The Price-Setter: Why Blocking Clean Energy Raises Everyone’s Bill

The staff economist at the state Public Service Commission had been staring at the same spreadsheet for forty minutes. It was a Thursday in late February, the heat in the building was set too low for the season, and her office still smelled faintly of the coffee she had spilled on Monday. The spreadsheet was a rate case filing from the largest investor-owned utility in the state — a request to pass through $1.4 billion in wholesale capacity charges as a line item on residential bills, beginning June 1. The filing was, by the standards of rate cases, unremarkable. The numbers added up. The methodology was orthodox. The utility was not making anything up.

What bothered her was not the filing. It was the cover memo from the utility’s regulatory affairs office, which explained the wholesale price increase in three short paragraphs and used the phrase “supply constraints” four times. The memo did not mention, because it did not have to, that the supply that was constrained was the supply that had not been built — the 12 gigawatts of solar, wind, and storage that had been sitting in the regional grid operator’s interconnection queue for six years, waiting for studies that kept getting delayed.

She picked up a red pen, hovered over the cover memo, and put the pen down. The numbers were the numbers. The math was the math. She would approve the rate increase, because the law required her to approve cost recovery for prudently incurred wholesale charges, and the wholesale charges were prudent. Whose fault those wholesale charges were was a different question, which her job did not give her standing to answer.

The price of electricity is now rising at the fastest rate in more than a decade, and the largest driver is not what most ratepayers think it is. The framework set out in The Food-Energy-Water-Compute Nexus named the systems at play; The Three-Year Window named the choice being made on AI infrastructure power supply. This article names the consequence. Blocking and delaying clean energy supply does not just slow the energy transition — it raises every American’s electricity bill, transfers tens of billions of dollars per year from ratepayers to fossil incumbents, and exports the rest of the cost to the climate, the watershed, and the air.

How Electricity Markets Actually Set Prices

Almost every wholesale electricity market in the United States — PJM, ERCOT, MISO, NYISO, ISO-NE, CAISO, SPP — runs on a uniform-price clearing auction. Every generator bids into the market at its marginal cost of producing electricity. The grid operator stacks the bids from cheapest to most expensive and dispatches in order, cheapest first, until demand is met. The price paid to every dispatched generator, including the cheap ones at the bottom of the stack, is the price of the last and most expensive unit needed to clear demand. That last unit is called the marginal unit, and its price is the clearing price for the entire market in that interval.

The merit order, cheapest to most expensive, looks roughly like this: nuclear and hydro at the bottom (effectively zero marginal cost), then wind and solar (zero fuel cost), then combined-cycle gas (moderate fuel cost), then simple-cycle gas peakers (high fuel cost, fast-starting), then oil and diesel at the top. When demand is low, a combined-cycle gas plant typically sets the clearing price. When demand is high — hot summer afternoons, cold winter mornings, or any hour the AI data centers are training large models — peakers run, and peakers set the price for everyone on the grid in those hours.

This mechanism is the design, not a flaw. It exists to incentivize generators to bid their true marginal cost. The consequence the design produces is straightforward and unforgiving. Adding cheap renewables to the supply stack pushes the marginal unit down — fewer hours of peakers setting the price, more hours of cheaper units clearing the market. Blocking those renewables holds the marginal unit at gas, often expensive peaking gas, and every consumer pays the difference.

What the PJM Numbers Are Telling Us

PJM serves 67 million people across thirteen states and DC. Its capacity market — separate from the wholesale energy market and used to ensure adequate generation is available for peak demand — makes the supply gap unusually visible. The auction clearing prices over four years:

• 2024/2025 delivery year: $28.92 per megawatt-day
• 2025/2026: $269.92 per megawatt-day, an 833 percent increase
• 2026/2027: $329.17 per megawatt-day
• 2027/2028: $333.44 per megawatt-day, the FERC-approved price cap

The Policy Choices Embedded in Those Numbers

A meaningful share of those higher prices is not caused by demand growth. It is caused by the supply that was not built to meet the demand.

