1  October, 2007

Overview of RGGI CO2 Budget Trading Program

The CO2 Budget Trading Program is based on the Model Rule, which was 

developed to provide guidance and consistency to states that signed the RGGI 

Memorandum of Understanding (MOU) as they implement the program detailed

in the MOU 1.  The MOU states that “Each of the Signatory States commits to

propose the Program substantially as reflected in the Model Rule”. 2 The Model 

Rule provides states flexibility in adopting provisions regarding applicability and

source exemptions, allowance allocations and allowance set­asides, and

permitting.  With the exception of these portions of the Model Rule where states 

are provided with discretion, the applicable regulatory agencies in the region

intend to propose rules that are materially consistent with the Model Rule.  This 

consistency is required to provide for participation in a regional allowance trading

program.

The initial template for the Model Rule was based on EPA’s Part 96 rule 3,  which was used as the starting point for provisions addressing the basic 

administrative functioning of the cap­and­trade program (e.g., process for

establishing authorized account representatives, compliance certification,  allowance tracking system, and allowance transfers). 

The Model Rule was developed by the RGGI Staff Working Group, 

comprised of staff members from the environmental and energy regulatory 

agencies in each signatory state. This effort was supported by an extensive 

regional stakeholder process that engaged the regulated community, 

environmental non­profits, and other organizations with technical expertise in the

design of cap­and­trade programs. 

1 The MOU was signed by the Governors of the participating states and outlines the program in

detail, including the framework for a Model Rule. The states made substantial revisions to the

draft model rule in response to public comments. As a result, an amendment to the MOU was 

agreed to and signed by the heads of the energy regulatory and environmental agencies in each

participating state. The MOU and amendments are available at

http://www.rggi.org/agreement.htm. 2 The RGGI Model Rule does not supplant any state regulatory or legislative efforts, but instead

facilitates them by including the types of provisions necessary to implement RGGI. The RGGI

Model Rule does so in a way that preserves state sovereignty and provides certainty and

consistency to the regulated community and to the public. The Model Rule is available at

http://www.rggi.org/modelrule.htm. 3 40 CFR Part 96 – NOX Budget Trading Program and CAIR, NOX, and SO2 Trading Programs for 

State Implementation Plans. See

http://www.access.gpo.gov/nara/cfr/waisidx_06/40cfr96_06.html.
2  October, 2007

The major components of the CO2 Budget Trading Program, as outlined in 

the Memorandum of Understanding and the Model Rule, are discussed below. 

Applicability 

The applicability criteria established by the Model Rule require fossil fuelfired electric generating units serving a generator of 25 MW or larger to comply 

with the CO2 Budget Trading Program.  Once a unit triggers applicability under

the CO2 Budget Trading Program (a CO2 budget unit), that unit will remain 

subject to the program, regardless of changes to the unit.   Regionally, units of 

this size are responsible for approximately 95% of CO2 emissions from the 

electric generation sector. 

The definition of “fossil fuel­fired” varies depending on when a unit 

commences operation. A unit that commences operation on or after January 1,  2005 is considered fossil fuel­fired provided that fossil fuel comprises more than 

5% of its total annual heat input. A unit that commenced operation prior to 

January 1, 2005 is considered to be fossil fuel­fired if fossil fuel comprises more 

than 50% of its total annual heat input. 

CO2 emissions attributable to the combustion of eligible biomass at a CO2

budget unit can be deducted from that unit’s CO2 compliance obligation.  Eligible 

biomass includes sustainably harvested woody and herbaceous fuel sources that 

are available on a renewable or recurring basis (excluding old­growth timber), 

including dedicated energy crops and trees, agricultural food and feed crop

residues, aquatic plants, unadulterated wood and wood residues, animal wastes, 

other clean organic wastes not mixed with other solid wastes, biogas, and other

neat liquid biofuels derived from such fuel sources. Determinations as to what 

constitutes sustainably harvested biomass shall be made by the applicable 

regulatory agencies in each participating state. 

