Category: Regional Greenhouse Gas Initiative

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. 

Updated after initial plublicatipn to include an Executive Summary and description of the RGGI announcement

In the last month I have published articles describing the impact of last year’s revisions to the Regional Greenhouse Gas Initiative (RGGI) and the impact of Virginia re-joining the program this year.  I noted that the cost of permits to emit CO2, aka allowances, increase when there is uncertainty or there is a scarcity of allowances. This post examines the results of the second quarterly auction of 2026 and concludes that the RGGI states must reconsider cost containment provisions and the projected trajectory for the cap on allowances.

Updated – Executive Summary

The second-quarter 2026 RGGI auction confirms that the program has become both an immediate affordability problem for consumers and a growing reliability risk. The allowance clearing price jumped 40% from $24.99 in March to $35.00 in June, and all available cost-containment reserve allowances for 2026 had already been exhausted by the prior auction. Using New York as a case study, the post shows that direct allowance purchases already cost consumers on the order of 700 million dollars per year at 2025 prices, rising to well over 1.1 billion dollars if the new 35‑dollar price persists. Once the wholesale market cost adder is included, the effective consumer burden plausibly reaches into the 1.8–3.2-billion-dollar range, much of which becomes windfall revenue for generators that do not themselves have RGGI obligations and does not come back to customers through any investment program.

The post argues that these rising costs are not matched by commensurate emissions or reliability benefits, and in fact sit on top of an allowance trajectory that is fundamentally incompatible with historical and expected emissions trends. The updated cap path reduces allowances by more than 10 percent of the 2025 budget each year from 2027 through 2033, despite the fact that the region has never sustained reductions of that magnitude and recent years have seen emissions rise with load growth. When banked allowances are accounted for, the analysis indicates that the system could effectively “run out” of allowances as early as the second quarter of 2032, forcing compliant units either to shut down or to operate out of compliance. At the same time, a review of RGGI investment reports suggests that auction proceeds are being deployed inefficiently: the implied cost per ton reduced is far above common social cost of carbon values, and RGGI-funded projects explain only a small fraction of observed reductions. The post concludes that the program now poses unacceptable affordability and reliability risks and needs immediate, fundamental revision—by regulators, system operators, and state lawmakers should reconsider participation —rather than the incremental tinkering contemplated in recent RGGI communications.

Author Background

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 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 rejoining in 2020 and Virginia scheduled to rejoin beginning July 1, 2026; Pennsylvania recently decided not to join.

According to the RGGI program description, the states issue permits to emit a ton of CO₂ 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.

I have long had concerns about the RGGI program, but recent events have exacerbated potential impacts on affordability and reliability.  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 $10 from the March 11, 2026 auction price of $24.99 (Figure 1).  This post describes the my concerns with this volatility.

Figure 1: RGGI Quarterly Auction Clearing Price

RGGI Affordability

RGGI allowance costs are driven by basic economic considerations. When there is scarcity, prices increase; when there is uncertainty about scarcity, costs also go up. The difference is that price increases associated with uncertainty can drop when more information is available, whereas as will be shown in the following, scarcity has been built into RGGI so costs may remain high going forward.

There are two consumer impacts of higher RGGI allowance prices.  Table 1 lists the annual proceeds from the RGGI auctions which in the last two years have totaled about $1.5 billion.  RGGI advocates claim these proceeds are invested in strategic energy and consumer programs.  In my review of the latest annual RGGI Investments of Proceeds report I concluded that RGGI does not make effective investments.  Claims that RGGI is a successful program are inconsistent with the following observations.  The overall RGGI cost per ton of CO2 reduced is $849.50 which is far above the social cost of carbon.  The amount raised falls far short of the funds necessary to reduce RGGI emissions in accordance with Third Program Review requirements.   Emission reductions associated with RGGI investments only account for 7.6% of the observed reductions.

In 2025 the direct cost of allowances in New York equals the annual emissions by multiplied by the average auction price: 32,037,339 tons times the annual allowance price or $22.09 per ton.  NYS consumers paid about $707.7 million for RGGI allowance costs assuming all allowances used came from the 2025 auctions.

Table 1:  Annual Auction Price and Proceeds

In a recent article I described the second consumer impact of RGGI allowance costs.  When generating units bid to sell their power in daily electricity market auctions, they include the cost to purchase replacement RGGI allowances.  If the clearing price is set by a unit that must comply with RGGI, then the added cost of RGGI allowances is included in their bid.  The problem for consumers is that every generating unit gets paid the clearing price.  That means facilities with no RGGI compliance obligations still get paid as if they did.  As a result, those facilities garner windfall profits at the public’s expense.

My analysis only looked at the effect of the RGGI electric market cost adder on New York State ratepayers.  I used annual values as a proxy for the hourly impacts that would ideally be calculated and summed across the year.  In 2025, statewide gross energy from New York RGGI units totaled 67,094.6 GWh, those units emitted 32,037,339 tons of CO2, the average quarterly RGGI auction price was $22.09 per ton, and NYISO Gold Book Table III-2a reports total net New York energy of 132,182 GWh.

