Air Resources Board

California Environmental Protection Agency

Proposed Regulation to Implement 

the California Cap-and-Trade Program 

PART I

Volume I

Staff Report: Initial Statement of Reasons

Release Date: October 28, 2010
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State of California

California Environmental Protection Agency

AIR RESOURCES BOARD

Office of Climate Change

STAFF REPORT: INITIAL STATEMENT OF REASONS

PROPOSED REGULATION TO IMPLEMENT 

THE CALIFORNIA CAP-AND-TRADE PROGRAM

PART I

Volume I

Public Hearing to Consider the Proposed Regulation 

to Implement the California Cap-and-Trade Program

Date of Release: October 28, 2010

Scheduled for Consideration: December 16, 2010

Location:

California Air Resources Board

Byron Sher Auditorium

1001 I Street

Sacramento, California 95814

This report has been reviewed by the staff of the California Air Resources Board and 

approved for publication. Approval does not signify that the contents necessarily reflect

the views and policies of the Air Resources Board, nor does mention of trade names or 

commercial products constitute endorsement or recommendation for use.
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Acknowledgments

This report was prepared with the assistance and support from many individuals 

within the Air Resources Board. In addition, staff would like to acknowledge the 

assistance and cooperation that we have received from many individuals and 

organizations, too numerous to list, whose contributions throughout the 

development process have been invaluable. Finally, staff would like to 

acknowledge the significant contributions from the numerous State, federal, and 

international governmental agencies that have provided assistance throughout 

the rulemaking process.
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TABLE OF CONTENTS

PART I

Volume I

EXECUTIVE SUMMARY.................................................................. ES-1

I BACKGROUND AND INTRODUCTION .....................................................I-1

A. Background ...........................................................................................I-2

B. California’s Climate Change Scoping Plan............................................I-4

C. Western Climate Initiative......................................................................I-5

D. Public Process for Regulation Development .........................................I-6

II GENERAL SUMMARY OF PROPOSED REGULATION...........................II-1

A. General Overview of Proposed Cap-and-Trade Program.....................II-1

B. Reporting Requirements.......................................................................II-7

C. Applicability ..........................................................................................II-9

D. Compliance Instruments.....................................................................II-14

E. Registration and Accounts..................................................................II-15

F. California Greenhouse Gas Allowance Budgets.................................II-16

G. Compliance Requirements for Covered Entities.................................II-18

H. Allowance Allocation...........................................................................II-24

I. Direct Allocations of California GHG Allowances ...............................II-30

J. Auction and Sale of California Greenhouse Gas Allowances .............II-35

K. Trading and Banking ..........................................................................II-39

L. Linkage...............................................................................................II-40

M. Offset Credits Issued by ARB.............................................................II-44

N. Recognition of Compliance Instruments from Other Programs ..........II-48

O. Enforcement and Penalties ................................................................II-49

P. AB 32 Requirements ..........................................................................II-49

Q. Program Monitoring............................................................................II-56

III OVERVIEW OF THE COMPLIANCE OFFSETS PROGRAM ...................III-1

A. Offset Credits Issued by ARB..............................................................III-1

B. Recognition of Compliance Instruments from Other Programs .........III-21

IV ANALYSIS OF ALTERNATIVES TO THE PROPOSED REGULATION . IV-1

A. Alternatives to the Cap-and-Trade Program....................................... IV-1

B. Alternatives to Specific Cap-and-Trade Program Design Features .... IV-7

V COMPLIANCE PATHWAYS SCENARIOS............................................... V-1

A. Introduction.......................................................................................... V-1

B. Relationship between Compliance Pathways Analysis and Economic 

Analysis ............................................................................................... V-1

C. Baseline Forecast and Required Reductions ...................................... V-2

D. Scenarios Analyzed............................................................................. V-3

E. Development of Abatement Cost Curves ............................................ V-5

F. Compliance Pathways Analysis......................................................... V-16

VI ENVIRONMENTAL IMPACTS OF THE PROPOSED REGULATION ..... VI-1

A. Summary of Environmental Analysis .................................................. VI-2
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B. Cap-and-Trade Program – Project Alternatives.................................. VI-3

C. Statewide GHG Benefits from Cap-and-Trade ................................... VI-3

D. Air Quality Impacts ............................................................................. VI-4

E. Other Environmental Impacts ............................................................. VI-5

VII CO-POLLUTANT EMISSIONS ASSESSMENT ................................... VII-1

A. Introduction........................................................................................ VII-1

B. Methods for Identifying Cumulatively Impacted Communities ........... VII-3

C. Method for Assessing Cumulative Emissions Impact ........................ VII-5

D. Community Case Studies .................................................................. VII-6

E. Conclusion....................................................................................... VII-23

VIII ECONOMIC IMPACTS OF THE PROPOSED REGULATION ............ VIII-1

A. Summary of Economic Impacts........................................................ VIII-1

B. Legal Requirements ......................................................................... VIII-2

C. Cap-and-Trade Program Design ...................................................... VIII-2

D. Costs and Benefits ........................................................................... VIII-3

E. Economic Analysis ........................................................................... VIII-6

F. Energy 2020 Estimated Price and Expenditures Changes ............... VIII-9

G. Economy-Wide Impacts from the Cap-and-Trade Program............ VIII-11

H. Cost-Effectiveness.......................................................................... VIII-13

I. Potential Impacts on Small Business.............................................. VIII-14

J. Potential Impacts on California Business Competitiveness ............ VIII-15

K. Potential Impacts on Individual Consumers.................................... VIII-17

L. Potential Cost to Local, State, and Federal Agencies..................... VIII-18

IX SUMMARY AND RATIONALE FOR PROPOSED REGULATION .......... IX-1

X REFERENCES ..............................................................................................1

Appendices

Appendix A: Regulation Order ........................................................................ A-1

Appendix B: Text of AB 32............................................................................... B-1

Appendix C: Executive Orders Relating to GHG Emission Reductions ........... C-1

Attachments are available under separate covers referred to as supporting 

documentation and appendices.

Volume II

Appendix D: Cap-And-Trade Program Design Development Process

Volume III

Appendix E: Setting the Program Emissions Cap

Appendix F: Compliance Pathway Analysis 

Appendix G: Allowance Price Containment Reserve Analysis
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Appendix H: Market Advisory Committee Recommendations

Appendix I: Western Climate Initiative Detailed Program Design

Volume IV

Appendix J: Allowance Allocation 

Appendix K: Leakage Analysis

Appendix L: Economic and Allocation Advisory Committee Recommendations 

Appendix M: CPUC/CEC Recommendations

Appendix N: Supporting Documentation for the Economic Analysis 

Volume V

Appendix O: Functional Equivalent Document 

Volume VI

Appendix P: Co-Pollutant Emissions Assessment

Appendix Q: Compliance Cycle and Program Activities

Part II 

Urban Forest Projects: Staff Report and Compliance Offset Protocol

Part III

U.S. Ozone Depleting Substances Projects: Staff Report and Compliance Offset 

Protocol

Part IV

Livestock Manure (Digester) Projects: Staff Report and Compliance Offset 

Protocol

Part V

U.S. Forest Projects: Staff Report and Compliance Offset Protocol
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Executive Summary

Background

Climate change is one of the most serious environmental threats facing the world 

today, and California is already feeling its effects. The goal of the California 

Global Warming Solutions Act of 2006 (AB 32, Nuñez, Chapter 488, Statutes of 

2006) is to reduce greenhouse gas (GHG) emissions in a cost-effective manner. 

The California Climate Change Scoping Plan lays out a comprehensive program 

to scale back our greenhouse gas emissions to 1990 levels by 2020, reduce our 

dependence on fossil fuels, stimulate investment in clean and efficient 

technologies, and improve air quality and public health. Achieving these goals is 

best accomplished through a coordinated set of programs that employ strategies 

tailored to specific needs, including market-based compliance mechanisms, 

performance standards, technology requirements, and voluntary reductions.

The cap-and-trade program is a key element of this overall strategy. It creates a 

limit on the emissions from sources responsible for 85 percent of California’s 

GHG emissions, establishes the price signal needed to drive long-term 

investment in cleaner fuels and more efficient use of energy, and affords covered 

entities flexibility to seek out and implement the lowest-cost options to reduce 

emissions. The cap-and-trade program is designed to work in concert with other 

measures, such as standards for cleaner vehicles, low-carbon fuels, renewable 

electricity and energy efficiency. The program will also complement and support 

California’s existing efforts to reduce criteria and toxic air pollutants. 

The cap-and-trade program and the broader Scoping Plan effort provide a model 

for action that can be taken at the federal level and by other states individually 

and through regional action. By moving forward, California is both positioning 

our economy to benefit as climate action is taken internationally and catalyzing 

action throughout the country and the world. 

The California cap-and-trade program has been designed to be part of a regional 

trading system. The program design allows linkage with programs established 

by partner jurisdictions in the Western Climate Initiative (WCI) to create a 

regional market system. The goal of the regional program is to enhance 

individual jurisdictions’ actions through collective action to reduce GHG 

emissions. On par with California, the regional cap-and-trade program would 

cover sources that encompass nearly 90 percent of the region's emissions. 

Linking with programs established by our WCI partners has several advantages 

for California. The reduction of greenhouse gas emissions that can be achieved 

collectively by the WCI partner jurisdictions are almost double what can be 

achieved through a California-only program. The broad scope of a WCI-wide 

market will also provide greater flexibility to California businesses by offering a 

wider range of emissions reduction opportunities and greater market liquidity.
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This report presents staff’s basis and rationale for the proposed regulation to 

establish the California Cap-and-Trade Program. Staff developed this proposed 

regulation to advance California’s GHG reduction goals, as required by AB 32. 

This regulation was developed through an extensive public process involving 

multiple stakeholders; local, state, and federal agencies; and the public.

Cap-and-Trade Program Objectives

In the cap-and-trade program, ARB will place a limit, or cap, on GHG emissions 

by issuing a limited number of tradable permits (called allowances) equal to the 

cap. Over time, the cap will steadily decline. The cap is enforced by requiring 

each source that operates under the cap to turn in one allowance or offset credit 

for every metric ton of carbon dioxide equivalent (MTCO2e) that it emits.

Because these allowances are tradable, individual emitters do not have specific 

emission limits. By establishing a limit for the program overall rather than for 

individual sources, the cap-and-trade program gives sources flexibility to make 

the most cost-effective choices about when and how to reduce emissions. The 

price of allowances will be established by the marketplace based on supply and 

demand. Allowance prices efficiently inform consumption and investment 

decisions and stimulate the development of new technological solutions that can 

enable lower-cost reductions now and in the future. For some in the program, 

implementing new, low-emitting technologies may be relatively inexpensive. 

Those participants will buy fewer allowances or sell surplus allowances to those 

that face higher costs. A participant will choose to buy more allowances when 

the cost of an allowance is lower than the cost of reducing its emissions. By 

giving participants a financial incentive to control emissions and the flexibility to 

determine how and when to do so through the ability to trade allowances, a 

three-year compliance period, and other provisions such the ability to bank 

allowances, emissions are reduced to the capped level while minimizing the cost 

of emissions reductions. 

In addition to allowances, a limited number of credits for emissions reductions 

from sources that are outside the cap coverage, called offsets, can be used for 

compliance with the program. At the end of each compliance period, covered 

entities are required to turn in, or surrender, enough allowances and offsets to 

match their emissions during this time period.

Major Provisions of the Proposed Regulation

The following elements constitute the basic components of the proposed capand-trade program.

Scope

The cap-and-trade program will cover the major sources of GHG emissions in the 

State, including refineries and power plants, industrial facilities, and 

transportation fuels. Starting in 2012, the program will cover electricity generation, 
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including imports, and large industrial sources and processes with annual GHG 

emissions at or above 25,000 MTCO2e. The program will expand in 2015 to 

include fuel distributors to address emissions from combustion of transportation 

fuels and combustion of natural gas and propane at sources not covered in the 

first phase of the program. 

The proposed regulation addresses emissions of carbon dioxide (CO2), methane 

(CH4), nitrous oxide (N2O), hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), 

sulfur hexafluoride (SF6), and nitrogen trifluoride (NF3). 

The Cap

The limit on GHG emissions—the program “cap”—determines the environmental 

effectiveness of the cap-and-trade program. If the cap is not set at a stringent 

enough level to reduce GHG emissions, the emissions-reduction goal of the 

program may not be met even if all sources comply with the program 

requirements. Staff has designed the program to be sufficiently stringent to spur 

GHG emissions reductions to achieve AB 32 goals. 

The program cap determines the number of total allowances issued by ARB. At 

the start of the program, ARB will issue allowances for each year consistent with 

the declining level of the cap. The initial cap level in 2012 will be set at the level 

of emissions expected in 2012 from sources covered at the start of the program. 

In 2015, the program scope expands to include the distributed use of fuels, and 

the cap increases to include emissions from those fuels based on the level of 

emissions expected in 2015 from the newly covered fuels. The cap will decline 

to a level in 2020 designed to ensure that emissions decline over time and 

California achieves the AB 32 GHG emissions target in 2020. 

Allowance Distribution and Trading

ARB plans to distribute allowances through a mix of direct allocation and auction. 

At the beginning of the program, most allowances will be distributed for free to 

help provide a soft start for the program. The allocation system is designed to 

reward those who have taken early action and have invested in energy efficiency 

and GHG emissions reductions and will encourage continued investment in 

efficiency and clean energy in the future. Because the allowances can be traded, 

the program provides incentives for those with the most cost-effective reduction 

opportunities to reduce emissions quickly. 

Covered entities are not the only entities that may hold and trade allowances in 

the cap-and-trade program. Other entities may be eligible to participate 

voluntarily in the program, including financial institutions, brokers, offset 

developers, and those who may want to voluntarily retire allowances. An entity 

that holds an allowance may surrender it to comply with its obligation under the 

regulation, bank it for future use, sell it to another entity, or ask ARB to retire it. 
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Because not all allowances will be distributed for free, the program includes 

creation of an auction system that will allow for broad participation and minimize 

opportunities for manipulation. Over time, the program will transition toward a

greater reliance on auctioning, which will help maximize incentives for continued 

investment in clean and efficient technologies and provide revenue that can be 

reinvested for public benefit.

Cost Containment Mechanisms

The flexibility afforded by a cap-and-trade program helps ensure that the needed 

GHG emissions reductions are cost-effective. Key elements of the program have 

been designed to optimize cost-effectiveness, including: (1) three year 

compliance periods, which smooth year-to-year variations in emissions levels; 

(2) allowance banking, which allows participants to hold allowances and use 

them for compliance in a later period; (3) offsets, which offer additional low-cost 

emissions-reduction opportunities; and (4) the establishment of an allowance 

reserve account, which allows covered entities access to allowances at set prices 

as a hedge against higher costs. A key consideration in designing these costcontainment mechanisms is to reduce compliance costs without compromising 

the environmental goals of the program. 

Reporting

The cap-and-trade program will rely on the Mandatory Reporting Regulation 

(MRR) as the primary mechanism for emissions reporting. Revisions to the MRR 

are being proposed by ARB staff concurrently with the proposed cap-and-trade 

regulation. These revisions are intended to align California’s reporting 

requirements with the federal reporting rules recently enacted by the U.S. 

Environmental Protection Agency (U.S. EPA), and to ensure that the information 

collected by those covered by the cap-and-trade program is of sufficient quality to 

support the program. 

Additional registration and reporting requirements are established in the cap-andtrade regulation for those who hold allowances or offset credits, and for other 

participants in the program, including offset registries and offset project 

developers. These requirements have been designed to ensure transparency 

and effective public disclosure while also minimizing the administrative burden on 

those covered by the regulation and on ARB staff. 

Offsets

Under the cap-and-trade program, covered entities may use a limited amount of 

offset credits to satisfy a portion of their compliance obligation. Offsets are 

tradable credits that represent verified GHG emissions reductions made in areas 

or sectors not covered by the cap-and-trade program. One offset credit is equal 

to one metric ton of GHG emissions. In addition to providing compliance flexibility, 

the inclusion of offsets in the program will support the development of innovative 
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projects and technologies from sources outside capped sectors that can play a 

key role in reducing emissions both inside and outside California.

Offsets must meet rigorous criteria that demonstrate that the emissions 

reductions are real, permanent, verifiable, enforceable, and quantifiable. To be 

credited as an offset, the action or project must also be in addition to what is 

required by law or regulation or would otherwise have occurred. Under the 

California cap-and-trade program, ARB will adopt specific compliance protocols 

for different project types, and will issue or recognize offset credits based on 

those adopted protocols that can be used for compliance purposes. 

Offset Protocols

ARB staff reviewed four offset protocols and recommends that they be approved 

by the Board as part of this regulatory package: (1) the Urban Forest Projects 

Protocol; (2) the U.S. Ozone Depleting Substances Projects Protocol; (3) the 

Livestock Manure (Digester) Projects Protocol; and (4) the U.S. Forest Projects 

Protocol. These protocols are based on those initially developed by the Climate 

Action Reserve (CAR) and its predecessor, the California Climate Action Registry 

(CCAR). The individual protocols are reviewed in Parts II through V of this 

rulemaking package, and each Part includes its own staff report and 

recommendations. To help ensure an adequate supply of high-quality offsets, 

staff anticipates that additional protocols will be reviewed and brought to the 

Board for consideration in 2011 and beyond. 

Sector-Based Offset Credits

Achieving the goal of climate stabilization will require a commitment to work at 

the international level to reduce GHG emissions globally. Sector-based crediting 

can increase participation in international efforts to control GHG emissions and 

address concerns about competitiveness and emissions leakage. Sectoral 

crediting can mobilize private and public resources, enabling the host 

government to reduce GHG emissions and transition toward a low-carbon 

economy. California has been working with strategic partners in the forest and 

cement sectors to explore sectoral crediting approaches to international action. 

The proposed regulation anticipates future inclusion of sectoral credits based on 

continuing work with international partners. 

Compliance and Enforcement

For each compliance period, each covered entity is required to surrender a 

sufficient number of compliance instruments (allowances and offset credits) to 

cover its total GHG emissions during that compliance period. A portion of the 

allowances must be provided annually, with the remaining allowances due 

following the end of the compliance period. Once allowances and offsets are 

surrendered they are permanently retired by ARB. 
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A robust enforcement program will play a vital role in the success of the cap-andtrade program by discouraging noncompliance and by deterring and punishing 

fraudulent activities. It also will play a vital role in the success of the cap-andtrade program by discouraging gaming of the system and by deterring and 

punishing fraudulent activities. Staff designed the proposed regulation to remove 

any financial incentive for noncompliance by requiring that additional allowances 

be surrendered for excess emissions not covered by the compliance deadline. 

Staff will also ensure that the requirements are enforced fairly, and that the 

enforcement process is transparent.

Linkage to Other Greenhouse Gas Emissions Trading Systems

Linkage involves the reciprocal acceptance of compliance instruments issued by 

another system. The proposed regulation includes a framework for California to 

link its cap-and-trade program to other emissions trading systems of similar 

scope and rigor. Linkage can expand the coverage of the cap-and-trade 

program to include emissions-reduction opportunities for sources covered in 

another program. 

Staff has designed the cap-and-trade program to allow California to link with the 

programs developed by WCI Partner jurisdictions that are consistent with the 

WCI Detailed Program Design. The proposed cap-and-trade regulation does not 

currently include linkage to other programs, though staff anticipates bringing 

recommendations to the Board in 2011 for possible linkage with the programs 

being developed by the four other WCI Partners that are currently working to 

implement programs by January, 2012: New Mexico, British Columbia, Quebec, 

and Ontario. Each program will undergo a case-by-case analysis by staff as part 

of a formal rulemaking process, and the Board will need to approve regulatory 

amendments reflecting the linkage with a particular program before it can take 

effect.

Program Monitoring

ARB will closely monitor whether, over time, the cap-and-trade program is 

meeting the objectives set forth in AB 32. These objectives include beneficial 

outcomes that should be maximized and adverse consequences that should be 

minimized or avoided. Much of the monitoring information ARB will need is 

collected as a part of normal program management, such as emissions data 

reports from the Mandatory Reporting Regulation, allowance price and use, or 

offset project annual reports. To supplement these sources, and to ensure that 

ARB has adequate information to identify whether the objectives are being met, 

ARB will require specified information from relevant expert sources, including the 

Offset Project Registries and Air Districts, and solicit additional information from 

stakeholders, including the public. Monitoring for potential emissions and 

economic leakage will be emphasized. 
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Using the results of monitoring, ARB will regularly evaluate (at a minimum once 

every three-year compliance period) whether the objectives identified by statute 

are being achieved. Periodic evaluation will be coordinated with other actions 

and information collection occurring at the end of compliance periods. 

ARB will conduct its evaluation sufficiently in advance of the end of each 

compliance period to allow ARB sufficient time adjust the cap-and-trade program, 

if warranted, before commencement of the next compliance period. If ARB 

determines during its periodic review that the cap-and-trade program is not 

achieving the objectives as defined by AB 32, or if substantial, unanticipated 

adverse economic or environmental effects are identified (e.g., substantial 

leakage), ARB will revise the operation and/or design of the program accordingly.

Evaluation of the Regulation 

Staff analyzed four alternatives to the proposed cap-and-trade regulation: (1) a 

“no project” alternative; (2) additional source-specific regulations; (3) a carbon 

fee; and (4) linking California’s cap-and-trade program to a future federal capand-trade program. In evaluating these alternatives, ARB staff found that none 

were as or more effective than the implementation of a cap-and-trade program in 

carrying out the goals of AB 32. In addition, staff analyzed a number of specific 

alternatives to the design of the cap-and-trade program. In recommending the 

specific design included in this proposal, staff balanced the need to maintain the 

environmental integrity of the program, to retain a level of flexibility to help ensure 

cost-effectiveness, and to consider the potential for co-benefits. 

This proposal has been evaluated for possible environmental impacts consistent 

with the requirements of the California Environmental Quality Act (CEQA). The 

environmental analysis also identifies potential environmental benefits associated 

with the proposed cap-and-trade program. The analysis identified potentially 

significant impacts related to air quality and to activities that disturb the ground, 

such as construction projects or site preparation for tree planting to establish 

offset credits. Based on the information available, such impacts are highly 

unlikely, but are nonetheless possible. ARB’s adaptive management program 

will include review of required reports and solicitation of comments from the 

public and stakeholders, including in-state and out-of state resource 

management agencies with jurisdiction over the forestry-related offset projects. 

Emissions Assessment

Air pollutant emissions that contribute to ozone and particulate matter pollution 

(i.e., criteria pollutants) and toxic air pollutants are “co-pollutants” often 

associated with GHG emissions from combustion processes. AB 32 requires 

ARB to consider the co-pollutant benefits of reducing GHGs. California’s air 

pollution control programs for criteria and toxic pollutants will continue to 

significantly reduce emissions and health risk into the future. Technology 

improvements and enhanced energy efficiency resulting from the cap-and-trade 
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program can further reduce these co-pollutants, providing public health benefits 

on both a regional and local basis in addition to the benefits of reducing GHG 

emissions. 

For market based-regulations like the cap-and-trade program, AB 32 requires 

ARB to consider the potential for direct, indirect, and cumulative emissions 

impacts, including localized impacts. Staff evaluated potential emissions impacts 

statewide and in four community case studies. The assessment focuses on the 

potential criteria and toxic pollutant emissions impacts from the industrial sources 

covered by the program. However, the assessment does not include criteria 

pollutant and toxic emissions reductions that the cap-and-trade program is 

expected to provide from transportation fuels and commercial and residential gas 

use, in addition to those likely to occur at industrial facilities.

Due to the inherent flexibility of the cap-and-trade regulation, as well as the 

overlay of other complementary greenhouse gas reduction measures, it is difficult 

to predict the decisions that individual facilities may make in any given 

community. However, based on the available data, current law and policies that 

control industrial sources of air pollution, and expected compliance responses, 

ARB believes that emissions increases at the statewide, regional, or local level 

due to the regulation are not likely. ARB seeks to ensure that the cap-and-trade 

program, as it operates over time, avoids and minimizes all instances of localized 

air quality impacts. ARB will use information collected through the mandatory 

reporting regulation, the cap-and-trade regulation, the industrial efficiency audit, 

and other sources to evaluate how facilities are complying with the cap-and-trade 

regulation. ARB will also solicit information from local air districts regarding 

permit modifications and new permit applications for covered sources. ARB will 

evaluate data from a variety of sources to determine whether there are any 

disproportionate impacts to low-income communities or any increases in the 

emissions of toxic air contaminants or criteria air pollutants resulting from the 

cap-and-trade program. If unanticipated adverse localized air quality impacts are 

identified during this periodic review, ARB is committed to promptly developing 

and implementing appropriate responses.

Economic Analysis

The cap-and-trade program is expected to result in increased investment in 

efficient buildings and technologies and in advanced fuels. At expected 

allowance prices ($15 and $30 per metric ton in 2020), these investments would

reduce fuel use by 2 to 4 percent in 2020, while economic growth between 2007 

and 2020 continues at a rate of 2.3 percent, virtually on par with the projected 

rate of 2.4 percent. Implementation of the program will, however, shift investment 

and growth within the overall economy toward those sectors driven by the 

production of cleaner and more efficient technologies.

Implementing the cap-and-trade program can also help mitigate the economic 

consequences of continued reliance on fossil fuels. Experience in recent 
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decades, such as the spike in world oil prices in the summer of 2008, has 

illustrated the economic costs of volatile energy prices on California’s economy. 

While this report does not attempt to quantify the insurance benefits of reduced 

dependence on fossil fuels in the face of continued volatility of world energy 

prices, it does show that California can significantly reduce its dependence on 

these fuels and, therefore, its vulnerability to future price spikes.

This economic analysis focuses exclusively on the economic effects in California 

of implementing the cap-and-trade program, and does not consider the avoided 

costs of inaction. The potential effects of climate change on California that are 

expected to occur, such as increased water scarcity, reduced crop yield, sea 

level rise, and increased incidence of wildfires, could cause severe economic 

impacts. While California has developed a Climate Adaptation Strategy to help 

alleviate these potential costs, the risk of potentially high economic costs from 

climate change in California remains real.

Requirements of AB 32

AB 32 calls on ARB to adopt regulations by January 1, 2011, to implement 

measures to “achieve the maximum technologically feasible and cost-effective 

reductions in greenhouse gas emissions.” AB 32 requires that the reductions be 

real, permanent, quantifiable, verifiable, and enforceable. AB 32 includes specific 

standards that apply to regulations that use market-based compliance 

mechanisms, such as the cap-and-trade program. 

Furthermore, AB 32 calls for the Board to “ensure that the greenhouse gas 

emissions-reduction rules, regulations, programs, mechanisms, and incentives 

under its jurisdiction, where applicable and to the extent feasible, direct public 

and private investment toward the most disadvantaged communities in California 

and provide an opportunity for small business, schools, affordable housing 

associations, and other community institutions to participate in and benefit from 

statewide efforts to reduce greenhouse gas emissions.”

The proposed regulation was developed in accordance with the requirements of 

AB 32 and the Staff Report presents supporting details. The following provides a 

brief response to several of the key AB 32 requirements that have received 

particular attention during the cap-and-trade rulemaking. 

Several AB 32 requirements relate to the potential economic effects of GHG 

regulations, including direction to minimize costs and maximize the total benefits, 

and to minimize leakage. Staff has designed the proposed cap-and-trade 

program, including the allowance allocation system, to minimize the cost of 

implementation and compliance and to maximize the overall benefits. The 

allowance allocation system is equitable within and across sectors of the 

California economy, and its primary reliance on efficiency benchmarks and 

auction encourages early action to reduce emissions. In addition, the ability to 
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bank allowances for future use provides an incentive for early action to reduce 

emissions. 

By ensuring that most GHG emissions in California are covered by the program, 

and that incentives are in place to ensure that the most cost-effective reductions 

are made, the program design shares the emissions-reduction burden equitably. 

Other AB 32 requirements relate to maximizing co-benefits, avoiding 

disproportionate impacts, considering the potential for emissions impacts, and 

avoiding emissions increases. Staff has evaluated both the health and economic 

effects of the proposed program to ensure to the extent feasible that no 

disproportionate negative impact will occur. The overall health and 

environmental effects of the regulation are expected to be positive, and the 

program has been designed to minimize the economic costs of the program, 

which will minimize the effects on low-income communities. 

AB 32 also calls for providing appropriate credit for early voluntary reductions 

and encouraging early action. ARB staff has recommended a system for 

distributing allowances in the industrial sector that will primarily rely on the 

relative efficiency of facilities for any free allocation. This approach rewards 

those who have already invested in emissions reductions. In addition, a portion 

of the allowances will be auctioned, and those who have taken early action will 

be less reliant on purchasing allowances at auction. This allowance allocation 

system provides appropriate credit for those who have taken steps to voluntarily 

reduce their emissions before the start of the cap-and-trade program. In addition, 

the ability to bank allowances for future use provides an incentive for early action 

to reduce emissions. The regulation would also allow existing offset credits 

generated under early versions of any offset protocols that the Board adopts to 

be used for compliance as early action offset credits.

Public Process for Cap-and-Trade Regulation Development

ARB staff developed this proposed cap-and-trade regulation through an 

extensive public process. In 2008, staff discussed the general framework for a 

cap-and-trade program as part of the development of the Scoping Plan. The 

Board included the cap-and-trade program as one of the central measures in the 

Scoping Plan. 

Following the Board's adoption of the Scoping Plan, staff held more than 30 

public workshops in 2009 and 2010 devoted to developing the cap-and-trade 

program design in more detail. These meetings allowed stakeholders and the 

public to discuss and share ideas on the appropriate design of the cap-and-trade 

program. Staff reviewed hundreds of public comments received from 

stakeholders and the general public from these workshops. Staff considered 

these comments in crafting the design of the proposed cap-and-trade regulation. 
ES-11

In November 2009, staff released a conceptual framework for the cap-and-trade 

program called the Preliminary Draft Regulation (PDR). The PDR combined 

preliminary regulatory language on the cap-and-trade process and structure, 

along with narrative text that described significant issues for which specific 

regulatory language had not yet been developed. In some cases, most notably 

the allocation sections, placeholders marked where specific language still 

needed to be developed. Staff released the PDR to maximize the opportunity for 

public comment and to advance the public dialogue on the proposed structure 

and content of this key Scoping Plan measure. In response to the PDR, staff 

received numerous written comments. 

Staff also provided regular updates to the Board on the development of the capand-trade program, including on allocation and offsets. Staff has also met with 

individuals, businesses, government representatives, scholars, experts, nongovernmental organizations, and general members of the public on a regular 

basis during the development of this regulation.

Recommendation

Staff recommends that the Board adopt the proposed cap-and-trade regulation. 

The program is expected to reduce GHG emissions between 18 and 

27 MMTCO2e in 2020, and the flexibility included in the program will ensure that 

these reductions are cost-effective. By establishing an overall cap on emissions 

from the major sources in California, the program will also play a critical role in 

ensuring that the AB 32 emissions target is met by 2020.
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I BACKGROUND AND INTRODUCTION

This Staff Report presents the California Air Resources Board (ARB or Board) 

staff’s basis and rationale for the proposed regulation for the California Cap-andTrade Program. The cap-and-trade regulation is designed to cost-effectively 

reduce emissions of greenhouse gases (GHG) by establishing a cap covering 

approximately 85 percent of the State’s GHG emissions and drive investment in 

cleaner and more efficient technologies to power California’s economy. Staff 

developed this proposed regulation to advance California’s GHG reduction goals 

as required by the California Global Warming Solutions Act of 2006 (AB 32) 

(AB 32, Nunez, Statutes of 2006, Chapter 488). This introduction describes the 

structure of the Staff Report and provides background on California’s Climate 

Change Scoping Plan,1

This Staff Report, including the attached appendices, represents the Initial 

Statement of Reasons (ISOR) for Proposed Rulemaking required by the 

California Administrative Procedure Act.

the Western Climate Initiative, and the public process 

used to develop the cap-and-trade program.

2

Part I of the Staff Report is divided into the following chapters: 

 

− Chapter I. Background and Introduction – Provides background on

California’s Climate Change Scoping Plan, the Western Climate Initiative, 

and the public process used to develop the cap-and-trade program.

− Chapter II. General Summary of the Proposed Regulation – Discussion of

selected design elements of the California Cap-and-Trade Program.

− Chapter III. Overview of the Compliance Offsets Program – Discussion of 

the design of the compliance offset program including: offset credits 

issued by ARB, early action offset credits, and sector-based offset credits, 

including Reducing Emissions from Deforestation and Degradation 

(REDD).

− Chapter IV. Analysis of Alternatives to the Proposed Regulation –

Describes alternatives that were considered for the California Cap-andTrade Program, and why the alternatives are less effective.

− Chapter V. Compliance Pathway Scenarios – Discusses scenarios and 

emissions-reduction opportunities that could be achieved by sources 

covered by the cap-and-trade program.

 

1 Climate Change Scoping Plan: A Framework for Change. Air Resources Board, December 2008. 

Found at: http://www.arb.ca.gov/cc/scopingplan/scopingplan.htm. 2 The Administrative Procedure Act, Government Code section 11340 et seq.
I-2

− Chapter VI. Environmental Impacts of the Proposed Regulation –

Describes potential impacts the proposed regulation may have on the 

environment, including potential impacts from project-specific activities.

− Chapter VII. Co-Pollutant Emissions Assessment – Describes the public 

health impacts of the proposed regulation.

− Chapter VIII. Economic Impacts of the Proposed Regulation – Describes 

the economic impacts of the regulation.

− Chapter IX. Summary and Rationale for the Proposed Regulation –

Describes the rationale for developing the rule provisions of the proposed 

regulation.

− Chapter X. References – Provides a list of references used for 

development of the Staff Report.

− Appendices include the proposed cap-and-trade regulation and technical 

appendices, including: cap setting; compliance pathways analysis;

allowance price containment; allocation; leakage analysis; and copollutant emissions.. They also include the Functional Equivalent 

Document that provides the environmental assessment required under the 

California Environmental Quality Act (CEQA) and other documents that 

serve as supporting documentation for the design and development of the 

program.

− Parts II through V provide Compliance Offset Protocols and related staff 

reports.

A. Background

Climate change poses a serious threat to the economic well-being, public health, 

natural resources, and environment of California. Global warming is projected to 

have detrimental effects on some of California’s largest industries (including 

agriculture and tourism), increase the strain on electricity supplies, and contribute 

to unhealthy air.3

 

3 Our Changing Climate – Assessing the Risks to California. California Energy Commission. 

Publication # CEC-500-2006-077, July 2006. Found at: 

 National and international actions are necessary to fully 

address the issue of global warming; therefore, California’s efforts alone will not 

solve the problem. Action taken by California to reduce emissions of GHGs will 

encourage other states, the federal government, and other countries to act. By 

exercising a leadership role, California will also position its economy, technology 

http://www.energy.ca.gov/2006publications/CEC-500-2006-077/CEC-500-2006-077.PDF.
I-3

centers, academic and financial institutions, and businesses to benefit from 

national and international efforts to reduce emissions of greenhouse gases.

The Legislature passed and the Governor signed AB 32 to exercise this 

leadership role. AB 32 directed ARB to prepare a Scoping Plan outlining the 

State’s strategy to achieve the GHG reduction limit established in the law. The 

reduction measures to meet the 2020 target are to become operative by 2012

(Health and Safety Code (HSC) §38562(c)).

AB 32 includes several specific requirements for ARB including:

• Identify the statewide level of greenhouse gas emissions in 1990 to serve 

as the emissions limit to be achieved by 2020 (HSC §38550). 

• Adopt a regulation requiring the mandatory reporting of greenhouse gas 

emissions (HSC §38530). 

• Identify and adopt regulations for Discrete Early Actions that could be 

enforceable on or before January 1, 2010 (HSC §38560.5). 

• Prepare and approve a Scoping Plan that identifies direct emissionsreduction measures, alternative compliance mechanisms, market-based 

compliance mechanisms, and potential monetary and non-monetary 

incentives to achieve the maximum technologically feasible and costeffective reductions in greenhouse gas emissions by 2020 (HSC §38561).

• Ensure that early voluntary reductions receive appropriate credit in the 

implementation of AB 32 (HSC §38562(b)(3)). 

• Convene an Environmental Justice Advisory Committee (EJAC) to advise 

the Board in developing the Scoping Plan and any other pertinent matter 

in implementing AB 32 (HSC §38591). 

• Appoint an Economic and Technology Advancement Advisory Committee 

(ETAAC) to provide recommendations for technologies, research, and 

greenhouse gas emissions-reduction measures (HSC §38591). 

AB 32 also includes a number of specific requirements that ARB must fulfill, to 

the extent feasible and in furtherance of achieving the statewide GHG emissions

limit, before adopting regulations that include market-based mechanisms:

• Consider the potential for direct, indirect, and cumulative emissions

impacts, including localized impacts in communities that are already 

adversely affected by air pollution (HSC §38570(b)(1)).
I-4

• Design any market-based compliance mechanism to prevent any increase 

in the emissions of toxic air contaminants or criteria air pollutants (HSC 

§38570(b)(2)).

• Maximize additional environmental and economic benefits for California, 

as appropriate (HSC §38570(b)(3)).

B. California’s Climate Change Scoping Plan 

The California Climate Change Scoping Plan was developed by ARB in 

coordination with the Climate Action Team and approved by the Board. The Plan 

lays out a comprehensive program to scale back our GHG emissions to 1990 

levels by 2020, reduce our dependence on fossil fuels, stimulate investment in 

clean and efficient technologies, and improve public health. Effectively achieving 

these goals is best accomplished through a mix of complementary strategies that 

combine market-based compliance mechanisms, direct regulations, and 

voluntary actions.

The cap-and-trade program is a key element of this overall strategy. It 

establishes an overall limit on the emissions from sources responsible for 

85 percent of California’s GHG emissions, establishes the price signal needed to 

drive long-term investment in cleaner and more efficient types of fuels and 

energy sources, and affords covered entities flexibility to seek out and implement 

the most cost-effective options to reduce emissions. 

As detailed in the Scoping Plan, the cap-and-trade program is designed to work 

in concert with a number of other complementary measures, such as standards 

for cleaner vehicles, low-carbon fuels, renewable electricity, and energy 

efficiency. The rationale for combining a cap-and-trade program with 

complementary measures was outlined by the Market Advisory Committee, 

which noted the following in its recommendations to the ARB:

Before setting out the key design elements of a cap-and-trade program it 

is important to explain how the proposed emissions trading approach 

relates to other policy measures. The following considerations seem 

especially relevant:

• The emissions trading program puts a cap on the total emissions 

generated by facilities covered under the system. Because a certain 

number of emissions allowances are put in circulation in each 

compliance period, this approach provides a measure of certainty 

about the total quantity of emissions that will be released from entities 

covered under the program.

• The market price of emissions allowances yields an enduring price 

signal for GHG emissions across the economy. This price signal 

provides incentives for the market to find new ways to reduce 

emissions.
I-5

• By itself, a cap-and-trade program alone will not deliver the most 

efficient mitigation outcome for the State. There is a strong economic 

and public policy basis for other policies that can accompany an 

emissions trading system.4

C. Western Climate Initiative

The Western Climate Initiative (WCI) is a cooperative effort of seven U.S. states 

and four Canadian provinces (the “partners”) that are collaborating to identify, 

evaluate, and implement policies to reduce GHG emissions, including the design 

and implementation of a regional cap-and-trade program. The WCI began in 

February 2007 with the governors of Arizona, California, New Mexico, Oregon, 

and Washington, who have since been joined by the premiers of British 

Columbia, Manitoba, Ontario, and Quebec, and the governors of Montana and 

Utah. Participation in the WCI reflects each partner’s strong commitment to 

identifying, evaluating, and implementing collective and cooperative actions to 

address climate change.

1. The WCI Regional Cap-and-Trade Program

The central component of the WCI partner jurisdictions’ comprehensive strategy 

is a flexible, market-based, regional cap-and-trade program that encourages the 

most cost-effective, reliable alternatives to reduce GHG emissions. The 

California cap-and-trade program intends to link to the programs established by 

other regional partner jurisdictions in the WCI to create a regional market system 

to collectively reduce GHG emissions. Similar to the California target, the 

regional program would cover sources that encompass about 90 percent of the 

region's emissions, and when fully implemented, would nearly double the 

reductions of a California-only program.

The WCI regional cap-and-trade program will consist of each individual 

jurisdictions’ cap-and-trade program implemented through state and provincial 

regulations. Each partner jurisdiction implementing a cap-and-trade program will 

issue emission allowances to meet its jurisdiction-specific emissions goal. A 

regional allowance market is created by the partner jurisdictions accepting each 

other’s allowances for compliance. The allowances can be sold between and 

among covered entities in linked jurisdictions, as well as by third parties.

Five WCI partner jurisdictions are currently working toward starting their 

programs in 2012: California, New Mexico, British Columbia, Ontario, and 

Quebec. These partners represent approximately two-thirds of the total 

 

4 Market Advisory Committee. Recommendations for Designing a Greenhouse Gas Cap-andTrade System for California. June 30, 2007. p. 19. Found at: 

http://www.climatechange.ca.gov/publications/market_advisory_committee/2007-06-

29_MAC_FINAL_REPORT.PDF.
I-6

emissions in the WCI jurisdictions—a critical mass and a robust market for 

achieving significant GHG emissions reductions.

2. WCI Cap-and-Trade Program Design

On July 27, 2010, the partner jurisdictions of the WCI released a comprehensive 

strategy designed to reduce GHG emissions, stimulate development of cleanenergy technologies, create green jobs, increase energy security and 

independence, and protect public health. The Design for the WCI Regional 

Program5

The WCI program design recognizes that variations in jurisdictional authority, 

regulatory procedures, and administrative requirements will result in different 

approaches to implementation of a cap-and-trade program. Between now and 

the planned program start date of January 2012, the WCI partner jurisdictions will 

take the steps necessary to make regional trading operational. They will also 

expand their efforts to develop and implement other core policies and programs, 

such as California’s complementary measures, to increase energy efficiency and 

fuel diversification to reduce GHG emissions. The WCI partner jurisdictions will 

continue to consult with stakeholders on the development of this regional effort.

is the culmination of two years of work by the partners.

D. Public Process for Regulation Development

Staff developed the regulatory proposal for the California cap-and-trade program 

with significant public input. The public process for the cap-and-trade program 

began in 2008 with the development of the Scoping Plan. At that time, staff 

discussed the general cap-and-trade program framework through numerous 

workshops and public consultations. The final Board-adopted Scoping Plan 

included the cap-and-trade program as a key element. 

Building on the Scoping Plan structure for a cap-and-trade program, staff held 

more than 30 public workshops in 2009 and 2010. Staff used these workshops 

to discuss options for the program design with stakeholders who shared their

ideas on the design of the program. Staff received and reviewed hundreds of 

public comments from stakeholders as part of the workshop process. Staff also 

gave numerous updates to the Board and met regularly with individual 

stakeholders to discuss their individual concerns and recommendations. As part 

of the regional effort, staff also participated in the WCI public process to 

understand the concerns of regional stakeholders.

ARB also received input and advice from the Market Advisory Committee and 

two advisory committees created under AB 32: the Economic and Technology 

 

5 Design for the WCI Regional Program. Western Climate Initiative, July 27, 2010. Found at: 

http://westernclimateinitiative.org/component/remository/general/program-design/Design-for-theWCI-Regional-Program/.
I-7

Advancement Advisory Committee (ETAAC) and the Environmental Justice 

Advisory Committee (EJAC). In addition, in May 2009, Cal/EPA Secretary 

Adams and ARB Chairman Nichols created the Economic and Allocation 

Advisory Committee (EAAC) to assist ARB in developing the cap-and-trade 

program. This panel of economic, financial, and policy experts was asked to 

evaluate various cap-and-trade allocation strategies and to review staff's 

Updated Economic Analysis of California’s Climate Change Scoping Plan.6

In November 2009, staff released a conceptual framework for the cap-and-trade 

program called the Preliminary Draft Regulation (PDR). Staff held a workshop on 

the draft in December 2009. The PDR contained preliminary regulatory language 

on the cap-and-trade process and structure, accompanied by narrative text that 

described significant issues for which specific regulatory language had not yet 

been developed. The primary purpose of releasing the PDR was to maximize 

the opportunity for public comment and to advance the public dialogue on the 

proposed structure and content of this key Scoping Plan measure. In response 

to the PDR, staff received over 130 written comments that were considered in the 

development of this staff proposal. 

 Staff 

has carefully considered the input from these committees during the program’s 

development. 

 

6 Updated Economic Analysis of California's Climate Change Scoping Plan: Staff Report to the Air 

Resources Board. March 24, 2010. http://www.arb.ca.gov/cc/scopingplan/economics-sp/updatedanalysis/updated_sp_analysis.pdf (accessed September 23, 2010).
I-8

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II-1

II GENERAL SUMMARY OF PROPOSED REGULATION

A. General Overview of Proposed Cap-and-Trade Program 

Under AB 32, California must reduce greenhouse gas (GHG) emissions to 1990 

levels by 2020. Cap-and-trade is one of the key measures that California will 

employ to reduce emissions and drive long-term investment in cleaner and more 

efficient technologies to power the State’s economy. As proposed here, the capand-trade program would establish a firm cap covering about 85 percent of the 

State’s GHG emissions and allow trading of allowances to ensure cost-effective 

emissions reductions. 

The cap-and-trade program will cover the major sources of GHG emissions in the 

State, including refineries and power plants, industrial facilities, and 

transportation fuels. The program will impose an enforceable emissions cap 

beginning in 2012 that will steadily decline over time. The State will distribute 

allowances, which are tradable permits, equal to the cap. Sources under the cap 

will need to turn in allowances equal to their emissions at the end of each 

compliance period. Sources that aggressively reduce their emissions can trade 

their surplus allowances to firms who find it more expensive to reduce their 

emissions. In the early stage of the program, most allowances will be distributed 

for free to provide a smooth transition into the program, allowing those covered 

by the program to focus on investing in emissions reductions and cleaner 

technologies, and limiting any concerns about competitiveness and emissions 

leakage. 

Under the cap-and-trade program, offset credits can be used by covered entities 

to meet a portion of their compliance obligation. An offset is a credit that 

represents a reduction of greenhouse gases resulting from an activity that can be 

measured, quantified, and verified. Each offset credit represents a specific 

quantity of emissions reductions from a source not directly covered by the capand-trade program. 

Implementation and enforcement of the cap-and-trade program will be key in 

ensuring that California meets its AB 32 goals. The proposed regulation includes 

strict rules for reporting emissions and trades, with substantial penalties for 

violations. Transparency in the trading process is important to avoid market 

volatility and manipulation.

This section provides a high-level overview of the elements of the proposed capand-trade program. Each design element is discussed in more detail later in this 

Chapter. 

1. Cap-and-Trade

In the proposed program, a limit, or cap, is put on the amount of GHGs that can 

be emitted by all covered sectors. The total number of allowances created is 

equal to the cap set for cumulative emissions from all the covered sectors. In 
II-2

addition to allowances, credits for a limited amount of emissions reductions from 

sources that are outside the cap coverage, called offsets, will be allowed for 

compliance. The use of offsets will allow emissions in the capped sectors to 

slightly exceed the allowances issued, though these additional emissions from 

capped sectors will be matched by emissions reductions that result from offset 

projects. The term compliance instrument covers both allowances and offsets. 

These compliance instruments may be traded among entities. At the end of each 

three-year compliance period,

7

The cap-and-trade program puts a price on emitting greenhouse gases. This 

price provides incentives for GHG emissions reductions and innovation. It can 

stimulate reductions for all covered sectors without requiring individual 

regulations for all GHG emissions. Pricing GHGs in this way ultimately creates a 

market for finding the most cost-effective emissions reductions. Providing 

entities with the flexibility to find the most cost-effective reductions lowers the 

program’s overall cost. Creating a market provides more flexibility than direct 

regulation can, and it also provides incentives that can spur local investment and 

the use of green technologies. 

covered entities are required to turn in, or 

surrender, enough compliance instruments to match their emissions during this 

time period. Each allowance equals one metric ton of carbon dioxide equivalent. 

Since the program includes some GHGs (e.g., methane) that are more effective 

at trapping heat than carbon dioxide is, all emissions are measured in units 

relative to the heat-trapping potential of carbon dioxide, or CO2e; the “e” standing 

for “equivalent.” 

2. Fundamental Elements of the Cap-and-Trade Program

The following elements constitute the basic components of the proposed capand-trade program.

a. Scope

The proposed regulation phases sectors into the program. Under this phased 

approach, entities in the following sectors will be covered in the program 

according to the following timelines:

Starting in 2012 (first compliance period):

• Electricity generation, including electricity imported from outside California.

• Large industrial sources with GHG emissions at or above 25,000 metric 

tons of carbon dioxide equivalent (MTCO2e). 

 

7 A compliance period is the length of time for which covered entities must submit compliance 

instruments equal to their verified emissions.
II-3

Starting in 2015 (the second compliance period), the program expands to include 

fuel distributors in order to cover emissions associated with:

• Combustion of gasoline, diesel, natural gas, and propane from sources

with emissions below 25,000 MTCO2e, including all commercial,

residential, and small industrial sources.

• Fuels used for transportation.

All sectors listed above will be covered through 2020.

b. The Cap

The limit on GHG emissions—the cap—is a critical part of the cap-and-trade 

program design because it determines the number of total allowances ARB

issues. The cap is set in the proposed regulation and consists of annual cap 

numbers, also referred to as “budgets.” Staff included annual numbers through 

2020 in the proposed regulation to allow entities that have a compliance 

obligation to know how many allowances will be available from 2012 through 

2020. 

The initial cap level in 2012 will be set at the level of emissions expected from 

covered sources for that year—at 165.8 million MTCO2e (MMTCO2e). The cap 

then declines starting in 2013 until 2015. In 2015 the cap will be expanded to 

include GHG emissions from fuel suppliers. This expansion is based on the level 

of GHG emissions expected from the covered fuels for the year 2015, resulting in 

a cap for 2015 of 394.5 MMTCO2e. The cap will then continue to decline from 

2015 to 2020.

The level of the cap is critical to the environmental effectiveness of the cap-andtrade program. If the cap is not set at a stringent enough level to drive GHG 

emissions-reduction activities, the environmental goals of the program may not 

be met even if all sources comply with program requirements. Staff has 

designed the program to be sufficiently stringent to spur GHG emissions

reductions to achieve AB 32 goals. Staff has set the cap for 2020 at 334 

MMTCO2e, which is designed to allow California to achieve the AB 32 target in 

2020.

c. Allowances

As discussed previously, an allowance is equal to one metric ton of CO2e. ARB 

will issue a total of approximately 2.7 billion allowances for the cap-and-trade 

program through the year 2020. Annual allowance budgets for calendar years 

2012–2020 are established in the proposed regulation, so that the total number 

of allowances issued in each year through 2020 are known. At the end of a 

compliance period, each covered entity is required to surrender allowances (and 

if it elects, a limited amount of offsets) equal to its total GHG emissions during 

that compliance period. ARB will also require entities to surrender compliance 

instruments to match a portion of their reported emissions each year during the 
II-4

three-year compliance period to reduce the risk of noncompliance at the end of 

the three-year period. When compliance instruments are surrendered, ARB will

permanently retire them. 

Covered entities are not the only entities that may hold and trade allowances in 

the program. Entities in covered sectors with emissions less than 25,000 

MTCO2e may voluntarily elect to become covered entities. Other non-covered

entities may be eligible to participate voluntarily. Some examples of these noncovered entities include financial institutions or brokers, offset developers, and 

those who may want to obtain and voluntarily retire allowances. Once an entity 

holds an allowance, it can: (1) surrender it to comply with an obligation under the 

regulation: (2) bank it for future use; (3) trade it to another entity; or (4) ask ARB 

to retire it. 

Staff proposes to create a gradual transition into the program through the design 

of the allocation system. ARB will rely primarily on free allocation at the start of 

the program to minimize near-term costs to California consumers and businesses 

and to minimize emissions leakage. The allocation design will reward those who 

have invested in energy efficiency and GHG emissions reductions, and will 

encourage continued investment in clean and efficient technologies in the future.

The outset of the program will include a small direct auction that includes a 

consignment feature for allowances allocated to electricity distribution utilities. 

