Category: Regional Greenhouse Gas Initiative

A similar but condensed version of this article was published at Watts Up With That

Regular readers know I have spent this year documenting how New York regulators sell the Regional Greenhouse Gas Initiative (RGGI) as a successful cap-and-invest program while allowance prices climb. Virginia’s return to the program deserves its own post. Governor Abigail Spanberger made affordability the cornerstone word of her campaign, and her energy plan promised to “negotiate the best ratepayer deal to rejoin RGGI.” For a Governor who ran on affordability, the entire Virginia RGGI re-entry process has been shocking.  Incredibly it is even worse than New York.

Virginia’s first auction back in the program cleared at $37.65 per allowance, raising $259 million for the Commonwealth. The last auction before Virginia left cleared at $14.88. Dominion Energy has asked the State Corporation Commission (SCC) to reinstate its RGGI rider at $13.00 per month for a typical residential customer, or $10.36 under its mitigation proposal. When the rider was removed in June 2024 it was $4.43 per month.

This post walks through the decisions that made the deal worse for ratepayers, drawing on the 2026 Virginia Energy Plan (VEP) and a presentation by William Shobe of the University of Virginia and member of the Virginia Air Pollution Control Board, “Explaining the RGGI price path.” Shobe helped design RGGI and is no program critic, which makes his slides especially useful.

This post is based on an outline from an anonymous colleague from the electric utility industry.  I have been involved in the RGGI program process since its inception and frequently write about the details of the RGGI program.  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 help research and draft this post.

Rushing in six months early

The General Assembly did not have to force a mid-year return. The 2025 Model Rule changes take effect on January 1, 2027, and the budget language itself required DEQ to align Virginia’s regulation with the new Model Rule “no later than January 1, 2027.” Instead, the February “caboose” budget, HB 29, directed agencies to repeal the 2023 exit regulation and reinstate the old one within 90 days. Virginia resumed participation on July 1, 2026.

The market noticed. Argus Media reported that the RGGI price rally was “likely kickstarted, at least in part, by news that Virginia would rejoin RGGI as soon as 1 July, six months earlier than what most market participants had anticipated.” Shobe’s slides show secondary prices going from $28.88 on April 13 to $52.88 on May 4 before falling back. The early start also meant that Dominion had to buy allowances in the September auction before its cost-recovery mechanism had been reinstated. Customers will pay for those eight months plus financing, which Appalachian Voices estimated could reach $17 million.

Cutting the 2026 budget in half instead of adjusting for the season

Virginia’s 2026 base budget was simply cut in half, to 11.48 million tons of the 22.96 million tons a full year would have received. Electric-sector emissions are not spread evenly across the year, though. The July–December period includes the summer peak, when fossil units run the hardest. Shobe’s presentation notes that Virginia’s covered sources emitted about 17 million tons in the second half of 2025, roughly 50% more than the six-month budget they were given (Figure 1, Panel A). A seasonally adjusted allocation would have reduced the impact; without one, Virginia came back shorter on day one.

Figure 1: Virginia Allowance Supply vs. Compliance Demand. Budgets from the DEQ Rev. D26 Agency Background Document; Dominion purchase estimate from WTVR’s report on the Dominion SCC filing; second-half 2025 emissions from Shobe (UVA).

Leakage

Virginia is in the PJM RTO.  When Virginia generating units add the cost of purchasing RGGI allowances to their bid prices it makes them less competitive compared to other states like West Virginia.  There is no doubt that this increases overall emissions or leakage.  Table 1 compares statewide emissions for facilities that report gross load and had data available for the third quarter of 2026.  That excluded three facilities for data availability and 12 that report steam load.  If you assume that the cost differential created by the RGGI adder caused all of the changes in quarter 3 between 2025 and 2026 then the upper bound leakage would be 1.9 million tons of CO2, 2,683 tons of SO2 and 1,433 tons of NOx.  This is a gross estimate because I do not have all the data necessary or the time to do it right.

Table 1: Comparison of WV and VA facilities in the third quarter of 2025 and 2026

No stakeholder engagement

Every step bypassed Virginia’s Administrative Process Act (APA). The HB 29 language says that any regulatory action needed to rejoin is “hereby exempted from the provisions of the Administrative Process Act” and is to be completed “without further action by the State Air Pollution Control Board.” The Town Hall record for the reinstatement regulation states: “No comment period held for this exempt action/stage.”

The second rulemaking, Revision D26, sets Virginia’s budgets through 2037 and beyond, and it worked the same way. DEQ said that because the budget bill required it, the action “will not have an associated public comment period.” The DEQ Director adopted it on September 24, 2026, again without Board action. The decision setting compliance costs for every Virginia power plant for the next decade got no public comment, no APA economic analysis, and no citizen-board vote.

“Aligned” to modeling that never included Virginia

The legislation directs DEQ to “align” Virginia’s regulation with the Third Program Review. That review, however, was carried out by the ten states excluding Virginia then participating, and the electricity-sector modeling behind the cap was a ten-state exercise. Even the Virginia Energy Plan labels its cap table “Summary of RGGI Regional Allowance Cap Updates, not including Virginia.”

DEQ  and RGGI’s consultant ICF did not model Virginia. It used a formula. The agency took Virginia’s 2026 budget of 22.96 million tons, which dates to the 2020 regulation, and then followed the RGGI trajectory reductions, cutting 2.55 million tons a year from 2027 to 2033 and 0.73 million tons a year from 2033 to 2037. That leaves 2.19 million tons in 2037. No analysis tested whether Virginia’s fleet can meet that path, or at what cost.

The world has also changed a lot since the program-review modeling was done. Shobe’s slides show that the 2017 cap was set when RGGI generation was modeled to fall about 5% between 2017 and 2031. Dominion’s ten-year growth forecast has since gone from 0.4% to 2.2% to 5.0% a year, and Virginia commercial sales rose 29.6 TWh from 2019 to 2025. On the supply side, the VEP admits that “Virginia’s investor-owned utilities resource additions are not on track to meet the VCEA’s net zero goals.” Higher demand and slower renewable buildout both push allowance demand up.

The final budget also turned out tighter than the one the Energy Plan was built on. The VEP modeled base allowances falling to 2.64 million in 2037. It said that forecast was 99.87% of DEQ’s preliminary revised trajectory, “suggesting a high amount of certainty.” The final D26 rule sets the 2037 base budget at 2,186,667 tons, about 17% lower.

The Energy Plan still depends on natural gas

There is a basic conflict between the cap and the state’s own plan. In the VEP’s Current Policies, moderate load case, Virginia adds about 6.7 GW of new natural gas capacity between 2029 and 2034 (Figure 56), and the plan’s projections keep roughly 13 to 15 GW of natural gas capacity serving the Commonwealth through 2045. According to the VEP, Dominion’s 2025 Integrated Resource Plan calls for roughly 8 GW of new gas, with no fossil retirements, and the company intends to use the VCEA reliability exception to keep units running. Meanwhile, Virginia’s base budget drops from 20.4 million tons in 2027 to 5.1 million tons in 2033. A gas fleet that grows while the cap falls 75% in six years has only one outcome: Virginia buys allowances from everyone else at whatever price the market sets.

No in-state projection of regulated-source emissions

Virginia has never published a projection of what its RGGI-covered sources are likely to emit compared with its budget. The VEP does not provide one either. Its capacity expansion model forced compliance by assuming “Virginia electric utilities will purchase and retire at least all the base and CCR allowances prorated for Virginia.” The plan concedes that the model “is more restrictive than the actual operation of RGGI in the Commonwealth. In reality, Virginia entities could purchase allowances that are allocated to other states.” The question that decides what ratepayers will pay, namely how many allowances Virginia sources will need beyond Virginia’s allocation, was never studied.