Table 2 provides bounding estimates for the electric market effect for last year’s average allowance price and the clearing price of the Quarter 2, 2026 RGGI auction ($35).  The first section, “Cost of Allowances for Annual Emissions,” documents the direct allowance-cost numbers.  If the future RGGI allowance prices settle at the Quarter 2 2026 auction price, consumers will have to pay an additional $413.6 million for a total of $1.121 billion.  The remaining scenarios use observed heat rates and observed CO2 emission rates derived from EPA data to estimate an allowance-cost adder in dollars per MWh, which is then multiplied by total NYISO energy to estimate the statewide annual cost impact for the two allowance prices.  This bounds the likely costs to consumers.  I believe that RGGI-affected units normally set the clearing price.  If the price were set by a modern combined cycle gas turbine every hour at the average generation rate,  then the increase from last year’s average price to the last quarterly auction price then consumer costs would increase $680 million to a total of $1.8 billion.  I believe this is a lower bound.    Using the same assumptions but assuming the auction price is set by an old inefficient simple-cycle combustion turbine, consumer impacts increase $1.17 billion to $3.18 billion.

Table 2: Range of Impacts of RGGI Cost Adder on New York State Ratepayer Annual Costs

Also note that the windfall profits do not accrue just to New York generators.  All imported electricity delivered to New York is affected by RGGI costs. Imported electricity from outside New York has the same perverse outcome: embedded RGGI costs paid in the exporting state are included in the prices paid by New York consumers.  My analysis does not include these costs, so  I am underestimating the impact of RGGI costs.  This situation exists for all RGGI states.

RGGI Reliability

There is another RGGI issue that needs to be addressed.  RGGI advocates ignore the fundamental risk that RGGI-affected electric generating units will only operate if they possess allowances to comply with their RGGI obligations.  The RGGI states recently updated the allowance cap trajectory so it would be consistent with state laws that require emissions to go to zero.   As a result, the allowances allotted to the program decline by over 10 percent of the 2025 budget per year from 2027 through 2033.  The problem is that the historical emissions have never consistently shown reductions of that magnitude.

RGGI Emission Trends

Figure 2 plots CO₂ emissions by fuel type across all eleven 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.  When I analyzed the 2023 RGGI investment proceeds report, I found that only about 7.6% of observed emission reductions could be attributed to RGGI‑funded projects despite RGGI auction proceeds of over $7 billion since 2021.  Changes to Federal policy, supply chain issues, and inflation coupled with load growth all indicate that reductions from other programs are unlikely as well. 

Figure 2: Eleven State RGGI CO₂ Emissions (short tons) for all Programs 2006–2025

Table 3 demonstrates that the cap trajectory is simply incompatible with reality. There have been four years with double digit percentage emission reductions and one of those occurred before RGGI started.  Because CO2 reductions are essentially equivalent to energy use, interannual variation can be caused by weather demand for energy.  Sustained emission reductions can occur because of control programs for other pollutants and economic fuel switching to low carbon fuel aka natural gas.  I think the 2008 10% reduction was affected by fuel switching and weather variations.  The first three years (2009-2011) of RGGI were characterized by increases and decreases that had nothing to do with RGGI.  The largest annual reduction since RGGI started in 2009 occurred in 2017 and was due to economic fuel switching.  The last double digit percentage reduction occurred in 2019.  Most importantly, emissions have increased due to load growth in the last two years.

Table 3: 11-State Clean Air Markets Division Emissions Data for All Regulatory Programs

When Will the Allowances Run Out?

Because the revised RGGI allowance reduction trajectory did not consider the emission trend I made an estimate of future allowance status using the data described above to determine when allowance availability would require units to shut down to comply.  Comparing the allowance allocations to the emissions does not consider the allowances already in the system.  The “allowance bank” is the aggregate number of allowances in circulation that have been issued but not yet surrendered for compliance (i.e., held in accounts or set‑asides). Historically there has been such a large bank of allowances the RGGI States implemented several adjustments to the allowances allocated to reduce the bank.  These adjustments ended in 2025.

RGGI does not provide a report that regularly describes the status of the allowance bank, so I had to develop my own estimate.  In my post When will the allowances run out? I documented the procedure I used to estimate quarterly emissions, allowance additions, and the resulting allowance bank status so I will not repeat that material here. 

Figure 3 plots the quarterly emissions (green), allowance cap (dark blue), added allowances (light blue) and allowance balance (orange).  This analysis assumes that emissions remain constant and shows that as the allowance cap is reduced the bank of allowances eventually is exhausted.  When the allowance balance is less than zero there are no longer sufficient permits to emit CO2 and affected units must shut down or end up out of compliance.  My analysis projects that this could happen as soon as Quarter 2 2032.

Figure 5:  Quarterly RGGI Allowance Balance, Emissions and Allowance Cap

RGGI Revisions are Necessary

In response on May 8, the RGGI states issued a notice that they were monitoring the allowance market in response to a sharp increase in the secondary futures market price.  The closing price of the June 3, 2026, quarterly auction shows that their concerns about allowance market prices are legitimate.

The RGGI allowance results announcement also described concerns:

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.  As part of that process, the RGGI states will offer opportunities to engage stakeholders for feedback on the range of topics to be considered and analyses that could be conducted, such as analyses related to ensuring RGGI’s continued benefits to residents, affordability to consumers, and the smooth reintegration of Virginia into the market.

The RGGI third program review process took years.  This stakeholder engagement needs to be done quickly and not on a protracted basis like that. Consumers are revolting against utility rate hikes under 10% and this 40% increase will add to those cost increases.  RGGI states needs to be accountable. 

Unfortunately, the RGGI states have not acknowledged two other cost problems.  RGGI states typically equate consumer costs to the auction prices.  The cost to consumers includes two other impacts.  RGGI-affected sources also purchase allowances on the secondary market and if the cost is higher than the auction purchase price consumers pay that cost and get no investment benefits.  There also are no investment benefits in most of the embedded cost of RGGI allowances in the electric market.  The RGGI cost adder is applied to all generators resulting in an enormous unacknowledged cost. 

