Category: Regional Greenhouse Gas Initiative

Governor Hochul has said that affordability comes first, however this post shows that her Regional Greenhouse Gas Initiative (RGGI) record says otherwise. I recently wrote about the implications of the New York approval of RGGI amendments which finalized New York’s alignment with the RGGI Third Program Review Model Rule on August 5, 2026. That post focused on the flaws in the “nearly 6-to-1” ratepayer benefit cost savings claim. This post makes a related but separate point: whatever the merits of the emissions math, the price record of the RGGI program itself is an inconvenient fact for a Governor who has made affordability her signature message. Because of the importance of consumer costs, I have updated and fully documented my consumer cost estimates.

I have been involved in the RGGI program process since its inception and have been writing about problems with the RGGI program here. I have worked on every cap-and-trade program affecting electric generating facilities in New York including RGGI, the Acid Rain Program, and several Nitrogen Oxide programs, since the inception of those programs. The opinions expressed in this post do not reflect the position of any of my previous employers or any other organization I have been associated with. These comments are mine alone. I acknowledge the use of Perplexity AI to generate material included in this document.

Background information about RGGI is available in the previous post and I have prepared a technical support document that explains the calculation methodology and provides cost background information.

The affordability claim meets reality

Governor Hochul has repeatedly told New Yorkers that affordability is her top priority. Her 2026 agenda and the May 2026 relief package were both framed explicitly as responses to high utility and gasoline costs. That framing invites a simple test: have the energy policies her Administration has advanced and defended made electricity more or less expensive?

On the RGGI allowance price alone, the answer is not close. When Hochul took office in late August 2021, the most recent completed auction — Auction 52 on June 2, 2021 — had cleared at $7.60 per ton. The first auction after she became Governor, Auction 53 in September 2021, cleared at $9.30. The most recent completed auction as of this writing, Auction 72 on June 3, 2026, cleared at $35.00 per allowance, selling all 18,349,699 allowances offered for total regional proceeds of about $642.2 million.  New York proceeds were $194.7 million on the sale of 5,563,451 allowances. At the time this was written, the secondary market for RGGI allowances is trading above $35.00 per allowance.

Measured from the first full auction of her tenure, that is an increase of $25.70 per ton, or 276% over a five-year period. The RGGI carbon price has multiplied nearly three times over on her watch, and it did so with the active participation of the state agencies she oversees — Department of Environmental Conservation (DEC), New York State Energy Research & Development Authority (NYSERDA), and the Department of Public Service (DPS), all of which take part in RGGI program design, auction administration, and the decisions that determine how aggressively the RGGI allowance cap is tightened.  There is no doubt that the recent price rise is related at least in part to the recently approved DEC amendments that mandate an arbitrary auction cap reduction consistent with state laws but are inconsistent with emission reductions that can be expected from RGGI auction revenue investments.

RGGI consumer costs

DEC and NYSERDA’s press release describing the final amendments claims RGGI investments have generated “nearly $12 billion in net ratepayer savings” against roughly $2 billion invested.  This benefit cost ratio only considers ratepayer costs of RGGI allowance auction investments. The Technical Support Document describes the source of those values, and it clearly only refers to auction revenues.

I have made this point in prior posts and it bears repeating because the Administration’s messaging has not acknowledged that there is a market clearing price effect. RGGI requires fossil-fueled generators to hold an allowance for every ton of CO2 they emit. That allowance price becomes a variable operating cost for the generator and part of their bid to market. In New York’s marginal-price wholesale electricity market, when an emitting generator sets the clearing price for an interval, its allowance cost is part of the bid and can raise the total energy price paid to every accepted resource in that interval — not merely reimburse the emitting unit for the allowances it bought. Non-emitting and even imported resources can collect the higher price despite bearing little or none of the underlying RGGI cost themselves.

Table 1 lists the total annual estimated RGGI costs. For consistency with the NYSERDA and DEC analyses I estimated annual RGGI costs through 2024, but I estimated a cost for 2026 by scaling the average auction price of allowances in 2024 by the Auction 72 $35 allowance cost. The Administration messaging only considers the cost of allowances sold in auction – the total direct RGGI allowance cost row. As described in the Technical Support Document I calculated estimates that include the variable operating costs in the wholesale electric market. When those costs are included the price impact of RGGI doubles and costs are rising steeply (Figure 1). We have complete numbers for 2024. Between 2021 when Hochul took office the annual RGGI costs have increased $233 million or 37%. Holding everything else constant but pro-rating the total by the Auction 72 $35 allowance cost the 2026 annual cost increases $1,317 million or more than 2.7 times higher.

Table 1:  Total Annual RGGI Costs($ millions)

Figure 1: Total Annual RGGI Cost Trend ($ millions)

I also estimated the annual cost to residential customers. A typical New York residential electric customer uses approximately 570 kWh per month (about 6.9 MWh annually). Table 2 lists the annual estimated RGGI costs for residential consumers. If the only costs considered are the direct cost of allowances the estimated costs are half as much as when the wholesale electric market costs are included. For example, in 2024 allowance costs were $24 a year but the total cost was $70 for the estimated mix of unit types. Between 2021 when Hochul took office and 2024 the residential annual RGGI costs have more than doubled. Holding everything else constant but pro-rating the total by the Auction 72 $35 allowance cost the annual cost increases $121 a year or more than 2.5 times higher. This represents over 7% of residential electric costs. This continues a trend (Figure 2) that I expect to continue to grow.

Table 2: Annual Residential Cost of RGGI ($)

Figure 2: Annual Residential Cost of RGGI ($) Trend

These cost estimates show the RGGI price increase does not stay contained to a line item on the emitting generator’s books. It works its way into wholesale prices, and from there into what load-serving entities — and retail customers — pay for the electric commodity they consume.

None of that disappears because the state collects auction revenue and calls the proceeds an “investment.” Consumers pay the higher embedded cost first, through what they are charged for each kilowatt of electricity. Only a portion of the allowance proceeds comes back later, to selected programs, or selected bill-credit recipients. A household that does not qualify for a program, cannot front the money for an efficiency upgrade, or simply does not live in a service territory where a credit is applied still pays the RGGI-driven cost with nothing returned.

The “6-to-1 return” does not rebut this

DEC and NYSERDA’s press release describing the final amendments claims RGGI investments have generated “nearly $12 billion in net ratepayer savings” against roughly $2 billion invested — a “nearly 6-to-1” return that supposedly proves affordability is being served. The Technical Support Document explains the source of those values. I evaluated that NYSERDA report and the qualifications matter: the $12.334 billion figure is not verified net ratepayer savings. NYSERDA itself calls it “Energy Bill Savings to Participating Customers,” a modeled, expected-lifetime estimate that includes savings from projects still in the pipeline, has generally not been adjusted through evaluation, measurement, and verification, and is compared against historical expenditures rather than against the full cost of the program to all ratepayers, including the market-clearing-price effect described above.

There is also a time-value-of-money problem that a colleague who prefers to remain anonymous framed better than I have seen it framed elsewhere: RGGI takes a dollar from the consumer now and, through delayed, partially administered programs, returns a fraction of that dollar’s value later — with the people who fall short of program eligibility or who face the ordinary friction of applying for assistance left to absorb the difference in full, indefinitely. Discount that delayed, diminished return to present value and the headline “6-to-1” ratio looks a great deal less generous than it is advertised to be. And a meaningful share of the RGGI-driven cost embedded in electricity bills — the wholesale-market cost adder described above — is never captured by any investment program at all. It simply flows through to consumers as a cost, full stop, with no delayed benefit on the other end. The exemplifies a true affordability issue for most energy consumers who are not eligible for the programs or credits created for a small percentage of energy customers.

My numbers show that when the energy costs are included the 6 to 1 benefit ratio is unsupported.

The contradiction Hochul has not had to answer

The same Administration that says it wants to protect New Yorkers from high energy costs signed off on a Third Program Review that lowers the regional RGGI cap sharply through 2037, with steeper annual reductions from 2027 through 2033. A tighter cap means a smaller supply of allowances at a time when there is growing electricity demand — precisely the dynamic that has already pushed the allowance price up 40 percent in a single quarter this year. RGGI’s own market monitor has acknowledged the resulting affordability and scarcity concerns are real, not hypothetical.

An affordability agenda should not rest on imposing a rising energy charge today while pointing to a modeled, largely unverified, multi-year savings projection as the offset. Governor Hochul cannot credibly claim affordability is her governing priority while her Administration has overseen — and just locked in further tightening of — a program whose price has risen nearly fourfold on her watch.

Discussion

In my opinion, the cost of RGGI allowances is another buried cost of the clean energy transition that very few people know about. In 2024 the impact of RGGI allowances accounted for $70 per year or 4.2% of a typical residential electric bill. Projecting the latest sharp rise in allowances raises the costs to $121 per year or 7.2% of a typical residential electric bill. At a time when there is an energy affordability crisis it is fair to ask whether New Yorkers are willing to pay for this program?

The Administration messaging about the “6-to-1” benefit to cost claim is unsupportable and self-promoting at best. If they want to prove a positive benefit/cost ratio then they should request that NYISO provide the wholesale market impact calculated with the hourly data that only they have. For the benefits they should only consider savings actually returned to consumers, broken out from savings that are committed but not yet delivering measured savings. They should also only include verified, evaluated-and-measured bill savings — not modeled lifetime projections — compared against the total full cost.

Until that accounting exists, “nearly 6-to-1” is a talking point, not a demonstrated result. New Yorkers who have watched the RGGI price climb from $9.30 to $35.00 per ton since Hochul took office are entitled to something better than the assurance that the difference will average out favorably over a very long period of time while losing the time value of the dollar spent today for energy consumed.