In January 2025, the federal government halted all offshore wind lease sales, approvals, and permits, an order a federal court declared unconstitutional in December 2025. The administration then pivoted from blocking to buyouts. The pattern now includes three different kinds of capital pivot. TotalEnergies agreed to exit U.S. offshore wind and invest $928 million in LNG, Gulf of Mexico oil, and shale gas projects before its offshore wind leases were terminated and reimbursed. Invenergy accepted a $765 million buyout to terminate four offshore wind leases, with federal statements saying the funds would support natural-gas plants in Indiana, Wisconsin, Iowa, Kansas, and Missouri, plus geothermal projects in the West. Duke Energy then brought the same pattern to a major U.S. utility: it agreed to terminate its Carolina Long Bay offshore wind lease, with nearly $129 million redirected into additional Carolinas power capacity that may include grid modernization, nuclear, and natural gas.

The legal status of this model is contested. Seven state attorneys general have sued over the TotalEnergies agreement, alleging violations of the Outer Continental Shelf Lands Act, the Judgment Fund Act, and federal administrative procedures. The administration and Interior Department have defended the agreements as lawful energy-security and affordability measures. For ratepayers, however, the market effect does not wait for the lawsuit to finish. When low-marginal-cost clean supply is removed, delayed, or made less financeable, higher-cost fossil units remain closer to the margin for more hours.

That is the ratepayer premium. It is not a separate tax line. It shows up as capacity payments, congestion charges, wholesale energy prices, fuel pass-throughs, emergency reliability actions, and eventually utility rate cases. The policy signal is no longer only anti-offshore-wind. It is a supply-stack intervention — removing potential low-marginal-cost generation before it can push expensive fossil units out of the price-setting position.

Duke Energy’s North Carolina rate case shows the ratepayer premium in miniature. The utility filed for an 18 percent rate increase tied in part to its gas and grid buildout; following pushback from the state Attorney General’s office and public advocates, Duke agreed to lower the increase to 11.6 percent. Even at the reduced rate, ratepayers are still absorbing the cost of a generation plan leaning further into gas and existing coal: the U.S. Department of Energy has separately directed close to $96 million in Defense Production Act grants toward refurbishing Duke coal units at Belews Creek and other North Carolina and Kentucky plants, funding that extends older, higher-emission generation while shielding shareholders from the capital cost. Consumer advocates note that North Carolina has not adopted large-load tariffs that would require data centers to pay for their own grid upgrades, leaving those costs to be spread across the general ratepayer base.

Beyond the buyouts, the more pervasive damage is delay. The American Clean Power Association reports 59 gigawatts of U.S. clean energy projects facing an average 19-month delay due to permitting, interconnection, and federal regulatory friction. Project analyst Michael Thomas tracked 266 gigawatts of planned electricity generation projects that fell through in 2025 alone. The Inflation Reduction Act’s clean energy tax credits begin sunsetting on July 4, 2026 under legislation passed in mid-2025, ending the most economically powerful incentive structure for new utility-scale solar, wind, and storage just as AI-driven demand peaks.

These are not climate decisions in any meaningful sense. They are decisions about who pays for electricity, and who gets paid for selling it. Every gigawatt of clean energy that does not get built is a gigawatt of expensive gas that keeps setting prices in the marginal hour, and every fossil incumbent earns inframarginal rent for as long as the marginal unit stays where it is. The $2 billion in offshore wind buyouts is a small line item to protect a much larger stream of inframarginal revenue.

The Ratepayer Premium: What This Costs the Average Household

Conservative estimates, built from PJM-style capacity market dynamics and the merit-order effect on wholesale energy prices, put the consumer cost of delayed and blocked clean energy supply at $100 to $200 billion cumulative over five years, or $300 to $500 billion over ten years, with the wider range reflecting whether the policy environment partially reverses. In percentage terms, the average U.S. electricity bill will be 6 to 10 percent higher by 2028 to 2030 than it would have been under a supportive clean energy policy. That works out to roughly $30 to $60 per month per household nationwide on average, and $70 to $100 per month in the most exposed regions of PJM. These estimates should be read as scenario-level planning numbers, not a utility-by-utility forecast, because the final bill impact depends on how each state allocates capacity costs, transmission upgrades, fuel costs, and large-load tariffs.

The distributional pattern matters. Electricity is a higher share of lower-income household budgets, so the bill increase falls disproportionately on those with the least margin to absorb it. Households with rooftop solar and battery storage can partially exit wholesale pricing dynamics — those without cannot. Behind-the-meter data center campuses like Stratos exit the wholesale market entirely, leaving the costs of an under-supplied grid to be absorbed by the residential and small-commercial ratepayers who cannot follow them.