Size and Structure of Cap 

The RGGI MOU calls for signatory states to stabilize power sector CO2

emissions over the first six years of program implementation (2009­2014) at a 

level roughly equal to current emissions 4, before initiating an emissions decline of

2.5% per year for the four years 2015 through 2018.  This approach will result in 

a 2018 annual emissions budget that is 10% smaller than the initial 2009 annual 

emissions budget.  The first three­year compliance period would begin January 

1, 2009. 

This phased approach with initially modest emissions reductions is intended 

to provide market signals and regulatory certainty so that electricity generators 

begin planning for, and investing in, lower­carbon alternatives throughout the

4 The initial regional cap is 188 million short tons of CO2 per year, which is approximately 4%

above annual average regional emissions during the period 2000­2004.
3  October, 2007

region, but without creating dramatic wholesale electricity price impacts and

attendant retail electricity rate impacts.  The RGGI MOU apportions CO2

allowances among signatory states through a process that was based on 

historical emissions and negotiation among the signatory states.  Together, the 

emissions budgets of each signatory state comprise the regional emissions 

budget, or RGGI “cap.”

Year Regional Annual CO2 Emissions Budget (short tons)

2009­2014  188,076,976 

2015 183,375,052 

2016 178,673,127 

2017 173,971,203 

2018 169,269,278 

Permitting

It is anticipated that the proposals in participating states may require each 

CO2 budget source to have an approved CO2 budget emission monitoring plan

(EMP). These permitting provisions would be developed by the applicable 

regulatory agency in each participating state in accordance with its permitting

regulations.  The anticipated potential scope of such state­specific provisions is 

outlined below. 

The purpose of the CO2 budget EMP is to define CO2 emissions and net 

energy output monitoring procedures for a particular CO2 budget source.  Applicable regulatory agencies could propose to allow CO2 budget sources that

are subject to the Acid Rain Program to submit as part of their CO2 budget EMP

a statement that they already have an emissions monitoring plan in place that 

meets the requirements of the CO2 Budget Program.  CO2 budget sources that

are not subject to the Acid Rain Program could be required to include in their 

EMP a detailed emissions monitoring plan that meets requirements specified by 

the CO2 Budget Trading Program.  These monitoring plans would be consistent 

with monitoring provisions at 40 CFR Part 75 (see “Emissions Monitoring”

below).  CO2 budget sources could also be required to include in their CO2

budget EMP a detailed electricity/useful steam output monitoring plan unless 

they already have an approved output monitoring plan under the NOX Budget 

Program or CAIR, in which case they would need to include a statement to that 

effect.5 After reviewing the CO2 budget EMP, the applicable regulatory agencies 

would issue a proposed final approval, a denial, or a final approval with 

conditions.  The applicable regulatory agencies would incorporate the CO2

budget emission monitoring plan into an operating permit in accordance with 

their permitting regulations. 

5 EPA does not currently require annual net energy output monitoring under 40 CFR Part 72 or 

Part 75.
4  October, 2007

Allowance Allocation

Auction of Allowances

States participating in RGGI have signed a Memorandum of

Understanding (MOU) that establishes a regional emissions budget (the cap),  and divides the emissions budget among participating states.  Each state will 

allocate allowances up to the amount of its emissions budget, with each

allowance allowing a regulated source to emit one ton of CO2. 

RGGI takes an innovative approach to how states allocate allowances to 

regulated sources. Historically, cap­and­trade programs have allocated 

allowances directly to regulated emissions sources.  Under RGGI, instead of 

giving allowances directly to electric generators for free, states would sell a 

significant portion or all allowances through a regional auction or otherwise. 

RGGI takes this approach because in a competitive wholesale market electric 

generators pass through the market value of free allowances to the price they bid 

into the market. 6 The RGGI program proposes to use this allowance value to 

provide incentives for end­use energy efficiency and other measures, thus 

lowering the impact of the program on electricity consumers. 

In the RGGI MOU participating states have agreed to allocate a 25%

minimum of allowances to support consumer benefit programs. 7Individual 

participating states may choose how to allocate the remaining 75% of their 

allowances, but the clear trend among the RGGI states is to auction nearly all of 

their allowances and dedicate the proceeds to support consumer benefits. NY, 

MA, VT, RI, CT, and ME have all publicly stated their commitment to auction

100%, or nearly 100%, of their allowances to support consumer benefit programs 

(CT, ME, RI, and VT have statutory requirements to this effect). 8 Allocating

allowances to support consumer benefits leads to lowering of electricity demand, 

reducing the overall compliance costs of the RGGI program and its impact on 

electricity ratepayers. 

