Where power markets go from here.
Power market restructuring has been underway for nearly 50 years, and it remains unfinished. The organized wholesale markets that operate in two-thirds of the country have delivered real benefits: lower costs in many regions, accelerated deployment of renewables, sophisticated financial tools for managing price risk, and a framework for integrating new technologies that the regulated monopoly model could never have accommodated.
But serious challenges remain.
Electricity markets, as currently designed, do not price carbon emissions. A generator using natural gas and one using coal compete on equal footing in the energy market — their offers differ only by fuel cost and heat rate. Coal, with higher carbon emissions per megawatt-hour, receives no market penalty for its environmental impact.
The standard economic solution is a carbon price — a tax or cap-and-trade system that makes generators internalize the social cost of their emissions. Several northeastern states operate the Regional Greenhouse Gas Initiative (RGGI), a cap-and-trade program for power sector emissions. California has a broader economy-wide cap-and-trade program. But no federal carbon price exists, and the political barriers have proven formidable.
Without a carbon price, markets rely on renewable mandates, subsidies, and carbon standards — blunter instruments that achieve similar goals less efficiently.
The energy transition — from fossil fuels to renewable electricity — is creating market design challenges that existing market structures were not built to handle:
Resource adequacy with high renewables: Traditional capacity markets were designed around dispatchable resources. How do you value a solar plant that can only generate during daylight hours? How much capacity credit should a 4-hour battery receive? Market rules are struggling to keep pace with technological change.
Transmission for the energy transition: The best wind resources are in the middle of the country; the best solar resources are in the Southwest. Getting that power to coastal demand centers requires new long-distance transmission infrastructure — but transmission planning and permitting processes have changed little since the 1990s. The result is a massive backlog of renewable projects waiting in interconnection queues.
Electrification: As transportation, heating, and industry electrify — replacing gasoline, natural gas, and coal with electricity — electricity demand, which has been roughly flat for two decades, may grow substantially. New patterns of demand (EV charging concentrated at night; heat pump load concentrated in cold mornings) will require both new supply and more sophisticated demand response.
The history of power markets is a story of partial solutions, unintended consequences, and continuous adaptation. The vertically integrated monopoly solved the problem of rural electrification but created gold-plating and regulatory capture. PURPA cracked open independent generation but produced perverse avoided-cost contracts. Order 888 opened transmission access but left manipulation opportunities. The California crisis exposed fragile market design. The rise of renewables disrupted the merit order. Storage is redrawing the boundary between supply and demand.
Each problem has generated new tools: LMP to manage congestion, two-settlement markets to manage price volatility, capacity markets to manage resource adequacy, RPS to manage carbon, demand response to manage peaks.
The grid of 2050 — fully electrified transportation and heating, dominated by zero-marginal-cost renewables, firmed by massive storage, managed by artificial intelligence — will require market structures we have not yet imagined. The engineers and economists who design those markets will face the same fundamental challenge as their predecessors: how do you align private incentives with the public interest in a system where physical laws leave no room for error?
The answer, as always, will be imperfect. But the history of American power markets suggests that markets, properly designed and vigorously regulated, are a powerful tool — imperfect, contested, but capable of delivering results that administrative planning never could.
New York, September 25, 2008 — RGGI holds America's first carbon auction. When the Regional Greenhouse Gas Initiative conducted its inaugural allowance auction, it marked the first time the United States had put a market price on power-sector carbon emissions. Ten northeastern states had agreed to cap their electricity generators' CO2 output and require each ton of emissions to be backed by a purchased allowance. The first auction cleared 12.5 million allowances at $3.07 per ton — below the level economists said would drive significant fuel switching, but enough to establish a functioning market and direct tens of millions in auction revenue to state clean energy programs. RGGI demonstrated that a regional cap-and-trade mechanism could operate across state lines without federal legislation. When California launched its own cap-and-trade program in 2013, it built on RGGI's operational experience. Both programs eventually raised carbon prices to levels where emissions costs began visibly influencing generator dispatch and investment decisions.
RGGI — CO2 Auction Results California Air Resources Board — Cap-and-Trade Program Overview