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Fiscal Alliance Foundation Study · Published: October 2026

RGGI: The Rising Cost of Carbon in New EnglandHigher Power Prices and the Uncertain Return to Ratepayers

By L. Linowes

Carbon cost vs. fuel cost
RGGI’s carbon cost now exceeds the cost of the fuel itself
RGGI carbon cost
$17.18
Natural-gas fuel cost
$13.88
Per MWh, representative New England natural-gas plant, September 2026 — at the $37.65 allowance price.
Energy efficiency
The cost of acquiring efficiency savings nearly tripled
2018
$362
2022
$979
Reported program cost per annual MWh of efficiency savings across New England. In Massachusetts it rose from $365 to $1,404 — nearly quadrupling.
$37.65
September 2026 allowance price per ton, up 69% in a year
73%
Fall in the RGGI-10 base cap between 2027 and 2033
$1.49B
Estimated addition to New England wholesale electricity costs in 2026
99%
Natural gas’s share of New England’s RGGI-covered fossil generation in 2024

Executive Summary

The Regional Greenhouse Gas Initiative (RGGI) is an 11-state cap-and-trade program, established in 2005 and first implemented in 2009, designed to reduce carbon emissions from large fossil-fueled power plants in the Northeast. Covered generators must purchase and retire one CO₂ allowance for every ton of carbon dioxide they emit. By limiting the supply of allowances, RGGI is designed to make emitting CO₂ increasingly costly and to make higher-emitting generation less competitive over time.

RGGI’s economic and operational pressures become more consequential once the easiest and least-cost emissions reductions have been exhausted. This report examines that major turning point: beginning in 2027, the program moves to a much more aggressive allowance framework just as the region has fewer ways to cut emissions further.

The analysis focuses on the ten states that were participating before Virginia’s return in July 2026: Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York, Rhode Island, and Vermont (RGGI-10). Virginia is excluded. At several points, the report looks specifically at the six New England states because all six have participated continuously in RGGI since implementation and operate within the same ISO New England wholesale electricity market.

46%
Decline in New England’s RGGI-covered CO₂ emissions from 2009 to 2019. Coal, oil, and other non-gas fuels accounted for 88% of that reduction.
2032
Under the report’s stress-test assumptions, the RGGI-10 allowance bank is exhausted in 2032, leaving generators 22 million allowances short of what they will need to cover emissions.
$785M
Estimated 2026 RGGI auction revenue collected by the six New England states. Generators recover these compliance costs through higher electricity prices paid by consumers.
Executive Summary

Early RGGI and RGGI 2027 and after

The program’s early years and the framework that begins in 2027

Key Findings

FINDING 1

Early Emissions Reductions Occurred While Allowances Were Abundant and Inexpensive: Across the RGGI region, emissions fell well below the original cap while allowance prices remained low. A major contributor was the broader shift from coal and oil to lower-emitting natural gas. New England provides a particularly clear example of that transition.

FINDING 2

The Easy Fuel-Switching Transition Is Largely Over: Much of the early reduction came from replacing higher-emitting fossil generation with natural gas. In New England, natural gas now accounts for about 99% of RGGI-covered fossil generation, leaving far less coal and oil for gas to replace. Further large reductions increasingly require reducing natural-gas generation itself or electricity demand.

FINDING 3

The 2027 Framework Creates Rapid Allowance Scarcity: Across RGGI-10, the base cap falls by 73% between 2027 and 2033. Unless covered emissions decline at a similar rate, the gap between emissions and the number of allowances available for compliance will grow, increasing competition and pushing prices higher.

FINDING 4

The Existing Allowance Bank Delays, but Does Not Eliminate, the Shortfall: A stress test prepared for this report estimates that roughly 49 million surplus allowances will be available to RGGI-10 entering 2027. Even after crediting offshore-wind projects already under construction and assuming all additional cost-containment allowances are available, the bank is exhausted in 2032. In that year, modeled emissions exceed total available allowance supply by about 22 million tons, meaning generators would not have enough allowances to cover their emissions.

FINDING 5

RGGI Costs Are Already Large Relative to Fuel Costs: At the September 2026 allowance price of $37.65 per ton, RGGI adds about $17.18/MWh to the cost of a representative New England natural-gas plant. This added cost is greater than the $13.88/MWh fuel cost for natural gas that month.

FINDING 6

Auction Revenue Captures Only Part of the Ratepayer Cost: This report estimates that RGGI could add about $1.49 billion to New England wholesale electricity costs in 2026, while the six states collect about $785 million in auction proceeds. Auction revenue therefore measures only what states collect, not the full cost borne by ratepayers.

FINDING 7

Replacing Natural Gas Will Not Be Simple or Cheap: New England’s current development pipeline is dominated by wind, solar, and battery storage, with little new dispatchable thermal capacity being developed. At the same time, the reported cost of acquiring additional energy-efficiency savings has risen sharply. As the RGGI cap tightens, reducing gas generation will therefore require replacement resources or demand reductions that cannot simply be assumed to arrive quickly or at low cost.