Finally, RGGI must acknowledge that the expectation that the current allowance trajectory is incompatible with the reality of potential emission reductions.  I evaluated the emissions associated with the New York State Energy Plan Pathways Analysis scenarios.  Table 4 shows that none of the scenarios project emissions consistent with the NYS RGGI allowance cap trajectory.  This will inevitably force RGGI-affected sources to shut down to comply with RGGI creating an artificial energy shortage.

Table 4: Comparison of RGGI Proposed Part 242 Cap and State Energy Plan Pathways Analysis Electric Power Scenario Projections

Conclusion

RGGI must be revised.  The Quarter 2 auction price increase from the previous auction portends future increased allowance costs.  RGGI states have not acknowledged that the costs to consumers are greater than the funds available for investment benefits nor that the alleged benefit claims are weak, so this is affordability pain for no gain.  The allowance cap trajectory is simply incompatible with observed and likely generating resource development that can displace existing resources. RGGI is headed to the point where there are  insufficient allowances to enable sources to run and remain in compliance. This can no longer be ignored because if left unchecked this will lead to an artificial energy storage, 

Three groups must act.  Regulators should revise the RGGI regulations.  The Regional Transmission Operators that operate in RGGI states must revise their planning estimates to incorporate the allowance cap trajectories.  Politicians in RGGI states who are worried about energy affordability should seriously consider dropping out of the program because it is simply unaffordable and risky without major changes.

At the May 6, 2026, Transmission Planning Advisory Subcommittee meeting, the New York Independent System Operator (NYISO) described an update to the 2025–2044 System & Resource Outlook (Outlook) and invited stakeholders to provide feedback on the planned analyses.  This post describes the comments I submitted related to recent Regional Greenhouse Gas Initiative (RGGI) developments and last winter’s extreme weather.  I also filed these comments to Case 15-E-0302 – Proceeding on Motion of the Commission to Implement a Large-Scale Renewable Program and a Clean Energy Standard and Case 22-M-0149 – Proceeding on Motion of the Commission Assessing implementation of and Compliance with the Requirements and Targets of the Climate Leadership and Community Protection Act.

I have extensive experience in two relevant areas: the Regional Greenhouse Gas Initiative (RGGI) and meteorological impacts on electric utility systems, and I based my comments on that experience. The opinions expressed in this post and in my filing do not reflect the position of any of my previous employers or any other organization with which I have been associated; these comments are mine alone.

Background

The NYISO is responsible for electric resource planning for New York State.  The Comprehensive System Planning Process (CSPP) consists of four components: the Local Transmission Planning Process (LTPP), the Reliability Planning Process (RPP), the Economic Planning Process, and the Public Policy Transmission Planning Process. My particular interest is the RPP.

Last December a NYISO update on the CSPP that described the Reliability Planning Process.  It is a two‑year process that starts in even years and has two components. The Reliability Needs Assessment (RNA) “evaluates the adequacy and security of the Bulk Power Transmission Facilities (BPTF)

over a seven-year Study Period (years four through ten of the next ten years) and identifies Reliability Needs defined as violations of Reliability Criteria” established by regulatory authorities.  The System & Resource Outlook is performed in the years between RNA.s  It includes the following:

• 20-year study of system and congestion
• Identifies, ranks, and groups congested elements
• Assesses the potential benefits of addressing the identified congestion
• Provides information to developers and marketplace regarding future challenges in the New York power system

The current analysis covers 2025 to 2044, so it must consider the transition requirements of the Climate Leadership & Community Protection Act (Climate Act).

RGGI

I recently published several articles describing RGGI issues that are relevant to the Outlook.  In the first article, I provided background information on the impact of the April 29, 2026 RGGI statement that Virginia was rejoining the program. In the days that followed, the futures market price of RGGI allowances nearly doubled, and the spot market cost also increased significantly.  In response on May 8, the RGGI states issued a notice that they were monitoring the allowance market in response to a sharp increase in the secondary futures market price.  This is relevant to the Outlook because it indicates that current and future allowance prices, allowance availability, and overall generating unit economics are far more volatile than in the past

RGGI Allowance Availability Risk

My second article compared historical emissions to the current RGGI allowance cap trajectory.  My analysis of RGGI emissions shows that the primary cause of historical emission reductions was fuel switching, and that RGGI emissions have leveled off since 2019, when opportunities for further fuel switching ended. When I analyzed the 2023 RGGI investment proceeds report, I estimated that only about 8% of observed emission reductions could be attributed to RGGI‑funded projects.  Changes to federal policy, supply chain issues, retirement of key nuclear assets, rejection of new permits to build natural gas combined‑cycle units, and inflation coupled with load growth all indicate that significant near‑term reductions in RGGI emissions are unlikely.

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

The RGGI webpage describes the current allowance cap trajectory.  The RGGI states developed the allowance cap trajectory so it would be consistent with state laws that require emissions to go to zero.   As a result, the allowances allotted to the program decline by approximately 10.5 percent of the 2025 budget per year from 2027 through 2033.

To determine when the allowances will run out it is necessary to consider emissions, allowances held in the market and when allowances are added to the market.  RGGI does not provide a report that describes the status of the allowance bank, so I had to develop my own estimate.

The projected trajectory of emissions and allowances is shown in Figure 2. It plots the quarterly emissions (green), allowance cap (dark blue), added allowances (light blue), and allowance balance (orange).  For this analysis, I assumed emissions stay constant.  This analysis estimates that during the third quarter of 2032 there will be insufficient allowances for expected emissions.  Needless to say, the Outlook must account for the potential that generating units will have to shut down to comply with the RGGI regulations well before the Outlook end date of 2044.