It is expected that the regulations promulgated by many states will include 

provisions outlining the process for auctioning allowances that will align with the 

design of a regional allowance auction platform established jointly by the RGGI 

signatory states. States participating in RGGI are currently discussing the design

6 This is because allowances can be traded to other parties, and therefore have a market value. Generators expend an asset – emission allowances – when generating electricity. As such, the

use of freely allocated allowances has an “opportunity cost” since revenue from the potential sale

of the allowance is foregone. In a competitive wholesale market, generators therefore pass on

the cost of allowances as a cost of generating electricity, whether allowances were received for 

free or were purchased. RGGI is being implemented in a region with deregulated wholesale

electricity markets, which warrants a design approach that includes the auctioning of allowances. 7 The MOU defines “consumer benefit or strategic energy purposes” as the following: the use of

allowances to promote energy efficiency, to directly mitigate electricity ratepayer impacts, to

promote renewable or non­carbon­emitting energy technologies, and to stimulate or reward

investment in the development of innovative carbon emissions abatement technologies. 8 Maine has a modest set­aside to address a portion of the emissions from cogeneration facilities.
5  October, 2007

of a regional auction platform and the components of regulatory provisions 

necessary for implementing a regional auction.

Early Reduction Allowances

The Model Rule includes Early Reduction Allowance (ERA) provisions. 

ERAs are intended to provide an incentive for facilities to take actions to reduce 

CO2 emissions sooner than otherwise would be required by granting allowances 

for qualifying emissions reductions made before the CO2 Budget Trading

Program start date.  ERAs are awarded directly to the CO2 budget source, are 

not included in the auction, and are in addition to the cap.  To be eligible to

receive ERAs, a CO2 budget source must submit an ERA application no later

than May 1, 2009 demonstrating the following:

· An absolute reduction in the mass of CO2 emitted during the early 

reduction period (the three years 2006, 2007, and 2008), relative to the

baseline period (the three years 2003, 2004, 2005 – the three years 

immediately preceding the early reduction period)

· A reduction in the average CO2 emissions rate resulting from electric 

energy output and useful thermal energy output for all the CO2 Budget 

Units at the CO2 budget source during the early reduction period relative 

to the baseline period

· Facility shutdowns are not eligible for ERAs

Allowance Retirement for Voluntary Renewable Energy Purchases

In order to promote and increase support for renewable energy and to 

encourage citizens to voluntarily purchase electricity that has a demonstrated 

greenhouse gas benefit, the Model Rule contains optional provisions that provide

for the retirement CO2 allowances from a participating state’s CO2 emissions 

budget for voluntary ratepayer purchases of qualified renewable energy. 

Imposing a cap on CO2 creates incentives for generating electricity in 

ways that do not emit carbon dioxide (e.g., renewable energy).  However, in a

capped environment, the development of new renewable electric generation

facilities does not necessarily reduce the emissions of carbon dioxide associated

with electric generation.  This is because the production of electricity by non­ carbon emitting sources does not lower the cap and the number of allowances 

available.  Therefore, electric generators can continue to emit carbon dioxide as 

long as CO2 allowances are available.  Under this scenario, additional electric 

generation by renewable sources could make it easier for carbon dioxide­emitting

electric generators to meet the cap (by avoiding CO2 emissions and reducing the

demand for CO2 allowances), which could affect generator dispatch order.  However, generators could still emit CO2 up to the level of the cap or bank 

allowances for future use.  Consequently, increased renewable energy 

generation would help achieve the emissions cap at lower cost, but would not 

necessarily result in lower overall CO2 emissions.  This dynamic precludes 

marketers from stating unequivocally that voluntary renewable energy purchases
6  October, 2007

can be used to offset a purchaser’s CO2 emissions, a quality that is often

highlighted to consumers when marketing such products. 