Conclusion

The combination of New York’s wholesale electric-market structure and the recent sharp increase in RGGI allowance prices means that the program is no longer a marginal cost with little consequence for consumers. It is now a meaningful contributor to residential electric bills.

My review of NYSERDA’s reported results indicates that RGGI-funded investments have produced relatively little measured progress toward the program’s core purpose: reducing emissions from the electric generating units subject to the RGGI cap. Using the State’s reported cumulative annualized program benefits, I estimate a cost of approximately $583 per ton of CO2 reduced. Moreover, the RGGI investment-related savings represent only about 4.7% of the electric-sector emissions reductions observed since the program began. Most of the historic reduction appears instead to be associated with fuel switching from coal and oil to lower-emitting natural gas—a transition that offers little opportunity for additional reductions going forward.

That mismatch matters because RGGI is fundamentally a power-sector compliance program, not simply a source of funding for otherwise worthwhile State initiatives. If allowance costs are adding more than 7% to residential electric bills, then New York should be able to demonstrate that the revenues are being directed first to cost-effective measures that reduce emissions from RGGI-covered sources, lower customer bills, and help maintain reliable compliance with an increasingly stringent cap.

Governor Hochul has emphasized energy affordability. That commitment should require an independent, transparent review of whether New York’s continued participation in RGGI—as presently designed and implemented—delivers emissions reductions and consumer benefits proportionate to its cost. If it does not, then withdrawal from RGGI, or at minimum a fundamental restructuring of the program and its revenue-allocation rules, should be considered a necessary test of rational energy policy.

On August 5, 2026, the New York State Department of Environmental Conservation (DEC) approved amendments to Part 242 CO2 Budget Trading Program.  This makes New York regulations consistent with the RGGI Third Program Review Model Rule but I believe that it was short-sighted because significant changes that occurred since the rule was proposed were ignored.  Furthermore, DEC has yet again failed to address the impacts of the rule on New Yorkers which are described in this article.

I have been involved in the RGGI program process since its inception and have been writing about problems with the RGGI program here. I have worked on every cap-and-trade program affecting electric generating facilities in New York including RGGI, the Acid Rain Program, and several Nitrogen Oxide programs, since the inception of those programs. The opinions expressed in this post do not reflect the position of any of my previous employers or any other organization I have been associated with, these comments are mine alone. I acknowledge the use of Perplexity AI to research and organize the material summarized in this article.

Background

RGGI is a market-based program to reduce greenhouse gas emissions (GHG) (Factsheet). It has been a cooperative effort among the states of Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New York, Rhode Island, and Vermont to cap and reduce CO2 emissions from the power sector since 2008. New Jersey was in at the beginning, dropped out for years, and re-joined in 2020. Virginia joined in 2021, withdrew in 2024, and rejoined effective July 1, 2026, and Pennsylvania considered joining but has since decided not to join.

RGGI includes a provision for regular reviews. The Third Program Review was completed in July 2025. It strengthened the regional CO₂ emissions cap through 2037, with steeper reductions from 2027 to 2033 and a lower rate thereafter. New York was required to align their regulations with the updated Model Rule by January 1, 2027, and finalized their rules to meet that requirement as mentioned earlier.

New York Benefits of RGGI Claim

RGGI is essentially a cap-and-invest program.  On a quarterly basis the RGGI states auction allowances or permits to emit a ton of CO2.  Proponents of this strategy tout the investment of the proceeds of the auctions as the  primary benefit to consumers.  The New York State Energy Research & Development Authority (NYSERDA) designed and implemented a process to develop and annually update an Operating Plan which summarizes and describes the initiatives to be supported by RGGI auction proceeds.  I usually comment on the annual updates.  For example, this year I commented and summarized the final 2026 Operating Plan.

The press release announcing that the regulations were finalized states:

The adopted RGGI program updates will help ensure New Yorkers continue to enjoy cleaner air while creating jobs and boosting the economy. The amended regulations build upon the progress already achieved by RGGI, including reducing carbon dioxide emissions from New York’s power sector by 50% from 2005 levels and generating more than $3 billion in RGGI auction proceeds that support investments in energy efficiency, renewable energy, and electrification that ultimately provide savings to utility ratepayers

My primary concern is that RGGI is an electric sector emissions reduction program and that state policies do not appreciate that.  The press release says that the observed carbon dioxide emissions reductions in New York’s power sector of 50% from 2005 levels are part of “the progress already achieved by RGGI”.  In the first place RGGI did not start until 2009 so the observed 24% reduction in emissions between 2005 and 2008 are not due to RGGI.  I believe it is more appropriate to compare emissions to three baseline years before RGGI started (Figure 1).  This figure shows that there was an emissions peak in 2005, and I calculate that when using the 3-year baseline  New York power sector emissions are only down 33%.  Furthermore, as shown in Figure 1, the primary reason for the observed reduction is due to fuel switching from coal and oil to natural gas.  I believe that the fuel price differential for natural gas use was much greater than the added cost of RGGI allowances in the early years, so the main driver of the observed reductions was economic fuel switching.   Also note that the option for fuel switching is not available anymore.

Figure 1: New York State Emissions by Fuel Type

The revisions to DEC RGGI regulations reduce the allowances available but it is not clear where the future reductions will come from.  Therefore, I believe that programs that materially decrease electric sector emissions directly or indirectly through energy use reductions should be a priority because affected sources have no other compliance options. I argued in my comments on the Operating Plan amendment that there are programs in the amendment that do not meet these criteria.  I think it is only appropriate to fund the non-priority programs if sufficient funding has been allocated to make the emission reductions necessary to meet RGGI compliance mandates. 

Affordability

According to the DEC the financial implications of RGGI are positive.  DEC and NYSERDA’s press release announcing finalization of these amendments claims that RGGI investments in New York have generated nearly $12 billion in net ratepayer savings over the lifetime of the program’s investments, on roughly $2 billion invested to date – a “nearly 6-to-1” return. In addition, the response to Comment 9 in the DEC Assessment of Public Comments claims that RGGI reduces consumer costs:

The proposed amendments are designed to deliver affordable energy. The RGGI Program has been shown to reduce the electricity bills of New Yorkers through the investments of proceeds raised by the RGGI Program. The updates to the RGGI Program, as outlined in the RGGI bills analysis , are estimated to have no significant impact on utility bills, with a slight decrease compared to status quo even under pessimistic projections of renewable energy deployment.

This section shows that those claims are incorrect.

The claim that there is a “nearly 6-to-1” return on investments is derived from NYSERDA’s June 2026 RGGI funding-status report—but the description simplifies important qualifications.  The underlying report does not call the $12.334 billion figure “net ratepayer savings.” It calls it “Energy Bill Savings to Participating Customers.” It is a modeled, expected-lifetime estimate that includes savings attributed to projects still in the pipeline—projects under contract or with applications received but not yet operational. NYSERDA also states that the metrics are estimates and generally have not been adjusted through evaluation, measurement, and verification.

The claimed return also compares lifetime projected participant bill savings with historical funds expended, rather than comparing verified realized savings with the full cost of the RGGI portfolio. The report notes that benefits may be recorded before associated funds are financially reported and that some reported project benefits reflect joint support from other NYSERDA non-RGGI funding sources. Those caveats mean the 5.6-to-1 calculation should not be read as a verified, RGGI-only net benefit to all New York ratepayers.

The “nearly 6-to-1” calculation also compares this projected lifetime benefit stream against $2.188 billion in historical expenditures. That is not an audited return on investment or a demonstration of savings to all New York ratepayers. The report further acknowledges timing differences between benefit reporting and financial reporting, as well as projects supported jointly with other NYSERDA funding sources.

More importantly, NYSERDA’s own recent EmPower evaluation demonstrates why the headline should be treated cautiously. It found evaluated-to-estimated realization rates of only 20% for natural-gas savings and 18% for electric savings. NYSERDA attributes part of the discrepancy to a methodological shift that increased estimated savings; it also reports declining evaluated electric savings over time and identifies cases where repairs increased energy use because previously non-functioning equipment could again be used. These findings do not mean the programs provide no customer benefits, but they do mean that modeled lifetime bill savings should not be marketed as verified “net ratepayer savings.”

In addition to the failed premises of the benefits, the cost estimates are incomplete because they primarily considered just the auction allowance costs.   The June 2025 Analysis Group presentation cited to claim that RGGI has “no significant impact on utility bills”. concludes that the RGGI Third Program Review update would have only small effects on average electric bills—generally within about ±1 percent—and that reinvesting auction proceeds could further reduce bill impacts. The analysis compares the proposed RGGI program update with a “status quo” case based on the volume-weighted average allowance price from the twelve most recent auctions. It considers two clean-energy deployment cases and three proceeds-reinvestment scenarios.[

The presentation should not, however, be interpreted as an estimate of the total cost of RGGI to New York electricity customers. It is an incremental comparison between two RGGI policy cases: an updated program and a baseline that already includes RGGI allowance costs. Therefore, its small bill impacts indicate only that the model projects relatively small differences between the update and its chosen RGGI status-quo reference case.  Importantly, it does not include the 40% increase in allowance prices noted in June 2026.

Analysis Group states that ICF modeled “wholesale electricity prices and allowance proceeds,” so it would be inaccurate to claim that the study wholly ignores wholesale-price effects that I think that RGGI advocates do not acknowledge. But the brief presentation does not explain how the wholesale-market model handles the critical mechanism by which allowance prices affect consumer costs. It provides no detail on whether generator offers reflect current allowance opportunity costs, which units set marginal prices, or whether the model quantifies the resulting uplift in market-clearing prices paid to all dispatched resources.