Staff designed an auction program that will allow for broad participation by 

diverse market players and minimize the chances for manipulation. The auction 

is set up in a way to ensure that allowances go to those market participants that 

place the highest value on them. 

d. Cost Containment Mechanisms

The proposed cap-and-trade program includes a number of mechanisms 

designed to minimize the costs of reducing GHGs without compromising the 

environmental integrity of the program. Some of the mechanisms that staff 

proposes in the cap-and-trade regulation are three-year compliance periods,

banking, offsets, the Allowance Price Containment Reserve, and linkage to other 

trading systems. 

i. Three-Year Compliance Period

A number of significant sources of California emissions are subject to significant 

year-to-year variations—for example, electricity sector emissions increase in low 

water years as hydropower generation is replaced with natural gas generation. 

For this reason, the proposed program has been designed with a three-year 

compliance cycle to help smooth out these annual variations, and to provide 

sources with greater flexibility to reduce emissions. 

ii. Banking

In a cap-and-trade program, banking allows participants to hold spare allowances 

and use them for compliance in a later period. The ability to bank allowances 
II-5

provides an incentive for covered entities to make early reductions since the 

declining cap could push allowance prices higher over time. Staff proposes to 

allow banking of allowances without restriction.

iii. Offset Credits

Under the proposed program, covered entities may use offset credits to satisfy a 

portion of their compliance obligation. In addition to providing compliance 

flexibility, the inclusion of offsets in the program will support the development of 

innovative projects and technologies from sources outside capped sectors that 

can play a key role in reducing emissions both inside and outside California.

Offsets must meet rigorous criteria that demonstrate that the emissions 

reductions are real, permanent, verifiable, enforceable, and quantifiable. To be 

credited as an offset, the action or project must also be additional to what is 

required by law or regulation or would otherwise have occurred. Under the 

program, ARB will issue or recognize an offset credit that could be used by a 

covered entity instead of turning in an allowance for the equivalent amount of 

CO2e emitted.

The proposed program imposes a limit on the amount of offsets that an individual 

covered entity can use for compliance. Allowing a limited number of offsets into 

the program provides benefits and ensures that some GHG emissions reductions 

occur within the sectors covered by the cap-and-trade program. The proposed 

program includes provisions that would allow a maximum of 232 MMTCO2e of 

offsets through the year 2020. This limit will be enforced through a limit on the 

use of offsets by an individual entity equal to eight percent of its compliance 

obligation. Combined with the Allowance Price Containment Reserve, this limit 

ensures that a majority of reductions from the program come from sources 

covered by the program at expected allowance prices, while use of the Reserve 

will relax that constraint if prices rise.

iv. Allowance Price Containment Reserve 

Staff proposes to establish an Allowance Price Containment Reserve (the 

Reserve). The Reserve is an account that is filled with a specified number of 

allowances removed from the overall cap at the beginning of the program. 

Covered entities may purchase reserve allowances at specified prices during 

direct quarterly sales. Covered entities gain flexibility through access to the 

Reserve if prices are high or entities expect prices to be high in the future. Staff 

proposes that the Reserve be filled with 123.5 million allowances out of the total 

of approximately 2.7 billion issued for the years 2012 to 2020. 

To ensure that allowance prices do not get too low to stimulate emissions

reductions, the proposed regulation establishes a price floor at the auction of $10 

per metric ton. Allowances that are unsold at auction will be added to the 

Reserve. This may happen if not all allowances are sold at the price floor of $10. 
II-6

v. Linkage to Other Greenhouse Gas Emissions Trading Systems

Linkage is the reciprocal acceptance of compliance instruments issued by 

another system. California could decide to link its cap-and-trade program to 

other emissions trading systems of similar scope and rigor, and has been 

working with our WCI partners to create the framework for a regional system of 

linked programs. Linkage can expand the coverage of the cap-and-trade 

program to include emissions-reduction opportunities for sources covered in 

another program. The proposed regulation establishes a framework for linkage. 

Each program considered for linkage would by subject to Board action, and will 

undergo a case-by-case analysis by staff as part of a formal rulemaking process. 

Although the regulation does not propose to link to any programs at this time, 

four programs are candidates for linkage before the 2012 start date. Currently 

four other WCI partners—New Mexico, British Columbia, Quebec, and Ontario—

are working to implement cap-and-trade programs consistent with the Design for 

the WCI Regional Program by January 2012. Linking to WCI partners has 

several advantages for California. The reduction of GHG emissions that can be 

achieved collectively by the WCI partner jurisdictions are approximately double 

what can be achieved through a California-only program. The broad scope of a 

WCI-wide market will provide additional opportunities for reduction of emissions, 

therefore, providing greater market liquidity and more stable carbon prices within 

the program. 

California and other WCI partners have also been participating in the Three 

Regions collaborative process with representatives from the jurisdictions in the 

Regional Greenhouse Gas Initiative and the Midwestern GHG Reduction Accord. 

The Three Regions have joined in a cooperative effort to share experiences in 

the design and implementation of regional cap-and-trade programs, inform 

federal decision making on climate change policy, and explore the potential for 

further collaboration among the three regional programs in the future.

e. Program Implementation

Assuming the design of the cap-and-trade program is approved by the Board, 

significant work will be needed to implement the regulation. Two primary areas 

that will require attention are finalizing the details of the allocation system for 

allowances, and designing and implementing a market tracking system. ARB 

staff is working closely on both efforts with our partners in the WCI, since 

coordinated approaches to allocation and the tracking system will simplify linking 

the individual programs into a regional market system. ARB staff believes that it 

is important for California to start its program in conjunction with our WCI 

partners. 

f. Compliance and Enforcement

A robust enforcement program will play a vital role in the success of the cap-andtrade program by discouraging gaming of the system and deterring and 

punishing fraudulent activities. One allowance is needed to cover one metric ton 
II-7

of a covered entity’s emissions, if they are turned in by the compliance deadline. 

If an entity does not meet the compliance deadline, it will need to surrender 

additional allowances. Staff designed the proposed regulation to remove, to the 

extent possible, financial incentives for noncompliance and to make sure that 

every metric ton of GHG emitted is covered by a valid compliance instrument. 

To develop the enforcement program for cap-and-trade, staff consulted with legal 

and enforcement staffs from state and federal agencies to gain insight in this 

area. These agencies included the California Environmental Protection Agency, 

California Attorney General’s Office, the California Energy Commission, the 

California Public Utilities Commission, the California Department of Water 

Resources, United States Department of Justice, the United States Securities

and Exchange Commission, and the United States Commodities and Futures 

Trading Commission. In addition, staff consulted with academic institutions 

including UC Berkeley’s Center for Law, Energy, and the Environment and legal 

scholars from other universities.

B. Reporting Requirements

The Mandatory Greenhouse Gas (GHG) Reporting Regulation (MRR) appears in 

Subchapter 10, Article 2, sections 95100-95199, title 17, California Code of 

Regulations. This regulation is a set of rules that establishes who must report 

GHG emissions to ARB and sets forth the requirements for monitoring,

calculating, reporting, and verifying those emissions. The MRR established 

reporting requirements for electricity and the largest stationary sources of GHG 

emissions in California. Changes are needed to the existing MRR because the 

cap-and-trade program covers more than large stationary sources and includes

electricity importers, transportation fuels, and smaller sources of fuel combustion 

by regulating the providers of these fuels. These changes will also ensure that 

the reported data are rigorous enough to support a trading program. These 

amendments and the MRR Initial Statement of Reasons will be considered by the 

Board in a separate rulemaking at the same time as the cap-and-trade regulation. 

The proposed MRR amendments are also intended to align California’s 

requirements with new federal requirements. On October 30, 2009, the United 

States Environmental Protection Agency (U.S. EPA) adopted its final Mandatory 

Reporting Rule8

The revised MRR requirements, if adopted by the Board, would first apply to 

reporting in 2012 for 2011 emissions. Until the new requirements take effect, 

those entities now subject to MRR requirements will continue to report under the 

(the “EPA rule”) for GHG emissions.

 

8 U.S. Environmental Protection Agency Final Rule on Mandatory Reporting of Greenhouse 

Gases. Promulgated by U.S. EPA on October 30, 2009 and July 12, 2010, 

http://www.epa.gov/climatechange/emissions/downloads09/GHG-MRR-Full%20Version.pdf
II-8

current regulation. The following sections briefly summarize the major changes 

being proposed to the MRR. See the Initial Statement of Reasons and proposed 

regulatory language for the MRR for more information.

1. Harmonization of MRR with U.S. EPA Requirements and Cap-andTrade

Since the adoption of California’s reporting requirements, the U.S. EPA has 

adopted federal GHG reporting requirements. ARB is working to harmonize 

California’s reporting requirements with the U.S. EPA rule. Many facilities in 

California will be subject to both reporting programs. Staff is working toward a 

unified reporting system to satisfy both state and federal requirements while 

minimizing duplicative or conflicting reporting obligations for facilities subject to 

both rules.

In developing harmonized reporting requirements for use in California, staff 

adhered to the following principles:

1. A California facility should be able to comply with both the MRR and the 

U.S. EPA rule by following a single set of monitoring, recordkeeping, and 

reporting requirements.

2. The quantification methodologies must be sufficiently reliable and 

accurate to be used to support a cap-and-trade program.

The most straightforward way to follow the first principle would be to adopt the 

U.S. EPA rule without change, but this approach would not adhere to the second 

principle. As U.S. EPA has acknowledged, the U.S. EPA rule has not been 

specifically designed to meet the needs of a cap-and-trade program. 

In nearly all cases where modification to the U.S. EPA rule was necessary to 

support the cap-and-trade program, staff included additional requirements in the 

MRR, without any alterations to the U.S. EPA program. This will allow a facility 

to still submit a report to California while complying with the U.S. EPA rule. The 

U.S. EPA rule generally allows a facility to use different tier quantification 

methodologies. For covered sources in cap-and-trade, the MRR is generally 

more prescriptive than the U.S. EPA rule by requiring the use of higher tier 

methods and MRR-specific procedures for missing data replacement. Facilities 

subject to cap-and-trade requirements will report at the unit level using methods 

usually consistent with higher-tier options in the U.S. EPA rule, while other 

facilities may use any method from the U.S. EPA rule. 

2. Threshold for Reporting

Entities subject to reporting under the MRR amendments are those with annual 

emissions equal to or greater than 10,000 MTCO2e. The threshold for entities to 

be directly included in the cap-and-trade program is annual emissions equal to or 

greater than 25,000 MTCO2e. Emissions from combustion of eligible biomassderived fuels must be reported, but do not have a compliance obligation 
II-9

associated with them in the cap-and-trade program. Staff proposes a lower 

reporting threshold for several reasons. Reporting down to a threshold of 10,000 

MTCO2e is needed to determine whether the threshold for inclusion in the capand-trade program is set at the appropriate level to capture the largest emissions 

sources. The lower reporting threshold is also required to monitor potential 

leakage to facilities or entities below the threshold of the cap-and-trade program.

3. Verification

The cap-and-trade program demands rigorous GHG accounting, reporting, and 

verification of emissions data. The MRR will continue to require independent

third-party verification of emission reports by entities and facilities included in the 

cap. Verification is not required for reporters under the 25,000 metric ton CO2e 

threshold; however, they are still subject to ARB audits. ARB will continue to 

accredit third-party verification bodies and verifiers for emissions reporting. In

the amended MRR, the verifier accreditation program will be expanded to also 

accredit third-party offset verifiers.

C. Applicability

The proposed cap-and-trade regulation establishes a program that covers GHG 

emissions from multiple sectors. In the initial compliance period, beginning in 

2012, the program will cover emissions from electricity, including imported 

electricity; industrial fuel combustion at large sources; and industrial process 

emissions, excluding fugitive emissions. In the second compliance period, 

beginning in 2015, the program will expand to include fuel distributors, to cover 

emissions associated with transportation fuels and fuels combusted at industrial, 

residential, and commercial buildings that are not otherwise covered directly as 

large emissions sources. The first compliance period of the program will include 

about 37 percent of the economy-wide emissions in California. Starting with the 

second compliance period, the program will include approximately 85 percent of 

emissions. The program could be expanded in the future based on new 

information.

The proposed regulation defines and includes requirements for covered entities, 

opt-in covered entities, and voluntarily associated entities. Under this regulation, 

covered entities and opt-in covered entities will be required to register with ARB, 

report their emissions annually, acquire compliance instruments, and surrender 

compliance instruments to match their emissions for the compliance period. 

Voluntarily associated entities must also register with ARB. These requirements 

are discussed in the following sections.

1. Covered Gases

Under the proposed cap-and-trade regulation the following gases are covered: 

carbon dioxide (CO2), methane (CH4), nitrous oxide (N2O), hydrofluorocarbons 
II-10

(HFCs), perfluorocarbons (PFCs), sulfur hexafluoride (SF6), and nitrogen 

trifluoride (NF3).9

2. Covered Entities

 Staff proposes to include all GHGs listed in AB 32 in the 

proposed regulation, even though some may not generate a compliance 

obligation in the program at this time. This will allow staff to include emissions 

associated with these gases in the future.

Covered entities are those that exceed the annual cap-and-trade emissions 

threshold and, therefore, have a compliance obligation in the program. Covered 

entities include: operators of large industrial sources of GHG emissions, first 

deliverers of electricity (the first entity that delivers electricity to the California 

grid), and fuel suppliers. Covered entities must submit compliance instruments

to match the amount of verified emissions they report. 

Staff proposes broad coverage of sources and emissions under the cap-andtrade program to provide greater certainty that economy-wide emissions

reductions will be achieved and provide more opportunities for reductions and 

trading. Operators of large point sources and first deliverers of electricity will be 

included under the cap in 2012. Electricity and large industrial sources are 

included at the outset of the program because they represent a significant 

amount of emissions from relatively few sources. Accurate emissions reporting 

and monitoring methods and requirements already exist for these sources. 

AB 32 also requires ARB to account for emissions of imported electricity (HSC 

§38530(b)(2)). Therefore, staff proposes to include in the program emissions 

that result from electricity generated out of state and consumed in California.

Staff proposes to include residential and commercial fuels, as well as 

transportation fuels, in the program starting in 2015 because together they are 

the largest source of GHG emissions in California. Including transportation fuels 

and fuel suppliers will help achieve the objective of reducing emissions not only 

by 2020, but also help to drive the long-term transition to cleaner fuels well into 

the future. Additionally, including these fuels in the program provides a 

consistent price on GHG pollution throughout the economy and ensures a level 

playing field across all fuels and consumers. Consequently, staff concluded that 

there are important benefits from including transportation fuels and fuels for 

residential, commercial, and small industrial users. While there would be 

benefits to including these fuels in the first compliance period, staff believes that 

it is appropriate to initially bring these fuels into the program on a reporting-only 

basis for the first compliance period. This will provide time for both ARB and the 

fuel deliverers to work through any issues in the reporting system before they 

have a compliance obligation.

 

9 HSC § 38505, as amended by Senate Bill 104, Oropeza, 2009.
II-11

3. Point of Regulation by Emissions Source

Point of regulation refers to the entities that must demonstrate compliance by 

submitting compliance instruments. As shown in Table II-1, staff proposes 

different points of regulation strategies, depending on the sector. 

Table II-1: Timing and Point of Regulation by Emissions Source

Sources of 

Emissions Point of Regulation Year Entering the Program

In-State Electricity

Generation

Those who generate electricity in-state and deliver it 

to the California electricity grid 2012

Imported Electricity First deliverers of electricity to the California 

electricity grid 2012

Industrial –

Combustion and 

Process Emissions

The source for large stationary combustion and 

process emission sources 2012

Carbon Dioxide 

Suppliers Those who supply carbon dioxide 2012

Commercial/ 

Residential/Small 

Industrial

Combustion

Where fuel is distributed, including natural gas local 

distribution companies (LDCs) and natural gas 

transmission pipelines

2015

Liquefied Petroleum 

Gas Combustion

Those who import or produce liquefied petroleum 

gas, including fractioners or refiners 2015

Transportation Fuel

Combustion

Enterers and position holders of transportation fuels, 

and producers of biomass-derived fuels 2015
II-12

a. Electricity Deliverers 

As required by AB 32 (HSC 38530(b)(2), ARB will account for emissions 

associated with both imported power and power generated in California. Staff 

proposes a first deliverer approach that regulates the first responsible party for 

placing power onto the California grid, because it treats all importers and in-state 

generators the same. The covered entity for in-state electricity generation is the 

source of generation. For emissions associated with imported electricity, the 

covered entity will be the first entity to place power onto the California grid. 

Electricity deliverers are responsible for deliveries of both specified and 

unspecified electricity delivered to the California grid. These entities include 

electrical distribution utilities (those that sell electricity to retail customers) and 

marketers (those that buy and sell in the wholesale electricity market). Typically 

these entities can be identified as purchasing-selling entities by the North 

American Electric Reliability Council (NERC) e-Tag.10

b. Industrial Process Emissions 

 

For large stationary sources with industrial process emissions, the covered entity 

will be the facility operator. Staff believes facility operators are most likely to 

have the authority to plan and implement GHG reduction projects at these large 

stationary sources. This point-of-regulation approach is identical to that taken in 

the MRR.

c. CO2 Suppliers

For use of CO2 as an industrial gas, the covered entity would be the supplier of 

CO2 because they are involved in the sale and delivery of the gas for commercial 

uses. 

d. Fuels

To cover the emissions from transportation fuel combustion and that of other 

fuels by residential, commercial, and small industrial sources, staff proposes to 

regulate fuel suppliers based on the quantities of fuel consumed by their 

customers. Fuel suppliers will be required to report emissions as specified in the 

MRR. While many of these suppliers will have a cap-and-trade compliance 

obligation, some who utilize eligible biomass-derived fuel sources may be 

reporting for informational purposes only. In no case would an entity have a capand-trade obligation without having a reporting obligation.

i. Natural Gas Suppliers

For natural gas combustion emissions, the covered entity is the supplier, 

meaning the owner when the fuel is distributed. Natural gas suppliers are 

 

10 North American Electric Reliability Corporation (NERC) electronic tag representing transactions 

on the North American bulk electricity market scheduled to flow between or across control areas.
II-13

defined as public utility gas corporations, publicly owned natural gas utilities

operating in California, and owners and operators of intrastate pipelines that

distribute natural gas directly to end users and are not part of utility pipeline 

systems.

ii. Suppliers of Transportation Fuels

For transportation fuel combustion emissions, the covered entity is the supplier of 

the fuel. Transportation fuel suppliers are limited to position holders (those who 

own fuel) at terminal racks that dispense Reformulated Gasoline Blendstock for 

Oxygenate Blending (RBOB) and/or diesel fuel, and enterers (those who bring in 

fuel from outside the State) that deliver fuel outside of the terminal system. This 

point of regulation is similar to the method used for imported electricity where the 

owner at the first point of receipt has a compliance obligation. ARB staff will 

continue to evaluate the concept of position holders relative to railroads and 

other specific types of fueling operations and may propose modifications to the 

regulations as appropriate.

iii. Suppliers of Liquefied Petroleum Gas 

For liquefied petroleum gas (LPG) the covered entity is the LPG supplier. 

Suppliers of LPG are defined as producers, including fractioners and refiners, 

and importers of LPG. Staff proposes to include LPG because of its substantial 

contribution to the statewide GHG inventory. 

4. Opt-In Covered Entities

The proposed regulation includes provisions for entities that do not meet the capand-trade threshold requirements but choose to voluntarily participate in the capand-trade program. These entities are referred to as “opt-in covered entities.” 

Staff included provisions for these entities to be eligible to receive free

allowances for implementing more efficient processes and technologies to 

reduce their associated emissions. If an entity opts into the program, it is subject 

to all reporting, verification, and compliance obligations of covered entities from 

the date of opt-in through the end of the current compliance period. 

5. Voluntarily Associated Entities

The proposed regulation describes requirements for entities who do not have a 

compliance obligation but who may participate in the auctions, secondary 

market, 11

 

11 The secondary market refers to a market that is established by trading compliance instruments 

after initial distribution of allowances through ARB auctions or allocations.

and tracking system. Voluntarily associated entities may include nongovernmental organizations or private individuals wishing to purchase 

allowances for the sole purpose of retiring them. Voluntarily associated entities 

may also include participants such as traders, brokers, offset providers, or 
II-14

financial institutions. Staff chose to allow these other market participants to 

increase liquidity in the market and to facilitate the buying and selling of 

allowances between emitters and counterparties. In addition, more market 

participants make it less likely for a particular market player to affect the price of 

allowances by acquiring too many.

Although voluntarily associated entities may participate in the secondary market, 

purchase allowances at ARB auctions, and participate in the tracking system, 

only covered entities and opt-in covered entities are eligible to receive 

allowances through direct allocation or buy them from the Reserve.

D. Compliance Instruments

The proposed regulation includes two kinds of compliance instruments—

allowances and offsets—to allow covered entities to meet their compliance 

obligations. Approved compliance instruments can be issued by ARB or other 

programs that are approved by the Board for linkage. Each allowance or offset 

equals one metric ton of CO2e. California-issued allowances and offsets, and 

approved compliance instruments from other programs, constitute the total 

number of compliance instruments available to covered entities to comply with 

the cap-and-trade program.

1. California Greenhouse Gas Allowances

ARB will issue allowances equal to allowable GHG emissions under the cap. 

Each allowance authorizes its owner to emit one metric ton of CO2e and has an 

economic value which depends on the supply of allowances (and offsets) and the 

demand to emit GHGs. To achieve GHG emissions reductions, the number of 

allowances issued is reduced over time. These allowances can be distributed by 

various methods, including: auctioning, benchmarking, and grandfathering. 

2. Offsets

An offset credit represents a reduction or removal of GHG emissions. These 

GHG emissions reductions or removals result from activities not covered by the 

cap-and-trade program, but must be monitored, quantified, and verified on an 

individual project basis. This credit can then be sold and used by a covered entity 

to meet a portion of its compliance obligation under the cap-and-trade program. 

Like an allowance, each offset credit authorizes its owner to emit one metric ton 

of CO2e. 

The number of offset credits that a covered entity may use to meet its 

compliance obligation will be limited. Offset credits must be real, additional, 

permanent, verifiable, enforceable, and quantifiable. Specific considerations and 

design elements of the offset program can be found in Chapter III—Overview of 

the Compliance Offsets Program.

3. Allowances and Offsets from Other Programs
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The proposed regulation provides a framework for allowances and offsets from 

other approved programs (such as another cap-and-trade program, an offset 

registry, or a sector-based crediting program) to be used to meet compliance 

obligations. The use of such instruments can help reduce compliance costs for 

emitters by expanding the available opportunities for low-cost emissions

reductions and the market for new technologies.

The proposed regulation establishes a process by which each program would be 

evaluated on a case-by-case basis before being considered by the Board. In 

approving an external program, the Board would also specify what compliance 

instruments from that program would be accepted for compliance use in 

California’s program. Recognition of another program’s compliance instruments 

or linkage would be implemented by program-specific contracts or memoranda of 

understandings, as applicable. This Chapter’s Section L: Linkage and Section N: 

Recognition of Compliance Instruments from Other Programs discuss the 

process for approving other programs. 

E. Registration and Accounts

1. Development and Implementation of a Market Tracking System

The proposed program will require a market tracking system (MTS) to record 

information about the holders of compliance instruments and trades of 

compliance instruments among market participants. ARB is working closely with 

our WCI partners on two possible approaches, (1) developing a single MTS that 

will serve all WCI partner programs, or (2) ensuring that the different tracking 

systems that are developed can communicate in a manner to allow linkage of the 

market programs.

The primary goal of the MTS will be to support the effective implementation of the 

cap-and-trade regulation and to reduce the costs and administrative burden 

associated with long-term cap-and-trade responsibilities. Additionally, the MTS

will collect the information necessary for a secure, liquid, and transparent 

allowance market. 

The MTS as a whole is scheduled to be operational in 2012. ARB is working to 

make the auction, market registry, trade data repository, and compliance subsystems of the MTS operational by the end of the third quarter of 2011 to enable

the cap-and-trade program to begin operation on January 1, 2012. 

2. Registration

The proposed regulation includes requirements for any entity that wishes to hold 

compliance instruments, including registration with ARB. When an entity 

registers with ARB, it must disclose all affiliated entities, provide information to 

allow ARB to oversee the market, and agree to be subject to ARB’s regulatory 

requirements. Once registered with ARB, an entity can possess an ARB account 

for holding, transferring, and surrendering compliance instruments. Each entity 

will specify who has the authority to access its accounts when it registers.
II-16

3. Accounts

ARB will establish three types of accounts in the MTS to track ownership and 

trades of compliance instruments: Holding Accounts, Compliance Accounts, and 

Limited Use Holding Accounts. All entities holding compliance instruments must 

have a Holding Account. Covered and opt-in entities will meet their compliance 

obligations by transferring allowances and offsets from their Holding Accounts to 

their Compliance Accounts. Because they have no compliance obligation,

voluntarily associated entities will only be approved for Holding Accounts to buy, 

sell, and voluntarily retire compliance instruments. 

Limited Use Holding Accounts will be created for electricity utilities that will 

receive free allowances. Holders of these accounts may only sell their directly 

allocated allowances on a consignment basis through the general quarterly 

auction held by ARB or, for publicly owned utilities, transfer them to their 

Compliance Account. For more information on Limited Use Holding Accounts,

please refer to Section I of this Chapter—Direct Allocations of California 

Greenhouse Gas Allowances.

4. Designation of an Authorized Account Representative

Staff proposes that transfers of compliance instruments only would be recorded 

by the accounts administrator (the ARB Executive Officer or designee) if the 

transaction is authorized by the account representative. An authorized account 

representative must be designated by the account holder to conduct transactions. 

Staff is proposing procedures for authorized account representatives to ensure 

integrity of transfers between accounts by preventing controversy over who has 

authority to conduct a transaction.

F. California Greenhouse Gas Allowance Budgets

The initial 2012 allowance budget was set based on the best estimate of actual 

emissions in 2012 for those sources that will be covered at the outset of the 

program. In 2015, the program will expand to cover fuel suppliers. The 

allowance budget in 2015 expands to reflect this increased coverage. 

The 2020 target for the cap-and-trade program was initially set through the 

Scoping Plan process as the emission level needed from capped sources to 

reach the overall AB 32 economy-wide target. The estimated 2020 cap from the 

Scoping Plan (365 MMTCO2e) was based on ARB’s top-down inventory of 

greenhouse gas emissions. Since the adoption of the Scoping Plan, the MRR 

has resulted in facility level data, which has allowed staff to develop a better 

estimate of the emissions from sources in the program. As a result, staff 

adjusted the Scoping Plan estimate of the 2020 cap to account for the revised 

estimate of emissions covered by the cap-and-trade program. Subsequently, the 

cap for 2020 has been set at 334.2 MMTCO2e. Since the Scoping Plan, staff 

have refined the coverage of the cap-and-trade program and improved emissions 

estimates for the covered entities using facility-level data gathered through the 

MRR program. 
II-17

After staff set the initial allowance budgets for 2012, 2015, and 2020, it defined 

annual budgets for the intervening years. Staff established a linear decline from 

2012 to 2015 and then from 2015 to 2020. Staff believes that a linear trajectory 

is the most straightforward method for reducing the cap. The specific 

methodology and data used for setting the annual allowance budgets can be 

found in Appendix E: Setting the Program Emissions Cap. 

Annual allowance budgets for calendar years 2012–2020 are established in the 

proposed regulation, so that the total number of allowances issued in each year 

through 2020 are known. Table II-2 shows the number of allowances created for 

each year from 2012 through 2020. 

These annual budgets were set to include all GHG emissions associated with 

imported electricity. Each time California links to a WCI partner jurisdiction from 

which California imports electricity, staff will need to reevaluate these annual 

budgets to prevent double-counting of these emissions. 

The proposed regulation includes three-year compliance periods, with the first 

commencing on January 1, 2012. At the end of each three-year period, covered 

entities are required to surrender enough compliance instruments to match their 

verified emissions from that period. A three-year compliance period provides 

some temporal flexibility by allowing covered entities to manage planned or 

emergency changes in operations over the short term, as well as to deal with low 

water years that might affect the generation of hydroelectric power.
II-18

Table II-2: Annual Allowance Budgets from 2012–2020

Allowance 

Budget 

Year

Annual Allowance 

Budget (Millions of 

CA GHG 

Allowances)

1st

Compliance 

Period

2012 165.8

2013 162.8

2014 159.7

2nd

Compliance 

Period

201512 394.5

2016 382.4

2017 370.4

3rd

Compliance 

Period

2018 358.3

2019 346.3

2020 334.2

G. Compliance Requirements for Covered Entities

The program will apply an emissions threshold of 25,000 MTCO2e annually to 

determine which entities will have a compliance obligation.

13

 

12 In 2015, annual allowance budgets are adjusted to reflect emissions from fuel suppliers.

Covered entities 

must comply with program requirements if they emit this threshold or greater. 

Any entity whose emissions exceed the threshold in any year of a compliance 

period has a compliance obligation for that compliance period and the next

compliance period, unless it has shut down all processes. To comply with the 

regulation, covered entities must report their emissions annually according to the 

requirements of the MRR and submit sufficient compliance instruments to cover 

their verified emissions at the end of each three-year compliance period. 

Covered entities must also surrender compliance instruments to match a portion 

of their reported emissions each year.

13 Emissions from combustion of eligible biomass-derived fuels must also be reported, but do not 

have a compliance obligation associated with them. Anything that is not verified as an eligible 

biomass-based fuel would be counted when calculating applicability and compliance obligation.
II-19

5. Calculating Compliance Requirements

a. Operators of Facilities

An operator of a facility has a compliance obligation if its emissions exceed the 

25,000 MTCO2e inclusion threshold, including process, industrial gas, or 

stationary combustion emissions. In the case that the operator receives an 

adverse verification statement14

b. First Deliverers of Electricity

or does not report its GHG emissions by the 

deadline in the MRR, the compliance obligation will be assigned by ARB. This 

assigned emissions level will be based on staff’s evaluation of the following: 

normal days and hours of operation, previous emissions data reports, potential 

maximum fuel and process material input and output capacities, wholesale and 

retail transactions (for electric power entities), and information reported to ARB or 

other agencies related to the reporting entity's facility.

The electricity sector includes both in-state generation and electricity imported 

into the State. Sources of California’s electricity include natural gas, large 

hydropower, coal, nuclear, cogeneration, and renewable energy facilities. 

In-state electricity sources supplied approximately 68 percent of California’s 

electricity in 2008.

15

Compliance obligations for emissions from the electricity sector are based on the 

emissions from plants that generated the electricity, if the source of the electricity 

generation is known. If the source is unknown, the compliance obligation is 

based on megawatt-hours (MWh) and a default emission factor, which is 

discussed below.

In-state generation was responsible for 44 percent of 

electricity emissions. Imported electricity accounted for 31 percent of California’s 

electricity supply, and 56 percent of California electricity sector emissions. 

Compliance obligations for electricity are calculated based on the emissions from 

the generating facility, if the facility is known. This is referred to as specified 

power. In this case, ARB knows what fuel was used to generate the electricity. 

For specified power, staff developed reporting factors that determine how many 

GHG emissions to assign to the specified power based on the fuel source used 

to generate the electricity. The threshold for determining compliance obligations 

for specified power is 25,000 MTCO2e through 2014. In the first compliance 

period, in-state power plants below the 25,000 MTCO2e threshold are not 

covered, even if it is specified as in-state power generation.

 

14 A verification statement rendered by a verification body attesting that the verification body 

cannot say with reasonable assurance that the submitted emissions data report is free of material 

misstatement.

15 California Energy Commission. 2008. Net System Power Report. Additionally, Total System 

Power for 2008. Found at: 

http://energyalmanac.ca.gov/electricity/system_power/2008_total_system_power.html. 
II-20

Electricity generated outside of California and imported into the State from an 

unknown source is referred to as unspecified power. This type of electricity is 

purchased on the electricity market, which experiences a large number of 

transactions each hour. The electricity is bought and sold many times before it is 

delivered to the California electricity grid. For this type of electricity, there is no 

threshold for the compliance obligation, because it is not possible to trace it back 

to the generator. Since ARB does not know the source of electricity, staff does 

not know the amount of GHG emissions to assign to it. Therefore, staff proposes 

to use a default emissions factor for unspecified power. Staff recommends the 

emissions factor be based on average emissions associated with the available 

electricity generation that could be sold on the spot market and brought into 

California. The GHG emissions will be calculated by multiplying this emission 

factor by the MWh delivered.

Changes in the reported mix of imported electricity that shift emissions within the 

Western Electricity Coordinating Council (WECC) region but do not reduce 

emissions overall should not result in a reduced compliance obligation. Staff is 

developing requirements to ensure reductions are real and not the result of 

incomplete accounting. In this way, the California cap-and-trade program will 

encourage low-emitting electricity generation for both in-state production and 

imported power.

In 2015, when natural gas is covered by the regulation, emissions from all

electricity generated in-state will be indirectly covered for any specified power 

plants. Beginning in 2015, the compliance threshold for facilities supplying 

specified imported electricity will be zero, to account for the addition of natural 

gas fuel coverage and to be consistent with the approach for covering all 

electricity deliveries in the program beginning in that year.

Electricity generating facilities that are solely powered by nuclear, hydroelectric, 

wind, or solar energy do not have a compliance obligation because these fuel 

sources do not directly emit GHGs.

c. Fuel Suppliers

Fuel suppliers are responsible for the emissions resulting from the combustion of 

the fuel they supply. In this way, a fuel supplier is acting on behalf of its 

customers who are emitting the GHGs. Facilities and fuel suppliers are distinct in 

that facilities are treated as physical locations and, therefore, they are covered 

entities based on operational control. Fuel suppliers are treated as corporate 

entities that are responsible for compliance.

i. Suppliers of Natural Gas

Because large industrial facilities and electricity deliverers will be responsible for 

emissions stemming from natural gas combustion, suppliers of natural gas will 

have a compliance obligation for the combustion emissions of all gas delivered, 

less the emissions from gas that is delivered to covered entities. This approach 

will ensure that these emissions are not double-counted. 
II-21

ii. Suppliers of Transportation Fuels

Suppliers of transportation fuels will have a compliance obligation for the 

combustion emissions from fuel that they sell, distribute, or otherwise transfer for 

consumption in California, including RBOB, and Distillate Fuel Oils No.1 and 2.

iii. Suppliers of Liquefied Petroleum Gas

Suppliers, including producers and importers, of liquefied petroleum gas (LPG) 

will have a compliance obligation for the combustion emissions from fuel sold in 

California. LPG producers, including fractioners and refiners, of liquefied

petroleum gas have a compliance obligation for emissions that results from the 

full combustion or oxidation of all fuel sold, distributed, or otherwise transferred in 

California. LPG importers have a compliance obligation for emissions that result 

from full combustion or oxidation of all fuel imported into California. 

d. Other Sectors and Categories of Emissions

i. Combined Heat and Power 

Staff proposes that emissions associated with electricity generated from 

combined heat and power (CHP) operations have a compliance obligation if the 

industrial facility’s total emissions exceed 25,000 MTCO2e. 

ii. Biomass-Derived Fuels 

Staff proposes to treat direct and indirect emissions from combustion of biomassderived fuels equally under the proposed regulation. Combustion emissions from 

specified biomass-derived fuels are excluded from compliance obligations if the 

biomass-derived fuel is reported and verified pursuant to the MRR. If the start-up 

fossil fuels that supplement biomass-derived fuel combustion at facilities and 

unverified biomass-derived fuels exceed the cap-and-trade threshold, the facility 

would be subject to cap-and-trade requirements based on emissions from these

sources. 

The MRR requires rigorous verification to validate any emissions reported as 

biomass-derived fuel emissions that would not generate a compliance obligation. 

In the absence of certification of the fuel by an accredited certifier of renewable 

biomass-derived fuels, a verification body must verify a biomass-derived fuel that 

will not be subject to a compliance obligation pursuant to provisions in MRR. If 

the verification body is unable to verify the biomass-derived fuel, it will be subject 

to a compliance obligation for emissions associated with its combustion.

To avoid potential double-counting of emissions reductions from biomass-derived 

fuels, any source of biomass-derived fuels that applies for offset credits under 

any ARB-approved offset protocols will be ineligible to be exempt from 

generating a compliance obligation. This includes but is not limited to the 

California offset program or any other mandatory or voluntary offset program.
II-22

iii. Landfills and Wastewater Treatment Facilities 

The proposed regulation excludes emissions from the combustion of biomass 

produced in solid waste management and wastewater treatment facilities from 

compliance obligations, if they can verify or certify their biomass through the 

MRR verification process. Facilities whose emissions from the combustion of 

fossil fuels and unverified or uncertified biomass-derived fuels exceed 

25,000 MTCO2e will have a compliance obligation. A few large wastewater 

treatment facilities or landfills may fall into this latter category.

iv. Waste-to-Energy Electricity Generation

Electricity deliverers that use biomass-derived fuels (e.g., waste-to-energy 

facilities) would have a compliance obligation for any biomass-derived fuel that is 

not verified through the MRR process. Emissions from deliveries associated with 

the combustion of fossil fuels and unverified or uncertified biomass-derived fuels 

that exceed 25,000 MTCO2e will have a compliance obligation.

6. Timing of Compliance Obligations

Staff proposes to require three-year compliance periods to provide increased

compliance flexibility and address price volatility that may be caused by annual 

variations in electricity sector emissions. Staff also recognizes that there is a 

need to require covered entities to submit a portion of its compliance obligation 

more frequently to ensure they are making progress toward their obligations. 

Covered entities could emit GHGs and then declare bankruptcy or otherwise 

cease operation before fulfilling their compliance obligations at the end of the 

three-year compliance period. Any compliance instrument that an entity owns at 

the time of bankruptcy could be included in its collection of assets for bankruptcy 

proceedings, thereby prohibiting claims to it by ARB. This form of default would 

hinder California’s ability to meet the cap and the requirements of AB 32. 

To reduce the impact of such a scenario, the proposed regulation requires 

covered entities to turn in a percentage of its verified emissions at intervals 

during the compliance period. ARB is proposing an “annual compliance 

obligation” to reduce the potential for a covered entity to default on a three-year 

compliance obligation.

In addition to the annual compliance obligation, the total obligation for a 

compliance period is resolved after positive or qualified positive verification 

statements for the third year are received and reconciled.

A covered entity will surrender compliance instruments to meet its compliance 

obligation by transferring the serial numbers from its Holding Account to its 

Compliance Account. Once transferred, compliance instruments may not be 

transferred back to a Holding Account. Entities can surrender allowances from 

the allowance budget years within the three-year compliance period, or from an 

earlier compliance period, to satisfy their compliance obligation. Allowances 

issued by ARB for an allowance budget year later than the compliance period 
II-23

cannot be used for compliance in the current period, except for allowances 

purchased from the Reserve.

a. Annual Compliance Obligation

A covered entity will be required to surrender compliance instruments in each of 

the first two years of a compliance period equal to 30 percent of its verified 

emissions for that year. For a covered entity that reports emissions in April under 

the MRR, the proposed surrender will be due by May 15 of the same year. For a 

covered entity that reports in June under the MRR, the surrender will be due by 

July 15 of the same year. 

b. Triennial Compliance Obligation

The triennial surrender obligation is the covered entity’s total verified emissions 

over the three-year compliance period, less the two annual surrender payments. 

ARB will work with covered entities to resolve any data issues related to

verification. After ARB makes a final determination of the amount of an entity’s 

compliance obligation based on its verified emissions and the validity of its 

surrendered compliance instruments, it will determine whether the covered entity 

has submitted a sufficient number of compliance instruments. The surrender 

deadline will be November 1 of the calendar year following the third year of the 

compliance period.

c. Untimely Surrender of Compliance Instruments

In the proposed regulation, covered entities must submit one allowance or offset

credit by the compliance deadline for each metric ton of CO2e emitted. Any 

emissions that exceed the number of valid compliance instruments surrendered 

by the deadline will be considered excess emissions, and the entity will be 

subject to excess emissions provisions. The excess emissions provision is 

intended to discourage untimely compliance. Four allowances issued by 

California or a linked program must be turned in for each metric ton of excess 

emissions. To avoid constricting the total supply of allowances, three of the

surrendered allowances will be placed into the Reserve and offered for purchase. 

One of the allowances will be retired to fulfill the entity’s original compliance 

obligation. 

7. Offset Quantitative Limit

To drive emissions reductions and incentivize innovation from sources within 

capped sectors, staff proposes to limit the number of offsets that may be used to 

meet a compliance obligation. The limit is expressed as a portion of the covered 

entity’s emissions. Using the sum of the annual allowance budgets, staff 

calculated the total limit on the use of offsets and applied the limit to all covered 

entities in the program in all of the compliance periods.

The Preliminary Draft Regulation (PDR) described a four percent limit on the use 

of offsets for an individual entity’s compliance obligation. This established a level 

of program stringency by allowing only 111 million offsets to be used over the life 
II-24

of the program, in addition to the number of allowances issued by ARB. The 

proposed regulation would establish an Allowance Price Containment Reserve in 

which ARB will place a total of 121 million allowances at the beginning of the 

program. By removing these 121 million allowances from the program, the level 

of stringency is increased, which could result in higher allowance prices. To 

address this, staff proposes that additional offsets, equal to the amount of 

allowances that are placed into the Reserve, be allowed in the program. This 

means that a maximum of 232 million offset credits may be used over the life of 

the program. This results in an offset limit in which a maximum of 8 percent of an 

individual entity’s compliance obligation can be met using offsets. 

H. Allowance Allocation

Allocation refers to how ARB distributes the allowances it issues. Allowances 

can be sold, freely allocated based on specific criteria, or some combination of 

the two. Because allowances are tradable among those in the market, they have 

value whether they are auctioned or freely distributed. If ARB sells allowances, 

an auction is the fairest and most transparent way to distribute allowances. 

When allowances are auctioned, they are distributed to the winning bidders. The 

proceeds collected from the sale of the allowances sold at auction could be used 

for a variety of purposes, including public benefit.

Staff proposes an allocation approach designed to give businesses and 

industries in the State sufficient time to reduce their emissions in a cost-effective 

manner, without unnecessary short-term costs. Therefore, in the proposed 

regulation, staff proposes a phased approach to the development of an auction 

system, beginning with a high percentage of free allocations to program 

participants. Staff also recognizes that the long-term success of the program will 

require significant investment in emissions reductions. However, under current 

economic conditions, an early emphasis on auction could hamper the ability of 

California sources to invest in low-carbon technologies. Further, as discussed 

below, freely allocating allowances in the early years of the program will help 

prevent leakage. Allocating the allowances for free using emissions efficiency 

benchmarks will reward companies that have already made investments in 

energy efficiency and carbon reductions, and will not penalize those that produce 

goods in California. The overall allocation approach includes: creation of an 

Allowance Price Containment Reserve for cost-containment purposes, free 

allocation to the industrial sector for transition assistance and leakage prevention, 

free allocation to electrical distribution utilities on behalf of ratepayers, and 

auction of the remaining allowances.

1. Establishment of an Allowance Price Containment Reserve

Key to the proposed cap-and-trade program is providing compliance flexibility 

while ensuring that emissions goals are achieved. To expand flexibility and 

reduce compliance costs, staff proposes to create an Allowance Price 

Containment Reserve. The ability of covered entities to purchase allowances 

from the Reserve will increase the supply of allowances in the market, thereby 
II-25

moderating the price as long as allowances remain in the Reserve. This reserve 

will hold allowances that will be made available for purchase by covered entities 

at fixed prices at direct quarterly reserve sales held three weeks after each 

general auction. Allowing covered entities to purchase allowances from the 

Reserve at fixed prices will limit increases in the market price as it approaches 

the established fixed reserve price. The Reserve will be filled: (1) at the 

beginning of the program with a portion of allowances from each budget year,

(2) with ARB allowances that remain unsold at a direct auction, and (3) with 

allowances surrendered to comply with excess emissions provisions.

Staff proposes to redirect allowances at the beginning of the program and place 

them into the Reserve. Staff proposes that a greater percentage of allowances 

come from later years of the program to provide more flexibility in the early years 

of the program. The Reserve will be filled with 1 percent of allowances from

each year from 2012 through 2014, 4 percent of allowances from each year from 

2015 through 2017, and 7 percent of allowances from each year from 2018

through 2020. This is equal to approximately 5 percent of total allowances in the 

program from 2012 through 2020.

The Reserve will be organized into three equal tiers. Allowances in each tier will 

be available for purchase at fixed prices. Staff proposes to sell reserve 

allowances at prices of $40/metric ton for the first tier, $45/metric ton for the 

second tier, and $50/metric ton for the third tier in 2012. These prices will 

escalate by 5 percent plus the cost of inflation each year, such that the reserve 

prices are approximately $60/ metric ton, $67/ metric ton, and $75/ metric ton in 

2020. Staff chose these prices to set them above the expected cost of 

abatement in the California program based on the economic analysis presented 

in Appendix N: Supporting Documentation for the Economic Analysis, the 

Updated Economic Analysis of California’s Climate Change Scoping Plan,

16 the

Updated Economic Analysis of the WCI Regional Program,

17

 

16 Updated Economic Analysis of California's Climate Change Scoping Plan: Staff Report to the 

Air Resources Board. March 24, 2010. 

and trading prices 

in the European Union Emissions Trading Scheme (EU ETS). Staff also notes 

that British Columbia, one of our WCI partners, has a carbon tax that is 

scheduled to be $30/metric ton in 2012. Direct sales of reserve allowances will 

take place three weeks after each quarterly auction. Covered entities will place 

bids for the number of allowances they wish to buy from each tier at each price. 

http://www.arb.ca.gov/cc/scopingplan/economicssp/updated-analysis/updated_sp_analysis.pdf (accessed September 23, 2010). 17 Updated Economic Analysis of the WCI Regional Cap-and-Trade Program. July 2010. 

Found at: http://www.westernclimateinitiative.org/component/remository/Economic-ModelingTeam-Documents/.
II-26

Direct quarterly reserve sales are discussed in more detail in this Chapter’s 

Section J: Auction and Sale of California Greenhouse Gas Allowances.

2. Allocation to the Industrial Sector for Transition Assistance and 

Leakage Prevention

Staff proposes to allocate allowances to the industrial sector for two purposes: 

(1) to provide transition assistance and (2) to prevent leakage. Transition 

assistance provides free allocation to the industrial sector at the outset of the 

program to avoid sudden or undue short-term economic impacts and promote a 

transition to a low-carbon economy. As depicted in Figure II-1, this transition 

assistance will decline as covered entities gradually adjust to the carbon price 

and adopt energy- and carbon-saving strategies. This level of free allocation will 

decline over time to settle at a level needed to prevent leakage.

If not appropriately compensated for in the design of the program, requirements 

for some energy-intensive trade-exposed (EITE) industries to reduce emissions

in California, either through inclusion in a cap-and-trade program or through 

source-specific regulation, have the potential to create a disadvantage for 

California facilities relative to out-of-state competitors who do not face similar 

requirements. If production shifts outside of California to a region not subject to 

GHG emissions-reduction requirements, emissions could remain unchanged or 

even increase. This is referred to as emissions “leakage.” AB 32 requires ARB 

to design measures to minimize leakage to the extent feasible. The cap-andtrade program is designed to minimize leakage in several ways, including 

accounting for both out-of-state and in-state electricity generation and linkage 

with partner jurisdictions in the WCI. Staff’s allocation approach is also intended 

to minimize emissions leakage for those in the industrial sector.

Staff analyzed the potential for emissions leakage by looking at emissions 

intensity and trade exposure. Emissions intensity is a measure of the impact that 

carbon pricing will have relative to a sector’s economic output. Those with higher 

emissions per unit of output are considered to be more emissions intensive.

Trade exposure is a measure of a sector’s ability to pass through a cost. Without 

assistance, the competitiveness of industries that are both highly emissions 

intensive and trade exposed has the potential to be negatively affected relative to 

competitors that do not face similar GHG emission reduction requirements. To 

minimize the potential for leakage, staff proposes to rely heavily on free 

allocation in the program’s early years. See Appendix K: Leakage Analysis for a 

detailed analysis.
II-27

Figure II-1: Representation of Allowance Value Distribution for Transition 

Assistance and Leakage Prevention

Staff believes that free allocation to industrial entities at risk of emissions leakage 

will help maintain the competitiveness of California industries. For as long as 

ARB assesses that the risk of leakage persists, allowances will be allocated for 

free to those at risk.

To determine whether a sector is at risk of emissions leakage, staff developed a 

methodology to assess a sector's emissions intensity and trade exposure. Staff 

presents this in Appendix K: Leakage Analysis. The number of allowances that 

an individual facility will be allocated within a specific sector will be based on an 

emissions efficiency benchmarking approach. Under this approach, more 

efficient facilities will receive a greater amount of free allowances relative to their 

actual emissions. The amount of free allowances distributed under this approach 

will vary with economic conditions. This means that, in an economic downturn, 

there will likely be fewer allowances distributed for free due to a decrease in 

production or output. When economic activity is robust and output increases, a 

greater number of allowances will be freely allocated. The efficiency benchmarks 

for each sector are described in the regulation. As staff continues to work with 

stakeholders to finalize the regulation, there may be updates to these efficiency 

benchmarks. Any updates will be publicly noticed in accordance with the 

Administrative Procedures Act.
II-28

3. Allocation to Electrical Distribution Utilities

Electrical distribution utilities provide electricity to residential and small 

commercial customers. These entities include Investor Owner Utilities (IOUs) 

and Publicly Owned Utilities (POUs). Staff proposes to allocate allowances to 

electrical distribution utilities, as opposed to the generators, because electrical 

distribution utilities are best situated to utilize the value of allowances for 

ratepayer benefit. 

To ensure that electricity ratepayers do not experience sudden increases in their 

electricity bills associated with the cap-and-trade regulation, staff proposes to 

allocate allowances for free to electrical distribution utilities on behalf of 

ratepayers. The proposed regulation stipulates that electrical distribution utilities 

must use the value associated with these allowances for the benefit of retail 

ratepayers of each electrical distribution utility, consistent with the goals of AB 32. 

They may not be used for the benefit of entities or persons other than their

ratepayers. Allowance value could be used for rebates, customer bill relief, or to 

pay for GHG-reducing measures such as energy efficiency, renewable electricity 

generation, or other similar programs. 

4. Voluntary Renewable Energy Allowance Set-Aside

The proposed regulation includes a placeholder for setting aside a small portion 

of the allowance pool to address the potential impacts of the cap-and-trade 

program on the voluntary renewable energy (VRE) market. At present individual 

decisions to purchase renewable energy in California can lead to reductions in 

greenhouse gas emissions. Implementation of the cap-and-trade program could 

change that dynamic because the amount of greenhouse gas emissions allowed 

will be pre-established by the cap level. As a result, decisions to purchase 

renewable energy free up emission allowances that would have been needed to 

generate electricity from fossil fuels, allowing other regulated entities to emit 

more than they could have otherwise. In essence, the voluntary purchase of 

renewable energy lessens the regulatory burden on greenhouse gas emitters. 

Without an allowance set-aside for VRE purchase, once the cap-and-trade 

program is in place, the voluntary use of electricity generated from renewable 

resources and delivered to California would no longer contribute additional 

greenhouse gas emission reductions because the level of allowable emissions is 

determined by the cap. A VRE set-aside has been implemented in the cap-andtrade system in the US Northeast (the Regional Greenhouse Gas Initiative, or 

RGGI). In order to implement an effective VRE set-aside, ARB would need to 

establish clear accounting rules to determine the relationship of voluntary 

renewable energy generation and GHG emissions avoided. Additionally, a 

process for reviewing VRE purchase claims would be needed as part of the 

process of retiring allowances from the set aside. Because the accounting rules 

and process for retiring allowances from the set aside have not yet been 

developed and undergone review, the current regulation only includes a 

placeholder for future inclusion of this mechanism.
II-29

5. Auction of Allowances

Covered entities, opt-in covered entities, and voluntarily associated entities may 

all participate in the general quarterly auctions to buy allowances. When 

allowances are auctioned, the allowances are distributed to the winning bidders. 

The value of the allowances not freely distributed to the industrial sector and 

electrical distribution utilities that are auctioned is represented by the money paid 

to the State, which would then have the opportunity to use the revenue for public 

benefit. 

According to the proposed regulation, after allowances have been placed into the 

Reserve and distributed to the industrial and electricity sectors, the remaining 

allowances issued for each year will be auctioned. The amount of allowances 

auctioned will increase over time as transition assistance is phased out and when 

distributed use of fuels is phased into the program in 2015. When ARB 

determines that the risk of emissions leakage abates for specific sectors, 

additional allowances may be auctioned. Auctioning can help establish price 

discovery; that is, provide a clear signal to market participants of the value of an 

allowance.