To remedy this situation, allowances could be retired in an amount 

equivalent to the avoided CO2 emissions resulting from voluntary purchases of 

qualified renewable energy.  Renewable energy purchases would qualify for this 

retirement if they represent a voluntary purchase of eligible renewable energy on 

behalf of retail customers in a respective participating state, provided that such 

purchases represent renewable energy generation in the RGGI region and may 

not be used for compliance with renewable portfolio standards in the RGGI 

region, or a renewable portfolio standard in any other state.  Depending on the 

annual marginal or average CO2 emission rate for electric generation, as 

determined by the applicable independent system operator (ISO), the applicable 

regulatory agency in a participating state would retire allowances representing

some small portion of the state’s emissions budget.

Temporal Flexibility Mechanisms

Overview

The Model Rule includes a number of temporal flexibility mechanisms (i.e.,  banking, extended compliance period, and early reduction allowances).  Allowance borrowing is not included in the model rule.

Banking

The Model Rule provides for the banking of allowances with no

restrictions.  Banking provides facilities with the ability to carry over unused

allowances from a current compliance period into future compliance periods. 

Therefore, banking should provide allowance price stability while providing an

incentive to hedge future year emissions uncertainty.

Extended Compliance Period

The Model Rule provides for a three­year compliance period.  This 

compliance period can be extended to four years in the event of a stage­two 

trigger event (see “Price Triggers” below). Multi­year compliance periods were 

employed to provide regulated facilities more flexibility to adjust to variations in 

electricity demand (driven by meteorology and load growth), fuel price spikes, 

clean unit outages, etc.  A longer compliance period may also lead to resource 

(administrative) savings for the regulated facilities and the states implementing

the program.  This design component was included in lieu of allowance 

borrowing, as it allows for de facto borrowing within a three­year compliance

period.
7  October, 2007

Price Triggers 

The MOU and Model Rule include allowance price triggers, which provide 

additional compliance flexibility and price dampening in the event of higher

allowance prices in two distinct stages. 

A stage­one trigger event occurs if the twelve­month rolling average CO2

allowance price is equal to or greater than the stage one trigger price.  The

stage­one trigger price is set at $7 in 2005 dollars, and will be adjusted up or

down each year according to the consumer price index.  In the event that a 

stage­one trigger event occurs, CO2 budget units will be able to expand their use

of CO2 offset allowances from 3.3% of their compliance obligation to 5% of their 

compliance obligation (see “Offsets” below). 

A stage­two trigger event occurs if the twelve­month rolling average CO2

allowance price is equal to or greater than the stage­two trigger price.   The

stage­two trigger price is set at $10 in 2005 dollars, and will be adjusted up or

down each year according to the consumer price index plus two percent.

If a stage­two trigger event occurs:

· CO2 budget units will be able to use CO2 offset allowances to satisfy 

10% of their compliance obligation;

· The compliance period will be extended to four years; and,

· CO2 offset allowances may be awarded for the permanent retirement 

of greenhouse gas allowances or credits that have been issued 

pursuant to any mandatory carbon constraining program outside the 

United States that places a specific tonnage limit on greenhouse gas 

emissions, or greenhouse gas emissions reduction credits certified

pursuant to the United Nations Framework Convention on Climate

Change (UNFCCC) or protocols adopted through the UNFCCC 

process. 

The price trigger provisions include a 14­month market settling period,  which commences at the start of each new compliance period.  The twelvemonth rolling averages used to calculate the stage one and stage two trigger

events cannot include the 14­month market settling period.  Therefore, the 

earliest that either trigger event can occur is 26 months after the commencement 

of a compliance period. 

Calculations of trigger prices, and determinations as to whether or not a 

stage­one or stage two trigger event has occurred, will be performed by the

applicable regulatory agency, in consultation with the applicable regulatory 

agencies in other signatory states.
8  October, 2007

Emissions Monitoring

The emissions monitoring and reporting section of the Model Rule 

requires the owners and operators and/or the CO2 Authorized Account

Representative of each CO2 budget unit to install and certify monitoring systems 

and to collect, record, quality­assure and report data necessary to quantify CO2

mass emissions from that unit.  The emissions monitoring and reporting

provisions contained in the Model Rule are primarily based upon the US EPA

monitoring provisions at 40 CFR Part 75, and contain many specific references to 

these provisions. 