That omission is significant in New York’s marginal-price electric market. When an emitting generator is needed to meet load, its RGGI allowance obligation is incorporated into its offer price. If that generator is marginal, the allowance-cost adder can raise the clearing price received by every accepted generator in the affected market interval—not merely reimburse the emitting generator for allowances purchased. Lower-emitting, non-emitting, and even imported resources may receive the higher clearing price despite having little or no corresponding RGGI compliance cost.

The direct cost of allowances and the wholesale market-clearing effect are therefore different things. Earlier this year I showed New York RGGI-unit allowance expenditures in 2025 at roughly $708 million using 32.0 million tons of emissions and an average $22.09 per-ton auction price. But it estimates that applying plausible marginal-unit allowance adders across statewide electricity consumption could add total annual consumer impacts of roughly $1.16 billion to $2.26 billion, depending on the assumed marginal generating-unit characteristics. Those figures are bounding estimates rather than a substitute for a full NYISO hourly production-cost and market-settlement analysis.

Discussion

There is a fundamental affordability issue raised by a colleague who wishes to remain anonymous.  He makes a point about the RGGI cost-recycling model that I have not seen made as clearly anywhere else in the record. As he put it:

This is all about time value of money. We take more dollars from the consumer – funnel to government administered programs on a time delay and realize some time delayed energy efficiency gains coupled with limited bill credits for certain customers. The end result is more consumers fall over the cliff into the limited bill credit programs.

Take one dollar today and give you 20 cents back in a year from now with everyone else subject to the poorly administered government programs with high admin fees. The original dollar gets watered down to a low percentage of value.

Conclusion

The approval of the RGGI amendments does not address the reality of emission reduction requirements and affordability.  New York CO2 emissions from the electric sector have leveled off and the only way for further reductions is to displace fossil units with zero emissions resources.  At a time when Hochul acknowledges the realities of “the COVID-19 pandemic and supply chain interruptions, inflation, the Trump administration’s hostility to wind and solar projects and ongoing trade wars” have made the Climate Act timelines “less possible” it is risky to not prioritize RGGI funding on proven emission reduction programs.  If there are insufficient allowances available it will create an artifical energy shortage preceeded by allowance price hikes.

RGGI revenues run through a state-administered efficiency or bill-credit program, and returned as a fraction of its original value months later is not the same as a dollar left in that ratepayer’s pocket today. Discount the delayed, partial, administratively-diminished return to present value and the “6-to-1” return DEC advertises looks a great deal less generous than the headline number suggests. And that is before accounting for the fact, which I have documented in prior posts, that a large share of the embedded RGGI cost in electricity bills – the cost adder created when RGGI-obligated generators bid their allowance costs into the wholesale market – never gets captured by any investment program in the first place. It just flows through to consumer bills as cost, full stop, with no delayed benefit on the other end at all.

I conclude that New York has not acknowledged that RGGI has entered a new phase where reality can no longer be ignored.

Recently I explained why I thought DEC’s New York State’s Short-Sighted Approval of Regional Greenhouse Gas Initiative (RGGI) Amendments ignored developments that undercut the analytical basis for the rule it finalized. Potomac Economics, the RGGI market monitor, has now published its Report on the Supply and Demand for RGGI CO2 Allowances: Second Quarter 2026, and it is worth a close look because it simultaneously confirms nearly everything I have documented about the RGGI allowance market this year and demonstrates exactly the blind spot that let DEC finalize Part 242 without confronting it. This post explains why I think the report is both a vindication of my reporting and, through what it deliberately does not say, more evidence that DEC’s rulemaking record was out of date when promulgated.

I have been involved in the RGGI program process since its inception and have been writing about problems with the RGGI program here. I have worked on every cap-and-trade program affecting electric generating facilities in New York including RGGI, the Acid Rain Program, and several Nitrogen Oxide programs, since the inception of those programs. The opinions expressed in this post do not reflect the position of any of my previous employers or any other organization I have been associated with, these comments are mine alone.  I acknowledge the use of Perplexity AI to prepare this document. 

Background

RGGI is a market-based program to reduce greenhouse gas emissions (GHG) (Factsheet). It has been a cooperative effort among the states of Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New York, Rhode Island, and Vermont to cap and reduce CO2 emissions from the power sector since 2008. New Jersey was in at the beginning, dropped out for years, and re-joined in 2020. Virginia joined in 2021, withdrew in 2024, and rejoined effective July 1, 2026, and Pennsylvania considered joining but has since decided not to join. The Third Program Review, completed in July 2025, strengthened the regional CO2 emissions cap through 2037, with steeper reductions from 2027 to 2033 and a lower rate thereafter.

As part of its oversight role, RGGI, Inc. retains Potomac Economics as the independent market monitor for the CO2 allowance market. On August 21, 2026, RGGI, Inc. released a special report from Potomac Economics, the Report on the Supply and Demand for RGGI CO2 Allowances, which it described as intended to help compliance entities “easily access key metrics” as they prepare to meet their obligations for the sixth control period (CP6), which closes March 1, 2027. This is not a periodic publication.   RGGI, Inc. has never produced a report like it before, unlike Potomac Economics’ quarterly Secondary Market Report, which was released the same day as a routine, recurring product. The timing is hard to read as coincidental. It arrives roughly three and a half months after RGGI, Inc. issued a public statement on May 8, 2026 acknowledging “high allowance prices and recent volatility” in the secondary market and pledging to watch future auction results before considering program adjustments. Whatever the stated purpose, this is the closest thing to an official accounting of “how many allowances are left” that RGGI has ever produced.  I think it is the document that New York State will leans on when anyone asserts that the allowance bank will probably be sufficient to cushion consumers from near-term cost impacts.

Timeline

In 2026 the price of allowances has been higher and more volatile than anytime since the start of the program. The allowance clearing price jumped from $24.99 in the March 11, 2026 auction to $35.00 in the June 3, 2026 auction, a 40% increase, with all of 2026’s Cost Containment Reserve (CCR) allowances already exhausted by the March auction. In between, on May 8, 2026, RGGI, Inc. issued a public statement acknowledging “high allowance prices and recent volatility” in the secondary market and said it would watch upcoming auction results before considering any program adjustments — the first sign RGGI itself was paying attention to the scarcity narrative building around its program. On May 15, 2026, I published my own allowance-bank exhaustion estimate, built from Potomac’s Q4 2025 secondary-market data because RGGI does not regularly provide its own accounting of the bank’s status, and projected the bank going negative around Q3 2032 to Q3 2033. Virginia formally rejoined RGGI on July 1, 2026. On August 5, 2026, DEC and NYSERDA jointly announced they had finalized the Part 242 and Part 507 amendments, effective January 1, 2027, over the objections I described in my August 19 post. On August 21, 2026, RGGI, Inc. released Potomac Economics’ special Q2 2026 Supply and Demand report alongside its routine Q2 2026 Secondary Market Report, giving us, for the first time since the rule was finalized — and for the first time ever, in the case of the Supply and Demand report — an independent, data-driven look at exactly the allowance-bank question DEC’s response to comments treated as settled.

What the Report Confirms — and Conveniently Doesn’t Say

RGGI frames the report as a routine compliance aid, but the timing tells a different story. The August 21 announcement describes the Supply and Demand report only as a special report “intended to help compliance entities easily access key metrics” as Control Period 6 winds down, with no reference anywhere to the $35 auction, the exhausted CCR, or the market commentary treating the June price jump as evidence of scarcity. But this is the first report of its kind RGGI has ever produced, and it lands eleven weeks after that record auction and three and a half months after RGGI’s own May 8 statement acknowledging “high allowance prices and recent volatility.” An organization that had never felt the need to publish a standalone supply-and-demand accounting despite my comments arguing that it was necessary suddenly produced one, unprompted, in the same window it was publicly fielding questions about whether the market was running short. RGGI is entitled to describe its own motives, but a “compliance aid” framing that omits any mention of the price spike that plausibly prompted the report in the first place is itself a data point about how this program manages its own narrative.

The report confirms what I documented in real time about the Cost Containment Reserve running dry. I reported that all of 2026’s CCR allowances were gone by the March 11 auction. The Q2 2026 report independently reaches the same conclusion, stating that “given recent allowance price levels, all remaining CCR allowances are assumed to be sold in Auction 73”.  The market monitor is now modeling full CCR exhaustion for the rest of the control period even when the Virginia CCR allotment is included in the next action. That is not a hypothetical anymore; it is the market monitor’s own baseline assumption, and it means the “release valve” DEC’s response to comments points to when it needs to reassure people about price spikes has already been used up, months before the compliance deadline crunch even arrives.

The market itself is behaving exactly as my scarcity argument predicted, even while the headline number says “surplus.” The report puts the Control Period 6 allowance surplus at 55 million tons (61% of the 2026 cap) as of the end of Q2 2026, down from 71 million tons at the end of CP5, and projects it will fall further to 45 million tons by the March 1, 2027 compliance deadline. Read in isolation, that sounds comfortable. But the report also shows that the composition of that surplus has shifted hard: investor-held allowances fell from 60 million tons at Q2 2025 to 37 million tons (68% of the surplus) at Q2 2026, while compliance-held allowances rose to 18 million tons (32%). The report attributes this to entities holding onto allowances for their own future compliance needs instead of releasing them into the secondary market, along with a rise in traders “spreading” 2026-vintage futures against 2027-vintage futures to hedge post-2026 exposure without tying up scarce near-term allowances. In plain terms, the people who actually have allowances to sell are increasingly choosing not to sell them. A surplus that will not come to market behaves like scarcity, which is exactly why the price jumped 40% in a single quarter while the official surplus number still looked fine.

