State Climate Policy Opportunities

• We model emissions caps on electricity consumed in US Climate Alliance (USCA) states aligned to achieve the US power sector goal of 80 percent reduction from 2005 levels by 2030, with allowance trading in three separate USCA regions. These caps would reduce emissions in those states by 123 million tons (43 percent) in 2030.
• Regional emissions caps would cause federal subsidies received by USCA states under the IRA to increase by $6.2 billion in 2023 US$ (49 percent). This is $1.1 billion greater than the increase in electricity expenditures in those states of $5.1 billion resulting from the auction of emissions allowances under the emissions caps.
• Nationally, power sector emissions would fall by 48 million tons (7 percent) by 2030. The cumulative emissions reductions from 2025 through 2030 would be 310 million metric tons.
• The regional emissions caps would expand nonemitting electricity generation in the USCA states by 181 terawatt-hours (TWh) in 2030 (15 percent). However, this is achieved partly by redirecting investments away from other states to USCA states and reducing clean generation in the non-USCA states by 84 TWh (6 percent).
• Auctioned emissions allowances in the USCA states would yield $6.6 billion in proceeds that would be available to compensate electricity consumers or accelerate further investments, which could draw in yet additional IRA incentives.
• We also model a state-level clean electricity standard (CES) implemented in the same three USCA regions and calibrated to achieve 80 percent clean generation by 2030. This policy would achieve fewer emissions reductions than the regional emissions caps, lower electricity prices, and not yield auction proceeds.

Under the United Nations Framework Convention on Climate Change Paris agreement of 2015, the United States pledged to reduce greenhouse gas emissions to 50–52 percent below 2005 levels by 2030. The Biden administration’s Department of Energy cited this goal as requiring 80 percent reduction in emissions below 2005 levels in the electricity sector by 2030, roughly equivalent to 80 percent nonemitting electricity supply. This has been termed the “80x30 goal.”

Current state and federal policies leave a gap between projected 2030 emissions and the 80x30 goal. In Domeshek et al. (2024), we examined how a national carbon price might close this gap and reach 80x30. We found that the federal Inflation Reduction Act of 2022 (IRA) lowers the necessary carbon price to achieve 80x30 by more than half. Accounting for new revenues and additional IRA subsidies associated with new investments, the net government expenditures are reduced by $7 billion in 2030 with the introduction of a national carbon price. Moreover, the emissions achieved by the IRA alone are uncertain and depend on such factors as economic activity, siting, and grid connection for new generation facilities, evolving market rules, and consumer acceptance of electrification. An additional benefit associated with a carbon cap is the opportunity to reduce uncertainty about the emissions outcome in the power sector.

Previous inaction in Congress has demonstrated that carbon pricing at the national level is unlikely, and the US Supreme Court ruled in 2022 that the Environmental Protection Agency lacked the authority to pursue emissions reductions in the power sector via the Clean Power Plan. On January 20, 2025, President Donald Trump signed an executive order calling for the United States to leave the Paris Agreement. All three branches of the federal government are currently aligned against further policy actions to reduce greenhouse gas emissions.

This report examines the opportunity for states to fill the gap in the electricity sector between emissions and the US pledge in the absence of further federal action. Justice Louis Brandeis famously noted that every state serves as a policy laboratory. A coalition of 24 states known as the US Climate Alliance (USCA) has focused on achieving the US climate pledge. Many states have policies aimed at decarbonizing electricity generation using various approaches, including carbon pricing and technology policy (e.g., renewable portfolio standard).

We examine two policy approaches that might be coordinated among the USCA states, aiming to achieve 80x30 in those states. One is a carbon cap aligned with state-specific 80x30 targets, and the other is a technology policy we describe as a clean energy standard (CES) that would require 80 percent nonemitting generation by 2030. These policies both allow flexible compliance through trading of emissions allowances or clean energy credits. We consider implementation of these policies in three separate regional groups of USCA states and for a unified group of the 24 USCA states.

With climate policy carried out by the USCA states, we ask several questions. First, what are the impacts of carbon pricing and technology policy on emissions within the USCA states and at the national level? We explore this question while accounting for potential emissions changes in electricity generation and transmission of power between states and for emissions rebound in the non-USCA states.