Those sources that would be subject to the CO2 Budget Trading Program

that are also subject to the Acid Rain Program are already required by EPA Acid 

Rain rules to monitor, record, and report CO2 mass emissions annually.  Those 

sources subject to CO2 Budget Trading Program that are not Acid Rain sources 

are subject to the Clean Air Interstate Rule, which requires sources to report 

mass emissions of oxides of nitrogen on an annual basis.  Since the physical 

equipment necessary to monitor emissions of oxides of nitrogen on an annual 

basis is also capable of monitoring for CO2 mass emissions, the Data Acquisition 

and Handling Systems would need modification to quantify CO2 mass emissions 

(additional programming with the additional formulas relative to CO2).  The

applicable agencies in participating states are currently in communication with 

the Clean Air Markets Division of the United States Environmental Protection

Agency to determine if US EPA will accept and perform quality assurance data

checks on CO2 mass emission monitoring data from non­Acid Rain Program

subject sources.

The monitoring provisions of the Model Rule include deadlines and 

procedures for the initial certification of, and, under certain circumstances, the

recertification of Continuous Emission Monitoring Systems.  Acid Rain Program

subject sources that have already certified CO2 monitoring systems will not 

require initial certification but may require recertification if, for example, changes 

to the monitoring system trigger such recertification. 

The monitoring section establishes procedures to apply conservative 

missing data routines in the event that a monitoring system fails to meet quality 

assurance and quality control requirements. 

The monitoring section contains specific provisions regarding:

· Requirements to provide heat input data;

· Requirements to provide electricity and useful steam output data;

· Procedures for filing petitions for alternative monitoring plans; and,
9 October, 2007

· Procedures for quantifying the portion of CO2 emissions associated

with the combustion of eligible biomass. 9

Offsets (Project­Based Emissions Reductions Outside the Capped Sector)

The emissions offset provisions of the Model Rule provide compliance 

flexibility by awarding CO2 offset allowances to projects outside the capped

sector that reduce and/or sequester emissions of greenhouse gases.  CO2 offset 

allowances may be used to satisfy a limited fraction of a source’s compliance 

obligation.  Initially, the use of CO2 offset allowances is constrained to 3.3% of a 

unit’s total compliance obligation during a control period, though this may be 

expanded to 5% and 10% if a stage one or stage two trigger event occurs, 

respectively. 

In order to ensure that the CO2 offset allowances awarded represent CO2­ equivalent emissions reductions or carbon sequestration that are real, additional,  verifiable, enforceable, and permanent, highly prescriptive standards were 

developed for specific project categories. At this time, only the following five 

project categories are eligible for CO2 offset allowances:

· Landfill methane capture and destruction;

· Reduction in emissions of sulfur hexafluoride (SF6);

· Sequestration of carbon due to afforestation;

· Reduction or avoidance of CO2 emissions from natural gas, oil, or

propane end­use combustion due to end­use energy efficiency in the 

building sector; and, · Avoided methane emissions from agricultural manure management 

operations.

The initial list of project categories was selected with consideration of 

expected offset supply within the borders of RGGI MOU signatory states; the 

relative ease of developing standards; and, the likelihood of mandatory 

greenhouse gas regulations for that sector.  The participating states intend to 

develop methodologies for evaluating new categories of offset projects.

Eligible offset projects may be located in any participating state, or any 

other state or U.S. jurisdiction in which a cooperating regulatory agency has 

entered into a MOU with the participating states to provide oversight support 

related to CO2 emissions offset projects in that state or U.S. jurisdiction. 10 Offset 

9 At this time, procedures have not yet been developed for deducting CO2 emissions associated

with the combustion of liquid biomass fuel. The net GHG emissions benefits of combusting liquid

biofuels can vary significantly due to the wide range of liquid biofuels production processes and

feedstocks. The participating states are jointly researching the appropriate manner of addressing

liquid biofuels. 10 Cooperating regulatory agencies would provide administrative oversight assistance to the

Signatory States to help ensure the credibility of offset allowances from the state or other 

jurisdiction.
10  October, 2007

project applications will be submitted to the appropriate regulatory agency in the

state where the project occurs.  Applications for projects not located in any RGGI

signatory state will be submitted to any one RGGI signatory state.