Figure 2:  Quarterly RGGI Allowance Balance, Emissions and Allowance Cap

RGGI Market Cost Adder

I was encouraged by electric system experts to write a post and submit comments about the two effects of RGGI allowance prices on customer supply costs: the direct cost of the allowances needed for each generating unit and the impact of the cost adder used by generating units in their bid prices.  My third recent RGGI article estimated the impact of the cost adder relative to recent RGGI allowance price volatility.

The third article provides details so I will not describe the analysis details here.  The impact on consumers is complicated and I did not understand the ramifications until now.  When generating units bid to sell their power in daily auctions, they include the cost to purchase replacement RGGI allowances.  If the clearing price is set by a unit that must comply with RGGI, then the added cost of RGGI allowances is included.  The problem for consumers is that every generating unit gets paid the clearing price.  That means facilities with no RGGI compliance obligations still get paid as if they did.  As a result, they garner windfall profits at the public’s expense.

When allowance costs were low this effect was relatively small, but allowance costs increase when there is uncertainty (like adding Virginia to the program) or there is a scarcity of allowances (like will happen with the unrealistic allowance cap trajectory).  Costs are no longer low and will only go higher.  I estimated the effect of the NYISO market clearing-price adder that is passed through to ratepayers in a range of scenarios that represent possible adder costs. 

Prior to this personal revelation, I was under the impression that the cost to consumers was only the cost of allowances consumed, which in 2025 was about 708 million dollars.  My analysis found that if every fossil unit in New York were a modern state-of-the-art combined-cycle unit then the market costs would add $1.16 billion to consumer bills.  Using average 2025 heat‑input‑weighted data for New York RGGI units, the estimated statewide cost impact is 2.26 billion dollars.  I believe that the true cost is closer to this estimate, which is nearly three times the direct cost of purchasing allowances alone

It gets worse because the windfall profits do not accrue just to New York generators.  All imported electricity delivered to New York is affected by RGGI costs. Imported electricity from outside New York has the same perverse outcome: embedded RGGI costs paid in the exporting state are included in the prices paid by New York consumers.  My analysis does not include these costs, so  I am underestimating the impact of RGGI costs.

When the RGGI announcement that Virginia was going to rejoin the program was made, there was a price spike that approximately doubled the cost of RGGI futures. If futures prices are a good indicator of future allowance prices and that projection is realized, then all of these cost estimates would roughly double.

There is another impact.  The allowances proceeds available for investments are much less than the cost to consumers due to the electric market impact.  In 2025 there were 20,902,887  New York adjusted allowances available and at an average cost of $22.09  that means that $461,797,031 was raised that can be invested for RGGI program objectives.  These results show that the RGGI revenue collections available to reduce emissions and mitigate cost impacts are much less than what ratepayers are paying for the RGGI program.  For all the talk of mitigating impacts to low- and middle-income consumers with RGGI proceeds these results show that regressive RGGI electric market prices likely exceed the benefits of those investments.

This is relevant to the NYISO and Outlook analyses because affordability must be a consideration.  I recommend that NYISO develop refined estimates of the electric market impacts to ratepayers caused by RGGI allowance prices, especially the potential for much higher prices due to market scarcity as the existing allowance bank declines.  I suspect that the models the NYISO use could track all the market costs.  Given the impact of these effects on consumer costs, I requested that NYISO report on the annual and peak market clearing price impacts of RGGI.

2026 Extreme Winter Weather

My comments on the Outlook addressed weather impacts.  My primary meteorological concern is reliability planning related to weather-dependent generating resources. I recently published a blog post that showed that last winter’s extreme weather proved that dispatchable emissions-free resources (DEFR) are necessary to achieve net-zero in New York.  The Winter 2025-2026 Cold Weather Operations presentation by the NYISO is an excellent summary of the conditions observed.

In 2023, Judith Curry and I prepared a white paper titled “Historical Weather and Climate Extremes for New York“.  We noted that there is substantial variability in seasonal temperatures and occurrence of temperature extremes on interannual, decadal, and multidecadal time scales. We also pointed out that the most recent 5-year period used in many NYISO planning analyses does not capture the most extreme temperature events that have been observed in the historical records. We also noted that the possible worst-case scenario could be a 15-day period from January 20 to February 3, 1961,

I recommend that this winter’s January 23–February 9, 2026 weather observations be included in Outlook analyses because the upper‑air pattern was similar to that of the 1961 event.  Including this winter’s event data will capture an extreme temperature event that is necessary to incorporate the impact of weather extremes as wind and solar resources increase.  For example, I considered  proposals to replace peaking units with renewables and storage for last winter’s cold snap. Using the liquid‑fuel generation during the event as a proxy for peaking units, I showed that oil‑fired units supplied roughly 2 million MWh over the episode while total renewable energy production was only 469,308 MWh. The scale of firm backup currently needed is much larger than what can be stored in batteries, meaning that oil-fired peaking units cannot be retired until DEFR backup is available. 

My recommendations stated that the Outlook should address timing for DEFR support.  Given that we do not yet know what DEFR resources will be commercially available before 2044, I believe that the Outlook should emphasize the importance of DEFR to the Climate Act’s Public Service Law 66‑P Renewable Energy Program.  That program mandates renewable resources which, in my view, cannot fully achieve reliability objectives without including DEFR.