Virginia’s return adds less new supply than the demand it brings with it. The report quantifies what I could only describe qualitatively in my May 9 and June 16 posts: Virginia’s re-entry adds 12.6 million allowances, including CCR, across the two remaining 2026 auctions, against 17 million tons of covered emissions Virginia generated in the second half of 2025 alone. A state that shows up with a 4.4-million-ton gap between the allowances it brings and the emissions it is already producing is not a source of relief for the regional bank; it is a net new claim on it.

The report authors twice flag their emission projections as too high. The Q2 2026 report notes that its assumption for second-half 2026 emissions “may be a conservative assumption because it does not account for the impact of recent allowance price increases” suggesting that higher prices could suppress emissions.  This theory is an article of faith for RGGI advocates but is flawed in my opinion.  Many other factors impact electricity generation emissions including unit performance, major transmission outages, abnormal weather, fuel pricing, and electric demand in the short term.  In the long-term patterns of electric production, electrification, and large load growth affect demand and emissions which are inextricably connected.   I believe that these inelastic factors outweigh allowance price impacts on emissions such that higher allowance prices just mean more consumer costs.

Given my pre-retirement responsibility tracking RGGI allowance compliance holdings relative to emissions I want to highlight the following claim in the report:  “A substantial share of the allowance surplus is held for compliance purposes – The number of surplus allowances held for compliance purposes was 18M (or 32 percent of the surplus) at the end of the second quarter.”  The report goes on to say “The compliance entities that hold these surplus allowances have generally not made them available for sale in the secondary market in the past, presumably intending to use them for compliance in the next control period.”  There has always been a disconnect between compliance entities and the academic theory of market programs like RGGI.  The theory is that compliance entities consider opportunities to make money in the secondary market, but the reality is that the compliance risk of insufficient allowance trumps that option.  If they do not have the allowances, then they will not run so the fact that only 32% of the surplus is held for compliance is concerning.  Also consider that means that 68% of the surplus is held by investors.  Presumably those investors want to maximize their profits so I think that means it is unlikely that costs will allowance prices will drop significantly because the surplus margins are small.

Most importantly, the report explicitly refuses to say anything about the exact question DEC needed an answer to before finalizing Part 242. The Q2 2026 report states plainly that “analysis of these factors” — meaning the post-2027 cap trajectory and the implications of the Third and now-needed Fourth Program Review — “is beyond the scope of this report.” That is an honest disclosure by Potomac Economics about what its report does and does not cover. But it also means the projected allowance surplus says  nothing about the annual cap cuts of more than 10% of the 2025 budget that begin in 2027 and run through 2033;  That is an entirely different order of scarcity than the roughly 2-million-ton annual declines this report is describing for 2023 through 2026. My own allowance-bank model, using the steeper post-Third-Program-Review cap, projects the bank going negative by 2032 or 2033 — a conclusion this report cannot confirm or refute because it was never designed to look that far ahead. Treating a Control Period 6-scoped market-monitor report as evidence that the post-2027 cap trajectory is manageable, which is functionally what DEC’s response to comments does, is exactly the kind of error the report’s own scope disclaimer should have prevented.

Bottom Line

RGGI, Inc. will not say this report exists because of the $35 auction and the scarcity questions that followed it, but the timing makes the connection hard to dismiss. Potomac Economics did its job. Its Q2 2026 report is a careful, appropriately hedged accounting of the sixth control period’s allowance bank, and it independently confirms nearly every specific claim I have made in my reporting this year: the 2026 CCR allowances are gone, the market is hoarding rather than releasing allowances as the compliance deadline nears, Virginia’s return brings more emissions than allowances, and the market monitor’s own baseline assumptions may understate how tight things really are. The failure here is not the market monitor’s. It is DEC’s. DEC and NYSERDA finalized Part 242 on August 5 leaning on “the Cost Containment Reserve” and “the allowance bank” as reasons consumer impacts would be manageable, without ever grappling with the fact that the only rigorous, independent accounting of that bank explicitly declines to say anything about the post-2027 period the amendments actually govern. A report that says “the near-term bank is fine, but we are not going to tell you anything about the long-term bank” is not evidence that the long-term bank is fine. DEC should stop citing the allowance bank as a reassurance it has not earned, and it should push for an immediate start to the Fourth Program Review rather than letting the “no later than 2028” timeline it floated in its response to comments run out the clock on a cap trajectory that its own market monitor will not vouch for.

Over the last couple of months, I have written articles describing my concerns about the recent sharp increase in Regional Greenhouse Gas Initiative (RGGI) allowance prices since the announcement that Virginia was rejoining the program.  I have argued that the RGGI allowance costs operate as a regressive, opaque tax on electricity that raises bills, stresses the grid, and may not deliver the durable climate or affordability benefits advocates claim.  RGGI cheerleaders’ arguments about higher RGGI allowance prices reflect a revenue‑first mindset that treat rising auction proceeds as a “big opportunity” to expand state‑controlled climate and rebate programs.  At a time when energy affordability is a concern not protecting consumer costs is inappropriate.   A recent article at E&E News exemplifies the mindset that spending more on the goals of RGGI is more valuable than keeping ratepayer costs low.

I have been involved in the RGGI program process since its inception and have been writing about the about problems with the RGGI program since the start of this blog.  I have worked on every cap-and-trade program affecting electric generating facilities in New York including RGGI, the Acid Rain Program, and several Nitrogen Oxide programs, since the inception of those programs. The opinions expressed in this post do not reflect the position of any of my previous employers or any other organization I have been associated with, these comments are mine alone.  I acknowledge the use of Perplexity AI to generate material included in this document. 

Background

RGGI is a market-based program to reduce greenhouse gas emissions from the power sector. It has been a cooperative effort among Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New York, Rhode Island, and Vermont since 2008, with New Jersey and Virginia rejoining in 2020 and July 2026, respectively. Pennsylvania recently decided not to join.

According to the RGGI program description, the states issue CO₂ allowances that are distributed almost entirely through regional auctions, and the proceeds are then reinvested in strategic energy and consumer programs. Those investments include energy efficiency, clean and renewable energy, beneficial electrification, greenhouse gas abatement and climate adaptation, and direct bill assistance, with energy efficiency receiving the largest share.  There also are unacknowledged administrative costs that reduce even rebate program benefits.

This blog has a web page dedicated to RGGI articles.  My work shows that RGGI has not effectively reduced CO2 emissions from the power sector and that most of the observed reductions were caused by economic fuel switching from coal and oil to natural gas.  Emission reductions associated with RGGI investments only account for 8.7% of the observed reductions.  The most recent RGGI Investments of Proceeds report notes that the RGGI auctions have raised over $4 billion and investments have reduced annual emissions a little over five billion tons.  That works out to a CO2 cost effectiveness of $800 per ton.  At this rate, the amount raised falls far short of the funds necessary to reduce RGGI emissions in accordance with Third Program Review requirements.  

Consumer Climate Cash is about to pour into East Coast States.    

This E&E News article recently argued that soaring RGGI allowance prices represent “a big opportunity” for East Coast states: hundreds of millions of new dollars that can be poured into climate programs and bill rebates just as federal support erodes. The story celebrates the first half of 2026 bringing in about $1.3 billion from RGGI auctions at record prices and frames that revenue as climate‑friendly cash that states can deploy to both cut emissions and lower bills.

Climate cash or consumer stealth tax?

The E&E article argues that soaring RGGI prices are “a big opportunity” because auctions now bring in billions more that states can pour into climate programs and bill rebates as federal support wanes. It treats this revenue as climate‑friendly cash, framing RGGI as both an emissions tool and a way to lower bills.

My work shows a different reality. Higher allowance prices don’t appear as free money; they arise because generators must pay more to produce power and recover that cost through wholesale markets. What looks like a windfall in state budgets is in fact a hidden,  regressive tax on the backs of consumers that show up in higher commodity prices on their bills. The key question is whether the modest bill credit or other anticipated programs offset the immediate cost impact that an individual customer faces?

What record prices really mean

Recent RGGI auctions have cleared at about $35 per ton, a record price driven by rising load, Virginia’s re‑entry, and bottlenecks in renewable development, not by orderly decarbonization. At current emissions levels, that isn’t a marginal tweak; it’s a major cost shift onto ratepayers. Furthermore, the secondary market for RGGI allowances is higher than $35 per ton, so future costs will be even higher than shown here.

In my New York analysis, direct allowance purchases now run on the order of $0.7–1.1 billion per year for New York, with total ratepayer impacts — once wholesale price uplifts are considered — plausibly in the $1.8–3.2 billion range. The E&E article considers only the $1.3 billion in first‑half auction proceeds across RGGI states and calls it climate cash.  It ignores the broader cost footprint of the wholesale market costs. To summarize, wholesale energy market impacts are $1.8 to $3.2B and auction revenues are $.7 to $1.1 billion, so the total consumer deficit is $1.1B to $2.1B. More importantly, the higher RGGI wholesale price impact flows through the energy futures trading market.

Proceeds versus total cost

The core problem in the “climate cash” narrative is its fixation on proceeds while ignoring total system costs. Every allowance a generator buys becomes a bid adder in energy markets. Because market prices are set by the marginal unit, that carbon cost flows into the clearing price and is collected on nearly every MWh sold, including from non‑emitting resources that don’t buy allowances but still receive higher revenues.

States see the portion of this money that passes through auctions, call it climate revenue, and fight over how to spend it. But ratepayers bear all the cost, and only a fraction returns to them via programs or credits. The rest is retained by non‑emitting generators or spent on administration and favored initiatives. There is no honest accounting that sets proceeds against total costs and explains the net impact on households.