How This Report Is Organized

This report focuses on the changes to RGGI beginning in 2027 and their implications for allowance supply, electricity costs, and future compliance. Historical context is included where needed; additional program detail appears in the appendices. Appendix A explains how RGGI works; Appendix B summarizes the evolution of the cap and allowance market; Appendix C documents the assumptions and calculations used in this analysis; and Appendix D provides supporting energy-efficiency data.

Unless otherwise noted, references to the cap, allowance supply, allowance bank, and auction prices refer to the RGGI-10 market. Where useful, the report examines New England separately because its six states have participated continuously in RGGI and operate within the same wholesale electricity market.

RGGI Is Entering a Much Tighter Phase

As RGGI transitions from a period of loose emissions caps to aggressive cap reductions, the allowance market faces unprecedented allowance scarcity.

RGGI is moving from a period of abundant allowances to one of increasing scarcity.

For much of the program’s early history, the emissions cap exceeded actual emissions. Unused allowances accumulated, and allowance prices remained low. Beginning in 2027, that changes: the supply of new allowances falls much more rapidly.

The power system has changed as well. Much of the early emissions decline occurred while natural gas was replacing higher-emitting coal and oil. That opportunity is now largely exhausted, particularly in New England.

The question facing RGGI after 2027 is therefore different from the one it faced at inception: can covered emissions fall fast enough to keep pace with a rapidly shrinking supply of allowances?

RGGI’s Early Record Was Shaped by a Different Power Market

Historical emissions declines occurred while allowances were cheap and plentiful, with low-cost natural gas displacing coal and oil as a major contributor.

The original RGGI cap substantially exceeded actual emissions, allowing a large allowance surplus to accumulate. By the end of 2013, approximately 319 million allowances were in circulation compared with 179 million tons of cumulative compliance obligations, leaving a surplus of about 140 million allowances (Potomac 2014, 8).

RGGI’s Early Record

A cap above emissions: the surplus by the end of 2013

Allowances in circulation vs. cumulative compliance obligations, million · average allowance clearing price, $ per ton
Allowances in circulation vs. compliance obligations, end of 2013 (million)
Average allowance clearing price ($ per ton)
By the end of 2013, approximately 319 million allowances were in circulation compared with 179 million tons of cumulative compliance obligations, a surplus of about 140 million allowances. The average clearing price was $2.77 per ton in 2009 and roughly $1.90 per ton from 2010 through 2012.

Prices initially reflected uncertainty about the new market. The average allowance clearing price was $2.77 per ton in 2009, but as it became clear that emissions were well below the cap and a large surplus was accumulating, prices fell and settled near the auction floor, averaging roughly $1.90 per ton from 2010 through 2012.[1]

Yet emissions were falling rapidly across the RGGI region, in large part because lower-cost natural gas was replacing coal and oil generation (EIA 2014).

New England provides a particularly clear example. Between 2009 and 2019, emissions from RGGI-covered generators fell from 39.4 million tons to 21.2 million tons, a decline of about 46 percent. Eighty-eight percent of the total emissions decline came from reductions in coal, oil, and other non-gas fuels.[2]

The Easy Coal-and-Oil-to-Gas Reductions Are Largely Gone

Natural gas now accounts for 99% of New England’s RGGI-covered fossil generation, leaving little coal and oil generation available for further fuel-switching.

After 2019, the direction changed. Covered CO₂ emissions in New England increased from 21.2 million tons in 2019 to 26.2 million tons in 2024.

Fossil generation also increased. From 2020 through 2024, electricity production from RGGI-covered fossil plants rose 19 percent to 54.3 million MWh. By 2024, natural gas accounted for 99 percent of covered fossil generation and 98 percent of covered CO₂ emissions.[3]

The Easy Reductions Are Largely Gone

New England’s covered emissions fell, then turned back up

CO₂ emissions from RGGI-covered generators in the six New England states, million tons · natural gas’s share of covered fossil generation, 2024
Covered CO₂ emissions, six New England states (million tons)
Natural gas’s share, 2024
0%
of New England’s RGGI-covered fossil generation was natural gas in 2024
98% of covered CO₂ emissions
Between 2009 and 2019, covered emissions fell from 39.4 million tons to 21.2 million tons, a decline of about 46 percent; eighty-eight percent of that decline came from reductions in coal, oil and other non-gas fuels. By 2024 emissions had increased to 26.2 million tons, and natural gas accounted for 99 percent of covered fossil generation and 98 percent of covered CO₂ emissions.

With little coal and oil generation left to displace, further large emissions reductions increasingly require reducing natural-gas generation itself.

RGGI Costs Are Already Rising

Allowance prices have surged to $37.65 per ton, making the carbon compliance cost on natural gas generation higher than the cost of the fuel itself.

RGGI allowance prices have risen sharply even before the new 2027 framework takes effect.

In RGGI’s early years, allowance prices remained at or near the auction floor. By September 2026, the auction clearing price had reached $37.65 per ton, 69 percent higher than a year earlier.

The increase appears to reflect a market already anticipating tighter allowance supply. RGGI’s market monitor reported that 2027 futures prices had risen to levels indicating that some market participants expected the additional allowance supply to be fully used as the new cap takes effect (Potomac 2026b, 9).[4] At the same time, covered generation remains heavily dependent on natural gas, thereby sustaining demand for allowances unless fossil generation or electricity demand falls.