Discussion

There is an affordability crisis in New York.  As of December 2024, over 1.3 million New York households were behind on their energy bills by sixty days or more, collectively owing more than $1.8 billion.  In response to the New York State Public Service Commission notice  soliciting comments regarding a petition for a hearing to suspend or temporarily modify the Renewable Energy Program, I demonstrated that the increase in the number of accounts in arrears from 2019 (before enactment of the CLCPA) to 2025 is statistically significantfor statewide totals and for four of the ten utilities.  In that light the unacknowledged RGGI electric market costs must be reconsidered. 

My analysis exposes fatal flaws in RGGI.  A billion dollars in added consumer costs due to an arbitrary accounting decision that gives most generators windfall profits can no longer be ignored.  Those costs are not part of the “dividend” benefits that only accrue when allowances are sold at auction.  The fact that the market costs far exceed the auction revenues means that RGGI is simply a regressive tax. 

Another unavoidable implication is now clear.  The presumption that a binding cap can ensure emission reductions is false.  RGGI emissions have been essentially constant since 2019 despite massive investments.  There should be no expectation that the factors causing emission reductions to stall will suddenly reverse so that emissions begin to match the allowance cap reduction trajectory.   The RGGI states must either modify the cap trajectory or accept that affected generating plants will stop producing power to comply with their rules.

Conclusion

I submitted comments on the NYISO Resource Outlook program because these recent events should be considered in long-range resource assessments.  In my opinion, the NYISO has avoided explicit policy recommendations for too long.  The potential that RGGI requirements will shut down power plants in less than seven years should spur a clear statement that the rule must be changed.  The longer there are no changes, the longer higher costs should be expected due to shrinking allowance availability.  The Outlook is an opportunity to hold policymakers accountable.

On April 29, 2026 the Regional Greenhouse Gas Initiative (RGGI) states announced that Virigina was rejoining.  The original intent of this post was to describe the potential impact of that development, but while doing research it became obvious that the bigger story is the impact of the cost adder for RGGI allowances on the electric market.  On May 8, the RGGI states issued a notice that they were monitoring the allowance market in response to a sharp increase in the secondary futures market price so I am not the only one concerned about this development.

Dealing with the RGGI regulatory and political landscapes is challenging enough 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 details of 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.

Background

RGGI is a market-based program to reduce greenhouse gas emissions from the power sector(Factsheet).   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 rejoining in 2020 and Virginia scheduled to rejoin beginning July 1, 2026.  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. 

Virginia Rejoins RGGI
The RGGI Statement said that, with Governor Spanberger’s approval of Virginia’s regulation reinstating the state’s CO2 budget trading program, Virginia’s participation and compliance obligations will resume on July 1, 2026.  Virginia’s allowance budget for the second half of 2026 will be 11.48 million allowances, and the state will participate in the September 9 and December 2, 2026 auctions.  Virginia will also originate 1.148 million Cost Containment Reserve allowances for the remainder of 2026, and later this year the state will undertake regulatory action to align its program with the Third Program Review and the updated Model Rule by January 1, 2027. 

Cost Impact of Virginia Rejoining RGGI

RGGI allowance costs are driven by basic economic considerations.  When there is scarcity prices increase and when there is uncertainty about scarcity costs also go up.  The difference is that price increases associated with uncertainty can drop when more information is available.  Whereas it is possible that the RGGI plans for the emission cap are so aspirational that scarcity is baked in.  A Perplexity AI review of the Annual RGGI Market Monitor reports describes observed price spikes were associated with the following:

• A regime change in supply (cap adjustment, Cost Containment Reserve (CCR) exhaustion, bank recalculation) alters the scarcity narrative and raises uncertainty.
• That uncertainty interacts with short‑term shocks—Clean Power Plan expectations and nuclear retirements in 2015, cap/bank adjustments in 2021, CCR exhaustion plus an expanded derivatives market in 2024, and the 2025 program review, the Virginia state election, and winter demand expectations in late 2025.
• A growing options and futures market means those shocks are transmitted and sometimes amplified via hedging and speculative flows, which shows up explicitly as higher option‑implied volatility in the RGGI monitor reports.

The price of RGGI allowance futures recently rose sharply after the announcement that Virginia would rejoin RGGI.  There is no publicly available resource describing the price of allowances on the secondary market.  Instead, subscription-based trade news services determine the secondary allowance prices.  The Carbon Pulse article RGGI Market: Historic rally rages over 30% into new week as RGAs breach $40 description stated the following before the article contents were available only to subscribers:

Last week’s surge in RGGI Allowance (RGA) futures carried over into the new week as prices broke all-time highs above the $40 threshold, up more than 30% in the last three days, with traders telling Carbon Pulse it’s unclear where and when the current rally could reach a pinnacle.

RGGI Cost Impacts

Several NYISO market experts have pointed out to me that this is a serious issue that should be addressed.  RGGI costs have two effects on customer supply costs: the direct cost of the allowances themselves for each generating unit and the impact of the cost adder used by generating units in their bid prices.  After a long delay I finally have found time and agree that this needs to be discussed.

In a deregulated electric market such as that run by the New York Independent System Operator, power plants, load-serving entities, and other participants submit competing bids and offers to an auction that determines the least-cost set of resources needed to meet demand while respecting grid limits.  NYISO’s day-ahead energy market is a financially binding, security-constrained auction in which generators, loads, and other participants submit bids and offers for each hour of the following day.  NYISO then runs an optimization that selects the least-cost portfolio of resources from those bids that can reliably meet forecasted demand given transmission limits and unit constraints, and the resulting locational marginal prices are used for settlement. 