In isolation, the IRA achieves nationwide emissions reductions in 2030 of 28 percent (277 million metric tons [MMt]) compared with a no-IRA baseline of 996 MMt. With the IRA in place, carbon pricing implemented through regional emissions caps reduces emissions by 47 percent (136 MMt) from anticipated 2030 levels in the USCA states. The caps cause emissions to increase by 17 percent (75 MMt) in the non-USCA states as investments in zero-emissions generation motivated by the IRA are diverted to USCA states. In aggregate, national emissions fall by 8 percent, or 61 million metric tons, with the introduction of regional caps.

The expenditure burden of climate policies has surfaced as a major factor affecting energy affordability. Consequently, we examine how these policies may affect electricity prices. With the IRA in place, we find the regional emissions caps increase electricity prices in the USCA states by 2 percent. These electricity price changes are moderated by IRA subsidies for nonemitting electricity generation and accompanied by carbon revenues that could be used for consumer compensation or energy-related investments. The net effects of the emissions caps and the IRA subsidies are electricity prices that remain below the no-IRA baseline. We also observe that incremental investment in nonemitting generation in the USCA states motivated by the carbon price is associated with decreased investment in other states.

We perform a similar analysis of the potential introduction of three regional CES policies aimed at achieving 80 percent nonemitting generation by 2030 in each of the three regional groups of USCA states. The regional CES policies achieve national annual emissions reductions of 20 MMt in 2030 in addition to those achieved by the IRA. This reflects reductions of 26 MMt in the USCA states and an increase of 6 MMt in the non-USCA states because some of their IRA-related investments are redirected to the USCA states.

An important difference between the regional caps and regional CES policies is that the caps provide auction proceeds that can be used for additional investments or compensating businesses or households. Both policies are self-financing and lead to additional uptake of IRA subsidies, introducing additional costs at the federal level. However, accounting for costs and subsidies experienced at the state level and with the IRA in place, we find that the regional caps in the USCA states would achieve 28 MMt greater annual emissions reductions nationwide in 2030 than would regional CES policies.

We use the Haiku simulation model of the electricity sector to analyze the effects of the IRA and additional state policies on the electricity sector, including changes in emissions of carbon dioxide (CO₂), investments, uptake of federal subsidies, resource costs in the sector, and retail electricity prices.

2.1. Haiku Electricity Market Model

The Haiku electricity market model solves for changes in electricity-generating capacity and future system operations at the state level, with the goal of minimizing system cost to meet projected demand with a capacity reserve margin. The model reflects demand and supply within the 48 contiguous states and DC. It includes interstate transmission capabilities, a 26-year horizon, and planned capacity costs and performance characteristics of existing capacity from the S&P Global database. Cost and performance characteristics for new renewable technologies and carbon capture and storage are from the 2022 National Renewable Energy Laboratory’s Annual Technologies Baseline “Reference” Scenario, and other technologies, fuel costs, and electricity demand are from the Annual Energy Outlook 2021 (EIA 2021). Natural gas prices have been adjusted to account for historic price fluctuations. Electricity demand is categorized into 24 distinct time blocks for each year (three seasons, with four load levels for two times of day, daytime and nighttime). Each state is characterized as either participating in an organized wholesale market or being subject to cost-of-service regulation.

Our modeling of IRA policies in the electricity sector could be characterized as an optimistic implementation because investments are driven by economic factors assuming only modest siting constraints on new facilities and a phase-in of substantial use of the bonus credits. On the other hand, we do not model transmission expansion and grid modernization, which are elements of a clean energy transformation in the electricity sector.

2.2. Policy Framework

The no-IRA baseline scenario assumes only existing state policies that are in place. This includes state-level renewable portfolio standards (RPSs), which credit only renewable resources, and CES policies that credit all nonemitting resources, including nuclear. It also includes a representation of the state and regional carbon-pricing policies facing electricity generators in California and the Regional Greenhouse Gas Initiative (RGGI).

