"Deregulated states are dirtier. Regulated states are greener." Not really.
The intuitive story is that regulated states (where the PUC can directly mandate clean generation) should be greener than deregulated states (where the market decides). The intuitive story is wrong. Texas, the most deregulated electricity market in the US, leads the country in both installed wind (~40 GW) and utility-scale battery storage (~10 GW). Washington and Oregon, both regulated, have very clean grids, but mostly because of legacy hydro built in the 1930s, not modern policy. West Virginia, regulated, remains coal-heavy. California, technically still has retail-choice statutes on the books but no functional residential market, is greener through state climate policy, not through wholesale design.
The truth is more structural: market design shapes clean-energy investment signals far more than the deregulated label does. ERCOT's energy-only design pays generators for being available in scarcity events. That suits batteries (which charge cheap and discharge expensive) and wind (which earns most when wind blows hardest, often during scarcity). PJM's capacity-auction design pays generators to promise availability three years out. That suits gas turbines, which discourages variable renewables.
Climate policy belongs on a different line of the bill, in any case. State Renewable Portfolio Standards (RPS), federal tax credits (ITC, PTC), the EPA Power Plant GHG Rule, IRA grants and the regulated delivery utility's Integrated Resource Plan all act on different layers from the wholesale energy auction. They reinforce or undermine the market signal; they do not replace it.
Read this guide as a state-by-state empirical answer to the question "did deregulation help or hurt the energy transition", with the data, not the slogans.
Three market-design mechanisms decide which clean tech actually gets built.
Wholesale-market revenue is what makes the financing model work for a new wind, solar or battery project. Three design choices in particular drive the outcome.
Energy-only vs capacity
ERCOT is energy-only: no capacity payment, scarcity prices up to $5,000/MWh under RTC+B. This rewards fast-cycling assets (batteries, wind) that can respond to scarcity. PJM, ISO-NE, NYISO pay capacity for being available 3 years out, which favors firm always-on resources (gas, nuclear) and dampens scarcity revenue.
Capacity accreditation
How much capacity payment does an intermittent resource earn per MW of nameplate? PJM's stricter Effective Load Carrying Capability rules (post-2024) credit a solar plant at ~15-20% of nameplate, a battery at ~50-60% depending on duration. That penalizes solar more than gas. CAISO uses similar but slightly more generous methods.
Interconnection queue
All ISOs have multi-year backlogs of generators waiting for transmission studies before they can connect. PJM's 2023 queue reform helped; CAISO and MISO queues remain bottlenecks. ERCOT's simpler queue process is part of why Texas can install 5-10 GW of new renewable + battery capacity per year. Source: ERCOT generator resources.
The detail that surprises most readers. Climate-policy riders (RPS targets, IRA grants, the EPA GHG rule) live on the regulated delivery line of your bill or on the federal balance sheet, not inside the wholesale auction. The wholesale auction's only job is to clear supply against demand at the lowest cost. Whether that supply ends up being green or fossil is a function of which technology can profitably bid into the auction's specific design. ERCOT's scarcity-revenue design happens to be very kind to batteries and wind. PJM's capacity-payment design happens to be kinder to gas. Neither is a climate policy on its own.
Installed clean capacity by state and wholesale market.
Verified against EIA Form 860 (most recent vintage), NREL ATB and ISO/RTO data, May 2026. Numbers rounded to the nearest GW.
| State | Market | Wind | Solar | Battery | Why |
|---|---|---|---|---|---|
| Texas | ERCOT (deregulated, energy-only) | ~40 GW | ~25 GW | ~10 GW | Energy-only market + CREZ transmission + ITC/PTC |
| California | CAISO (no real residential choice) | ~6 GW | ~45 GW | ~13 GW | RPS + IRA + duck curve drove battery boom |
| Iowa | MISO (regulated) | ~13 GW | ~1 GW | <1 GW | Wind-heavy MidAmerican Energy IRP + federal PTC |
| Oklahoma | SPP (regulated) | ~12 GW | ~1 GW | <1 GW | Wind resource + federal PTC; minimal state policy |
| New York | NYISO (deregulated) | ~2 GW | ~6 GW | ~1 GW | CLCPA targets + offshore wind in development |
| West Virginia | PJM (regulated) | ~1 GW | <1 GW | ~0 GW | Coal-heavy IRPs, weak state policy |
| Washington | No RTO (regulated) | ~3 GW | ~1 GW | <1 GW | Already 70%+ hydro; small need for new clean |
! Wind, solar, battery are not interchangeable
A megawatt of wind, solar and battery do very different things on the grid. Wind is variable, peaks at night and in winter, and pairs naturally with summer-peak gas. Solar peaks at midday and creates the "duck curve" that requires evening ramp. A battery shifts solar from midday to evening or charges off cheap renewables and discharges during scarcity. So a state with high installed solar AND high battery is far cleaner in practice than a state with the same nameplate solar alone. ERCOT and CAISO both fit this pattern. PJM and the Southeast do not yet.