A useful way to picture the market is as a stack of generator offers, with the cheapest megawatts at the bottom and progressively more expensive plants piled on top until the stack is high enough to meet NYISO forecast load.  At that point, the most expensive marginal unit needed sets the clearing price for the zone.  If the marginal unit must add a CO2 allowance cost to its bid, then the clearing price rises accordingly, increasing the price paid to all accepted generators in that market interval.  Lower-emitting generators still incur their own allowance costs, but their revenues also increase because they are paid the higher clearing price, and non-emitting units receive the clearing-price increase as pure profit without any direct CO2 compliance cost. 

RGGI Cost Estimate

To calculate the best estimate of the cost of RGGI on the New York electric system, it would be necessary to obtain hourly emissions and operating data for all units participating in the NYISO market.  Unit-specific operating information is proprietary and not publicly available.  For a first-cut estimate, emission monitoring data for RGGI program units were downloaded from the EPA CAMPD database for 2025.  Those hourly data include CO2 emissions, heat input, and gross load, so estimates of heat rate and CO2 emission rate can be derived.  However, this database was not designed specifically for heat-rate analysis, and the hourly values necessarily rely on simplifying assumptions about fuel heat content for emissions-trading purposes.  Nonetheless, the data are indicative. 

Figure 1 plots 2025 annual operating time against annual heat rate for New York RGGI units.  It would be better to plot heat rate against capacity factor, but the EPA data do not include nameplate capacity in a form that can be readily matched to NYISO data.  Three clusters stand out: highly efficient gas-fired combined-cycle units with low CO2 rates (red circle), steam boilers in the middle of the distribution (purple circle), and older simple-cycle turbines with the highest heat rates and CO2 emission rates (dark yellow circle). 

Operating Time for NYS RGGI Units

To illustrate the effect of the RGGI cost adder, the estimates below use annual values as a proxy for the hourly impacts that would ideally be summed across the year.  In 2025, statewide gross energy from New York RGGI units totaled 67,094.6 GWh, those units emitted 32,037,339 tons of CO2, the average quarterly RGGI auction price was $22.09 per ton, and NYISO Gold Book Table III-2a reports total net New York energy of 132,182 GWh.

The direct cost of allowances alone can be estimated by multiplying annual emissions by the average auction price: 32,037,339 tons times $22.09 per ton, or about $707.7 million.  That simple estimate does not account for the effect of the NYISO market clearing-price adder that is passed through to ratepayers. 

Table 1 provides bounding estimates for that market effect.  The first section, “Cost of Allowances for Annual Emissions,” documents the direct allowance-cost numbers just described.  The Annual Total section lists the NYISO total net energy used in the scaling calculation.  The remaining scenarios use observed heat rates and observed CO2 emission rates derived from EPA data to estimate an allowance-cost adder in dollars per MWh, which is then multiplied by total NYISO energy to estimate the statewide annual cost impact. 

Table 1: 2025 New York State RGGI Unit Operating Characteristics &  Emissions, RGGI Allowance Cost, and Consumer Cost Impacts

Using average 2025 data for New York RGGI units, the “RGGI Average” scenario yields an estimated statewide cost impact of $1.39 billion, nearly double the direct cost of purchasing allowances alone. Using the heat input weighted input data, the statewide cost impact would be $2.26 billion.  If every fossil unit in New York were a modern state-of-the-art combined-cycle unit, represented here by the average of the Cricket Valley and Valley Energy Center units, the “Modern CCGT” scenario yields about $1.16 billion.  A representative steam-boiler scenario yields about $1.74 billion.  The worst-case “Old Combustion Turbine” scenario yields about $2.01 billion, although that result is not realistic because it would require an old combustion turbine to be marginal in every hour and every relevant zone. 

Discussion

RGGI allowance prices raise the marginal bid of emitting generators in NYISO, so the allowance “cost adder” lifts the market clearing price on essentially all electricity consumed in New York, causing total costs to ratepayers that can be two or more times higher than the direct allowance expenditures and creating a windfall for non‑emitting “free‑rider” units. In simplest terms assuming that the weighted average heat rate is the marginal heat rate (11,700 mmBtu/MWh), the weighted average emission rate (0.77 tons/MWh), the last auction RGGI closing price ($22), and apply that allowance adder to all delivered MWh (150 TWh) shows that RGGI raises retail bills on the order of $2.26 billion dollars per year at the allowance cost in late March.  The recent price spike doubled this cost increasing this impact of RGGI to $12.3 million a day.   The generators’ direct compliance costs are much smaller, with the difference accruing as bonus money to non‑emitters. It is not yet clear whether the recent spike in RGGI allowance futures will be the new normal or whether it is the result of today’s uncertainty about the impact of Virginia rejoining RGGI. 

RGGI allowance prices from 2009 to 2018 were generally below $5 per ton, but since then both prices and volatility have increased materially (Figure 2).  It is not yet clear whether the recent spike in RGGI allowance futures will be fully reflected in future auction prices.  Importantly, when generating units incorporate the RGGI cost into their market bids they use the current spot market price.  In other words, the impacts of this price spike are showing up in electric prices now.  When the net monthly bills go out if this trend continues there will be a noticeable increase in costs.

Figure 2: RGGI Quarterly Auction Allowance Clearing Prices

Only the NYISO has the proprietary hourly market and unit-commitment information needed to estimate the total consumer impact of the RGGI cost adder with confidence.  Even so, the bounding scenarios presented here indicate that the added cost to consumers is likely substantial and that a significant portion of that added cost appears as windfall revenue to lower-emitting and non-emitting generators. 