For a representative New England natural-gas plant, higher allowance prices translate directly into a higher cost of producing electricity.

Figure 1

RGGI Cost Added to Representative Natural-Gas Generation

Dollars per MWh · representative New England natural-gas plant · 2012 to September 2026
The 2012 value is plotted at the chart’s “Less than $1” label. The dashed line marks the $13.88/MWh fuel cost for natural gas in September 2026, which the RGGI carbon cost of $17.18/MWh now exceeds.
Source: ISO-NE 2026e; RGGI 2026a; author calculations.

The trend has accelerated sharply. ISO New England estimated that RGGI added $10.21/MWh to the production cost of a representative natural-gas combined-cycle plant in 2025 (ISO-NE, 2026a). At the September 2026 allowance price, that cost rises to $17.18/MWh. The RGGI carbon cost alone is now greater than the $13.88/MWh fuel cost for natural gas that month.[5]

The effect is amplified in New England because fossil generators frequently set the real-time wholesale price. In 2025, natural-gas generators set the price for 79 percent of electricity demand and oil generators for another 3 percent. When a RGGI-covered fossil generator sets the price, its allowance cost can raise the clearing price paid across the market, including to generators that do not themselves purchase allowances. Ratepayers ultimately bear that higher cost through wholesale electricity prices.

RGGI Costs Are Already Rising

Fossil generators set the price for most of New England’s load

Share of 2025 electricity demand for which each resource set the real-time wholesale price
Natural gas — 79%Oil — 3%All other resources (calculated) — 18%
In 2025, natural-gas generators set the price for 79 percent of electricity demand and oil generators for another 3 percent. The remaining 18 percent is calculated as the balance.

If current allowance prices persist through the end of 2026, this analysis estimates that RGGI could add $1.49 billion to New England wholesale electricity costs for the year.[6]

$1.49 billion
Estimated addition to New England wholesale electricity costs in 2026 if current allowance prices persist through the end of the year

RGGI has therefore moved far beyond the relatively small carbon charge of its early years. It is already adding a substantial cost to New England electricity before the much tighter allowance framework begins in 2027.

Beginning in 2027, Allowance Supply Falls Sharply

A 73% reduction in the RGGI-10 base cap between 2027 and 2033 will create a steep deficit in allowance supply relative to emissions unless covered emissions fall at a comparable pace.

Today’s high carbon costs precede an even sharper contraction in allowance supply set to take effect in 2027.

For the ten states covered by the new framework, the regional base cap was 81.35 million tons in 2025. Under the new schedule, it falls rapidly. Compared with 2025, the base cap falls by 46 percent in 2030, 77 percent by 2033, and 89 percent by 2037.

Figure 2

RGGI Cap Trajectory: Current Policy vs. 2027 Framework

RGGI-10, excludes Virginia · base cap, million tons · 2024 to 2037
Compared with 2025, the base cap falls by 46 percent in 2030, 77 percent by 2033 and 89 percent by 2037. Between 2027 and 2033 it falls from 69.8 million tons to 18.6 million tons.
Source: RGGI 2026d

The steepest reductions occur between 2027 and 2033. In just six years, the base cap falls from 69.8 million tons to 18.6 million tons.[7]

Each allowance covers one ton of CO₂ emissions. As the cap falls, the number of allowances available under the program falls with it. By 2033, roughly 51 million fewer new allowances are available each year under the base program than in 2027.

That is a dramatic reduction in the number of tons of CO₂ covered generators are permitted to emit.

Every covered ton of CO₂ still has to be matched by an allowance. If emissions do not fall along with the supply of allowances, generators face increasing competition for a shrinking supply. That puts upward pressure on allowance prices and creates strong economic incentives to run fossil plants less.

The new rules also make it harder for another large surplus to develop. Beginning in 2027, the minimum auction price rises to $9.00 per ton and increases 7 percent each year. Standard allowances offered at auction but left unsold will be removed from circulation rather than returned to the market later (RGGI 2026d).

The direction of the program is clear: RGGI is deliberately making new allowances much scarcer. If emissions do not fall with that supply, the cost of emitting CO₂ will rise and fossil generation will come under increasing pressure.

The Allowance Bank Buys Time as Supply Tightens

The existing allowance bank delays the impact of tightening supply, but under the report’s stress test it is exhausted during 2032.

The private allowance bank stood at about 48 million allowances at the end of 2025. (Potomac 2026a, 8) Adjusting subsequent projections to exclude Virginia, this report estimates that roughly 49 million banked allowances will be available to RGGI-10 entering 2027 (Potomac 2026c, 9).

As noted earlier, the September 2026 auction cleared at $37.65 per ton, 69 percent higher than a year earlier, despite the remaining allowance bank and before the new cap trajectory had begun.

A stress test prepared for this report examines how long the existing allowance bank can extend compliance as the RGGI-10 cap declines. The analysis uses assumptions favorable to RGGI compliance: emissions remain near recent levels, accounts for expected reductions from offshore-wind projects already under construction, and additional allowances are assumed to be released under RGGI’s cost-containment rules (see Appendix B). Even under those assumptions, the allowance bank is exhausted in 2032. In that year, modeled emissions exceed total available allowance supply by about 22 million tons, meaning generators would not have enough allowances to cover their emissions. Full assumptions and calculations are provided in Appendix C.