Some allowances will be auctioned directly by ARB; the proceeds will be placed 

into the Air Pollution Control Fund and made available for appropriation by the 

Governor and the Legislature for the purposes outlined in AB 32. How the 

Governor and Legislature apportion this portion of total allowance value will be 

important to the legacy of the cap-and-trade program. Staff recommends that 

these revenues be used primarily for the protection of California’s consumers and 

to further the goals of AB 32. The following uses would achieve those ends:

• Per Capita Consumer Rebate Program. A significant amount of the 

allowances auctioned by the State in the second and third compliance 

period will likely be purchased by fuel suppliers to cover emissions 

associated with distributed fuel uses. Staff anticipates that these fuel 

providers will be able to fully pass the cost of acquiring these allowances 

to the consumers of these fuels. A per capita lump sum distribution of the 

proceeds raised at auction would help consumers avoid negative impacts 

of higher fuel expenditures while still providing the correct incentives to 

reduce fossil fuel use.18

• Community Benefit Fund. Staff recommends the creation of a Community 

Benefit Fund to recognize the community protection goals of AB 32.

19

 

18 See the recommendations of the Economic and Allocation Advisory Committee (Appendix L). 

 

ARB or another agency could administer a competitive grant program 

designed to promote projects that simultaneously reduce GHGs and co19 Consistent with Health and Safety Code section 38565.
II-30

pollutants, finance adaptation/preparedness for climate change health 

impacts, create improvements to mass transit and land use planning,

facilitate natural resource conservation, and support non-utility energy 

efficiency programs.

• Low Carbon Investment Fund. Staff received many suggestions that a 

portion of total allowance value be directed toward public investments in 

the energy innovation goals of AB 32. Various names have been 

proposed for this type of program including the “California Carbon Trust”

and the “Investment Advisory Board.”

20

I. Direct Allocations of California GHG Allowances

 Conceptually, this use of auction 

proceeds could be structured as a competitive grant program administered 

by ARB or another entity. Project types could include research, 

development and demonstration projects in zero- or low-GHG 

technologies, and/or support for a green technology workforce training 

program.

The proposed regulation includes formulas which determine how many 

allowances each individual facility will be allocated for free. The number of 

allowances that an individual facility will receive is based on its output and the 

sector-specific emissions efficiency benchmark for those in the industrial sector,

and a mix of historical emissions and sales for electrical distribution utilities. Staff 

is evaluating different approaches for allocation of allowances associated with 

the distributed use of natural gas. In the first compliance period, staff proposes 

to freely allocate the majority of allowances to the industrial and electricity

sectors. Appendix J: Allowance Allocation, provides a more detailed discussion 

of the allocation approach being proposed, including discussion of how 

benchmarks will be applied in specific sectors. 

1. Direct Allocation to Industrial Sectors

Staff proposes to use an updating output-based, free allocation methodology,

combined with an emissions efficiency benchmark for allocating to industrial 

sources. This means that the amount of allowances given to each facility is 

based on its production activities in recent years compared with a sector-specific 

benchmark—the more a facility produces, the more free allowances it receives. 

The purpose of updating output-based benchmarking is to incentivize continued 

in-state production by tying the allowance value an entity receives to the amount 

 

20 See the recommendations of the Economic and Allocation Advisory Committee (Appendix L) 

and the recommendations of the California Public Utilities Commission (CPUC) and the California 

Energy Commission (CEC) (Appendix M), as well as Recommendations of the Economic and 

Technology Advancement Advisory Committee. February 2008. 

http://www.arb.ca.gov/cc/etaac/ETAACFinalReport2-11-08.pdf (accessed 10/10/10).
II-31

of its in-state production. This method of allocation helps level the playing field 

with out-of-state manufacturers. 

Staff also proposes to use emissions efficiency benchmarking to reward more 

efficient facilities on an emissions-per-unit-of-output basis. Benchmarking 

establishes an emissions performance standard for each sector. Depending on 

the processes of an industrial sector, it may use one of two types of benchmarks 

in the proposed cap-and-trade regulation: product-based and thermal energybased. 

A product-based benchmark sets an emissions performance standard per unit of 

output. For each unit of product that is manufactured, the benchmark will 

establish a standard level of emissions associated with its production. Ideally, 

staff would apply a product-based benchmark in every case. This type of 

benchmarking rewards efficiency throughout the production process all the way 

to the end product. However, applying a product-based benchmark is not 

feasible in the near-term for some sectors where the production processes are 

very similar, but they produce a wide array of products. For example, food 

processors produce hundreds of different products using a very similar 

production process (e.g., using heat or steam from an industrial boiler). In this 

case, staff would have to create benchmarks for many individual products, which 

is administratively burdensome and not feasible in the near-term. For these 

sources, staff proposes a fall-back approach using thermal energy-based 

benchmarks. 

A thermal energy-based benchmark sets an emissions performance standard 

based on how efficiently a facility sources its energy. For such facilities, staff 

proposes to look at the types of fuels they use to determine the efficiency of their 

production processes. Since natural gas is the dominant fuel used in California 

manufacturing facilities, staff proposes to use the emissions factor associated 

with natural gas combustion as the benchmark for these sources. In this case, if 

a facility used a cleaner fuel source, like biomass, or combusts the fuel more 

efficiently, it would be rewarded with more allowances relative to its actual 

emissions. If a facility used a higher emitting fuel (like coal) or has an inefficient 

combustion process, it would not receive as many allowances relative to its 

actual emissions. 

2. Direct Allocation to Electrical Distribution Utilities

Allowances will be freely allocated to the entities that provide retail electricity to 

California ratepayers, referred to as electrical distribution utilities. Requirements 

for how the freely allocated allowance value can be used differ for IOUs and 

POUs.

For IOUs, the allowances directly allocated to them must be auctioned at general 

quarterly auctions. The proceeds from these auctions must be used by the utility 

to mitigate the bill impacts of AB 32 programs on their distribution customers.

Staff proposes that ARB place all allowances freely allocated to IOUs into their 
II-32

Limited Use Holding Accounts. At each general auction, the utility must consign 

their allowances (put them up for sale at the auction). If the auction settlement 

price21

In the current California electricity market, electricity is produced by both IOUs

and independent generators. An IOU will have a compliance obligation for the 

emissions resulting from generation it operates. An independent electricity 

generator will have a compliance obligation for the emissions from the generation 

it operates. Both the IOU and the independent generator will purchase 

allowances at auction for their emissions. Because the price of electricity in the 

wholesale electricity market will reflect the cost of those purchased allowances, 

staff expects that independent generators will incorporate their cap-and-trade 

compliance costs into their bids in the wholesale power markets.

exceeds the minimum set in the regulation, allowances are sold and the 

proceeds will go to utilities for the benefit of their ratepayers in the form of 

rebates, customer bill relief, or other AB 32 uses. If there are allowances that 

remain unsold at the general auction, they will be transferred back to the entity’s 

Limited Use Holding Account for sale at the next auction. 

22

By requiring IOUs to put their allowances up for auction, the regulation maintains 

the current competitiveness of the deregulated California electricity market. In 

this way, utility-owned generation and independent generation have equal 

access to allowances. 

These costs 

will be paid by the IOUs when the power is purchased.

Most POUs own and operate their own generation and do not compete with 

independent generators in the way IOUs do. Because of this, allowances directly 

allocated to POUs may either be consigned for sale at the general quarterly 

auctions or used directly to meet their compliance obligations. If a POU decides 

to auction some of its allowances at the general auction, the same auction rules 

apply to the POUs as those described above for the IOUs. 

Each year, IOUs and POUs must report to ARB on the monetary value of auction 

proceeds and how the use of this value of the freely allocated allowances 

complies with the cap-and-trade regulation.

Staff is continuing to evaluate possible methods for allocating allowances among 

the electrical distribution utilities. The allocation must further the cap-and-trade 

emissions-reduction objectives, including providing incentives to cost-effectively 

 

21 The auction settlement price is the price that all successful bidders will pay for their allowances 

and the price to be paid to those entities which consigned allowances to the auction.

22 Some generators have reported that some existing contracts do not include provisions that 

would allow full pass-through of cap-and-trade costs. These contracts pre-date the mid-2000s 

and many may be addressed through the recently announced combined heat and power 

settlement at the California Public Utilities Commission. Staff is evaluating this issue to determine 

whether some specific contracts may require special treatment on a case-by-case basis.
II-33

reduce emissions. Additionally, the allocation must enable all the utilities to 

serve their customers reliably and affordably. 

Staff recognizes that substantial effort is being asked of the electricity sector to 

realize environmental and energy security goals for California, which include

addressing the following policy objectives:

23

• Energy efficiency and demand response are the top priority for meeting 

future energy needs.

• Renewable energy is the preferred electricity supply resource, reflected in 

recently adopted renewable energy procurement requirements under the 

Renewable Electricity Standard (RES).24

• Combined heat and power and distributed generation are priorities, 

including the California Solar Initiative and the New Solar Homes 

Partnership.

• Continued reductions in the impacts of power plants on air quality and 

coastal and estuarine environments will be achieved with power plant 

efficiency and control improvements.

• Electrification of transportation is expected to contribute to energy security 

as well as environmental goals.

Utilities are committing significant resources to achieve these policy objectives, 

most of which help reduce GHG emissions.

Staff must also consider that, although all the utilities are moving toward these 

common policy goals, they currently have very different GHG emissions profiles 

and emissions-reduction opportunities. Some utilities, particularly in Southern 

California, have relied more on coal-fired electricity generation and have longterm commitments that were developed prior to concerns about GHG emissions 

and AB 32. Although Senate Bill 1368 (SB 1368, Perata, Chapter 598, Statutes 

of 2006) and its implementing regulations will result in substantial displacement 

of coal-based electricity imports from long-term commitments, existing contracts 

and ownership agreements have substantial remaining time periods; for instance, 

some stakeholders have stated that their existing agreements run through 2027

and would be costly to terminate. In Northern California, hydroelectric resources 

are more abundant, and those, combined with natural gas, result in a lower-

 

23 A summary is presented in California’s Clean Energy Future. An Overview on Meeting 

California’s Energy and Environmental Goals in the Electric Power Sector in 2020 and Beyond, 

California Energy Commission Report CEC-100-2010-002, September 2010, at: 

http://www.climatechange.ca.gov/energy/index.html (accessed 10/14/2010). 24 Renewable Electricity Standard. California Air Resources Board. Found at: 

http://www.arb.ca.gov/energy/res/res.htm (accessed 10/10/10).
II-34

emitting generation portfolio. Additionally, the absence of long-term contracts 

tied to high-emitting resources provides more flexibility to reduce emissions prior 

to 2020.

This diversity of resources and emissions-reduction opportunities across utilities 

creates challenges for defining an allowance allocation method that provides 

proper incentives, is affordable for all utilities, and is considered equitable. 

Approaches proposed by stakeholders, the California Public Utilities Commission 

(CPUC), and the California Energy Commission (CEC)

25

To date, staff’s analyses of options based on historical emissions and sales have 

not identified an allocation method that provides appropriate incentives for 

emissions reductions and is considered affordable and effective for all utilities. 

The contracts for high-emitting resources pose a particular challenge. Some 

contracts expire as soon as 2016, providing substantial opportunity for emissions

reduction prior to 2020. Other commitments run past 2020, limiting the 

opportunity to reduce emissions from the existing resource in the next 10 years, 

even as substantial investments are made to acquire new low-emitting resources. 

Simply considering historical emissions and sales does not adequately reflect 

these divergent circumstances. Also, the allocation method must avoid 

inadvertently providing an incentive to continue using high-emitting resources, 

but rather must provide incentives to ensure that all cost-effective efforts are 

undertaken to achieve necessary emissions reductions.

have suggested 

balancing historical emissions and electricity sales to allocate allowances. By 

considering historical emissions, allocation can recognize the diversity of 

generating resources across utilities. Recent investments to reduce emissions 

can also be rewarded by using historical emissions that, for example, preceded 

the enactment of AB 32. By considering retail sales, allocation can reflect 

differences in the amount of electricity delivered by each retail provider. The 

sales metric would reward utilities that achieve lower emissions intensities, 

consistent with the long-term goal of reducing GHG emissions from the sector 

overall.

Staff is continuing to examine options and obtain feedback. With input from 

stakeholders, staff’s analysis is examining additional factors that could be 

considered beyond historical emissions and sales, including, among other things, 

the dates of contract expirations, the rate of achievement of renewable and other

low-emitting resources, incentives for early reductions in commitments for highemitting resources, and other program design features. Staff will continue to 

work with stakeholders and will review comments received during the comment 

period on this proposal. Staff may bring a more detailed proposal to the Board 

 

25 The California Public Utilities Commission and the California Energy Commission presented 

recommendations to ARB about the design of a cap-and-trade program for the electricity sector in 

October 2008. Those recommendations are included as Appendix M.
II-35

based on this ongoing effort, and will circulate any such proposal for review in a 

subsequent 15-day comment period. 

3. Allocation of Allowances Associated with Distributed Use of Natural 

Gas 

Beginning in 2015, natural gas distribution utilities will be responsible for the 

emissions associated with natural gas delivered to customers not directly 

covered under the cap-and-trade program, including residential, commercial, and 

small industrial customers. Following comparable arguments to those applied in 

the electric sector, the investor-owned natural gas distribution utilities have 

proposed allocation to the gas utilities based on the proportionate share of total 

capped emissions from residential and commercial natural gas use over a 

historical period. 

Under the utilities’ proposal, the allowances allocated to the sector would decline 

over time in proportion to overall cap decline. The utilities requested that ARB 

allow 90 percent of the allowances to be directly retired to reduce the utility 

compliance obligations, with the remaining 10 percent offered on consignment by 

the utility at auction. The proceeds raised from the sale of this 10 percent would 

be used to fund customer energy efficiency and other greenhouse gas reduction 

programs. 

ARB is considering this proposal along with alternative approaches. One 

alternative would be for ARB to allocate allowances to the utilities but require 

them to offer all allowances on consignment at auction. Proceeds from the sale 

of these allowances could then be used to provide rebates to customers on a 

non-volumetric basis. The CPUC would determine the final amount of proceeds 

dedicated to rebate programs or to customer energy efficiency and other GHGreduction programs. This treatment would be analogous to how investor-owned 

utilities are expected to protect their customers in the electricity sector. 

Another alternative under consideration would be to have the allowances 

associated with emissions from dispersed natural gas combustion auctioned and 

the allowance value returned to customers through action by the Governor and 

the Legislature. This approach is analogous to how other distributed fuel use 

(i.e., gasoline, diesel, and propane) is treated under staff’s current proposal. 

J. Auction and Sale of California Greenhouse Gas Allowances 

ARB staff developed its auction design proposal based on a set of objectives that 

were discussed with stakeholders including: 

 Promoting open access to the auction. 

 Ensuring fairness and transparency of the procedures. 

 Minimizing administrative and transactions costs to participants. 
II-36

• Promoting economic efficiency.

• Preventing manipulative behavior.

• Revealing the market valuation of allowances.

• Minimizing price volatility.

• Promoting allowance market liquidity.

Staff has carefully examined rules for auction in existing GHG emissions trading 

systems, and is proposing an auction design closely resembling that used in the 

Northeast Regional Greenhouse Gas Initiative (RGGI). Staff also continues to 

participate in the development of recommendations for auction design in the WCI. 

Preliminary WCI recommendations are consistent with most of the main design 

features in the ARB staff proposal.26

1. Timing of Allowance Auctions

The first allowance auction will take place in February 2012. The auctions will 

continue based on the calendar quarter for the remainder of the program. These 

auctions are general auctions in which covered entities, opt-in covered entities,

and voluntarily associated entities may bid for allowances.

At each general quarterly auction, one-quarter of the total allowances available 

for auction in the budget year will be auctioned. A number of allowances from 

future budget years will also be auctioned. In addition to these allowances, any

party with a Limited Use Holding Account in the system may offer their 

allowances for sale at the general quarterly auction. Any party using this 

“consignment” option will be paid the auction settlement price for their allowances. 

If any allowances offered on consignment remain unsold after the auction, ARB 

will transfer them back to the owners’ accounts. 

Three weeks after the regular quarterly auction, ARB will also offer allowances in 

the Reserve for sale at fixed prices to covered entities. 

2. Auction Format and Reserve Price

In each auction, participants can submit bids by specifying how many allowances 

they want at a specific price. Allowances will be sold in 1,000 unit bundles. 

Participants can submit as many bids as they like, as long as they can prove to 

the auction operator that they can pay for allowances they win. The bids will be 

sealed, which means a participant does not know what price others have bid. A 

 

26 Western Climate Initiative. Markets Committee Task 6: Auction Design White Paper. April 14, 

2010. Found at: http://www.westernclimateinitiative.org/component/remository/funcstartdown/231/.
II-37

sealed bid makes it difficult for participants to manipulate the auction price or 

collude with others to change the auction price for their mutual benefit. 

The auction will be settled in a single round of bidding. The auction operator will 

award allowances beginning with the highest bid. The operator will award 

allowances to each bid in declining order until all allowances are awarded. 

However, the auction operator will not accept any bids below the reserve price. If 

the auction settlement price equals the reserve price, unsold allowances will be 

placed into the Reserve, or in the case of IOUs and POUs offering their 

allowances on consignment, back to their Limited Use Holding Accounts. 

Allowances placed back into the Reserve will be offered at the direct quarterly 

reserve sales that occur after each general auction, as described below. 

The reserve price in the proposed regulation has been set at $10/metric ton for

auctions in 2012. This is the same level as the price floor that was established in 

the Waxman-Markey cap-and-trade legislation introduced in the United States 

Senate in 200927

3. Auction Administration and Registration

. Staff believes setting the reserve price at this dollar amount 

will send a signal to technology developers, as well as those investing in GHG 

offset projects. For all years following 2012, this reserve price will be increased 

by 5 percent plus a consumer price index. The auction reserve price is one of 

the components of a linked regional market program for which consistency 

across the individual programs is especially important. For this reason, ARB staff 

will work closely to evaluate this issue with other WCI jurisdictions while 

evaluating their programs for possible linkage. Staff may propose an adjustment 

to the reserve price as part of changes made to link California’s program with the 

programs established by WCI partner jurisdictions. 

The auctions will be conducted by ARB or may be contracted to a third party that 

is hired by ARB to act as the auction operator. Any auction operator hired by 

ARB to conduct auctions will be subject to ARB oversight, and no auctions will be 

final until ARB approves the results. If California links with other WCI

jurisdictions, then the auction operator may sell California and linked jurisdictions 

allowances in the same auction.

ARB will announce the auction on its website at least 60 days prior to each 

auction. This announcement will specify the date, time, and location of the 

auction; information that must be submitted to ARB by those wishing to 

participate in the auction consistent with the proposed regulation; and the 

number of allowances that will be auctioned.

 

27 American Clean Energy and Security Act of 2009, H.R. 2454, 111th United States Congress, 1st

Session. (2009).
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All entities wishing to participate in an auction must register for each auction at 

least 30 days prior to the date of the auction. The proposed regulation specifies 

the information each auction participant must submit to take part in the auction. 

The registration process allows ARB to update information on participants. ARB 

retains the ability to deny registration approval to any participant with a history of 

violating auction or market rules. Each entity must also provide a bid guarantee. 

A bid guarantee provides assurance to ARB that the purchaser of allowances at 

auction has the financial capability to buy them. A bid guarantee can be a bond 

issued by a financial institution, cash in the form of a wire transfer or certified 

funds, or a irrevocable letter of credit issued by a financial institution. 

Staff proposes to implement a limit, known as a purchase limit, on the amount of 

allowances that a single entity and its affiliates are able to purchase at any single 

auction to ensure that all entities with a compliance obligation have fair and 

equitable access to allowances sold at auction. Each covered entity and opt-in 

covered entity can purchase of a maximum of 10 percent of the total number of 

allowances offered for each budget year. Each voluntarily associated entity can 

purchase a maximum of four percent of the total number of allowances offered at 

each auction. ARB believes this purchase limit, together with direct allocations to 

covered entities and the option to use offset credits, would allow covered entities 

to obtain a sufficient part of their compliance obligation at auction. In addition, 

ARB proposes to exempt the investor-owned utilities from the purchase limit

because entities do not receive a direct allocation that they can use for their own 

compliance needs.

4. Direct Quarterly Sales of Allowances from the Allowance Price 

Containment Reserve 

Staff recognizes that unforeseen events, such as a drought year that results in 

low hydroelectricity generation and high electricity sector emissions, could create 

a shortage of allowances and result in periods of high market prices. The 

proposed regulation includes a reserve pool of allowances to manage potential 

price spikes. Covered entities will have the option of buying from the reserve 

pool at fixed prices. The reserve allowances will not be available to voluntarily 

associated entities.

Sales from the Reserve will take place three weeks after each quarterly auction. 

Allowances in each tier can be purchased at a fixed price. Staff proposes to set 

these prices at $40/metric ton, $45/metric ton, and $50/metric ton. These prices 

will increase each year. Covered entities will place bids for the number of 

allowances they wish to buy from each tier. Many of the administrative 

procedures, such as the requirement for a bid guarantee, will be the same as for 

the auction. The Reserve administrator will award allowances from each tier until 

the tier is exhausted. Empty tiers will not be refilled. If too many bids are 

submitted for a tier, the Reserve administrator will prorate the available 

allowances to the bidders.
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Purchases from the Reserve will be subject to the Holding Limit described in 

Section K: Trading and Banking. In addition, allowances purchased from the 

Reserve will be transferred by the administrator directly to the purchasing entity’s 

Compliance Account, from which it cannot be removed until it is surrendered. 

Staff proposes this to ensure that allowances are only purchased to meet 

compliance needs, not to provide a supply of allowances for speculative activity.

5. Identifying Corporate Affiliations and Beneficial Purchases

Staff proposes to require disclosure of affiliations of registered entities, along with 

entities purchasing or holding instruments on behalf of another entity. These 

disclosures are essential to market monitoring. The information is also crucial to 

evaluating the purchase and holding limits when auction purchases are made. 

K. Trading and Banking

Trading allowances establishes a price for each metric ton of GHG emissions. 

Participation of covered entities ensures the market price reflects the cost for 

reducing emissions per metric ton, as well as market participants’ expectations of 

how that cost will change over time. An entity would buy an allowance if the 

market value of the allowance is less than the entity’s cost of reducing emissions. 

Alternatively, an entity may sell an allowance to another entity at the current 

market price if it can make direct reductions at a cost lower than the allowance 

price. An entity that anticipates that the cost of direct reductions will be more 

expensive in the future may purchase and hold allowances for sale in the future.

Staff is proposing rules to prevent market manipulation, since some entities may 

attempt to manipulate the market for compliance instruments, as has been 

observed in other markets. Some rules involve information disclosures to assist 

in monitoring the market. Staff is also proposing prohibitions on trading activities 

that involve fraud, reporting false or misleading information, misrepresentations, 

and manipulations that are commonly used in other markets.

One prohibition in the proposed regulation deals with efforts to “corner” a market 

—an entity purchases such a large share of available compliance instruments 

that other market participants have no choice but to buy from them. To combat 

this tactic, staff proposes the use of a holding limit, which is the maximum share 

of available compliance instruments that an entity or group of affiliated entities 

may own. All types of registered entities will face a limit on allowances placed in 

their Holding Accounts, which entities use for buying and selling. Covered 

entities will have an exemption from the holding limit for allowances they place in 

their Compliance Accounts up to the amount of their most recent year’s verified 

emissions. This exemption allows them to accumulate compliance instruments 

to meet their surrender obligation without violating the limit. Without this limited 

exemption, ARB would have to set the holding limit so high that it could not 

prevent hoarding. Holdings by affiliated entities will be evaluated as if they 

belonged to a single entity.
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Transactions, such as trades or surrender of compliance instruments, are

transfers of serial numbers between accounts. All transfers are accomplished 

through submission of a transaction report to the accounts administrator. Staff 

proposes that these reports include such information as account numbers and 

authorized account representatives of both parties, the serial numbers of

instruments to be transferred, settlement and delivery dates, and price if 

applicable. The rules also set a time limit for reporting the transaction. The 

accounts administrator may reject reports if the transaction does not conform to 

the regulations.

California compliance instruments do not expire. This allows an entity to hold the 

instrument until it is needed. Staff proposes this “banking” feature to allow 

entities to save instruments across compliance periods. This is intended to limit 

price variability, as entities buy additional instruments during times of relative 

oversupply and use or sell them when supplies are short and prices are higher.

Allowances issued for a future year cannot be used for surrender in an earlier 

compliance period. The one exception is an allowance purchased from the 

Reserve, which may be used as soon as it is bought. This approach is proposed

to prevent the threat of “cascading borrowing.” This situation occurs when 

entities are able to use future allowances for current compliance, and it creates a 

growing shortage of instruments in later compliance periods.

Staff also proposes that entities without a compliance obligation may voluntarily 

submit allowances to ARB for retirement. The process simply requires them to 

submit a transaction report that names the ARB Retirement Account as the 

destination account for the transaction.

L. Linkage

The concept of linkage involves integrating one greenhouse gas emissions 

trading system with one or more other systems. When two cap-and-trade 

programs—for example, California and another WCI partner jurisdiction—

recognize allowances and offsets from each other’s systems, they are linked. 

The two systems must agree to accept allowances and offsets to meet surrender 

obligations interchangeably between them. If California were to link to another 

program, allowances could flow in both directions between California and the 

other system. To accomplish this in California, ARB would accept allowances or 

offsets issued by other approved programs to meet a compliance obligation in 

the California cap-and-trade program.

If California were to link, covered entities would generally use allowances and 

offsets from a linked program if they were less expensive than making reductions 

on-site or purchasing California allowances and offsets. Sources in both 

programs would seek out the lowest cost reductions to be found across systems, 

which should lead to a more liquid and better functioning market. For this reason, 

linkage allows for increased cost-containment by reducing the aggregate cost of 
II-41

meeting the cap. While the proposed regulation establishes a framework and 

criteria for linkage, staff is not proposing to link to any programs at this time.

1. Evaluating Linkages

Each cap-and-trade program will have slightly different design elements. If 

design features exist or are later adopted into a linked program they will be made 

indirectly available to California participants, regardless of whether the same 

provisions exist in the design of the California program. Therefore, it is critical 

that before California links to another program, ARB evaluate the design features 

of a potential linked program. There must also be assurances that the program 

will continue to implement the agreed-upon program design moving forward.

When evaluating a program for linkage it is important to consider the implications 

that linkage may have on California’s program, including the indirect impacts that 

could occur. When California establishes a linkage there may be unintended 

consequences for the California cap-and-trade program. These consequences 

could occur if the linked system makes changes to the design of its program in 

the future or links to another system. 

2. Process for Approval of Linkages

A regulatory action by the Board will be needed to approve linkage with another 

program. Before a program would be brought to the Board for approval, it would 

undergo an analysis culminating in a separate rulemaking process. Each 

rulemaking process would occur prior to staff proposing regulatory amendments 

incorporating the linkage, and would include a public process, CEQA evaluation,

and statement of reasons. The linkage section in the regulation would be 

amended to include specific provisions for each approved linkage.

3. Criteria for Evaluating a Program for Linkage

Following staff’s evaluation of the implications of the linkage, staff would propose 

linkage to the Board. In evaluating whether California should link to another 

program, staff will consider criteria that the potential linked program must meet, 

as discussed below.

The potential program must be operated by a sub-national or national 

government that has committed to a similarly stringent binding and declining cap. 

That cap must also cover one or more economic sectors, such as in the 

California cap-and-trade program.

The key to maintaining the environmental integrity of the California cap-and-trade 

program is the effectiveness of its monitoring, reporting, verification, and 

enforcement provisions. Although, these provisions do not need to be identical, 

ARB needs to be confident that the linked program has provisions for monitoring, 

reporting, verification and enforcement that are reliable and sufficient to ensure 

the environmental integrity of the program. 
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Certain other features of a cap-and-trade program, mainly those designed to 

contain costs, need to be harmonized before ARB links to another program. In 

particular, these include cost-containment provisions such as offset credits, 

linkage to other programs, an auction floor price, and banking and borrowing.

The potentially linked program must contain provisions to ensure that offset 

credits issued by, and accepted into, its system provide the same integrity as 

those issued by California’s program. Because the design and operation of an 

offset program is key to maintaining the environmental integrity in any cap-andtrade program, the potential program must have a mechanism that limits the use 

of offset credits in its program, similar to California’s quantitative usage limit. 

In addition to including similar cost-containment mechanisms, the potentially 

linked program must have sufficient requirements for market tracking, registration, 

enforcement, and information transfer. The system must have a market tracking 

system that is able to provide that compliance instruments, when voluntarily 

retired or used to meet a compliance obligation in any program, are disqualified 

from further use in any program. This mechanism will ensure that the same 

allowances and offsets are not used more than once in multiple programs.

The potentially linked program must also have a comprehensive registration 

requirement for all market participants and be capable of transferring information 

on all registrants to California’s market tracking system. The program must be 

able to: transfer information on creation, approval, and retirement of compliance 

instruments; serve as a permanent repository of ownership information on all 

transactions involving approved compliance instruments, from the time they are

created or approved to the time they are retired, including prices, those who 

transact compliance instruments, and other documentation; and provide a 

complete history of ownership of all approved compliance instruments to linked 

programs that may retire the compliance instruments issued, or approved for use, 

under its system. These requirements are necessary for ARB to be able to track 

the owner of a specific compliance instrument at any time, even if it did not 

originate in California’s market tracking system.

It is important for linked programs to have a similar level of enforcement 

provisions as those of ARB. The potentially linked program must have an 

enforcement mechanism that can: provide general market surveillance; identify 

suspect transactions; undertake investigations and enforcement actions; ensure 

that consequences for noncompliance are substantially the same in all programs 

linked to its system; respond in a timely manner to requests by ARB for 

information on market participants under investigation by ARB; and transfer to 

ARB, in a timely manner, a complete record of all enforcement actions 

undertaken by the program’s jurisdictional enforcement authority. 

The potentially linked program must also be capable of transferring marketsensitive information necessary to monitor market trends on a regional basis, 

including: prices, aggregate emissions, positions of major market participants,
II-43

issuance of offset credits, and information that can be released to the public in a 

coordinated and consistent manner. By requiring transparency and collecting 

pertinent market and trading information ARB, as well as the public, can monitor 

and track market transactions and trends.

4. Potential Linkage with Western Climate Initiative Partners

Although California is unable to include regulatory language for linkage to 

programs that are still being developed, some WCI partners may be ready to 

implement their cap-and-trade programs in the near term. 

WCI partners developed a model rule released in July 2010 called the Design for 

the WCI Regional Program.28

Staff is looking to link with WCI partner programs for several reasons, including:

 Four other WCI Partner jurisdictions—New Mexico, 

British Columbia, Ontario, and Quebec—are working to implement their cap-andtrade programs by January 2012. Although these partner jurisdictions have not 

finalized their programs, staff has been working closely with them and is 

confident that these partners are moving forward with cap-and-trade programs 

generally consistent with the Design for the WCI Regional Program. As these 

programs move closer to implementation, staff will evaluate them and return to 

the Board with recommendations for linkage.

• Achieving greater emissions reductions and improving the costeffectiveness of the program by including additional low-cost emissionsreduction opportunities throughout the region.

• Reducing the risk of emissions leakage and maintaining competitiveness 

by expanding the geographic coverage.

• Improving market liquidity and reducing market volatility and manipulation 

by enlarging the supply of compliance instruments.

Linkage provisions adopted through a separate regulatory process would need to 

specify how the cap limits would be adjusted to include linkage to WCI partner 

jurisdictions where California is an importer of electricity. Currently, the proposed 

regulation accounts for emissions of imported electricity in the allowance budgets. 

To prevent double-counting of these emissions, California would have to subtract 

these emissions from cap levels in the case of future linkages. In this case, ARB 

would specify in the approval of linkage the equivalent number of allowances that 

 

28 Design for the WCI Regional Program. Western Climate Initiative, July 27, 2010. Found at: 

http://westernclimateinitiative.org/component/remository/general/program-design/Design-for-theWCI-Regional-Program/.
II-44

would need to be retired in the California system to account for the emissions of 

imported electricity from the linked jurisdiction.

New Mexico’s proposed regulation29

M. Offset Credits Issued by ARB

varies from the Design for the WCI Regional 

Program in a number of areas, including not accounting for emissions associated 

with imported electricity. AB 32 requires ARB to account for emissions 

associated with imported electricity and to minimize leakage. Staff plans to work 

closely with New Mexico and the relevant utilities to determine what can and 

should be done to allow California to appropriately account for imported 

electricity. If an appropriate mechanism can be developed and implemented, 

and all other aspects of New Mexico’s program are acceptable for linkage, ARB 

staff would be able to recommend to the Board that California’s program should 

link with New Mexico’s program.

Individual projects can be developed to achieve GHG reductions from activities 

not otherwise regulated or covered under the cap-and-trade program. These 

projects, called offset projects, can generate offsets, or verifiable emissions

reductions whose ownership can be transferred to others, including entities with 

a compliance obligation under a cap-and-trade program. In addition to providing 

compliance flexibility, the inclusion of offsets in the program will support the 

development of innovative projects and technologies from sources outside 

capped sectors that can play a key role in reducing emissions both inside and 

outside California.

As required by AB 32, any reduction of GHG emissions used for compliance 

purposes must be real, permanent, quantifiable, verifiable, enforceable, and 

additional (HSC §38562(d)(1) and (2)). Offsets issued by ARB must be 

quantified according to Board-adopted methodologies. The proposed regulation 

includes provisions to verify and enforce the reductions incentivized through the 

generation and retirement of offset credits. The regulatory criteria for compliance 

offsets will ensure that the reductions are quantified accurately and are not 

double-counted within the system. 

Staff recognizes that a robust supply of offset credits can help to contain the 

costs of a cap-and-trade program. To promote the supply of offset credits, staff 

proposes that: (a) ARB issues offset credits for projects using ARB-approved 

protocols, and (b) ARB recognizes offset credits from ARB-approved offset 

programs. These programs could include sectoral programs such as those 

reducing emissions from deforestation and forest degradation in developing 

 

29 Proposed Greenhouse Gas Cap-and-Trade Program, New Mexico Environment Department. 

(2010). Found at: http://www.nmenv.state.nm.us/cc/CapandTradeRegulation.htm.
II-45

countries (REDD). Offset credits from linked programs (such as WCI partner 

jurisdictions) would also be eligible for use in California’s cap-and-trade program. 

ARB staff incorporates provisions in the proposed regulation to allow these two 

methods to be used following Board approval of specific protocols or programs. 

The proposed regulation includes provisions to specify requirements for thirdparty verifiers, offset project developers, and offset credit users, as well as 

penalties for noncompliance. Since offset projects can be located outside of 

California, all offset credits must be verified by an ARB-accredited verifier, and 

ARB has the ability to audit all accredited verifiers. Offset verification procedures 

in the proposed program are designed to reduce subjectivity and uncertainty. 

These procedures help ensure the rigor and validity of offset credits. The offsets 

verification program requires that verifiers demonstrate competence in each 

specific project type, employ conflict of interest assessments and mitigation 

requirements, and include random verifier audits and strict performance 

evaluations to ensure that offset verification activities are conducted accurately 

and properly. The program’s underlying registry system for compliance 

instruments is being designed to provide strong enforcement capabilities,

including mechanisms to prevent double-counting, impose public disclosure 

requirements, and ensure ownership.

For offset credits issued by ARB, all offset protocols used in the compliance 

program must be adopted by the Board. The proposed regulation establishes 

the process by which the Board will approve and amend offset protocols based 

on staff’s evaluation and a public process. These protocols will be made publicly 

available so that anyone interested in developing an offset project can do so 

according to Board-approved standards. Approved protocols serve as a 

cornerstone to ensure that reductions are appropriately quantified, monitored, 

reported, and documented. Those taken to the Board for adoption will consist of 

standardized methods that quantify reductions based on specific criteria and preestablished calculation methods. This approach will result in streamlining the 

calculation of project baselines and determining the additionality of projects using 

standard eligibility criteria that ensure projects are additional. 

Staff has developed four compliance offset protocols, which can be found in 

Parts II through V of the Staff Report, for use under the compliance offset

program. These protocols include the U.S. Forest Projects Protocol, the

Livestock Manure (Digester) Projects Protocol, the Urban Forest Projects 

Protocol, and the U.S. Ozone Depleting Substances Projects Protocol. They are 

incorporated by reference in the proposed regulation and are being considered 

for adoption by the Board as part of this rulemaking package. While the program 

contains provisions to allow offset projects from North America, staff is only 

taking offset protocols applicable in the United States to the Board for approval 

as part of this rulemaking package. 

ARB has coordinated with the other WCI partner jurisdictions in developing the 

offset program, including identifying specific project types for first priority and a 
II-46

review of existing protocols for those project types.

30

To ensure that there is a ready supply of offset projects developed according to 

Board-approved protocols, staff proposes to work with qualified third-party offset 

programs to bring offset credits from new offset projects into the offset program. 

Staff recognizes that third-party offset programs have existing capabilities and 

infrastructure that can be deployed quickly to enhance the supply of offset credits. 

The proposed regulation includes conditions and processes under which thirdparty programs can be approved to generate offset credits for compliance use 

according to ARB-approved protocols.

 While ozone-depleting 

substances projects were not included in this priority review, ARB considers it to 

be a promising offset project type. The WCI partner jurisdictions are currently 

reviewing this protocol, including assessing it relative to the WCI offset criteria 

recommendations. Staff will continue to work within WCI to address any issues 

that may arise with use of this protocol in the context of linking with a WCI 

partner.

The proposed regulation establishes requirements for offset projects that want to 

be issued offset credits. These include using a Board-approved protocol, 

meeting the requirements for additionality, being located in North America, and 

complying with all applicable laws and regulations at the national, state or 

provincial, and local levels. 

The proposed regulation requires that project developers “list” their projects (i.e.,

submit information pertaining to their offset projects). Listing establishes a 

mechanism for project developers to record information on their offset projects 

for ultimate issuance of offset credits. Project listing requires the submittal of 

information on each project for transparency purposes. The requirements for 

what information must be submitted can be found for each type of offset project 

in the corresponding offset protocol, which are incorporated by reference in the 

proposed regulation. When listing, project developers must also attest to ARB 

that all information they submit for listing purposes is truthful and accurate. 

These attestations will be used for enforcement purposes. 

Monitoring requirements in the proposed regulation include measurement and 

data collection for key project parameters, as well as related procedures and 

quality control procedures. The monitoring requirements address questions 

regarding what needs to be measured, how often, and acceptable methods and 

instrumentation for data collection. The staff proposal requires measurement 

 

30 Det Norske Veritas. Review of Existing protocols Against WCI Offset Criteria. For the Western 

Climate Initiative. April 2010. Found at: 

http://www.westernclimateinitiative.org/component/remository/Offsets-CommitteeDocuments/WCI-Review-of-Existing-Offset-Protocols. 
II-47

device calibration according to the manufacturer’s recommended procedures. 

General monitoring requirements can be found in the proposed regulation, while 

specific requirements for each type of offset project can be found in the individual 

protocols. Protocol-specific monitoring requirements increase consistency 

among projects of the same type and allow monitoring requirements to be 

tailored to each project type.

The proposed regulation requires reporting on the performance of offset projects, 

including a process for summarizing project monitoring data, calculating the GHG 

reductions achieved in the applicable period, and documenting that information in 

a project report. The required content and level of detail demanded in project 

reports, referred to as Offset Project Data Reports in the proposed regulation, 

vary between project types.

In the proposed regulation, staff includes requirements for a verification program 

that are consistent with international standards and subject to ARB oversight. 

This oversight includes verifier accreditation, verification body accreditation, 

requirements for verification services, and conflict-of-interest requirements. The 

proposed regulation includes enforcement provisions that apply to parties that 

participate in the offset program. These parties include offset project developers, 

verifiers, and covered entities.

The proposed regulation establishes a Forest Buffer Account—a permanence 

mechanism for ensuring that GHG emissions remain out of the atmosphere—to 

replace offset credits in the event of an unintentional reversal. The Forest Buffer 

Account acts as an insurance policy; the developer pays a premium up front to 

be fully covered later in the event of a loss. A portion of all offset credits issued 

to offset projects developed according to ARB’s U.S. Forest Projects Protocol 

must be placed into the Forest Buffer Account to cover unintentional reversals. 

The forest project operator is required to follow the methods in the U.S. Forest 

Projects Protocol for calculating the project’s risk rating. The risk rating is based 

on a number of default and calculated factors that differ, depending on the 

individual project. The factors and equations that must be used to determine 

each project’s risk rating are provided in the U.S. Forest Projects Protocol. 

To ensure enforceability of compliance offsets, ARB needs to have the ability to 

investigate and take action for violations or noncompliance with the regulations. 

There are two primary reasons that ARB may need to invalidate offset credits 

after they have been issued: (1) fraud or malfeasance on behalf of the project 

developer, the third-party verifier, verification bodies, or others involved in 

producing the documentation used to support the issuance of offset credits, or 

(2) a reversal in the forest sector. If an offset credit is invalidated and has been 

used for compliance or retired, it must be replaced. If the offset credit has 

already been retired, staff is proposing, in all cases of fraud or malfeasance, that 

the entity that used or retired it be responsible for replacing any invalidated offset

credits. The covered entity may then take appropriate action through third-party 

contractual arrangements they may have established prior to purchase. In the 
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event that the offset credit has not yet been used or retired, it will be canceled in 

the market tracking system and removed from any Holding or Compliance 

Accounts. If there is an unintentional reversal in the forest sector, staff will 

deduct the necessary amount of offset credits from the Forest Buffer Account 

and retire them, whether or not they have been used or retired within the system. 

If there is an intentional reversal in the forest sector, staff proposes that the forest 

project developer replace the invalidated offset credits, whether or not they have 

been retired within the system.

N. Recognition of Compliance Instruments from Other Programs

1. Early Action Offset Credits

The proposed regulation includes a process for accepting offset credits from 

qualified existing offset projects into the ARB compliance offsets program to help 

create an initial supply of offset credits for the cap-and-trade program. Beginning 

in 2005, the Climate Action Reserve (CAR) and its predecessor, the California 

Climate Action Registry, began adopting voluntary GHG accounting protocols to 

encourage voluntary early action to reduce GHG emissions. ARB recognizes the 

rigor of the voluntary accounting procedures CAR adopted to establish that GHG

emissions reductions are real, additional, and permanent. Staff proposes to 

allow eligible offset credits and ongoing projects under protocols developed for 

four project types to transition into ARB’s compliance offset program. These 

project types are the four for which protocols are proposed for adoption as part of 

the cap-and-trade regulation: (1) U.S. Forest Projects, (2) Urban Forest Projects, 

(3) U.S. Ozone Depleting Substances Projects, and (4) Livestock Manure 

(Digesters) Projects.

Staff includes requirements in the proposed regulation that an offset program 

must meet in order to have its early action offset credits used for compliance 

purposes. 

2. Sector-Based Offset Crediting Mechanisms

The regulation establishes a framework for accepting sector-based offset credits 

from developing countries. While staff is not proposing to approve any sector 

offset crediting programs or adopt any protocols for sector-based offset credits at 

this time, this framework should help provide a necessary incentive for 

developing countries to reduce their emissions and work toward meeting 

compliance-grade, sector-based offset credit requirements in California.

Each sector-based crediting program will need to be approved by the Board, and 

staff anticipates that a limited number of sector-based programs will be approved 

in the near-term because of the intensive review each program will undergo. 

Staff also proposes that the first sectors to be considered for approval be 

developed through existing partnerships, such as the Governors’ Climate and 

Forests Task Force (GCF) and the International Carbon Action Partnership 

(ICAP). To that end, Reducing Emissions from Deforestation and Forest 

Degradation (REDD) is likely to be the first type of sector-based crediting 
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program brought to the Board for consideration, as is discussed in more detail in 

Chapter III: Overview of the Compliance Offsets Program. 

Some general requirements have been proposed in the regulation that sectorbased crediting programs should meet before being considered by the Board, but 

more detailed criteria and methodologies must be established for each sector 

prior to Board approval and acceptance of sector-based credits. 

O. Enforcement and Penalties

ARB has authority in existing Health and Safety Code provisions to enjoin and 

set penalties for violations of its regulations. As such, staff has established in the 

proposed cap-and-trade regulation violations unique to the cap-and-trade

program. These include defining a separate violation for each compliance 

instrument for each day that has not been surrendered as required, and a 

separate violation for each day or part of a day for which any other part of the 

regulation has been violated.

1. Jurisdiction

Staff recognizes that not all participants in the California cap-and-trade program 

will be located in California. The regulation contains a list of activities involved in 

the cap-and-trade program that would establish the jurisdiction of California over 

the entity. These include: registration, the purchase or holding of a compliance 

instrument issued by ARB, verification of an offset to be issued by ARB, or the 

receipt of any form of compensation resulting from participation in the transfer of 

allowances or offsets issued by ARB.

2. Authority to Suspend, Revoke, or Restrict Accounts or to Modify an 

Executive Order

In addition to conventional penalties, staff proposes that ARB may limit the ability 

of a registered entity to fully participate in the market as a response to violations 

by the entity. For voluntarily associated entities, staff proposes that the 

Executive Officer be able to suspend, revoke, or place transaction restrictions on 

the Holding Accounts of violators. For covered entities, staff proposes that the 

Executive Officer be able to place transaction restrictions on the Holding 

Accounts of violators. Staff also proposes that the Executive Officer be able to 

revoke the registration of entities in the Other Registered Participants category if 

they violate the regulations. Finally, staff proposes that the Executive Officer be 

able to suspend, revoke, or modify an existing Executive Order in response to 

violations by an entity.

P. AB 32 Requirements

AB 32 contains standards that apply to regulations that will be adopted for all 

GHG emissions-reduction measures (HSC section 38562) and additional 

requirements for market-based regulations such as a cap-and-trade program 

(HSC section 38570(b)). AB 32 also calls for ARB to direct public and private 

investment to the extent feasible toward disadvantaged communities and provide 
II-50

an opportunity for small business, schools, affordable housing associations, and 

other community institutions to participate in and benefit from statewide efforts 

(HSC section 38565). AB 32 further requires that the GHG reductions be real, 

additional, permanent, quantifiable, verifiable, and enforceable. 

The cap-and-trade program was developed in accordance with these AB 32

requirements, and this Staff Report presents supporting details. The following 

provides a brief response to each of the specific requirements set forth in 

sections 38562(b), 38562(d), and 38570(b) of the Health and Safety Code. The 

text in italics is verbatim from the particular section.

38562(b) In adopting regulations pursuant to this section and Part 5 

(commencing with Section 38570), to the extent feasible and in furtherance of 

achieving the statewide greenhouse gas emissions limit, the state board shall do 

all of the following:

(1) Design the regulations, including distribution of emissions allowances 

where appropriate, in a manner that is equitable, seeks to minimize costs 

and maximize the total benefits to California, and encourages early action 

to reduce greenhouse gas emissions.

Staff has designed the proposed cap-and-trade program, including the 

allowance allocation system, to minimize the cost of implementation and 

compliance and to maximize the overall benefits. The allowance allocation 

system is equitable within and across sectors of the California economy, 

and its primary reliance on efficiency benchmarks and auction encourages 

early action to reduce emissions. In addition, the ability to bank 

allowances for future use provides an incentive for early action to reduce 

emissions. 

By ensuring that most GHG emissions in California are covered by the 

program, and that incentives are in place to ensure that the most costeffective reductions are made, the program design shares the emissionsreduction burden equitably. 

(2) Ensure that activities undertaken to comply with the regulations do not 

disproportionately impact low-income communities.

Staff has evaluated both the health and economic effects of the proposed 

program to ensure, to the extent feasible, that no disproportionate 

negative impact will occur in low-income communities. The overall health 

and environmental effects of the regulation are expected to be positive, 

and the program has been designed to minimize any economic costs that 

might affect low-income communities. 

(3) Ensure that entities that have voluntarily reduced their greenhouse gas 

emissions prior to the implementation of this section receive appropriate 

credit for early voluntary reductions.
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ARB staff has recommended a system for distributing allowances in the 

industrial sector that will primarily rely on efficiency benchmarks for any 

free allocation. This type of approach rewards those who have already 

invested in emissions reductions. In addition, a portion of the allowances 

will be auctioned, and those who have taken early action will be less 

reliant on purchasing allowances at auction. This allowance allocation 

system provides appropriate credit for those who have taken steps to 

voluntarily reduce their emissions before the start of the cap-and-trade 

program. 

(4) Ensure that activities undertaken pursuant to the regulations 

complement, and do not interfere with, efforts to achieve and maintain 

federal and state ambient air quality standards and to reduce toxic air 

contaminant emissions.

The proposed regulation is not expected to adversely affect federal or 

State ambient air quality standards. This issue has been analyzed and the 

results are provided within Chapter VI: Environmental Impacts of the 

Proposed Regulation, which summarizes the environmental analysis of 

the proposed regulation. In addition, staff analyzed the potential effect of 

the cap-and-trade program on air pollutant emissions, as discussed in 

Chapter VII: Co-Pollutant Emissions Assessment. California’s existing 

programs to meet federal air quality standards will provide substantial 

emissions reductions. Staff’s analysis indicates that the effect of the capand-trade regulation on criteria and toxic emissions is expected to be 

small compared to the emissions reductions resulting from California’s 

existing programs to meet federal air quality standards.

(5) Consider cost-effectiveness of these regulations.

The flexibility of the cap-and-trade program, together with specific design 

features included in the regulation to help contain costs, ensures that the 

reductions needed to meet the requirements of the regulation will be costeffective. Staff estimates that the allowance prices in the program, which 

provide a measure of the marginal cost of emissions reductions needed to 

comply, will be between $15 and $30 per metric ton in 2020. See Chapter 

VIII: Economic Impacts of the Proposed Regulation for a detailed 

discussion. 

(6) Consider overall societal benefits, including reductions in other air 

pollutants, diversification of energy sources, and other benefits to the 

economy environment and public health. 

The cap-and-trade program is a key element of the overall Scoping Plan 

strategy to scale back California’s greenhouse gas emissions to 1990 

levels by 2020, reduce our dependence on fossil fuels, stimulate 

investment in clean and efficient technologies, and improve air quality and 
II-52

public health. By establishing an overall limit on GHG emissions, the 

program establishes the price signal needed to drive long-term investment 

in cleaner and more efficient types of fuels and energy sources, while 

affording covered entities flexibility to seek out and implement the most 

cost-effective options to reduce emissions. The program will also 

complement and support California’s existing efforts to reduce criteria and 

toxic air pollutants. 

(7) Minimize the administrative burden of implementing and complying 

with these regulations.

The proposed regulation will require a market tracking system (MTS) to 

record information about the holders of compliance instruments and trades 

of compliance instruments among market participants. The primary goal 

of the MTS will be to support the effective implementation of the cap-andtrade regulation and to reduce the costs and administrative burden 

associated with long-term cap-and-trade responsibilities. 

The cap-and-trade program will also rely on a revised version of the 

Mandatory Reporting Regulation (MRR) as the primary mechanism for 

emissions reporting. A set of revisions to the MRR are being proposed by 

ARB staff concurrently with the proposed cap-and-trade regulation. These 

revisions are intended to align California’s reporting requirements with the 

federal reporting rules recently enacted by U.S. EPA, and to ensure that 

the information collected by those covered by the cap-and-trade program 

is of sufficient quality to support the market program. 

These requirements have been designed to strike a balance between the 

need for transparency in this new market and the need to minimize the 

administrative burden on those covered by the regulation and on ARB 

staff. 

(8) Minimize leakage. 

Staff proposes an allocation approach designed to minimize leakage and 

to give businesses and industries in the State sufficient time to reduce 

their emissions in a cost-effective manner. Allocating the allowances for 

free to industrial sources using emissions efficiency benchmarks will 

reward companies that have already made investments in energy 

efficiency and carbon reductions, and will benefit those that continue to 

produce goods in California. 

(9) Consider the significance of the contribution of each source or 

category of sources to statewide emissions of greenhouse gases.

The cap-and-trade program has been designed to cover all emission 

sources for which adequate quantification of the emissions is sufficient to 

include in a market program. The program design exempts small sources 
II-53

from direct coverage in the program by establishing an emissions 

threshold for inclusion of 25,000 MTCO2e. However, because 

transportation fuels and use of natural gas by residential and commercial 

users is a significant portion of California’s overall GHG emissions, the 

emissions from these sources are covered indirectly through the inclusion 

of fuel distributors. 

38562(d) Any regulation adopted by the state board pursuant to this part or 

Part 5 (commencing with Section 38570) shall ensure all of the following:

(1) The greenhouse gas emission reductions achieved are real, 

permanent, quantifiable, verifiable, and enforceable by the state board.