Net buyers cannot be sheltered by their own auction revenue

The Governor’s affordability argument depends on the bill credit. The budget sends 45% of RGGI revenue back as bill credits to residential, small business, and church customers. The VEP says these classes “were assigned 41% of the costs related to RGGI compliance,” so they “should expect a net credit.” The Governor said “average monthly bills could drop by as much as $36 annually.”

The arithmetic only works if Virginia sells roughly as many allowances as Virginia sources buy. It does not. Shobe’s slide is titled plainly: “Virginia is likely a net buyer.” Dominion alone expects to buy 51 million allowances from July 2026 through December 2028 at a projected cost of roughly $1.2 billion. Virginia’s base budget for that same period adds up to only 49.75 million tons (Figure 1, Panel B). The cost of RGGI is on the retail side and any imported or clean electricity that serves local load is not covered. It is not about how much is emitted in state vs. how much is purchased.  Instead it is more whether Virginia fossil generation covers the entire footprint to shelter the consumers. Any import or clean generation is still sold at the marginal cost that is a RGGI fossil generator, so RGGI costs are borne by the entire load, and the State is only able to collect from the in-state generation, which is only a percentage of total generation.

Large commercial, industrial customers, and ratepayers from municipal utilities who buy power from independent power producers like Potomac Energy Center are not among the classes receiving the credit, and their higher costs show up in the price of everything Virginians buy. The credit also comes at the expense of the programs RGGI was supposed to fund. The Virginia Mercury notes that the amendment means less money for low-income energy efficiency and flood preparedness, which previously received 50% and 45% of proceeds. Ratepayers pay more to get less of the “investment” used to justify RGGI. As of the October 28 SCC hearing, the method for calculating the credit still had not been finalized.

Scarcity, not speculation

RGGI supporters often blame high prices on speculators, implying prices will fall on their own. Shobe rejects that idea. His slide is titled “Scarcity, not speculation.” Auction 73 drew 65 bidders, with bids at 2.6 times supply. Investor-held surplus fell from 60 million to 37 million allowances between the second quarters of 2025 and 2026, and 71% of allowances in circulation are now held by compliance-oriented entities. “A speculative bubble would show investors accumulating. The data show the opposite.”

He also notes that the Cost Containment Reserve “sold out in the first auction of every year since 2024, so the CCR no longer caps the price,” and that second-quarter 2026 futures traded above the $29.25 Tier 2 trigger, meaning “the market expects both tiers to be exhausted in 2027.” His conclusion: current prices “reflect both increased emission reduction ambition and increased demand growth.”

If high prices come from scarcity, they are structural, not temporary. The cap falls faster after 2027, data center load keeps growing, and the Energy Plan builds more gas. Nothing in the program design brings prices back to 2021–2023 levels.

Is Dominion collecting RGGI twice?

The last issue is one the SCC needs to examine before February 5, 2027. RGGI costs reach customers in two ways. The first is the rider, which recovers what Dominion pays for allowances. The second is the wholesale market. As Shobe explained to VPM, in PJM “any generator that has carbon-intensive generation has to add that RGGI price” to its offer. When an emitting unit sets the locational marginal price (LMP), every megawatt-hour clearing in that interval, including nuclear, solar, and imports, gets paid the higher price.

So the SCC should ask several questions:

• When Dominion’s fossil units clear at RGGI-inflated LMPs, do the extra PJM energy revenues fully flow back to customers as an offset to Rider RGGI, or does the rider recover allowance costs that the market has already paid?
• How much of the RGGI cost built into LMPs reaches Dominion customers through power purchased from merchant Virginia units and through the roughly 30% of Virginia’s electricity that is imported? None of that is counted in the rider or offset by the credit.
• How much of the higher wholesale price is simply a windfall for non-emitting generators that never buy an allowance?

In my New York work, counting that wholesale-market effect roughly doubles the consumer cost compared with counting direct allowance purchases alone. Virginia’s $10-to-$13 rider debate leaves that half of the cost out entirely.

What an affordability Governor should have done

A Governor who meant what she said about affordability would have waited until January 1, 2027, when the new Model Rule takes effect. She would have run the rulemaking through the Administrative Process Act with a real economic analysis and published a projection of Virginia’s covered-source emissions against the budget before agreeing to a trajectory that assumes Virginia is like New England. She would have required the SCC to account for the wholesale-price effect before telling families the credit makes them whole. None of that happened. Virginia rushed in at the worst possible time, accepted a cap built for other states, skipped every public check, the program is shifting generation to West Virginia units that emit more pollutants and is presenting a partial refund of its own residents’ money as a savings program.

Governor Spanberger promised to negotiate “the best ratepayer deal.” As far as I can tell, there was no negotiation and there is no deal. Virginians are left with a higher bill and a credit that can’t cover it.

Governor Hochul also ran on an affordability platform.  Unfortunately, the hypocrisy of her claims relative to her energy affordability record did not make a difference with New York voters. 

New York’s support for the Regional Greenhouse Gas Initiative (RGGI) emphasizes what the State does with auction proceeds: “The State invests RGGI proceeds to support comprehensive strategies that best achieve the RGGI CO2 emission reduction goals.” In addition, the State claims significant energy bill savings from those investments that offset the costs of the program.  However, the ratepayer costs do not reflect just the money spent for allowances at the auctions. When an investor buys an allowance and later resells it at a higher price, the additional payment does not fund New York’s programs. That distinction deserves more attention in the State’s affordability analysis.

I have been involved in the RGGI program process since its inception.  I blog about the details of the RGGI program because I think it is over-rated.  In this post, I examine the distinction between auction revenue and allowance costs, what the market-monitor reports show about investor participation, and what those findings mean for claims that RGGI benefits offset its costs.  The opinions expressed in this post do not reflect the position of any of my previous employers or any other organization I have been associated with. These comments are mine alone. I acknowledge the use of Perplexity AI to generate material included in this document.

Background

RGGI requires covered power plants to obtain allowances for their carbon dioxide emissions. Generators can acquire allowances at quarterly auctions or in the secondary market. They can also bank allowances for future compliance. Participation is not restricted to generators: firms without compliance obligations can buy and hold allowances too.

New York’s RGGI funding status report emphasizes the benefits of investing auction proceeds. The Revised Regulatory Impact Statement says that proceeds support energy efficiency, renewable and clean energy, and other carbon-abatement investments. Its bill-impact analysis models investment benefits as a credit against electricity bills. The projected residential bill reduction of $0.24 per month appears only after accounting for those benefits.

There is an important distinction between that revenue and the costs reflected in electricity prices. New York receives the auction clearing price for each allowance it sells. A subsequent transaction does not generate another payment to the State. If an allowance originally sold for $20 changes hands later for $40, the additional $20 is not available for State-administered efficiency programs or consumer benefits.

That is the gap examined here: allowance-related costs can increase without a corresponding increase in the proceeds available to fund the benefits emphasized in the regulatory analysis.

Who Is Buying the Allowances?

The independent RGGI market monitor, Potomac Economics, distinguishes among compliance-oriented entities, investors with compliance obligations, and investors without compliance obligations. That distinction matters. A generator buying allowances beyond its expected compliance needs can also participate as an investor. Consequently, “compliance entity” and “compliance-oriented entity” are not interchangeable categories.