The theory that auction revenues support cost-effective consumer benefits typically considers only the direct cost of allowances.  Even if all the allowance auction proceeds were directly returned to customers this analysis shows that when the market-clearing-price effects of the RGGI allowance adder are included consumer impacts will be significant.

Conclusion

My market expert tutors pointed out that the RGGI carbon tax has been ignored for years.  The ultimate beauty of the program is that the costs of RGGI allowances are not visible on electric bills because the allowance costs are buried in the bid prices.  We are sure that the PSC would never allow any information about RGGI allowance costs to be included as information items on electric bills. Ultimately the best tax is a hidden tax.

This issue was reportedly a topic of conversation at NYISO during the early years of RGGI implementation.  Given that allowance prices are now an order of magnitude higher than they were for many years and could go higher still, it is time for NYISO to reconsider the windfall profits that non-emitting units are reaping on the backs of New York ratepayers. 

I submitted comments on the 2025 Operating Plan Amendment (“Amendment”) for the Regional Greenhouse Gas Initiative (RGGI).  This is the sixth time I have comments on Operating Plan amendments and this post summarizes my latest submittal.

Dealing with the RGGI regulatory and political landscapes is challenging enough 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 details of 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

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 but has since withdrawn, and Pennsylvania recently 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.

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.

NYSERDA Operating Plan

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.  The latest Draft RGGI Operating Plan Amendment explains that

 New York State uses RGGI proceeds to promote and implement programs for energy efficiency, renewable or non-carbon emitting technologies, and innovative carbon emissions abatement technologies with significant carbon reduction potential, in accordance with 21 NYCRR Part 507 and in compliance with the Climate Leadership and Community Protection Act (CLCPA).

This year, consistent with authorized RGGI uses, and to highlight the link between RGGI programmatic investments and core state priorities, we have organized our RGGI programmatic investments in terms of four themes, which are the following:

• Affordability: The programmatic investments under this theme focus on creating affordable, efficient, healthy, and comfortable homes and workplaces by deploying commercially available energy efficiency, building electrification, and renewable energy technologies.

• Energy abundance, diversity, and reliability: The programmatic investments under this theme focus on understanding and building out diverse energy options, including responsible renewable generation and storage, as well as modernizing energy system infrastructure, planning, and markets.

• Energy innovation and economic development: The programmatic investments under this theme focus on supporting economic growth and competitiveness, including enabling job, tax revenue, and supply chain growth; stimulating entrepreneurship and company growth in New York; and expanding public-private partnerships and investments.

• Thriving communities and environments: The programmatic investments under this theme focus on helping New Yorkers equitably participate and share in the benefits of the clean energy future; ensuring the energy transition provides meaningful benefits to local communities and disadvantaged communities; and improving climate resiliency and adaptation and public and environmental health.

Investment Priorities and RGGI Compliance

As far as I can tell I have submitted comments on six amendments to the Operating Plan.  Given my decades-long emission and allowance reporting responsibilities in the electric sector, it is not surprising that the primary concern in all my comments has been related to compliance obligations.  In my opinion, NYSERDA ignores the fact that RGGI is not just a pot of money to exploit but is at its core a pollution control program that includes compliance obligations for electric generating units in the program.   This year is particularly important because of the more stringent RGGI caps proposed in the 6 NYCRR Part 242 CO2 Budget Trading Program amendments that I discussed recently.

The compliance challenge is illustrated in Figure 1.  Relative to the three baseline years before RGGI started New York RGGI emission are down 33%.  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, so the main driver of the observed reductions was economic fuel switching.   Also note that this option is not available anymore.

Figure 1: New York State Emissions by Fuel Type

NYSERDA RGGI Funding Emission Savings

The estimated emission savings from historical NYSERDA investments are described in the Semi-Annual Status Report through December 2024.  The description states that:

This report is prepared pursuant to the State’s RGGI Investment Plan (2024 Operating Plan) and provides an update on the progress of programs through the quarter ending December 31, 2024. It contains an accounting of program spending; an estimate of program benefits; and a summary description of program activities, implementation, and evaluation. An amendment providing updated program descriptions and funding levels for the 2024 version of the Operating Plan was approved by NYSERDA’s Board in January 2025.

Table 1 is a copy of Table 1 in the latest full-year Semi-Annual Status Report.  It summarizes the effectiveness of the NYSERDA investments and lists expected cumulative portfolio benefits including emissions savings.

Table 1. Summary of Expected Cumulative Portfolio Benefits through December 31, 2024

Comparison of NYSERDA Cumulative Emissions Savings to Observed Emission Reductions

Table 2 presents the relevant data to compare the observed reductions and NYSERDA RGGI investment emission savings.  I list the last five years of data starting in 2019 when the emissions went up because of the closure of Indian Point.  Reductions from the 2006-2008 average baseline are listed.  The emissions savings listed are cumulative annual emissions.  If the RGGI proceeds were invested, then the total emissions would be higher by the amount of the savings.  The total cumulative annual emission savings through the end of 2023 is only 1,976,101 tons and that represents a reduction of 4.2% from the pre-RGGI baseline.  Emission reductions by fuel type clearly show that fuel switching is the primary cause of reductions.