We consider additional policy scenarios with and without the IRA. We organize the 24 USCA states into three groups for policy experiments. One includes the Pacific coast and mountain states, aligning roughly with members of the original Western Climate Initiative. The second includes upper plains and some Midwestern states. The third includes mid-Atlantic and Northeastern states, aligning mostly with members of RGGI. States in these regions generally share power markets and have similar resource characteristics, and many share common regional eligibility for compliance with existing RPS policies.

The regions are illustrated in Figure 1, organized into three groups identified by colored borders. The existing carbon-pricing policies in USCA states are also indicated. Twenty-eight states plus the District of Columbia have existing RPS policies, and 11 have CES policies, sometimes with one evolving into the other.

2.2.1. IRA Baseline

The representation of the IRA in the baseline and policy scenarios focuses on the tax credit provisions that promote renewable and other carbon-free (or very low-carbon) sources of electricity production. Chief among these is the long-term extension and reformulation of the production tax credit (PTC) and investment tax credit (ITC) to apply to solar and wind and the extension to energy storage and a potentially broader range of new nonemitting generators beginning in 2025. Both the ITC and PTC include base credit levels and bonuses that apply to projects that meet specific labor standards, are built in areas defined as “energy communities,” and use domestic content to enable them to capture bonus credits. Taken together, these bonus provisions increase the 30 percent ITC to as much as 50 percent and the $25/MWh PTC to as much as $30/MWh. The choice between the PTC and the ITC is endogenous in the model.

We locate energy communities in each state (Raimi and Pesek 2022) and apply a partial credit based on the percentage of land in each state in each category to adjust the PTC and ITC rates. In April 2023, the US Department of Treasury and Internal Revenue Service finalized guidance that would lead to a somewhat different geographic distribution of renewables than that in our analysis. For the domestic content bonus, we assume that 20 percent of it applies in 2026 and that it increases linearly to the full amount by 2030. We represent endogenous economic investments in offshore and onshore wind, solar, and battery storage. Our modeling reflects the provisions of the IRA and the Infrastructure Investment and Jobs Act that support nuclear generators by assuming the subsidies successfully maintain the level of nuclear generation achieved in the baseline. The PTC for existing nuclear in the IRA is not represented explicitly, and neither are associated government expenditures or any wholesale electricity price benefits. We also incorporate the Section 45Q tax credit of $85 per ton for new fossil generators that capture at least 75 percent of the carbon emissions from the facility. This credit translates to an $85/MWh tax credit for coal-fired generators equipped with carbon capture and storage and a $40/MWh credit for gas-fired generators.

The IRA has influenced the pattern of investments that will occur with and without the policies we model. As a sensitivity analysis, we consider each policy with and without the IRA in place.

2.2.2. Emissions Caps

Emissions caps are calculated on a state-specific basis at levels that achieve an 80 percent reduction from 2005 emissions in 2030. These state-specific caps are aggregated to identify regional caps, and compliance is achieved on a regional basis in 2030 without allowance banking. The carbon price is applied to all in-state generation including exports from the policy state. We assume each state can enforce its carbon-pricing policy on imported power, assuming an emissions intensity (tons/MWh) equal to the annual average rate in the baseline for each adjoining non-USCA state. The average annual rate is a coarse approximation of how the policy will affect emissions outcomes overall; this depends on the marginal emissions rate, which varies over hours. Generally, it is not clear how enforcement of a border policy on power imports into the USCA states would be implemented, but we assume it is possible through emerging software capabilities on the electricity grid. In general, the application of an estimate of the emissions intensity of imported power, and using that to require compliance, resembles the First Jurisdictional Deliverer policy in the California cap-and-trade program, which assigns rates to specific sources when possible and otherwise uses a default rate approximately equal to fossil gas combined cycle units. California Air Resources Board is able to implement this policy because the state mostly aligns with the California Independent System Operator. New York is the only other USCA state that aligns with a power market.

The use of auction proceeds to accelerate the energy transition or provide compensation for consumers or regulated entities is an important element of current state and regional carbon markets. We account for carbon revenues under the emissions caps, but we do not account for their potential uses, which could yield additional emissions reductions.

2.2.3. Clean Electricity Standard

We represent a CES policy that resembles an RPS calculated to achieve a specified amount of clean generation as a share of total consumption. Unlike existing RPS policies, we assume the CES policy credits existing clean nuclear generation toward the clean energy goal. We keep existing RPS policies in place. Like the carbon caps, the CES we model is implemented for three regional USCA states.