The auction reports (Table 1) show substantial purchases by firms other than compliance-oriented entities.

Table 1: RGGI Auction Report Summary

*The investor share is calculated as 100% minus the reported compliance-oriented share. The final column is 100% minus the reported compliance-entity share. Figures are regional, not New York-specific.

Across these six auctions, investors bought between 43% and 53% of the allowances offered. Firms without any compliance obligation bought between 35% and 47%. These are not incidental participants. They account for a substantial share of auction purchases.

The holdings data tell a similar story. At the end of the second quarter of 2026, approximately 178 million allowances were in circulation. Potomac estimated that about 141 million were held for compliance, leaving approximately 37 million held for investment. Investment holdings had declined from approximately 60 million a year earlier. That decline is consistent with investors drawing down their holdings, although it does not establish the purchase price, resale price, or profit on individual transactions.

Auction Prices and Secondary-Market Prices Are Different

The second-quarter market report (Table 2) provides a useful comparison. The secondary-market figures are volume-weighted averages. The physical-transfer series comes from the RGGI CO2 Allowance Tracking System, known as COATS. The ICE futures price for RGGI allowances is the price quoted on the Intercontinental Exchange (ICE) for a contract to deliver RGGI carbon dioxide allowances at a specified future date.

Table 2: RGGI Allowance Price Measures

In the second quarter of 2026, the average physical-transfer price exceeded the auction clearing price by $5.78 per allowance. The market monitor reported that secondary prices approached $44 before the June auction, which cleared at $35, and ended the quarter near $43. Approximately 21 million allowances were physically transferred between unaffiliated firms during the quarter.

These comparisons require care. A quarterly average and an individual auction price do not represent matched purchases and sales. Their difference is not a direct measure of investor profit. Nevertheless, they demonstrate why auction prices alone do not describe the prices faced by generators obtaining allowances in the secondary market.

How the Difference Reaches Electricity Customers

The relevant cost for electricity-market offers is not necessarily what a generator paid at an earlier auction. A generator purchasing an allowance in the secondary market uses the current purchase price. A generator using an allowance already in its account also faces an opportunity cost: using it means giving up the ability to sell it or retain it for future use.

The Quarter 2 2026 NYISO market monitor report attributed an approximately $9-per-megawatt-hour increase in marginal production costs to an approximately $20-per-ton increase in RGGI prices since the second quarter of 2025. Over that period, the reported ICE futures average rose from $19.98 to $40.75, an increase of $20.77. The auction clearing price increased by a smaller amount, $15.37. The comparison is consistent with current market values, rather than historical auction expenditures alone, influencing generation costs.

That does not mean every dollar of wholesale-market impact becomes investor profit. Nor does every increase in production costs translate immediately or identically into every retail bill. The primary point is that the allowance value affecting electricity prices can exceed the proceeds received when the State originally sold the allowance.

What Might the Difference Be Worth?

Consider three illustrative allowances, each hypothetically resold at the second-quarter 2026 average physical-transfer price in Table 3.  These are examples, not documented trading histories. The purchase and resale prices of a particular allowance are not established by these averages.

Table 3: Example Allowance Price Differences

Applying the reported investor shares to Auctions 68 through 71 gives approximately 33 million allowances purchased at a weighted-average auction price of $23.72. If that quantity were subsequently sold at $40.78, the gross difference would be approximately $563 million.

That is not an estimate of actual profits, a New York ratepayer cost estimate, or a demonstrated upper bound. It is a hypothetical calculation showing the scale of the potential difference. Actual results depend on which allowances were sold, when they were sold, transaction and financing costs, and other trading positions. Investors also bear the risk that prices will fall.

Discussion

Investor participation is not, by itself, evidence of market manipulation. Investors can provide liquidity, accept price risk, and potentially increase auction proceeds through their bids. Banking also gives generators flexibility in meeting future obligations. Those considerations belong in a balanced assessment.

I have two concerns.  First is the accounting used to defend affordability. New York emphasizes the benefits of investing auction proceeds. Those proceeds are not the same thing as the full allowance-related costs influencing electricity prices.  My second concern is that the investors who purchased allowances in the last year are not dumb.  They know allowances are going to get scarcer and that someday compliance entities are going to need the allowances they hold so they expect to make profits.  I believe that means that the current allowance market price will never decrease significantly so the gap described here is the new normal.

Conclusion

The State’s affordability claims should distinguish three things: auction revenue, allowance-related electricity costs, and the benefits attributed to spending the revenue. They are related, but they are not interchangeable.

The available figures show substantial investor participation and secondary-market prices above earlier auction prices. They do not establish actual investor profits or New York-specific resale costs. They do establish a reason to demand a transparent reconciliation between what customers pay and what the State receives.

DEC and NYSERDA should explain whether their analysis captures secondary-market allowance values, how those values affect modeled electricity prices, and how the resulting costs compare with the auction proceeds available for investment.

Auction-funded investments may provide benefits. But pointing to those investments does not answer the separate question of how much allowance-related cost electricity customers ultimately bear.

On October 15, 2026, the New Jersey Department of Environmental Protection (DEP) and Board of Public Utilities (BPU) held a joint hearing on the price of Regional Greenhouse Gas Initiative (RGGI) allowances. The most important testimony came from the owner of the largest and cleanest fleet of power plants in the state. Liam Baker, Senior Vice President of Regulatory Affairs for Alpha Generation (AlphaGen), told regulators that high RGGI clearing prices put New Jersey’s efficient plants “at a significant competitive disadvantage to coal-fueled and otherwise less efficient, and higher emitting, resources in upwind states such as Pennsylvania, West Virginia and Ohio – states that are not part of RGGI.” NJBIA summarized the hearing under a blunt headline: “How RGGI Now Incentivizes Dirtier Air in NJ.”

That is emissions leakage, and it is no longer a theoretical concern raised by program skeptics. It is a New Jersey generator telling its regulators that the program is shifting output, and emissions, to plants across the border. New York faces the same problem. This post summarizes the New Jersey testimony, explains why the same mechanism applies to New York, and describes my preliminary estimates of the RGGI leakage monitoring metric for New York for 2024 and 2025, two years that RGGI has not yet reported.

I have been involved in the RGGI program process since its inception and have been writing 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. The opinions expressed in this post do not reflect the position of any of my previous employers or any other organization I have been associated with. These comments are mine alone. I acknowledge the use of Perplexity AI to generate material included in this document.

Background

RGGI is a market-based program to reduce greenhouse gas emissions from the power sector. It has been a cooperative effort among Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New York, Rhode Island, and Vermont since 2008, with New Jersey rejoining in 2020.  Virginia rejoined beginning July 1, 2026 and Pennsylvania recently decided not to join.  According to the RGGI program description, the states issue permits to emit a ton of CO₂ or allowances that are distributed almost entirely through regional auctions, and the proceeds are then reinvested in strategic energy and consumer programs.

That is the root of the leakage problem. RGGI’s borders are political, but the grid is not. New Jersey shares the PJM Interconnection with Pennsylvania, Ohio, and West Virginia, which are not in RGGI, and New York imports power from PJM, New England, Ontario, and Québec. When the allowance price rises, the RGGI unit’s bid rises and the non-RGGI unit outside the region is unaffected, so the non-RGGI unit runs more. If that unit burns coal and the RGGI unit is an efficient combined cycle, emissions go up, not down.

That price signal has grown dramatically. Auction 73 in September 2026 cleared at a record $37.65, up 296 percent from $9.30 in September 2021, the Cost Containment Reserve intended to keep prices low is exhausted, and the cap will be cut more than 10 percent per year from 2027 through 2033. Every one of those factors widens the cost gap between RGGI and non-RGGI generators.