And That’s Only the Portion That Arrives in the Mail

The $100 to $200 billion that consumers will pay in higher bills is only the portion of the cost that arrives in the mail. The larger and less visible cost is the environmental damage of running a power system on gas turbines that should have been running on sun and wind.

At a conservative social cost of carbon of $50 per metric ton — well below the EPA’s own current estimate and below the figure used by the IMF and most peer governments — the additional 150 to 300 million tons of CO2 emitted each year by 2030 from delayed renewables and new behind-the-meter gas represents $8 to $15 billion per year in climate damages, borne globally and disproportionately by people far from the data centers. Add upstream methane leakage from expanded gas production, valued at another $2 to $3 billion per year. Add the water cost: the new fossil-fired data center fleet will consume an estimated 50 to 150 billion gallons annually by 2030, much of it in already stressed basins where each acre-foot withdrawn reduces agricultural output, ecological resilience, or municipal margin — call it $3 to $8 billion per year when valued at watershed opportunity cost. Add the local air quality damages: NOx, particulates, and ozone precursors from gas turbines impose well-documented respiratory and cardiovascular health costs on nearby communities, conservatively $2 to $5 billion per year.

The unbilled total runs to roughly $15 to $30 billion per year by 2030, or $50 to $100 billion cumulative over five years. Combined with higher utility bills, the full cost of the current policy choice approaches $200 to $300 billion over the next five years — money the country is spending to not build cleaner, cheaper power that exists today.

The figures get larger at the EPA’s own current social cost of carbon of approximately $190 per metric ton, where climate damages alone reach $30 to $60 billion per year and may exceed the consumer bill impact itself.

What Could Be Done

The reforms that would close the gap are not technological. They are procedural and political. Finish the interconnection queue reforms FERC began under Order 2023. Streamline siting and easement for clean firm projects with the same urgency that gas turbines currently receive. Restore predictable clean energy tax treatment so project finance can underwrite long-duration deployments. Stop paying power companies hundreds of millions of dollars to not build low-marginal-cost clean supply, unless the replacement capacity is demonstrably cleaner, cheaper, faster, and less water-intensive. Require behind-the-meter generation above a meaningful threshold to disclose its full lifecycle costs so the public conversation can work from facts.

These reforms would not eliminate AI data center demand growth. They would change which generation responds to it. That single change — clean responding instead of gas — would compound across capacity prices, wholesale energy prices, emissions, water, and health, and would return the savings to the same residential and small-commercial ratepayers currently absorbing the cost of the choice not being made.

Conclusion: Who Pays, and Why

The Perpetual Sustainability™ framework asks how systems regenerate. The current U.S. electricity system is being designed not to. Demand is rising sharply because of AI. Clean supply that would naturally respond to that demand is being delayed, denied, or paid to walk away. Fossil supply is filling the gap because nothing else is allowed to fill it fast enough, and is being paid more in the process. The bills are being mailed to households that have no behind-the-meter alternative and no political access to the rooms where the choices are made.

This is not a hidden cost. It is a transferred cost. Every dollar that does not appear on a hyperscaler’s behind-the-meter gas balance sheet appears somewhere — on a household electricity bill, on a hospital admission for an asthma flare-up in a county hosting a gas peaker, on a climate damage payment a future government will be required to make, on a watershed that loses its margin one acre-foot at a time. The accounting boundary that the Food-Energy-Water-Compute Nexus draws around the system exists precisely so these costs are visible and addressable. Drawing the boundary smaller — counting only what shows up on the utility’s spreadsheet, the way the regulatory affairs office did in that February cover memo — produces the policy environment we currently have.

The economics of clean energy already work. The technology already works. The window described in The Three-Year Window is still open. What remains is the political and regulatory will to let the cheaper, cleaner, faster-deploying option win the auction the market is already trying to give it.

The staff economist went home at 6:14 that evening. She drove past a billboard for a new data center being built thirty miles east of the city — the third one she had seen go up that year. She thought about her own February utility bill, sitting on the kitchen counter, which was 14 percent higher than the same month a year ago. She thought about her sister in West Virginia, whose bill was up 22 percent. She thought about the four-paragraph rate case memo she had approved that afternoon, and the way it had used the phrase “supply constraints” without ever naming the supply that had been constrained or who had constrained it. She thought about what her job allowed her to do and what it did not.