Eligible offset projects must go through a two­step application process and

must be verified after both steps by an accredited independent verifier. The first 

step is a consistency determination, whereby the applicable regulatory agency 

would determine whether a project meets the eligibility criteria.  The second step

is the submittal of an annual monitoring and verification report, which requires the 

applicant to demonstrate the precise amount of greenhouse gas emissions 

reduced or sequestered before offset allowances are awarded. 

A key component of the offset provisions in the Model Rule are those that 

address project “additionality”. Broadly, additionality attempts to address whether

incremental greenhouse gas emissions reductions will be achieved from an offset

project that would not otherwise have occurred in the absence of the RGGI 

offsets component.  Additionality is the key criteria for ensuring that offsets 

projects result in “real” emissions reductions in the context of a cap­and­trade 

program.  Since offsets allow an additional ton of CO2 to be emitted from sources 

subject to RGGI for each ton of emission reduction achieved through an offset,  offset projects must provide reasonable assurance that they are achieving 

emissions reductions that would not otherwise have occurred in the absence of 

the offset provisions of RGGI.  This presumes that offsets must involve actions 

that are unlikely to occur under a business­as­usual scenario (standard market 

practice). 

Evaluating additionality is difficult, since it requires a counterfactual 

assessment based on assumptions about what would likely have occurred in the

absence of the offset project.  It may also involve an evaluation of individual 

project developer intent to determine if a project presents an attractive 

investment alternative absent offset allowance revenue. 

Despite the problematic nature of determining additionality, the

environmental integrity of emissions offsets, and by extension the environmental 

integrity of the cap­and­trade system, presumes that best practical efforts are 

made to account for additionality. Offsets mechanisms without additionality 

criteria would simply involve quantification of emissions reductions achieved 

through typical market activities. 

There are two levels of additionality, “regulatory additionality” and 

“financial additionality”:

· Regulatory additionality is the simplest version of additionality – only 

project­based reductions not required by law or regulation would be 

eligible.  However, for many offset types this standard would allow a 

significant number of voluntary actions that are otherwise highly
11  October, 2007

economically attractive or representative of standard market practice to 

receive offset allowances.  Many of these actions would be considered

business­as­usual by a wide range of stakeholders.

· Financial additionality attempts to determine whether a project is likely 

to be economically attractive absent the revenue stream provided by 

an emissions offset.  This route is being utilized by the Clean 

Development Mechanism (CDM) and has typically been evaluated on 

a case­by­case basis, a process that has received significant criticism.  CDM financial additionality evaluation typically involves the following:

o Identification of alternatives to the project

o Barriers analysis (market barriers, technology barriers, or financial 

barriers)

o Common practice analysis

o Investment analysis (project­specific analysis, such as IRR or NPV)

with and without the projected revenue stream provided by the

CDM offset credits.  Determination is made as to whether the 

project, without offset credit revenue, is less financially attractive 

than other market options. 

The Model Rule employs a benchmark and performance standard approach to 

evaluating the additionality of a prospective offset project, referred to as a 

“standardized approach”. Benchmarks and performance standards are proxies that 

may be used to infer financial additionality, as outlined below:

· Benchmark is a qualitative eligibility criterion for a category of projects 

that reasonably ensures that a project is unlikely to occur under

standard market practice.  For example, prohibition of receipt of both 

offset allowances and other attribute credits, such as renewable 

energy credits (RECs), or the ability to receive both only under certain 

limited conditions.

· Performance standard is a quantitative eligibility criterion that 

establishes a metric for determining if categories of projects are 

unlikely to occur under standard market practice.  The criterion is 

usually established in relation to the performance level achieved 

through standard market practice for the category of activities eligible 

for a certain type of offset.  Projects that meet or surpass the standard 

qualify as additional.  Examples of performance standards include:

o Emission rate

o Energy efficiency criteria

o Market penetration rate
12  October, 2007

These benchmarks and performance standards are used independently or

in tandem, depending on the market situation for specific categories of eligible 

offset project types.