What New Jersey heard

The New Jersey hearing deserves attention because of who was testifying. According to NJBIA, AlphaGen owns and operates about 4,000 MW of baseload, mid-merit and peaking generation, the largest fleet in New Jersey and also its cleanest and most efficient. This is not a coal company looking for relief. It is the type of company RGGI supporters claim the program rewards.

Baker made three points. First, RGGI costs “must be included in the price of power,” which raises costs for New Jersey consumers. Second, those costs make New Jersey’s cleaner plants “run less than the ostensibly ‘cheaper’ upwind and higher emitting power plants in those non-RGGI states.” Third, the result is that RGGI “has inadvertently led to New Jersey suffering from millions of tons of increased pollution every year,” pollution that New Jersey bears the brunt of because it is downwind of the non-RGGI states.

As an air pollution meteorologist, I want to emphasize that last point. Leakage is usually discussed as a CO₂ accounting problem, but a coal plant in western Pennsylvania or Ohio that runs more hours also emits more sulfur dioxide, nitrogen oxides, and particulate matter. Prevailing winds carry those emissions east. A program that shifts generation from a New Jersey combined cycle to an upwind coal unit is not just failing on carbon; it is making air quality worse for the people it is supposed to protect.

NJBIA’s “Rethink RGGI” campaign proposes replacing the auction price with a $7-per-ton allowance charge, which NJBIA’s Ray Cantor said could save New Jersey consumers $279 million a year. Cantor also questioned a DEP proposal to implement the latest RGGI Program Review amendments that cut allowances 90 percent over ten years amid capacity shortages and rising demand. His summary is one I agree with: “RGGI can’t just operate in a vacuum. It must be reevaluated, re-thought, in the context of the region, the need for capacity, the competition from non-RGGI states, and growing demand for energy.”

Independent modeling confirms the mechanism

The AlphaGen testimony is consistent with the independent analysis I described in June. Tabors Caramanis Rudkevich (TCR) simulated PJM with Delaware, Maryland, and New Jersey in RGGI at $20 per ton. Combined-cycle gas generation fell 6,850 GWh while coal rose 5,220 GWh. Emissions fell about 3 million short tons in the RGGI zones but rose 5.7 million elsewhere in PJM, a net increase of 2.7 million short tons per year. That was at $20 per ton; at $37.65 the leakage should be larger.

New York’s own regulators have modeling that shows the same thing, even though they did not say so. I reconstructed the comparison from the tables in the Department of Environmental Conservation (DEC) Regulatory Impact Statement for the August 2026 Part 242 amendments. Across the five modeled snapshot years, the increase in emissions in the rest of the Eastern Interconnection offset about 76 percent of the reductions at RGGI plants in one policy case and 72 percent in the other. Those are my calculations, not figures DEC reported, and they were modeled at $8.55 to $28.20 per ton (2022 dollars), well below today’s prices.

Why New York should be paying attention

New York is not in PJM, but every New York RGGI unit competes with PJM imports, so the cost gap AlphaGen described applies here too. New York law is also more explicit than RGGI about leakage. The Climate Leadership & Community Protection Act defines leakage as a reduction in emissions in the state that is offset by an increase outside the state, and ECL § 75-0109(3)(e) directs DEC to “incorporate measures to minimize leakage” when it promulgates Climate Act regulations. DEC’s Regulatory Impact Statement for the RGGI amendments relied on the RGGI electricity monitoring reports to claim there has been “no clear evidence” of leakage. However, the 2023 monitoring report itself states that “this report does not provide indicators of CO2 emissions leakage” and that its results “do not address causality.” DEC did not update its leakage analysis after allowance prices jumped.

New York leakage estimates for 2024 and 2025

The RGGI electricity monitoring reports track one metric that comes closest to measuring leakage: CO₂ emissions from all non-RGGI generation serving load in the region. For New York that includes in-state generation that is not subject to RGGI, such as waste-to-energy, landfill gas and small fossil units, plus net imports from PJM, Ontario, Québec, and New England. The most recent report covers 2023 data and was not released until December 2025. RGGI is two years behind, and the two missing years are exactly the period when allowance prices took off.

I estimated the NYISO version of this metric for 2024 and 2025 using NYISO Gold Book generation and import data and published emissions rates for the neighboring regions. Before extending the series, I tested the method against RGGI’s published 2023 NYISO numbers. It matched within 0.26 percent on generation and 0.03 percent on CO₂. Table 1 lists the results.

Table 1: CO₂ from Non-RGGI Generation Serving NYISO Load

NYISO metric	2006–08 baseline	2023 (RGGI)	2024 central (range)	2025 central (range)
Non-RGGI generation serving load (million MWh)	95.1	85.5	84.0	81.7
CO₂ (million short tons)	11.3	9.5	9.5 (8.4–10.2)	10.5 (9.3–11.2)
Emission rate (lb/MWh)	237	221	226 (201–242)	257 (228–275)
CO₂ from net imports (million short tons)	7.9	7.0	7.2	8.1

Sources: RGGI 2023 Electricity Monitoring Report; NYISO Gold Books; EIA, ISO-NE, and Environment and Climate Change Canada emissions data; my calculations. The 2025 emissions rates are extrapolated.

Three results stand out. First, CO₂ from non-RGGI electricity serving New York load was flat in 2024 at about 9.5 million tons but rose to about 10.5 million tons in 2025, the highest level since 2010. Second, the 2025 emission rate of 257 lb/MWh is higher than every year in the 2006–2008 baseline period, even though the amount of non-RGGI generation serving load fell. Third, emissions from net imports rose to about 8.1 million tons in 2025, slightly above the baseline average, even though import volumes declined. The non-RGGI electricity New York uses is getting dirtier.

Figure 1 puts the estimates in the context of the full RGGI record. Emissions from non-RGGI sources serving New York load bottomed out in 2020 and have risen every year since.

Figure 1: CO₂ from Non-RGGI Generation Serving NYISO Load, 2006–2025

The 2006–2023 values are from the RGGI electricity monitoring reports. The 2024 and 2025 values are my preliminary central estimates, with error bars showing the low-to-high range.

What is driving the increase

I want to be careful here, because I have criticized RGGI supporters for claiming credit for emission reductions that were caused by other factors. The same standard applies to me. The 2025 increase has identifiable causes that are not necessarily RGGI. New York swung from a net importer of Québec hydropower in 2023 (+2.7 TWh) to a net exporter in 2025 (−4.9 TWh). In-state hydro output fell to 24.3 TWh. Imports from PJM rose to 21.7 TWh, while PJM’s emissions rate also climbed. Lower hydro availability and more PJM imports explain most of the change.

That said, the PJM piece is exactly the piece that AlphaGen and TCR describe. Using my central estimate of the non-RGGI PJM emissions rate (881 lb/MWh in 2025), imports from PJM alone carried roughly 9.5 million tons of CO₂ into New York’s load in 2025. That is larger than the 8.1 million tons of total net import emissions because exports to New England and Québec are netted out of the total. The point is that New York’s growing dependence on PJM imports means its non-RGGI emissions are increasingly tied to the coal and gas fleets of Pennsylvania, Ohio, and West Virginia, the same plants that are gaining market share from RGGI generators in New Jersey.

The monitoring metric does not prove that RGGI caused the 2025 increase. But the cost gap between New York RGGI generators and PJM non-RGGI generators widened sharply in 2026 and will widen further as the cap tightens. I expect leakage to be visible in the 2026 and later data. Waiting two years for RGGI to tell us is not an appropriate policy.