What deregulation actually changed on the environment scoreboard.
Four documented effects, two positive and two negative. None can be evaluated honestly without naming both sides.
+ Faster coal retirement
In competitive wholesale markets, coal plants face the same merit-order test as everyone else and lose to cheaper shale gas through the 2010s. PJM, MISO, ERCOT have retired ~140 GW of coal since 2010. Regulated states often kept coal running through the same period because the IRP process valued fuel diversity over short-run economics.
+ Renewable buildout where market design suits
ERCOT and CAISO have absorbed wind, solar and battery additions at a pace no regulated grid has matched. Federal PTC/ITC + IRA created the financing; open-access transmission + scarcity-priced energy markets created the revenue stack. Texas, the deregulated capital of US energy, is also the wind and battery capital.
- Capacity-market accreditation penalty
PJM's stricter Effective Load Carrying Capability rules (post-2024) credit solar at ~15-20% of nameplate and wind at ~15-25%, which means a renewable project earns far less capacity revenue per MW than a gas turbine. The July 2024 + July 2025 PJM auctions cleared at record-high capacity prices partly because of this asymmetry. Net effect: capacity-market RTOs have built less variable renewable per dollar of policy support than energy-only markets.
- Gas dependence and infrastructure lock-in
Coal retirements in deregulated markets were replaced primarily with combined-cycle gas, not directly with renewables. The result is that PJM, MISO and ERCOT now have higher gas dependence than they did pre-deregulation. Methane leakage upstream and the long asset life of new gas plants mean the climate benefit of switching from coal to gas is real but smaller than the headline numbers suggest. Source: EPA eGRID.
Net assessment: deregulation accelerated some clean-energy outcomes (coal retirement, wind, batteries in ERCOT/CAISO) and slowed others (variable renewables in PJM capacity-auction zones, gas lock-in). Whether the net effect was positive depends on the state and the time window. There is no honest national-aggregate answer.
The two federal policy layers that did the heavy lifting.
Whatever the wholesale market design contributed, two federal levers did most of the actual clean-energy buildout.
Residential Clean Energy Credit
IRS Residential Clean Energy Credit (formerly ITC): 30% federal tax credit for residential solar, batteries, geothermal through 2032 under IRA. IRS.
IRA climate funding (10 yr)
Inflation Reduction Act 2022: ~$369B in clean-energy credits, grants, loan guarantees over 10 years. Largest US climate investment ever.
EPA coal CO2 capture, by 2039
May 2024 EPA Power Plant GHG Rule. Status uncertain under second Trump admin but in force May 2026.
FERC Order 2222 rollout
DER aggregation in wholesale markets. ISO-NE 1 Nov 2026, PJM 2028, MISO 2029, SPP 2030.
How federal policy interacts with deregulated markets
- A Federal tax credits financed the project; the market provided the revenue. The IRA's extension of ITC and PTC + storage eligibility unlocked the financing for nearly every utility-scale wind, solar and battery project in the country. But once the project is built, it earns wholesale revenue in whatever market it sits in. ERCOT-grid battery projects can earn 2-3x more per MW than PJM-grid projects because of energy-only design.
- B The EPA GHG Rule prices the externality. By requiring 90% CO2 capture on coal and new baseload gas by 2039, the rule pulls future coal economics under water and makes new gas baseload riskier. This shifts the IRP calculus in regulated states (most of the South, Mountain West) and accelerates the same coal retirements that deregulated markets already produced through merit-order pressure.
- C FERC Order 2222 will turn distributed clean tech into a wholesale revenue stream. Once your rooftop solar, home battery or EV charger can be aggregated and bid into wholesale energy, capacity and ancillary-service markets, the asset earns its own revenue independent of net-metering credits. The 2026-2030 rollout reshapes the residential clean-energy investment case more than any state policy change.