The “affordability strategy” claim

To address political backlash over rising bills, the article touts RGGI‑funded rebates as an “affordability strategy.” New Hampshire returns almost all proceeds as bill credits; Virginia has earmarked about half of its RGGI revenue for new rebates when it rejoins. Advocates, citing modeling from Resources for the Future, claim higher prices can ultimately lower household electricity costs.

This is appealing but misleading. In Virginia, RGGI previously added about $4 per month to the average customer’s bill; with higher prices, the projected cost is $10–$13 per month. Policymakers propose a roughly $3 per month rebate funded from RGGI proceeds and call that affordability. RGGI raises bills with a hidden surcharge, then politicians refund part of what was collected and declare victory for ratepayers.

Rebates are also politically fragile and temporary. They can be redirected or cut in a budget cycle and don’t alter the underlying wholesale price adder from the carbon requirement. Even if they work as proposed, there is a lag between electric bill payments and rebates which could be problematic for any ratepayers with affordability issues.  Furthermore, there are transactional costs incurred that someone must pay for.  The structural reality remains that RGGI pushes base prices up by design.  Rebates partially mask that effect for some customers in some years. That is not what most people would consider a genuine affordability strategy.

Regressive and opaque incidence

The E&E article barely addresses who pays and who benefits. Because RGGI costs flow through wholesale settlement rather than being itemized on bills, customers simply see higher prices without a clear explanation. Low‑ and moderate‑income households, who spend a larger share of income on electricity and have less ability to adapt, pay more but are not guaranteed proportional relief.

Meanwhile, proceeds are distributed across bill assistance, efficiency, resilience projects, and administrative overhead. Some households receive credits; others do not. Non‑emitting generators gain from uplifted wholesale prices. The impact of RGGI is regressive and opaque.  Ordinary ratepayers shoulder most of the burden, while benefits are dispersed based on policy choices rather than a transparent link to who paid.

An affordability‑focused policy would rely on explicit charges, clear line items, and targeted assistance to vulnerable customers, not wholesale price increases and intermittent rebates. RGGI’s current structure sacrifices transparency for political convenience.

Are efficiency gains enough?

I have evaluated RGGI proceeds reports and Acadia Center claims that billions of investment dollars have produced even larger lifetime bill savings that the E&E report accepts without skepticism. Efficiency and related programs funded by RGGI do provide benefits, but those estimates are modeled, spread over many years, and largely based on periods when allowance prices were far lower and system conditions were different.  It is also important to note that RGGI categorical investments are not what I believe are cost effective (Table 1).

Table 1: Summary of Recent RGGI Categorial Investments and Avoided Emissions Over the Last 7 Years

When you compare these long‑run, modeled savings to the very real, near‑term multi‑billion‑dollar annual costs implied by $35 per ton in a context of rising load and stalled renewables, the offset is much less convincing. Advocates are using uncritical assessment of historical performance under a less stressed regime to justify today’s much higher tax incidence. That’s not a sound basis for declaring RGGI an affordability success.

Leakage, effectiveness, and reliability

The article briefly mentions New Jersey concerns about leakage — the idea that RGGI shifts emissions rather than reducing them — and an alternative flat‑fee proposal. Independent analysis has gone further, suggesting RGGI may not be functioning as intended and could even increase net CO₂ emissions while costing consumers billions once cross‑border flows and market interactions are fully considered. I do not think leakage is theoretical any longer; it is inevitable, especially given the interconnected nature of PJM and the ability of non‑RGGI generators to serve load in RGGI states. If that’s true, high proceeds are not proof of climate success; they are evidence of design failure.

At the same time, the updated cap trajectory cuts allowances by more than 10% of the 2025 budget each year from 2027 to 2033, a pace the region has never sustained. Load is increasing; renewables face federal and local bottlenecks; dispatchable thermal capacity remains essential. Record prices in this context are a reliability warning as much as an affordability problem. Yet the article treats RGGI mostly as a fiscal tool, without grappling with its interaction with grid physics and capacity needs. Higher allowance prices, higher imports from non-RGGI states, higher CO2 emissions, consumer affordability concerns, and potential reliability based issues are the consequences of the current RGGI design.

Time for RGGI Changes

It appears to me that the E&E article is part of a concerted effort by climate NGOs, sympathetic lawmakers, and policy analysts who see RGGI as one of the few remaining levers to fund climate-related programs in a hostile federal policy environment to disparage any of the many observed issues with RGGI.  RGGI is an increasingly blunt, costly, and opaque instrument to pursue climate and affordability goals.

If states truly care about both, they should:

• Use transparent funding mechanisms instead of hiding costs in wholesale prices.
• Align any carbon price with realistic emissions paths and reliability needs.
• Build strong safeguards against leakage and measure net emissions outcomes honestly.
• Explicitly compare total RGGI costs with proceeds and commit to returning a defined share of net costs to ratepayers in predictable ways.

As things stand, RGGI at $35 per ton looks more like a stressed carbon tax with uncertain climate benefits than a stable source of “climate cash.” Higher allowance prices should be treated as a warning signal that the program’s design and trajectory need serious re‑evaluation, not a cause for celebration.

interest.  I believe that given the energy affordability concerns within the RGGI states and the poor performance of this emission reduction program, that RGGI needs to be paused if not rescinded altogether.

I have regularly prepared updates on the Regional Greenhouse Gas Initiative (RGGI) annual Investments of Proceeds report.  Last year I described the implications of the report relative to the finalized Third Program Review.  This year the report comes out at a time when the costs have risen sharply and the trend of emission reductions has stalled while at the same time the future annual allowance reduction trajectory mandates an annual reduction of over 10% between 2026 and 2027 and beyond.  In this post I review the 2024 investment proceeds to see if there is any indication that auction proceeds are being invested better.

Dealing with the RGGI regulatory and political landscapes is challenging enough and agency retribution is enough of a threat that affected entities seldom see value in speaking out about fundamental issues associated with the program.  I have been involved in the RGGI program process since its inception and have no such restrictions when writing about the about problems with the RGGI program.  I have worked on every cap-and-trade program affecting electric generating facilities in New York including RGGI, the Acid Rain Program, and several Nitrogen Oxide programs, since the inception of those programs. I also participated in RGGI Auction 41 successfully winning allowances and holding them for several years.   The opinions expressed in this post do not reflect the position of any of my previous employers or any other organization I have been associated with, these comments are mine alone.

Background

RGGI is a market-based program to reduce greenhouse gas emissions (GHG) (Factsheet). It has been a cooperative effort among the states of Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New York, Rhode Island, and Vermont to cap and reduce CO2 emissions from the power sector since 2008.  New Jersey was in at the beginning, dropped out for years, and re-joined in 2020. Virginia joined in 2021, withdrew in 2024, and rejoined effective July 1, 2026, and Pennsylvania considered joining but has since decided not to join.  According to a RGGI website:

The RGGI states issue CO₂ allowances that are distributed almost entirely through regional auctions, resulting in proceeds for reinvestment in strategic energy and consumer programs. Programs funded with RGGI investments have benefited local businesses, low-income communities, industrial facilities, and households throughout the region.

Proceeds were invested in programs including energy efficiency, clean and renewable energy, beneficial electrification, greenhouse gas abatement and climate change adaptation, and direct bill assistance. Energy efficiency continued to receive the largest share of investments.

Despite claims about the success of RGGI, the reality is that the only thing it is good at is raising money.  Suggestions that RGGI has been responsible for the observed reductions in CO2 emissions over the life of the program ignore the importance of fuel switching and the poor performance of RGGI auction proceed investments in reducing emissions.  I document these  observations below.

Proceeds Investment Report

The 2024 investment proceeds report was released on June 26, 2026.  According to the press release: “In 2024, $856 million in RGGI proceeds were invested in programs including energy efficiency, clean and renewable energy, beneficial electrification, greenhouse gas abatement, and direct bill assistance. Over their lifetime, these 2024 investments are projected to provide participating households and businesses with $2.6 billion in energy bill savings and avoid the emission of 4.4 million short tons of CO₂..”  The report breaks down the investments into major categories.  The 2024 investment report explains:

Energy efficiency makes up 46% of 2024 RGGI investments and 54% of cumulative investments. Programs funded by these investments in 2024 are expected to return about $1.8 billion in lifetime energy bill savings to more than 127,000 participating households and 2,000 businesses in the region and avoid the release of 2.1 million short tons of CO2.

Clean and renewable energy makes up 6% of 2024 RGGI investments and 11% of cumulative investments. RGGI investments in these technologies in 2024 are expected to return over $421 million in lifetime energy bill savings and avoid the release of more than 1.1 million short tons of CO2.

Beneficial electrification makes up 16% of 2024 RGGI investments 6% of cumulative investments. RGGI investments in beneficial electrification in 2024 are expected to avoid the release of 1.2 million short tons of CO2 and return over $167 million in lifetime savings.

Greenhouse gas abatement and climate change adaptation makes up 4% of 2024 RGGI investments and 6% of cumulative investments. RGGI investments in greenhouse gas (GHG) abatement and climate change adaptation (CCA) in 2024 are expected to avoid the release of more than 3,400 short tons of CO2.

Direct bill assistance makes up 23% of 2024 RGGI investments and 16% of cumulative investments. Direct bill assistance programs funded through RGGI in 2024 have returned over $197 million in credits or assistance to consumers.

Unfortunately, this official story about the virtues of RGGI investments does not square with reality.

Emission Reductions

All my summaries of the RGGI Investment Proceeds reports have found the same results.  Since the beginning of the RGGI program, RGGI funded control programs have been responsible for a small fraction of the observed reductions – only 8.7% in 2024 (Table 1).  Figure 1 plots CO₂ emissions by fuel type across all eleven RGGI states from 2006 to 2025.  What you see is fuel switching caused the reductions and that there are only minor opportunities for future fuel switching. Consequently, future reductions will have to rely on the deployment of zero-emission generating resources and load reductions which makes cost-effective emission investments important. 