The Allowance Bank

The stress test: the allowance bank is exhausted in 2032

RGGI-10 · million allowances / million tons · both CCR tiers assumed fully released and sold every year (Appendix C)
Blue bars show the bank at the end of each year; orange bars, from 2032, show the uncovered compliance shortfall (million allowances). The solid line is the maximum new allowance supply each year (base cap plus both Cost Containment Reserve tiers); the dashed line is adjusted emissions — the 89.0-million-ton baseline less expected offshore-wind reductions, 83.0 million tons a year from 2028. The bank initially grows to approximately 58.0 million allowances at the end of 2028, then declines as emissions exceed annual allowance supply and is exhausted during 2032, leaving an estimated 22-million-allowance shortfall.

The 2032 result is not a forecast. Faster emissions reductions would extend the bank; higher fossil generation would deplete it sooner. The analysis illustrates the scale of the adjustment required as allowance supply declines.

RGGI can release additional allowances when prices rise, and the states can revise the program in future reviews. The stress test already assumes those additional allowances are available. Even so, the underlying constraint remains: if covered emissions exceed the total supply available for compliance, emissions must fall or the program rules must change.

If Gas Must Run Less, What Will Replace It?

RGGI increasingly depends on lower demand or replacement resources, yet the region’s development pipeline shows little new dependable capacity to replace natural gas.

If New England is going to reduce natural-gas generation enough to keep pace with the falling RGGI cap, other resources must be available to serve that load or electricity demand must fall.

RGGI is deliberately designed to drive that shift by raising the cost of fossil generation. Higher allowance prices make natural-gas generation more expensive, encouraging lower-emitting generation and reductions in electricity demand.

RGGI’s modeling assumed substantial additions of lower-emitting resources over time, supported by state clean-energy policies and federal incentives (RGGI 2026d).[8] Some of those federal assumptions have since changed. Federal law enacted in 2025 shortened the availability of the Section 45Y clean-electricity production credit and Section 48E clean-electricity investment credit for many future wind and solar projects (IRS 2025). Existing projects may still qualify, and state mandates remain, but some future projects will operate under different federal economic conditions than those assumed in the earlier modeling.

The current development pipeline is heavily weighted toward wind, solar, and battery storage. ISO New England’s 2026 state profiles show proposed development concentrated in those resources (ISO-NE 2026c). The queue is not a forecast of what ultimately will be built, but it illustrates the composition of the region’s current development pipeline.

New York shows a similar pattern. NYISO’s development pipeline is heavily weighted toward wind, solar, and storage, with comparatively little new fossil generation evident in the current queue. (NYISO 2025) PJM provides a useful comparison because its footprint includes both RGGI and non-RGGI states. Of 52 natural-gas projects reported by PJM as holding agreements or under study in March 2026, only six were located in RGGI participating states: Delaware, Maryland, and New Jersey, and only one of those had an interconnection agreement (Bennett 2026).

What Will Replace It?

Where PJM’s new natural-gas projects are being developed

Natural-gas projects reported by PJM as holding agreements or under study, March 2026 · each circle is one project
52 natural-gas projects in PJM6 in RGGI states (Delaware, Maryland and New Jersey)1 with an interconnection agreement
Of 52 natural-gas projects, only six were located in RGGI participating states (Delaware, Maryland and New Jersey), and only one of those had an interconnection agreement.

These comparisons do not establish that RGGI alone determines where generating plants are built. But they show that little new dispatchable thermal capacity is being developed within the RGGI jurisdictions examined here.

For New England, the consequences are not limited to higher allowance prices. Unlike PJM, the region has no non-RGGI territory within its wholesale market where new thermal generation can be built and still serve regional load. Imports can help, but they are limited by transmission capacity and conditions in neighboring regions (ISO-NE 2026d). If replacement resources do not arrive fast enough, the tightening RGGI cap could raise electricity costs and make it less economical to operate or keep the dispatchable generation the region still depends on. The reliability implications will depend on how those gaps are filled.

Can Energy Efficiency Fill the Gap?

Lowering demand can no longer be assumed to be the least-cost option, given that the cost of acquiring annual energy-efficiency savings nearly tripled across New England between 2018 and 2022.

RGGI does not assume that every megawatt-hour displaced from fossil generation must be replaced by another generator. Lower electricity demand can also reduce the amount of generation required.

However, data reported by state energy-efficiency program administrators and compiled by ISO New England show that acquiring additional efficiency savings has become substantially more expensive. Across New England, reported program spending remained near $1 billion annually between 2018 and 2022 while annual savings declined. The reported program cost per annual MWh saved rose from $362 to $979 across New England and from $365 to $1,404 in Massachusetts, nearly tripling across the region and nearly quadrupling in Massachusetts over that period.

Even on a lifetime basis, reported costs increased from $37 to $99/MWh across New England and from $39 to $142/MWh in Massachusetts (Costa 2024).

Can Energy Efficiency Fill the Gap?