Why ERCOT became the US clean-energy capital.
Four structural reasons the most deregulated US grid leads the country in both renewable and storage installs in 2026.
Energy-only design rewards scarcity-response
ERCOT does not pay capacity. Generators recover fixed costs through scarcity prices in the spot market, capped at $5,000/MWh day-ahead and $2,000/MWh real-time under the December 2025 RTC+B redesign. A battery that charges at $25/MWh and discharges at $2,000/MWh earns the spread. A wind farm that generates during a scarcity event captures it too. Gas turbines earn the same way but with much higher fuel cost.
CREZ moved wind to load
The 2008-2014 Competitive Renewable Energy Zone transmission build moved 18,500 MW of capacity from west-Texas wind country to Dallas/Houston load. Open-access (Order 888 equivalent at state level) made it possible. No other US grid has built transmission for renewables at this scale. PJM's queue reform is slowly catching up but the gap is years wide.
Simpler interconnection queue, faster build
ERCOT's connect-and-manage model lets developers build first and curtail later if congestion arises. CAISO and PJM require full network impact studies before construction. The result: Texas adds 5-10 GW of new renewable + battery capacity per year, California 4-6 GW, PJM 2-3 GW.
Property tax abatements close the financing
Texas's former Chapter 313 program (and its successor Chapter 403) gave rural counties incentive to host wind, solar and battery projects. Combined with federal ITC/PTC, the abatements close the financing case. Republican-led state, mostly red counties, and yet the most pro-clean-energy financing environment in the country. The market does not care about politics; it cares about returns.
The Texas paradox is the answer to the deregulation-and-environment question in compressed form: deregulation can be a powerful clean-energy lever when the market design suits clean tech, and a brake when it does not. The wholesale auction does not pick winners; it picks whichever technology can earn the most given its rules. ERCOT's rules happen to suit clean tech.
Six things to do if you care about the environment of your bill.
Install rooftop solar with the 30% credit
The Residential Clean Energy Credit covers 30% of the installed cost of solar + storage through 2032 under the IRA. Pair with a battery to maximize the credit and to enable future Order 2222 aggregator revenue. IRS.
Check your state's eGRID emissions intensity
EPA eGRID publishes annual lb CO2/MWh by state and by utility. If your state is gas-heavy (TX, OH) or coal-heavy (WV, WY), every kWh you shift off the grid (solar, EV at midday, demand response) matters more.
Join your CCA or community-solar program
CCAs in CA, IL, MA, OH and community-solar programs in NY, MD, MN, NJ and CO actually fund new renewable builds (unlike most "green" retail plans backed by RECs). If your municipality offers one, enrollment is usually opt-out.
Track Order 2222 in your ISO
If you have or plan to have a battery, EV charger or smart thermostat, the wholesale revenue you can earn through an aggregator arrives on a schedule: ISO-NE 1 Nov 2026, PJM 2028, MISO 2029, SPP 2030. FERC fact sheet.
Audit any "100% renewable" retail offer
Ask the supplier: (a) Is your green energy backed by RECs or by a long-term PPA tied to my subscription? (b) Are the RECs Green-e certified? (c) Is the premium above default service worth it? If the answer is "RECs only" you are paying for an accounting layer, not additional renewable buildout.
Engage your PUC on the next IRP
In regulated states the utility's Integrated Resource Plan, filed every 2-3 years, decides what gets built. Public-comment dockets are open at every state PUC; consumer-advocate offices (NC Public Staff, GA Utility Consumer Office, OCA PA) frequently testify and welcome citizen input.
Common questions about deregulation and the environment.
Mixed answer, by design. ERCOT (energy-only, scarcity-priced) became the US wind and battery capital because scarcity revenue rewards fast-cycling resources. CAISO's duck-curve problem drove a battery boom that has now reshaped the entire US storage market. PJM (capacity-auction, stricter accreditation) makes life harder for variable renewables than for gas. The conclusion: market design matters more than the regulated-vs-deregulated label. Texas is greener under deregulation than most regulated states are under their PUC; California is greener under regulated retail than most retail-choice states are under their default service.
