Since 2007, Shale Gas Has Saved U.S. Consumers Approximately $200 Billion Annually — A Quiet Revolution in Affordability

A new analysis from the Energy Institute at Haas at UC Berkeley quantifies what many in the energy sector have long known: the shale gas revolution, powered by hydraulic fracturing and horizontal drilling, has delivered extraordinary savings to American consumers. According to Lucas Davis’s May 2026 working paper and accompanying blog post, shale gas has saved U.S. natural gas consumers $4.5–$5.3 trillion cumulatively since 2007, or roughly $237–$276 billion per year. With reasonable adjustments to demand elasticity, the figure aligns closely with the ~$200 billion annually highlighted in recent discussions.

These savings stem from a dramatic divergence in natural gas prices. Before 2007, U.S. prices tracked closely with those in Europe and Japan. Post-shale boom, U.S. prices stabilized around $3 per Mcf while international LNG-linked prices soared — creating persistent gaps of $9/Mcf versus Europe and $11/Mcf versus Japan. Multiplying these differentials by U.S. consumption (around 30 billion Mcf recently) yields the massive annual benefit. About 39% of the savings flowed to the electric power sector, directly lowering electricity generation costs. Texas saved the most in absolute terms; Louisiana led in per capita savings. Every American benefited indirectly through lower production costs across the economy.

The working paper uses a straightforward counterfactual: without shale, the U.S. would likely have become a major LNG importer, paying global prices. The analysis draws on EIA data for prices, consumption, and trade flows. It builds on earlier work like Hausman and Kellogg (2015) but focuses on realized LNG price differentials.

Electricity Prices Since 2007: National Rise, Stark State Differences

While shale gas dramatically lowered the fuel cost for power generation, average U.S. retail electricity prices have still increased since 2007. EIA data show the national average retail price rose from about 9.13 ¢/kWh in 2007 to roughly 12.9–13.6 ¢/kWh in recent years (with residential rates often higher, exceeding 16 ¢/kWh in many areas by 2024–2025). Nominal increases reflect inflation, grid investments, demand growth (including data centers and EVs), and policy-driven costs — but shale gas clearly mitigated what would have been far steeper rises from higher natural gas prices.

State-level variation tells a clearer story when viewed alongside energy mixes and policy choices:

Shale-rich or gas-heavy states (Texas, Louisiana, Pennsylvania, Oklahoma, North Dakota) generally saw more moderate price increases or remained among the lower-cost states. Abundant local natural gas, combined with market-oriented approaches, kept generation costs competitive. Texas, despite massive wind additions, maintains relatively affordable power thanks to its ERCOT market and gas fleet flexibility.
High-renewable-mandate states (California, Hawaii, many Northeastern states) experienced the sharpest rises. California’s average prices now exceed 27 ¢/kWh in recent data — among the highest in the nation — amid aggressive renewable targets, transmission buildout, and regulatory costs. New England and other RPS-heavy regions show similar patterns.

Over longer periods (e.g., 2005–2025), California and several New England states rank among those with the largest price increases. In contrast, many interior and shale-producing states experienced smaller escalations.

Energy Mix Shifts and the Dual Role of Natural Gas

Since 2007, the U.S. electricity generation mix has transformed:

Natural gas share surged (now often ~40%+ nationally) as cheap shale gas displaced coal.
Wind and solar grew from negligible levels to double-digit shares in many regions.
Coal declined sharply.

EIA state electricity profiles and generation data illustrate the divergence. Texas leads in wind while retaining strong gas capacity. California pushed solar and wind aggressively but relies on gas for reliability and imports power. Midwest states added substantial wind. High-renewable-penetration areas often pair variable resources with flexible gas generation for balancing.

Shale gas enabled this transition by providing low-cost, dispatchable backup. Without it, integrating high shares of wind and solar would have been even more expensive or unreliable.

Regulatory Burdens, Renewables, and the Real Costs of Intermittency

Many states imposed Renewable Portfolio Standards (RPS) requiring utilities to source increasing percentages of electricity from renewables. Compliance costs — through renewable energy credits (RECs), above-market contracts, and grid upgrades — are passed to ratepayers.

Studies document pressure on prices upward:

An EPIC/University of Chicago analysis found RPS policies raised retail electricity prices by about 11% (1.3 ¢/kWh) seven years after passage and 17% (2 ¢/kWh) after twelve years across 29 states, with consumers paying over $125 billion extra in the first seven years.

LBNL assessments show RPS compliance costs averaging around 4.3% of retail bills recently (up from ~2.2% earlier), with wide variation — low in some states, exceeding 10–15% in others like New Jersey or D.C.

Other research finds mixed or smaller net effects in some cases due to the “merit order” effect (renewables’ near-zero marginal cost can suppress wholesale prices), but retail prices often rise due to fixed costs, transmission, and policy design.

A major hidden cost comes from intermittency management. Wind and solar require fast-ramping backup, primarily from natural gas turbines. Frequent starts, stops, and cycling cause thermal stress, increased maintenance, more frequent repairs, and shorter equipment life.NREL’s Western Wind and Solar Integration Study (WWSIS) and related Power Plant Cycling Costs reports quantify this:

Cycling increases operations and maintenance (O&M) costs for thermal plants, with gas combustion turbines particularly affected.
In higher renewable penetration scenarios, additional cycling and ramping costs across the Western Interconnection reached tens to hundreds of millions of dollars annually.
One analysis estimated potential added costs of $35–157 million per year from wear-and-tear in certain high-renewable cases.

Utilities across the country have reported millions in extra expenditures to keep gas fleets reliable while accommodating variable renewables. These costs — plus new transmission, storage needs, and overbuild requirements — contribute to higher system expenses borne by consumers, even as shale gas kept the underlying fuel price low.

The Bottom Line: Markets and Innovation Delivered; Mandates Add Costs

Shale gas stands as one of the greatest energy successes of the 21st century. It slashed prices, boosted manufacturing competitiveness, reduced emissions by displacing coal, and provided the flexible backbone for growing renewables. The ~$200 billion annual consumer savings (per the Haas analysis) represent real money in household budgets, industrial competitiveness, and economic growth.

Yet in states pursuing aggressive renewable mandates alongside heavy regulatory burdens, electricity prices have risen faster — compounded by intermittency-driven cycling costs on gas infrastructure. The data show clear patterns: abundant, affordable domestic natural gas correlates with better price outcomes; top-down renewable quotas often correlate with higher costs and reliability challenges.

Energy abundance through innovation — not mandates that ignore physics and economics — remains the proven path to affordable, reliable power. Shale gas has proved it since 2007. Policymakers ignoring these lessons risk repeating expensive mistakes.

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