Table 1: State-Level CO2 Emissions for Nine RGGI States 2009 to 2024

Figure 1: Eleven State RGGI CO₂ Emissions (short tons) for all Programs 2006–2025

The importance of cost-effective investments for emission reductions is unacknowledged by the RGGI states.  I calculate cost effectiveness by dividing the RGGI total investments divided by the estimated avoided CO2 emissions. In 2022 the CO2 emission reduction efficiency was $949 per ton of CO2 reduced, in 2023 the cost per ton reduced increased to $1,854, and in 2024 the cost per ton reduced reached $3200 per ton.  It is not clear why there are such big changes.  There is no obvious change in investment strategies, but the avoided annual CO2 emissions went down 42% in 2024 from 2023.  I suspect that the calculation methodology contributes to these numbers but this cannot be confirmed because there is insufficient documentation. Nonetheless, if the RGGI states prioritized emission reduction efficiency then the trend should reverse.

Table 2: Accumulated Annual RGGI Proceeds, Avoided CO2, and Cost Efficiency

Emission Reduction Costs

RGGI is supposed to be an emissions reduction program.  On July 3, 2025, RGGI announced the results of the Third Program Review that modified the requirements for future reductions.  Based on my analysis of the planned revisions, the RGGI States only delayed the inevitable reckoning of the futility of this program to achieve the goal of a “zero-emissions” electric system.  The RGGI summary  of the revisions states that the revised mandated reductions will “decline by an average of 8,538,789 tons per year, which is approximately 10.5% of the 2025 budget” from 2027 to 2033.

The emission proceeds reports can be used to estimate expected costs if RGGI investments were the only source of emission reductions.  Table 3 lists the cost per ton of CO2 removed of the RGGI investments from 2015 to 2024, the cost to reduce 8,538,789 tons per year using their observed costs, and the RGGI proceeds for each year.  In 2024 the Third Program Review mandated annual emission reduction multiplied by the cost per ton ($1,854) totals $27.3 billion but the RGGI proceeds were only $0.86 billion.  Even using the cost over the entire 10-year period of $1,126 per ton, it would cost $9.6 billion to make the reductions mandated.  This is still far short of the proceeds available.

Table 3: Annual RGGI Cost Efficiency, Cost to Meet 2027 RGGI Annual Reduction, and Annual Proceeds

Investment of Proceeds Summary

The 2024 investment proceeds report breaks down the investments into major categories. I added the annual values for each category to provide the following summary (Table 4).  Note that the overall cost effectiveness is $1,422 per ton avoided.  Clearly the proceed investment strategy is not emphasizing emission reduction effectiveness.  It is encouraging that savings of $1.3 billion are claimed but total investments are $3.1 billion.   In my opinion, these numbers are inconsistent with claims that RGGI is successful.

Table 4: RGGI Proceeds Report Investment Category Annual Totals

Cost Effectiveness Implications

One of my big concerns about any cost on carbon emissions is that it is a regressive stealth tax on energy.  There is a tradeoff between trying to minimize those impacts and reducing emissions.  In the last seven years $568 million or 18% of the RGGI auction proceeds went to direct bill assistance, which is good but that means that much less was available to reduce emissions (Table 5).  Throw in the $166 million over the last seven years for administration that means that 24% of the RGGI auction proceeds were not used to reduce emissions.

Table 5: Summary of Recent RGGI Categorial Investments and Avoided Emissions Over the Last 7 Years

This article compares the cost effectiveness of emission reductions for the following investment categories: energy efficiency, clean and renewable energy, beneficial electrification, greenhouse gas abatement and climate change adaptation (Table 5).  For the investment categories that provided emission reductions Clean and Renewable Energy was the most effective way to reduce emissions.  As far as I can tell this category provides the most funding for projects that directly reduce emissions.  It is encouraging that the energy efficiency is less than the average over all categories.  This means that energy efficiency programs targeted at low- and middle-income households most affected by this energy tax will provide effective emission reductions but only at a cost near $1,160 per ton. 

On the other hand, programs promoting the research and development of GHG abatement and climate change adaptation are less effective at reducing emissions.  Perhaps a greater emphasis on programs promoting reduction of emissions in the power generation sector and advanced energy technologies and less emphasis on programs for the reduction of vehicle miles traveled, tree-planting projects designed to increase carbon sequestration, and climate adaptation and community preparedness initiatives would improve emission reduction efforts consistent with the emission reduction goal of RGGI.

The worst emission reduction programs are associated with beneficial electrification that are “designed to reduce fossil fuel consumption by implementing or facilitating fuel-switching to replace direct fossil fuel use with electric power“ for non-generating sources. This category was added recently.  There are two ways to look at the high numbers.  On one hand, it could be that it recognizes that reductions of overall fossil fuel consumption require efforts across all sectors.  On the other hand, I think it inappropriately transfers costs to the electric sector that do not provide efficient emission reductions at a time when reductions are needed to achieve the accelerated allowance cap reductions.

My biggest concern is that RGGI funding priorities do not reflect the necessary funding required to meet the annual reduction mandates in the recently approved Third Program Review modifications. These results show that RGGI investments will not fund the emission reductions mandated.  That leaves the question – where will the reductions come from?

Conclusion

The closing price of the early June RGGI allowance auction increased 40% since March. Claims that RGGI is a successful emission reduction program are inconsistent with the observations.  The amount raised falls far short of the funds necessary to reduce RGGI emissions in accordance with Third Program Review requirements.   Investment priorities are inconsistent with the emission reduction objectives.  Finally, emission reductions associated with RGGI investments only account for 8.7% of the observed reductions.  These results support my belief that RGGI now poses unacceptable affordability and reliability risks and needs immediate, fundamental revision. 

Over the past several months I have published a series of posts arguing that the Regional Greenhouse Gas Initiative (RGGI), as currently structured, no longer serves its stated purpose of reducing greenhouse gas emissions and has become a significant, largely unacknowledged burden on electricity consumers throughout the RGGI states. I found independent corroboration from two white papers published by Tabors, Caramanis, and Rudkevich (TCR), an energy consulting and analytics firm. The convergence of conclusions reached through entirely different methodologies — my narrative and historical analysis versus TCR’s full power market simulation — is, I believe, significant and worth examining in detail. 

Dealing with the RGGI regulatory and political landscapes is challenging enough and agency retribution is enough of a threat that affected entities seldom see value in speaking out about fundamental issues associated with the program.  I have been involved in the RGGI program process since its inception and have no such restrictions when writing about the about problems with the RGGI program.  I have worked on every cap-and-trade program affecting electric generating facilities in New York including RGGI, the Acid Rain Program, and several Nitrogen Oxide programs, since the inception of those programs. I also participated in RGGI Auction 41 successfully winning allowances and holding them for several years.   The opinions expressed in this post do not reflect the position of any of my previous employers or any other organization I have been associated with, these comments are mine alone.  I acknowledge the use of Perplexity AI to generate references and draft text included in this document. 

The Two White Papers

TCR published two relevant papers. The first, dated February 15, 2025, is titled Summary Impact of RGGI on Electricity Prices and Generation Fleet Operation in the PJM Interconnection and was authored by Dr. Aleksandr Rudkevich and Dr. Richard Tabors. It uses TCR’s ENELYTIX power market simulation tool to model the PJM wholesale electricity market across a full calendar year (2025) under two scenarios: a Business-as-Usual case in which Delaware, Maryland, and New Jersey participate in RGGI at $20 per short ton of CO₂, and a No-RGGI case in which no PJM state participates. The $20/ton price reflects the RGGI forward market in October 2024, when the work began.

The second white paper, dated April 1, 2026, is titled Quantitative Evaluation of a RGGI Fixed Price Proposal for New Jersey and models a specific reform proposal: setting the RGGI compliance price to a fixed $7 per short ton for New Jersey generators, compared to a base case in which New Jersey operates under the Cost Containment Reserve (CCR) Tier 2 Trigger Price of approximately $29.25/ton. That paper also includes a sensitivity analysis examining what happens if Virginia re-joins RGGI in 2028. The study period is 2027–2030.

Where the Analysis Converges: The Emissions Leakage Problem

The event that solidified my belief that changes are in order was the fallout from the April 29, 2026, RGGI statement that Virginia was rejoining the program.  I explained  in the days that followed, the futures market price of RGGI allowances nearly doubled, and the spot market cost also increased significantly.  The closing price of the most recent RGGI auction on June 3, 2026, was $35.00 up 40% from the March 11, 2026 auction price of $24.99.  One of the implications of this increase in price is that emissions leakage from RGGI states to now cheaper sources in non-RGGI states is no longer a theoretical problem.

The core analytical finding of the TCR 2025 white paper confirms the leakage observation from a different direction: RGGI, at current prices, does not reduce carbon dioxide emissions in any net sense. Because there are states in RGGI and not in RGGI in the PJM Interconnection this effect is magnified.  The higher RGGI prices redistributes where generation and  emissions occur, and because it displaces efficient gas-fired combined-cycle generation in RGGI states with less-efficient coal-fired generation in non-RGGI PJM states, the net effect is a larger total emissions footprint.