A CES, like an RPS, effectively consists of two policy instruments combined into one. The requirement to surrender a clean energy credit imposes a cost on the firm that serves as an incentive to use clean technology. The CES credits are earned by nonemitting electricity generation, providing a production incentive. The CES policies set a target within each region specifying that its clean electricity generation must equate to 80 percent of its electricity consumption in 2030 on an average annual basis.

We examine emissions caps applied to three regional groups of USCA states. We compare this policy framework with the business-as-usual baseline and with a national emissions cap.

3.1. Emissions

Figure 2 shows 2030 US emissions with and without the IRA for no cap, regional caps, and national cap scenarios. The horizontal lines indicate the national 80 percent reduction target and the 80 percent reduction target for the three regions. Nationally, baseline emissions without state-level emissions caps and in the absence of the IRA would total 996 MMt. They fall by 28 percent to 719 MMt under the IRA. The greatest change in percentage and tons reduced is observed in the non-USCA states, where emissions fall by 33 percent compared with an 18 percent decline in the USCA states. This outcome is illustrated in the left panel of Figure 2.

The middle panel displays the outcome with three regional caps limited to the USCA states. Without the IRA, these caps lower emissions by 54 percent from anticipated 2030 baseline levels in the USCA states. Emissions outside the USCA states rise 14 percent because of an increase in fossil generation. Border adjustments for imported electricity in our modeling are based on projected emissions intensity from non-USCA states. However, when the non-USCA states increase fossil generation, emissions intensity is greater than originally projected, meaning that the carbon price adder associated with imported electricity is too low. This carbon intensity discount on non-USCA electricity generation leads to emissions leakage through imports into USCA states. Ultimately, the emissions decrease in the USCA states is greater than the increase in the non-USCA states, causing national emissions to fall 10 percent to 901 MMt.

With the IRA, the regional caps reduce emissions in the USCA states 43 percent. The shift of zero-emitting generation into the USCA states and away from non-USCA states causes emissions outside of the USCA states to rise 17 percent. Again, the emissions decrease in the USCA states is greater than the increase in the non-USCA states, causing national emissions in this case to fall 7 percent to 671 MMt.

The right panel in Figure 2 shows emissions with a national emissions cap, which leads to more emissions reductions because it covers all emissions in the country. Emissions leakage, measured by emissions increases in non-USCA states under the USCA regional caps, is eliminated with a single national cap. Without the IRA, emissions under a national cap in the non-USCA states are 62 percent lower than under the regional caps, and emissions in the USCA states are 25 percent greater than in the regional caps case. With the IRA, under a national cap, the emissions in the non-USCA states are 43 percent lower than under the regional caps, and emissions in the USCA states are 18 percent greater than in the regional caps case.

3.2. Generation

Nationwide electricity consumption is estimated to be almost 4,000 TWh in 2030, as illustrated in Figure 3. Electricity generation is roughly 7 percent greater than consumption to account for transmission losses. In the baseline without the IRA, just over 50 percent of generation would be from nonemitting sources, with about 55 percent of that in the USCA states and 45 percent in the non-USCA states. We find the IRA expands clean generation to almost 65 percent of total generation and has its greatest influence in the non-USCA states, where clean generation grows from 23 to 34 percent of total national generation.

The introduction of regional caps ensures that renewable generation is built in the USCA states regardless of federal policy. Without the IRA, the regional caps grow total clean generation by 5 percentage points to almost 56 percent of total national generation. The growth in clean generation occurs almost entirely in the USCA states, and there is virtually no change in the non-USCA states.

With the IRA already in place, the introduction of the regional caps causes clean generation nationally to grow by only 2 additional percentage points, reaching 67 percent of total generation. Clean generation in the USCA states increases by 15 percent, but clean generation in the non-USCA states is diverted to the USCA states and falls by 7 percent.

The right panel in Figure 3 shows that under a national emissions cap, clean energy generation MWhs are split about evenly between USCA and non-USCA states without and with the IRA.