Table 2: NY Electric Generating Unit Emissions, NYSERDA GHG Emission Savings from RGGI Investments, and Emissions by Fuel Type

New York RGGI Program Investment Reductions

Another finding that has been ignored or possibly covered up by NYSERDA is the poor emission reduction cost effectiveness of NYSERDA investments.  Table 3 lists data from Semi-Annual Status Report through December 2024 Table 2.  The report presents “expected quantifiable benefits related to carbon dioxide equivalent (CO2e) reductions, energy savings, and participant energy bill savings with expended and encumbered funds” but I only considered the CO2e reductions.  Note that the emission savings evaluated in the report include carbon dioxide, methane, and nitrous oxide that are not included in RGGI.  I did not use “lifetime” savings data because I am trying to compare the RGGI program benefits emission savings reductions to the RGGI compliance metric of an annual emission cap.  Lifetime reductions are clearly irrelevant.  The observed cost per ton of emissions savings is $583.

Table 3: RGGI Funding Status Report Table 2: Summary of Total Expected Cumulative Annual Program Benefits

Program Benefit Impacts on RGGI

I categorized programs relative to RGGI compliance obligation support based on the Semi-Annual Status Report through December 2024.  The table breaks down the program allocations and expected annualized CO2 savings for three categories: direct reductions to RGGI sources, indirect reductions, and those programs that will increase electric generating emissions. An example of a program that increases RGGI emissions is NYSERDA’s Clean Transportation Program that “has been pursuing five strategies to promote EV adoption by consumers and fleets across New York”.   The emission reductions claimed are from decreased internal combustion engine vehicles, so the reductions do not reflect reductions in RGGI electric generating units.  In addition, increased electricity for charging will require RGGI facilities to operate more thus increasing their emissions.

The results in the Funding Status reports summarized in Table 4 show that since the start of the program NYSERDA has allocated $101.6 million to programs that directly reduce utility emissions achieving emission savings of 202,422 tons, $1,007.6 million for programs that indirectly reduce utility emissions savings by 1,634,000 tons, and $178.5 million for programs that will increase utility emissions by 395,152 tons.  When emissions savings from non-RGGI sources are removed, total savings are 1,827,575 tons instead of 2,221,757.

Table 4: Summary of Expected Cumulative Annualized Program Benefits through 31 December 2024 for Programs that Directly, Indirectly, or Do Not Affect RGGI CO2 Emissions

Reduction Potentials

I evaluated the potential effectiveness of the proposed funding allocations relative to RGGI compliance support.  I reviewed each proposed program and classified each program into six categories of potential RGGI source emission reductions.  The first three categories covered programs that directly, indirectly or could potentially decrease RGGI-affected source emissions.  I also included a category for programs that will add load that could potentially increase RGGI source emissions such as programs to incentivize electrification.  The two other categories considered programs that do not affect emissions and administrative costs respectively.

The results are in Table 5.  The first three categories cover programs that directly, indirectly, or could potentially decrease RGGI-affected source emissions and account for 53% of investments which is up sharply from the 2025 Amendment which only allotted 31% of the investments. This positive development occurred because Empower+ funding doubled and the Retrofit Challenges Programs funding increased sharply.  Programs that will add load that could potentially increase RGGI source emissions and whose emissions savings are unrelated to the electric sector total 20% of the investments.  Programs that do not affect emissions are funded with 18% of the proceeds and administrative costs total another 9%.  The increased preference for funding that could reduce RGGI emissions is a good development.  On the other hand, Administration costs are 8.8% of the total and programs that have nothing to do with emissions total 18%.  In my opinion, those are programs that should be funded from other sources.

Table 5: Potential for RGGI Reductions for Funding Allocations for 2025 Operating Plan Amendments

RGGI Compliance Summary

Figure 1 shows that no further fuel switching emission reductions are available.  Affected sources have no remaining options to comply with RGGI mandates other than limiting operations.  Future emission reductions are only possible if zero-emission resources displace the generation of RGGI-affected sources.  However, there is a complicating factor that makes emphasis on reducing RGGI-affected emissions more important.  The New York State Department of Environmental Conservation (DEC) recently announced revisions to 6 NYCRR Part 242 – CO2 Budget Trading Program the regulation that sets the New York RGGI allowance cap. 

Comparison of the revised cap starting in 2027 with the New York State Energy Plan shows that in 2029 projected emissions are double the RGGI cap.  Table 10 lists projections starting in 2027 that range from 49.3 to 40.3 MMT.  The 2023 observed emissions from RGGI sources was 28.7 MMT.  Table 6 lists the proposed RGGI cap or limit on tons of CO2 permitted.  There is a big difference between the Pathways Analysis projection and the RGGI cap.  There are some mitigating factors because of the Climate Act accounting methodology, but I believe that the Pathways Analysis emissions are well more than the cap.

Table 6: Comparison of RGGI Proposed Part 242 Cap and State Energy Plan Pathways Analysis Electric Power Scenario Projections

Discussion

My primary concern is that RGGI is an electric sector emissions reduction program.  I have shown that the observed electric sector emission trends indicate that the observed reductions occurred because of fuel switching from coal and oil to natural gas and that there are no more fuel switching opportunities. Therefore, 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. There are programs in the amendment that do not meet these criteria.  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.  

These results should be used to determine funding priorities.  There are significant differences in the expected emission reductions for different programs and that should also be considered when allocating revenues.  While the fraction of funding allocations that could potentially decrease RGGI source emissions has gone up I think that more emphasis is needed to assure compliance and avert compliance problems.

Conclusion

NYSERDA has treated RGGI allowance auction revenues as a convenient slush fund totaling 18% of total funding for whatever politically connected program needs money.  As a result, investments that reduce emissions and support those most impacted by increased costs received less funding.