TCR’s simulation is precise about the mechanism. Under RGGI at $20/ton, the allowance cost adder renders highly efficient combined-cycle power plants in Delaware, Maryland, and New Jersey uneconomical in the PJM dispatch stack. The gap is filled by coal-fired units located in western PJM — in states like Ohio, West Virginia, and Pennsylvania — that face no RGGI compliance obligation. The quantitative result from TCR’s Figure 1 is striking: RGGI causes combined-cycle gas generation to fall by 6,850 gigawatt-hours, while coal generation increases by 5,220 GWh and other thermal generation rises by another 628 GWh. The net CO₂ impact, shown in TCR’s Figure 2, is a system-wide increase of 2.7 million short tons per year. Emissions fall by roughly 3 million short tons in the RGGI-participating zones as gas-fired CC plants run less — but they rise by 5.7 million short tons in the rest of PJM as coal and other thermal plants fill the void.

My recent post on Virginia and the myth of lower energy costs made the identical analytical argument, estimating a net emissions increase attributable to the leakage mechanism. The TCR 2025 paper confirms this with precision. It also notes a secondary concern I raised as well: RGGI’s effect on PJM exports reduces sales to MISO and other neighboring grids by approximately one terawatt-hour, likely causing further emission increases in those systems — a second-order leakage effect that is not counted in the headline figure.

It is important to note that TCR modeled RGGI at $20/ton. As of the most recent auction in June 2026, RGGI allowances cleared at $35/ton — 75% higher than the TCR assumption. The leakage and cost impacts TCR documented are therefore considerably worse today than their published numbers reflect.

Where the Analysis Converges: Consumer Cost Impacts

The TCR 2025 paper quantifies the consumer cost impact across the entire PJM footprint at $1.16 billion per year in additional costs (expressed in constant 2024 dollars) for the $20/ton scenario. This arises from two mechanisms that I have described. First, RGGI-obligated generators embed the allowance cost directly in their market bids. Second — and this is the more important and less-understood effect — when a RGGI-obligated unit sets the market clearing price, every generator in that pricing zone collects the higher clearing price, including non-emitting units that have no compliance obligation whatsoever. Those zero-emission units receive the carbon cost premium as pure profit without bearing any direct CO₂ compliance cost.

My May 9, 2026 post on RGGI’s unacknowledged New York cost impact described this mechanism and concluded that total consumer costs can be “two or more times higher than the direct allowance expenditures.” The TCR paper’s system-wide $1.16 billion figure, modeled at $20/ton, is consistent with that characterization. The primary beneficiaries TCR identifies are generators located in non-RGGI PJM states, which receive nearly $1.3 billion per year in additional revenues as a result of the program. RGGI-state generators actually see their revenues reduced by approximately $500 million per year, for a net revenue transfer to non-participating states of $825 million annually. Consumers in RGGI states are, in effect, subsidizing coal-state generators through their electricity bills.

The Historical Attribution Problem

This is an area where my analysis goes meaningfully beyond what either TCR white paper addresses. Both TCR papers acknowledge the historical emission reduction record of the RGGI program: the three PJM participants (Delaware, Maryland, and New Jersey) collectively reduced in-state CO₂ from 44.8 million short tons in 2009 to 23.6 million short tons in 2024 — a net reduction of 21.2 million short tons. The TCR papers present this as RGGI’s achievement without examining the counterfactual question: how much of this reduction would have occurred anyway?

My December 2025 post analyzing New York’s RGGI Cap-and-Invest emission reduction performance addresses that question directly, at least for New York. By examining NYSERDA’s own program investment data, I calculated that total cumulative annual emission savings from RGGI-funded investments through 2023 amounted to approximately 1.4 million tons — meaning that emissions from RGGI sources in New York would have been only about 3% higher in the absence of any RGGI investment spending. My Virginia post extended the analysis to the broader program, estimating that roughly 7.6% of observed reductions can be attributed to RGGI-funded projects; the remaining 93% or more reflect market-driven fuel switching from coal and oil to natural gas, driven by price differentials that had nothing to do with RGGI allowance costs.

The TCR white papers take the reduction record at face value. This is not a criticism — attribution analysis was outside their scope — but it means the papers’ own historical framing somewhat overstates RGGI’s contribution during its early years. The combination of the TCR findings and my attribution analysis leads to a more complete picture: RGGI may have modestly reinforced a reduction trend it did not create, while today it has reversed sign and is now adding to system-wide emissions rather than reducing them.

The Reform Scenario: The NJ $7 Proposal

The TCR 2026 white paper breaks new and useful analytical ground by evaluating a specific structural reform. New Jersey has been exploring a proposal to fix the RGGI compliance price for its generators at $7 per short ton — far below both the current market clearing price and the CCR Tier 2 cap of $29.25/ton used as the 2026 paper’s base case. TCR’s simulation of this proposal is revealing: the $7 fixed-price scenario would reduce PJM-wide CO₂ emissions by an average of 4.7 million short tons per year relative to the high-price base case, and would save New Jersey consumers approximately $274 million per year in wholesale energy costs.

The mechanism runs exactly in reverse of the high-price leakage problem. At $7/ton, the compliance cost adder for New Jersey’s efficient combined-cycle generators is small enough that they remain competitive in the PJM dispatch stack against non-RGGI coal plants. Gas-fired CC units in New Jersey dispatch more, coal plants in western PJM dispatch less, and system-wide emissions fall. The program at $7/ton functions more like a modest carbon fee that funds state clean energy investments without distorting the dispatch order in harmful ways — which is, notably, exactly how RGGI functioned during its first decade, when prices were generally below $5/ton.

This analysis raises a question worth exploring in future posts: is the concept of RGGI broken, or is it the current price level that has broken RGGI? The TCR 2026 paper’s findings suggest the latter. A reformed RGGI with substantially lower and more stable allowance prices might actually accomplish what the program’s proponents claim it does today — reduce emissions without imposing unacceptable consumer costs. At current prices, those claims are simply not supported by the evidence.

The Virginia Complication

Both my May 2026 post on Virginia’s rejoining and the TCR 2026 sensitivity analysis point in the same direction: Virginia re-entering RGGI at current price levels makes matters worse, not better. The TCR 2026 paper finds that baseline costs to New Jersey consumers are lower when Virginia is not a RGGI participant, and that the CO₂ emission reductions achievable through the NJ $7 Proposal are larger when Virginia stays out. My own compliance analysis found that Virginia’s addition tightens the allowance pool and is likely to accelerate the depletion of available allowances, which I project runs out in the third quarter of 2033 at constant emission rates.

What makes the Virginia situation particularly concerning is the price signal. When Governor Spanberger’s commitment to rejoin RGGI was announced in November 2025, RGGI futures prices rose more than 30% in three days, breaking all-time highs above $40/ton. That price spike immediately flowed into generator bids and was “showing up in electric prices” as I noted at the time. RGGI’s volatility at current scarcity levels — any news about program participation moves the market sharply — compounds the cost problem for consumers and the planning problem for grid operators.

The Bottom Line

The TCR 2025 white paper’s own “Bottom Line” section (Section 4.4) contains language that I could have written: the continuation of RGGI in its current form “contradicts RGGI’s principal intent, which is to reduce greenhouse gas emissions,” and the program “appears, quite clearly, to have outlived its stated objective in PJM and from a policy perspective is in need of significant realignment if not elimination.”

That conclusion, reached by professional power market economists using rigorous quantitative simulation, validates the core argument I have been making my work through historical and analytical work. Two independent lines of inquiry — one empirical and narrative, one formal and computational — have converged on the same answer.

The path forward is not necessarily to abandon carbon pricing in the electricity sector. The TCR 2026 paper’s $7/ton analysis suggests that a reformed program with much lower and stable prices could work better on both the cost and environmental dimensions simultaneously. But the current program, at current prices, with the current cap trajectory, is failing on both dimensions at once. Proponents who continue to claim that RGGI reduces emissions and lowers consumer costs now have two independent analyses to refute — not just my work.

The Acadia Center recently published a post titled “Virginia is for Lovers, and RGGI is for Lower Energy Costs,” arguing that Virginia’s reentry into the Regional Greenhouse Gas Initiative (RGGI) will make energy more affordable. That narrative is increasingly at odds with both recent auction results and the actual mechanics of how RGGI costs flow through wholesale power markets and retail bills.  This post explains why the Acadia Center story is incomplete at best and dangerously misleading at worst.

Dealing with the RGGI regulatory and political landscapes is challenging enough and agency retribution is enough of a threat that affected entities seldom see value in speaking out about fundamental issues associated with the program.  I have been involved in the RGGI program process since its inception and have no such restrictions when writing about the about problems with the RGGI program.  I have worked on every cap-and-trade program affecting electric generating facilities in New York including RGGI, the Acid Rain Program, and several Nitrogen Oxide programs, since the inception of those programs. I also participated in RGGI Auction 41 successfully winning allowances and holding them for several years.   The opinions expressed in this post do not reflect the position of any of my previous employers or any other organization I have been associated with, these comments are mine alone.

What Acadia Center Claims

Acadia Center’s RGGI advocacy rests on a familiar trilogy of claims: emissions have fallen faster in RGGI states, retail electricity prices are lower than in non‑RGGI states, and reinvestment of auction proceeds delivers bill savings that outweigh allowance costs.

In its RGGI materials, Acadia Center touts that:

• CO₂ emissions from covered power plants are down nearly 50 percent in RGGI states since 2008.
• Economic growth and per‑capita GDP have been stronger in RGGI states than elsewhere.
• Retail electricity prices in RGGI states fell by about 3 percent while prices rose nearly 8 percent in other states over roughly the same period.
• Over 8 million households and 400,000 businesses have benefited from RGGI proceeds, with claimed future bill savings of more than 20 billion dollars.

Acadia then projects this regional story onto Virginia, arguing that carbon pricing revenues can fund energy efficiency and bill assistance programs that will leave households better off.

What these talking points omit are: what actually drove the emissions reductions, how small the RGGI “signal” is relative to other factors, and how the RGGI cost adder interacts with today’s tight supply‑demand balance and rising load from data centers and electrification.