The cost of acquiring efficiency savings nearly tripled

Reported program cost per annual MWh saved, 2018–2022 · lifetime cost per MWh (Appendix D)
Reported program cost per annual MWh saved
Lifetime basis
New England · lifetime cost per MWh saved
$37→$992018 → 2022
Massachusetts · lifetime cost per MWh saved
$39→$1422018 → 2022
The reported program cost per annual MWh saved rose from $362 to $979 across New England and from $365 to $1,404 in Massachusetts between 2018 and 2022. On a lifetime basis, reported costs increased from $37 to $99/MWh across New England and from $39 to $142/MWh in Massachusetts.

Further efficiency savings are still possible, but the cost of obtaining them has been rising. Because RGGI funds only a portion of these programs, these data are not a measure of RGGI’s effectiveness. They are relevant, however, because the cap is tightening at a time when additional reductions in electricity demand are becoming more expensive to achieve.

The underlying data are provided in Appendix D.

Auction Revenue Is Only Part of What Ratepayers Pay

For 2026, this report estimates that RGGI could add $1.49 billion to New England wholesale electricity costs while the six states collect about $785 million in auction proceeds.

RGGI states frequently point to auction proceeds as one of the program’s major benefits. But those revenues are not free money.

States auction CO₂ allowances and collect the proceeds. Covered generators pay for those allowances and recover the cost through wholesale electricity prices. The money received by the states therefore ultimately comes from electricity customers.

As estimated in Section 4, RGGI could add about $1.49 billion to New England wholesale electricity costs in 2026. Under the same allowance-price assumption, the six New England states would collect about $785 million in auction proceeds. The auction revenue would therefore represent only about half of the estimated wholesale-market cost borne by ratepayers.

Auction Revenue

Auction proceeds are about half of what ratepayers pay

New England, 2026 estimate · $ millions
RGGI could add about $1.49 billion to New England wholesale electricity costs in 2026; under the same allowance-price assumption, the six New England states would collect about $785 million in auction proceeds.

States seek to create benefits by putting the auction proceeds back into the economy. Some funds are returned directly through bill assistance; others support energy efficiency, renewable energy, electrification, greenhouse-gas abatement, and other programs.

But state spending is not itself an economic benefit. It is a reallocation of money that ratepayers first paid through higher electricity costs. The spending may produce benefits, but those benefits depend on what the programs actually accomplish.

Prior assessments have attributed substantial consumer and economic benefits to the use of RGGI proceeds. Analysis Group estimated $1.6 billion in net economic benefits during RGGI’s first compliance period and $1.3 billion during the second (Hibbard 2011; Hibbard 2015). Those figures are modeled estimates. Analysis Group’s studies account for the increase in wholesale electricity prices caused by allowance costs, but the benefit side depends in significant part on the savings and other effects attributed to investments made with RGGI proceeds.

That attribution is not always straightforward because RGGI is often only one funding source within much larger state programs. In Massachusetts, for example, RGGI supplied only 11 percent of electric energy-efficiency funding in 2010–2012 and 5 percent in 2013–2015 (MEEAC 2013, 10; MEEAC 2015, 14). In both periods, the large majority of funding came from charges collected directly from electricity customers on their monthly bills. Massachusetts later developed its 2022–2024 statewide electric energy-efficiency program with no RGGI proceeds included in the initial budget, relying primarily on direct charges to electricity customers (MEEAC 2022, 12).

Auction Revenue

RGGI’s share of Massachusetts electric energy-efficiency funding

Share of program funding supplied by RGGI proceeds
RGGI supplied 11 percent of electric energy-efficiency funding in 2010–2012 and 5 percent in 2013–2015; the 2022–2024 statewide program was developed with no RGGI proceeds in its initial budget. In each period the large majority of funding came from charges collected directly from electricity customers.

This distinction matters. Energy savings produced by the broader efficiency program cannot automatically be treated as benefits of RGGI. The relevant benefit is the incremental result of the RGGI funding itself: additional savings that would not otherwise have occurred, direct assistance returned to customers, or customer charges avoided because RGGI proceeds replaced another source of funding.

Massachusetts also illustrates a second distinction. The state has directed RGGI proceeds to residential heating electrification and broader greenhouse-gas abatement programs (MEEAC 2022, 12). Those expenditures may advance state climate objectives, but they do not necessarily offset the higher electricity prices caused by RGGI.

Those earlier benefit studies also examined periods when allowance prices were only a fraction of today’s level. Their findings therefore do not establish that the same balance of costs and benefits persists as the carbon price rises sharply.

Claimed offsets should be credited only where benefits can reasonably be attributed to RGGI funding and shown to produce measurable value for electricity customers. The economic case for RGGI must account for both sides of the transaction: the full electricity-market cost imposed by the carbon price and what RGGI actually delivers through the use of auction proceeds.

Conclusion: The Stark Reality of RGGI After 2027

After 2027, rapidly tightening allowance supply will increasingly put carbon targets, electricity affordability, and grid reliability in conflict.

RGGI is entering a fundamentally different era from the one that produced its historical record. The program’s early years were characterized by inexpensive allowances and large emissions reductions as natural gas displaced coal and oil. That fuel-switching opportunity is now largely exhausted, leaving New England’s covered fossil generation almost entirely dependent on natural gas.