Problems with the RGGI monitoring numbers

These estimates exposed two problems with the RGGI reports. The non-RGGI PJM emissions rate RGGI uses (866 lb/MWh in 2023) is not documented well enough to reproduce, yet it is the most important input; the choice of PJM rate alone moves my 2025 estimate by about 1.5 million tons. RGGI has also used an Ontario import rate of 17 lb/MWh since 2020, while Canada’s national inventory shows 119 lb/MWh for 2023 and 143 for 2024. Using the inventory values would add about 0.4 million tons in 2025. If regulators cite these reports as evidence against leakage, the inputs should be current and transparent.

Discussion

The New Jersey hearing should end the argument that leakage is hypothetical. New Jersey’s cleanest generator testified that RGGI is displacing its plants with upwind coal units, independent modeling found a net emissions increase in PJM, DEC’s own tables show most RGGI-region reductions reappearing outside the region, and the non-RGGI electricity serving New York got dirtier in 2025.

None of this is surprising. RGGI’s historical reductions came mostly from cheap natural gas displacing coal and oil, when the allowance price was too low for the border to matter. Those conditions are gone.

Further reductions mean running gas plants less, and if imports from non-RGGI coal and gas units fill the gap, the CO₂ is emitted somewhere else, often upwind, along with the conventional pollutants.

The affordability consequences are just as clear. When a RGGI unit sets the clearing price, the allowance cost is paid to every accepted generator, so New York consumers pay roughly two or more times the direct allowance cost for a program that, at current prices, may be shifting emissions rather than reducing them.

Conclusion

New Jersey regulators are at least asking whether RGGI prices are hurting consumers and the environment. New York regulators are not. DEC and NYSERDA adopted the Part 242 and Part 507 amendments in August without updating their leakage analysis for current allowance prices, without addressing the statutory requirement to incorporate measures to minimize leakage, while relying on monitoring reports that explicitly disclaim any ability to identify leakage.

At a minimum, DEC should update its leakage analysis at current and projected allowance prices, including New York imports from PJM, and the RGGI states should publish the monitoring metric within a year with transparent, current import emissions rates. New York should also acknowledge what New Jersey’s largest clean generator has already said: RGGI, in its current form, raises costs and can increase emissions. When the cap tightens faster than the fleet can change, the emissions do not go away. They move across the border, and New Yorkers pay for the privilege.

Governor Hochul has said that affordability comes first, however this post shows that her Regional Greenhouse Gas Initiative (RGGI) record says otherwise.  In early September I posted an article about the impact on consumer costs that I fully documented.  This post revises my cost estimates using the Potomac Economics report “Quarterly Report on the New York ISO Electricity Markets Second Quarter of 2026” that includes data that I previously had to assume. It also adds complete 2025 data and the results of the September 2026 RGGI auction.

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

Background information about RGGI is available here.  I have also revised the technical support document provided earlier that explains the calculation methodology and provides cost background information.

The affordability claim meets reality

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

On the RGGI allowance price alone, the answer is not close. When Hochul took office in late August 2021, the most recent completed auction — Auction 52 on June 2, 2021 — had cleared at $7.60 per ton. The first auction after she became Governor, Auction 53 in September 2021, cleared at $9.30. Auction 72 on June 3, 2026, cleared at $35.00 per allowance. The most recent completed auction as of this writing, Auction 73 on September 9, 2026, cleared at $37.65 per allowance for total regional proceeds of about $1,074.4 million.  New York proceeds were $262.4 million on the sale of 6,970,201 allowances. At the time this was written, the secondary market for RGGI allowances is trading above $37.00 per allowance.

Measured from the first full auction of her tenure, that is an increase of $28.35 per ton, or 305% over a five-year period. The RGGI carbon price has multiplied more than four times over on her watch, and it did so with the active participation of the state agencies she oversees — Department of Environmental Conservation (DEC), New York State Energy Research & Development Authority (NYSERDA), and the Department of Public Service (DPS), all of which take part in RGGI program design, auction administration, and the decisions that determine how aggressively the RGGI allowance cap is tightened.  There is no doubt that the recent price rise is related at least in part to the recently approved DEC amendments that mandate an arbitrary auction cap reduction consistent with state laws but are inconsistent with emission reductions that can be expected from RGGI auction revenue investments.

RGGI consumer costs

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

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

What the Potomac report changed

My earlier estimate had to assume which types of units set the wholesale price. Because NYISO does not publish the price-setting unit for each interval, I originally assumed that modern combined cycle units set the price 60% of the time, gas-fired boilers 35% of the time, and oil-fired combustion turbines 5% of the time, and that a RGGI-affected unit set the price in every hour. The Potomac Economics quarterly report describes how often each fuel type is the marginal unit in the real-time market. In the first quarter of 2026 natural gas combined cycle units were marginal in 67% of intervals and oil units in 19%. In the second quarter combined cycle units were marginal in 84% of intervals, other gas units in 28%, hydro in 25%, wind and solar in 24%, and oil in none. The percentages add up to more than 100% because more than one unit can be marginal when transmission constraints bind.

Two conclusions follow. First, oil units matter in some seasons and not others, so a fixed annual share is not appropriate. Second, RGGI-affected units do not set the price in every hour, so applying a RGGI cost to all the energy used in New York overstates the cost. I revised the spreadsheet to address both points. For each year I used EPA Clean Air Markets data for New York’s RGGI units to calculate the average operating hours of five unit types: modern combined cycle units, gas-fired and oil-fired boilers, and gas-fired and oil-fired combustion turbines. I assumed that the most expensive type of unit operating sets the price during its operating hours, the next most expensive type sets the price for its additional hours, and so on down to the combined cycle units. The rest of the year, between 25% and 33% of the hours depending on the year, is assigned to hydro, imports, renewables, and nuclear with no RGGI cost at all. Each unit type’s RGGI cost is its CO2 rate times the allowance price, applied to its share of the Gold Book total energy.

Potomac uses the same calculation for the equivalent energy cost of RGGI: the allowance price times the emission rate times the heat rate. It reports that the roughly $20 per ton increase in RGGI prices from the second quarter of 2025 increased marginal production costs by about $9 per MWh. Using Potomac’s natural gas emission factor of 0.059 tons per mmBtu and an efficient 7,500 Btu/kWh gas unit, $20 × 0.059 × 7.5 = $8.85 per MWh, so my approach is consistent with the market monitor’s. I think the new central estimate is conservative. My approach has combined cycle units setting the price in only 37% to 47% of the hours, while Potomac found them marginal in 67% to 84% of intervals in the first half of 2026. I also included a fleet-average estimate that assumes the average RGGI unit sets the price in all hours as an upper bound.

Table 1 lists the total annual estimated RGGI costs. The NYSERDA and DEC analyses only go through 2024, but complete emissions and auction data are now available for 2025, so my estimates run through 2025. I also projected a 2026 cost using the Auction 72 $35 allowance price and average 2023–2025 operating data. The Administration messaging only considers the cost of allowances sold in auction – the total direct RGGI allowance cost row. As described in the Technical Support Document I also calculated estimates that include the variable operating costs in the wholesale electric market. The Potomac-informed marginal units row is my central estimate. The fleet average row is an upper bound that assumes an average RGGI unit sets the price in every hour. When the wholesale market costs are included, the central estimate is about 50% higher than the direct allowance cost and the upper bound is about double, and costs are rising steeply (Figure 1). Between 2021 when Hochul took office and 2025 the central estimate of annual RGGI costs increased $630 million, or 2.5 times. Holding everything else constant at the Auction 72 $35 allowance price, the 2026 central estimate is $1,587 million, 3.8 times the 2021 cost. At the Auction 73 price of $37.65 it would be $1,707 million.