The Mandatory Report Regulation is being revised to ensure that all 

reported data for sources in the cap-and-trade program provide the high 

quality data needed for a market-based program. This will ensure that any 

emissions reductions at covered sources will be real, permanent, 

quantifiable, verifiable, and enforceable. 

The offsets portion of the cap-and-trade program also includes extensive 

requirements to ensure that any credits for offset projects are limited to 

emissions reductions or removals that are real, permanent, quantifiable, 

verifiable, and enforceable.

(2) For regulations pursuant to Part 5 (commencing with Section 38570), 

the reduction is in addition to any greenhouse gas emission reduction 

otherwise required by law or regulation, and any other greenhouse gas 

emission reduction that otherwise would occur.

The cap-and-trade program does not require specific emissions reductions 

from any sources, but instead places an overall limit on the emissions that 

are allowed by the covered sources. Because the emissions reductions 

from other Scoping Plan measures are insufficient to reduce emissions 

below the cap level, the cap-and-trade program will require emissions

reductions in addition to those otherwise required by law or regulation. 

(3) If applicable, the greenhouse gas emission reduction occurs over the 

same time period and is equivalent in amount to any direct emission 

reduction required pursuant to this division.

The cap-and-trade program places a limit on emissions from 2012 through 

2020, and will require emissions reductions from those sources covered 

by the program over that time period. Other measures adopted under 

AB 32 are designed to get emissions reductions over the same time 

period to help achieve AB 32’s emissions target for 2020. 

AB 32 allows market-based mechanisms, such as a cap-and-trade

program, to help meet the statewide GHG emissions-reduction goals. 
II-54

Market mechanisms are used to supplement, rather than replace, direct 

regulation approaches. The purpose of using alternate compliance 

mechanisms is to accomplish AB 32’s environmental goals in the most 

cost-effective way. 

38570(b) Prior to the inclusion of any market-based compliance mechanism in 

the regulations, to the extent feasible and in furtherance of achieving the

statewide greenhouse gas emissions limit, the state board shall do all of the 

following:

(1) Consider the potential for direct, indirect, and cumulative emission 

impacts from these mechanisms, including localized impacts in 

communities that are already adversely impacted by air pollution.

Staff’s analysis of the potential for direct, indirect, and cumulative 

emissions impacts, including localized impacts in communities that are 

already adversely impacted by air pollution, is discussed in Chapter VII: 

Co-Pollutant Emissions Assessment. Staff’s analysis indicates that the 

cap-and-trade regulation is expected to have a beneficial impact on 

emissions overall. California’s existing programs to meet federal air 

quality standards will provide the majority of emissions reductions through 

2020. The regulation has the potential to provide additional NOx

reductions if all greenhouse gas reductions are implemented locally, even 

without consideration of the criteria pollutant and toxic emissions

reductions that the cap-and-trade program is expected to provide from 

transportation fuels and commercial and residential gas use. While the 

flexibility inherent in the cap-and-trade program could allow some facilities 

to increase GHG emissions, any related criteria or toxic emissions

increases at these facilities would mean a smaller decrease in local 

emissions in 2020 when the existing air quality programs are taken into 

account. The cap-and-trade program will provide an incentive for covered 

facilities to decrease greenhouse gas emissions and any related 

emissions of criteria and toxic pollutants.

(2) Design any market-based compliance mechanism to prevent any 

increase in the emissions of toxic air contaminants or criteria air pollutants.

ARB’s analysis indicates that the cap-and-trade regulation is expected to 

have a beneficial impact on air emissions by reducing emissions of criteria 

pollutants and toxics. As discussed in Chapter VII: Co-Pollutant 

Emissions Assessment, based on the available data, current law and 

policies that control industrial sources of air pollution, and expected 

compliance responses, ARB believes that emissions increases due to the 

regulation at the statewide, regional, or local level are extremely unlikely,

at best. Nevertheless, as described in Section Q: Program Monitoring, 

ARB is committed to monitoring the implementation of the cap-and-trade 
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regulation to identify any situations where the cap-and-trade program has 

led to an increase in criteria pollutant or toxic emissions.

(3) Maximize additional environmental and economic benefits for 

California, as appropriate.

The cap-and-trade program is a key element of the overall Scoping Plan 

strategy to scale back our greenhouse gas emissions to 1990 levels by 

2020, reduce our dependence on fossil fuels, stimulate investment in 

clean and efficient technologies, and improve air quality and public health. 

By establishing an overall limit on the GHG emissions, the program 

establishes the price signal needed to drive long-term investment in 

cleaner and more efficient types of fuels and energy sources, while 

affording covered entities flexibility to seek out and implement the most 

cost-effective options to reduce emissions. The program will also 

complement and support California’s existing efforts to reduce criteria and 

toxic air pollutants. 

Staff’s evaluation of the cap-and-trade program is consistent with these 

requirements of AB 32. In addition, the evaluation is consistent with ARB’s 

Environmental Justice Policy adopted by the Board in 2001.31 State law defines 

environmental justice as the fair treatment of people of all races, cultures, and 

incomes with respect to the development, adoption, implementation, and 

enforcement of environmental laws, regulations, and policies.32

As part of the economic, emissions, and environmental assessment of the capand-trade regulation, staff assessed the emission reduction opportunities 

available to sources covered by this regulation. This evaluation considered the 

potential for the incentives and flexibility inherent in the cap-and-trade program to 

result in direct, indirect, and cumulative emission impacts, including localized 

impacts in communities that are already adversely impacted by air 

pollution. Based on the available data and current law and policies that control 

 ARB is 

committed to making environmental justice an integral part of its activities. The 

Board approved its Environmental Justice Policies and Actions (Policies) on 

December 13, 2001, to establish a framework for incorporating environmental 

justice into ARB's programs consistent with the directives of State law. These 

policies apply to all communities in California, but recognize that environmental 

justice issues have been raised more in the context of low-income and minority 

communities.

 

31 http://www.arb.ca.gov/ch/programs/ej/ejpolicies.pdf

32 Senate Bill 115 (Solis, Statutes of 1999, chapter 690); California Government Code § 

65040.12(c)
II-56

localized air pollution, and expected compliance responses to the cap-and-trade 

regulation, ARB concludes that, increases in localized air pollution, including 

toxic air contaminants and criteria air pollutants, attributable to the cap-and-trade 

program are extremely unlikely. For more information see Chapter VII. CoPollutant Emissions Assessment and Appendix P: Co-Pollutant Emissions 

Assessment.

Q. Program Monitoring

The cap-and-trade program is made up of many elements, must serve a large 

number of important objectives at the same time, and relies on the cumulative 

actions of a large number of participants operating in a complex market system. 

Accordingly, unanticipated effects and results could occur over the life of the 

program. ARB will monitor the program to ensure that it is achieving emissions 

reductions and other AB 32 objectives and is not resulting in unanticipated 

outcomes. ARB is committed to review and revise policies, protocols, and 

procedures as more information becomes available.

Once the cap-and-trade program is implemented, ARB will monitor whether, over 

time, the program is meeting all of the objectives set forth in AB 32. These 

objectives include certain beneficial outcomes that should be maximized, and 

also certain adverse consequences that should be minimized or avoided. 

Using the results of monitoring, ARB will regularly (at a minimum, once every 

three-year compliance period) evaluate whether the objectives identified by 

statute are being achieved. Periodic evaluation will be coordinated with other

actions and information-collection occurring at the end of compliance periods. 

ARB will conduct its evaluation sufficiently in advance of the end of each 

compliance period to allow ARB sufficient time to adjust the cap-and-trade 

program, if warranted, before commencement of the next compliance period. If 

ARB determines during its periodic review that the cap-and-trade program is not 

achieving the objectives as defined by AB 32, or if substantial, unanticipated 

adverse environmental effects are identified, ARB will revise the operation of the 

program accordingly.

ARB has designed the regulation to avoid unintended consequences. However, 

given the complexity of the program, it is important to incorporate systems to 

monitor and evaluate the performance of the cap-and-trade program. ARB 

proposes to monitor emissions leakage, the generation and use of offset credits, 

and the potential for emissions increases to ensure that the program continues to 

meet the diverse objectives described in Health and Safety Code sections 

38562(b) and 38570(b) over time.

1. Achieving the Greenhouse Gas Limit

At its core, the cap-and-trade regulation sets a limit on greenhouse gas 

emissions. ARB ensures that the cap is met by distributing a limited number of 

allowances to emit greenhouse gases. At the end of each three-year compliance 
II-57

period, ARB will determine whether the limit has been met by examining whether 

the number of compliance instruments turned in by covered entities matches the 

emissions reported under the Mandatory Reporting Regulation plus the allowable 

number of offsets. ARB will post the results of its evaluation on its website or 

otherwise make this information publicly available.

The regulation requires entities that do not meet their compliance obligation by 

the deadline to turn in additional allowances, and provides for enforcement 

actions against covered entities that do not meet their obligations. If these 

mechanisms are not sufficient to ensure that the cap is met, ARB will reevaluate 

the regulation to strengthen these provisions.

ARB will also monitor both the price that is bid to purchase allowances at the 

quarterly auctions and the price at which allowances are bought and sold on the 

secondary market to determine whether the market is functioning as expected. 

Monitoring the price and the status of bids for allowances in the Allowance Price 

Containment Reserve will also help alert ARB staff to price increases and the 

need to determine whether these increases are due to legitimate unforeseen 

events or market manipulation. 

2. Detecting Market Manipulation

ARB has collaborated closely with numerous experts to craft regulatory 

requirements that will provide the means to identify and ultimately prevent market 

manipulation. However, as with any regulation, we cannot guarantee that all 

regulated parties will abide by the letter and the spirit of regulatory requirements. 

Because of this issue, the regulation proposes registration of all market 

participants to ensure that third-party participants can be vetted; and requires 

disclosure of affiliates for whom allowances are owned (“beneficial holdings”), to 

help identify potential collusion or other forms of market manipulation. If market 

manipulation or other illicit activities are detected, ARB will work with the 

appropriate authorities to initiate enforcement activity and, if necessary, 

reevaluate regulatory requirements to avoid future incidents.

3. Leakage

ARB has designed the regulation to minimize leakage by placing covered entities 

on an equal footing with their non-covered competitors (both those that are outof-state, and those that are below the threshold for inclusion in the program), and

ARB is committed to monitor how covered sectors address carbon costs once 

the program is in place. The focus of this monitoring will be on whether 

industries in a sector increase their product price in response to the carbon cost, 

whether or not the price increase (or inability to increase the price) led to a 

change in market share for the covered entities, and the relative share of the 

California market served by in-state production and by imports. ARB staff will 

also work with covered sources and other interested parties to identify additional 

sources of information at the state level that could improve ARB’s ability to 

monitor leakage. Should ARB find that leakage is occurring despite the 
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safeguards in the regulation, ARB will examine mechanisms to address leakage, 

including border adjustments or changes to the allowance distribution system.

4. Offset Projects

The regulation proposes a robust monitoring program for offset projects—both 

the verification that the offsets are real, additional, and enforceable, and that 

Offset Project Operators, verifiers, and Offset Project Registries are operating 

according to regulatory requirements. Offset Project Registries are required to 

conduct oversight of their registry program and randomly audit verifications to 

ensure that ARB regulatory requirements are being met by Offset Project 

Operators and verification bodies. ARB will have a rigorous oversight of its 

approved Offset Project Registries. Each year, the Offset Project Registries will 

provide ARB with a report providing basic information related to any offset project 

listed using a Compliance Offset Protocol and any findings related to verification 

audits. ARB will make this report publicly available. The Offset Project 

Registries will be required to provide any information related to an offset project 

when requested by ARB as part of its oversight of the Offset Project Registry. 

During the course of an offset project, the Offset Project Registry will track and 

report any guidance or information provided to an Offset Project Operator related 

to a compliance offset project to ARB every month. This will ensure that ARB 

understands any issues or concerns related to its compliance offset program as 

Offset Project Operators are implementing the actual offset projects.

In addition, the ARB regulatory offset verification program is designed to provide 

a transparent process by which ARB can review verification documents and fully 

understand any findings uncovered during the course of verification of an offset 

project by an ARB accredited verification body. ARB will also develop an audit 

and oversight program for offset project verifications.

5. Offset Protocols

Offset protocols include several elements to support existing health and 

environmental protection measures. Specifically, each individual offset protocol 

requires all offset projects to be developed in compliance with all federal, state, 

and local laws, regulations, ordinances, and any other legal mandate, including 

all CEQA and National Environmental Policy Act (NEPA) requirements where 

applicable. The Offset Project Operator is required to attest to ARB that their 

offset project meets these requirements. If, during verification, it is found that the 

offset project does not meet any of these requirements, the project is ineligible to 

be issued ARB offset credits until the project is in compliance. In addition to 

regulatory compliance, during project listing, Offset Project Operators must 

provide detailed project information, which must be posted on the Internet and 

available for public review.

Because of the possibility that forest projects could unintentionally “reverse,” 

negating the benefits of those projects because of fire, pest infestation, or 

disease, ARB is requiring the creation and maintenance of a Forest Buffer 

Account to be populated by a percentage of ARB-issued offset credits from forest 
II-59

offset projects. ARB will regularly monitor the number of offset credits in this 

Buffer Account to ensure it is sufficient to offset unintentional reversals. If the 

Buffer Account is found to be insufficient, ARB will revisit the contribution 

required by forest offset projects to this account. 

Even with these safeguards, ARB recognizes that there could be unanticipated 

impacts from offset projects. ARB will monitor and assess offset project 

documentation and potential impacts from offset project implementation at a 

minimum of once each compliance period. In the event that unintended impacts 

are identified during this review, and they are substantial enough to interfere with 

or undermine the achievement of the objectives for the cap-and-trade program as 

defined by AB 32, including the objectives set forth in 38562(b) and 38570(b), 

ARB would develop and implement appropriate responses to rectify identified 

health or environmental effects. Potential responses ARB would consider, if 

warranted, include, but are not limited to, revising the types and/or geographic 

location of offset projects and disallowing the use of some types of offset credits. 

These potential future responses are not, however, warranted based on currently 

available information, and their imposition today would unnecessarily conflict with 

AB 32’s other objectives. Monitoring of the implementation of the U.S. Forest 

Projects Protocol is further discussed in the Adaptive Management section of 

Appendix O: Functional Equivalent Document.

6. Emissions Increases

ARB’s analysis indicates that the cap-and-trade regulation is expected to have a 

beneficial impact on air emissions by reducing emissions of criteria pollutants 

and toxics. Based on the available data, current law and policies that control 

industrial sources of air pollution, and expected compliance responses, ARB 

believes that emissions increases due to the regulation at the statewide, regional, 

or local level are extremely unlikely, at best.33

 

33 Not all emissions increases at facilities covered by the cap-and-trade program will result from 

the program itself. The cap-and-trade program will place a new regulatory requirement and a 

new cost on GHG emissions from all covered facilities, so that the program provides an incentive 

to minimize increases or to decrease GHG emissions and any related emissions of criteria or 

toxic emissions. While the program provides flexibility that could allow increased production due 

to economic growth, such increases would not be caused by the cap-and-trade program. Staff 

believes that only in very limited circumstances would a localized emissions increase be the 

actual result of the incentives created by the cap-and-trade program (e.g., shifting of production 

within a company from an inefficient facility with higher compliance costs to a more efficient 

facility that results in higher emissions at the more efficient facility).

Nevertheless, ARB is committed 

to monitoring the implementation of the cap-and-trade regulation to identify any 

situations where the cap-and-trade program has led to an increase in criteria 

pollutant or toxic emissions.
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As discussed in the Adaptive Management section of Appendix O: Functional 

Equivalent Document, at least once each compliance period, ARB will use 

information collected through the mandatory reporting regulation, the cap-andtrade regulation, the industrial efficiency audit, and other sources to evaluate how 

facilities are complying with the cap-and-trade regulation. ARB will also solicit 

information from local air districts regarding permit modifications and new permit 

applications for covered sources. This information will be used to identify 

compliance activities that could lead to increased emissions and to determine

whether further investigation of potential criteria pollutant and toxic emissions is 

warranted. 

If unanticipated adverse localized emissions impacts that can be attributed to the 

cap-and-trade regulation are identified during this periodic review, ARB will 

consider whether these impacts affect the achievement of the program objectives. 

If so, ARB will promptly develop and implement appropriate responses. Potential 

responses ARB would consider include, but are not limited to, using allowance 

value from the cap-and-trade program to mitigate localized emissions increases, 

providing incentives for energy efficiency and other emissions-reduction activities 

within the community, or restricting trading or prohibiting certain compliance 

responses in specifically identified communities. These potential future 

responses are not, however, warranted based on currently available information, 

and their imposition today would unnecessarily conflict with AB 32’s other 

objectives.
III-1

III OVERVIEW OF THE COMPLIANCE OFFSETS PROGRAM

A. Offset Credits Issued by ARB

Individual projects can be developed to achieve GHG reductions from activities 

not otherwise regulated or covered under the cap-and-trade program. These 

projects can generate offset credits, or verifiable emissions reductions whose 

ownership can be transferred to others, including entities with a compliance 

obligation under the cap-and-trade program. In addition to providing compliance 

flexibility, the inclusion of offset credits in the program will support the 

development of innovative projects and technologies from sources outside 

capped sectors that can play a key role in reducing emissions both inside and 

outside California. Offset projects can reduce emissions, thereby generating

offset credits that can be used by entities who must comply with the program. 

The use of an offset credit allows a covered entity to forgo some amount of onsite reductions by offsetting emissions elsewhere. Therefore, the integrity of the 

offsets program is crucial to achieving the AB 32 goal.

As required by AB 32, any reduction of GHG emissions used for compliance 

purposes must be real, permanent, quantifiable, verifiable, enforceable, and 

additional (HSC §38562(d)(1) and (2)). Offset credits issued by ARB must be 

quantified according to Board-adopted methodologies. The proposed regulation 

includes provisions to verify and enforce the reductions incentivized through the 

generation and retirement of offset credits. The criteria for compliance offset

credits will ensure that the reductions are quantified accurately and are not 

double-counted within the market tracking system.

Offset credits can provide covered entities a source of low-cost emissions 

reductions. Reductions achieved through the offset program must be measured 

using rigorous quantification methods. Offset protocols provide a basis to 

determine whether offset projects are also additional. Establishing that offset 

projects are additional is one of the most important factors for the validity of 

individual offset credits. After a project uses an approved offset protocol to 

quantify its emissions reductions, it must continue to monitor, report, and verify 

its emissions reductions.

1. Role of the Offsets Program

The offsets program is designed to increase compliance flexibility and contain 

costs associated with complying with cap-and-trade program requirements. 

Because offset credits are expected to cost less than allowances, they are 

considered by many to be the most important cost-containment tool in the capand-trade program. Offset credits allow greater flexibility for covered entities to 

cover their emissions by offering an additional supply of compliance instruments 

in the market, which can create a demand for lower-cost emissions reductions 

and reduce the overall cost of achieving the emissions cap.
III-2

In addition to increasing the cost-effectiveness of the program, the California 

offsets program can benefit other AB 32 goals by:

• Stimulating emissions-reduction opportunities and technological

innovation in sectors outside of the capped sectors.

• Encouraging early emissions-reduction activities while providing a 

transition period for industry to develop and deploy low-GHG technologies.

• Promoting technology and knowledge transfer between developed and 

developing countries, such as helping to preserve rainforests in danger of 

deforestation.

• Providing environmental, social, and economic benefits, such as reduced 

air or water pollution through improved land management practices and 

wildlife habitat.

Staff recognizes that a robust supply of offset credits can help to contain the 

costs of a cap-and-trade program. To promote the supply of offsets, staff 

proposes that: (a) ARB issues offset credits for projects using ARB-approved 

protocols, and (b) ARB recognizes offset credits from ARB-approved offset 

programs. Approved programs could include sectoral programs such as those 

Reducing Emissions from Deforestation and Forest Degradation (REDD) in 

developing countries. Offset credits from linked programs (such as WCI partner 

jurisdictions) would also be eligible for use in California’s cap-and-trade program. 

ARB staff incorporates provisions in the proposed regulation to allow these two

methods to be used following Board approval of specific protocols or programs. 

Staff has developed four compliance offset protocols, , which can be found in 

Parts II through V of the Cap-and-Trade Program Staff Report, for use under the 

compliance offset program.. These protocols include the U.S. Forest Projects

Protocol, the Livestock Manure (Digester) Projects Protocol, the Urban Forest

Projects Protocol, and the U.S. Ozone Depleting Substances Projects Protocol. 

They are incorporated by reference in the proposed regulation and are being 

considered for adoption by the Board as part of this rulemaking package. While 

the program contains provisions to allow offset projects from North America, staff 

is taking offset protocols applicable in the United States to the Board for approval 

as part of this rulemaking package.

For these four protocols, staff relied on Climate Action Reserve (CAR) work on 

the four protocols for use in the voluntary offsets market. Staff recognizes the 

extensive contributions that stakeholders and experts have made to the CAR 

protocols, including fashioning effective solutions to difficult problems.

Accordingly, ARB is relying on this work to help support ARB’s offset quality 

objectives, as well as provide continuity and stability for offset projects both 

within California and other parts of the United States.
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In addition to these four protocols, staff intends to review and adopt additional 

offset protocols in the future. Staff will evaluate additional offset project types 

and protocols. Protocols developed by third parties may be reviewed and, if 

applicable, be considered for adoption by ARB.

To ensure that there is a ready supply of offset projects developed according to 

Board-approved protocols, staff proposes to work with qualified third-party offset 

programs to bring offset credits from new offset projects into the offset program. 

Staff recognizes that third-party offset programs have existing capabilities and 

infrastructure that can be deployed quickly to enhance the supply of offset credits. 

The proposed regulation includes conditions and processes under which thirdparty programs can be approved to generate offset credits for compliance use 

according to ARB-approved protocols.

In addition to protocols developed and approved by ARB, staff proposes to 

recognize offset credits from existing offset projects under protocols developed

for the four project types for purposes of early action. The proposed regulation 

includes a process for offset credits from qualified existing offset projects to be 

accepted into the compliance offsets program, to help create an initial supply of 

offset credits for the cap-and-trade program.

2. Transparency in the Offsets Program

Transparency is critical to the environmental integrity and effective administration 

of an offset program. The proposed regulation establishes an open and 

transparent offsets system to build confidence in the long-term success of the 

cap-and-trade program. ARB will ensure that information regarding offset 

projects and assessments will be made publicly available. The proposed 

regulation establishes requirements for offset projects and the offset credits they 

are issued to be listed on a publicly available webpage.

3. ARB as an Offset Program Administrator 

An important procedural aspect of the offset program relates to the entity that

issues offset credits. Staff proposes for ARB to play the role of a credit-issuing 

body, with provisions for third parties to fulfill some of these responsibilities 

subject to ARB oversight. 

Offset credits are created for GHG reductions or removals that have been 

quantified, verified, and recorded. Credit-issuing bodies review all project 

quantification and verification information to determine if GHGs have been 

reduced. Once the credit-issuing body determines that the reduction occurred, 

usually based on third-party verification statements, they create (or issue) offset 

credits, each of which represents one metric ton of CO2e. 

As the offset program administrator, ARB would fulfill specific roles during the 

offset credit creation process. These roles include: approving compliance offset 

protocols as required by AB 32; reviewing and listing offset projects in the 

system; overseeing monitoring, reporting, and verification activities; and making 
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the determination of whether offset credits should be issued and, if so, how many. 

The regulation also proposes provisions to allow third parties that operate offset 

programs to fulfill some of these same roles, subject to ARB audits and oversight. 

These registries would be allowed to list offset projects in their own system and 

oversee monitoring, reporting, and verification activities. These third-party offset 

programs—referred to as Offset Project Registries in the proposed regulation—

must meet requirements included in the proposed regulation and be approved by 

ARB. They must share all information they collect for offset projects with ARB,

and make this information publicly available. Staff proposes to allow Offset 

Project Registries to assume these roles to access their existing capabilities and 

infrastructure so that the offsets program can be deployed quickly to enhance the 

supply of offset credits. The obligations and services of Offset Project Registries 

are discussed later in this Chapter.

4. General Requirements for Offset Credits Issued by ARB

The proposed regulation includes provisions to ensure all offset credits used for 

compliance purposes are real, additional, permanent, quantifiable, verifiable, and 

enforceable. Ensuring the environmental integrity of the offsets program is 

critical to guaranteeing the credibility of the entire cap-and-trade program,

achieving the environmental objectives of real emissions reductions, and 

preserving the value of offset credits to project developers, offset buyers, and all 

market participants. To assure offset quality, the proposed regulation includes

rigorous and transparent quantification methodologies, training and oversight of 

independent ARB-accredited verifiers, and a registration and tracking system.

The proposed program relies on offset protocols that are developed with 

stakeholder input, standardized, and approved by the Board. The offset 

quantification and the regulatory offset verification requirements are designed to 

reduce subjectivity and uncertainty. These procedures are the cornerstone of the 

offsets program and will help ensure the rigor and integrity of offset credits. The

offsets verification program will require that verifiers demonstrate competence in 

each specific project type, employ conflict-of-interest assessments, and include 

random verifier audits and strict performance evaluations to ensure that 

verification activities are conducted accurately and consistently. The registry 

system for compliance instruments is being designed to provide strong 

enforcement capabilities, including mechanisms to prevent double-counting, 

public disclosure requirements, and methods to clearly define ownership.

5. Approving Compliance Offset Protocols

Offset credits issued by ARB must be generated using offset protocols adopted 

by the Board. The proposed regulation establishes a process by which the 

Board will approve and amend protocols and their quantification methodologies 

based on staff’s evaluation and a public process. These protocols will be made 

publicly available so that anyone interested in developing an offset project can do 

so according to Board-approved standards.
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Four protocols are part of this rulemaking package, as described below. ARB 

staff will periodically propose new offset protocols or revisions to previously 

approved protocols to reflect the current regulatory environment and latest 

scientific information, to the Board. Before ARB staff brings new protocols or 

updates to existing protocols to the Board, a public stakeholder process will be 

conducted to develop, review and revise the offset protocols. Before the Board 

adopts a new protocol there will be a separate CEQA review to assess the

environmental impacts associated with that protocol. 

As part of this rulemaking package, staff is bringing four offset protocols to the 

Board for approval:

Four Protocols for Board Approval

• U.S. Ozone Depleting Substances (ODS) Projects Protocol: 

Destruction of ODS from refrigerant and foam-blowing agents sourced 

from and destroyed within the United States. Production of ODS is being 

phased out through the Montreal Protocol, but there are significant banks 

from which these gases will be emitted in coming years unless they are 

destroyed. ODS destruction has stratospheric ozone benefits in addition 

to climate benefits.

• Livestock Manure (Digesters) Projects Protocol: Capture and 

destruction of methane from anaerobic manure treatment and/or storage 

facilities on dairy cattle and swine farms within the United States. 

• Urban Forest Projects Protocol: Urban tree planting projects by 

municipalities, educational campuses, utilities, and partner organizations

to sequester carbon.

• U.S. Forest Projects Protocol: Increasing sequestered carbon or 

avoided GHG emissions due to forest management activities in three 

project types: reforestation, improved forest management, and/or avoided 

conversion within the United States.

ARB has coordinated with the other WCI partner jurisdictions to develop the 

offset program, and three of these proposed protocols have been reviewed as 

part of that effort.34

 

34 Det Norske Veritas. Review of Existing Protocols Against WCI Offset Criteria. For the Western 

Climate Initiative. April 2010. Found at: 

 The U.S. Ozone Depleting Substances Projects Protocol has 

not been part of this review process to date, but the WCI Partner jurisdictions are 

http://www.westernclimateinitiative.org/component/remository/Offsets-CommitteeDocuments/WCI-Review-of-Existing-Offset-Protocols. 
III-6

currently reviewing it and assessing it relative to the WCI offset criteria 

recommendations. Staff will continue to work within WCI to address any issues 

that may arise with use of this protocol in the context of linking with a WCI 

Partner.

Staff is relying on the work that the Climate Action Reserve (CAR) has done to 

develop these four protocols for use in the voluntary offset market. In reviewing 

these protocols for possible use in the cap-and-trade program, staff examined all

aspects of the protocols, including but not limited to the following:

• Mechanisms for ensuring permanence in forest projects, to ensure that 

they are effective and enforceable by ARB.

• Technical details, including incorporating minor adjustments to emission 

factors.

• Modifications to each protocol to align them with the requirements of the 

cap-and-trade program, such as aligning project start eligibility dates and 

crediting periods, or alignment of terms and definitions. 

On June 23, 2010, staff held a workshop to discuss the transition of the four CAR 

protocols for use in a compliance program. Specifically, this workshop focused 

on options for aligning the most recent versions of these protocols with the offset 

criteria proposed in the cap-and-trade regulation. In addition to seeking public 

input, a CEQA review of each protocol has been completed and is included as 

part of this regulatory package in Appendix O: Functional Equivalent Document. 

6. Requirements for Compliance Offset Protocols

Compliance offset protocols serve as a cornerstone to ensure that reductions are 

appropriately quantified, monitored, reported, and documented. Protocols taken 

to the Board for adoption will consist of standardized methods that quantify 

reductions based on specific criteria and pre-established calculation methods. 

This approach will streamline the calculation of project baselines and 

determination of additionality of projects by using standard eligibility criteria that 

ensure that projects are additional. Protocols approved by the Board will include 

project-type-specific monitoring and reporting requirements and methods for 

addressing leakage. 

a. Additionality

Protocols approved by the Board provide a basis to determine whether offset 

projects are additional. Approved protocols are designed to ensure that the 

determination of additionality will be replicable for all offset projects of the same 

type. Additionality in the offset program requires that ARB only credit projects 

that would not have otherwise occurred in the absence of an offsets mechanism. 

Staff designed the offset system with this requirement to be consistent with 

AB 32, which requires that emissions reductions used for compliance must be “in 

addition to any greenhouse gas emissions reduction otherwise required by law or 
III-7

regulation, and any greenhouse gas emissions reduction that otherwise would 

occur” (HSC §38562[d][2]). Most existing offset programs have excluded project 

activities required by law or regulation from receiving offset credits in their 

programs. However, staff expects some GHG emissions-reduction activities not 

required by law or regulation to occur under a business-as-usual scenario. ARB 

is defining additionality to exclude these offset projects from receiving credit. 

The proposed regulation establishes that an offset project, which has already 

begun to generate offset credits under a protocol approved by the Board, may 

continue to generate offset credits until the end of its crediting period, even if in 

the future regulations are adopted that mandate reductions from projects that 

have already begun to generate offset credits. At the time a newly adopted 

regulation takes effect, a project type or technology would cease to be additional 

for new offset projects wishing to enter the system. Generally an offset project 

will be developed if the revenue it expects to generate over the length of the

crediting period will cover its upfront investment and ongoing maintenance costs. 

This means that an offset project will be implemented only if it is expected to be 

financially beneficial to do so over that length of time. Therefore, staff believes 

that offset projects should be credited for emissions reductions throughout the 

entire crediting period. Crediting periods are discussed in more detail later in this 

Chapter.

b. Project Baselines

Project baselines are a core component of the quantification process and the 

determination of additionality. Project baselines are conservative estimates of 

business-as-usual reductions or removals for an offset project. The difference 

between the project baseline and the reductions achieved by the offset project is 

what will be considered beyond business-as-usual, and therefore creditable as 

an offset. Therefore, in the proposed regulation, staff proposes to require that 

protocols include a method for calculating project baselines to quantify a project’s 

emissions reductions. The GHG reductions or removals can only be assessed if 

the baseline reflects an accurate and realistic business-as-usual emissions 

scenario.

c. Accounting for Leakage

In the context of offset credits, leakage refers to a shift in emissions due to the 

offset project activity to another place that negates some or all of the emissions

reductions achieved by the offset project. Leakage can occur with offset credits 

because they are based on individual projects. The proposed regulation requires 

that protocols include a clear methodology to account for leakage when 

quantifying emissions reductions from offset projects. Two types of leakage must 

be accounted for in offset projects, if applicable for the specific offset project 

type: activity-shifting and market-shifting leakage. Any leakage associated with 

an offset project type will be factored into the final calculation of emissions and 

emissions reductions for individual offset projects.
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d. Accounting for Uncertainty

When uncertainty exists in quantifying GHG reductions, ARB will only issue offset

credits when there is a high level of confidence that reductions actually occurred. 

Staff proposes to employ a principle of conservativeness in the quantification of 

emissions reductions. This method will ensure that the accounting will 

underestimate rather than overestimate any reductions when there is a high level 

of uncertainty. Staff prefers this approach to applying an arbitrary discount factor 

to account for uncertainty after emissions reductions have been verified. 

Applying a single discount factor across projects to account for risk and 

uncertainty could penalize projects that achieve truly real and additional 

emissions reductions.

e. Permanence Requirements

Permanence refers to the period of time that an emissions reduction must stay 

absent from the atmosphere. In general, it is equal to the duration of an emitted 

GHG in the atmosphere. Requiring permanence in the offsets program ensures 

that if there is a risk of reversal, the atmosphere can be made whole. It also 

ensures that offset credits are equivalent to emissions reductions that would be 

achieved from covered entities at their facilities. Permanence is particularly an 

issue in projects with a risk of GHG reversal, such as sequestration-based

projects. Disturbances, such as fire, insects, disease, and project 

mismanagement or failure can return sequestered carbon or release GHGs to 

the atmosphere.

In the case of sequestration-based projects, the proposed regulation requires an 

upfront commitment by the project developer to permanently maintain GHG 

reductions to ensure permanence. To achieve this, staff proposes to establish a 

Forest Buffer Account to provide insurance, in the case of an unintentional GHG 

reversal. The details of the Forest Buffer Account are discussed later in this 

Chapter. Although staff includes the Forest Buffer Account to deal with 

unintentional reversals, there are still risks that intentional reversals can occur in 

forest projects. In this, case the forest owner must replace all credited carbon 

that has been reversed.

f. Crediting Periods

Each protocol must establish a crediting period for the relevant offset project type. 

The crediting period refers to the period that an offset project is allowed to be 

issued compliance offset credits. Without certainty about a project’s life span, 

there may be too much risk for a project to attract investors. Therefore, staff 

understands there must be some guarantee that the emissions reductions 

achieved according to a protocol will be eligible to generate offset credits for a 

given period. However, some types of offset projects could no longer be valid for 

generating offset credits in the future. This could be because the offset projects 

have become unadditional because business practices change or the sources 

are now suited for direct regulation or another market-based incentive program. 

Staff determined that there must be a balance between guaranteeing investment 
III-9

certainty and allowing ARB to update methods and quantification, as well as to 

reevaluate and readjust baseline and additionality requirements in protocols in 

the future.

To achieve this balance, staff proposes to set a range for crediting periods. For 

non-sequestration projects, each protocol will include a crediting period between 

seven and 10 years. Staff believes that this is sufficient time needed to make an 

investment attractive for most non-sequestration projects. For sequestrationbased projects, each protocol will include a crediting period between 10 and 30 

years. Staff recommends this period for sequestration projects because they 

require long-term investment and commitment by project developers, and these 

projects achieve gradual GHG removals over longer timescales. Staff will 

establish a crediting period for a specific project type in each protocol.

The proposed regulation includes two types of crediting periods: an initial

crediting period and a renewed crediting period. The initial crediting period 

occurs once and begins on the date that the first verified GHG reductions occur 

according to an offset verification statement submitted by an ARB-accredited 

verifier. Offset projects may qualify for renewed crediting periods if they continue 

to meet the requirements for additionality. An offset project must also utilize the 

most updated version of an approved protocol for that offset project type at the 

time of renewal. An offset project that does not involve sequestration of GHGs 

may be renewed twice. Staff believes this is generally the amount of time that an 

offset project in industrial sectors will remain additional. There is no limitation on 

the number of times a crediting period may be renewed for sequestration-based 

offset projects; however, when added together the crediting periods may not 

exceed a total of 100 years. 

7. Requirements for Offset Projects 

The proposed regulation establishes requirements for offset projects if they want 

to be issued offset credits. These include using a Board-approved protocol, 

meeting the requirements for additionality, being located in an applicable 

jurisdiction, and complying with all applicable laws and regulations at the national, 

state or provincial, and local levels. Throughout this Staff Report, those that 

develop offset projects are referred to as offset project developers, without 

elaborating on who these parties may be. Under the proposed regulation, those 

that have legal authority to implement offset projects—referred to as Offset 

Project Operators in the proposed regulation—must identify themselves to ARB 

or an Offset Project Registry. In most cases these are facility operators or 

landowners. Many times facility operators or landowners will contract with 

third- party investors to assist in the development, implementation, and 

maintenance of the project. Staff recognizes that some facility operators and 

landowners may not be the parties implementing and overseeing the offset 

project; therefore, staff is allowing these parties to identify another party—

referred to as an Authorized Project Designee in the proposed regulation—to be 

identified as responsible for the offset project. In the proposed regulation, a 

facility operator or landowner may delegate responsibilities, such as 
III-10

communications with ARB or an Offset Project Registry regarding the offset 

project, to an Authorized Project Designee. In some cases, the facility operator 

or landowner may also assign rights to own offset credits that are issued to the 

offset project to the Authorized Project Designee or another third party. 

a. Requirement to Use a Compliance Offset Protocol 

An offset project developer must use a protocol approved by the Board to qualify 

for the issuance of offset credits. Staff will make all approved protocols available 

on ARB’s public website.

b. Requirements for Additionality

Offset project developers must ensure that offset credits generated under their 

project are considered additional. To be additional GHG reductions must result 

from activities that:

1. Are not required by or undertaken to comply with any federal, state or 

local law or ordinance, including any regulation, consent order, and 

stipulated agreement or Memorandum of Understanding.

2. Are not considered common practice or would not have occurred under a 

business-as-usual scenario.

3. Were not commenced prior to January 1, 2007.

4. Exceed a project baseline calculated by a protocol for an offset project of 

that type.

Establishing the eligibility date for an offset project is critical to determining the 

additionality of offset projects. The eligibility date is the date from which a project 

can be issued offset credits by ARB. ARB will not issue offset credits for 

emissions reductions until after they have been verified. For the issuance of 

offset credits, ARB is proposing that offset projects which commence on or after

January 1, 2007, be eligible. This date is the implementation date of AB 32 and 

provides for a better likelihood that the project was implemented to achieve 

AB 32 goals. Staff is also proposing that when recognizing offset credits issued 

according to non-ARB offset protocols or those issued by other programs 

approved by ARB, the eligibility date may differ from the date for ARB-issued 

offset credits. For purposes of recognizing projects undertaken to achieve early 

action GHG reductions, staff may recognize offset credits issued prior to January 

1, 2007. The specific eligibility date requirements will be established depending 

on the evaluation of a specific program or set of protocols.

c. Locations of Offset Projects

While staff proposes to allow offset projects from North America to be credited 

under ARB-approved protocols, staff is only taking protocols to the Board for 

approval as part of this rulemaking package that are applicable for projects in the 

United States and its territories. Staff plans to evaluate how the four protocols 
III-11

being taken to the Board can be expanded to include projects in Mexico35

Offset credits from projects located outside of North America may also be used 

for compliance if they are issued by an outside program that is approved by the 

Board, though no such approval of another program is being recommended at 

this time. Recognition of offsets issued by other programs is discussed in more 

detail in Section B of this Chapter.

and 

Canada. Although staff encourages offset projects to be developed in California, 

it recognizes out-of-state projects will expand the scope of the program to allow 

for more low-cost GHG reduction possibilities to be incorporated and reduce the 

overall costs of the program. Therefore, staff recommends that ARB issue offset

credits for projects located in the U.S., Canada, and Mexico. Staff proposes that 

all GHG reductions for offset projects, whether they are located within or outside 

of California, be verified by an ARB accredited third-party verifier, and that ARB

have the ability to audit all accredited verifiers. 

Staff’s intent in approving protocols is that the standard for additionality will be 

set to reflect the most stringent regulatory or legal requirements among linked 

WCI partners. This would result in the most conservative assessment of GHG

reductions, helping to ensure the integrity of the offset system. Setting an

additionality standard based on the most stringent regulation in the region would

remove any incentive to weaken or solely maintain environmental protections to 

qualify more offset projects. For some project types it will be difficult to apply this 

standard in the protocols based on regional differences. For these project types, 

staff may address regional differences using alternative methods.

d. Environmental Assessment Requirements

In the proposed regulation, staff includes requirements that offset projects meet 

all local, state, and federal laws for environmental assessments. The purpose of 

including this requirement is to ensure that offset project developers assess and 

disclose any potential impacts associated with implementing their offset projects. 

While staff is not requiring that offset projects meet specific requirements for 

environmental assessments, this requirement acknowledges the importance of 

all potential projects adhering to the environmental laws of the jurisdiction in 

which the project is located. For example, new offset projects in California may 

be subject to local permitting processes and, if not exempt, environmental review 

under CEQA.

 

35 Staff does not intend to evaluate an ODS protocol for offset projects in Mexico because the 

substances covered under the protocol have not yet been completely phased out in developing 

countries.
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8. Listing Offset Projects 

The proposed regulation requires that project developers “list” their projects—or 

submit information pertaining to their offset projects—with ARB or an Offset 

Project Registry. Listing establishes a mechanism for a project developer to 

record information on their offset project for ultimate issuance of offset credits. 

Project listing requires the submittal of information on each project for 

transparency purposes. The requirements for what information must be 

submitted can be found for each type of offset project in its corresponding 

protocol, all of which are incorporated by reference in the proposed regulation. 

Before listing, a project developer must register for an account with ARB to hold 

compliance instruments and must attest to ARB that all information they submit 

for listing purposes is truthful and accurate. These attestations will be used for 

enforcement purposes. 

All listed projects and associated information will be posted on a publicly 

available website. Once ARB or an Offset Project Registry has determined that 

all the information submitted by the project developer is complete and that the 

offset project generally meets the requirements for additionality, it will be listed as 

a “proposed” project on the website. This status will change to an “active” project 

once the project developer submits its verification statements (attested to by an 

ARB-accredited verification body) and ARB or an Offset Project Registry issues 

an offset credits for the GHG reductions. Changing the status of the offset 

project from “proposed” to “active” will allow the public to know that the offset 

project has begun to be issued offset credits and has completed its first 

verification process. 

The listing process is not intended to be an approval process for offset projects. 

The determination that an offset project meets all the regulatory requirements 

occurs at the time an accredited verifier issues a positive or qualified positive 

offset verification statement and ARB or the Offset Project Registry issues an 

offset credit based on that statement. This means that some offset projects may 

be listed as a proposed project but never have the status changed to an active 

project or receive offset credits. 

Offset project developers are required to list their offset projects for an initial 

crediting period no later than the date they submit their project’s first annual 

reporting data. For renewed crediting periods, project developers must submit 

their listing information no earlier than 18 months before and no later than 9 

months after the conclusion of the previous crediting period. This timeframe 

establishes the period of time in which additionality would be assessed and will 

also determine which protocol version should be utilized.

9. Monitoring, Reporting, and Record Retention Requirements for 

Offset Projects

Ongoing monitoring of offset projects is necessary to ensure that offsets credited 

to the project have occurred, and to provide the necessary data for quantifying 

and verifying GHG reductions. Monitoring requirements in the proposed 
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regulation include measurement and data collection for key project parameters, 

as well as related procedures and quality control procedures. The monitoring 

requirements address what needs to be measured, how often it needs to be 

measured, and what methods and instrumentation are acceptable for data 

collection. General monitoring requirements can be found in the proposed 

regulation, while specific requirements for each type of offset project can be 

found in the individual protocols. Protocol-specific monitoring requirements 

increase consistency among projects of the same type, while allowing monitoring 

requirements to be tailored to each project type.

Staff includes separate requirements for the substitution of missing fuel analytical 

data in the proposed regulation, in the case that an offset project’s gas or fuel 

analytical monitoring data equipment breaks down. In turn, it is necessary to 

collect data that would be needed to support the missing data substitution 

procedures for fuel use. The offset project developer may benefit from such a 

provision because it could reduce or eliminate the need for more punitive data 

substitution in a missing data situation. 

The proposed regulation requires reporting on the performance of offset projects, 

including summarizing project monitoring data, calculating the GHG reductions

achieved in the applicable period, and documenting that information in a project 

report. The required content and level of detail demanded in project reports—

referred to as Offset Project Data Reports in the proposed regulation—vary 

between project types.

Staff proposes an annual reporting frequency. Reductions can be aggregated by 

year and reported once every six years in the case of urban forest projects. Staff 

chose these timeframes because reporting represents a project cost due to the 

resources required to prepare and subsequently verify reported data. Staff 

believes these timeframes strike a balance between cost and accountability, and 

are cost-effective for the various types of offset projects. All reports will be due 

on April 1 of the subsequent year for which GHG reductions are being reported. 

These general requirements for offset project reporting are described in the 

proposed regulation. There are also specific reporting requirements for each 

type of offset project in the individual protocols. In addition to meeting these 

requirements, project developers must submit a statement to ARB attesting to 

the accuracy and truthfulness of the Offset Project Data Reports they submit. If a 

project developer fails to submit their reported data by the appropriate deadline, 

they will be disqualified from being issued offset credits based on the reported 

GHG reductions covered in that particular data report.

The proposed regulation includes requirements for project developers to retain 

records and documents pertaining to monitoring and reporting activities. Project 

developers must retain all information used to develop their Offset Project Data 

Reports. The information retained must also be sufficient to allow for verification 

of the GHG reductions contained in each report. These general record retention 

requirements can be found in the proposed regulation, while specific 
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requirements for each type of offset project are described in the individual 

protocols, if applicable. Developers of non-sequestration-based projects are 

required to retain these records for five years after the crediting period in which 

that data report is submitted ends. Developers of sequestration offset projects 

must retain these records for the length of time that the offset project is issued 

offset credits plus 100 years.

10.Verification for Offset Projects

Verification is the process of reviewing offset project information to ensure that 

claimed GHG emissions reductions have been achieved in accordance with the 

proposed regulation. According to the proposed regulation, verification will occur 

after project implementation and prior to offset credit issuance. 

In the proposed regulation, staff includes requirements for a verification program 

that are consistent with international standards and subject to ARB oversight. 

This oversight includes verifier accreditation, verification body accreditation, 

requirements for verification services, and conflict of interest requirements. The 

proposed regulation includes enforcement provisions that apply to parties that 

participate in the offset program. These parties include offset project developers, 

verifiers, and covered entities.

To establish a high level of trust in the program and address public concerns 

related to the integrity of offset projects, staff has developed a verifier

accreditation process and conflict-of-interest process that ensures quality in the 

evaluations and prevents potential bias when offset projects are verified by 

independent third parties. 

The verifier and verification body accreditation program established in the MRR 

for purposes of emissions reporting will be expanded to include the accreditation 

of verifiers and verification bodies for offsets. Expanding the accreditation 

program will involve project type or protocol-specific training for verifiers 

accredited through the MRR program.

a. Offset Verification Services

Staff includes several key elements for offsets verification in the proposed 

regulation. The first is a mandatory site visit during the first year of verification.

Site inspection allows the verification team to ensure that all GHG sources, sinks, 

and reservoirs within the defined offset project boundary are included in the 

project’s reduction and removal estimates and that the reported data are

complete as required by the proposed regulation and the applicable protocol. It 

is also an opportunity for the verifier to assess the adequacy of the data 

management and data acquisitions systems used to collect and process data 

underlying reduction and removal estimates. At the same time, the verification 

team may conduct a review of contracts and other documents to substantiate 

reported data and ensure that data sampling and monitoring were conducted as 

applicable in the regulation and applicable protocol.
III-15

The offset verification team is also required to develop a verification plan. 

Verification plans provide documentation of planned activities, site visits, and 

document reviews. The plan will be submitted by the verification body to ARB or 

an Offset Project Registry, if applicable, with a Notice of Verification Services, ten 

days prior to a kick-off meeting with the offset project developer. The Notice of 

Verification Services allows for ARB to plan in advance for any additional

oversight of the verification, with dates of verification activities proposed in

advance. 

A critical element of offset verification is the sampling plan. This plan is used to 

conduct data checks on the reported GHG sources, sinks, and reservoirs. Offset 

verification does not call for a duplication of all calculations, but rather checking 

specific subsets of the reported data based on several criteria. Selection of data 

subsets for checking involves a review of the largest contributions to overall GHG 

sources, sinks, and reservoirs that result in reduction or removals, as well as the 

sources, sinks, and reservoirs associated with the greatest uncertainties in 

estimation. Therefore, the sampling plan includes a ranking of source 

contributions to overall GHG sources, sinks, and reservoirs and a ranking of 

sources, sinks, and reservoirs with the greatest calculation uncertainty.

The offset verification team conducts a qualitative risk assessment based on the 

uncertainty of the data acquisition equipment, data sampling and frequency, data 

processing, reduction or removal calculations, data reporting, and management 

policies or practices applied to the Offset Project Data Reports. For example, in 

evaluating the uncertainty of the data acquisition equipment, an offset verifier 

may check the age of a meter or the maintenance record for the meter. For data 

processing, the offset verifier may check how the data management system

records and tracks data that supports reduction or removal estimates. The risk 

assessment qualitatively evaluates how much confidence rests with the 

underlying infrastructure that generates reduction or removal estimates.

The proposed regulation does not prescribe the number of data checks that the 

offset verification team must perform. The offset verification team must exercise

professional judgment in choosing these. Ultimately, the offset verification team 

must have reasonable assurance that the reported emissions reductions or 

removals do not contain a material misstatement that would overestimate 

reductions or removals or a material misstatement that would underestimate by 

more than 5 percent the reported emissions reductions or removals, and that all 

applicable regulatory requirements in the proposed regulation and the applicable

protocol have been met in the estimation and reporting of those reduction or 

removal estimates. 

During the course of the offset verification, the offset verification team is required 

to maintain an issues log of any findings that may affect materiality or 

conformance with the proposed regulation. The offset verification team must also 

log how those issues are resolved to the satisfaction of the team so that the 

verification body may then provide a positive offset or qualified offset verification 
III-16

statement. Any findings that result in a change of the initial Offset Project Data

Report submitted to ARB or an Offset Project Registry must be documented. 

This careful documentation provides transparency in the offset verification 

process and allows ARB to follow the verification in detail as part of its oversight 

role.

b. Completing the Offset Verification Process

Upon completion of review by the offset verification team, the verification body 

may submit a positive offset verification statement to the operator—and ARB

and/or an Offset Project Registry—if the offset verification team has found no 

material error in the Offset Project Data Report, and if the team finds the report 

meets the requirements of the regulation. The verification body may submit a 

qualified positive offset verification statement if the team has found no material 

error in the report, but it may include one or more nonconformance(s) with 

quantification, monitoring, or metering requirements that do not result in material 

error. The verification body may also submit an adverse verification statement if

the team has found material error or is otherwise unable to state that the Offset

Project Data Report meets the requirements of the regulation. When providing 

the offset verification statement, the verification body will have an opportunity to 

add any comments or qualifiers they deem necessary to provide a complete 

context for the verification. The verification body will also submit a detailed 

verification report to the offset project developer that includes the verification plan, 

sampling plan, issues log, and additional documentation. The detailed 

verification report is retained by the project developer, but is made available to 

ARB or an Offset Project Registry upon request. The detailed verification report 

may be used by ARB or an Offset Project Registry at its discretion, to review the 

work of the verification body or review the verification process or the submitted 

data.

If a verification body and offset project developer cannot agree on the verifiability 

of the reported reductions or removals, or the need to revise the Offset Project 

Data Report, the project developer may petition ARB or an Offset Project 

Registry for review of the offset verification statement. ARB could use any 

experts at its disposal to review questions, and both parties would be held to the 

subsequent ARB decision.

11.Verifier and Verification Body Accreditation

A key element for ensuring the credibility of the offsets program is independent 

verification of reductions or removals to ensure the completeness and accuracy 

of the estimates and conformance to the regulation. Under the proposed 

regulation, verification for offsets will be performed by qualified and trained thirdparty verifiers that meet specifications for education and experience, and 

demonstrate that there is no conflict of interest for verifying reductions or 

removals due to current or previous relationships with the project developer. 

Verifiers will be required to attend a multi-day ARB-approved verifier training 
III-17

course and successfully complete an exit exam prior to being accredited to 

provide verification services for offset projects.