Beginning in 2027, the allowance constraint becomes far more consequential. By 2037, the base cap falls nearly 90 percent from 2025 levels. Under the assumptions tested in this report, the existing allowance bank delays the impact only temporarily: it is exhausted in 2032, when modeled emissions still exceed the total allowance supply available for compliance by 22 million tons.

The cost is already showing up in the electricity market. Because fossil generators set New England’s wholesale price for most load, RGGI allowance costs can raise the clearing price paid across the market. Under the 2026 assumptions examined here, RGGI will add an estimated $1.49 billion to New England wholesale electricity costs. About $785 million of that amount represents the full cost of allowances purchased by generators at auctions conducted by the six New England states. In other words, what RGGI states call auction revenue is actually a compliance cost that generators pass on to ratepayers through higher electricity prices. The remainder reflects the broader effect of allowance costs on market-clearing prices.

Policymakers therefore cannot assume that the experience of the program’s early years will repeat itself. Unless emissions fall rapidly, the post-2027 framework will increasingly force a tradeoff among tighter carbon limits, electricity affordability, and the need to maintain enough dependable generation to keep the system reliable.

Appendices

Appendix A — How RGGI Works[9]

The Regional Greenhouse Gas Initiative (RGGI) is a regional CO₂ cap-and-trade program for large fossil-fueled electric generating units. Each participating state operates its own CO₂ budget trading program under state law or regulation, while the states link their programs through a common allowance market. Covered sources generally include fossil-fueled generating units of 25 MW or greater, subject to state-specific rules.

The Cap and Allowances

RGGI establishes an annual regional CO₂ emissions cap. Each participating state has an allowance budget, and the sum of those state budgets forms the regional cap.

One CO₂ allowance authorizes the emission of one short ton of carbon dioxide. Allowances issued by one participating state may generally be used for compliance by a covered generator in another participating state.

Most allowances are sold through coordinated regional auctions, although states may reserve limited quantities for state-specific programs or set-asides. Allowances can also be bought and sold in the secondary market.

Compliance and Banking

RGGI operates through three-year compliance periods. At the end of each period, a covered generator must surrender enough allowances to cover its CO₂ emissions. Since 2015, generators have also been required to hold allowances covering 50 percent of their emissions during each of the first two years of the three-year period.

Unused allowances generally do not expire. Market participants may save, or bank, them for use in later compliance periods. As a result, the number of allowances available for compliance in a particular year can exceed the number of new allowances issued under that year’s cap.

How the Carbon Price Is Created

RGGI is designed to reduce the supply of allowances over time. If generators continue to need more allowances than the states make available, competition for the remaining supply puts upward pressure on allowance prices.

As the cap declines, the states issue fewer new allowances. If emissions do not fall at the same pace, generators must compete for a smaller supply, putting upward pressure on allowance prices and increasing the cost of fossil generation.

Allowance costs become part of the operating cost of covered fossil generation. The strength of that price signal therefore depends not simply on the published cap, but on the relationship among current emissions, newly issued allowances, previously banked allowances, and any additional allowances made available under the program’s reserve mechanisms.

Auction Revenue

Because most allowances are auctioned rather than distributed free of charge, participating states receive the auction proceeds. States determine how those revenues are used, including for energy efficiency, renewable-energy programs, bill assistance, and other purposes.

Auction revenue and allowance cost are two sides of the same transaction: states receive revenue from selling allowances that covered generators ultimately need for compliance. The electricity-market consequences of that cost and the value produced by the subsequent use of auction proceeds are discussed in the main report.

Appendix B — How RGGI Changed: From Surplus Allowances to a Much Tighter Market

RGGI was designed to be reviewed periodically rather than operate indefinitely under its original rules. Since the program began in 2009, the participating states have completed three major Program Reviews. Each has changed the future supply of allowances and the mechanisms used to manage allowance prices.

The Original Program: 2009–2013

RGGI began in 2009 with a regional cap of approximately 188 million tons per year for the original ten participating states. When New Jersey withdrew after 2011, its allowance budget was removed, reducing the regional cap to approximately 165 million tons in 2012 and 2013. That reduction reflected the change in membership rather than a tightening of the emissions limit.

Actual emissions were substantially below the original cap. Because unused allowances could be banked, a large surplus accumulated. At the end of 2013, 319 million allowances were in circulation compared with 179 million tons of cumulative compliance obligations, leaving approximately 140 million surplus allowances.

The program’s first major redesign was aimed largely at correcting that oversupply.

First Program Review — Correcting the Original Surplus

Completed in 2013, the First Program Review reduced the 2014 regional cap from approximately 165 million tons to 91 million tons, a reduction of about 45 percent, and scheduled further 2.5 percent annual reductions through 2020.

But lowering the future cap did not eliminate the allowances already held by market participants. RGGI therefore made additional downward adjustments to the number of new allowances distributed between 2014 and 2020 so the existing bank could gradually be absorbed. Those adjustments totaled approximately 139.5 million allowances over the period.

The First Review also created the Cost Containment Reserve (CCR). The CCR made additional allowances available if auction prices reached specified trigger levels, providing additional supply if allowance prices rose more rapidly than anticipated.