Table 1:  Total Annual RGGI Costs($ millions)

Notes: 2026 uses 2023-2025 average energy and generation-weighted unit rates. 2026 YTD average = Auctions 71-73. Results scale linearly with price.

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

I also estimated the annual cost to residential customers. A typical New York residential electric customer uses approximately 570 kWh per month (about 6.8 MWh annually). Table 2 lists the annual estimated RGGI costs for residential consumers. The direct allowance cost row spreads the total direct allowance cost over all the electricity used in the state. If the only costs considered are the direct cost of allowances, the estimated costs are substantially lower than when the wholesale electric market costs are included. For example, in 2025 allowance costs were $37 a year, but the central estimate of the total cost was $54 and the upper bound was $73. Between 2021 when Hochul took office and 2025 the central estimate of residential annual RGGI costs increased from $23 to $54, or 2.4 times. Holding everything else constant at the Auction 72 $35 allowance price, the 2026 central estimate is $85 a year, 3.7 times the 2021 cost, and the upper bound is $117. That represents 5.1% to 7.0% of a typical residential electric bill. At the Auction 73 price of $37.65 the range is $91 to $125 a year. This continues a trend (Figure 2) that I expect to continue to grow.

Table 2: Annual Residential Cost of RGGI ($)

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

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

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

The contradiction Hochul has not had to answer

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

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

Discussion

In my opinion, the cost of RGGI allowances is another buried cost of the clean energy transition that very few people know about. In 2025 the impact of RGGI allowances accounted for $54 to $73 per year, or 3.2% to 4.3% of a typical residential electric bill based on the most recent EIA data ($139.53 per month in 2024). Projecting the latest sharp rise in allowance prices raises the costs to $85 to $117 per year, or 5.1% to 7.0% of a typical residential electric bill. At a time when there is an energy affordability crisis it is fair to ask whether New Yorkers are willing to pay for this program?

If the Administration wants to prove a positive benefit/cost ratio then they should request that NYISO provide the wholesale market impact calculated with the hourly data that only they have. For the benefits they should only consider savings actually returned to consumers, broken out from savings that are committed but not yet delivering measured savings. They should also only include verified, evaluated-and-measured bill savings — not modeled lifetime projections — compared against the total full cost.

Conclusion

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

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

That mismatch matters because RGGI is fundamentally a power-sector compliance program, not simply a source of funding for otherwise worthwhile State initiatives. If allowance costs are adding 5% to 7% to residential electric bills, then New York should be able to demonstrate that the revenues are being directed first to cost-effective measures that reduce emissions from RGGI-covered sources, lower customer bills, and help maintain reliable compliance with an increasingly stringent cap.

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

On September 9, 2026, Acadia Center published a fact sheet titled “Regional Greenhouse Gas Initiative (RGGI) Impacts in ISO New England: Setting the Record Straight on Costs and Benefits.” Its “bottom line” is that RGGI is a $4-to-1 winner for New England ratepayers — $445 million in 2025 auction proceeds projected to return $1.3 billion in lifetime energy-bill savings, comfortably beating the $815 million ISO-NE estimates RGGI added to 2025 wholesale costs. The fact sheet closes by urging ISO-NE states to keep championing the program and to finish implementing the Third Program Review’s tighter caps.

I have spent the summer documenting exactly this kind of accounting in New York, where the Department of Environmental Conservation (DEC) and New York State Energy Research & Development Authority (NYSERDA) defended the same Third Program Review amendments with a “nearly 6-to-1” ratepayer savings ratio. Acadia’s fact sheet uses the identical structure — a modeled, lifetime, participant-side savings figure set against a single year of narrowly defined cost — and it does so in the same week that RGGI’s own auction results undercut its “manageable costs” framing. Setting the record straight requires looking at both halves of the ledger, not just the half that makes the program look good.

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

Bad timing: Auction 73 landed the same day

Acadia’s fact sheet is dated September 9, 2026 — the same day RGGI held Auction 73. The results came out two days later: a clearing price of $37.65 per allowance, up $2.65 from Auction 72’s $35.00 record set just three months earlier, and up 296 percent from the $9.30 clearing price at the first full auction of Governor Hochul’s tenure in September 2021. The top bid at Auction 73 was $190 per allowance — five times the clearing price — which is not what a market in balance looks like. I covered this in RGGI Auction 73: The Clearing Price Question Is Answered, following up on RGGI Update and the Auction Clearing Price Question.

Acadia’s fact sheet was written before the auction set its second consecutive record high, with the program’s own price-relief mechanism — the Cost Containment Reserve (CCR) — already exhausted for the year by the March 2026 auction. A fact sheet arguing that RGGI’s costs are modest and well-managed needed to grapple with that trajectory. It doesn’t mention it at all.

The core accounting problem: modeled lifetime savings vs. one year of cost

Acadia’s $1.3 billion savings figure is explicitly a projection, not a measured result. Its own Endnote 3 says so: “2025 investment and outcomes data are not yet available, this analysis applies real data from [the] 2024 report”.  The reports calculates the ratio of proceeds each state invested in each program category, and the lifetime savings each ratio historically returned — to 2025’s actual proceeds total. In other words, Acadia took last year’s return ratios and multiplied them by this year’s revenue. That’s a projection built on an assumption of continuity, not a report of what actually happened.

This is the same structural move the DEC and NYSERDA made when they defended New York’s RGGI amendments with a “nearly 6-to-1” ratio: $12.334 billion in what NYSERDA itself labels “Energy Bill Savings to Participating Customers” against $2.188 billion invested. When I went through the Technical Support Document behind that number, the qualifications mattered enormously. The $12.334 billion figure is a modeled, expected-lifetime estimate. It includes projects still in the pipeline that are not yet operational. It has generally not been adjusted through evaluation, measurement, and verification (EM&V). And it is compared only against historical program expenditures, not against the revenues collected or the program’s full cost. Acadia’s multipliers — 4.5x for energy efficiency, 8.2x for clean energy, 1.22x for electrification, 1.0x for bill assistance — are the same kind of lifetime, model-derived ratio, applied here to a single year of proceeds rather than verified against actual outcomes.

Acadia also compares apples to oranges on the timing. The $1.3 billion is a lifetime figure — savings that compound over the 15-to-20-year measure life of efficiency and clean-energy programs. The $815 million cost is a single year, 2025 only value. Stacking a multi-year benefit stream against one year of cost is not a real return-on-investment calculation; it overstates the ratio by construction. A colleague of mine, who prefers to remain anonymous, framed the broader problem well: this kind of program takes a dollar from the consumer now and returns a fraction of that dollar’s value later, through delayed and partially administered programs — with people who don’t qualify, can’t front the upgrade cost, or don’t navigate the application process absorbing the shortfall in full, indefinitely. Discount a delayed, diminished, partially realized return to present value, and Acadia’s 4-to-1 ratio — like NYSERDA’s 6-to-1 — looks considerably less generous than advertised.

