What Is the Reason for the 1000% Increase in Power costs to Consumers?

American electricity customers are facing sticker shock that goes far beyond ordinary inflation. In the nation’s largest grid region, PJM Interconnection—serving 65 million people across 13 states and Washington, D.C.—capacity prices have risen from roughly $29 per MW-day in the 2024/2025 auction to $270, then $329–$333 per MW-day in subsequent auctions. That is an increase of nearly 1,000 percent. Those wholesale capacity costs flow directly onto retail bills.

The 1,000 percent figure is not a national average retail rate (those have risen more like 30–63 percent since 2019–2010 depending on the dataset and starting point). It is a market signal of tightness that reveals deeper structural problems: how the grid is planned, how transmission is paid for, and how policy has replaced dispatchable power with distant, intermittent resources whose full system costs are socialized onto every ratepayer.

How Distant Wind, Solar, and Storage Get Charged to Consumers

Regional Transmission Organizations (RTOs) such as PJM coordinate high-voltage transmission planning and wholesale markets for about two-thirds of U.S. demand. Generation developers pay the direct costs of interconnecting their project to the existing grid. Broader network upgrades and new long-distance lines, however, are typically socialized across all transmission customers and ultimately retail consumers.

This matters because the best wind and solar resources are often hundreds of miles from load centers. New lines are built to move that power, plus the extra capacity and flexibility needed to manage intermittency. Consumers—not the project owners—absorb most of those costs. The National Center for Energy Analytics (NCEA) notes that this practice subsidizes poorly sited intermittent generation instead of encouraging resources closer to demand or that can be dispatched on command.

Texas offers a concrete illustration. In ERCOT, transmission costs rose from $1.5 billion in 2010 to more than $5 billion in 2024 and are projected to exceed $12 billion annually by 2033. After inflation and demand growth, the average ratepayer paid 57 percent more in transmission charges in 2024 than in 2010. Texas customers have paid nearly $15 billion since 2010, or about $1 billion per year, specifically to support transmission for wind and solar. A proposed 765-kV plan carries an estimated $33 billion capital cost and nearly $100 billion lifetime cost, largely to move renewable output.

Alberta’s contrasting model requires generators to make up-front, non-refundable payments based on location and attributes: distant or intermittent projects pay more. That aligns costs with causation rather than spreading them across every household and business.

Other Key Drivers of Higher Grid Costs

Several forces are colliding:

1. Loss of dispatchable capacity. Between 2010 and 2024, total U.S. generating capacity grew, but dispatchable (coal, gas, nuclear) capacity fell by about 80 GW while wind and solar grew nearly sevenfold. Subsidies, including the federal production tax credit, allow intermittent resources to bid low or negative, squeezing conventional plants that provide reliability attributes such as inertia and voltage support. NCEA calls this “Gresham’s Law of Green Energy.” State zero-emissions mandates and environmental rules have accelerated retirements.
2. Surging demand. Data centers and AI loads are the most visible new driver. PJM’s independent market monitor has identified data-center growth as a primary reason for tight supply-demand balance and high capacity prices. Wholesale prices near major data-center clusters have risen as much as 267 percent in five years in some analyses. Electrification of vehicles and buildings adds further pressure.
3. Aging infrastructure and extreme weather. Much of the grid dates to the 1960s–1970s. Replacement, wildfire hardening (especially in California), storm recovery, and resilience upgrades are expensive and recovered through rates.
   Market design and queues. Capacity markets reward availability, so thinning firm supply produces price spikes. Interconnection queues remain backlogged. Price caps in energy markets create a “missing money” problem for peaking plants.

No single factor explains every state’s increase—California’s wildfire liabilities are unique, natural-gas price volatility affects others—but the combination of policy-driven retirements, socialized transmission for remote renewables, and unexpected load growth is producing the sharpest rises in organized markets like PJM.

Will White House Executive Orders Help Anytime Soon?

The Trump administration has issued multiple orders aimed at reliability and supply. An April 2025 order directed the Department of Energy to streamline Federal Power Act Section 202(c) emergency authority so plants needed for reliability can be kept online. DOE has used that authority repeatedly, issuing dozens of 90-day (and renewed) orders to delay retirements of coal and other units in MISO, PJM, the West, and Florida. A Defense Production Act determination targets transformers, conductors, and other grid equipment. An August 2026 order declared a national emergency over foreign-sourced bulk-power equipment and software. “Speed to Power” initiatives seek faster transmission and generation.

These steps provide near-term reliability insurance by keeping existing firm plants available and signaling that premature retirements will be challenged. They do not instantly add new generation or transmission. Permitting, supply chains, and construction still take years. Capacity prices already cleared in prior auctions will appear on bills through 2028–2029. New large-scale lines and plants will not arrive “any time soon” in sufficient volume to reverse the current tightness. The orders buy time and change incentives; they do not repeal physics or instantly rebuild the system.’

Should Consumers Prepare for Rolling Blackouts?

Several major utilities and grid operators have issued explicit warnings.

Exelon CEO Calvin Butler, whose company serves more than 10 million customers, told the Financial Times in June 2026 that Americans could “absolutely” lose power as soon as 2027 because of plant shortages in the Northeast and Midwest. He said Exelon came “very close” last winter to curtailing service for about 400,000 customers on the coldest days: “And it’s only getting worse.” PJM has recorded multi-gigawatt shortfalls against its reliability target and is developing a reliability backstop plus potential temporary curtailment of large data-center loads during stress.

NERC’s long-term assessments flag elevated risk of insufficient reserves or unserved energy in PJM, MISO, ERCOT, and parts of the Pacific Northwest within five years, driven by data-center load growth and coal retirements. The Southwest Power Pool issued energy emergency alerts during 2026 heat waves and warned of possible rolling blackouts when plants tripped offline. A utility-sponsored Pacific Northwest study identified a growing reliability gap starting in 2026, especially in dry hydro years plus cold snaps. An FPL consultant previously warned of likely rolling blackouts in Florida without major rate-supported investment.

Nationwide rolling blackouts are not guaranteed, but localized or regional controlled outages during extreme weather or coincident high demand are a realistic risk in the tightest regions. Consumers in PJM, MISO, parts of Texas, the Northwest, and Florida should treat the warnings seriously: know their utility’s alert systems, consider backup generation or storage where feasible, reduce peak usage during emergencies, and follow official conservation requests. Households and businesses that cannot tolerate even short interruptions should plan accordingly.

The 1,000 percent jump in capacity price is a symptom. Distant intermittent resources whose transmission and balancing costs are socialized, combined with policy-driven loss of firm generation and explosive new demand, have produced a tighter, more expensive, and less resilient grid. Executive actions can slow further deterioration and keep existing plants running, but they cannot instantly deliver the new dispatchable capacity and properly allocated infrastructure the system now needs. Ratepayers are already paying the bill.

The bottom line: get prepared and get some form of backup that can help you through any storm or disaster. Those who are prepared for a disaster walk through the problem rather than panic or have a horrible outcome. It only takes one freezer full of food to waste to pay for a good solution. We will be interviewing Jackery’s CEO again next week with Doomber to cover this. Also interviewing Meredith Angwin, author of “Shorting the Grid,” on her most recent experiences, and we will release that soon