3.3. Electricity Prices

Investments made possible under the IRA are expected to reduce average retail electricity prices by 5 percent in the USCA states in 2030. In the non-USCA states, where the majority of incentivized nonemitting generation is expected to occur, electricity prices are expected to fall by 6 percent. Figure 4 shows the projected electricity prices for 2030.

Without the IRA, in the USCA states covered by the regional emissions caps, electricity prices increase by 7 percent. In the non-USCA states, electricity prices fall by 1 percent.

With the IRA in place, the regional caps yield a 2 percent increase in electricity prices in the USCA states. These caps yield no significant change in the non-USCA states. The combined effect of the IRA and the regional caps is a reduction of 3 percent in prices in the USCA states and 6 percent in the non-USCA states.

In contrast, with the IRA already in place, a national emissions cap would increase prices by 4 percent in the USCA states, and the net effect of the IRA and the national cap would be a decrease in prices of 1 percent. In the non-USCA states with the IRA in place, a national emissions cap would increase prices by 8 percent, and the net effect of the IRA and a national emissions cap would be to increase prices by 1 percent.

3.4. Carbon Revenues and IRA Subsidies in the USCA States

The IRA and the proposed emissions caps produce two types of government revenue impacts: clean energy tax credit expenditures by the federal government and carbon revenue accruing to either the federal or state governments. Figure 5 shows the combined impact of subsidies and carbon revenues as experienced in USCA and non-USCA states.

In the leftmost panel of Figure 5, the only government revenue impacts are tax credit expenditures. The IRA provides clean energy subsidies nationwide totaling almost $35 billion in 2030, as illustrated in the left panel of Figure 5. The major share, nearly $21 billion, flows to non-USCA states. Subsidies present in the no IRA case describe subsidies applied to qualifying wind generation that phased down prior to the IRA.

The addition of regional caps (middle panel of Figure 5) introduces the second category of government impact: carbon revenues. Without the IRA, the regional caps would generate $13 billion in carbon revenues for USCA states in 2030. The IRA subsidies reduce the carbon price necessary to achieve the caps, causing carbon revenues to fall by over 40 percent.

The regional caps also trigger an increase and a shift in where IRA subsidies are received. IRA subsidies increase by $7 billion in USCA states and decrease by $3.4 billion in non-USCA states, as the increase in renewable energy investments in the USCA states is partially a redirection of investments from non-USCA states. The revenue collected from the carbon price is greater than the increased investment in USCA states, which partially drives the 2 percent increase in prices from the emissions caps.

The $5 billion increase in USCA electricity expenditures is less than the $7.7 billion in carbon revenues collected by the emissions cap policy. This is partly because the policy draws in additional IRA subsidies for renewable generation, which has a downward effect on the electricity price. Policymakers might reinvest carbon revenues to further reduce emissions and lower energy costs. This can be done in such a way that emphasizes lowering costs most for those with the highest energy burden. Alternatively, carbon revenues can neutralize rate impacts and allow the state to invest remaining revenues toward other policy goals.

The introduction of a national emissions cap would yield a higher carbon price than what occurs under the regional emissions caps, and consequently, greater revenues would be collected in the USCA states; however, under a national cap, those revenues would flow to the federal government rather than the states. We also observe that substantially more IRA subsidies would flow to non-USCA states under a national cap.

3.5. Carbon Prices

Emissions caps generate carbon prices that represent the marginal cost of abatement. The IRA subsidies reduce the marginal cost of abatement from the state perspective because zero-emissions technology is effectively cheaper. Each regional cap produces a different carbon price, illustrating the variation in marginal cost of abatement across regions

Figure 6 shows the carbon prices under these policies. The introduction of IRA subsidies reduces the marginal cost of abatement under a national cap by over $50, cutting the price in half. For the USCA regional caps, the West and East regions see a similar reduction of around $50, equating to a 40 percent reduction in the West and a 60 percent reduction in the East. The Midwest, which has a much lower marginal cost of abatement of $44 without the IRA, still sees a similar 50 percent reduction in cost, leading to a $20 marginal cost with the IRA.