For offset verification, staff recognizes the need for project type- or protocolspecific verifiers, especially in the case of forestry projects or those including

carbon sequestration. These sectors often have complex baseline and 

emissions-reduction calculation methods, contractual arrangements, and sales

and purchase complexities that require verifiers to have special knowledge. ARB 

will offer project type-specific training in addition to general verification and lead 

verifier training. All lead verifiers and general verifiers may take the additional 

project type-specific training if there is a training offered by ARB. Lead verifiers 

who lack experience in environmental or financial auditing would have additional 

training. Based on guidance from existing programs, such as the International 

Organization for Standardization (ISO), these various requirements aim to ensure 

quality and consistency in the conduct of verification activities.

12.Conflict of Interest for Offset Projects

Conflict of interests arise when an individual or organization have interests in one 

activity that could possibly influence its objectives in another activity. Conflict-ofinterest safeguards are especially important in the offsets program because 

verification bodies and the offset project developers enter into contracts for 

performing verification activities, in which they agree on a monetary payment for 

services rendered. In an offset verification scenario, the verifier reviews the 

amount of GHG emissions reductions reported, as well as the project developer’s

conformance with the requirements of the regulation. The monetary value of this 

contractual relationship depends on the complexity of the project verified by the 

verification body. The proposed regulation contains requirements and criteria for

potential conflict-of-interest assessments between verification bodies and offset 

project developers to prevent them from occurring. 

The conflict-of-interest requirements in the proposed regulation ensure that the 

verification process is independent and free of any external bias or interests of 

the verifier influencing the review of data reported by the offset project developer. 

The proposed regulation provides guidance and criteria as to what types of 

relationships and practices are unacceptable between a verification body and the 

offset project developer. 

Prior to providing verification services to an offset project developer, the 

verification body must evaluate the level of potential conflict between itself and 

the developer. The proposed regulation provides requirements and criteria for 

determining whether a potential conflict is low, medium, or high. If the potential 

conflict is determined to be high, then offset verification may not commence 

between that verification body and the project developer. If the potential conflict 

is found to be low, then the verification may commence. If there is a medium 

level of risk for conflict of interest, and the verification body wishes to pursue 

offset verification services, it must provide a plan for how it will mitigate any 
III-18

conflict before finding the risk as acceptable and proceeding with the offset

verification process.

ARB plans to train its accredited offset verifiers to properly assess conflict-ofinterest situations based on the criteria laid out in the regulation. ARB’s role in 

the conflict-of-interest process will be actively auditing the offset verifiers to 

ensure they appropriately assess and certify their conflict of interests before they 

move forward with providing offset verification services. 

The proposed regulation contains a requirement for offset project developers to 

change offset verifiers after six years to avoid potential conflict-of-interest issues 

from lengthy business relationships. This results in a new set of eyes to review 

the reduction or removal estimates provided by the project developer. Staff 

includes this requirement to reduce complacency that may occur given the 

familiarity a verification body may feel toward an offset project developer after 

that time period. 

13.Issuance and Registration of Offset Credits

Once emissions reductions or removals from projects listed through the ARB 

process have been verified and issued a positive offset or qualified positive offset 

verification statement, ARB or an Offset Project Registry will issue offset credits 

in an amount equal to the GHG reductions or removals verified. Each offset 

credit that is issued by ARB or an Offset Project Registry will be assigned a 

unique serial number and be entered (registered) into the respective registry 

systems and subsequently the account of the registered owner of the offset

credits, unless the offset credit is being diverted into ARB’s Forest Buffer Account 

for forestry permanence purposes. Owners of offset credits will be notified by 

ARB or an Offset Project Registry within 45 days of the determination for 

issuance of offsets.

Offset credits do not constitute a property right and may be invalidated by ARB. 

Once issued, offset credits can be traded, sold, or used as part of an entity’s 

compliance obligation. To ensure that offset credits are not double-counted, the 

serial numbers must be taken out of circulation when an offset credit has been 

retired or used for compliance.

Before offset credits issued by Offset Project Registries can be used for 

compliance in the cap-and-trade program, all information for that offset project 

submitted by the project developer to the Offset Project Registry—including 

listing, reporting, and verification information—must be transferred from the 

registry to ARB. The offset project developer must also submit a series of 

attestations to ARB stating that all information they have submitted to a registry is 

truthful and accurate. These attestations provide an enforcement link between 

the project developer and ARB. In the event that ARB needs additional 

information regarding the initial information submitted, ARB will notify the project 

developer and allow time for this review. After all information is satisfactory and 

the attestations are made, ARB will issue an offset credit within 30 days. ARB 
III-19

will place it into the owner’s Holding Account once it has confirmation that any

corresponding offset credit has been retired in the originating registry. 

14.Forest Buffer Account

The proposed regulation establishes a Forest Buffer Account—a permanence 

mechanism for ensuring GHG emissions remain out of the atmosphere—to 

replace offset credits in the event of an unintentional reversal. The account acts 

as an insurance policy; the developers pay a premium up front to be fully covered 

in the event of an unintentional loss of sequestered carbon. An unintentional 

reversal of stored GHGs means any reversal, including wildfires or disease, that 

is not the result of the forest project developer’s negligence, gross negligence, or 

willful intent. Ultimately, the risk of impermanence may affect the cap, if 

obligated metric tons are lost, and the liable party is not able to make good on 

their obligation. In the case of an unintentional or an intentional reversal, the 

forest project operator must notify ARB of the reversal and how many metric tons 

were reversed. If the unintentional reversal reduces the project’s stored carbon 

below its project baseline, the project will automatically be terminated, but the 

developer may relist the offset project under certain conditions. If the reversal is 

intentional, the offset project will be terminated, and it may not be relisted.

The proposed regulation requires that a portion of all offset credits issued by 

ARB to offset projects developed according to ARB’s U.S. Forest Projects 

Protocol be placed into the Forest Buffer Account to cover unintentional reversals. 

The forest project operator is required to follow the methods in the U.S. Forest 

Projects Protocol for calculating the project’s risk rating. The risk rating is based 

on a number of default and calculated factors that differ depending on the 

individual project. The factors and equations that must be used to determine 

each project’s risk rating are provided in the protocol. 

The project must place offsets into a buffer mechanism, regardless of whether a 

forest project originates with ARB or an Offset Project Registry. If a forest project 

originates through the use of an Offset Project Registry, all offset credits that are 

set into the Offset Project Registry’s buffer account must be transferred to ARB 

at the time that a forest offset credit is brought into the compliance offset program.

Staff will monitor the use of the Forest Buffer Account over time. If the account

appears to be diminishing at a faster rate than it is being replenished, ARB may 

need to adjust the U.S. Forest Projects Protocol to require that more offset 

credits are placed into the buffer pool in the future. If the buffer pool is ever 

exhausted, staff would evaluate options for replenishing it, including potentially 

retiring allowances from the Reserve.

15.Invalidation of Offset Credits

To ensure the enforceability of compliance offsets, ARB needs to have the ability 

to investigate and take action for violations or noncompliance with the proposed 

regulation. There are two primary reasons that ARB may need to invalidate 

offset credits after they have been issued: (1) fraud or malfeasance on behalf of 
III-20

the project developer, the third-party verifier, verification bodies, or others 

involved in producing the documentation used to support the issuance of offset 

credits, or (2) a reversal in the forest sector. If an offset credit has been used for 

compliance or retired and is subsequently invalidated, it must be replaced within 

30 days. If the offset credit has already been retired, staff is proposing in all 

cases of fraud or malfeasance that the entity that used or retired it be responsible 

for replacing the invalidated offset credits. The covered entity may then take 

appropriate action through third-party contractual arrangements they may have 

established prior to purchase. These arrangements currently exist in the 

voluntary offset market, and staff expects that as the offset market becomes 

more established, that a standardized contract for third-party liability will be 

established. In the event that the offset credit has not yet been used or retired, it 

will be canceled in the market tracking system and removed from any Holding or 

Compliance Accounts.

If there is an unintentional reversal in the forest sector, staff will retire the 

appropriate number of offset credits from the Forest Buffer Account, whether or 

not they have already been used or retired within the system. If there is an 

intentional reversal in the forest sector, staff proposes that the forest project 

developer replace the invalidated offset credits within 30 days, whether or not 

they have been retired within the system. Staff is proposing to hold the project 

developer liable for intentional reversals in the forest sector because the risk of 

reversal is more prevalent. Buyers will have little incentive to invest in forestry 

projects if the liability falls back to them. Instead they will pursue projects with 

more certain emissions reductions. 

16.Offset Project Registries

Staff includes provisions in the proposed regulation to allow third-party offset 

programs (Offset Project Registries), that meet ARB standards, to perform many 

of the responsibilities in the offset creation process to take advantage of their 

resources and expertise and minimize the administrative burden of the offsets 

program on ARB staff. The responsibilities that Offset Project Registries may 

take on include: listing offset projects; overseeing monitoring; reporting; and 

verification activities; and issuance of ensuing offset credits. These services are 

also referred to as registry services. All offset credits issued according to Boardapproved protocols must be verified using ARB-accredited verifiers. ARB would 

still need to perform required CEQA analyses, adopt compliance protocols, and 

oversee Offset Project Registry activities. ARB oversight of the conduct of Offset 

Project Registries and ARB-accredited verifiers is critical to the overall quality of 

the program. 

The proposed regulation includes comprehensive requirements that an Offset 

Project Registry must meet to be approved by ARB, including the submittal of: an 

application, information regarding its staff and Board members, and proof of 

professional liability insurance. ARB will then evaluate the application and 

information submitted to ensure that it meets the regulatory criteria in the 

proposed regulation and does not have any conflict of interests. If the program is 
III-21

approved, ARB will issue an Executive Order designating the Offset Project 

Registry to provide registry services which will be valid for five years. At the end 

of the five years it may reapply to continue offering registry services to ARB. 

ARB may also decide to modify, suspend, or revoke this approval for good cause.

Offset Project Registries are required to make specific information publicly 

available on all of the listed offset projects. They are also required to perform

annual audits of 20 percent of a representative sample of listed offset projects. 

This information must be submitted to ARB, along with an annual report of its 

findings. The Offset Project Registry must also make its staff and all 

documentation related to any offset project it lists available to ARB for audits, and 

it must retain all records related to its audits and its listed offset projects for a 

specified period of time, as laid out in the proposed regulation.

B. Recognition of Compliance Instruments from Other Programs

1. Early Action Offset Credits

Beginning in 2005, the Climate Action Reserve (CAR) and its predecessor, the 

California Climate Action Registry began adopting voluntary GHG accounting 

protocols to encourage voluntary early action to reduce GHG emissions. ARB 

recognizes the rigor of the voluntary accounting procedures CAR adopted to 

establish that GHG emissions reductions are real, additional, and permanent. 

CAR has issued approximately 7.5 million credits for offset reduction projects to 

date under its voluntary program.36

Staff is proposing to allow offset credits issued according to the following 

protocols developed for four project types to be used for compliance purposes:

 Staff proposes to allow eligible offset credits 

and ongoing projects using protocols developed for four project types and

adopted by CAR’s Board to transition into ARB’s compliance offset program. 

Recognition of early action offset credits will increase the supply of eligible 

compliance offset credits available in the short term. 

• Climate Action Reserve Livestock Protocol versions 1.0 through 3.0.

• Climate Action Reserve Urban Forestry Protocol versions 1.0 through 1.1.

• Climate Action Reserve Ozone Depleting Substances Protocol version 1.0.

• Climate Action Reserve Forestry Protocol version 2.1, or Climate Action 

Reserve Forestry Protocol versions 3.0 through 3.2, if the offset project 

has a conservation easement of has contributed offset credits based on its

reversal risk to an insurance buffer account. 

 

36 Information found at: http://www.climateactionreserve.org/. (accessed October 24, 2010)
III-22

If an offset project has used one of the above-mentioned protocols, its offset 

credits may be used for compliance purposes if the GHG reductions meet the 

following criteria:

• Occurred between January 1, 2005, and December 31, 2014.

• Result from an offset project with an offset project commencement date 

prior to January 1, 2012.

• Result from an offset project located in the United States.

• Have not been retired, canceled, or used to meet a voluntary commitment 

or a surrender obligation in any voluntary or regulatory system.

• Meet the requirements for verification and conflict of interest for offset 

projects as required by the proposed regulation and required under AB 32

for all GHG reductions and GHG removals used for compliance purposes.

If an offset credit meets all of these requirements it may be used for compliance 

purposes. To avoid double-counting, the third-party offset program that issued 

the offset must retire it in their system before it is issued within ARB’s tracking 

system.

Staff is aware that several voluntary offset programs currently use and may, in 

the future, use these protocols to issue offset credits. In the proposed regulation,

staff includes requirements that an offset program must meet in order to have its 

offset credits issued according to these protocols for compliance purposes. If the 

program is an Offset Project Registry has been issued an Executive Order, it will 

be approved for purposes of recognizing early action offsets. If it has not been 

issued an Executive Order, it must prove it meets the requirements spelled out in 

the proposed regulation.

2. Sector-Based Offset Crediting Programs

Because climate stabilization requires global cooperation to reduce GHG 

emissions, staff proposes a framework for including sector-based offset credits 

from subnational programs in developing countries in the proposed regulation. 

Sector-based crediting is a concept that has emerged in international climate 

forums as an opportunity to broaden the scope and scale of emissions reductions 

in developing countries. It offers a bottom-up approach to developing-country 

mitigation, whereby host jurisdictions commit to establishing programs to reduce 

emissions in a particular sector of their economy, while jurisdictions in developed 

nations provide markets and other incentives to help finance those reductions. 

The term sector refers to an economic activity or a group of related economic 

activities that occurs across a government jurisdiction. The cement and forest 

sectors are two examples. In a sector-based crediting program, a host 

jurisdiction’s entire sector would need to meet an emission target before crediting 
III-23

could be used in a California compliance market. The program’s host jurisdiction 

would establish its own baseline (which would represent existing conditions for

the particular sector) and a crediting baseline (which would represent a 

significant reduction in GHG emissions from its existing condition for the entire 

sector within that jurisdiction). Emissions reductions that occur below the 

crediting baseline could be issued credits that can be used by covered entities in 

the California compliance market, subject to approval of that program by the 

Board. 

Sectoral approaches allow jurisdictions to focus on those economic sectors that 

have contributed the most significant GHG emissions within their jurisdiction or 

that have the potential for significant future emissions. By moving from a projectby-project approach, a sector-based crediting program can cover a larger 

geographical area or market and reduce the risk of emissions leakage within the 

jurisdiction. By crediting a sector based on some target level of reductions, 

competitiveness concerns among trade-exposed sectors can also be alleviated. 

The regulation establishes a framework for accepting sector-based offset credits 

from developing countries. While staff is not proposing to approve any sectorcrediting programs or adopt any protocols for sector-based offset credits at this 

time, this framework should help provide a necessary incentive for developing 

countries37

California has been working with state and provincial partners in two major 

initiatives exploring and developing sector-based offset crediting mechanisms. 

First, Governor Schwarzenegger established the Governors’ Climate and Forests 

Task Force (GCF) in 2008. The GCF is a consortium of states and provinces 

aimed at establishing a market for forest carbon offset credits from reducing 

emissions from deforestation and forest degradation (REDD). Second, California 

has also been a leader and co-founder of the International Carbon Action 

Partnership (ICAP), a consortium of states and countries pursuing the 

development of carbon markets. 

to reduce their emissions and work toward meeting compliance grade 

sector-based offset credit requirements in California.

 

37 Developing countries, for the purpose of this regulation, are defined as those identified as NonAnnex 1 Parties by the United Nations Convention on Climate Change (UNFCCC). These 

countries have been recognized as being especially vulnerable to the adverse impacts of climate 

change and include countries with low-lying coastal areas, those prone to desertification and 

drought, and those that rely heavily on fossil fuel production due to their economic vulnerability to 

climate change mitigation measures. Least Developed Countries, as identified by the United 

Nations, are included in this list due to their limited capacity to respond to climate change and 

adapt to its adverse effects. California will also take into consideration opportunities where 

emissions reductions also have significant health benefits.
III-24

a. Sector-Based Crediting Program Approval

Each sector-based crediting program will need to be approved by the Board, and 

ARB’s review of each sector-based crediting program will include a public 

consultation process pursuant to the Administrative Procedure Act. Staff 

anticipates a limited number of sector-based programs will be approved in the 

near-term because of the intensive review each program will undergo. Initially, 

staff anticipates that the Board would limit itself to working with subnational 

jurisdictions that have the most advanced and promising infrastructure necessary 

to develop sector-based programs. Staff also proposes that the first sectors to be 

considered for approval be developed through existing partnerships such as the 

GCF and ICAP. To that end, REDD is likely to be the first type of sector-based 

crediting program brought to the Board for consideration, as is discussed below 

in more detail. 

Some general principles that will guide ARB’s review of sector-based crediting 

programs include the following:

• Whether the sector represents a significant portion of the host 

jurisdiction’s economy-wide GHG emissions.

• Whether the opportunities for reductions resulting from the program are 

especially significant.

• Whether the host jurisdiction has employed robust emissions monitoring, 

reporting, and verification practices.

• Whether the host jurisdiction has a GHG emissions-reduction strategy that 

incorporates reductions from its own domestic actions or policies in 

addition to reductions that result from a carbon offset program.

• Whether the program has homogeneity of the product, production process, 

and concentration of firms located or operating within the jurisdiction.

• Whether the host-jurisdiction’s program includes means for public 

participation and consultation in the program design process. 

Following Board approval of a program, offset credits generated from the 

program can be used for compliance in the California cap-and-trade program,

consistent with the regulation. ARB will evaluate opportunities for additional 

programs after the first programs are established and tested.

b. Crediting Pathways to Emissions Reductions 

Staff proposes the inclusion of two crediting pathways for ARB-approved sectorbased crediting programs. A crediting pathway refers to how a sector-based 

crediting program issues credits for reducing or avoiding emissions, or for 

removing and sequestering carbon from the atmosphere. 
III-25

The first type of crediting pathway would be used when an ARB-approved 

program achieves sector-wide emissions reductions from mitigation policies 

undertaken by or in coordination with the jurisdiction. The second crediting 

pathway occurs when an ARB-approved program issues credits to project 

developers for project-level activities that are “nested” within a jurisdiction-wide 

sectoral program. A nested system must coordinate the accounting of reductions 

at the project within the jurisdiction’s own sectoral planning and accounting. 

Under either crediting pathway, sector-based credits used for compliance in the 

California program must be additional to the host jurisdiction’s legal requirements 

and in excess of the host jurisdiction’s own commitment toward GHG emissions

reductions for that sector. This additionality requirement ensures that the host 

jurisdiction is responsible for achieving a reasonable level of emissions

reductions across the sector prior to credits being issued to covered entities. 

c. Quantitative Limit 

Because sector-based offset crediting programs are new and evolving, staff 

proposes to limit the number of sector-based offset credits allowed in the 

California compliance market to 25 percent of the overall quantitative offset limit 

during the first and second compliance periods, and 50 percent of the limit during 

the third compliance period.

d. General Sector-Based Offset Credit Program Elements 

For the Board to consider a given sector-based crediting program for approval, 

the program would need to satisfy several criteria. While the proposed regulation 

establishes general requirements, staff will need to develop more sector-specific 

criteria and methodologies dependent upon the specific program considered prior 

to Board approval. 

Programs must establish a business-as-usual reference-level baseline that 

accurately reflects the sector’s historic and/or potential future GHG emissions for 

that jurisdiction’s entire sector. The program would need an agreed level of 

deviation from the reference-level baseline, or crediting baseline, which is 

achieved through the jurisdiction’s direct policies and mitigation actions. Sectorbased credits could then be used for compliance once GHG emissions are 

reduced beyond the program’s established crediting baseline. Emissions

reductions must be verified by a third party to ensure reductions are real, 

additional, quantifiable, and permanent.

The program must also include a robust and transparent system for inventory, 

monitoring, and reporting to track and evaluate GHG reduction activities for the 

sector’s emissions performance over time. Inventory and monitoring for land-use 

sectors should reflect, at a minimum, Intergovernmental Panel on Climate 
III-26

Change (IPCC) Tier 2 methodologies,

38

e. Reducing Emissions from Deforestation and Forest Degradation 

(REDD) 

which apply country or region-specific 

emission factors and higher temporal and spatial resolution rather than more 

general default factors and course resolution. The program will also need to 

establish an accounting mechanism that has the ability to reconcile accounting at 

both the project and sector level, as well as nest into a national accounting 

system, if one exists. A program must also include a registry, mechanisms for 

credit retirement, and protection against reversals where applicable. Each sector 

may require its own set of unique set of criteria beyond the general criteria 

currently included in the regulation.

Staff proposes that the first sector-based credits to be incorporated in the capand-trade program come from Board-approved REDD sector-based crediting 

programs. This recommendation is based on the important role that forests play 

in climate change in terms of sequestering carbon, and in particular, the role that 

tropical forests play in directly affecting the climate. According to the Technical 

Summary from the IPCC Working Group,39

The significance of deforestation emissions has brought the issue to the forefront 

of both domestic and international negotiations. Attention has focused on 

developing a REDD mechanism that offers incentives for domestic actions to 

further avoid deforestation and to transition to a low-carbon economy. In the 

above-mentioned Technical Summary, the IPCC has stated that “Reduced 

deforestation and degradation is the forest mitigation option with the largest and 

most immediate carbon stock impact in the short term per hectare and per year 

globally.” For California’s cap-and-trade program, sector-based credits from 

avoided deforestation are a potentially promising opportunity for covered entities 

to reduce compliance costs while ensuring net reduction of GHG emissions to 

the atmosphere.

CO2 emissions from tropical 

deforestation and degradation account for approximately 17 percent of global 

greenhouse gas emissions to the atmosphere, representing the second largest 

emissions sector after fossil fuel use.

 

38 Paustian, K. et al. IPCC Guidelines for National Greenhouse Gas Inventories. Volume 4, 

Chapter 1, (2006). Found at: 

http://www.ipcc-nggip.iges.or.jp/public/2006gl/pdf/4_Volume4/V4_01_Ch1_Introduction.pdf. See 

Page 1-11, Box 1.1 Framework of Tier Structure for Agriculture, Forestry, and Other Land Use 

Methods.

39 Nabuurs, G. J., O. Masera, et al. (2007). Forestry. Climate Change 2007: Mitigation of Climate

Change. Contributions of Working Group III to the Fourth Assessment Report of the

Intergovernmental Panel on Climate Change. M. Apps and E. Calvo. New York, Cambridge 

University Press. Found at: http://www.ipcc.ch/publications_and_data/ar4/wg3/en/ch9.html
III-27

Since 2008, California established itself as a leader in the REDD effort at the 

subnational level through the creation of and participation in the GCF process, 

creating global subnational partnerships and a blueprint for supporting eligible 

forest carbon activities in REDD programs. Subnational jurisdictions that are 

members of the GCF are home to 21 percent of the world’s tropical forests, most 

of which are experiencing severe deforestation pressure for alternative uses, 

such as large-scale agriculture, and ranching.

40

While REDD poses significant emissions mitigation opportunities, the concept is 

newly emerging, and it is imperative that California moves forward carefully with 

the goal of establishing a REDD model for subnational programs that is of high 

quality and replicable.

i. Setting a Framework and Criteria for Subnational REDD 

Programs

A protocol must be developed and approved by the Board to quantify, monitor, 

report, and verify emissions reductions achieved by REDD programs. To be 

considered for approval by the Board, a REDD program will need to be designed 

as closely to the following framework and criteria as possible:

• REDD Plan. The host jurisdiction’s REDD program must be based on a 

forest sector plan that has been approved by the host jurisdiction and 

specifically:

o Assesses the local drivers of deforestation in its jurisdiction; 

identifies reforms and policies to address these drivers; identifies 

emissions from deforestation; and identifies systems to be used for 

data collection, monitoring, and the development of institutional 

capacity necessary to implement a deforestation reduction program.

 

40 Gibbs, H. K. and J. O. Niles. 2010 (unpublished). Preliminary Estimates of Forest Area and 

Forest Carbon Stocks in Developing Country GCF States and Provinces. Tropical Forest Group 

Report for the Governors’ Climate and Forest Taskforce (GCF). Boulder, CO. 2010. Based on: A. 

Ruesch, and H.K. Gibbs. 2008. New IPCC Tier-1 Global Biomass Carbon Map For the Year 2000. 

Available online from the Carbon Dioxide Information Analysis Center http://cdiac.ornl.gov, Oak 

Ridge National Laboratory, Oak Ridge, Tennessee.

Note: Carbon estimates are based on Ruesch and Gibbs (2008) spatial database of biomass carbon stored in above and 

belowground living vegetation, circa 2000, which was created following the International Panel on Climate Change (IPCC) 

Good Practice Guidance for reporting national greenhouse gas inventories. The team synthesized and mapped the IPCC 

Tier -1 default values using the GLC2000 global land cover map stratified by continent, ecoregion and forest disturbance 

level. The database is appropriate for regional to global assessments only and has not been validated with field data and 

therefore may be used for estimations. Spatial resolution is 1km by 1km. 

http://cdiac.ornl.gov/epubs/ndp/global_carbon/carbon_documentation.html
III-28

o Establishes a timeframe for implementing the program and 

transitioning to low emissions development with respect to 

emissions from forest and land use activities.

• Inventory. The REDD program must utilize the most up-to-date and 

comprehensive accounting of sources and sinks available to the host 

jurisdiction, and is consistent with estimates of carbon stocks and 

emissions based on forest classes defined in the Intergovernmental Panel 

on Climate Change Good Practice Guidance for Land Use, Land Use 

Change, and Forestry.41

• Reference Level. The REDD program must set a GHG emissions 

reference level that represents a conservative estimate across a 

jurisdiction’s forest sector. Staff’s initial thinking is that this reference level 

should be derived from absolute deforestation based on historic emissions 

averaged over a 10-year period and adjusted if necessary.

 

• Crediting Baseline. The REDD program must set a crediting baseline 

based on specific targets for 2020 and beyond.

• Nested Accounting. If the program is nested, it must include the 

necessary infrastructure for clear reconciliation of project performance 

with the performance of the sector as a whole. 

• Retirement. The program must include a retirement mechanism for 

removing the credits that have been used for compliance from the statelevel accounting system, crediting baseline, and credits retired.

• Public Participation and Participatory Management Mechanism. The 

REDD program must established and incorporated an effective public 

participation and participatory management process that provides for the 

consultation and full involvement of forest-dependent communities in 

affected areas during the planning, design, implementation, monitoring,

and evaluation of program activities.

• Protection Against Reversals. The REDD program must established a 

statewide forest sector performance insurance mechanism to ensure 

projects are not penalized for reversals against the jurisdiction’s crediting 

baseline.

 

41 Good Practice Guidance for Land-Use, Land-Use Change and Forestry, (2003). Edited by 

Penman J., et al. Published by the Institute for Global Environmental Strategies (IGES) for the 

IPCC. Found at: http://www.ipcc-nggip.iges.or.jp/public/gpglulucf/gpglulucf_contents.html. 
III-29

ii. Next Steps for REDD Implementation

In 2011, ARB will work closely with REDD technical experts, scientists, 

stakeholders, research institutes, and the Governors’ Climate and Forests Task 

Force to address critical technical and policy issues in order to refine guidance 

for a high-quality subnational REDD program. Staff anticipates that REDD offset 

credits from Board-approved programs could enter the California market in 2015. 

Staff is, however, contemplating how pilot activities with host-jurisdictions closest 

to having program infrastructure in place could be considered for approval earlier 

than 2015. A pilot program or group of pilot programs could provide REDD 

credits sometime during the first compliance period. 
IV-1

IV ANALYSIS OF ALTERNATIVES TO THE PROPOSED 

REGULATION

This Chapter provides an analysis of the alternatives staff considered to the 

proposed cap-and-trade regulation. Part A describes the alternatives to 

implementing a cap-and-trade program. Part B describes the alternatives to 

some specific cap-and-trade program design features. For each of the 

alternatives, staff outlines the costs and benefits of the approach and explains 

why it chose to propose the cap-and-trade regulation and incorporated design 

features.

A. Alternatives to the Cap-and-Trade Program

Staff analyzed four alternatives to the proposed cap-and-trade regulation:

• Do not implement the cap-and-trade program, and do not replace it with 

an alternate approach to achieve additional emissions reductions (no 

project).

• Implement additional source-specific regulations designed to achieve the 

AB 32 goals in place of the cap-and-trade program.

• Implement a carbon fee in place of the cap-and-trade program.

• Link a California cap-and-trade program to a federal cap-and-trade 

program.

In evaluating these alternative approaches to the proposed regulation, ARB staff 

found that none were as, or more, effective than a cap-and-trade program in 

carrying out the goals of AB 32. Further, none of the options that would have 

enabled California to meet AB 32 goals were as cost-effective as the proposed 

cap-and-trade regulation. Staff provides a discussion of each alternative in the 

following sections.

1. Do Not Implement the Cap-and-Trade Program (“No Project” 

Alternative)

The “No Project” Alternative defines a scenario in which ARB would not 

implement a cap-and-trade program, and would not supplement the 

complementary measures identified in the Climate Change Scoping Plan to 

achieve the additional emissions reductions needed to meet the AB 32 emissions 

limit. Under this alternative, ARB would fail to meet its legal mandate to reduce 

GHG emissions to 1990 levels by 2020. 

As part of the ongoing work to implement the Scoping Plan, ARB staff updated 

2020 GHG emissions-reductions projections with estimates published in adopted 

regulations’ staff reports. In addition, the baseline forecast and the reductions 

that would be achieved by the complementary measures were adjusted to 

account for the recent economic downturn. Measures that were not considered 
IV-2

likely to realize reductions within the 2020 timeframe were not included in 

emissions-reduction totals. In analyzing reductions that would occur under the 

No Project Alternative, staff considered only those measures that are adopted 

and those not-yet-adopted measures that are planned and reasonably 

foreseeable. 

ARB Scoping Plan measures that have been adopted by the Board, pursuant to 

AB 32,42 measures that are being implemented by other agencies and 

organizations,43 and measures that are reasonably foreseeable44 are currently 

projected to provide approximately 62 MMTCO2e in reductions in 2020. Given a 

2020 baseline projection of 507 MMTCO2e,45

In addition, the cap-and-trade program is unique in setting a firm limit on 

emissions, rather than establishing performance standards and other 

mechanisms to reduce the emissions intensity of different activities. For most 

complementary measures, the emissions reductions will vary based on factors 

like economic and population growth. The firm limit on emissions established by 

the cap-and-trade program will help ensure that statewide emissions will meet 

the AB 32 target, even if implementation of the complementary measures results 

in greater remaining emissions than currently anticipated.

 the No Project Alternative would 

result in emissions of 445 MMTCO2e in 2020—at least 18 MMTCO2e above the 

427 MMTCO2e target. This gap could be significantly greater if adopted 

measures fail to achieve expected reductions, if energy-efficiency programs are 

not funded at adequate levels or are less effective than projected, or if the 

economy grows faster than expected. Based on this information, if the cap-andtrade regulation is not implemented, California’s GHG emissions will not be 

reduced to 1990 levels by 2020, in violation of AB 32. 

 

42 33 percent Renewable Electricity Standard (part of E-3), Low Carbon Fuel Standard (T-2), 

Regional Targets (T-3), Tire Pressure Program (part of T-4), Ship Electrification (T-5), Port 

Drayage Trucks (part of T-6), Heavy Duty Aerodynamics (T-7), Medium/Heavy Hybridization (T-8), 

Energy Efficiency and Co-Benefits Audits for Large Industrial Sources (I-1), Motor Vehicle A/C (H1), SF6 Limits in Non-Utility and Non-Semiconductor Applications (H-2), Reduction of 

Perfluorocarbons in Semiconductor Manufacturing (H-3), Limit High GWP Use in Consumer 

Products (H-4), Refrigerant Tracking/Reporting/Repair Deposit Program (part of H-6), SF6 Leak 

Reduction and Recycling in Electrical Applications (part of H-6), and Landfill Methane Control 

Measure (RW-1).

43 High-Speed Rail (T-9), Energy Efficiency and Conservation (E-1), Million Solar Roofs (E-4), 

and Sustainable Forests (F-1).

44 Advanced Clean Cars (formerly Pavley II, T-1).

45 The revised 2020 baseline accounts for the economic downturn and includes the emissions 

reductions from Pavley I and the 20 percent renewable portfolio standard. For more details, see 

the revised 2020 baseline forecast at ARB’s “Greenhouse Gas Inventory - 2020 Forecast” 

webpage: http://www.arb.ca.gov/cc/inventory/data/forecast.htm.
IV-3

2. Implement Only Additional Source-Specific Command-and-Control 

Regulations

Another alternative to adopting the cap-and-trade regulation would be to 

implement additional source-specific command-and-control regulations that 

would achieve the same level of GHG emissions reductions as that of the 

proposed cap-and-trade program. If this alternative were pursued, ARB would 

likely focus primarily on the industrial sector because the transportation, 

electricity, and natural gas sectors are already extensively addressed46

Command-and-control regulations would not provide the same assurance of 

reductions as that offered by a cap-and-trade program. Emissions reductions 

from command-and-control regulations are estimates based on assumptions 

about the specific regulation, and typically result from reducing the emissions 

intensity of the activity that is regulated. These assumptions may include 

forecasts of technology development and penetration estimates. Although these 

estimates would be based on the best data available, actual results may be 

significantly different because regulations may fail to achieve expected 

reductions, or programs may not be funded at adequate levels or may be less 

effective than projected. In addition, increases in the regulated activity (e.g., an 

increase in throughput) could mean that the regulation has the effect of reducing 

emissions intensity but the absolute level of emissions could actually increase. A 

cap-and-trade program, on the other hand, would establish the maximum level of 

total GHG emissions allowed to be emitted collectively by all covered sources. 

Because the proposed cap-and-trade program sets a cap on the GHG emissions 

from the majority of California’s GHG emissions, it helps ensure that the State 

will meet the AB 32 statewide emissions limit. 

through 

complementary Scoping Plan measures. 

Command-and-control regulations would also not allow for a demand-side 

response to an allowance price signal across the entire economy. The price 

signal established through a cap-and-trade program would provide an incentive 

for investment in energy efficiency and clean fuels, and would also drive 

efficiency and conservation in consumer and residential energy use beyond that 

required through the Scoping Plan’s complementary measures.

Source-specific regulations are also unlikely to be as cost-effective at reducing 

GHG emissions as the proposed cap-and-trade program. The cap-and-trade 

program is designed to allow covered entities to find the most cost-effective GHG 

emissions reductions by reducing their GHG emissions, buying allowances from 

 

46 The transportation, electricity, and natural gas sectors provide over 80 percent of total 

adopted and foreseeable 2020 reductions from complementary measures; whereas, the industrial 

sector provides less than 1 percent of these reductions.
IV-4

an entity that does not need them for compliance, or purchasing offset credits. 

With source-specific regulations, entities must comply with the regulation, no 

matter what it costs. Even though each source-specific regulation must undergo 

cost-effectiveness analyses, it may not necessarily be the most cost-effective for 

the industry and economy as a whole because cost-effective reductions are not 

necessarily evenly distributed through all industrial sectors.

In addition to lacking emissions-reductions certainty, and having the potential to 

be less cost-effective at reducing emissions, industry-wide command-and-control 

regulations would be challenging to draft and implement. To develop these 

regulations, ARB would need to identify and target specific processes and 

equipment and formulate regulations for each. Due to the diverse nature of 

many industrial processes and a lack of data, it is not practical for ARB to craft 

and implement such regulations at this time. 

The petroleum refining sector, which is the largest industrial GHG emissions 

source, provides a good example of the complexity of crafting such regulations. 

As noted by Sweeney and Wyant et al. (2008), “The complex and heterogeneous 

nature of refineries and their operations cause significant variation in the amount 

of opportunity and cost of mitigation through efficiency improvements. Thus, a 

bottom-up approach where individual refineries are examined would be needed 

to precisely quantify the amount of GHG reduction through efficiency 

improvements.”47 Worrell and Galitsky (2005) make a similar point: “Every 

refinery and plant will be different. The most favorable selection of energy 

efficiency opportunities should be made on a plant-specific basis.”48

 

47 Sweeney, Jim, John Weyant, et al. 2008. Analysis of Measures to Meet the Requirement of 

California’s Assembly Bill 32. Precourt Institute for Energy Efficiency, Stanford University. 

 Thus, to 

effectively regulate petroleum refining, plant-specific data and requirements 

would be needed. Because ARB does not have access to such data at this time, 

it would be impossible to develop these requirements. Additionally, developing, 

implementing, and enforcing plant-specific regulations would be resource 

intensive.

48 Worrell, Ernst, and Christina Galitsky. 2005. Energy Efficiency Improvement and Cost Saving 

Opportunities for Petroleum Refineries. Lawrence Berkeley National Laboratory. 

http://escholarship.org/uc/item/96m8d8gm (accessed September 22, 2010).
IV-5

3. Carbon Fee

Another alternative to the cap-and-trade regulation is to place a per-metric-ton

fee on GHG emissions from covered sources. Both a carbon fee and a cap-andtrade program would incentivize GHG emissions reductions by pricing those 

emissions, and ARB would expect to see similar types of emissions-reduction 

approaches under either pricing scheme. The major benefit of a carbon fee is 

that it provides price certainty for covered entities; with a cap-and-trade program, 

the major benefit is environmental (GHG emissions) certainty. The greater 

certainty in meeting the emissions goals provides an important policy reason to 

prefer the cap-and-trade program over a carbon fee approach. In addition, the 

cap-and-trade program proposed in this regulation includes a number of features 

designed to provide some predictability in cost, including limited use of offsets, 

banking, and an allowance reserve and reserve price.

While covered sources would face more price certainty in a carbon fee program, 

the sources covered by a cap-and-trade program can still plan effectively 

because they know what they would need to spend to reduce emissions. The 

sources can weigh those costs against the expected cost of compliance 

instruments and the long-term need to reduce emissions as part of business 

planning. A cap-and-trade program is the preferred approach because it ensures 

that technologically feasible reductions occur with the lowest marginal cost of 

control.

A carbon fee does not provide the same level of certainty in emissions as that 

provided by a cap-and-trade program. While economic modeling can estimate 

the marginal cost of abatement for emissions reductions, it cannot predict exactly 

how high the fee must be set to discourage emission sources from simply paying 

the fee instead of reducing their emissions to a level envisioned by the program. 

If the carbon fee is set too low, not enough reductions will take place and 

California will not meet the AB 32 goals. If the carbon fee is set too high, a 

greater amount of reductions would take place than would be necessary to 

comply with the program requirements, which increases the cost of the program 

to covered entities. 

Adoption of a carbon fee would also not avoid many of the complexities 

associated with implementing a cap-and-trade program, since it would still 

require reporting, monitoring, and verification of covered entities’ GHG emissions. 

ARB would also still be required49

 

49 HSC §38562 (b)(8).

to minimize emissions leakage to the extent 

feasible. Because adding any price on carbon could increase the potential for 

emissions leakage from emissions-intensive, trade-exposed industries, rules and 

protocols for managing leakage would need to be developed under both a carbon 
IV-6

fee and a cap-and-trade regulation. The proposed regulation includes a number 

of features designed to achieve this end, including substantial free distribution of 

allowances in the early years of the program, and many features designed to 

help contain costs. 

While some may argue that a carbon fee would provide a more predictable 

source of income for the State to put toward the furtherance of AB 32 goals, staff 

believes that the predictability of carbon fee revenue streams is neither 

guaranteed nor exclusive to this approach. Revenues generated by a carbon fee 

may be more predictable than those from a cap-and-trade program, but revenues 

can also be generated under a cap-and-trade program to the extent that 

allowances are auctioned. The cap-and-trade regulation mandates a minimum 

Reserve Price for allowances, guaranteeing revenue for all auctioned allowances. 

Further, cap-and-trade program auction prices also send an important signal that 

reflects the ease or difficulty of meeting program goals. Low auction prices 

would reflect low demand for permits, meaning that sources are able to 

collectively reduce emissions to meet the emissions limits at low cost. While the 

program would generate relatively lower revenues if auction prices are low, less

revenue would be needed to implement AB 32 because the AB 32 targets were 

being met. If sources are having difficulty meeting the targets, there would be 

higher demand for allowances and higher prices at auction. Under these 

circumstances, higher revenues would be generated that could be used to invest 

in additional measures to help meet the AB 32 emission targets. It is important to 

note that the measures in the Scoping Plan are designed to reduce GHG 

emissions, not to raise money.

Staff notes that implementing a carbon fee combined with a cap-and-trade 

program is possible. Indeed, British Columbia, a WCI partner, currently has a 

carbon fee and is planning to start a cap-and-trade program in 2012. Staff 

believes that the proposed cap-and-trade program design provides acceptable 

price certainty50

4. California Cap-and-Trade Program Linked with a Federal Cap-andTrade Program

while assuring that emissions do not exceed the 2020 target.

ARB is moving forward with its development of a cap-and-trade regulation while 

federal climate change legislation has stalled in Congress, leaving no prospect of 

a federal GHG cap-and-trade program in the near term.51

 

50 The cost-containment reserve mechanism sets a soft ceiling of prices, keeping them within a 

known range in most scenarios. (See Appendix G for more details.)

 With no federal cap51 The American Clean Energy and Security Act of 2009 was passed by the U.S. House of 

Representatives in June 2009, but no legislation was passed by the Senate. Several climate, 

clean energy, and energy-efficiency bills have been introduced in the Senate this year, but as of 

the beginning of October 2010, no vote is expected during this Congress, and prospects for 

action on economy-wide climate change legislation in the next Congress is unclear.
IV-7

and-trade program anticipated in the near future, ARB will continue to move 

ahead with the proposed California program designed to meet the AB 32 goals, 

and to work toward linking that program with programs developed by our WCI 

partners. If ARB waited for a federal cap-and-trade program to link with, it is 

possible that California would fail to meet the AB 32’s 2020 target. 

The major federal proposals in recent years included some form of a moratorium 

on state or regional cap-and-trade programs in the United States. If a federal 

cap-and-trade program is adopted that preempts any subnational cap-and-trade 

programs, California, along with other states participating in regional programs 

(e.g., Western Climate Initiative, Regional Greenhouse Gas Initiative, and the 

Midwestern Regional Greenhouse Gas Reduction Accord) will work to transition 

their programs to a national program.

At the federal level, California has continued to promote appropriate recognition 

of early actions taken by states to reduce GHG emissions. States that have 

taken early action through the establishment of cap-and-trade programs, 

including programs that fund GHG-reduction activities, should not be 

disadvantaged if a federal program is implemented. Should a federal cap-andtrade program be established that preempts California’s program, staff supports 

the establishment of a mechanism for the exchange of State-issued allowances 

for federal allowances to provide for an orderly transition and avoid the creation 

of stranded allowances.

B. Alternatives to Specific Cap-and-Trade Program Design Features

Staff analyzed specific alternatives to the design of the cap-and-trade regulation. 

These design elements include the following: 

• Border adjustments.

• Different offset limit.

• 100 percent auction of allowances.

• No banking of allowances.

• Not linking to other cap-and-trade programs.

• Facility-specific caps.

• Restricting trading in adversely affected communities.
IV-8

1. Border Adjustments

Staff explored two options, both recommended by the Economic and Allocation 

Advisory Committee (EAAC),52

Under the first deliverer approach, the entity that first delivers a good into the 

State would be responsible for the compliance obligation for the emissions 

associated with manufacture and transport of those goods. ARB has chosen to 

utilize the first deliverer approach to regulate emissions associated with electricity 

generated in another jurisdiction but consumed in California. This approach is 

possible for electricity because significant information is available on the 

generation and distribution of electricity with the Western Electric Coordinating 

Council system, which covers all imported electricity consumed in California.

for reducing the risk of emissions leakage in the 

cap-and-trade program: border adjustments and output-based free allocation. 

Border adjustments are a way to place a price, in the form of allowances or 

dollars, on the GHG emissions associated with imports. They are meant to 

create a level playing field when regulations vary across jurisdictions. In contrast, 

under output-based free allocation, facilities receive free allocation of allowances 

based on their output and an industry emission benchmark. Staff compared 

output-based free allocation to border adjustments and concluded that outputbased free allocation is a superior approach for non-electricity goods because it 

does not face the considerable technical and legal difficulties that border 

adjustments face. For electricity, staff chose to utilize a border adjustment in the 

form of the first deliverer compliance obligation because the requisite data are 

available, and because of the express direction in AB 32 to address electricity 

imports.

Staff chose not to extend the first deliverer approach to include entities that 

import non-electricity goods into California from out-of-state because of 

potentially significant technical and legal challenges. The first deliverer approach 

is effective if detailed production data are available on both the imported goods 

themselves and the entities producing them. Because goods are often traded 

several times before entering the California market, determining the associated 

GHG emissions could be exceedingly difficult. The application of border 

adjustments to interstate and international trade would also face legal scrutiny 

under the Commerce Clause53 and World Trade Organization principles.54

 

52 Economic and Allocation Advisory Committee. March 2010. Allocating Emissions Allowances 

under a California Cap-and-Trade Program: Recommendations to the California Air Resources 

Board and California Environmental Protection Agency. 53 Article I, Section 8, Clause 3 of the United States Constitution.

54 World Trade Organization (WTO) principles require that the cap-and-trade program must have 

the capacity to assign or verify emissions associated with the goods produced in California and in 

foreign countries in exactly the same manner. There is increasing consensus in the international 

community that border adjustments may be implemented in a manner compatible with WTO 
IV-9

In the Preliminary Draft Regulation, staff discussed the possibility of using a 

lifecycle analysis (LCA) calculation for transportation fuels’ compliance 

obligations. The LCA approach is a type of border adjustment for imported fuels. 

While this approach is being used in ARB’s Low Carbon Fuel Standard (LCFS), 

significant additional work would be needed to account for emissions that are 

included in the LCA and are also proposed to be covered under the cap-andtrade program. Staff chose not to apply LCA in the cap-and-trade program, but 

instead chose to calculate compliance obligations from direct combustion 

emissions because of the challenges of netting out stationary emissions across 

emissions categories. Staff’s proposed approach allows for greater 

administrative simplicity, and does not interfere with the goal of reducing lifecycle emissions from transportation fuels that the LCFS is designed to achieve.

Because of the technical and legal challenges involved with border adjustments, 

ARB has chosen to utilize free allocation of allowances to entities at risk of 

leakage. The proposed method of allocation used is output-based, updated, free 

allocation and was recommended by EAAC. For more information on the 

proposed allocation program, see Appendix J: Allowance Allocation.

As part of implementation of the cap-and-trade program, ARB will monitor 

whether leakage is occurring. Should ARB find that leakage is occurring despite 

the safeguards in the regulation, ARB will examine what additional safeguards, 

possibly including border adjustments, should be implemented.

2. Different Offset Limit

In the Climate Change Scoping Plan, ARB proposed setting the offset limit such 

that a majority of emissions reductions come from capped sectors. In the 

Preliminary Draft Regulation, staff converted this offset reduction to a limit of 

4 percent of each covered entity’s compliance obligation. In this proposed capand-trade regulation, this percentage was increased by 4 percent, for a total of 

8 percent, to compensate for allowances removed from general circulation to 

populate the Allowance Price Containment Reserve.55

 

requirements; however, because border adjustments are still associated with significant 

uncertainty, staff proposes to use output-based free allocation to address emissions leakage.

 Staff explored two 

alternatives to the 8 percent-of-compliance-obligation offset limit for complying 

entities in the cap-and-trade program: not allowing use of offset credits, and 

allowing unlimited use of offset credits

55 For further discussion of the Allowance Price Containment Reserve Account, see Chapter II, 

part H (Allowance Allocation), subpart 1 (Establishment of an Allowance Price Containment 

Reserve) of this volume.
IV-10

ARB’s Updated Economic Analysis of California's Climate Change Scoping 

Plan56

While offsets provide significant benefits (providing low-cost emissions 

reductions, flexibility in achieving reductions, and incentives to reduce emissions 

in sectors otherwise difficult to regulate), allowing unlimited use of offset credits 

would reduce the amount of GHG emissions reductions occurring directly within 

the sectors covered by the cap-and-trade program. This approach could reduce 

local economic, environmental, and public health co-benefits, and delay 

California’s transition to a low-carbon economy. This transition is critical to meet 

California’s long-term GHG emissions reductions goals. Because of this, staff 

has opted to allow entities to cover up to 8 percent of their individual compliance 

obligations with offset credits.

showed a large increase in the price of 2020 allowances if offsets are not 

allowed into the system. For this reason, ARB staff has chosen to allow the use 

of offsets—up to the specified limit—for compliance in the proposed cap-andtrade program.

ARB analysis of the potential emissions impacts of the cap-and-trade regulation57

3. 100 Percent Auction of Allowances

indicates that California’s existing programs to meet federal air quality standards 

will provide the majority of criteria pollutant reductions with further NOx reductions 

ranging from about 15 to 45 percent by 2020. In communities that ARB 

evaluated, the cap-and-trade regulation has the potential to provide small 

additional criteria pollutant reductions in the range of 1 to 3 percent if all 

greenhouse gas reductions were implemented locally. Because offsets provide 

more compliance instruments and lower the price, some entities may choose not 

to reduce greenhouse gas emissions on-site. In this case, the communities 

evaluated would still experience 15 to 45 percent NOx reductions by 2020.

Allowances can either be distributed freely to covered entities, sold through an 

auction, or through a combination of the two. EAAC recommended addressing 

leakage through free allocation, and relying on auction for distribution of the 

remaining allowances. In developing the cap-and-trade program, staff 

determined that a soft start for the program under the current economic 

conditions dictates greater reliance on free allocation of allowances in the early 

years of the program. Staff views this free allocation as critical to avoid adding 

an immediate cost to covered industries that could inhibit their ability to invest in 

emissions reductions. As the program progresses, staff propose a transition to a 

 

56 Updated Economic Analysis of California's Climate Change Scoping Plan: Staff Report to the 

Air Resources Board. March 24, 2010. http://www.arb.ca.gov/cc/scopingplan/economicssp/updated-analysis/updated_sp_analysis.pdf (accessed September 23, 2010). 57 See Appendix P for more details. 
IV-11

heavier reliance on auction for allowance distribution while still minimizing 

leakage where risk exists.

Because of the risk of leakage for emissions-intensive, trade-exposed (EITE) 

industries, staff has chosen to employ free allocation to minimize leakage risk. 

(See “Border Adjustments,” above, for more information.) EITE industries will 

receive free allocation of allowances for as long as the risk of leakage exists. For 

the first compliance period, the proposed program also includes allocation of the 

majority of allowances required to fulfill compliance obligations for free, not just to 

EITE industries, but also to non-EITE industries and to the electricity sector. The 

remaining allowances will be auctioned. 

An alternative approach would be to auction 100 percent of allowances at the 

beginning of the program. Staff has rejected this approach for two reasons. First, 

to avoid economic dislocation, covered entities need time to plan for and invest in 

ways to reduce their emissions in a cost-effective manner. Second, a large 

portion of free allocation is necessary due to the uncertainty associated with 

covered entities’ ability to pass through costs to consumers and remain 

competitive.

4. No Banking of Allowances

The proposed cap-and-trade regulation allows for unlimited banking of 

allowances. Allowances, once issued, do not expire. Banking provides market 

stability during times when emissions may fluctuate due to weather or economic 

conditions. In such cases, banking helps to prevent large fluctuations in 

allowance price during these periods of emissions variation. Banking also helps 

provide price stability by assuring that allowances will retain their value, and 

gives covered entities a stake in the continued operation of the program because 

allowances are a financial asset. A positive impact of allowing banking is that it 

incentivizes firms to over-comply in early compliance periods. 

Staff rejected the alternative of disallowing banking of allowances because it 

provides no financial or environmental benefits and would not necessarily 

increase the environmental integrity of the program.

5. Not Linking to Other Cap-and-Trade Programs

The proposed cap-and-trade regulation allows potential future linkage with 

external greenhouse gas emissions trading systems (GHG ETS), including those 

of WCI partner jurisdictions. Linking with external GHG ETS’s involves 

jurisdictions accepting one another’s allowances and offsets for compliance, 

creating a regional market. Linkage would increase the total supply of 

compliance instruments, which would reduce compliance costs for California’s 

covered entities. 

As proposed, the cap-and-trade regulation does not link with any external GHG

ETS. Future linkage would require regulatory action by the Board supported by a 

case-by-case analysis, including an environmental analysis. Several options 
IV-12

exist for how linkage with WCI partner jurisdictions or other GHG ETS’s might 

occur (e.g., unilateral linkage,58 bilateral linkage59

Staff rejected the option of precluding linkage with external cap-and-trade 

programs because linkage can lead to significant reductions in compliance costs 

associated with increasing the supply of compliance instruments. While linkage 

would require California to forfeit some control over where the reductions occur 

(i.e., out of state versus in state), staff believes the increased cost-effectiveness 

of the program that should result from a more liquid and better-functioning market 

for California’s covered entities offsets the possibility of fewer in-state reductions.