The missing piece: the wholesale-market cost adder

Acadia’s entire cost side of the ledger is ISO-NE’s estimate that carbon pricing programs added $815 million to New England’s 2025 wholesale electricity costs, or roughly $55 per household per year. ISO-NE’s own 2025 Annual Markets Report is worth reading directly here, because it confirms the mechanism I have been documenting in New York: the wholesale-market cost of carbon compliance is larger than the direct cost of the allowances themselves. ISO-NE’s report separately estimates the direct cost of carbon allowances purchased — based on spot allowance prices — at about $668 million, versus the roughly $1.1 billion (all carbon programs) added to total energy market costs. The report explains why those two numbers differ: “the total cost of carbon allowances is lower than the total cost to the energy market because when fossil fuel-fired generators are on the margin, the inclusion of carbon costs raises the market clearing price” paid to every dispatched resource in that interval — not just the unit that bought the allowance.

ISO-NE’s own numbers show the same markup that I found in New York — roughly a 65 percent gap between the $668 million direct allowance cost and the $1.1 billion total energy-market effect for 2025. Acadia cites the $815 million RGGI-specific share of that already-marked-up total as its entire cost figure, which is more honest than counting direct allowance purchases alone. But it still stops at the energy-market adder ISO-NE models.  It does not address capacity-market or other second-order effects, and it treats that single number as the full and final cost against which a multi-year, multi-program savings projection should be judged. If the wholesale mechanism is real enough for ISO-NE to model explicitly, it deserves more scrutiny than a single citation before being set against a rosy, projected benefit.

There’s also a regional wrinkle Acadia doesn’t address: this cost doesn’t stay inside RGGI’s borders. I looked at this question for New Hampshire’s potential exit from RGGI and found that even a state that leaves the program, or a ratepayer who receives no direct benefit from RGGI-funded programs, still pays an embedded RGGI cost on any imported electricity from RGGI-compliant states, because the marginal generator setting the regional clearing price is often RGGI-covered. Cost and benefit are not neatly contained within each state’s own ledger the way Acadia’s state-by-state table implies.

Averages hide who actually pays and who actually benefits

Acadia’s own Table 2 shows the “4-to-1” story doesn’t hold uniformly. Vermont receives $9.45 million in proceeds and shows zero recorded clean-energy or electrification savings in the table — its entire $42.1 million total comes from the energy-efficiency category alone. New Hampshire gets $65 million in direct bill assistance and comparatively little efficiency benefit relative to its proceeds. Massachusetts, with the largest efficiency infrastructure, drives most of the region’s projected savings. The multipliers Acadia uses aren’t universal constants.  Instead, they depend entirely on which category a state’s dollars land in and how mature that state’s program infrastructure already is.

That variance matters because the cost side doesn’t vary the same way. The $4-to-5-per-month wholesale cost adder is charged to every ratepayer, uniformly, embedded in the price of every kilowatt-hour, whether or not that household ever benefits from an efficiency rebate or a bill-assistance program. The offsetting “savings” are conditional on eligibility, program capacity, and successful completion of an application process. A household that doesn’t qualify for a program, can’t front the money for an efficiency upgrade, or doesn’t live in a service territory where a credit applies still pays the RGGI-driven cost in full, with nothing returned. Averaging across six states and four program categories smooths over exactly the distributional problem that determines whether any individual ratepayer actually comes out ahead.

How much of the 37 percent reduction is actually RGGI?

Acadia states plainly that RGGI “has driven CO2 reductions of 37% since 2001 across New England power plants,” and repeats the claim in its conclusions. Firstly, RGGI started in 2009 so RGGI had no impact until then.  Secondly, I’ve run the equivalent calculation for New York, using the state’s own reported cumulative program benefits, and found that RGGI-funded investments and programs account for only about 4.7 to 8.7 percent of the observed power-sector CO2 reduction since the program began. The overwhelming majority of the historical reduction is attributable to fuel switching from coal and oil to lower-emitting natural gas — a transition that happened for reasons largely unrelated to RGGI’s reinvestment programs, and one that offers little room to repeat.

Acadia’s own Table 3 makes the same point for New England, probably without meaning to. It shows natural gas now accounts for 95.4 percent of RGGI-covered CO2 emissions in ISO-NE, with oil contributing just 3.7 percent. The coal-to-gas switch that produced most of the historical emissions decline has already happened; there’s essentially no coal left to switch away from in this region. Which raises the obvious question Acadia doesn’t ask: if further RGGI-covered emissions reductions now require displacing gas generation directly, rather than riding a fuel-switching wave that has already run its course, what is the actual mechanism — and cost — of the next round of reductions the program claims credit for? A 37 percent historical reduction that mostly happened for other reasons isn’t a reason to expect the next 37 percent to come as easily, or as cheaply.

The oil-burn section: refuting an argument nobody serious is making

Acadia devotes a full page to rebutting the idea that New England’s wintertime oil burn is the primary driver of RGGI costs, concluding — correctly, based on their Table 3 — that natural gas is responsible for 26 times more RGGI-covered emissions than oil in 2025. That’s a fine technical point, but it isn’t the critique that matters. The substantive concern with RGGI, in New York and everywhere else, is the allowance price trajectory and the wholesale-market mechanism that embeds that price into every consumer’s bill — not the fuel mix of the marginal generator in any given hour. Spending a full section rebutting a weaker, secondary claim about oil, while never engaging the allowance-price-and-market-mechanism critique that program skeptics actually make, is a rhetorical choice. It answers a question nobody serious is asking instead of the one that’s actually on the table.

It’s also worth noting, in passing, what Table 3’s own footnote admits: wood and refuse-derived generation are exempt from RGGI’s cap entirely, despite being more emissions-intensive per megawatt-hour than oil and producing more electricity than oil in New England — 2,012 GWh and 2,563 GWh respectively, against oil’s 1,147 GWh. A cap that carves out fuels more emissions-intensive than the one being singled out for scrutiny is not the airtight accounting Acadia’s framing implies.

The cap trajectory: “manageable” is getting harder to say with a straight face

Acadia’s closing recommendation is that ISO-NE states should keep championing RGGI and finish implementing the Third Program Review’s steeper caps. That recommendation doesn’t engage with what’s happening in the allowance market right now. RGGI’s own price-relief valve, the Cost Containment Reserve, was fully exhausted for 2026 by the March auction — months before the year’s compliance deadline. The Auction 73 clearing price exceeds the 2036 CCR1 trigger price and the 2030 CCR2 trigger price and that suggests that in future years both CCR allocations will be exhausted in the first quarterly auction.  That means the CCR will not meaningfully reduce costs.  On August 21, 2026, RGGI’s independent market monitor, Potomac Economics, released an unprecedented special report on the second-quarter 2026 supply-demand balance, roughly eleven weeks after the Auction 72 price spike, apparently to reassure the market. Instead, it confirmed that compliance entities and investors are increasingly hoarding allowances rather than selling them as compliance deadlines approach, that investors hold 68 percent of the allowance surplus with no obligation to sell below whatever price the market has already shown it will bear, and that Virginia’s return to the program (it resumed participation July 1, 2026) adds less new supply than the new demand it represents. Most tellingly, the report explicitly declined to address whether the Third Program Review’s post-2027 cap trajectory — more than 10 percent annual reductions in the regional budget from 2027 through 2033, a pace the program has never sustained historically — is even sustainable, calling that question “beyond the scope” of the report. 

Auction 73 answered the question the market monitor wouldn’t. The cap tightens further, the CCR is gone for the year, Virginia is a net new claim on the allowance bank rather than a source of relief, and the price cleared at a record $37.65 anyway, on one of the largest single allowance offerings in the program’s history. If the tool specifically designed to prevent this kind of price escalation is already exhausted, and the program’s own independent monitor won’t vouch for the tightening path immediately ahead, then “continue to champion the program and keep tightening the cap” is not the reassuring, record-straightening conclusion Acadia presents it as.

