. power system. Data center electricity demand, which may triple between 2024 and 2028 according to analyses cited in the study, represents a qualitatively different load profile than historical commercial and industrial growth. Hyperscale facilities can draw hundreds of megawatts at peak, comparable to a mid-size city, and their siting decisions are influenced by factors including network connectivity, land availability, tax treatment, and the availability of clean power supplies. States that offer hybrid choice pathways may gain a competitive advantage in attracting these facilities, since corporate buyers increasingly seek both cost predictability and verifiable clean energy attributes. This creates a dynamic in which energy policy becomes intertwined with economic development strategy, as state regulators weigh the benefits of attracting large loads against the risk of shifting infrastructure costs onto other ratepayers.

The cost-allocation question is central to the study’s hypothesis that expanded choice could mitigate price impacts from demand growth. Historically, growing commercial and industrial demand benefited all ratepayers by spreading fixed system costs—generation plants, transmission lines, distribution networks—across larger sales volumes. Recent evidence from 2025, however, indicates that in some regions this relationship has reversed, with demand growth contributing to price increases where system capacity is strained. New large-load tariffs under development by utilities and regulators typically attempt to assign incremental costs to the customers who cause them, protecting existing ratepayers. Hybrid choice mechanisms can complement this approach: a large customer that contracts directly with a new renewable project, for example, may in principle bring its own generation resources to the system rather than drawing on existing capacity. Whether this benefit materializes depends heavily on tariff design, including whether the customer’s contract insulates it from broader system costs or whether network upgrades triggered by its interconnection are socialized across all ratepayers.

The study’s methodological approach—a narrative review leveraging public data sources—reflects both the strength and the limitation of policy research in this domain. Because hybrid choice operates through heterogeneous state-specific mechanisms, ranging from limited direct access caps in some states to comprehensive green tariff frameworks in others, standardized national datasets do not capture these transactions. Utility integrated resource plans, regulatory filings, and voluntary disclosure programs become the primary evidence base, and estimates derived from them carry inherent uncertainty. The 4% share of commercial and industrial demand served through hybrid pathways should therefore be read as an order-of-magnitude indication rather than a precise measurement, though it establishes that hybrid choice has moved well beyond the pilot stage in the states examined.

For policymakers in states without wholesale market access, the review offers a catalogue of design considerations. Direct access provisions, where they exist, are typically capped at a percentage of utility load, creating waiting lists and limiting participation. Green tariff eligibility criteria vary in whether they permit new renewable builds or only existing resources, whether projects must be located within the state or utility territory, and whether attributes are bundled or unbundled. Each design choice affects both the volume of procurement and the degree to which it supports new renewable development. The finding that half of the hybrid choice volume—about 17 of 34 million megawatt-hours—was renewable suggests that states with policies favoring new-build projects have captured greater sustainability value, a relevant consideration for states drafting their own frameworks.

Looking forward, the interplay between hybrid choice and potential future market formation warrants attention. The western and southeastern regions where hybrid choice is concentrated have been the subject of renewed interest in expanded regional transmission organization participation, driven in part by reliability concerns and the operational challenges of integrating large variable renewable resources. If additional states eventually join organized wholesale markets, the hybrid policies documented here could serve as transitional instruments that build regulatory experience with customer choice. Conversely, if states remain outside formal markets, hybrid mechanisms may continue to evolve toward greater sophistication, potentially incorporating storage, clean firm capacity, and other resources beyond conventional renewable procurement. In either scenario, the documented 34 million megawatt-hours of hybrid procurement establishes a baseline against which future policy developments can be measured.

The corporate dimension of this research also merits emphasis. Companies such as Google and Meta, which have sought Federal Energy Regulatory Commission approval to participate directly in wholesale markets, exemplify a broader trend of large electricity consumers becoming active participants in power system governance rather than passive ratepayers. In states without market access, these firms have historically faced limited options: accept default utility service, self-supply behind the meter, or advocate for policy change. The growth of hybrid choice in the 18 states studied indicates that this advocacy has produced results, and that regulated utilities have often proved willing partners when offered mechanisms to retain large loads. This cooperative dynamic—rather than the adversarial framing that characterized earlier debates over retail competition—may explain why hybrid choice has advanced in politically conservative regions where comprehensive restructuring failed decades ago.

Ultimately, the study contributes to a reframing of the U.S. customer choice landscape away from a binary of restructured versus non-restructured states and toward a continuum in which policy design determines the degree and character of customer choice. As demand growth intensifies competition for generation resources and grid capacity, the instruments documented in this review—green tariffs, direct access provisions, and their emerging variants—are likely to play an expanding role in how states balance load growth, affordability, reliability, and decarbonization objectives. The evidence that commercial and industrial customers have already used these instruments to procure tens of millions of megawatt-hours of electricity, including substantial renewable volumes, suggests that hybrid choice has established itself as a durable feature of the American electricity policy landscape rather than a temporary accommodation awaiting eventual market restructuring.

Subject of Research: …

Article Title: Pathways to meeting growing electricity demand through expanding customer choice: a review of emerging hybrid power choice policies and practices

Article References: O'Shaughnessy, E., & Villegas, J. (2026). Pathways to meeting growing electricity demand through expanding customer choice: a review of emerging hybrid power choice policies and practices. Frontiers in Sustainable Energy Policy, 5, Article 1766514. https://doi.org/10.3389/fsuep.2026.1766514

Image Credits: AI Generated

DOI: 10.3389/fsuep.2026.1766514

Keywords: electricity demand, customer choice, utility green tariffs, direct access, community solar, data centers, renewable energy, electricity policy, retail electricity markets, distributed energy resources, Pathways, meeting