) but are not explored here.

6. Facility-Specific Caps

An alternative to an overarching cap for covered entities and sectors would be to 

have facility-specific declining caps. This would ensure that each facility would 

reduce its proportional share of emissions. Under such an option, ARB would 

need to identify the specific facilities that would be covered by the program, 

conduct an appropriate analysis to support a specific cap for each facility, and 

consider whether the reduction requirements established by the declining cap for 

that facility would be cost-effective. Such a program would be extremely difficult 

to apply to imported electricity or to distributed use of fuels, so that the overall 

scope of the program would likely be need to be limited to industrial facilities and 

in-state power plants. 

Facility-specific caps would diminish the flexibility of these facilities to meet the 

GHG reduction goals. In a standard cap-and-trade program, facilities can either 

reduce emissions or buy allowances from other facilities that do reduce 

emissions. Restricting trading leaves only one compliance option: reduce 

emissions on-site through increasing efficiency, modernizing equipment, 

changing to cleaner fuels, or reducing production. If the cap for all facilities 

declined at the same rate, individual facilities might not have cost-effective 

options, especially if they seek to expand production to meet increased demand. 

Establishing caps that decline at different rates at different facilities would require 

ARB staff to conduct a detailed analysis to determine what, if any, cost-effective 

options were available at each covered facility.

Reducing the flexibility of trading allowances would increase the cost of the 

program. With facility-specific caps, no market would exist that allowed entities 

to trade allowances and achieve the lowest-cost reductions. Facilities with large 

amounts of low-cost reductions would have little incentive to over-comply, while 

 

58 Unilateral linkage would allow the covered entities from one jurisdiction to use compliance 

instruments from a linked program, but would not allow covered entities from the linked 

jurisdiction to use allowances and offset credits issued by the first jurisdiction.

59 With bilateral linkage, compliance instruments are fully fungible between linked programs.
IV-13

facilities with a limited number of reduction opportunities would have to 

implement expensive reduction strategies. Thus, staff has rejected this 

alternative because of the increased cost of implementing the program across

the economy.

Although facility-specific caps would ensure that emissions reductions occur in 

specific communities, ARB’s analysis60

7. Restricting Trading in Adversely Impacted Communities

indicates that California’s existing 

programs to meet federal air quality standards will provide the majority of criteria 

pollutant reductions with further NOx reductions ranging from about 15 to 45 

percent by 2020. In communities that ARB evaluated, the cap-and-trade 

regulation has the potential to provide small additional criteria pollutant 

reductions in the range of 1 to 3 percent if all greenhouse gas reductions were 

implemented locally. Although ARB staff does not predict that the cap-and-trade 

regulation will result in emissions increases, our examination of the potential 

impacts of facility growth, for any reason, shows that in the context of total 

community emissions, these increases would be very small, reducing the 

expected 15 to 45 percent reduction by 2020 by 2 percent or less. 

Restricting trading in adversely affected communities is a design option to reduce 

potential negative impacts of cap-and-trade. By restricting trading in 

communities with heavy localized air pollution, local facilities must reduce their 

share of emissions. This design option is similar to facility-specific caps but 

applied only to discrete locations. 

Although restricting trading in adversely affected communities would ensure that 

emissions reductions occur in specific communities, ARB’s analysis61

Restricting trading among participants increases the cost to comply with the 

program. A cap-and-trade program gives entities the option of decreasing 

indicates 

that California’s existing programs to meet federal air quality standards will 

provide the majority of criteria pollutant reductions, with further NOx reductions 

ranging from about 15 to 45 percent by 2020. In communities that ARB 

evaluated, the cap-and-trade regulation has the potential to provide small 

additional criteria pollutant reductions in the range of 1 to 3 percent, if all 

greenhouse gas reductions were implemented locally. Although ARB staff does 

not predict that the cap-and-trade regulation will result in emissions increases, 

our examination of the potential impacts of facility growth, for any reason, shows 

that in the context of total community emissions, these increases would be very 

small, reducing the expected 15 to 45 percent reduction by 2020 by 2 percent or 

less.

 

60 See Appendix P: Co-Pollutant Emissions Assessment for more details.

61 See Appendix P: Co-Pollutant Emissions Assessment for more details.
IV-14

emissions at the facility or buying allowances from another entity that reduced 

emissions. In limiting these options by reducing trading, emissions reductions 

are mandated at that entity. This limits the market to find the lowest-cost 

compliance pathway. Staff feels the potential limited environmental benefits of 

restricting trading in adversely affected communities do not outweigh the 

increased cost to comply with the proposed regulation.
V-1

V COMPLIANCE P ATHWAYS SCENARIOS

A. Introduction

The California cap-and-trade program is proposed to be a flexible, market-based 

regulation designed to reduce greenhouse gas (GHG) emissions. The program 

neither mandates nor prohibits the use of specific technologies to achieve these 

reductions. The scenarios described in this Chapter demonstrate that covered 

entities will be able to comply with the cap-and-trade program using a variety of 

currently available GHG reduction strategies. Further, numerous abatement 

strategies exist, and compliance is not contingent upon the availability of only a 

limited number of abatement strategies.

Compliance pathways demonstrate which strategies covered entities could utilize 

(i.e., what “paths” they could travel) to comply with the cap-and-trade regulation. 

Staff developed compliance pathways for four scenarios, each with different 

assumptions about the availability of GHG abatement opportunities and the 

pathways that covered entities would use to achieve the GHG emissions cap. 

Each scenario includes enough emissions abatement opportunities to meet the 

AB 32 goal.

Staff developed four scenarios that illustrate the range of pathways that capped 

entities could follow to meet their compliance obligations and collectively achieve 

the cap. Staff believes that Scenario 1 (full abatement potential from 

complementary policies and full availability of offsets) is the most likely scenario, 

as it includes staff’s best estimates of complementary measures and offset 

potential achieved within the 2012–2020 timeframe. In this scenario, 43.3 

MMTCO2e of the required 74.6 MMTCO2e of reductions in 2020 would be 

achieved directly through the complementary measures, and 31.3 MMTCO2e of 

reductions would be achieved through the price signal imposed by the cap-andtrade program. At this level of abatement, the allowance price would be 

$20/metric ton in 2020—a price considered to be achievable by covered entities.

In Scenarios 2 and 3, in which offset supply (Scenario 2) and complementary 

policy reduction estimates (Scenario 3) would be decreased, allowance prices 

would increase to $40/metric ton in 2020. However, in Scenario 4, in which both 

complementary policy reduction estimates and offset potential would be reduced, 

large price increases would occur. This increase comes from the resulting 

requirement that many of the emissions reductions must come from consumers.

Analysis. 

B. Relationship between Compliance Pathways Analysis and 

Economic Analysis

The compliance pathways presented here complement the abatement estimates 

from more comprehensive models such as Energy 2020. The compliance 

pathways scenarios should be used in conjunction with the economic analysis 

provided in Chapter VIII: Economic Impacts of the Proposed Regulation. The 
V-2

compliance pathways and economic analyses estimate the cost of compliance 

with the proposed cap-and-trade regulation using different models and 

methods.62

This analysis should be viewed as illustrative of possible strategies and 

scenarios for reducing emissions consistent with the declining cap. It is flexible 

in that assumptions about abatement strategies can be easily modified, and 

transparent in that all assumptions about abatements strategies are clearly 

defined. Information about the assumptions, as well as references to supporting 

data, are described in detail in Appendix F: Compliance Pathways Analysis.

 Limitations of the compliance pathways analysis include difficulty 

harmonizing assumptions and inputs across all abatement activities, and that 

interaction effects between abatement activities are not taken into consideration. 

This analysis also does not account for implementation obstacles such as 

compliance with New Source Review regulations for criteria pollutants, 

availability of fuels and feedstock, and other environmental requirements.

C. Baseline Forecast and Required Reductions

The AB 32 baseline forecast of emissions from California capped sectors is given 

in Table V-1and presented graphically in Figure V-1. The baseline forecast 

represents an update of the GHG emissions inventory forecast used in 

developing the Scoping Plan. The forecast used the economic and energy 

forecasts from the California Energy Commission’s 2009 Integrated Energy 

Policy Report,63 which reflects the current economic downturn. Consistent with 

the updated economic analysis of the Scoping Plan completed in March 2010,64

 

62 The economic analysis uses energy and macroeconomic models, while this analysis uses a 

bottom-up approach based on information about existing technologies.

this baseline also assumes implementation of the existing California vehicles 

standards and the 20 percent Renewable Portfolio Standard. Other Scoping 

Plan measures are assessed in the compliance pathways analysis presented 

here, and so are not included in the baseline forecast. The difference between 

the baseline emissions forecast and the cap determines the GHG abatement 

necessary to meet the cap. 

63 California Energy Commission. 2009 Integrated Energy Policy Report, Final Commission 

Report, CEC -100-2009-003-CMF. http://www.energy.ca.gov/2009publications/CEC-100-2009-

003/CEC-100-2009-003-CMF.PDF (accessed October 25, 2010). 64 Updated Economic Analysis of California's Climate Change Scoping Plan: Staff Report to the 

Air Resources Board. March 24, 2010. http://www.arb.ca.gov/cc/scopingplan/economicssp/updated-analysis/updated_sp_analysis.pdf (accessed September 23, 2010).
V-3

Table V-1: Baseline Emissions, Cap Level, and Abatement Required to 

Achieve the Cap.

GHG Emissions (MMTCO2e)

Year

Forecast for Sources in the 

Cap-and-Trade Program Cap

Annual Abatement 

Needed 

2012 165.8 165.8 0.0

2013 167.3 162.8 4.5

2014 168.1 159.7 8.4

2015 406.7 394.5 12.2

2016 406.9 382.4 24.5

2017 407.6 370.4 37.2

2018 407.6 358.3 49.3

2019 408.4 346.3 62.1

2020 408.8 334.2 74.6

Figure V-1: Baseline Emissions, Cap Level, and Abatement Required to 

Achieve the Cap

0

50

100

150

200

250

300

350

400

450

2010 2012 2014 2016 2018 2020 2022

Year

Carbon Emissions (MMTCO2e)

Forecast

Cap

Abatement

Narrow

Scope

Broad Scope

D. Scenarios Analyzed

Staff developed four scenarios to illustrate the range of potential pathways that 

capped entities could follow to meet their compliance obligations and collectively 

achieve the cap. These are discussed in detail below. In each scenario, the 

entities collectively meet the regulating cap in the proposed regulation.
V-4

Staff varied assumptions about the effect of complementary policies and offset 

supply to create different scenarios. For complementary policies, staff explored 

two scenarios: (1) full abatement potential from complementary measures 

consistent with estimates in staff reports and the Scoping Plan, and (2) reduced 

abatement potential from complementary measures. For offsets, staff also 

explored two potential supply scenarios that varied the number of available offset 

credits: (1) sufficient offsets were available to meet the 8 percent limit in the 

regulation, (2) offsets were only available to meet 4 percent of entities’ 

compliance obligations. 

Based on implementation status, past experience, and current estimates of offset 

supply, staff believes that the most likely scenario is Scenario 1 (full abatement 

potential for both complementary measures and offsets) and the least likely 

scenario is Scenario 4 (partial abatement potential from complementary policies 

and offsets). Scenario 4 could occur if implementation of complementary 

measures were delayed due to legal action, if non-regulatory complementary 

measures were not as effective as originally estimated, if economic growth meant 

that reduced emissions intensity from the measures in the Scoping Plan still 

resulted in higher remaining emissions than estimated, and/or if offset projects 

did not materialize as expected by staff. Staff chose to analyze a full range of 

scenarios in order to illustrate how the cap could be met under a variety of 

assumptions. The next sections describe the assumptions for each of the four 

scenarios.

1. Scenario 1: Full Complementary Policies, Full Offsets

Scenario 1 assumes that full abatement potential is available from all sectors and 

all complementary policies, and reflects an offset supply equal to the offset 

quantitative limit.

2. Scenario 2: Full Complementary Policies, Partial Offsets

Scenario 2 assumes full abatement from the complementary policies and a 

reduced availability of offsets. 

3. Scenario 3: Partial Complementary Policies, Full Offsets

In Scenario 3, staff explores a reduced abatement potential from the 

complementary policies and reflects and offset supply equal to the offset 

quantitative limit. 

4. Scenario 4: Partial Complementary Policies, Partial Offsets

In Scenario 4, staff explores reduced abatement potential from complementary 

policies, and assumes a limited supply of offset credits.
V-5

E. Development of Abatement Cost Curves

1. Introduction

Abatement cost curves, or supply curves, provide a means to graph the impacts 

and costs of numerous abatement strategies. In the context of this analysis, 

abatement refers to greenhouse gas emissions reductions. The cost of each 

strategy is measured in dollars per metric ton of CO2 equivalent (MTCO2e) 

reduced. In these figures, the x-axis represents the annual GHG abatement 

potential, and the y-axis represents the cost of the strategy in dollars per metric 

ton. Strategies are plotted in blocks, with the width of the block representing the 

maximum potential GHG reduction, and the height representing the average cost 

in dollars per MTCO2e reduced. Strategies are organized by cost from least to 

greatest, and plotted adjacent to one another. Thus, the abatement strategies 

are sorted to give an idea of how the cost of strategies compare to each other. 

An example of an abatement cost curve for GHG reductions is shown in Figure 

V-2 and described below.

Figure V-2: Example 2020 Abatement Curve

0 20 40 60 80 100

-100

-50

0

50

100

150

Cost [$/metric ton]

GHG Reduction [MMTCO2

e]

Strategy "X" ($19/metric ton)

Strategy "Y" ($94/metric ton)

$32/metric ton

.

Figure V-2 shows an example abatement curve for a set of hypothetical GHG 

abatement strategies. Some costs are negative, denoting that the strategy saves 

money annually—usually from a decreased fuel cost from the baseline case. 

Thus, the strategy will pay for itself over its lifetime. Positive costs show that the 

strategy does not save money annually, usually caused by a combination of high 
V-6

capital expenditures and low fuel reduction. These strategies will not pay for 

themselves over the life of the strategy in the absence of a cap-and-trade 

regulation.

Abatement curves are used to evaluate which abatement strategies might occur 

under a California cap-and-trade program. To use the curve to analyze a capand-trade scenario, a line is drawn at the amount of GHG reductions required. 

An example is shown in Figure V-2. In this illustration, achieving the 2020 cap 

would require approximately 70 MMTCO2e in reductions from the baseline case. 

This is illustrated by drawing a vertical line at a reduction of 70 MMTCO2e. At the 

intersection of the GHG reduction line and the cost curve, a horizontal line is 

drawn, estimating the marginal cost of GHG emissions reductions; that is, the 

cost to reduce one more metric ton of GHG emissions. In the example case, the 

marginal cost is $32/metric ton. The analysis assumes that all abatement 

strategies to the left of the curve will be implemented because those strategies 

are less expensive than the marginal price. Thus, strategy ”X,” which costs 

$19/metric ton, is assumed to be fully implemented. All abatement strategies to 

the right of the vertical line are considered more expensive than the marginal 

price, and there is no economic incentive to develop these strategies. Thus 

strategy ”Y,” which costs $94/metric ton, is assumed not to be implemented.

2. Abatement Cost Curve Calculations

The abatement potential and cost of each GHG reduction strategy is calculated 

in reference to the baseline case, and therefore are dependent upon 

assumptions about the baseline forecast. Reductions are calculated by taking 

the difference between the emissions from the alternative strategy and the 

baseline forecast. Similarly, the capital costs and operation and maintenance 

(O&M) costs of a new strategy must be calculated with respect to what is being 

replaced. In most cases, the unit being replaced is similar to the new unit (i.e., a 

high-efficiency boiler replacing a low-efficiency boiler), and the change in O&M 

cost is negligible.

Greenhouse gas abatement is calculated by a reduction in combustion of fuel 

that would otherwise have been burned, a reduction in process emissions, or a 

combination of the two. Most GHG abatement strategies that are analyzed 

reduce GHG emissions by reducing the amount of fuel burned. Examples of 

these fuel-reduction strategies are increasing the efficiency of boilers and 

process heaters, increasing insulation, and purchasing more-efficient vehicles. 

The calculation of GHG reductions from reductions in fuel use are shown in 

Equation V-1.
V-7

Equation V-1: Greenhouse Gas Reduction Potential Calculation of 

Abatement Strategies

GHGR = (FuelUseNewStrategy − FuelUseBAUStrategy)∗ n ∗ FI ,

where GHGR is the greenhouse gas reductions, FuelUseNewStrategy is the 

annual fuel use of the new unit, FuelUseBAUStrategy is the annual fuel use of 

the unit that was replaced, n is the number total number of units installed, and FI

is the fuel intensity of the fuel used, in MTCO2e per one million British thermal 

units (MMBTU).

Costs are calculated on an annual basis by summing annualized capital cost, 

O&M costs, and fuel savings and expenditures. Staff used discount rates to 

annualize the capital cost. The equation used to calculate the annualized capital 

cost is shown in Equation V-2:

Equation V-2: Annualized Capital Cost Equation

( ) 























+ −

= ×

t r

r AnnualizedCapitalCost CapitalCost

1

1 1

,

where r is the discount rate and t is the life of the capital in years. 

Two discount rates are used to develop the abatement curves. For strategies 

adopted by the general public (e.g., vehicles and energy efficiency), staff 

assumed a discount rate of 5 percent. Staff assumed a discount rate for industry 

of 30 percent; this higher rate reflects industries’ strategy to invest in abatement 

opportunities with shorter payback periods and under the constraint of limited 

availability of capital. The 30 percent discount rate for industry has been used in

a number of studies.

65,66,67,68

 

65 Wagger, David. Reducing CO2 Emissions from California’s Cement Sector. Washington D.C.: 

Center for Clean Air Policy. 2005

 The higher rate also ensures that additional costs 

are included that may not have been included in the capital cost, such as 

permitting costs. 

66 Bloomberg New Energy Finance. Carbon Markets – North America – Research Note. 2010

67 Sathaye, Jayant, et al. Bottom-up Representation of Industrial Energy Efficiency Technologies 

in Integrated Assessment Models for the Cement Sector. Lawrence Berkeley National Laboratory, 

Environmental Energy Technologies Division. 2010. 68 Xu, Tengfang, et al. Development of Bottom-up Representations of Industrial Energy Efficiency 

Technologies in Integrated Assessment Models for the Iron and Steel Sector. Lawrence Berkeley 

National Laboratory, Environmental Energy Technologies Division. 2010.
V-8

Costs on this study’s abatement cost curve are measured in dollars per metric 

ton. By calculating abatement on a per-metric-ton basis, the costs of many 

abatement opportunities can be directly compared. The calculation is shown in 

Equation V-3:

Equation V-3: Dollars-per-Metric-Ton Cost Calculation of Strategies

GHGR

TotalAnnualCostOfAltStrategy TotalAnnualCostOfBAUStrategy

MetricTon

Cost −  =



 



 $ ,

where TotalAnnualCostofAltStrategy is the sum of the annualized cost of the new 

unit, TotalAnnualCostofBAUStrategy is the sum of the annualized cost of the old 

unit, and GHGR is the total annual GHG reductions as calculated by Equation 

V-1. 

3. Abatement Strategies

A summary of the abatement options analyzed in this Chapter is shown in Table 

V-2. The abatement potential is split into five sectors: industrial, power, 

transportation, residential and commercial, and offsets. A summary of the 

sectors and strategies is included below. For more information on the reduction 

strategies, see Appendix F: Compliance Pathway Analysis. 
V-9

Table V-2: Abatement Option Summary

Sector Abatement Options Sources69

Industrial

Steam Efficiency U.S. Department of Energy

Process Heat Efficiency

Lawrence Berkeley 

National Laboratory

Fuel Mix case studies

Process Improvements local air districts

Power

Renewables

Energy and Environmental 

Economics, Inc. (E3)

Power Dispatch: Coal-to-Gas

Switching

Economic and Allocation 

Advisory Committee 

(EAAC)

Combined Heat and Power

Transportation

Light-Duty Vehicle Fuel Efficiency U.S. EPA VISION model

Biofuels

U.S. Energy Information 

Administration fuel 

economy estimates

Electrification ARB EMFAC model

Regional Transportation Targets

Residential and 

Commercial Energy

Energy Efficiency E3/Itron

Consumer Demand Response EAAC

Offsets

Methane Digesters

Climate Action Reserve & 

ARB estimates

Forestry

Ozone Depleting Substances

Abatement strategies available to the industrial sector include efficiency 

increases from steam systems and process heat systems, fuel changes, and 

process improvements. California industries analyzed were petroleum refining, 

oil and gas, food, wood products, chemicals, iron and steel, and cement. Staff 

relied on reports from the U.S. Department of Energy, Lawrence Berkeley 

National Laboratory, and local air districts, among others, to obtain estimates of 

industrial abatement potential.

Abatement strategies available to the power sector include increased renewable 

electricity, changes in power dispatch from coal power to gas power, and 

increased combined heat and power. Estimates of the abatement potential from 

these strategies were gathered from an Energy and Environmental Economics, 

Inc. (E3) report prepared for the California Public Utilities Commission.70

 

69 Specific references can be found in Appendix F: Compliance Pathways Analysis.

 The 

70 Energy and Environmental Economics, Inc. (2010): Greenhouse Gas Calculator for the 

California Electricity Sector. 

http://www.ethree.com/documents/GHG%203.11.10/GHG%20Calculator%20version%203b_Final

_to_Post_March2010.zip.
V-10

total abatement potential of renewable electricity was scaled to match the 

Renewable Electricity Standard (RES) that increases the proportion of electricity 

sales from renewables to 33 percent in 2020. For coal-to-natural gas dispatch 

changes, E3 provided a figure detailing the 2020 WECC dispatch under different 

allowance prices. Three 2020 allowance prices were chosen from this plot to 

represent the coal-to-gas switching: $50/metric ton, $80/metric ton, and 

$120/metric ton. These prices were chosen to be just above the consumer 

demand responses mentioned below.

Abatement from the transportation sector relied on ARB estimates from 

complementary measures, including the Low Carbon Fuel Standard (LCFS), 

Advanced Clean Car standards, Goods Movement, vehicle efficiency, Regional 

Targets, High Speed Rail, and Heavy- and Medium-Duty Hybridization and 

Aerodynamics. 

Abatement from the residential and commercial sector includes energy efficiency 

and consumer demand responses. Electricity and natural gas efficiency 

abatement potentials were based on the work done by E3 and Itron.71 Consumer 

demand responses are calculated from price elasticities of electricity and 

gasoline. That is, when the price of electricity and gasoline increase, consumers 

reduce demand for these goods. The consumer demand responses for 

electricity and gasoline are calculated for three allowance prices: $20/metric ton, 

$60/metric ton, and $100/metric ton. For each of these allowance prices, 

estimates are made about the increased price of electricity and gasoline. With 

the increase in prices, demand responses are calculated based on electricity and 

gasoline elasticities of -0.15 and -0.1, respectively.72,73

Offset protocols under consideration with this regulation include the U.S. Forest 

Projects Protocol, Urban Forest Projects Protocol, U.S. Ozone Depleting 

Substances Projects Protocol, and Livestock Manure (Digester) Projects Protocol. 

Abatement potentials of these reductions are based on ARB estimates. While 

ARB staff anticipates that additional offset protocols may be brought to the Board 

for approval in 2011 and beyond, no attempt was made in this analysis to 

consider the effect of additional offset supplies beyond the four protocols that are 

part of the current rulemaking. 

 

71 Rufo, Michael W., and Alan S. North. Assessment of Long-Term Electric Energy Efficiency 

Potential in California’s Residential Sector. California Energy Commission, PIER Energy-Related 

Environmental Research. CEC-500-2007-002.

72 Hughes, Jonathan E., Christopher R. Knittel, and Daniel Sperling. 2006. Evidence of a Shift in 

the Short-Run Price Elasticity of Gasoline Demand. 73 Bernstein, M. A., and J. Griffin. 2005. Regional differences in the price elasticity of demand for 

energy. RAND Corporation.
V-11

4. Abatement Curve Results

Three master abatement cost curves were constructed. The first curve includes 

all the potential abatement strategies that would be available to capped sectors, 

including those that would be used to meet complementary measure 

requirements. The second curve includes abatement strategies that would be 

driven by the cap-and-trade program price signal, but excludes abatement 

strategies required by other measures (e.g., LCFS, Advanced Clean Cars, 

Regional Targets, RES). The last abatement curve is a further subset of the 

abatement potential driven by the price signal, and it only includes industry 

abatement opportunities. 

In each curve, two methods are used to differentiate strategies. For strategies 

that have a sufficiently large abatement potential, the name of the strategy is 

plotted over the strategy. By only placing a title on these large strategies, the 

curves are more legible and titles are not placed over one another. The other 

method of differentiating strategies is through color. In each curve, there is a 

legend of the colors used to describe the types of abatement opportunities

a. Total Capped Sector Abatement Potential

The Total Capped Sector Abatement Potential shown in Figure V-3 represents 

abatement strategies that are available to the capped sectors in 2020, including 

offsets, renewable energy, vehicle efficiency, and biofuels. The baseline forecast 

for capped sectors is 408.8 MMTCO2e in 2020, so the capped sector must 

achieve reductions of at least 74.6 MMTCO2e in 2020 to achieve the AB 32

target. 
V-12

Figure V-3: Total Capped Sector Abatement Potential in 2020

0 20 40 60 80 100 120

-100

-50

0

50

100

150

200

Cost [$/metric ton]

GHG Reduction [MMTCO2

e]

Regional Trans TargetsBiofuelsVehicle EfficiencyRes & Com EE Low GoalLow Res/Commercial Nat Gas Eff

Forestry Offsets Low Cost

ODS Offsets Low Cost

Res & Com EE Mid Goal

Forestry Offsets High CostElectricity Demand Low Gasoline Demand Low

Methane Digesters High Cost

Res & Com EE High Goal Power Dispatch: Coal to Gas Electricity Demand Mid Gasoline Demand Mid

Power Dispatch: Coal to Gas Biogas Electricity Demand High Gasoline Demand High Geothermal

Export CHP Wind Power Dispatch: Coal to Gas Onsite CHP

Solar Thermal

Offsets

Residential and Commercial

Industry

Power

Transportation

The total capped sector abatement curve shows approximately 108 MMTCO2e of 

abatement available in 2020, with over 32 MMTCO2e of that abatement having a 

negative cost per metric ton. The least expensive abatement opportunities are 

from the transportation sector. These include regional transportation targets 

(SB 375), biofuels, and high-efficiency vehicles.

Approximately 76 MMTCO2e of abatement potential is available at a positive 

cost-per-metric-ton. Offsets are available in the mid-range cost per metric ton 

($10–$30/metric ton), with a total abatement potential of 30 MMTCO2e. The 

residential and commercial sector has a wide range of abatement prices 

(-$10/metric ton to $100/metric ton). The power sector has the highest-priced 

abatement opportunities, with most greater than $80/metric ton.

b. Abatement Potential Driven by the Price Signal

The abatement potential driven by the price signal is shown in Figure V-4. This 

curve is a subset of the strategies plotted in the total capped sector abatement 

potential in Figure V-3. The abatement in Figure V-4 does not include reductions 

that are expected to take place due to complementary measures (e.g., LCFS, 

Advanced Clean Cars, RES, Regional Transportation Targets). The abatement 

potential driven by the price signal includes energy efficiency, even though 

energy efficiency is one of the complementary measures. It is included because 
V-13

additional energy efficiency can be driven by the cap-and-trade program price 

signal. E3 assumes three energy-efficiency scenarios based on a 2007 CEC 

report74

According to

and ranging in cost from -$10 to $50/metric ton. High-cost energy 

efficiency becomes incentivized as energy prices increase due to price signal.

Figure V-4, approximately 72 MMTCO2e of abatement is available 

from capped sectors and offsets. Of this potential, 9 MMTCO2e of abatement 

has a negative cost-per-metric-ton. Most of the available abatement potential is 

from consumers. Even at a low costs, consumers respond with increased

electricity efficiency. At higher costs, consumers respond with greater 

conservation of electricity and gasoline. A significant portion of offsets are 

available at medium prices ($10–$30/metric ton). Allowance price is shown to 

promote the creation of additional offsets, and increased allowance prices bring 

additional forestry, ODS, and methane digester offsets. At prices greater than 

$50/metric ton, it becomes cost-effective to dispatch power from natural gas 

power plants over coal power plants. Increasing the price further promotes 

additional dispatch switching to natural gas.

The abatement potential driven by the price signal is the primary tool used in the 

analyses of the compliance pathway scenarios. As mentioned, this curve only 

shows abatement strategies that are driven by a price signal, thus a given 

number of reductions can be used to determine the allowance price. With a 

given allowance price, staff can use the curve to analyze what strategies may or 

may not take place to describe the compliance pathways.

 

74 Rufo, Michael W., and Alan S. North. Assessment of Long-Term Electric Energy Efficiency 

Potential in California’s Residential Sector. California Energy Commission, PIER Energy-Related 

Environmental Research. CEC-500-2007-002.
V-14

Figure V-4: Abatement Potential Driven by the Price Signal in 2020

0 20 40 60 80 -100

-50

0

50

100

150

200

Cost [$/metric ton]

GHG Reduction [MMTCO2e]

SCM Blending Low Res/Commercial Nat Gas EffRes & Com EE Low Goal

Forestry Offsets Low CostMethane Digesters Low Cost

ODS Offsets Low Cost

Med Res/Commercial Nat Gas Eff Res & Com EE Mid Goal

Forestry Offsets High CostElectricity Demand Low Gasoline Demand Low ODS Offsets High Cost

Methane Digesters High Cost

Cement: Alternative Fuels High Res/Commercial Nat Gas Eff Res & Com EE High Goal Power Dispatch: Coal to Gas Electricity Demand Mid

Gasoline Demand Mid

Power Dispatch: Coal to Gas

Electricity Demand HighGasoline Demand High

Export CHP

Power Dispatch: Coal to Gas

Onsite CHP

Offsets

Residential and Commercial

Industry

Power

Transportation

c. Industry-Only Abatement Reductions

Reductions from the industry section are shown in Figure V-5. A total of 

5.5 MMTCO2e in reductions were identified for the industrial sector. The lowest 

cost reductions are boiler and process heater optimization. This is usually 

accomplished by trimming excess air in the units. Most optimization strategies 

have a significant negative cost, saving more than $100/metric ton; however, 

additional reductions can be attained at a cost of -$10/metric ton to $20/metric 

ton.

Maintenance strategies include steam leak and steam trap maintenance. 

Increasing maintenance has the largest potential to reduce GHG in the industrial 

sector. Most of these opportunities are available at negative costs, ranging from 

-$100/metric ton to -$40/metric ton. Additional maintenance for boilers and 

process heaters generates emissions reductions.

Staff looked at heat recovery techniques such as flue-gas heat recovery for 

process heaters, boiler economizers, and boiler blowdown heat recovery. This 

analysis found a small amount of abatement potential from heat recovery at a 
V-15

negative cost. However, the cost of most abatement from heat recovery ranged 

between $10/metric ton and $100/metric ton. 

Blending of semi-cementitious material (SCM) with cement to produce concrete 

has a large potential to reduce GHG emissions at a savings (-$17/metric ton). 

Semi-cementitious materials are a by-product of coal-fired power plants and 

other industrial facilities. Blending SCMs with cement results in more concrete 

per unit of cement, so that the emission intensity of the use of cement is 

decreased. 

Figure V-5: Industry-Only Abatement Potential in 2020

0 1 2 3 4 5 6 -100

-50

0

50

100

150

200

Cost [$/metric ton]

GHG Reduction [MMTCO2

e]

Oil&Gas Steam Trap Maint.-Cat1Refinery Steam Trap Maint.-Cat1Refinery Optimize Process Heater-Cat1Oil&Gas Steam Trap Maint.-Cat2Refinery Steam Trap Maint.-Cat2Refinery Boiler Insulation Maint.-Cat1Refinery PH Insulation Maint.-Cat1Oil&Gas Boiler Insulation Maint.-Cat1SCM Blending

Cement Efficiency

Oil&Gas Replace Boiler-Cat1

Refinery Replace Process Heater-Cat1

Cement: Alternative Fuels

Refinery Replace Boiler-Cat1

Refinery Replace Boiler-Cat2

Oil&Gas Replace Boiler-Cat2Refinery Replace Process Heater-Cat2

Boiler/Process Heater Efficiency

Boiler/Process Heater Replacement

Cement

Maintenance

Heat Recovery

An additional 2.58 MMTCO2e have a positive cost per metric ton, and thus, 

would likely not be implemented unless there was a price signal on GHG 

emissions. The largest abatement opportunities at positive costs per metric ton 

are boiler and process heater replacement. Depending on the efficiency of the 

unit being replaced, a range of costs vary between $20/metric ton and 

$200/metric ton. In the positive cost per metric ton, additional heat recovery 

strategies are also available. Alternative fuels for cement can achieve significant 

reductions at $36/metric ton.
V-16

F. Compliance Pathways Analysis 

The proposed cap-and-trade program does not specify what combination of GHG 

abatement strategies regulated parties must implement. Instead, the program 

establishes an overall cap on GHG emissions and allows covered entities to use 

any combination of GHG abatement strategies, including those not covered in 

this Chapter, to achieve the cap. Based on the abatement strategies described 

above, ARB staff has analyzed four scenarios with different compliance 

pathways for achieving the necessary reductions.

The abatement strategies that sources will implement in the future cannot be 

predicted. Technologies that currently appear most likely to reduce emissions in 

the near- to mid-term could encounter delays, and development of other 

technologies could achieve breakthroughs. Also, since the proposed regulation 

is market based, regulated entities make decisions on energy efficiency using inhouse analyses. Thus, the path taken to achieve the may be different from the 

pathways described below.

1. Results of Scenario 1: Full Abatement Potential from Complementary 

Policies, Full Availability of Offsets

In this scenario, full abatement potential is available from complementary policies 

and offsets. As discussed above, 74.6 MMTCO2e in reductions from projected 

baseline emissions are needed to meet the cap in 2020. Table V-3 identifies the 

reductions assumed in this scenario from complementary measures that will 

reduce emissions under the cap. The cap-and-trade program price signal is 

required to achieve the remaining reductions of 31.3 MMTCO2e.

Table V-3: Scenario 1 Abatement Estimates (in MMTCO2e) in 2020 

Abatement Needed (Table V-1) 74.6

Advanced Clean Cars Standards 3.8

LCFS 15.1

Regional Targets 3.0

RES 11.4

Vehicle Efficiency 4.6

Goods Movement 3.5

Med-/Heavy-Duty Hybridization and Aerodynamics 0.9

High Speed Rail 1.0

Total Abatement from Complementary Policies 43.3

Abatement from Capped Sectors Driven by the Price 

Signal 31.375

 

75 Numbers may not add due to rounding. 
V-17

The abatement curve driven by the price signal corresponding to Scenario 1 is 

shown in Figure V-6. As shown in the figure, 31 MMTCO2e of abatement 

corresponds to an allowance price of $20/metric ton. Thus, if all measures less 

than $20/metric ton are implemented, the emissions will stay below the cap. 

These measures include a number of low-cost industrial abatement strategies, 

such as optimization of boilers and process heaters, steam maintenance, and 

SCM blending. The residential and commercial sector will respond by 

implementing a large amount of residential and commercial efficiency. 

Approximately 16 MMTCO2e of offsets will be used to comply with the cap-andtrade regulation. All of the low-cost offsets will be used for compliance, and only 

a portion of the high-cost forestry projects will be implemented.

Figure V-6: Abatement Curve for Scenario 1 in 2020

0 20 40 60 80 -100

-50

0

50

100

150

200

Cost [$/metric ton]

GHG Reduction [MMTCO2e]

SCM Blending Low Res/Commercial Nat Gas EffRes & Com EE Low Goal

Forestry Offsets Low CostMethane Digesters Low Cost

ODS Offsets Low Cost

Med Res/Commercial Nat Gas Eff Res & Com EE Mid Goal

Forestry Offsets High CostElectricity Demand Low Gasoline Demand Low ODS Offsets High Cost

Methane Digesters High Cost

Cement: Alternative Fuels High Res/Commercial Nat Gas Eff Res & Com EE High Goal Power Dispatch: Coal to Gas Electricity Demand Mid

Gasoline Demand Mid

Power Dispatch: Coal to Gas

Electricity Demand HighGasoline Demand High

Export CHP

Power Dispatch: Coal to Gas

Onsite CHP

Offsets

Residential and Commercial

Industry

Power

Transportation

31 MMTCO2e

$20/ton

2. Results of Scenario 2: Full Abatement Potential from Complementary 

Policies, Partial Availability of Offsets

In this scenario, the offsets potential is reduced by half. Table V-4 identifies the 

reductions assumed in the scenario from the complementary measures that will 

reduce emissions under the cap. Similar to Scenario 1, the complementary 

measures achieve 43.3 MMTCO2e of reductions, requiring the allowance price to 

drive an additional 31.3 MMTCO2e of reductions. 
V-18

Table V-4: Scenario 2 Abatement Estimates (in MMTCO2e) in 2020

Abatement Needed (Table V-1) 74.6

Advanced Clean Cars Standards 3.8

LCFS 15.1

Regional Targets 3.0

RES 11.4

Vehicle Efficiency 4.6

Goods Movement 3.5

Med-/Heavy-Duty Hybridization and Aerodynamics 0.9

High Speed Rail 1.0

Total Abatement from Complementary Policies 43.3

Abatement from Capped Sectors Driven by the Price 

Signal 31.376

The abatement curve driven by the price signal corresponding to Scenario 2 is 

shown in Figure V-7. As shown in Figure V-7, 31 MMTCO2e of abatement 

corresponds to an allowance price of approximately $40/metric ton. Thus, all 

measures less than $40/metric ton are expected to be implemented. The 

increased price results from the limited offset potential in this scenario. In this 

scenario, all of the 15.1 MMTCO2e of available offsets potential are used to meet 

the cap, and there is an increased use of energy efficiency and demand-side 

reductions. 

 

76 Numbers may not add due to rounding. 
V-19

Figure V-7: Abatement Curve for Scenario 2 in 2020

0 10 20 30 40 50 60 -100

-50

0

50

100

150

200

Cost [$/metric ton]

GHG Reduction [MMTCO2e]

SCM Blending Low Res/Commercial Nat Gas EffRes & Com EE Low Goal

Forestry Offsets Low Cost

ODS Offsets Low CostMed Res/Commercial Nat Gas EffRes & Com EE Mid Goal

Forestry Offsets High CostElectricity Demand Low Gasoline Demand Low

Methane Digesters High Cost

Cement: Alternative Fuels High Res/Commercial Nat Gas Eff

Res & Com EE High GoalPower Dispatch: Coal to Gas

Electricity Demand MidGasoline Demand Mid

Power Dispatch: Coal to Gas

Electricity Demand HighGasoline Demand High

Export CHP

Power Dispatch: Coal to Gas

Onsite CHP

$40/ton

31 MMTCO2

e

Offsets

Residential and Commercial

Industry

Power

Transportation

The results from this scenario show the importance of the offset program to 

mitigate prices. This curve can be compared to Scenario 1, which uses the same 

assumptions for the complementary measures but assumed ample offset supply. 

In comparing the curves, decreasing the offset potential by half increases the 

allowance price from $20/metric ton to $40/metric ton.

3. Results of Scenario 3: Partial Abatement Potential from 

Complementary Policies, Full Availability of Offsets

In this scenario, staff explores the complementary policies. Table V-5 identifies 

the reductions assumed in this scenario from complementary measures that will 

reduce emissions under the cap. Staff assumed 15 MMTCO2e less than the 43.3 

MMTCO2e GHG reductions originally estimated from the complementary policies 

in Scenarios 1 and 2. In Scenario 3, 46.3 MMTCO2e of additional reductions are 

needed from the capped sectors based on the price signal.
V-20

Table V-5: Scenario 3 Abatement Estimates (in MMTCO2e) in 2020

Abatement Needed (Table V-1) 74.6

Abatement From Complementary Policies 28.3

Abatement from Capped Sectors Driven by the Price 

Signal 46.377

The abatement curve driven by the price signal corresponding to Scenario 3 is 

shown in Figure V-8. As shown in the figure, 46 MMTCO2e of abatement 

corresponds to an allowance price of approximately $40/metric ton. Thus, all 

measures less than $40/metric ton are expected to be implemented. The 

medium-level allowance price spurs some demand-side changes from 

consumers and brings additional offsets online. In this curve, all of the 

approximately 30 MMTCO2e of available offsets were used to meet the cap. In 

the range of $10/metric ton to $30/metric ton, the curve has a low slope, meaning 

that the marginal allowance price is slowly increasing. Thus, from the price of 

$10 to $30/metric ton, capped sectors can increase abatement with relatively 

little price fluctuation. 

 

77 Numbers may not add due to rounding. 
V-21

Figure V-8: Abatement Curve for Scenario 3 in 2020

0 20 40 60 80 -100

-50

0

50

100

150

200

Cost [$/metric ton]

GHG Reduction [MMTCO2e]

SCM Blending Low Res/Commercial Nat Gas EffRes & Com EE Low Goal

Forestry Offsets Low CostMethane Digesters Low Cost

ODS Offsets Low Cost

Med Res/Commercial Nat Gas Eff Res & Com EE Mid Goal

Forestry Offsets High CostElectricity Demand Low Gasoline Demand Low ODS Offsets High Cost

Methane Digesters High Cost

Cement: Alternative Fuels High Res/Commercial Nat Gas Eff Res & Com EE High Goal Power Dispatch: Coal to Gas Electricity Demand Mid

Gasoline Demand Mid

Power Dispatch: Coal to Gas

Electricity Demand HighGasoline Demand High

Export CHP

Power Dispatch: Coal to Gas

Onsite CHP

46 MMTCO2

e

Offsets

Residential and Commercial

Industry

Power

Transportation

$40/ton

4. Scenario 4: Partial Abatement from Complementary policies, Partial 

Availability of Offsets

In Scenario 4, staff explores a limited abatement potential from the 

complementary policies and limited availability of offsets. As shown in Table V-6, 

46 MMTCO2e of allowance price-driven abatements are needed from capped

sectors. 

Table V-6: Scenario 4 Abatement Estimates (in MMTCO2e) in 2020

Abatement Needed (Table V-1) 74.6

Abatement From Complementary Policies 28.3

Abatement from Capped Sectors Driven by the Price 

Signal 46.378

 

78 Numbers may not add due to rounding. 
V-22

The abatement curve corresponding to Scenario 4 is shown in Figure V-9. As 

shown, 46 MMTCO2e of abatement corresponds to an allowance price of 

$100/metric ton. Thus, all measures less than $100/metric ton are expected to 

be implemented. To achieve the 46 MMTCO2e with limited offsets, high prices 

were necessary to achieve the abatement from the capped sectors. Many of the 

reductions were from consumers. A large amount of energy efficiency and 

demand-side reductions occurred to meet the necessary reductions. In addition, 

the significant power dispatch switching occurred. In this scenario, all of the 15 

MMTCO2e of available offsets were used.

Figure V-9: Abatement Curve for Scenario 4 in 2020

0 10 20 30 40 50 60 -100

-50

0

50

100

150

200

Cost [$/metric ton]

GHG Reduction [MMTCO2e]

SCM Blending Low Res/Commercial Nat Gas EffRes & Com EE Low Goal

Forestry Offsets Low Cost

ODS Offsets Low CostMed Res/Commercial Nat Gas EffRes & Com EE Mid Goal

Forestry Offsets High CostElectricity Demand Low Gasoline Demand Low

Methane Digesters High Cost

Cement: Alternative Fuels

Res & Com EE High GoalPower Dispatch: Coal to Gas

Electricity Demand MidGasoline Demand Mid

Power Dispatch: Coal to Gas

Electricity Demand High

Gasoline Demand High

Export CHP

Power Dispatch: Coal to Gas

Onsite CHP

46 MMTCO2e

Offsets

Residential and Commercial

Industry

Power

Transportation

The results from this scenario show the importance of complementary policies 

and offsets supply to obtaining the necessary GHG reductions to achieve the cap. 

The results of Scenario 2 (full complementary policies, partial offsets) and 

Scenario 3 (partial complementary policies, full offsets) show only modest price 

increases from Scenario 1 (full complementary policies, full offsets). However, in 

Scenario 4, large price increases occur due to the limited availability of 

reductions from complementary policies and offsets. This price increase is 

caused by requiring many of the reductions to come from consumers.

Even though the results of this scenario show an allowance price of $100/metric 

ton, achievement of this price is unlikely because of the cost containment 
V-23

mechanism that makes allowances available at lower prices. For more 

information on cost containment, see Chapter II: General Summary of the 

Proposed Regulation.

5. Conclusion

The proposed cap-and-trade program provides a flexible market-based tool that 

can achieve the AB 32 goals under a number of different scenarios. Scenario 1, 

in which the complementary measures achieve expected reductions and there is 

a full supply of offsets, requires an allowance price of $20/metric ton to achieve 

the necessary reductions. Scenario 1 is considered to be the most likely 

scenario.

Scenario 2 shows the importance of offsets in mitigating high allowance price. In 

this case, the complementary measures reach their full potential but the offset 

potential is reduced by half, and the allowance price increases to $40/metric ton 

due to the reduced availability of offsets.

Scenario 3 shows the flexibility of the cap-and-trade program to meet the AB 32 

goals. By reducing the abatement potential from the complementary measures, 

but assuming a full availability of offsets, this scenario illustrates that abatement 

can be met through additional purchase of offsets and additional consumer and 

industry responses. In Scenario 3, the allowance price is $40/metric ton. 

Scenario 4 shows the worst case and least likely scenario, in which neither 

offsets nor complementary measures reach their full potential. In this case, 

allowance price increases to $100/metric ton, and the program relies on 

consumers and industry to make the necessary reductions. Nonetheless, 

demand response and a high level of energy efficiency can provide sufficient 

emissions reductions to meet the cap. It should be noted that it is highly unlikely 

that allowance prices will reach $100/metric ton because regulation includes a 

number of cost-containment mechanisms.
VI-1

VI ENVIRONMENTAL IMPACTS OF THE PROPOSED 

REGULATION

This Chapter summarizes the environmental impacts analysis and identifies 

potential environmental benefits associated with the proposed cap-and-trade 

program. Complementing other AB 32 Scoping Plan measures, the proposed 

cap-and-trade program provides market-based incentives to reduce GHG 

emissions in California consistent with the requirements of AB 32, including HSC 

§38562, §38570, and §38571. The analysis shows that the proposed cap-andtrade program will reduce GHG emissions throughout the state. It will provide 

facility owners more flexibility to determine the most cost-effective way to meet 

emission reduction targets than a command-and-control approach with 

prescribed control measures would allow. 

The California Environmental Quality Act (CEQA) and ARB policy require an 

analysis to determine the potential environmental impacts of the proposed 

regulation. ARB’s program for adopting regulations has been designated as a 

Certified State Regulatory Program by the Secretary of Resources pursuant to 

Public Resources Code (PRC) section 21080.5. Consequently, the analysis 

required under CEQA may be included in the Initial Statement of Reasons (ISOR 

or Staff Report) rather than adhering to the format described in CEQA for an 

Initial Study, a Negative Declaration, or an Environmental Impact Report. 

ARB has prepared a programmatic Functionally Equivalent Document (FED) that 

addresses direct and indirect impacts and identifies feasible mitigation that could 

be used to reduce significant adverse effects on the environment. This 

document is included in Appendix O, and is summarized in this Chapter. Staff’s 

environmental analysis anticipates a variety of compliance responses that 

covered entities may use to comply with the program, such as increased energy 

efficiency, decarbonization of fuel, process changes, as well as surrender of 

allowances. These responses will not only help reduce GHG emissions, but are 

also anticipated to provide multiple environmental co-benefits that can provide 

relief from the demand on the State’s already stressed water, air and mineral 

resources. A summary of the analysis of the potential environmental impacts 

and mitigation associated with covered entities’ compliance responses follows. 

The Board is also considering approval of four offset protocols. Each of these 

protocols is analyzed individually. The FED also includes a cumulative impact 

section that examines impacts associated with the cap-and-trade program, in its 

entirety (including the protocols), and the remaining suite of Scoping Plan 

measures. Staff will respond to all significant environmental issues raised by the 

public during the 45-day public review period or at the Board hearing in the Final 

Statement of Reasons for the proposed regulation. 
VI-2

A. Summary of Environmental Analysis

1. Analyses of Emissions Reductions

The environmental analysis of the proposed cap-and-trade program focuses on 

the activities that those covered by the program could take to reduce GHG 

emissions. The purpose of the cap-and-trade program is to reduce GHG 

emissions from sources subject to the regulation (i.e., covered entities). This is 

achieved by applying an aggregate total GHG emissions cap on covered entities

that declines over time. The program provides a trading mechanism for 

compliance instruments that offers covered entities flexibility in how they comply 

with the regulation. Reductions in GHG emissions would result from the use of 

cleaner fuels and from investment in onsite efficiency and process improvements. 

Additional reductions would come from offset projects that reduce emissions not 

directly covered by the cap-and-trade program or increase sequestration of 

carbon. Covered entities must turn in “allowances” and offset credits equal to 

their emissions. They may choose to lower their emissions to reduce their 

compliance obligation or procure allowances and/or offsets. The environmental 

analysis is based on the variety of covered entities’ expected compliance 

responses and their respective impacts on the physical environment.

Total GHG emissions under baseline conditions in 2020 are estimated to be 507 

MMTCO2e. GHG emissions from the capped sectors are approximately 409 

MMTCO2e of the baseline. Reductions needed to meet the cap of 334 

MMTCO2e will come in part through complementary measures from the Scoping 

Plan. After reductions from those measures, the cap-and-trade regulation is 

estimated to reduce at least 18 MMTCO2e, representing a 4 percent reduction 

from capped sector emissions. The reductions needed from cap-and-trade could 

be greater if adopted measures fail to achieve expected reductions, if energy 

efficiency programs are not funded at adequate levels or are less effective than 

projected, or if the economy grows faster than expected. 

The cap-and-trade program is made up of many elements, must serve a large 

number of important objectives at the same time, and relies on the cumulative 

actions of a large number of participants operating in a complex market system. 

Accordingly, unanticipated effects and results could occur over the life of the 

program. ARB therefore is committed to using an adaptive management process 

to review and revise policies, protocols, and procedures as more information 

becomes available. This approach is discussed further in Appendix O.

2. Impacted Communities

ARB is committed to making the achievement of fair treatment of people of all 

races, cultures, and incomes with respect to the development, adoption, 

implementation and enforcement of environmental laws, regulations, and policies. 

This commitment is an integral part of development and implementation of the 

proposed cap-and-trade program. As such, staff evaluated the proposed 

regulation to determine if it disproportionately affects local communities, or 
VI-3

interferes with the attainment and maintenance of ambient air quality standards. 

As part of the Co-Pollutant Emissions Assessment of the cap-and-trade 

regulation, ARB staff evaluated the potential emissions impact of the regulation 

on four cumulatively impacted communities in California. The choice of 

communities captures the diverse nature of California’s air quality problems, as 

well as a range of sources that would be subject to the regulation. The analysis 

found that the cap-and-trade program is unlikely to significantly impact on 

emissions in the four communities and is more likely to have a positive effect. 

The analysis is summarized in Chapter VII and Appendix P.

Also included in the environmental analysis is an examination of potential 

impacts to aesthetic resources, biological resources, cultural resources, energy 

demand, geological resources, land use, water quality and demand, among 

others. Possible approaches to mitigate or minimize these effects are included in 

the analysis.

B. Cap-and-Trade Program – Project Alternatives

Staff evaluated a suite of alternatives to the proposed regulation as required by 

the CEQA guidelines. A range of alternatives analyzed in an environmental 

document is governed by the “rule of reason,” requiring evaluation of those 

alternatives “necessary to permit a reasoned choice.” (CEQA Guidelines section 

15126(f)). The alternatives include the required “No Project Alternative”, as well 

as program design options, a regulation-only approach, a carbon fee, and others. 

C. Statewide GHG Benefits from Cap-and-Trade

This section discusses staff’s evaluation of the statewide GHG emission 

reduction estimates from the proposed cap-and-trade program.