The carbon prices we project are in line with current emissions market outcomes. In the West, the carbon price is estimated to be only slightly higher than the current economy-wide carbon-pricing programs. However, in the real-world California and Washington programs, allowances to utilities are freely allocated, and some rebate is provided to ratepayers (e.g., the California Climate Credit) to mitigate the cost impacts. In the East, RGGI prices are lower today than the $37 we project in 2030, but the current cap is less stringent than the 80x30 target.

Although the Midwest does not presently have an emissions cap, its relatively low marginal cost for the 80x30 target, regardless of federal policy, presents an opportunity to achieve climate targets at a lower cost. The existence of the IRA subsidies keeps the cost of state emissions caps lower, enabling greater ambition. In their absence, a Midwest emissions cap for the USCA states would still outperform the other regional programs.

Technology policies including renewable energy standards and clean energy standards have been influential in driving a clean energy transition. Twice as many states have some form of technology policy as those with an active emissions cap on their power sector. With this evidence of policy acceptance in mind, we explore what could be accomplished with a CES policy calibrated to achieve 80 percent clean generation (including existing nonemitting nuclear generation) implemented in three regional groups.

4.1. Emissions

Figure 7 shows emissions with and without the IRA for different regional configurations of a Clean Energy standard in a manner analogous to that in Figure 2. Without the IRA in place, the three regional CES policies achieving 80 percent clean energy generation have a modest effect on emissions. In the USCA states, emissions fall by 51 MMt to 301 MMt, which remains above an 80 percent emissions reduction target of 164 MMt. Perhaps surprisingly, the CES policies have a greater effect on emissions in the non-USCA states, where they fall by 73 MMt as a result of changes in electricity trade between states.

With the IRA in place, the regional CES policies have a smaller effect in the USCA states because the IRA has already significantly reduced emissions. In the USCA states, emissions are reduced by 26 MMt to 261 MMt, still well above the USCA state emissions target of 164 MMt. Emissions in the non-USCA states rise slightly, by 6 MMt, as new clean generation in the USCA states crowds out clean generation elsewhere. National emissions total 699 MMt, a reduction of 20 MMt, relative to an 80x30 emissions goal of 456 MMt.

In contrast, a national CES could come much closer to achieving the 80x30 emissions goal by driving investments in non-USCA states. With or without the IRA, the national standard would determine clean energy investments. With these investments in place, emissions under a national CES would approximately achieve the 80x30 emissions reduction goal. This is in line with the US Department of Energy finding that 80 percent emissions reductions in the power sector align approximately with 80 percent nonemitting generation in 2030 (DOE 2023).

4.2. Generation

Figure 8 compares clean energy generation across different regional CES configurations. The IRA sparks a 28 percent growth in clean energy generation, as illustrated in the figure. However, the geographic impacts vary. In USCA states, clean energy grows by 128 TWh (12 percent), and in non-USCA states, by 439 TWh (49 percent). With the IRA in place, the regional CES policies further increase clean energy by 145 TWh. However, this is accompanied by 103 TWh in reduced clean energy generation in the non-USCA states because the requirement to build clean generation in the USCA states diverts investment away from elsewhere.

Although the impacts vary geographically with regional CES policies, they are more uniform under a national CES policy. In the right panel of Figure 8, we find the quantity of clean energy generation varies by less than 1 percent in the USCA and non-USCA states with or without the IRA in place. Variation is partly due to the geographic differences in the IRA from the energy community bonus and the regional heterogeneity of new plant characteristics such as capital costs and resource availability.

4.3. Electricity Prices

With the IRA in place, the regional CES policies would yield a 2 percent decline in electricity prices in the USCA states, driven primarily by the increase in IRA subsidies to renewables in those states, with no change in the electricity price in the non-USCA states (see Figure 9). The net effect of the IRA and the regional CES policies is a reduction of 7 percent in electricity prices in the USCA states. A national CES policy added to the IRA would yield approximately no change in electricity prices in the USCA states and a 1 percent increase in the non-USCA states. The net effect of the IRA and a national CES policy is a 5 percent reduction in electricity prices in both types of states compared with the absence of both policies.