What would actually set the record straight

Proponents of RGGI claim the program has been a success.  It’s an argument that this program’s accounting doesn’t support the “clear win for ratepayers, no real cost” story currently being told about it — in New York, and now in New England. If RGGI states and their advocates want to demonstrate a real, net ratepayer benefit rather than a modeled one, three things would help: publish realized, EM&V-verified savings instead of projected lifetime estimates built on the prior year’s ratios; have ISO-NE and NYISO calculate the full wholesale-market cost adder using the hourly dispatch data only grid operators have, rather than relying on a single annual estimate cited without independent scrutiny; and report the cost per ton of CO2 actually achieved through RGGI-specific investment, isolated from the fuel-switching-driven reductions that occurred for entirely separate reasons.  Acadia’s own fuel-mix data shows have largely already happened. Until that accounting exists, an aggregate, multi-year “4-to-1” ratio measured against one year of narrowly scoped cost is not setting the record straight. It’s the same rhetorical move New York regulators made with a bigger number, dressed for a different region.

On September 3 I published an article about Regional Greenhouse Gas Initiative (RGGI) costs that contradicted the energy affordability messaging of Governor Hochul.  A week ago, I had an article published at Watts Up With That which summarized recent articles here and posed a simple question: would the Regional Greenhouse Gas Initiative’s Auction 73 clearing price exceed the Auction 72 record of $35.00 per ton? The answer arrived this week, and it wasn’t close. RGGI announced that Auction 73 cleared at $37.65 per ton — $2.65 above Auction 72, and yet another record for the program.

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

What RGGI reported

The RGGI press release described the results this way:

NEW YORK — The eleven participating states in the Regional Greenhouse Gas Initiative (RGGI), the nation’s first market-based regulatory effort to reduce greenhouse gas (GHG) pollution, today announced the results of their 73rd auction of carbon dioxide (CO2) allowances. 28,537,847 CO2 allowances were sold at the auction at a clearing price of $37.65. This includes an initial offering of 27,389,847 allowances and 1,148,000 CCR allowances. The allowance offering included a supply of 5,740,000 allowances from Virginia, which resumed RGGI participation on July 1, 2026. Bids for the CO2 allowances ranged from $2.69 to $190 per allowance.

Two details in that paragraph matter more than they might look at first glance. First, the auction included 1,148,000 Cost Containment Reserve (CCR) allowances, and Virginia’s re-entry contributed 5,740,000 allowances to the offering — the two factors I’d flagged in my earlier post as the only real candidates for near-term relief. Second, the top bid was $190 per allowance, five times the clearing price. That kind of bid spread is not what a market in balance looks like.

Why this result was predictable

Regular readers know I have been documenting this trajectory since summer. The short version: RGGI’s allowance price has more than tripled since the start of Governor Hochul’s tenure, and every structural signal pointed toward more of the same rather than relief in the latest auction.

In Hochul and RGGI Affordability, I quantified the wholesale-market effect of RGGI allowance costs and showed why it undercuts the Governor’s affordability messaging. New York’s electricity market pays every accepted generator the market-clearing price for a given interval. When an emitting generator sets that price, its RGGI allowance cost is embedded in the bid and gets paid to every dispatched resource in that interval — including non-emitting and imported resources that bear little or none of the underlying RGGI cost. That post showed the RGGI allowance price rising from $9.30 per ton at the first full auction of Hochul’s tenure to $35.00 at Auction 72 — a 276% increase. At the Auction 73 price of $37.65, that increase is now 296%. For a typical residential customer, the RGGI-attributable share of the electric bill was around 4.2% in 2024; at $37.65 it is roughly 7.8%.

I also covered the special report RGGI’s own market monitor, Potomac Economics, released on August 21, 2026 — the Report on the Supply and Demand for RGGI CO2 Allowances: Second Quarter 2026 — in RGGI’s Market Monitor Confirms the Scarcity I’ve Been Tracking. I believe that report’s timing, roughly eleven weeks after the record $35 auction, was meant to calm the market. Instead it confirmed that 2026’s CCR allowances were fully exhausted, that compliance entities and investors are increasingly hoarding rather than selling allowances as the compliance deadline approaches, that Virginia’s return adds less new supply than the demand it brings, and — most tellingly — that the report declined to address whether the steep post-2027 cap trajectory is sustainable, calling that question “beyond the scope” of the report. Given that the auction price went up anyway, whatever calming effect was intended did not materialize.

Heading into Auction 73, secondary-market pricing was already telling the same story. Argus Media reported 2026-vintage RGGI allowances trading in the high-$30s to around $40 per short ton in mid-to-late August (Argus Carbon), with December 2026 futures trading even higher. The market monitor’s own Q2 2026 report showed that investors — who have no obligation to sell — held 68% of the allowance surplus, with little incentive to release allowances below the price the market had already demonstrated it would pay. The 2026 CCR was gone before the auction. Virginia’s re-entry was always a net new claim on the bank, not a source of relief. A larger Auction 73 offering had the opportunity to absorb that pressure; instead, it simply confirmed how much latent demand exists, since the price cleared above $35 despite the bigger offering.

Costs are not hypothetical

Put together, this is a consistent story, not a series of isolated data points. RGGI’s own cost-containment mechanism — the CCR, which is supposed to release additional allowances once prices cross a trigger — was exhausted as soon as 2026’s allowances became available, months before the compliance deadline. The regional cap is scheduled to tighten by more than 10% of the 2025 budget every year from 2027 through 2033, a pace the program has never sustained historically. Virginia’s re-entry adds demand faster than it adds supply. And New York adopted its conforming rule amendments in August without grappling with any of this, leaning on cost-impact modeling that predates the price spike and a ratepayer-benefit claim that ignores the wholesale market cost adder entirely.

None of this is abstract for consumers. My estimates put the total New York consumer impact of RGGI — direct allowance costs plus the wholesale market cost adder — at $1.1 to $3.4 billion annually at a sustained $37.65 allowance price, more than double the direct-allowance-cost figure that state messaging emphasizes. Scaled across all eleven RGGI states, the same mechanism plausibly adds several billion dollars more. That is the real price of a program whose defenders describe rising auction revenue as a “big opportunity” for new spending rather than what it actually is: a cost signal ratepayers are already absorbing.

Where this leaves the debate

When I posed the question of whether the price would exceed $35, I noted that every available signal pointed toward continued upward pressure rather than relief. Auction 73 confirmed it. That is real-time evidence that the price trajectory regulators have not acknowledged is not leveling off — and one more sign that the states’ own cost-containment tools, the mechanism regulators cite as evidence that consumer costs will stay manageable, can no longer do the job they were designed to do. Given these cost impacts, it is past time to pause RGGI.

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

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

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

The affordability claim meets reality

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

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

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

RGGI consumer costs

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

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

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

Table 1:  Total Annual RGGI Costs($ millions)

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

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

Table 2: Annual Residential Cost of RGGI ($)

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

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

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

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

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

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

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

The contradiction Hochul has not had to answer

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

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

Discussion

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

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

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

Conclusion

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

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

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

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

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

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

Background

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

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

New York Benefits of RGGI Claim

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

The press release announcing that the regulations were finalized states:

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

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

Figure 1: New York State Emissions by Fuel Type

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

Affordability

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

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

This section shows that those claims are incorrect.

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

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

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

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

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

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

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

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

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

Discussion

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

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

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

Conclusion

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

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

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