The amount of GHG emissions that would have to be reduced by the cap-andtrade program is a function of the 2020 business-as-usual (BAU) and the 

effectiveness of other Scoping Plan measures. Since adoption of the Scoping 

Plan, ARB has updated its emission inventories, revising the statewide 2020 

emissions estimate to 507 MMTCO2e. Scoping Plan measures that are adopted 

or would be adopted in the reasonably foreseeable future would achieve 

approximately 62 MMTCO2e of reductions. The cap-and-trade program must 

reduce at least 18 MMTCO2e to reach the 2020 target. The needed reductions 

could be greater if adopted measures fail to achieve expected reductions, if 

energy efficiency programs are not funded at adequate levels or are less 

effective than projected, or if the economy grows faster than expected. This is 

considered a beneficial impact.

GHG Emission Reduction Estimates
VI-4

D. Air Quality Impacts

This section discusses the potential air quality impacts related to the cap-andtrade program. Below are descriptions of the pollutants of interest in this chapter.

• Criteria Air Pollutants

•

: Criteria air pollutants are determined to be 

hazardous to human health and are regulated under U.S. EPA’s National 

Ambient Air Quality Standards. The 1970 amendments to the Clean Air 

Act require U.S. EPA to describe the health and welfare impacts of a 

pollutant as the “criteria” for inclusion in the regulatory regime. Both the 

California and federal governments have adopted health-based standards 

for the criteria pollutants that include ozone, particulate matter (10 microns 

or less in diameter, PM10 and 2.5 micron or less in diameter, PM2.5), 

carbon monoxide (CO), nitrogen dioxide (NO2), and sulfur dioxide (SO2). 

Toxic Air Contaminants

ARB evaluated the potential statewide and localized emission impacts resulting 

from the changes in criteria pollutant and toxic air contaminant emissions that 

accompany implementing the proposed cap-and-trade program. The localized 

emission assessment is presented in Chapter VII and Appendix P: Co-Pollutant 

Emissions Assessment, and indicates that the proposed cap-and-trade program 

is expected to provide an emissions benefit by reducing emissions of criteria and 

toxic air pollutants. Because GHG emissions are largely the result of combustion, 

the declining cap will result in reduced combustion and related air pollution 

emissions. The estimated statewide emission reductions of criteria pollutants are 

shown in Table VI-1 below.

: Toxic air contaminants (TAC or toxics) are those 

pollutants which may cause or contribute to an increase in mortality or 

serious illness, or which may pose a hazard to human health even at very 

low concentrations.

Table VII-1: Potential Statewide Reductions from the Proposed Cap-andTrade Regulation in 2020* 

(TPD)

ROG CO NOx PM2.5

22.4 210.4 50.8 3.4

*Assumes implementation of adopted and foreseeable Scoping Plan measures in 2020 

and that combustion emissions from capped sources decrease by 4 percent to meet 

the 2020 cap. The 4 percent reduction is estimated as follows. Total GHG emissions 

under baseline conditions in 2020 are estimated to be 507 MMTCO2e. GHG 

emissions from the capped sectors are approximately 409 MMTCO2e of the baseline. 

Reductions needed to meet the cap of 334 MMTCO2e will come in part through 

complementary measures from the Scoping Plan. After reductions from those 

measures, the cap-and-trade regulation is estimated to reduce at least 18 MMTCO2e, 

representing a 4 percent reduction from capped sector emissions.
VI-5

An advantage of the cap-and-trade approach to achieving GHG emission 

reduction goals is that it gives facility owners more flexibility to determine the 

most cost-effective way to meet emission reduction targets than a command and 

control approach with prescribed control measures would allow. This flexibility to 

covered entities can help reduce the overall cost of meeting California’s GHG 

emission reduction goals. This flexibility also means that there are no facilityspecific emission reduction requirements for GHG emitting facilities. Because of 

this, some commenters have expressed concern that the cap-and-trade program 

could lead to disproportionate emission impacts. ARB’s analysis, as detailed in 

the Co-Pollutant Emissions Assessment in Chapter VII and Appendix P: CoPollutant Emissions Assessment indicates that is unlikely. California’s 

comprehensive control program will continue to reduce emissions and improve 

air quality. The cap-and-trade program is likely to provide small additional criteria 

pollutant reductions statewide. Although ARB’s analysis indicates that localized 

impacts are unlikely, there is a chance that small increases that would be 

considered potentially significant under CEQA could occur. ARB proposes an 

adaptive management approach to address this potential impact.

Short-term increases in construction and operational emissions resulting from 

covered entity compliance responses are identified as significant and 

unavoidable in the FED, but could be evaluated by agencies with local permitting 

authority at the time specific projects are proposed and potentially mitigated to 

less than significant.

The proposed livestock offset protocol could result in a significant unavoidable 

impact resulting from the generation of odors that could affect sensitive receptors. 

Other than this potential odor impact, offset protocols would not be expected to 

result in potentially significant project-level impacts, or contribute to a cumulative,

adverse air quality impact. New offset projects may be subject to local 

permitting processes and, if not exempt, environmental review under CEQA.

E. Other Environmental Impacts

1. Overview

The environmental analysis included in this Staff Report as Appendix O is a 

Functional Equivalent Document (FED), and complies with CEQA. It presents a 

programmatic evaluation that describes potential environmental impacts that are 

reasonably foreseeable, and does not speculate as to all of the possible 

compliance responses that could occur at the site- or project-specific levels. The 

compliance responses evaluated are representative of an entire business sector. 

Although compliance with existing federal and state statutes and regulations, and 

local ordinances and permitting requirements may be adequate to address 

potential adverse project-specific environmental impacts, agencies with local 

permitting authority would be responsible for determining project-level impacts 

and mitigation. Because the programmatic analysis does not allow description of 

the details of project-specific mitigation, the degree of mitigation ultimately 
VI-6

implemented to reduce the potentially significant impacts is inherently uncertain. 

Consequently, the FED takes the conservative approach in its post-mitigation 

significance conclusions (i.e., tending to overstate the risk that feasible mitigation 

may not be sufficient or may not be implemented by other parties) and discloses, 

for CEQA compliance purposes, that potentially significant environmental 

impacts may be unavoidable. It is expected that many impacts resulting from 

covered entity compliance responses and offset projects would be avoided or 

mitigated to a less-than-significant level, and many potentially significant impacts 

would be addressed during project-specific environmental review processes.

2. Impact Analysis

This section evaluates potential impacts that could result from implementation of

the covered entity compliance responses. The reasonably foreseeable covered 

entity compliance responses are some combination of (1) Upgrade Equipment, 

(2) Decarbonization, (3) Implement Process Changes, and (4) Surrender 

Compliance Instruments, and implementation of offset projects under the 

Compliance Offset Protocol for U.S. Ozone Depleting Substances Projects, 

Compliance Offset Protocol for Livestock Manure (Digesters) Projects, 

Compliance Offset Protocol for Urban Forest Projects, and the Compliance 

Offset Protocol for U.S. Forest Projects.

a. Aesthetics

Implementation of the cap-and-trade program would not result in actions that 

would pose a significant adverse impact to aesthetic, scenic, or visual resources. 

The compliance responses implemented by covered entities largely consist of 

onsite improvements to existing facilities located in industrial settings, and as 

such would not change the character of the project sites.

The ODS offset protocol would not introduce activities that would disrupt 

aesthetic or visual settings. The Livestock offset protocol would include the 

construction of digesters in agricultural settings. Digesters are consistent with 

agricultural uses and would not represent an adverse change to the visual 

character of the vicinity. The Urban Forest offset protocol would improve the 

quality of the urban visual environment and would be considered aesthetically 

beneficial. The Forest offset protocol would not increase the amount of forest 

activities, but could shift activities to projects that increase carbon sequestration. 

This shift could change the visual character of offset project sites over time, but 

would not pose an adverse visual impact. Managing forests to increase cover 

and remove dead and diseased trees may be considered a visually beneficial 

effect.

b. Agriculture and Forest Resources

Implementation of the cap-and-trade program would not result in actions that 

would pose a significant adverse impact to agriculture and forest resources. 
VI-7

The compliance responses implemented by covered entities largely consist of 

onsite improvements to existing facilities located in industrial settings, and as 

such would not be expected to impact agriculture or forest resources.

The ODS offset protocol would not include activities that impact agriculture or 

forest resources. The Livestock offset protocol would include the construction of 

digesters in agricultural settings. Digesters are consistent with agricultural uses 

and would not represent an adverse change to agriculture or forest resources. 

The Urban Forest offset protocol would not impact agriculture or forest resources. 

The Forest offset protocol would not increase the amount of forest activities, but 

could shift activities to projects that increase carbon sequestration. Managing 

forests to increase cover and remove dead and diseased trees may be 

considered a beneficial impact to forests. The Forest offset protocol does not 

include actions that would encourage the conversion of agricultural land to 

forest.

c. Biological Resources

Implementation of the cap-and-trade program has the potential to adversely 

impact biological resources. 

The compliance responses evaluated in the FED consist of onsite improvements 

to existing facilities located in industrial settings. Construction, grading and 

trenching have the potential to adversely impact any protected biological 

resources that might exist at those locations. Although recognized mitigation 

measures exist to reduce this potential impact, the authority to require mitigation 

lies with local permitting agencies and not ARB. Consequently, this potentially 

significant impact may be unavoidable.

The ODS offset protocol would not include activities that potentially impact 

biological resources. The Livestock offset protocol would include the 

construction of digesters at or adjacent to existing livestock operations where 

natural habitats are expected to be absent or limited. As such, the livestock 

offset protocol would result in less than significant impacts to biological resources. 

The Urban Forest offset protocol recognizes tree improvement projects in urban 

settings, and as such would not be expected to significantly affect biological 

resources. The Forest offset protocol would not increase total forest activities, 

but could shift activities to projects that increase carbon sequestration. This shift 

could change the habitat of offset project sites over time. Consequently, this 

potentially significant impact may be unavoidable. ARB will implement adaptive 

management to monitor this impact.

d. Cultural Resources

Implementation of the cap-and-trade program has the potential to adversely 

impact cultural resources. 

The compliance responses evaluated in the FED consist of onsite improvements 

to existing facilities located in industrial settings. Construction, grading and 
VI-8

trenching have the potential to adversely impact any cultural resources that might 

exist at those locations. Although recognized mitigation measures exist to 

reduce this potential impact, the authority to require mitigation lies with local 

permitting agencies and not ARB. Consequently, this potentially significant 

impact may be unavoidable.

The ODS offset protocol would not include activities that potentially impact 

cultural resources. The Livestock offset protocol would include the construction 

of digesters at or adjacent to existing livestock operations where cultural or 

historic features could exist. Similarly, the Urban Forest offset protocol includes 

projects in urban settings where cultural and historic resources could exist. 

Although recognized mitigation measures exist to reduce these potential impacts, 

the authority to require mitigation lies with local permitting agencies and not ARB. 

Consequently, these potential impacts are identified as significant and 

unavoidable. The Forest offset protocol could change the type of forest projects 

that are undertaken, but would not alter the overall level of forest activities, and 

as such would not increase potential impacts to cultural resources. This potential 

impact would be less than significant.

e. Energy Demand

Implementation of the cap-and-trade program would reduce energy demand, 

representing a beneficial effect. 

The covered entity compliance responses evaluated in the FED include 

upgrading equipment, switching to lower-intensity carbon fuels, and 

implementing maintenance and process changes. These actions will reduce 

overall energy demand and are considered beneficial effects.

Projects implemented under the compliance offset protocols will not increase 

energy demand, and as such pose no impact or less than significant impacts to 

energy demand.

f. Geology, Soils, and Mineral Resources

Implementation of the cap-and-trade program has the potential to adversely 

impact geology, soils, and mineral resources. 

The covered entity compliance responses evaluated in the FED include onsite 

improvements to existing facilities located in industrial settings. Construction, 

grading and trenching have the potential to result in adverse soil erosion, dust 

generation, and sedimentation of local waterways. Although recognized 

mitigation measures exist to reduce this potential impact, the authority to require 

mitigation lies with local permitting agencies and not with ARB. Consequently, 

this potentially significant impact may be unavoidable.

The ODS offset protocol would have no impacts on geology, soils and mineral 

resources. The Livestock offset protocol would include the construction of 

digesters that would be subject to regulations that are considered sufficient to 
VI-9

mitigate potential impacts to geology, soils and mineral resources to a less than 

significant level. The Urban forest offset protocol would result in only minor soils 

disturbance and would not be expected to adversely impact geology, soils or 

mineral resources. This impact would be less than significant. The Forest offset 

protocol would not increase total forest activities, but could shift activities to 

projects that increase carbon sequestration. Because the overall level of forest 

activities would not change, this impact would be less than significant.

g. Hazardous Materials

Implementation of the cap-and-trade program would not result in actions that 

would result in potentially significant adverse impacts related to hazards or 

hazardous materials. 

The covered entity compliance responses evaluated in the FED include onsite 

improvements to existing facilities located in industrial settings. The use of 

hazardous materials is common practice in industrial settings. Implementation of 

compliance responses could include the use of hazardous materials, but this 

would be considered simply an extension of business as usual for most covered 

entities, mitigated by existing practices and regulations, and thus considered less 

than significant.

Offset projects implemented under the proposed offset protocols may result in 

the use or transport of hazardous materials that require special handling and 

disposal. All projects would be required to comply with established local, state, 

and federal laws pertaining to the use, storage, and transportation of these 

materials. Assuming compliance with applicable laws and regulations, the 

impacts would be less than significant.

h. Hydrology and Water Quality

Implementation of the cap-and-trade program has the potential to adversely 

impact hydrology and water quality. 

The covered entity compliance responses evaluated in the FED include onsite 

improvements to existing facilities located in industrial settings. Construction, 

grading and trenching have the potential to result in adverse soil erosion resulting 

in sedimentation and degradation of local waterways. Although recognized 

mitigation measures exist to reduce this potential impact, the authority to require 

mitigation lies with local permitting agencies and not with ARB. Consequently, 

this potentially significant impact may be unavoidable.

The ODS offset protocol would have no adverse impacts on hydrology and water 

quality. The Livestock offset protocol would include the construction of digesters 

that would be subject to regulations which are considered sufficient to mitigate 

potential impacts to hydrology and water quality to a less than significant level. 

The Urban forest offset protocol would result in only minor soil disturbance 

resulting in less than significant impacts to hydrology or water quality. The 

Forest offset protocol would not increase total forest activities, but could shift 
VI-10

activities to projects that increase carbon sequestration. Because the overall 

level of forest activities would not change, the potential to adversely impact 

hydrology and water quality would not change. This impact would be less than 

significant..

i. Land Use and Planning

Implementation of the cap-and-trade program has the potential to result in a 

significant adverse impact to land use and planning. 

The covered entity compliance responses evaluated in the FED include onsite 

improvements to existing facilities located in industrial settings, and as such 

would be consistent with the existing land use and would pose a less than 

significant land use and planning impact. 

The ODS offset protocol would use existing facilities, representing a less than 

significant impact to land use and planning. The Livestock offset protocol would 

allow the construction of digesters in agricultural settings. Digesters are a 

consistent use in agricultural areas. As such, their construction would not conflict 

with existing land use plans, and thus would be a less than significant impact.

Projects implemented under the Urban Forest offset protocol would not conflict 

with land use plans, resulting in a less than significant impact. 

The Forest offset protocol includes avoided conversion projects that could 

conflict with local land use plans that envision development or other uses of 

forested areas. Consequently, this potentially significant impact may be an 

unavoidable conflict with local land use plans.

j. Noise

Implementation of the cap-and-trade program has the potential to result in a 

significant adverse noise impact. 

The covered entity compliance responses evaluated in the FED include 

upgrading equipment, switching to lower intensity carbon fuels, and implementing 

maintenance and process changes. Construction has the potential to introduce 

short-term noise levels that would exceed acceptable ambient levels. Because 

of the short-term nature of construction, and the general compatibility of loud 

sounds with industrial settings, this impact would be less than significant. 

Recognized measures are standard business practice to minimize construction 

noise.

The ODS offset protocol would not result in significant adverse noise impacts. 

The Livestock offset protocol would allow the construction of digesters in 

agricultural settings. Construction of digesters could adversely impact sensitive 

receptors and is considered a significant and unavoidable impact. Although 

recognized mitigation measures exist to reduce this potential impact, the 
VI-11

authority to require mitigation lies with local permitting agencies and not ARB. 

Consequently, this potentially significant impact may be unavoidable.

Projects implemented under the Urban Forest offset protocol would not produce 

unacceptable noise levels and potential noise impacts are considered a less than 

significant impact. 

Projects implemented under the Forest offset protocol would occur in forested 

areas. Forest projects would produce elevated noise levels that exceed 

accepted ambient levels. However, adoption of the Forest offset protocol would 

not alter the extent of forest activities, but would simply shift some activities to 

projects that sequester carbon. Because the level of overall forest activities 

would not change, the consequential noise impacts would not change. Thus, this 

impact is considered less than significant.

k. Population and Housing

The cap-and-trade program, including the proposed compliance offset protocols 

and associated offset projects would not be expected to result in significant 

adverse impacts to employment, population, or housing. All impacts to 

population, employment, and housing would be less than significant.

l. Public Services

The proposed covered entity compliance responses, compliance offset protocols 

and associated offset projects would not be expected to result in adverse impacts 

to public services. All potential impacts to public services would be less than 

significant.

The covered entity compliance responses evaluated in the FED include 

upgrading equipment, switching to lower-intensity carbon fuels, and 

implementing maintenance and process changes. These projects would not 

increase the level of public services beyond that already provided to existing 

facilities.

The ODS offset protocol, the Livestock offset protocol, and the Urban Forest 

offset protocol and associated projects would not result in a need for an 

increased level of public services beyond that already provided to existing 

facilities. The Forest offset protocol would not alter the extent of forest activities, 

but would shift some activities to projects that sequester carbon. Because the 

level of overall forest activities would not change, the consequential need for 

public services would not change. Thus, this impact would be less than 

significant.

m. Recreation

The proposed covered entity compliance responses, compliance offset protocols 

and associated offset projects would not be expected to result in adverse impacts 

to public services. All potential impacts to recreation would be less than 

significant.
VI-12

The covered entity compliance responses evaluated in the FED include 

upgrading equipment, switching to lower intensity carbon fuels, and implementing 

maintenance and process changes. These actions would have a less than 

significant impact on recreation resources.

The ODS offset protocol, the Livestock offset protocol, and the Urban Forest 

offset protocol and associated projects would result in a less than significant 

impact on recreation resources.

Forest management activities could disrupt opportunities for forest recreation, but 

such disruptions exist under current conditions. Offset projects developed under 

the proposed Forest offset protocol would include the construction of roads, 

temporary closures for tree installation and periodic increases in truck or 

construction equipment traffic that could disrupt recreational activities, but forest 

projects developed under the Forest offset protocol would occur on land that was 

historically forested or currently forested, and consequently, the overall impact to 

recreational resources would be less than significant.

n. Transportation and Traffic

Implementation of covered entity compliance responses is not expected to cause 

significant adverse impacts to transportation or traffic. If a facility expands or 

requires construction to take place, increases in construction traffic would be 

temporary and considered less than significant. Construction traffic impacts can 

be mitigated through ingress and egress controls, traffic controls, and reduced 

speed zones to ensure safety. Activities undertaken to develop offset projects 

would be expected to vary according to the type of offset project. Construction of 

livestock digesters could require the operation of heavy equipment on rural roads, 

resulting in potentially significant safety concerns that may be unavoidable. 

Transportation and traffic impacts resulting from other offset protocol projects 

would be less than significant.

o. Utility Service Systems

The cap-and-trade program, including the proposed compliance offset protocols 

and associated offset projects would not significantly increase or decrease the 

need for utilities and associated services, and as such would be a less than 

significant impact. 

The covered entity compliance responses evaluated in the FED include 

upgrading equipment, switching to lower-intensity carbon fuels, and 

implementing maintenance and process changes. These projects would not 

increase the level of utilities beyond that already provided to existing facilities. 

Fuel switching could require provision of new services. The availability and 

extension of utilities is subject to approval of the local utility provider, and thus 

mitigated to less than significant.

The ODS offset protocol, the Livestock offset protocol, and the Urban Forest 

offset protocol and associated projects would not result in a need for an 
VI-13

increased level of utilities beyond that already provided to existing facilities. 

Construction of new facilities would require the extension of utilities and services. 

The availability and extension of utilities is subject to approval of the local utility 

provider, and thus mitigated to less than significant.

The Forest offset protocol would not alter the extent of forest activities, but would 

shift some activities to projects that sequester carbon. Because the level of 

overall forest activities would not change, the consequential need for utility 

service systems associated with those activities would not change. Thus, this 

impact is considered less than significant.
VI-14

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VII-1

VII CO-POLLUTANT EMISSIONS ASSESSMENT

A. Introduction

AB 32 requires ARB, to the extent feasible, and in furtherance of achieving the 

statewide greenhouse gas (GHG) emissions limits, to: consider the potential for 

direct, indirect, and cumulative emissions impacts, including any localized 

impacts; prevent increases in criteria and toxic air pollutants; and maximize 

additional environmental and economic benefits. Although the cap-and-trade 

regulation is specifically aimed at reducing GHGs, technology improvements and 

enhanced energy efficiency can also reduce criteria and toxic air pollutants (copollutants) associated with GHG emissions as a co-benefit. Reductions in copollutants will have positive health benefits and assist in meeting health-based air 

quality standards. The AB 32 Scoping Plan estimated statewide co-pollutant 

reductions from the combination of measures in the Plan. This assessment 

focuses on the potential for direct, indirect, and cumulative emissions impacts of 

the proposed cap-and-trade regulation. It is designed to evaluate the potential 

co-pollutant benefits from the rule, scenarios which might lead to potential 

increases in co-pollutants, and cumulative emissions impacts on communities 

already adversely impacted by air pollution. 

The assessment focuses on the potential criteria and toxic pollutant emissions

impacts from the industrial and electricity generation sources covered by the 

program. The assessment does not include criteria pollutant and toxic emissions

reductions that the cap-and-trade program is expected to provide from 

transportation fuels and commercial and residential gas use in addition to those 

likely to occur at industrial and electricity generation facilities. 

Designing the emissions assessment proved to be challenging, given the nature 

and complexity of a cap-and-trade rule. The inherent flexibility provided by capand-trade makes it difficult to predict the specific changes that may result at an 

individual facility, and in turn, how those changes may impact cumulative 

emissions within a particular community. Because of the market-based design of 

the program, compliance decisions are expected to reflect the relative cost of 

compliance options. However, other business and operational considerations, 

such as overall economic growth and demand for their products, will also 

influence the choices made by regulated entities. For this reason, this 

assessment uses a case study approach to look at potential emissions impacts 

at a community level. Although staff's analysis indicates that emissions

increases as a result of the cap-and-trade program are unlikely, the case studies 

are designed as a hypothetical bounding exercise to look at both the best-case 

and worst-case emissions scenarios, to characterize the bounds of potential 

outcomes and cumulative impacts.

Any evaluation of potential impacts must consider the existing programs that are 

already in place to address criteria and toxic air pollutants. California’s air quality 

program leads the nation in terms of stringency of required emission controls. 
VII-2

This includes local air district permitting programs for stationary sources; ARB’s 

comprehensive control programs for mobile sources, goods movement, and 

diesel risk reduction; and the air toxics identification and risk assessment process. 

The cap-and-trade regulation will not affect the stringency of these programs. 

Rather, sources regulated by the cap-and-trade program must continue to 

operate within these existing requirements and as such the cap-and-trade 

program provides an additional mechanism to ensure continued air quality 

improvement. 

California’s air pollution control programs for criteria and toxic pollutants will 

continue to significantly reduce emissions and health risk into the future. 

Reductions in co-pollutants that occur as a result of AB 32 complement the 

benefits of California’s existing air quality programs. Reducing emissions from 

combustion sources is at the core of California’s program to meet air quality 

standards for ozone and fine particles and is also central to the AB 32 Scoping 

Plan for meeting the 2020 greenhouse gas emissions target. California’s climate 

and criteria pollutant programs are complementary, and the AB 32 regulations 

ARB is adopting will provide benefits that will be incorporated into future air 

quality plans for ozone and fine particles.

The potential for cumulative impacts in communities already adversely impacted 

by air pollution is included as a specific consideration in the statute, but AB 32 

does not define “cumulative emissions impacts” or “communities already 

impacted by air pollution.” Most urban areas in California are impacted by air 

pollution on a regional basis, and as a result, all have air quality programs and 

plans in place that are designed to provide for compliance with air quality 

standards. Transportation and industrial air pollution sources are also 

concentrated in urban areas, which can contribute to cumulative emissions 

impacts on a localized level. Rural areas downwind of urban centers also 

experience poor air quality due to the transport of air pollution, and are adversely 

impacted by air pollution. Each of these situations is considered in this 

assessment, to the extent feasible, with special attention to the potential for 

localized impacts in communities experiencing the greatest air pollution impacts.

The emissions assessment is designed to meet statutory requirements to 

evaluate the potential emissions impacts of the proposed cap-and-trade rule and 

complements the Health Impact Assessment (HIA) being conducted by the 

California Department of Public Health (CDPH). To supplement ARB’s 

emissions assessment, the HIA evaluates potential health impacts other than air 

pollution effects and explores other issues such as health disparities among 

communities, and potential uses of revenue generated by the program to further 

improve public health in California. CDPH recently presented its work plan to the 

California Climate Action Team Public Health Work Group. Broader 

considerations related to community health status, air pollution exposures, and 

vulnerable populations are expected to be part of a public decision-making 

process on the use of revenues generated by the program. Taken together, the 
VII-3

ARB emissions assessment and the HIA provide information on the broad 

implementation of the cap-and-trade program.

This emissions assessment analyzes a range of potential compliance options for 

industrial and electricity generation sources in the cap-and-trade program. Most 

compliance approaches are expected to result in reductions in co-pollutants 

through increased efficiency and decreased combustion of fossil fuels. However, 

the regulation affords entities flexibility to choose the most cost-effective 

strategies to reduce emissions, so the potential for some compliance actions to 

result in increased co-pollutant emissions at some facilities cannot be entirely 

discounted. 79

Although staff believes that the potential for emissions increases attributable to 

the rule are very unlikely, ARB is committed to monitoring the implementation of 

the cap-and-trade regulation to identify and to address any situations where the 

program has caused an increase in criteria pollutant or toxic emissions. At least 

once each compliance period, ARB will use information collected through the 

mandatory reporting regulation, the cap-and-trade regulation, the industrial 

efficiency audit, and other sources of information to evaluate how individual 

facilities are complying with the regulation. The cap-and-trade program is 

another layer of review and opportunity for data gathering, decision-making, and 

agency and public vigilance to ensure any potential increases are identified and 

addressed.

For this reason, continued monitoring and review will be 

necessary to identify situations where increases in criteria pollutants and toxics 

might occur, and to allow the appropriate agencies to take the needed steps to 

address them. Many of the mechanisms are already in place to do so: 

stationary source control and permitting programs; toxics control and risk 

assessment requirements; and air monitoring for ozone, PM2.5, and toxics. 

B. Methods for Identifying Cumulatively Impacted Communities

In 2005, ARB sponsored a research project on an environmental justice 

screening method that combines indicators of current air pollution risk with social 

and health vulnerability. The final report for this work is entitled: Air Pollution and 

Environmental Justice: Integrating Indicators of Cumulative Impact and Socio-

 

79 Not all emissions increases at facilities covered by the cap-and-trade program will result from 

the program itself. The cap-and-trade program will place a new regulatory requirement and a 

new cost on GHG emissions from all covered facilities, so that the program provides an incentive 

to decrease (or to minimize increases in) GHG emissions and any related emissions of criteria or 

toxic emissions. While the program provides flexibility that could allow increased production due 

to economic growth, such increases would not be caused by the cap-and-trade program. Staff 

believes that only in very limited circumstances would a localized emissions increase be the 

actual result of the incentives created by the cap-and-trade program – e.g. shifting of production 

within a company from an inefficient facility with higher compliance costs to a more efficient 

facility that results in higher emissions at the more efficient facility.
VII-4

Economic Vulnerability into Regulatory Decision-Making.80

This screening approach is a visual mapping tool and scoring procedure that 

examines cumulative impacts in neighborhoods. The screening approach 

incorporates a number of indicators of cumulative impact, reflecting research on 

air pollution, public health, and environmental justice. It incorporates indicators 

for three categories of potential impact and vulnerability: air pollution exposures 

and health risk, social and health vulnerability, and proximity between hazardous 

and sensitive land uses. 

 The final report was 

reviewed by the ARB Research Screening Committee.

To identify communities for the case studies, ARB consulted with the 

Environmental Justice Advisory Committee (EJAC)81

In addition to requiring an assessment of the emissions impact, AB 32 requires 

the Board, where applicable and feasible, to direct investment toward the most 

disadvantaged communities. With respect to the cap-and-trade rule, this relates 

to the use of allowance value. This emissions assessment does not address the 

distribution of revenues, which is an implementation issue that deserves serious 

consideration and a broad-based public discussion. Identification of 

disadvantaged communities must be part of that discussion, including the 

and other environmental 

stakeholders. These groups recommended that multiple communities be 

evaluated. Staff also considered availability of data, concentration of facilities 

that would be subject to cap-and-trade, and regional diversity. As a result, this 

assessment looks at four cumulatively impacted communities: Wilmington, 

Oildale/Bakersfield, Richmond, and Apple Valley/Oro Grande. Wilmington is 

identified as a cumulatively impacted community by the mapping tool described 

in Air Pollution and Environmental Justice: Integrating Indicators of Cumulative 

Impact and Socio-Economic Vulnerability into Regulatory Decision-Making. At 

this time, that mapping tool is available only for the Los Angeles region. ARB is 

in the process of evaluating how to expand the availability of this screening 

approach statewide. The other three communities are also identified as 

cumulatively impacted by a similar screening tool developed by ARB staff. While 

the ARB staff-developed tool does not include all the factors used in the research 

contract tool, if the latter were available statewide, it is expected that it would 

identify the same three communities as appropriate case studies.

 

80 California Air Resources Board (2010): Air Pollution and Environmental Justice: Integrating 

Indicators of Cumulative Impact and Socio-Economic Vulnerability into Regulatory DecisionMaking. http://www.arb.ca.gov/research/apr/past/04-308.pdf.

81 Environmental Justice Advisory Committee (2008): Recommendations and Comments of the 

Environmental Justice Advisory Committee on the Implementation of the Global Warming 

Solutions Act. California Air Resources Board. http://www.arb.ca.gov/cc/ejac/proposedplanejaccommentsfinaldec10.pdf
VII-5

possible use of the mapping tool described in Air Pollution and Environmental 

Justice: Integrating Indicators of Cumulative Impact and Socio-Economic 

Vulnerability into Regulatory Decision-Making.

C. Method for Assessing Cumulative Emissions Impact 

This assessment addresses potential direct, indirect, and cumulative emissions 

impacts in the context of both emission and air pollution exposure trends. Some 

air pollutant emissions directly impact health, while others chemically react in the 

atmosphere to form pollutants of health concern. Ambient air monitoring data 

provide empirical information on recent trends in exposure to air pollution for both 

direct air pollutants and those formed in the atmosphere. The full assessment is 

described in Appendix P: Co-Pollutant Emissions Assessment. 

Determining the potential impact of the cap-and-trade regulation on cumulative 

emissions requires looking at how various industrial sectors and individual 

facilities may move to comply with the program and then evaluating that 

response in the context of all emissions from all sources, first at the regional level, 

and then at the local level. This assessment takes a stepwise approach, with 

each step providing information used by ARB staff to conduct the subsequent 

analyses.

Step 1: The assessment considers California’s existing regulatory programs 

governing smog-forming, fine particulate, and toxics emissions from stationary 

sources. Any specific changes made at a facility in response to the cap-andtrade regulation must be in compliance with this framework, which includes 

regulatory programs, permit systems, risk assessment, and more. Appendix P 

summarizes the major programs that will reduce emissions from cars, trucks, and 

other mobile sources between now and 2020. Appendix P also describes 

cumulative emissions today statewide, as well as recent air quality. Maps are 

presented that show how air quality varies within the State to provide context for 

the community case studies.

Step 2: The assessment examines future emissions in 2020. Appendix P 

describes the expected emissions reductions that will take place at the regional 

level as a result of the existing control programs and the contribution of the 

capped sources to the regional cumulative emissions totals in 2020. This shows 

that absent the cap-and-trade rule, capped industrial and electricity generation

sources are forecast to be less than 10 percent of cumulative emissions from all 

sources. This percentage varies by region and pollutant.

Step 3: The assessment looks at the potential impact of the cap-and-trade 

regulation on co-pollutant emissions, starting with a general description of how 

the cap-and-trade industrial and electricity generation sectors may respond to 

rule requirements, how other greenhouse gas programs apply to the sectors, and 

how the existing co-pollutant control requirements examined in Step 1 overlay. 

This analysis appears in Appendix P: Co-Pollutant Emissions Assessment.
VII-6

Step 4: The assessment examines four communities. Each community 

assessment includes descriptions of current air quality exposure and trends, 

existing co-pollutant emissions and control programs, and an evaluation of the 

potential for cumulative emissions impacts in 2020 from the implementation of 

the cap-and-trade program. The full assessments are presented in Appendix P: 

Co-Pollutant Emissions Assessment.

D. Community Case Studies

For major pollutants like ozone and PM2.5, it is important to ensure that any 

actions taken through a cap-and-trade rule do not hinder progress toward 

attainment of air quality standards established to protect public health. With that 

as a framework, this section focuses on four communities and explores 

hypothetical situations that might result from the implementation of a cap-andtrade rule at a local level. A full description of the assessment appears in 

Appendix P: Co-Pollutant Emissions Assessment. 

The choice of communities captures the diverse nature of California’s air quality 

problems, as well as range of sources that would be subject to the cap-and-trade 

regulation. The boundary of each assessment area captures the most highly 

impacted communities. Because community level exposure reflects impacts 

from both local and regional emission sources, the size of each assessment area 

was selected to encompass a representative sampling of cap-and-trade sources 

which could potentially impact the local community. The size also represents a 

balance between reflecting broader regional-scale impacts versus smaller facilityspecific impacts. The four communities are: 

• Wilmington and Richmond: These two cities are part of larger 

metropolitan areas in Southern and Northern California. They are located 

among a nexus of major transportation corridors, large refineries and other 

industrial and electricity generation facilities, and busy international ports. 

The concentration of emission sources contribute to air quality problems in 

the local community, as well as downwind areas. Both Wilmington and 

Richmond have a large number of industrial and electricity generation 

facilities that would be subject to the cap-and-trade regulation.

• Bakersfield/Oildale: This region of the Central Valley has a mix of sources 

ranging from agricultural operations to widely dispersed stationary sources. 

The area also has a significant amount of mobile source emissions, 

resulting from its location along the two interstate highways connecting 

Northern and Southern California. The Bakersfield region has one of the 

most severe air quality problems in the nation. The Bakersfield/Oildale 

area contains a diverse array of industrial and electricity generation 

facilities that would be subject to the cap-and-trade regulation.

• Oro Grande: This community is located in the high Mojave Desert and 

includes the moderately sized towns of Hesperia and Victorville. Local air 

pollution sources are primarily from mineral extraction and related 
VII-7

commercial activities. This area has a small number of industrial and 

electrical generation sources that would be subject to the cap-and-trade 

regulation, with a focus on cement manufacturing. The local air quality 

problem is primarily due to the community’s proximity to the South Coast,

which transports substantial air pollution into the Mojave Desert. 

As noted above, each community has a unique mix of industrial and electricity 

generation sources that would be subject to the cap-and-trade regulation. Air 

quality experienced by community residents is influenced by regional emissions 

and air quality levels, as well as an additional overlay from local sources. 

Therefore the assessment for each community begins with an overview of air 

quality and emissions on a regional basis, and then focuses on the nature of the 

local air quality problem and the local sources, including industrial and electricity 

generation facilities expected to be subject to the cap-and-trade regulation. It is 

difficult to predict how individual facilities within a given community may respond

to the cap-and-trade regulation. However, staff examined hypothetical bounding 

scenarios in each community based on the nature of the sources in that 

community and the possible responses for each cap-and-trade sector, as 

discussed in Appendix P: Co-Pollutant Emissions Assessment.

1. Description of the Scenarios

Because of the compliance flexibility provided by the cap-and-trade regulation, it 

was not possible to identify facility-specific changes that might occur within each 

community. Instead, three basic hypothetical bounding scenarios were used to 

assess potential cumulative emissions impacts. Those bounding scenarios are: 

(1) a bounding co-benefit scenario, where all covered industrial and electricity 

generation facilities within the community reduce their greenhouse gas emissions, 

(2) a bounding dis-benefit scenario where all covered facilities increase their 

emissions, and (3) a second dis-benefit scenario where a new facility is built in 

the community. 

For each assessment, the emissions reductions that will result from ongoing 

regulatory programs to reduce co-pollutants between 2008 and 2020 provide the 

baseline for evaluating each scenario’s impacts. This baseline reflects what 

would occur in the absence of cap-and-trade, or if all GHG reductions were 

achieved outside the community. 

The first scenario explores the potential co-benefits of limiting trading and the use 

of offsets within a community. The baseline (no change) and the first scenario 

bound the most likely impact of the regulation’s implementation. In addition, staff 

examined the potential impacts of general facility growth through two additional 

scenarios. The possible co-pollutant increases in these two additional scenarios 

cannot be specifically attributed to the cap-and-trade regulation. The scenario 

analysis focused on the industrial and electricity generation facilities covered 

under cap-and-trade and does not address the additional reductions that will 

likely occur when transportation fuels and commercial and residential natural gas 

are also included under the cap.
VII-8

ARB staff believes that scenarios 2 and 3 are very unlikely to result from the capand-trade regulation. Many factors influence a decision to expand production or 

build a new facility, and the cap-and-trade program itself imposes a new 

requirement on facilities—the need to procure allowances and offsets to 

accommodate GHG emissions—in addition to the strict permitting requirements 

already in effect for criteria pollutants and toxic air contaminants. Under scenario

2, every facility would need to purchase allowances and offsets to accommodate 

any growth. We believe it is more likely that a few facilities may increase 

production, while others would decrease. Similarly, we do not believe that 

compliance with the cap-and-trade regulation will cause the siting of new facilities 

assumed in scenario 3, though the regulation would not prevent it. Nevertheless, 

both scenarios are useful as hypothetical bounding analyses.

Scenario 1: The first scenario assumes as a hypothetical upper bound that 

GHG emissions reductions occur at each of the local industrial and electricity 

generation facilities in the community. On average, the cap-and-trade industrial 

and electricity generation sources will need to reduce their GHG emissions by 

4 percent to meet the 2020 cap.82

Scenario 2: The second scenario represents a hypothetical emissions increase 

of 4 percent at each of the cap-and-trade facilities in the community. While this 

scenario provides a hypothetical upper bound of aggregate facility growth in the 

community, staff believes it is an unlikely situation, given the current regulatory 

structure. As described in Appendix P: Co-Pollutant Emissions Assessment, 

each individual unit of permitted equipment has a maximum permitted emission 

limit. Large facilities such as those covered under cap-and-trade often have 

hundreds of individual permits. If the facility owner modified that equipment or its 

operation such that actual emissions would exceed the permitted levels, New 

Source Review (NSR) and its requirements to implement Best Available Control 

Technology (BACT) would apply. This is a comprehensive and lengthy process 

that is subject to public review. The extensive requirements of this permitting 

process effectively limit the potential for significant emissions increases at a 

given facility. 

 Therefore, staff assumed a commensurate 4 

percent reduction would occur in combustion-related NOx, PM2.5, and reactive 

organic gases (ROG) from these industrial and electricity generation facilities. 

These additional reductions would further enhance the cumulative emissions

reductions from ongoing programs.

 

82 Total GHG emissions under baseline conditions in 2020 are estimated to be 507 MMTCO2e. 

GHG emissions from the capped sectors are approximately 409 MMTCO2e of the baseline. 

Reductions needed to meet the cap of 334 MMTCO2e will come in part through complementary 

measures from the Scoping Plan. After reductions from those measures, the cap-and-trade 

regulation is estimated to reduce at least 18 MMTCO2e, representing a 4 percent reduction from 

capped sector emissions.
VII-9

In addition, under this scenario, every facility would need to purchase allowances 

and offsets to accommodate any growth. While there could be growth at a few 

facilities within a community, as some facilities move to more efficient ways of 

operation or switch to use of less carbon-intensive fuels, it is very unlikely that 

emissions would increase at every facility. Much more likely is a situation where 

a few facilities may increase production, while others would decrease. 

Nevertheless, staff evaluated the impact of an increase of 4 percent at every 

facility to represent a potential maximum community-level impact. 

Scenario 3: For the third scenario, ARB assumed the hypothetical construction 

of a new facility within the community. For each community, ARB chose to site a 

facility consistent with the already existing industrial and electricity generation 

sources. Siting of a new facility would generally trigger NSR and its 

requirements to implement BACT would apply. This is a comprehensive and 

lengthy process that is subject to public review. In addition, the new facility 

would need to purchase allowances and offsets to accommodate its GHG

emissions. As discussed above, ARB staff believes that the cap-and-trade 

regulation is unlikely to trigger construction of new facilities. 

There is also the potential for increases in toxic air contaminants under 

Scenarios 2 and 3. Toxics emissions are typically reflected in PM2.5 and ROG 

emission estimates, thus efforts to control ROG and PM2.5 also help address 

toxic air contaminants broadly within the community. In addition, the 

requirements of the “Hot Spots”

83

2. Limitations

Information and Assessment Act are designed 

to assess and mitigate more localized, facility-specific impacts. As described 

earlier in this section, should emissions of toxics increase such that they exceed 

the screening threshold, the facility would be required to conduct a Health Risk 

Assessment. Facility emissions that are determined to present a significant risk 

would then be required to implement measures to reduce that risk. 

These scenarios focus on the compliance responses of the industrial and 

electricity generation sources covered by the cap-and-trade regulation. In 2015, 

transportation fuels and commercial and residential natural gas will be included in 

the cap, likely reducing emissions from those sources. Because the reductions 

associated with transportation fuel and commercial and residential natural gas 

would be the same for each of the scenarios, ARB chose to focus the analysis on 

industrial and electricity generation sources. The inclusion of the emissions

reductions from transportation fuel and commercial and residential natural gas 

 

83 California Air Resources Board: Webpage (as reviewed January 14, 2010): AB 2588 Air 

Toxics “Hot Spots” Program. http://www.arb.ca.gov/ab2588/ ab2588.htm.
VII-10

would likely increase the total co-pollutant benefits of the cap-and-trade 

regulation. 

In all scenarios it is difficult to predict the actual air quality impacts within the local 

community of any change in emissions. For example, combustion emissions, 

especially from large industry and electricity generation sources, are often vented 

through tall stacks. The heat generated by the combustion process can further 

increase the height of the emissions plume. As a result, emissions from a large 

stack may not reach the surface until some distance downwind. In addition, due 

to dispersion and the time needed for chemical reactions to form regional 

pollutants such as ozone and secondary particulate matter, the maximum air 

quality impact may occur well downwind of a facility. 

Air quality modeling is a standard tool for relating emissions to estimated air 

quality impacts. However, detailed information is required by the models to 

quantify the impacts. This information includes specificity on locations and types 

of emission sources, stack heights, timing of emissions, emission rates, and for 

point sources, information to characterize the point of release. Due to the 

flexibility each individual facility has to comply with the cap-and-trade regulation, 

it is impossible to characterize the timing and location of emissions changes. 

This makes use of modeling to characterize the air quality impact of potential 

changes in emissions infeasible.

Health assessments of the impact of air quality changes on human health require 

estimates of the change in PM2.5, ozone, and other air pollutants for an exposed 

population. The health impact depends on the air pollutant type and ambient 

concentration, location and duration of exposure, and characteristics of the 

exposed population, including total number of residents, age, and baseline 

incident rates for various death and disease types where a quantitative 

relationship has been established with an air pollutant. Health assessments in 

California have been limited to pollution sources where PM2.5, ozone, and air 

toxic exposures can be estimated using measured air quality data as a surrogate 

for a widely distributed source (e.g., trucks) or with the use of air quality models 

(e.g., ports and railyards). However, there is no unique air quality surrogate for 

the large industrial and electricity generation sources covered by the cap-andtrade regulation to distinguish them from smaller industrial and electricity 

generation sources or other types of combustion sources. Nor, as discussed 

above, was it feasible to conduct air quality modeling. Due to this lack of 

information on the concentration, location, and duration of air pollutant exposures, 

it was not possible to conduct a health assessment.

3. Wilmington Assessment

Wilmington is a suburb of Los Angeles, with a racially and ethnically diverse 

population of about 53,000 (See map in Appendix P: Co-Pollutant Emissions 

Assessment). Located between the Port of Los Angeles and the Port of 

Long Beach, the Wilmington area includes a diverse range of stationary and 

mobile source emissions. In combination, these two ports represent the third 
VII-11

largest container port in the world and account for about 25 percent of 

California’s goods movement emissions84

A total of 15 industrial and electricity generation facilities in the Wilmington area 

would be subject to the cap-and-trade regulation. See Appendix P: Co-Pollutant 

Emissions Assessment for a description of air quality and emissions in the 

Wilmington area and the traditional emissions control programs currently in place. 

Appendix P: Co-Pollutant Emissions Assessment also includes a discussion of 

potential emissions changes that could occur under the cap-and-trade regulation. 

. These shipping activities result in 

large amounts of diesel and fugitive emissions from bulk transport operations. In 

addition to port-related activities, Wilmington and the surrounding area are home 

to railyards, major transportation corridors, oil refineries, and power plants, as 

well as other industrial and commercial operations. Approximately 300,000 

people live within the emissions assessment area.

As described above, ARB developed three hypothetical bounding scenarios to 

assess potential cumulative emissions impacts in 2020 in Wilmington. For the 

third scenario (placing a new facility in the community), ARB evaluated the 

hypothetical construction of a new combined heat and power facility within the 

community. A combined heat and power generation facility was selected 

because petroleum refining is the largest cap-and-trade emissions sector in the 

Wilmington area. This would have the dual benefit of providing a more efficient 

heat source for refinery processes, while allowing excess power to be sold back 

to the grid. Table VII-1 provides an estimate of criteria pollutant emissions from a 

hypothetical 85 megawatt (MW) combined heat and power unit. It is important to 

remember that under California’s existing regulatory structure, the construction of 

a new facility would be subject to the strict NSR permitting requirements 

described in Appendix P: Co-Pollutant Emissions Assessment. This would 

include requirements to implement BACT, as well as to offset the emissions 

regionally.

 

84 California Air Resources Board (2006): Proposed Emission Reduction Plan for Ports and 

Goods Movement in California.

http://www.arb.ca.gov/planning/gmerp/march21plan/march22_plan.pdf
VII-12

Table VII-1

Estimated Criteria Pollutant Emissions

Hypothetical Combined Heat and Power Facility

(85 MW Capacity)

Emissions

(tons per day)

NOX ROG PM2.5

Operating Emissions 0.11 0.05 0.12

Analysis of Potential Impacts

Under the baseline existing control program, including rules adopted in the 2007 

State Implementation Plan (SIP)

85

Table VII-2

to meet national air quality standards, the

Wilmington area will realize further NOx, PM2.5, and ROG emissions reductions in 

2020. The reductions will come primarily from mobile sources, including 

light- and heavy-duty vehicles and from port-related activities such as ships 

maneuvering and anchoring within the port area and equipment used to load and 

unload ships. As shown in , these ongoing emissions reductions 

result in a 23 percent reduction in NOx, a 24 percent reduction in PM2.5, and a 

4 percent reduction in ROG emissions from 2008 levels. 

The first scenario assumes that all the emission reductions needed from the capand-trade regulation are implemented locally at the 15 industrial and electricity 

generation facilities in the Wilmington area, realizing a further 4 percent reduction 

in combustion-related co-pollutant emissions. Because emissions from the capand-trade industrial and electricity generation facilities comprise only a small 

portion of the overall inventory, these reductions translate into less than a 4

percent decrease in the total inventory for the Wilmington area. In aggregate,

implementation of reductions for the cap-and-trade regulation by industrial and 

electricity generation sources locally would result in an additional 1 percent 

enhancement in localized NOx and PM2.5 reductions, and a small enhancement 

of less than 1 percent in ROG reductions. While not quantified here, combustiongenerated toxic air contaminants would also likely decrease. 

 

85 California Air Resources Board: Webpage (as reviewed February 9, 2010): Proposed State 

Strategy for California’s State Implementation Plan (SIP) for the New Federal PM2.5 and 8-Hour 

Ozone Standards. http://www.arb.ca.gov/ planning/sip/2007sip/2007sip.htm
VII-13

Table VII-2

Percent of Emissions Reductions Between 2008 and 2020

Wilmington Area1

NOX PM2.5 ROG

BASELINE

Emission Reductions from Existing Controls and 

No Emission Reductions at Cap-and-Trade 

Industrial and Electricity Generation Facilities

23% 24% 4%

SCENARIO 1

Emission Reductions from Existing Controls and 

Emission Reductions at all Cap-and-Trade 

Industrial and Electricity Generation Facilities

24% 25% 4%

SCENARIO 2

Emission Reductions from Existing Controls and 

Emission Increases at all Cap-and-Trade 

Industrial and Electricity Generation Facilities

22% 22% 3%

SCENARIO 3

Emission Reductions from Existing Controls and 

Addition of New Facility

23% 20% 4%

Numbers are rounded to nearest percentage

1 These tables include the combined emissions from mobile, area, and stationary sources. The 

industrial and electricity generation facilities covered by the proposed cap-and-trade regulation 

represent only a portion of these emissions. The emission impacts of the scenarios do not 

include the additional emissions reductions that will likely occur when transportation fuels and 

commercial and residential natural gas are included in the cap. The emissions reductions from 

transportation fuels and commercial and residential natural gas would affect each of these 

scenarios equally.

As described previously, while ARB staff did not find situations where emissions

increases were clearly attributable to implementation of cap-and-trade, the 

second scenario evaluated the potential general impact of an emissions increase 

of 4 percent at every cap-and-trade industrial and electricity generation facility in 

the community region. This hypothetical upper-bound increase in emissions 

would slightly reduce the benefits of the ongoing control program, with a 2 

percent reduction in PM2.5 benefits, and a 1 percent reduction in NOx and ROG 

benefits. However, cumulative emissions in the Wilmington area would still be 

lower in 2020, as compared to 2008. 

Scenario 3 explored the potential emissions impacts of construction of a new 

combined heat and power unit at an existing refinery. Based on typical 

emissions from similar units, the addition of a hypothetical new unit in the 

community would slightly reduce the benefits of the ongoing control program, 

with a 4 percent reduction in PM2.5 benefits, and a very small reduction that is 

less than 1 percent in NOx and ROG benefits. Overall, cumulative emissions in 

the Wilmington area would still be lower in 2020, as compared to 2008.
VII-14

Summary

In summary, air quality is improving throughout the Wilmington area. The 

assessment area meets both the federal annual PM2.5 and 8-hour ozone 

standards, and the area is very close to meeting the daily PM2.5 standard. 

California’s ongoing co-pollutant emissions control programs will ensure that 

cumulative emissions will continue to decrease through 2020 in the Wilmington 

area, with associated health improvements from improved air quality. 

While the cap-and-trade regulation allows for flexibility in how facilities comply, 

staff looked at several scenarios that bound the possibilities, including the 

construction of a new facility. If emissions reductions due to implementation of 

the cap-and-trade regulation occur locally at the fifteen facilities in Wilmington, 

there could be some small additional co-benefits from the reduction of 

combustion-related criteria pollutants. While emissions increases directly 

attributable to the cap-and-trade regulation are considered very unlikely, potential 

emissions increases that might occur in general are also expected to be small 

within the context of the larger cumulative emissions reductions that will be 

occurring as a result of California’s extensive emissions control programs. 

4. Oildale-Bakersfield Assessment

The Oildale/Bakersfield area (Bakersfield area) is located in the central portion of 

Kern County in the San Joaquin Valley Air Basin. It includes not only Oildale, but 

much of the Bakersfield urban area and the town of Shafter as well (See map in 

Appendix P: Co-Pollutant Emissions Assessment). Overall, about 425,000 

people live in this area. In addition to significant mobile source emissions from 

trucks and passenger cars traveling along Highway 99 and Interstate 5, the 

Bakersfield area is adjacent to a number of oil fields, including two of the largest 

in California. The Kern River Oil Field to the east and northeast of Oildale has 

more than 9,000 active wells. It ranks second only to the Midway-Sunset Oil 

Field in southwestern Kern County. Other sizeable fields in the Bakersfield area 

include the Kern Front and Poso Creek oil fields north of Oildale and the smaller 

Fruitvale Oil Field to the southwest. In addition to the oil-related activities, the 

Bakersfield assessment area also contains a number of cogeneration facilities.