The IRA subsidies interact with the CES policies to realign the deployment of nonemitting technology and electricity affordability. Without these policies, new capacity investments are motivated by higher electricity prices or, in cost-of-service regions, by increases in demand at regulated prices that initiate utility financing of new projects through rate increases. However, both federal subsidies and the low cost of wind and solar generation reduce or slow the increase of electricity prices while providing incentives for new investment in electricity generation.

4.4. Credit Prices

Technology policy often takes the form of a tradable performance standard. This means that compliance entities (typically utilities) are required to procure credits produced by qualifying clean technologies to cover some percentage of their generation. The CES policy we model requires that 80 percent of generation must be met by zero-emissions generation. The CES credit price is the production incentive paid to clean generation by utilities. These may be distinguished as renewable energy credits under an RPS or clean energy credits when all nonemitting generation qualifies, as in the CES we model.

IRA subsidies reduce the cost of these credits because they lower the costs of investments and the generation that produces the credit. In Figure 10, we see the credit prices across the regional CES policies we consider. We find that a national CES would yield a CES credit price of $48/MWh of zero-emissions generation. With the IRA, this price falls to $29/MWh. In the three USCA regions, without the IRA, CES credit prices are below $20/MWh. With the IRA, the credit prices fall substantially and are zero in the East region, implying that no additional production incentive is necessary to achieve 80 percent clean electricity generation in that region in 2030.

Credit prices under technology policy are not comparable to carbon prices under an emissions cap. Emissions caps represent the marginal cost of abatement in units of $/ton, while credit prices represent the necessary subsidy to bring additional qualifying generation online in units of $/MWh. It is also not always the case that an additional MWh displaces emissions because of the time profile of generation for zero-emissions technologies. In this way, technology policies are better for targeting technology goals than emissions goals.

Modeling allows us to mathematically describe policy impacts in the future. Policy implementation has greater complexity because of the need to accommodate important stakeholders, political dynamics, or other policy goals that can be difficult to mathematically describe. In this section, we qualitatively describe the impacts of common adjustments to emissions caps and clean electricity standards.

5.1. Cost Efficiency of Regional Policies

Covering a larger number of emissions with cost-effective climate policy can enhance overall performance of programs. In this analysis, we considered policies in three regions of USCA states. However, some emissions caps are implemented at the state level (e.g., Washington and California) instead of regionally (e.g., the Regional Greenhouse Gas Initiative). RPS policies aggregate across states, and generation capacity and availability requirements effectively do also because regional transmission operators and independent system operators who run the grid have multistate jurisdiction. Regionally aggregated or linked policies are more cost-effective than individual state policies with equivalent targets because some states have lower cost compliance options than others. Similar improvements in cost effectiveness from aggregating state-level climate policy to the regional level can be achieved by aggregating regional USCA policies to a single USCA region.

With the merging of regional markets, the local political economy considerations of states still matter. Some state policy is intentionally separated from a regional program because of factors other than cost-effectiveness. For example, if local air pollution from power plants is particularly concentrated near population centers in one state, the cobenefits of reducing air pollutants in the state might outweigh the cheaper emissions reductions out of state. When policymakers implement emissions caps, thinking forward about these considerations in the initial design can smooth the program-merging process. For example, Washington state designed its cap-and-invest program to include many design elements found in California’s cap-and-trade program. This approach to policy design eases the compatibility of the programs for linking and simplifies negotiations toward moving into a merged emissions market.

Partial crediting is another consideration for technology policy that can improve the cost efficiency of a program. Emissions caps allow for the most cost-effective reductions because emissions can be reduced by switching to a lower-emissions generator even if it is not entirely nonemitting. However, for a technology policy, this type of switching is not incentivized unless lower-emitting generators receive a partial credit. Different benchmark emissions rates can be set to determine the maximum emissions rate a generator can have while also receiving a credit. The benchmark emissions rate is calculated as one minus the emissions rate of a generator divided by the reference emissions rate. Such partial crediting is one way to enhance technology policy with the cost-effectiveness of fuel switching.

5.2. Cost Containment

If the incentives in the IRA are reduced in the future, the carbon prices and clean energy credit prices in the policies we model will increase. This federal policy change would increase the costs of these policies for households and businesses. Many states have designed mechanisms to reduce costs in the face of uncertain increases resulting from federal policy shifts or other factors.