Emissions Fell Mostly Because of Fuel Switching

Acadia’s headline claim is that RGGI caused power‑sector CO₂ emissions to fall roughly 40 to 50 percent in the region. Figure 1 plots CO₂ emissions from all programs and all fuels in the eleven RGGI states from 2006 to 2025. The pattern is clear: emissions dropped primarily because of fuel switching from coal and oil to natural gas, not because of the modest CO₂ price RGGI imposed for most of its history.

Figure 1: Eleven State RGGI CO₂ Emissions (short tons) for all Programs 2006–2025

When I analyzed the 2023 RGGI investment proceeds report, I estimated that only about 7.6 percent of observed emission reductions could be attributed to RGGI‑funded projects, despite more than 7 billion dollars in auction proceeds since 2021. In other words, more than 90 percent of the emission reductions RGGI proponents celebrate came from factors that would have occurred with or without a RGGI cap‑and‑trade overlay.

If the emissions reductions were largely driven by cheap gas and non‑RGGI policy mandates, then it is intellectually dishonest to claim RGGI “delivered” those reductions and associated economic benefits. That matters for the future of RGGI, because the low‑hanging fruit from fuel switching has already been picked; repeating history is not an option.

Auction Prices Have Exploded

Acadia Center describes RGGI costs as a “very, very small percentage” of overall bills. That might have been a defensible talking point when allowance prices were in the single digits or low teens. It is no longer tenable at current levels.

The June 3, 2026 RGGI auction cleared at 35 dollars per ton, a 40 percent jump from the March 11, 2026 auction price of 24.99 dollars (Figure 2). RGGI itself acknowledged the affordability problem in its Auction 72 announcement, stating that the states intend to begin a scoping process to “continue to achieve reliable, clean electricity supply at affordable prices.”

Figure 2: RGGI Quarterly Auction Clearing Price

In 2025, RGGI‑affected sources emitted 86.4 million tons of CO₂, and the average auction price was 22.09 dollars per ton. That translates to 1.94 billion dollars in direct allowance costs to cover auction purchases. At a 35‑dollar allowance price, holding emissions constant, the direct cost rises by about 1.32 billion dollars to roughly 3.02 billion dollars per year.

These are not trivial numbers; they are large, recurring cost streams that must be recovered from someone. In practice, that “someone” is ratepayers across the region, including Virginia households and businesses once the state reenters.

The Hidden RGGI Cost Adder in Wholesale Markets

Acadia’s narrative focuses on what states do with auction revenue but ignores the way RGGI costs propagate through wholesale electricity markets. This omission is critical, particularly for a state like Virginia embedded in PJM with a large data‑center‑driven load growth problem.

When generators bid into daily wholesale markets, they embed the cost of RGGI allowances into their marginal energy bids. If the clearing price is set by a RGGI‑affected unit, then the clearing price includes the CO₂ allowance cost adder. Every unit dispatched at that price – including generators that do not have RGGI compliance obligations – gets paid the RGGI‑inflated clearing price.

The result is a two‑part cost impact:

• Direct compliance cost: RGGI‑covered generators pay for allowances, which they recover through higher energy prices.
• Indirect windfall cost: Non‑RGGI‑covered units receive higher revenues than they would have absent RGGI, because clearing prices are higher, even though they have no compliance costs.

In New York, I estimated that this market cost adder alone – the difference between what consumers pay in wholesale markets and the actual compliance costs – runs on the order of 1 to 3 billion dollars per year. Scaling that effect across all RGGI states suggests a regional market impact between roughly 2.7 and 8.1 billion dollars annually, depending on assumptions about generation and price formation.

Acadia Center’s claim that RGGI is an “energy affordability tool” glosses over this wholesale market dynamic, treating auction revenue as free money rather than as a tax on every megawatt‑hour consumers buy. For Virginia, plugging into this system at current prices means willingly imposing an added 10 to 20 dollars per megawatt‑hour on wholesale prices, according to industry estimates, just as bills are already under pressure from new infrastructure and load growth.

RGGI’s Cap Trajectory Is Detached from Reality

Acadia’s storyline assumes that RGGI’s cap trajectory is a reasonable reflection of technical and economic reality. The updated cap path adopted in mid‑2025 tells a different story.

I have found that the new cap reduction schedule cuts allowances by more than 10 percent of the 2025 budget each year from 2027 through 2033. The region has never sustained reductions of that magnitude, and recent years have seen emissions rise due to load growth and delays in clean generation deployment.

Once banked allowances are accounted for, my modeling indicates that the system could effectively “run out” of allowances as early as the second quarter of 2032. At that point, compliant units would face a choice between shutting down or operating out of compliance, neither of which is compatible with a reliable, affordable electric system (Figure 3).

Figure 3:  Quarterly RGGI Allowance Balance, Emissions and Allowance Cap

RGGI’s own Auction 72 announcement admits that cost containment measures have already been exhausted in 2026: the primary cost control mechanism, the Cost Containment Reserve, was fully released in Auction 71, and no additional CCR allowances were available in Auction 72. When Virginia rejoins RGGI there will be another tranche of CCR allowances that I am sure will be released in the next auction.  The market is signaling that the current cap path is too tight relative to realistic deployment trajectories for replacement generation.

Acadia Center ignores this looming supply‑demand imbalance in allowances, treating RGGI as a steady‑state policy rather than a program on track to collide with physical and economic constraints in the next decade.

Who Really Benefits from RGGI Revenue?

Acadia emphasizes that RGGI has generated over 9 billion dollars in proceeds, which states have invested in energy efficiency, clean energy, and bill assistance, benefiting millions of households and hundreds of thousands of businesses. That is technically true; those dollars do fund programs. The question is whether the emission reductions and bill savings they buy justify the costs – and whether the distributional impacts are as progressive as advertised.

My review of the 2023 RGGI investment report concluded that auction proceeds are being deployed inefficiently, with implied cost per ton reduced far above commonly cited social cost of carbon values. RGGI‑funded projects explain only a small fraction of observed emission reductions, while consuming billions of dollars in ratepayer‑funded resources.

Acadia’s “energy affordability” framing implies that these investments more than pay for themselves on consumer bills. Yet RGGI’s own announcement projects 20 billion dollars in future bill savings from investments, compared to allowance costs that, at current prices, could approach 30 billion dollars over a similar horizon if emissions remain near recent levels. Even if those bill savings materialize – a big if – they are not a free lunch; they are funded by the very bill surcharges the program imposes.

Moreover, the wholesale market cost adder described above means that a significant share of the burden falls on customers in the form of higher prices for every kilowatt‑hour, while benefits are concentrated in a subset of households and businesses that receive targeted efficiency or bill assistance. That might be a defensible redistribution if it were transparently acknowledged but calling the program an “affordability tool” obscures who pays and who gets paid.

RGGI states have long acknowledged leakage as a theoretical concern, but treated it as manageable. With Virginia’s reentry at current prices, leakage is no longer theoretical; it is inevitable, especially given the interconnected nature of PJM and the ability of non‑RGGI generators to serve load in RGGI states.^[10][2][1]

Market Structure and Allowance Holdings Matter

Another blind spot in Acadia’s framing is how RGGI’s allowance market is structured and who holds allowances. Unlike some federal programs, RGGI does not publicly disclose ownership of allowances in detail; instead, its independent market monitor, Potomac Economics, reports aggregate holdings by broad categories such as “compliance‑oriented entities,” “investors with compliance obligations,” and “investors without compliance obligations.”

After Auction 72, compliance entities held 65 percent of allowances in circulation, and Potomac Economics estimates that 78 percent of allowances are held for compliance purposes. That leaves roughly 22 percent in the hands of entities that may be primarily motivated by investment returns rather than compliance.

There is also a fourth, largely unacknowledged category: non‑compliance entities that buy allowances explicitly to retire them, such as environmental organizations selling “carbon reduction certificates” to donors. While their holdings may be small today, the existence of such players underscores that not all allowances in circulation are actually available for resale or compliance.

In a tight market with a steeply declining cap, the presence of investors and voluntary retirement entities can exacerbate scarcity and volatility, driving up prices further. Acadia’s depiction of RGGI as a stable, well‑functioning market glosses over these structural issues.

Even RGGI States Now Admit There Is a Problem

Perhaps the most telling evidence that RGGI has drifted away from its original “no more than a few dollars per ton” promise is the RGGI states’ own recent language.

In the Auction 72 press release, the states tout the program’s benefits – emissions reductions, billions in proceeds, millions of households served – but then add a new note of concern: “Following this auction, the RGGI states intend to begin a scoping process to consider further targeted measures to continue to achieve reliable, clean electricity supply at affordable prices for consumers.”

Translation: at current prices and cap trajectories, the program is posing an affordability and reliability challenge serious enough to merit yet another multi‑year review process. This is the same program Acadia Center is selling to Virginians as an “energy affordability tool.”^[3][2][1]

Given that the last program review, launched in late 2021, did not conclude until mid‑2025, there is a real risk that RGGI states will repeat the “slow walk” while allowance prices remain elevated and consumers bear the cost. If Virginia joins mid‑compliance‑period under these conditions, it will be volunteering its ratepayers to subsidize both regional climate ambitions and market participants’

Conclusion

The Acadia Report maintains that all is well with RGGI.  I believe that its conclusions are not supportable.  My analysis finds that RGGI now poses unacceptable affordability and reliability risks and needs immediate, fundamental revision.  The RGGI states must disavow this report and acknowledge the enormity of the risks and engage regulators, system operators, and state lawmakers to consider substantive changes rather than the incremental tinkering contemplated in recent RGGI communications.