At a stoplight she pulled out her phone and started a draft of a letter to the chair of her commission, suggesting that the rate case approval process needed to include, somewhere in the record, a finding of fact about whether the supply constraints driving the wholesale charges were the kind that came from physics or the kind that came from policy. She did not know whether the letter would change anything. She knew it would at least put the question on the record. The light turned green. She kept driving. The letter could wait until morning.

Dynamic Links

Internal — PerpetualInnovation.org

• The Food-Energy-Water-Compute Nexus: Adding the Fourth Letter — the framework underpinning this analysis
• The Three-Year Window: Powering AI Without Locking In Gas — the AI infrastructure fuel choice driving the supply gap
• Earth Day 2026: Fossil Fuels, Hormuz & the One-Way Trip — the broader argument on stranded fossil assets
• Pi-Sustain — Sustainability Strategy Hub
• Pi-Econ — Macroeconomic Analysis Hub — the economic-policy companion category

External — High-Authority Sources

• PJM Interconnection — Capacity Auction Results — official auction clearing prices
• IEEFA — Data Center Growth and PJM Capacity Prices — independent analysis of the price spike
• American Clean Power Association — Quarterly Market Report — current data on stalled clean energy capacity
• NRDC — PJM Capacity Cost Projections — cumulative cost analysis through 2033
• Lazard — Levelized Cost of Energy+ (2024) — unsubsidized cost comparison across generation types
• EPA — Social Cost of Greenhouse Gases — federal estimates used in regulatory analysis
• Reuters — Duke Energy to terminate North Carolina offshore wind lease (2026) — current example of a U.S. utility clean-energy lease buyout
• Reuters — TotalEnergies abandons U.S. offshore wind and shifts investment to oil and gas (2026) — example of clean-energy capital redirected toward fossil-fuel projects
• Reuters — Invenergy offshore-wind lease termination and reinvestment agreement (2026) — example of buyout funds directed to natural-gas and geothermal projects
• New York Attorney General — lawsuit challenging TotalEnergies offshore-wind lease cancellation (2026) — state legal challenge to the buyout mechanism
• Reuters — PJM moves toward managing data center demand (2026) — current grid-operator response to data-center-driven load pressure
• Reuters — PJM price spikes during July 2026 heat wave — current example of constrained supply and peak-price stress
• Sierra Club — Duke Energy reduces proposed rate increase after public pressure (2026) — the North Carolina rate case behind the ratepayer-premium case study
• PR Newswire — DOE announces Defense Production Act grants for Duke Energy coal plants (2026) — federal coal-fleet funding cited alongside the rate case

Suggested GenAI Prompts

1. I like using stories to convey complex or challenging topics. Tell a story that conveys both the fact and the counter-factual about this topic: how the merit-order pricing mechanism on a regional electricity grid responds to adding versus subtracting renewable energy capacity. Make sure the narrative is grounded in verifiable data and be prepared to cite reliable sources for every factual claim embedded in the story.
2. What are the top 4 to 6 questions a [household ratepayer / small business / state legislator] should ask their utility commission about rising electricity bills? [Optional: I live in (state/region), and my bill has risen approximately X% in the past two years.]
3. Walk me through, in plain language, how the wholesale electricity capacity market works in PJM, and how data center demand and delayed clean energy supply combine to drive the auction clearing price. What policy levers exist at the state and federal level to change that outcome?
4. What can a small business or community organization do to make rising electricity costs and their causes visible in local and state policy conversations? [Optional: We are located in (state/region) and our biggest electricity-related concern is (cost / reliability / emissions).]
5. Build a household-level estimate of the additional electricity costs an average family in [my state or PJM zone] is likely to pay over the next five years as a result of delayed clean energy supply versus a baseline policy environment. Break down the bill increase by capacity market effect, wholesale energy effect, and externality effects not directly billed.

AI Disclosure and Attribution

This article was created with assistance from Claude Opus 4.7 (2026, May), Gemini 3.5 (2026, May), and ChatGPT 5.5 (2026, May), with additional research and drafting support from Gemini 3.5 Deep Research (2026, Jul), ChatGPT 5 (2026, Jul), and Claude Sonnet 5 (2026, Jul), as part of the Pi-rdAI Rapid Strategic Planning ecosystem. Feature image parameters by ChatGPT 5 (2026, May) based on the research and article; final image generated using ChatGPT (2026, Jul) with significant prompting and polishing. Content development and review by Dr. Elmer B. Hall — Strategic Business Planning Company (SBPlan.com) and PerpetualInnovation.org.

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