The RGGI, Washington, California, and Quebec emissions cap programs include cost containment reserves, also known as allowance price containment reserves. These mechanisms work by introducing additional allowances to the market at a predetermined trigger price. This feature allows for a slight increase in emissions while containing costs in the near term. A ceiling on the carbon price can also exist for similar purposes.

Technology policy programs often contain an analogous feature called an alternative compliance payment (ACP), which is a maximum price for the renewable energy credits or clean energy credit in our scenarios. Revenues from ACPs can be used to invest in additional generation but can also be used to mitigate ratepayer cost increases. This feature is like the revenue recycling done with carbon pricing.

Another method to manage costs used in some carbon-pricing programs is free allocation. For regulated utilities, free allocation reduces the cost of compliance for utilities as well as the costs they pass on to ratepayers. In California, the value of all free allowances allocated to utilities must be used for the benefit of ratepayers, and most of that value is directed to the California Climate Credit, which is a rebate to electricity and natural gas ratepayers. Our policy formulation is a revenue-raising auction of all emissions allowances, with no free allocation.

5.3. Multipolicy Solutions

Many states are under both a multijurisdictional emissions cap and a technology policy. In the Northeast, there are several linked state RPS policies involving states that are also part of the RGGI cap. This combined-policy approach allows for revenues to be collected from polluters while simultaneously increasing incentives for renewable energy. In California, where the emissions cap is economy-wide, a clean energy standard applies to generators that also must purchase allowances to cover their emissions. This overlapping policy framework allows for the carbon price to motivate some reductions in the power sector but guarantees specific outcomes through the clean energy credit market. While emissions reductions are the primary goal of carbon pricing, clean energy outcomes that might be promoted independently or concurrently through CES policies in the power sector may help achieve national climate goals economy-wide because of the important role for electrification of other sectors.

The IRA clean energy tax credits help enable state policymakers to meet their climate goals in the power sector. With the IRA, additional state climate policy is less costly to ratepayers and utilities. At the same time, state climate policies serve as a backstop to potential rollback of federal policy, enforcing a minimum level of emissions reductions or clean energy deployment even with the prospect of potential repeal of federal policy. The associated emissions reductions from the state CO₂ caps and technology policies also yield emissions reductions in copollutants that can improve local air quality in the USCA states.

We have examined two policies that the US Climate Alliance (USCA) states could apply at a regional level to achieve an 80x30 target:

• an emissions cap set to reach emissions that are 80 percent below 2005 levels by 2030
• a technology policy designed to reach 80 percent nonemitting electricity generation by 2030

USCA regional emissions caps create a carbon price incentivizing emissions abatement in the power sector. This policy draws additional uptake of IRA subsidies in those states. The carbon price raises electricity prices, but prices remain below their level in the absence of the IRA and regional emissions caps combined. Because the carbon price also raises revenues that are greater than the change in ratepayer costs, the state can use these revenues to compensate households and businesses for any cost imposed on them through higher electricity bills.

USCA regional technology policy in the form of a CES creates a credit market that subsidizes nonemitting electricity generation through payments from emitting generation. This type of policy increases the subsidies flowing into the USCA states but has a smaller net emissions impact than regional emissions caps, and it provides no additional state revenues if the price ceiling (ACP) is not binding. The increased subsidy flow further decreases electricity prices below their level with only the IRA.

State climate policy serves as a magnet for federal investments. However, some of the additional emissions reductions are lost to emissions leakage. To address this, expanding these policies beyond the USCA states and eventually to the federal level can increase both the efficiency and climate benefits of these policies.

Currently, the IRA creates synergies such that increased regional or state climate policy ambition correlates with electricity rate reductions within those regions. This alignment also might encourage states that have not already implemented state climate policy to do so. Removing the IRA subsidies would reorient these interactions between state and federal policy such that increased ambition could increase local costs. On the other hand, expanding federal policy to include emissions caps or a federal CES or RPS could provide the benefits of reduced emissions and lower energy prices more broadly across the country.

State policy serves as a backstop to potential federal policy repeal. Even without the additional incentives provided by the IRA, state efforts can help modernize local economies to prepare for the energy transition that is accelerating on an international stage.