Three reasons. (1) ERCOT is energy-only. No capacity payment. Wind earns by clearing in real time when it is windy and by capturing scarcity prices when conventional plants fail. That suits a variable resource. (2) The 2008-2014 CREZ transmission build moved 18,500 MW of capacity from windy west Texas to Dallas/Houston load. Open-access transmission (Order 888 equivalent at state level) made this possible. (3) Property tax abatements + federal PTC closed the financing. The "Texas miracle" is a market-design story, not a politics story. ERCOT now has ~40 GW of installed wind. Source: ERCOT generator resources.
Same reason as wind: the energy-only market. A battery earns by charging cheap (midday solar) and discharging expensive (evening peaks or scarcity events). ERCOT scarcity events pay up to $5,000/MWh under the December 2025 RTC+B redesign. PJM, with its capacity market, dampens scarcity revenue and rewards always-on resources, which favors gas turbines over batteries. ERCOT now has ~10 GW of installed utility-scale battery storage; CAISO ~13 GW; rest of US together ~17 GW.
Verified against EIA Form 860 and NREL ATB data: solar ~220 GW total (utility-scale ~140 GW, behind-the-meter ~80 GW); wind ~155 GW (almost all utility-scale, ~40 GW in Texas alone); battery storage ~40+ GW utility-scale (doubled from ~20 GW at end 2023). Combined, US renewables and storage now exceed installed coal capacity. Source: NREL Annual Technology Baseline.
Marginally and indirectly. A "100% renewable" retail plan is almost always backed by Renewable Energy Credits (RECs) sourced from existing renewable generators, not new builds. The supplier buys the REC, applies it to your kWh, and you nominally "consume" green energy. The physical electrons on the grid are the same. Some long-term Power Purchase Agreements (PPAs) tied to retail subscriptions do directly fund new builds, but these are rare in residential markets. For real emissions impact: install rooftop solar, install a battery, buy an EV, or support a community-solar project.
It is the most consequential federal clean-energy market rule since the 2005 ITC. Aggregators (Sunrun, Tesla, AutoGrid, Voltus, OhmConnect and others) can bundle thousands of rooftop solar systems, home batteries, smart thermostats and EV chargers into a single wholesale-market bid. The bundle competes alongside gas plants in energy, capacity and ancillary-service markets. Implementation: ISO-NE 1 November 2026, PJM 1 February 2028, MISO 1 June 2029, SPP Q2 2030. CAISO and NYISO already do most of what Order 2222 requires. Source: FERC Order 2222 fact sheet.
The May 2024 rule requires existing coal plants (operating past 2039) and new baseload gas plants to capture 90% of their CO2. It was issued under the Biden administration. The second Trump administration has signaled an intent to rescind, but as of May 2026 the rule remains in force, pending court litigation and a new EPA rulemaking. Coal plant operators have continued to file early retirements based on the rule's economics, which the second EPA cannot reverse. Source: EPA Power Plant GHG standards page.
For real-time clean-energy share: Washington and Oregon (heavy hydro) clear ~85%+ clean; California ~60% non-fossil on an average day; New York around 50% (hydro + nuclear + growing offshore wind); Texas around 35% (rapid wind+solar+storage growth); coal-heavy states (WV, WY, ND) below 20%. The EPA eGRID database publishes annual emissions intensity by state and by utility. ISO-level real-time dashboards (CAISO, ERCOT, NYISO) also show live fuel-mix data.
Keep learning about US energy markets
What is a wholesale electricity market
Seven US ISO/RTOs, marginal pricing, capacity auctions, and what moves your bill.
Deregulated states map
State-by-state status of electricity and gas retail choice in the US.
Introduction to competition
PURPA, EPAct 1992, FERC Orders 888, 889, 2000, 2222.
How liberalization affects you
What retail choice actually means on a residential bill, state by state.
Alternate supplier vs utility
Who does what, who bills you, who handles outages, side by side.
Distributed energy
Rooftop solar, batteries and EVs as wholesale resources under FERC Order 2222.
Demand response
Getting paid to use less. How aggregated demand bids into the wholesale market.
Who regulates US energy?
FERC, state PUCs, the EPA, and where their jurisdictions meet.
Electricity prices per kWh
EIA-verified state-by-state residential prices, May 2026.
Texas energy hub
ERCOT, retail providers, rate plans and the RTC+B redesign.
New York: 1998 to 2026
NYISO, the Reset Order and the offshore-wind buildout.
Illinois: ComEd, Ameren and PJM
CEJA targets, IPA procurement, and the PJM 2026/27 auction impact.