The result was a two-part strategy: reduce the supply of new allowances to work down the accumulated surplus while maintaining a reserve that could release additional allowances if prices became sufficiently high.

Second Program Review — Further Tightening and Managing the Bank

The Second Program Review was completed in December 2017. It continued the decline in the emissions cap, adopting a trajectory designed to reduce the regional cap by another 30 percent between 2020 and 2030.

The allowance bank remained an important issue. The updated rules therefore created a Third Adjustment for Banked Allowances, reducing allowance budgets during 2021–2025 to account for surplus pre-2021 allowances still held by market participants. The resulting adjustment totaled approximately 86.8 million allowances over those five years. Market participants remained free to retain and use their banked allowances.

The Second Review also added the Emissions Containment Reserve (ECR). Unlike the CCR, which increased supply when prices were high, the ECR withheld allowances when prices fell below a specified level. RGGI therefore had mechanisms operating in both directions: additional supply could enter the market when prices became high, while supply could be withheld when prices became unusually low.

Third Program Review — A Much Steeper Post-2027 Framework

The third review was completed in July 2025. For the ten states examined in this report, the changes substantially accelerate the reduction in the base cap beginning in 2027. Virginia is not included in the cap and reserve figures discussed here.

The RGGI-10 base cap falls to approximately 69.8 million tons in 2027 and then declines rapidly through 2033. From 2034 through 2037 it continues falling, reaching approximately 9.0 million tons in 2037. Existing banked allowances are not canceled and remain available for compliance.

The 2025 changes also:

  • raise the minimum auction price to $9.00 in 2027, increasing 7 percent annually;
  • eliminate the ECR and replace it with the higher minimum auction price;
  • expand the cost-containment system to two reserve tiers;
  • provide approximately 11.75 million allowances in each reserve tier annually beginning in 2027;
  • remove standard allowances from circulation if they are offered at auction but remain unsold; and
  • eliminate the issuance of new offset allowances beginning in 2027.

The states also committed to begin another Program Review no later than 2028, including consideration of the cap trajectory, reliability, affordability, electricity-load growth, and clean-energy deployment.

The Overall Direction

The three reviews show a clear evolution in the program.

The First Review responded to a cap that had become far too loose and to a large accumulated allowance surplus.

The Second Review continued reducing allowance supply and introduced additional mechanisms to manage both the allowance bank and low market prices.

The Third Review goes considerably further. Beginning in 2027, the base cap falls rapidly, the auction floor rises substantially, unsold allowances are removed rather than returned to future auctions, and additional allowances are made available only through defined cost-containment mechanisms.

The result is a program that is structurally different from its early years. RGGI began with emissions well below the cap and a growing surplus of inexpensive allowances. The post-2027 framework is designed around a much smaller and declining supply of new allowances, while previously banked allowances provide only a temporary source of additional compliance flexibility.

Appendix C — RGGI-10 Allowance Bank Stress Test

This stress test examines how long the existing bank of surplus RGGI allowances can bridge the gap between covered emissions and the much lower caps beginning in 2027. The analysis covers the ten states included in RGGI’s 2025 Program Review and excludes Virginia throughout. It is not a forecast; it tests what happens if RGGI-10 emissions remain near recent levels while allowance supply declines.

Starting allowance bank. The RGGI Market Monitor reported a private surplus bank of 48 million allowances at the end of 2025. Using its Q2 2026 supply-and-demand projections and removing the effect of Virginia’s return to RGGI produces an estimated RGGI-10 bank of approximately 49.4 million allowances entering 2027.

Emissions and offshore wind. Covered RGGI-10 emissions were approximately 85 million tons in 2025. First-half 2026 emissions were about 4 million tons higher than during the same period of 2025, supporting an underlying baseline of approximately 89 million tons per year. The model holds that baseline constant before subtracting estimated reductions from Vineyard Wind 1, Revolution Wind, Empire Wind 1, and Sunrise Wind. It assumes a 45 percent capacity factor and treats offshore-wind generation as displacing natural-gas generation.[10]

Allowance supply. The model applies the RGGI-10 cap adopted in the 2025 Program Review, beginning at 69.8 million allowances in 2027 and declining to approximately 9.0 million in 2037. To make the test favorable to compliance, it assumes that both Cost Containment Reserve tiers are fully released and sold every year, adding approximately 23.5 million allowances annually. Existing banked allowances remain available for compliance.

Under these assumptions, the allowance bank initially grows, reaching approximately 58.0 million allowances at the end of 2028, and then declines as emissions exceed annual allowance supply. The bank is exhausted during 2032, leaving an estimated 22-million-allowance compliance shortfall even after both CCR tiers are assumed to be fully available.

Sources: Potomac 2026a; Potomac 2026c; RGGI 2026d; BOEM 2026; Author assumptions and calculations.

Appendix C — RGGI-10 Allowance Bank Stress Test

Virginia is excluded. One allowance covers one short ton of CO₂. The model holds the underlying RGGI-10 emissions baseline at 89.0 million tons, subtracts expected offshore-wind reductions, and assumes both CCR tiers are fully available and sold each year.

2026 RGGI-10 bank bridgeValue (million)UnitsExplanation
Private surplus bank — Dec. 31, 202548.0allowancesReported private surplus at year-end 2025
Surplus allowances — June 30, 202655.0allowancesReported Q2 2026 surplus; still RGGI-10
Projected Compliance Period surplus — including Virginia45.0allowancesMarket Monitor projection after 2026 compliance
Add back Virginia net H2 draw4.4allowancesRestores Virginia’s assumed draw on banked allowances to maintain the RGGI-10 analysis.
RGGI-10 carried-in bank entering 202749.4allowancesRGGI-10 starting bank used in the stress test
Key result — both CCR tiers
Starting bank entering 202749.4million allowances
Bank after 202756.5million allowances
Bank after 202858.0million allowances
Bank entering 203210.6million allowances
First compliance shortfall2032
2032 uncovered shortfall22.0million allowances
Offshore-wind projects includedRegionCapacity MWFirst full model yearCapacity factorAvoided CO₂ / year (million tons)
Vineyard Wind 1ISO-NE / MA806202745%1.480
Revolution WindISO-NE / RI-CT704202745%1.292
Empire Wind 1NYISO / NY810202845%1.487
Sunrise WindNYISO / NY924202845%1.696

Model logic: If current-year allowance supply exceeds adjusted emissions, the excess is added to the bank. If emissions exceed current-year supply, the bank is drawn down. Once the bank is exhausted, any remaining gap is shown explicitly as an uncovered compliance shortfall.

YearBase cap (million)Tier 1 CCR (million)Tier 2 CCR (million)Maximum new allowance supply (million)Baseline emissions (million tons)OSW avoided CO₂ (million tons)Adjusted emissions (million tons)Beginning bank (million)Current-year surplus / (deficit) (million)Bank used (million)Ending bank (million)Uncovered compliance shortfall (million)Compliance status
202769.811.7511.7593.389.02.886.249.47.10.056.50.0Covered
202861.111.7511.7584.689.06.083.056.51.50.058.00.0Covered
202952.411.7511.7575.889.06.083.058.0-7.27.250.80.0Covered
203043.611.7511.7567.189.06.083.050.8-15.915.934.90.0Covered
203135.311.7511.7558.889.06.083.034.9-24.324.310.60.0Covered
203226.911.7511.7550.489.06.083.010.6-32.610.60.022.0SHORTFALL
203318.611.7511.7542.189.06.083.00.0-41.00.00.041.0SHORTFALL
203416.211.7511.7539.789.06.083.00.0-43.40.00.043.4SHORTFALL
203513.811.7511.7537.389.06.083.00.0-45.80.00.045.8SHORTFALL
203611.411.7511.7534.989.06.083.00.0-48.10.00.048.1SHORTFALL
20379.011.7511.7532.589.06.083.00.0-50.50.00.050.5SHORTFALL

Appendix D: Energy-Efficiency Data

Appendix D summarizes energy-efficiency program data reported by state program administrators and compiled by ISO New England. The tables show reported program spending, achieved annual and lifetime energy savings, and the resulting cost per MWh saved for New England as a whole and for Massachusetts. These figures are used in Section 8 to illustrate how the reported cost of acquiring additional energy-efficiency savings changed between 2018 and 2022.

Appendix D — energy-efficiency program data, New England and Massachusetts
PeriodBudget ($1000's)Total Costs ($1000's)Achieved Annual Energy (MWh)Dollars per MWhAchieved Summer Peak (MW)Dollars per MW% Energy Achieved% Budget Spent% Peak AchievedPeak to Energy Ratio Achieved (MW/GWh)Achieved Lifetime Energy (MWh)Lifetime Dollars Per MWh
New England
2018$907,857$890,1982,458,078$362359$2,476,671125%98%133%0.1524,222,183$37
2019$989,613$976,8961,957,564$499295$3,316,350110%99%113%0.1518,641,730$52
2020$992,536$945,4811,858,030$509290$3,265,56797%95%109%0.1621,224,453$45
2021$1,020,620$1,038,3671,571,836$661230$4,521,288105%102%112%0.1515,597,232$67
2022$1,013,291$915,969935,419$979129$7,107,353105%90%98%0.149,221,128$99
Avg 2019-2021$1,000,923$986,9141,795,810$556271$3,701,068104%99%111%0.1518,487,805$55
Avg 2020-2022$1,008,816$966,6051,455,095$716216$4,964,736102%96%106%0.1515,347,605$70
Massachusetts
2018$582,618$553,4641,517,809$365225$2,463,288110%95%117%0.1514,225,585$39
2019$558,589$573,9401,093,958$525168$3,410,134104%103%109%0.159,784,529$59
2020$525,384$541,7971,098,882$493182$2,973,60491%103%111%0.1713,428,376$40
2021$570,030$591,980879,958$673129$4,579,97496%104%105%0.158,428,017$70
2022$543,231$502,715357,978$1,40447$10,649,51986%93%79%0.133,530,850$142
Avg 2019-2021$551,335$569,2391,024,266$563160$3,654,57197%103%108%0.1610,546,974$56
Avg 2020-2022$546,215$545,497778,939$857120$6,067,69991%100%98%0.158,462,415$84
Source: (Costa 2024)
Download the Full Study (PDF)

L. Linowes · Published: October 2026

Notes
References
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