A total of 23 industrial and electricity generation facilities in the Bakersfield area 

would be subject to the cap-and-trade regulation. These facilities represent a 

mix of different types of operations. Appendix P: Co-Pollutant Emissions 

Assessment describes air quality and emissions in the assessment area and the 

traditional emissions control programs currently in place. This section provides a 

discussion of the emissions changes that could occur under the cap-and-trade 

regulation.

As described above, ARB developed three hypothetical bounding scenarios to 

assess potential cumulative emissions impacts in 2020 in the Bakersfield area. 

For the third scenario (placing a new facility in the community), ARB evaluated 

the hypothetical construction of a new biorefinery within the Bakersfield area. 
VII-15

The Low Carbon Fuel Standard and the federal renewable fuels standard have 

mandated that biofuels become a greater portion of transportation fuels, in order 

to reduce GHG emissions. Agricultural activities in the San Joaquin Valley 

generate materials that could be used to fuel a biorefinery. Table VII-3, below, 

provides an estimate of criteria pollutant emissions from a hypothetical biofuel 

refinery with an annual capacity of 50 million gallons. Under California’s existing 

regulatory structure, the construction of a new facility would be subject to the 

strict NSR permitting requirements described in Appendix P. This would include 

requirements to implement BACT, as well as to offset the emissions regionally. 

There is also the potential for increased truck traffic to deliver biomass to the 

plant. However, due to ARB regulations, in 2020 most trucks will be required to 

be equipped with the cleanest 2010 engines, as well as diesel particulate traps. 

Table VII-3

Estimated Criteria Pollutant Emissions

Hypothetical Biofuel Refining Facility

(50 million gallons/year capacity)

Emissions 

(tons per day)

NOX ROG PM10

Cellulosic Ethanol Facility 0.26 0.69 0.27

Analysis of Potential Impacts

Under the existing baseline control program, including rules adopted in the 2007 

SIP to meet national air quality standards, the Bakersfield area would realize 

NOx, PM2.5, and ROG emissions reductions in 2020. The reductions will come 

primarily from on-road and off-road motor vehicles. As shown in Table VII-4, 

these ongoing emissions reductions result in a 44 percent reduction in NOx and 

an 11 percent reduction in both PM2.5 and ROG emissions from 2008 levels.

The first scenario assumes that all the emissions reductions needed from the 

cap-and-trade regulation are implemented locally at the 23 industrial and 

electricity generation facilities in the Bakersfield area, realizing a further 4 percent 

reduction in co-pollutant emissions. Because emissions from the cap-and-trade 

industrial and electricity generation facilities comprise only a small portion of the 

overall inventory, these reductions translate into less than a 4 percent decrease

in the total inventory for the Bakersfield area. In aggregate, full implementation 

of the cap-and-trade regulation by industrial and electricity generation sources 

locally would result in an additional 1 percent enhancement in localized NOx 

reductions, and a small, less than 1 percent enhancement in localized PM2.5 and 

ROG reductions. While not quantified here, combustion-generated toxic air 

contaminants would also likely decrease. 
VII-16

Table VII-4

Percent Emissions Reductions Between 2008 and 2020

Bakersfield Area1

NOX PM2.5 ROG

BASELINE

Emission Reductions from Existing Controls and

No Emission Reductions from Cap-and-Trade 

Industrial and Electricity Generation Facilities

44% 11% 11%

SCENARIO 1

Emission Reductions from Existing Controls and 

Emission Reductions at all Cap-and-Trade 

Industrial and Electricity Generation Facilities

45% 11% 11%

SCENARIO 2

Emissions Reductions from Existing Controls and 

Emission Increases at all Cap-and-Trade 

Industrial and Electricity Generation Facilities

44% 10% 11%

SCENARIO 3

Emissions Reductions from Existing Controls and 

Addition of New Facility

44% 7% 9%

Numbers are rounded to nearest percentage

1 These tables include the combined emissions from mobile, area, and stationary sources. The 

industrial and electricity generation facilities covered by the proposed cap-and-trade regulation 

represent only a portion of these emissions. The emissions impacts of the scenarios do not 

include the additional emissions reductions that will likely occur when transportation fuels and 

commercial and residential natural gas are included in the cap. The emissions reductions from 

transportation fuels and commercial and residential natural gas would affect each of these 

scenarios equally.

As described previously, while ARB staff did not find situations where emissions

increases were clearly attributable to implementation of cap-and-trade, the 

second scenario evaluated the potential general impact of an emissions increase 

of 4 percent at every cap-and-trade facility in the assessment area. This 

hypothetical upper-bound increase in emissions would slightly reduce the overall 

benefits of the ongoing control program, with a 1 percent reduction in PM2.5

benefits, and a very small reduction that is less than 1 percent in NOx and ROG

benefits. However, cumulative emissions in the Bakersfield area would still be 

lower in 2020, as compared with 2008. 

Scenario 3 explored the potential emissions impacts of constructing a new 

biofuel refining facility. Based on typical emissions from similar facilities, the 

addition of a hypothetical new facility in the Bakersfield area would slightly 

reduce the benefits of the ongoing control program, with a 4 percent reduction in 

PM2.5 benefits, 2 percent reduction in ROG benefits, and a small reduction that is 

less than 1 percent in NOx benefits. However, overall, cumulative emissions in 

the Bakersfield area would still be lower in 2020, when compared with 2008.
VII-17

Summary

In summary, air quality is improving throughout the Bakersfield area, and the 

assessment area is making progress toward meeting the federal PM2.5 and 8-

hour ozone standards. California’s ongoing co-pollutant emissions control 

programs will ensure that cumulative emissions will continue to decrease through 

2020 in the Bakersfield area, with associated health improvements from 

improved air quality. 

While the cap-and-trade regulation allows for flexibility in how facilities comply, 

staff looked at several scenarios that bound the possibilities, including the 

construction of a new facility. If emissions reductions due to implementing the 

cap-and-trade regulation occur locally at the 23 facilities in the assessment area, 

there could be some small additional co-benefits from the reduction of 

combustion-related criteria pollutants. While emissions increases directly 

attributable to the cap-and-trade regulation are considered very unlikely, potential 

emissions increases that might occur in general are also expected to be small 

within the context of the larger cumulative emissions reductions that will be 

occurring as a result of California’s extensive emissions control programs. 

5. Richmond Assessment

The Richmond area, located on both the San Pablo and San Francisco Bays, 

encompasses portions of Contra Costa, Alameda, and Solano Counties, and 

includes portions of the cities of Richmond, El Cerrito, Berkeley, Emeryville, 

Benicia, and Alameda (See map in Appendix P: Co-Pollutant Emissions 

Assessment). The area is home to a racially and ethnically diverse population of 

over approximately 500,000 people and contains a wide range of stationary and 

mobile source emissions. These sources include the Port of Richmond and the 

Richmond Rail Yard, which produce diesel and fugitive emissions from bulk 

transport operations. In addition, the Richmond area is home to oil refineries, 

power plants, and major transportation corridors, as well as other industrial and 

commercial operations. 

A total of seven industrial and electricity generation facilities in the Richmond 

area would be subject to a cap-and-trade program. Appendix P: Co-Pollutant 

Emissions Assessment describes air quality and emissions in the Richmond area 

and the traditional emissions control programs currently in place. This section 

provides a discussion of potential emissions changes that could occur under the 

cap-and-trade regulation. 

As described above, ARB developed three hypothetical bounding scenarios to 

assess potential cumulative emissions impacts in 2020 in the Richmond area. 

For the third scenario (placing a new facility in the community), ARB evaluated 

the hypothetical construction of a new combined heat and power facility within 

the community. A combined heat and power generation facility was selected 

because petroleum refining is the largest cap-and-trade emissions sector in the 

Richmond area. This would have the dual benefit of providing a more efficient 
VII-18

heat source for refinery processes, while allowing excess power to be sold back 

to the grid. Table VII-5, below, provides an estimate of criteria pollutant 

emissions from a hypothetical 85 megawatt (MW) combined heat and power unit. 

It is important to remember that under California’s existing regulatory structure, 

the construction of a new facility would be subject to the strict NSR permitting 

requirements described in Appendix P: Co-Pollutant Emissions Assessment. 

This would include requirements to implement BACT, as well as to offset the 

emissions regionally. 

Table VII-5

Estimated Criteria Pollutant Emissions

Hypothetical Combined Heat and Power Facility

(85 MW Capacity)

Emissions 

(tons per day)

NOX ROG PM2.5

Operating Emissions 0.11 0.05 0.12

Analysis of Impacts 

Under the existing baseline control program, including rules adopted in the 2007 

SIP to meet national air quality standards, the Richmond area will realize further 

NOx and ROG emissions reductions in 2020. The reductions will come primarily 

from on-road motor vehicle and off-road mobile sources, including light- and 

heavy-duty vehicles. These ongoing emissions reductions are summarized in

Table VII-6, and reflect a 25 percent reduction in NOx and ROG emissions from 

2008 levels. In contrast, the Richmond study area would see a slight increase of 

1 percent in PM2.5 (reflected as negative numbers in Table VII-6), resulting from 

projected increases in area source emissions such as commercial cooking and 

residential fuel use, which are linked to population growth. 

The first scenario assumes that all the emissions reductions needed from the 

cap-and-trade regulation are implemented locally at the seven industrial and 

electricity generation facilities in the Richmond area, realizing a further 4 percent 

reduction in co-pollutant emissions. Because emissions from the cap-and-trade 

industrial and electricity generation facilities comprise only a small portion of the 

overall inventory, these reductions translate into less than a 4 percent decrease 

in the total inventory for the Richmond area. In aggregate, full implementation of 

the cap-and-trade regulation by industrial and electricity generation sources 

locally would result in an additional 2 percent enhancement in localized NOx 

reductions, a 1 percent reduction in PM2.5, and a small enhancement, less than 1 

percent, in localized ROG reductions. While not quantified here, combustiongenerated toxic air contaminants would also likely decrease.
VII-19

Table VII-6

Percent of Emissions Reductions Between 2008 and 2020

Richmond Area1

NOx PM2.5 ROG

BASELINE

Emission Reductions from Existing Controls and

No Emission Reductions at Cap-and-Trade 

Industrial and Electricity Generation Facilities

28% -1% 16%

SCENARIO 1

Emissions Reductions from Existing Controls and 

Emission Reductions at all Cap-and-Trade 

Industrial and Electricity Generation Facilities

30% 0% 16%

SCENARIO 2

Emission Reductions from Existing Controls and 

Emission Increases at all Cap-and-Trade 

Industrial and Electricity Generation Facilities

27% -2% 14%

SCENARIO 3

Emission Reductions from Existing Controls and 

Addition of New Facility

28% -2% 16%

Numbers are rounded to nearest percentage

1 These tables include the combined emissions from mobile, area, and stationary sources. The 

industrial and electricity generation facilities covered by the proposed cap-and-trade regulation 

represent only a portion of these emissions. The emissions impacts of the scenarios do not 

include the additional emissions reductions that will likely occur when transportation fuels and 

commercial and residential natural gas are included in the cap. The emissions reductions from 

transportation fuels and commercial and residential natural gas would affect each of these 

scenarios equally.

As described previously, while ARB staff did not find situations where emissions

increases were clearly attributable to implementation of cap-and-trade, the 

second scenario evaluated the potential general impact of an emissions increase 

of four percent at every cap-and-trade facility in the community region. This 

hypothetical upper-bound increase in emissions would slightly reduce the overall 

benefits of the ongoing control program, with a 2 percent reduction in ROG 

benefits, a 1 percent reduction in NOx benefits, and an additional 1 percent 

increase in PM2.5. However, cumulative emissions of NOx and ROG in the 

Richmond area would still be lower in 2020, as compared to 2008. 

Scenario 3 explored the potential emissions impacts of construction of a new 

combined heat and power unit at an existing refinery. Based on typical 

emissions from similar units, the addition of a hypothetical new unit in the 

community would slightly reduce the benefits of the ongoing control program, 

with a very small reduction that is less than 1 percent in NOx and ROG benefits, 
VII-20

and an additional 1 percent increase in PM2.5 emissions. Overall, cumulative 

emissions for NOx and ROG in the Richmond area would still be lower in 2020,

as compared to 2008. 

Summary

In summary, air quality is improving throughout the Richmond area. The 

assessment area meets both federal PM2.5 and 8-hour ozone standards. 

California’s ongoing co-pollutant emissions control programs will ensure that 

cumulative emissions will continue to decrease through 2020 in the Richmond 

area, with associated health improvements from improved air quality. 

While the cap-and-trade regulation allows for flexibility in how facilities comply, 

staff looked at several scenarios that bound the possibilities, including the 

construction of a new facility. If emissions reductions due to implementation of 

the cap-and-trade regulation occur locally at the seven facilities in Richmond, 

there could be some small additional co-benefits from the reduction of 

combustion-related criteria pollutants. While emissions increases directly 

attributable to the cap-and-trade regulation are considered very unlikely, potential 

emissions increases that might occur in general are also expected to be small 

within the context of the larger cumulative emissions reductions that will be 

occurring as a result of California’s extensive emissions control programs. 

6. Apple Valley/Oro Grande Assessment

The Apple Valley/Oro Grande area (hereafter called the Oro Grande area) is an 

economically and racially diverse area located in the Mojave Desert’s Victor 

Valley. With the town of Oro Grande in the northwest, Apple Valley in the center, 

and Lucerne Valley in the southeast of the assessment area, this high desert 

region also includes the towns of Victorville, Hesperia, and Adelanto. About 

230,000 people live in this portion of the Mojave Desert (See map in Appendix P: 

Co-Pollutant Emissions Assessment).

Although the Oro Grande area is more sparsely populated than the South Coast 

region to the south, the desert communities have grown over the last several 

decades as bedroom communities of the South Coast. Interstate 15 and 

Highway 395 act as thoroughfares, carrying significant amounts of commuter and 

truck traffic in and out of the Mojave Desert region.

Four industrial and electricity generation facilities in the Oro Grande area would 

be subject to the cap-and-trade regulation. Appendix P describes air quality and 

emissions in the Oro Grande area and the traditional emissions-control programs 

currently in place. This section provides a discussion of potential emissions 

changes that could occur under the cap-and-trade regulation.

As described above, ARB developed three hypothetical bounding scenarios to 

assess potential cumulative emissions impacts in 2020 in Oro Grande. For the 

third scenario (placing a new facility in the community), ARB evaluated the 
VII-21

hypothetical construction of a new natural gas power plant. Due to requirements 

of the Renewable Energy Standard and other initiatives, there may be an 

increase in natural gas-fueled power generation, as compared to more carbonintensive coal, in order to reduce GHG emissions. Given that the Oro Grande 

area already contains one small power facility, ARB staff evaluated the potential 

emissions from an additional natural gas facility. Table VII-7, below, provides an 

estimate of criteria pollutant emissions from a hypothetical 500 megawatt (MW) 

combined-cycle natural gas power plant. It is important to remember that under 

California’s existing regulatory structure, the construction of a new facility would 

be subject to the strict NSR permitting requirement described in Appendix P: CoPollutant Emissions Assessment. This would include requirements to implement 

BACT, as well as offset the emissions regionally.

Table VII-7

Estimated Criteria Pollutant Emissions

Hypothetical Combined-Cycle Natural Gas Baseload Power Plant

(500 MW Capacity)

Emissions (tons per day)

NOX ROG PM10

Operating Emissions 0.31 0.11 0.27

Analysis of Potential Impacts 

Under the existing baseline control program, including rules adopted in the 2007 

SIP to meet national air quality standards, the Oro Grande area would still realize 

NOx, PM2.5, and ROG emissions reductions in 2020. The reductions will come 

primarily from on-road and off-road motor vehicles. As shown in Table VII-8, 

these ongoing emissions reductions result in a 16 percent reduction in NOx, 

2 percent reduction in PM2.5, and 3 percent reduction in ROG emissions from 

2008 levels. 

The first scenario assumes that all the emissions reductions needed from the 

cap-and-trade regulation are implemented locally at the four industrial and 

electricity generation facilities in the Oro Grande area, realizing a further 4 

percent reduction in co-pollutant emissions. Because emissions from the capand-trade industrial and electricity generation facilities comprise only a small 

portion of the overall inventory, these reductions translate into less than a 

4 percent decrease in the total inventory for the Oro Grande area. In aggregate, 

full implementation of the cap-and-trade regulation by industrial and electricity 

generation sources locally would result in an additional 3 percent enhancement 

in localized NOx benefits, and an additional 1 percent enhancement in both the 

PM2.5 and ROG benefits (Table VII-8). While not quantified here, combustiongenerated toxic air contaminants would also likely decrease. 
VII-22

Table VII-8

Percent Emissions Reductions Between 2008 and 2020

Oro Grande Area1

NOx PM2.5 ROG

BASELINE

Emission Reductions from Existing Controls and

No Emission Reductions at Cap-and-Trade 

Industrial and Electricity Generation Facilities

16% 2% 3%

SCENARIO 1

Emissions Reductions from Existing Controls and 

Emission Reduction at all Cap-and-Trade 

Industrial and Electricity Generation Facilities

19% 3% 4%

SCENARIO 2

Emission Reductions from Existing Controls and 

Emission Increases at all Cap-and-Trade 

Industrial and Electricity Generation Facilities

14% 0% 3%

SCENARIO 3

Emissions Reductions from Existing Controls and 

Addition of New Facility

16% -1% 3%

Numbers are rounded to nearest percentage

1 These tables include the combined emissions from mobile, area, and stationary sources. The 

industrial and electricity generation facilities covered by the proposed cap-and-trade regulation 

represent only a portion of these emissions. The emissions impacts of the scenarios do not 

include the additional emissions reductions that will likely occur when transportation fuels and 

commercial and residential natural gas are included in the cap. The emissions reductions from 

transportation fuels and commercial and residential natural gas would affect each of these 

scenarios equally.

As described previously, while ARB staff did not find situations where emissions

increases were clearly attributable to implementation of cap-and-trade, the 

second scenario evaluated the potential general impact of an emissions increase 

of 4 percent at every cap-and-trade facility in the community region. This 

hypothetical upper-bound increase in emissions would slightly reduce the overall 

benefits of the ongoing control program, with a 2 percent reduction in both NOx 

and PM2.5 benefits, and a small reduction, less than 1 percent, in ROG benefits. 

However, cumulative emissions in the Oro Grande area would still be lower in 

2020, as compared to 2008, for both NOx and ROG, while PM2.5 emissions 

would remain constant. 

Scenario 3 explored the potential emissions impacts of constructing a new 

natural gas power plant in the local area. Based on typical emissions from 

similar facilities, the addition of a hypothetical new facility would slightly reduce 

the overall benefits of the ongoing control program, with a small reduction, less 
VII-23

than 1 percent, in NOx and ROG benefits and a 1 percent increase in PM2.5. 

Overall, cumulative emissions in the Oro Grande area would still be lower in 

2020, as compared to 2008, for both NOx and ROG, while PM2.5 emissions 

would increase slightly.

Summary

In summary, air quality is improving throughout the Oro Grande area. The 

assessment area meets the federal PM2.5 standards and shows continued 

progress toward meeting the federal ozone standard. California’s ongoing copollutant emissions control programs will ensure that cumulative emissions will 

continue to decrease through 2020 in the Oro Grande area, with associated 

health improvements from improved air quality. 

While the cap-and-trade regulation allows for flexibility in how facilities comply, 

staff looked at several scenarios that bound the possibilities, including the 

construction of a new facility. If emissions reductions due to implementing the 

cap-and-trade regulation occur locally at the four facilities in the assessment area, 

there could be some small additional co-benefits from the reduction of 

combustion-related criteria pollutants. While emissions increases directly 

attributable to the cap-and-trade regulation are considered very unlikely, potential 

emissions increases that might occur in general are also expected to be small 

within the context of the larger cumulative emissions reductions that will be 

occurring as a result of California’s extensive emissions control programs. 

E. Conclusion

Due to California’s comprehensive control programs, air quality has improved 

significantly throughout the State, with commensurate reductions in adverse 

health impacts. These improvements will continue through 2020 as ARB 

continues to adopt and implement regulations to meet State and federal air

quality standards, reduce toxic risk, and decrease California’s GHG emissions.

ARB’s analysis demonstrated that California’s existing programs to meet federal 

air quality standards will provide the majority of emissions reductions in each 

community, with further NOx reductions ranging from approximately 15 to 

45 percent by 2020. Staff’s analysis further indicates that the cap-and-trade 

regulation is expected to have a beneficial impact on emissions. In the 

communities evaluated, the regulation has the potential to provide small 

additional NOx reductions in the range of 1 to 3 percent if all GHG reductions 

were implemented locally. The assessment does not include criteria pollutant 

and toxic emissions reductions that the cap-and-trade program is expected to 

provide from transportation fuels and commercial and residential gas use, in 

addition to those likely to occur at industrial and electricity generation facilities. 

Due to the inherent flexibility of the cap-and-trade regulation, as well as the 

overlay of other complementary GHG reduction measures, it is difficult to predict 

the decisions that individual facilities may make in any given community. 
VII-24

However, based on the available data, current law and policies that control 

industrial and electricity generation sources of air pollution, and expected 

compliance responses, ARB believes that emissions increases at the statewide, 

regional, or local level due to the regulation are not likely. The cap-and-trade 

program will provide an incentive for covered facilities to decrease GHG

emissions and any related emissions of criteria and toxic pollutants.
VIII-1

VIII ECONOMIC IMPACTS OF THE PROPOSED REGULATION

A. Summary of Economic Impacts

The cap-and-trade program will lead to increased investment in efficient buildings 

and technologies and in advanced fuels. At expected allowance prices, these 

investments reduce fuel use by 2 to 4 percent in 2020, while economic growth 

between 2007 and 2020 continues at a rate virtually on par with current 

projections. Impacts on long-term projected growth rates in personal income and 

employment are similarly small. Implementation of the program will, however, 

shift investment and growth within the overall economy toward those sectors 

driven by the production of cleaner and more efficient technologies.

Implementing the cap-and-trade program can also help mitigate the economic 

consequences of continued reliance on fossil fuels. Experience in recent 

decades, such as the spike in world oil prices in the summer of 2008, has 

illustrated the economic costs of volatile energy prices on California’s economy. 

While this report does not attempt to quantify the benefits of reduced 

dependence on fossil fuels in the face of continued volatility of world energy 

prices, it does show that California can significantly reduce its dependence on 

these fuels and, therefore, its vulnerability to future price spikes.

The cap-and-trade program is designed to help drive investment into activities 

that result in lower GHG emissions. As businesses and consumers make 

investments in energy efficiency and clean fuels, some sectors will see significant 

new activity, including those that design or manufacture renewable technologies, 

and those that provide energy retrofits or efficiency improvements. Because the 

models used in this analysis are based on the structure of the economy in the 

base year, the analysis does not fully reflect the potential for increased growth in 

output and employment in sectors that could benefit from this new investment. 

This analysis should be viewed as a conservative estimate of the potential 

statewide impacts from the program. 

This economic analysis focuses exclusively on the economic effects in California 

of implementing the cap-and-trade program, and does not consider the avoided 

costs of inaction. The potential effects of climate change on California could 

cause severe economic damage. While California has developed a climate 

adaptation strategy to help alleviate these potential costs, the risk of potentially 

high economic costs from climate change in California remains real.86

 

86 2009 California Climate Adaptation Strategy. 2009. California Natural Resources Agency. 

Found at: http://www.climatechange.ca.gov/adaptation/. 
VIII-2

While California acting alone cannot reduce emissions sufficiently to change the 

course of climate change worldwide, California’s leadership has played, and 

continues to play, a critical role in moving federal and international climate policy 

forward. Successful implementation of AB 32, including the cap-and-trade 

program, has the potential to help move climate policy in a positive direction at 

the state, regional, and federal levels in the coming years. The magnitude of the 

impacts that California could face from climate change provide a useful context 

for understanding the significance of the relatively modest economic costs 

associated with taking action to reduce California’s GHG emissions. Overall, staff 

finds no significant adverse impacts on California business or consumers as a 

whole as a result of the proposed regulation. 

B. Legal Requirements

Section 11346.3 of the Government Code requires State agencies to assess the 

potential for adverse economic impacts on California business enterprises and 

individuals when proposing to adopt or amend any administrative regulation. The 

assessment must include a consideration of the impact of the proposed 

regulation on California jobs, the expansion, elimination or creation of businesses, 

and the ability of California businesses to compete with businesses in other 

states.

Also, State agencies are required to estimate the cost or savings to any State or 

local agency and school district in accordance with instructions adopted by the

Department of Finance (DOF). The estimate shall include any non-discretionary 

cost or savings to local agencies and the cost or savings in federal funding to the 

State.

Finally, Health and Safety Code section 57005 requires the ARB to perform an 

economic impact analysis of submitted alternatives to a proposed regulation 

before adopting any major regulation. A major regulation is defined as a 

regulation that will have a potential cost to California business enterprises in an 

amount exceeding $10 million in any single year.

This Chapter provides a description of the methodology used to estimate costs,

as well as ARB staff’s analysis of the economic impacts on California businesses 

and State and local agencies.

C. Cap-and-Trade Program Design

The main design elements of the cap-and-trade program are described in Table 

VIII-1. The analysis is performed with the assumption that no regional or federal
VIII-3

climate program is in place prior to 2020.87

The modeling uses allowance prices that rise by a fixed percentage each year. 

Banking of allowances for future use is allowed without limitation. In the early 

years, relatively low-cost abatement opportunities are available. Thus, banking 

motivates emitters to over-comply in early years if those low-cost reductions can 

be credited against compliance obligations in later years. 

 Furthermore, the analysis does not 

speculate about polices that may be adopted to reach targets beyond the 2020 

goal established by AB 32. 

Table VIII-1: Cap-and-Trade Program Elements

1. Region California

2. GHG Pollutants CO2, CH4, N2O, SF6, PFC, NF3 and HFC

3. Covered Sectors

2012–2014 Electricity and large industrial

2015–2020

Electricity, large industrial, transportation fuels, commercial 

and residential fuels, and small industrial

4. Cap Trajectory Linear phase-in

5. Allocation 100 percent auction for the electricity sector

6. Offsets Limited to 8 percent of emissions

7. Banking Allowed without limitation

8. Allowance Reserve

Allowances from the Reserve made available at $40, $45,

and $50/metric ton in 2012, rising to $60, $67, and 

$75/metric ton in 2020

D. Costs and Benefits

The cap-and-trade program does not specify how or where emissions reductions 

will be made. Reductions will be made by covered sources if the cost of making 

reductions is less than the cost of acquiring allowances and offsets. Reductions 

will also be made throughout the economy as a result of increased investment in 

energy efficiency and energy conservation. 

 

87 The regulation allows linking with other programs, including those being developed by other 

WCI jurisdictions. However, a decision to link will require a separate regulatory action subject to 

the formal rulemaking process, including requirements for an economic analysis.
VIII-4

Compliance options available to California producers and consumers are 

discussed in Appendix F: Compliance Pathway Analysis. In this economic 

analysis, energy and economic models are used to generate estimates of the 

potential compliance costs and the associated economic impacts.

The financial effects of the cap-and-trade program can be divided into four main 

categories:

• Transaction costs (for covered sectors only).

• Changes in device and/or process expenditures.

88

• Changes in fuel expenditures.

• Changes in device operation and maintenance expenditures.

In addition to analyzing these financial effects, this analysis also examines the 

macro-economic effects on California’s economy. 

Reductions in fuel use brought on by cap-and-trade will also reduce criteria 

pollutant emissions, as discussed in Chapter VII: Co-Pollutant Emissions 

Assessment and in Appendix P: Co-Pollutant Emissions Assessment. This 

analysis does not attempt to measure the economic benefits from reductions in 

criteria pollutants. 

1. Transactions Costs

Transaction costs apply only to facilities with a compliance obligation. These 

costs can be grouped into three categories: (1) early implementation costs; 

(2) monitoring, reporting, and verification costs; and (3) trading costs.

Early implementation costs are fixed costs that are incurred only once, before the 

program launch; for example, the familiarization with program rules and 

guidelines, calculating baseline emissions, and the purchase of any necessary 

capital equipment. Annualized across the life span of the program, these costs 

would be significantly lower than the other transaction cost components for most 

of the program’s participants. 

The costs for monitoring, reporting, and verification of emissions are considered 

a part of the ARB Mandatory Reporting Rule and are not considered as 

additional in this analysis. However, staff notes that over time, the costs for 

 

88 Devices are mechanical end-uses of energy, such as lighting, space heating, or air conditioning, 

while process reflects building shell improvements, such as insulation, or industrial process 

improvements.
VIII-5

monitoring, reporting, and verification of emissions should decline as a result of 

learning-by-doing and increased competition among verifiers. For example, a 

survey of Irish firms in the EU ETS found that for one quarter of the respondents, 

monitoring, reporting, and verification costs had decreased over the first three 

years of the EU ETS.89

2. Expenditure Changes

 Based on analysis of existing programs, trading costs 

are not expected to be significant. Therefore trading costs will not be considered 

further in this analysis.

The cap-and-trade program will affect the cost of using fossil fuel-based energy, 

which in turn will affect the price of most goods and services throughout the 

California economy. Some covered entities will make efficiency improvements 

that will reduce their emissions and their fuel expenditures. Additionally, 

increases in energy costs will drive secondary emissions reductions by noncovered entities though increased energy efficiency, decreased purchases of 

energy-intensive goods and services, and conservation.

Since the cap-and-trade program does not specify how or where emissions 

reductions will occur, it is impossible to know what covered or non-covered 

entities will do in response to the cap-and-trade program. Possible compliance 

responses must therefore be estimated using models. The Energy 2020 model 

was used to estimate the change in emissions and energy prices, and in capital, 

process, operation and maintenance, and fuel expenditures associated with a 

price on CO2.

Energy 2020 is a detailed energy supply and demand and emissions accounting 

system of the Western United States. The model simulates the demand for all 

fuels for three residential categories, over 40 commercial and industrial 

categories, and three transportation categories. Additional detail on the Energy 

2020 model is presented in Appendix N: Supporting Documentation for the 

Economic Analysis and the Energy 2020 Inputs and Assumptions book.

90

Methods available for emissions reductions in Energy 2020 include:

• Fuel switching.

91

• Earlier replacement of devices.

 

89 Jaraite, J., F. Convery, and C. Di Maria. 2009. Transaction Costs of Firms in the EU ETS. 

University College Dublin, School of Geography, Planning and Environmental Policy, Richview, 

Clonskeagh, Dublin. 90 The Energy 2020 Inputs and Assumptions book can be found at: 

http://www.arb.ca.gov/cc/scopingplan/economics-sp/models/book1002.pdf. 91 Renewable electricity above the 33 percent Renewable Electricity Standard or transportation 

biofuel penetration above the Low Carbon Fuel Standard is not assumed to occur in the Energy 

2020 modeling.
VIII-6

• Purchase of devices with greater efficiency.

• Building shell improvements.

• Reductions in high-GWP gases.

Methods not available for emissions reductions in Energy 2020 include:92

• Carbon capture and sequestration.

• New nuclear power plants.

3. Economic Impacts

The overall impacts on the State economy are estimated using the 

Environmental Dynamic Revenue Assessment Model (E-DRAM). E-DRAM is a 

computable general equilibrium (CGE) model of the California economy. 

Computable general equilibrium models are standard tools of empirical analysis 

designed to assess the regional costs of GHG emissions limits that take into 

account all secondary effects that these policies could have on prices, 

commodity and factor substitutions, and incomes. 

The E-DRAM model was developed by Dr. Peter Berck of the University of 

California, Berkeley, in collaboration with the California Department of Finance 

and the Air Resources Board. The current model includes 188 distinct sectors: 

120 industrial sectors, 2 factor sectors (labor and capital), 8 household sectors, 

9 consumption sectors, 1 investment sector, 45 government sectors, and 1

sector that represents the rest of the world. 

More detail on the E-DRAM model is presented in Appendix N: Supporting 

Documentation for the Economic Analysis. 

E. Economic Analysis

This analysis presents estimated impacts for a range of possible allowance 

prices. A large number of factors influence the allowance price.93

 

92 These technologies are unlikely to be available for emissions reductions before 2020. They 

may play a role in a longer-run emissions-reduction strategy. 

 The 

technological and behavioral factors include the ease of substitution by firms to 

low-GHG methods of production, the extent to which consumers shift to low-GHG 

products in response to changes in prices, and the pace of technological 

progress. A number of policy factors also apply. These include the stringency of 

93 For a fuller discussion of these factors, see Allocating Emissions Allowances Under a California 

Cap-and-Trade Program, a report from the Economic and Allocation Advisory Committee. March 

2010. http://www.climatechange.ca.gov/eaac/documents/eaac_reports/2010-03-

22_EAAC_Allocation_Report_Final.pdf.
VIII-7

the overall cap and the reductions from other AB 32 policies. Other important 

policy factors include the extent of output-based updated free allocation, linkages 

with other markets, the availability and price of offsets, provisions for allowance 

banking and borrowing, and leakage.

Given the uncertainties about the nature of these factors, the allowance price 

cannot be predicted precisely. Rather, to evaluate potential economic impacts,

the allowance price is estimated based on a range of reasonable scenarios of 

technological opportunities and behavioral responses. 

In 2010, ARB conducted a joint analysis of the AB 32 Scoping Plan with Charles 

River Associates and Professor David Roland-Holst of the University of California,

Berkeley. The estimated 2020 allowance price in these three analyses ranged 

from about $20 to $100.94, 95, 96

Appendix E: Setting the Program Emissions Cap, presents detail on the number 

of allowances that will be made available and the reduction path for the proposed 

regulation. Cumulative projected emissions over 2012 through 2020 total 

2,948 MMTCO2e. The number of allowances that would be made available over 

those years is 2,674 million. The difference between these two numbers, 273 

million, represents the required program reductions, some of which may be 

achieved through projects that generate offset credits. However, approximately 

123 million allowances will be placed in the Reserve and only made available at 

the prescribed reserve prices. For allowance prices to remain below the reserve 

prices—that is, for none of the allowances from the Reserve to be used—

approximately 397 million metric tons must be reduced by 2020.

 The range of prices in those analyses depended 

on assumptions about the success of other AB 32 policies and whether offsets 

were allowed for compliance. 

Table VIII-2 presents the potential cumulative reductions for the years 2012 

through 2020 estimated in Energy 2020 that could occur at the various price 

levels, along with an estimate of the number of offsets that could be available for 

compliance at those prices. The number of offsets available each year is 

calculated using the following offset supply curve: 

Q (millions) = (P – 8) / 0.75

Q is the quantity of offsets available at price P in a given year

Regulations implementing AB 32 complementary policies in capped sectors that 

are either adopted or are likely to be adopted, such as the 33 Percent Renewable 

 

94 http://www.arb.ca.gov/cc/scopingplan/economics-sp/updated-analysis/updated_sp_analysis.pdf 95 http://www.arb.ca.gov/board/books/2010/042110/10-3-6-david-roland-holst-panelist.pdf 96 http://www.arb.ca.gov/cc/scopingplan/economics-sp/meetings/042110/bernstein.pdf
VIII-8

Energy Standard, the Low Carbon Fuel Standard, and the California Advanced 

Clean Cars Program, could account for more than 150 million cumulative tons of 

reductions.97

Based on the assumptions about internal reductions available to capped sectors, 

the availability of offsets and the reductions from AB 32 complementary policies, 

staff believe that the 397 million cumulative metric ton reduction requirement is 

likely to be met at an allowance price that falls within the range of $15 to $30 per 

metric ton in 2020. For example, at an allowance price of $30 metric ton, 

estimated reductions by covered sources total 114 million, while an estimate of 

offsets available at a $30/metric ton price total 177 million. Therefore, to achieve 

the 397 metric ton reduction, the complementary policies would have to provide 

for slightly over 100 million metric tons in reductions. To the extent that they do 

more, a lower allowance price would occur.

 Further reductions are anticipated from other complementary 

policies in capped sectors, such as aggressive energy efficiency or changes in 

land use and transportation planning. Finally, there would be additional 

reductions that come from price-induced conservation that are not captured in 

the Energy 2020 model. 

The 2020 prices used in this analysis include those that could be considered 

likely given the previous analyses and more recent estimates about emissions: 

prices of $10 and $20/metric ton at the start of the program in 2012, which 

equate to $15 and $30/metric ton in the year 2020; and the reserve trigger prices 

where additional allowances would be made available as part of the proposed 

cost containment mechanism: $40, $45, and $50/metric ton in 2012, which 

equate to $60, $67, and $75/metric ton in the year 2020. 98

Table VIII-2: Estimated Energy 2020 Cumulative Emissions Reductions, 

2012–2020

Expected

Price Range Reserve Prices

2020 Allowance Prices per Metric 

Ton of CO2e $15 $30 $60 $67 $75

Internal Reductions (Energy 2020) 99 114 148 156 166

Offsets 42 177 225 228 231

Total Available Reductions 141 291 373 384 397

 

97 Updated Economic Analysis of California’s Climate Change Scoping Plan: Staff Report to the 

Air Resources Board. March 2010. http://www.arb.ca.gov/cc/scopingplan/economics-sp/updatedanalysis/updated_sp_analysis.pdf. 98 The estimated increase in prices from 2012 to 2020 is based on a growth rate of 5 percent per 

year rounded to the nearest dollar. The auction floor price and prices for the allowance reserve 

all increase under the proposed regulation by 5 percent per year, plus inflation. 
VIII-9

The range of allowance prices used in this analysis is intended to illustrate the 

possible economic effects of several uncertainties. If the economy grows faster 

than currently forecast, or the other Scoping Plan measures achieve fewer 

cumulative reductions than expected, the cap-and-trade program would need to 

provide more reductions than previously estimated. On the other hand, if fewer 

offsets are available or the reductions estimated by Energy 2020 are more 

expensive than assumed, the cap-and-trade program would need to produce the 

same amount of reductions but would do so at higher allowance prices. 

F. Energy 2020 Estimated Price and Expenditures Changes

The estimated impacts on the cost of using fossil-based energy in 2020 from the 

proposed cap-and-trade program are detailed in Table VIII-3. These estimates

are based on full pass-through of allowance value to the consumers. While the 

analysis indicates that the cap-and-trade program will likely produce some 

increases in the cost of using energy, increased investments in efficiency and 

alternative fuels will also result in an overall decrease in fuel expenditures, as 

discussed below. The manner in which allowances are distributed is also likely 

to affect impacts. The potential effects of different allocation methods are 

discussed in Appendix J: Allowance Allocation and Appendix K: Leakage 

Analysis.

The change in energy costs induces consumers of energy to increase their 

energy efficiency. For example, a higher price on gasoline and diesel may induce 

some consumers to switch to smaller vehicles that are both more fuel-efficient 

but less expensive than the larger vehicles chosen without cap-and-trade. This 

analysis does not assume that economies of scale or learning effects cause the 

price of energy efficiency or delivering of alternative low-carbon fuels to decrease 

from those in the initial case, though such effects are likely.
VIII-10

Table VIII-3: Energy 2020 Estimated Cap-and-Trade Energy Price Changes 

in 2020

Expected

Price Range Reserve Prices

2020 Allowance 

Prices per Metric Ton 

of CO2e: $15 $30 $60 $67 $75

Residential

Electric 1% 3% 6% 7% 9%

Natural Gas 7% 14% 28% 31% 35%

Oil 5% 10% 21% 23% 26%

LPG 2% 4% 9% 10% 11%

Commercial 

Electric 1% 3% 7% 8% 9%

Natural Gas 8% 16% 32% 36% 40%

Oil 6% 12% 24% 26% 29%

LPG 3% 5% 11% 12% 13%

Industrial

Electric 1% 3% 8% 9% 11%

Natural Gas 6% 13% 26% 29% 32%

Coal 54% 107% 215% 240% 269%

Oil 4% 8% 17% 18% 21%

Transportation

Gasoline 4% 8% 15% 17% 19%

Diesel 2% 4% 9% 10% 11%

Price changes reflect only the contribution of cap-and-trade and do not reflect changes from other AB 32 

policies.

Table VIII-4: Energy 2020 Estimated 2020 Changes in Annualized Expenditures 

from Cap-and-Trade ($[2007]Millions)

details the estimated 2020 changes in investment and fuel expenditures induced 

by the cap-and-trade program. A more detailed breakdown of expenditures is 

provided in Appendix N: Supporting Documentation for the Economic Analysis. 

The investments in devices are annualized using a 5 percent real capital 

recovery factor over the life of the equipment. The fuel expenditures do not 

reflect the allowance value. At the prices modeled, the annual allowance value 

could be an additional $5 to $25 billion in 2020. The allowance value represents 

a transfer of income from among sectors of the economy. The allowance value 

is accounted for separately from the expenditures in the economy-wide analysis 

by increasing prices in the E-DRAM model.

The total cost estimates include both the change in fuel expenditures and the 

change in investment costs. These cost estimates become the inputs for the 

E-DRAM model to estimate the economy-wide impacts of the cap-and-trade 

program. As seen in Table VIII-4, rising energy costs drive purchases of devices 

of greater efficiency, which are generally more expensive at the outset. However 
VIII-11

the increase in fuel savings offsets much of this expenditure. As a result, the net 

change in expenditures remains fairly constant over the range of prices.

Table VIII-4: Energy 2020 Estimated 2020 Changes in Annualized 

Expenditures from Cap-and-Trade ($[2007]Millions)

Expected

Price Range Reserve Prices

2020 Allowance Prices per 

Metric Ton of CO2e: $15 $30 $60 $67 $75

Device Investment $3,359 $3,472 $3,709 $3,770 $3,847 

Process Investment $52 $93 $170 $187 $206 

Operating and Maintenance $1,007 $1,073 $1,203 $1,232 $1,266 

Fuel Expenditures* ($2,874) ($3,245) ($3,944) ($4,102) ($4,286)

Total $1,544 $1,393 $1,138 $1,086 $1,034 

2020–2012 Total Change $5,069 $4,530 $3,584 $3,390 $3,185 

Percent Change from No Policy Case

Device Investment 1.8% 1.8% 1.9% 2.0% 2.0%

Process Investment 0.0% 0.0% 0.1% 0.1% 0.1%

Operating and Maintenance 11.9% 12.6% 14.2% 14.5% 14.9%

Fuel Expenditures -1.9% -2.1% -2.6% -2.7% -2.8%

Total 0.2% 0.2% 0.2% 0.2% 0.2%

2020–2012 Total Change 0.1% 0.1% 0.1% 0.1% 0.1%

*Fuel expenditures do not include allowance value.

G. Economy-Wide Impacts from the Cap-and-Trade Program 

To assess the economy-wide effects of the cap-and-trade program, the 

estimated allowance price and the expenditure changes and offset expenditures 

are used as inputs to the E-DRAM model. A model such as E-DRAM is not 

meant to predict which sectors may experience increased growth because of 

new opportunities brought on by limiting GHG emissions, such as those that 

design or manufacture renewable technologies, or to predict the creation and 

growth of jobs in sectors driven by the production of cleaner and more efficient 

technologies. Because E-DRAM is based on historical data, the economy and 

the way the economy uses inputs to production such as energy or labor looks 

very similar in the future as it does today, only larger. 

The results shown in Table VII-5 use the costs presented in Table VIII-5 and 

assume that all allowance value is recycled as income to California consumers. 

Allowance value may be redirected to a number of different uses. In E-DRAM, 

the manner in which allowance value is redistributed has a greater effect on the 

impact to specific groups and less of an effect at the state level, as long as the 

value remains in-state. The 2020 state-level impacts are presented in Table 

VIII-5.
VIII-12

These results provide insight into the potential range of impacts that the cap-andtrade program could have on the California economy. The estimated impacts 

show relatively small changes in economic growth when compared to growth 

otherwise expected over 2007 to 2020. The Reference case forecast used in the 

E-DRAM model assumes that California gross state product will grow by about 

35 percent between 2007 and 2020. With imposition of the cap-and-trade 

program, the annual average growth in gross state product is reduced by only 

about one-tenths of 1 percent, under the expected allowance price assumption. 

These results indicate that at the state level, the cap-and-trade program does not 

have a significant adverse impact on California business or consumers as a 

whole, and that the rate of job creation under the proposed regulation is very 

similar to currently projected rates. 

Table VIII-5: E-DRAM Estimated 2020 Economic Impacts of the Cap-andTrade Program $(2007)

2020

No Cap

Expected

Price Range Reserve Prices

2020 Allowance Prices 

per Metric Ton of CO2e: 2007

and 

Trade $15 $30 $60 $67 $75 

Gross State Product 

($ Billions) $1,845 $2,498 $2,495 $2,491 $2,484 $2,482 $2,481

Personal Income 

($ Billions) $1,492 $2,024 $2,021 $2,019 $2,015 $2,014 $2,013

Income Per Capita 

($ Thousands) $39.3 $46.0 $46.0 $46.0 $45.9 $45.9 $45.9

Labor Demand 

(Millions) 16.35 18.40 18.34 18.30 18.22 18.20 18.18

Percent Change from No Policy Case

Gross State Product - - -0.1% -0.3% -0.6% -0.6% -0.7%

Personal Income - - -0.1% -0.2% -0.5% -0.5% -0.6%

Income Per Capita - - 0.0% -0.1% -0.2% -0.2% -0.2%

Labor Demand - - -0.3% -0.6% -1.0% -1.1% -1.2%

Annual Average Growth 2007–2020

Gross State Product - 2.4% 2.3% 2.3% 2.3% 2.3% 2.3%

Personal Income - 2.4% 2.4% 2.4% 2.3% 2.3% 2.3%

Income Per Capita - 1.2% 1.2% 1.2% 1.2% 1.2% 1.2%

Labor Demand - 0.9% 0.9% 0.9% 0.8% 0.8% 0.8%

It is not possible to verify all of the expenditure data used in Energy 2020, so staff 

conducted a sensitivity analysis to evaluate the potential for expenditures to be 

greater than estimated by the model. In this sensitivity case, the change in 

device investment, process investment, and operating and maintenance 

expenditures used in the previous example (Table VIII-4) were doubled. Since 

the change in investment and operating and maintenance expenditures for 
VIII-13

passenger cars and trucks were negative in the initial analysis, reflecting the 

purchase of smaller less expensive vehicles, these values were set to zero.

The 2020 state-level impacts for the cost sensitivity are presented in Table VIII-6. 

The effect of doubling all expenditures except for fuel expenditures results in 

slightly greater economic impacts, primarily at the lower allowance prices. At 

higher allowance prices, the estimated impacts are driven more by the allowance 

value and less by the expenditures. 

Table VIII-6: E-DRAM Estimated 2020 Economic Impacts of the Cap-andTrade Program With Device, Process, and Operating and Maintenance 

Expenditures Doubled $(2007)

2020

No CapandTrade

Expected

Price Range Reserve Prices

2020 Allowance Prices 

per Metric Ton of CO2e: 2007 $15 $30 $60 $67 $75 

Gross State Product 

($ Billions) $1,845 $2,498 $2,488 $2,484 $2,476 $2,474 $2,472

Personal Income 

($ Billions) $1,492 $2,024 $2,016 $2,013 $2,008 $2,007 $2,005

Income Per Capita 

($ Thousands) $39.3 $46.0 $45.9 $45.9 $45.8 $45.8 $45.8

Labor Demand 

(Millions) 16.35 18.40 18.31 18.27 18.18 18.16 18.13

Percent Change from No Policy Case

Gross State Product - - -0.4% -0.6% -0.9% -1.0% -1.0%

Personal Income - - -0.4% -0.5% -0.8% -0.9% -0.9%

Income Per Capita - - -0.2% -0.3% -0.4% -0.4% -0.4%

Labor Demand - - -0.5% -0.7% -1.2% -1.3% -1.5%

Annual Average Growth 2007–2020

Gross State Product - 2.4% 2.3% 2.3% 2.3% 2.3% 2.3%

Personal Income - 2.4% 2.3% 2.3% 2.3% 2.3% 2.3%

Income Per Capita - 1.2% 1.2% 1.2% 1.2% 1.2% 1.2%

Labor Demand - 0.9% 0.9% 0.9% 0.8% 0.8% 0.8%

H. Cost-Effectiveness

This section discusses the cost-effectiveness of the proposed regulation. AB 32 

requires the Board to consider cost-effectiveness of each GHG control measure 

it adopts. The values must be expressed in dollars per metric ton of CO2e

emissions reduced. AB 32 does not specify what costs should be included in 

these calculations nor does it provide criteria to assess if a regulation is costeffective, beyond directing ARB to adopt regulations “to achieve the maximum 

technologically feasible and cost-effective reductions...in furtherance of 

achieving the statewide greenhouse gas emissions limit” (HSC §38562[a]).
VIII-14

A cap-and-trade program is a market-based mechanism that helps establish a 

common marginal cost of reductions (i.e., a common cost of the next action to be 

taken to reduce emissions) across all covered entities by providing for the trading 

of allowances. This common cost will encourage those who can reduce 

emissions most cheaply to do so, achieving the pollution reduction at the lowest 

cost to society. The measure of cost-effectiveness is therefore the estimated 

allowance price.

As previously discussed, many factors influence the allowance price, making it 

impossible to predict with precision. Rather than attempting to predict a specific 

price, this analysis has used a series of time profiles based on reasonable 

estimates of technological opportunities and behavioral responses under various 

scenarios. The results show that the needed reductions could be achieved at 

allowance prices in 2020 in the range of $15 to $30 per metric ton. Should likely 

prices not prove accurate, the program has established price containment 

measures that would come into effect to mitigate excessively high prices. Table 

VIII-7 shows the cost-effectiveness of the proposed cap-and-trade regulation in 

2020 for the expected range of prices. 

Table VIII-7: Cost-Effectiveness of the Proposed Cap-and-Trade Regulation 

in 2020

($ per Metric Ton of CO2e)

Expected

Price Range

Allowance Price in 2020 $15–$30

I. Potential Impacts on Small Business

Very few small businesses have enough emissions to be regulated directly under 

the cap-and-trade program. Most foreseeable small business impacts will result

from changes in energy expenditures. Therefore, this analysis focuses on how 

implementation of the program could affect expenditures that small businesses 

make on electricity and natural gas and how such shifts could affect their 

profitability. ARB will continue to seek ways to measure impacts and report to 

the Board as the program is implemented.

Under a contract with ARB, Dun and Bradstreet (D&B) provided ARB with data 

from a statistical data model that estimates the portion of revenue that 

businesses spend on energy. The model is based on D&B marketing files from 

approximately 17 million businesses nationwide including over 2.1 million in 

California. The annual spending on electricity and natural gas was calculated for 

affected businesses as follows:

• D&B collected data on monthly electricity and natural gas bills for 

approximately 628,000 businesses nationally from 18 utilities nationwide, 

including two California utilities, from April 2007 to March 2008.
VIII-15

• Annual spending on electricity and natural gas were calculated for these 

businesses by summing the monthly bills.

• Of these 628,000 businesses, D&B has revenue data for 210,000.

• Revenue data were available for a greater number of large businesses in 

the sample. Thus, the sample distribution was adjusted to represent the 

true universal distribution of the D&B database of 17 million businesses.

Staff analyzed the California industries with the greatest expenditures on retail

electricity and natural gas as a percentage of their revenue. These industries are 

primarily service-related and serve local markets. The price changes displayed 

in Table VIII-3 were used to estimate the change in the share of revenue spent

on energy. This estimate assumes that these industries make no changes in 

their energy use in response to the price changes. Table VIII-8 reports the 

results. Additional detail on this analysis is provided in Appendix N: Supporting 

Documentation for the Economic Analysis. 

Under the likely range of allowance prices, most sectors experience less than a 

2 percent change in the share of revenue spent on energy. Even at the highest 

reserve price, most sectors experience less than a 4 percent change. The 

majority of the listed business categories are those that serve local markets such 

as trailer parks and camps, hotels, barbershops, bakeries, etc. Out-of-state 

businesses cannot serve these local markets. As a result, most California small 

businesses are not likely to face competitiveness issues relative to out-of-state 

businesses. 

The potential impact estimated here may be high because small businesses, like 

any other businesses, are likely to respond to the increase in energy prices by 

investing in energy-efficient technologies to achieve energy savings. In light of 

many public incentive programs available, most small businesses should not 

have difficulties in obtaining the required capital for investment in energy-efficient 

technologies. The savings from electricity efficiency improvements are likely to 

partially offset or mitigate the impact of any increase in electricity prices and 

could mean decreased energy bills even in the face of increased prices.

J. Potential Impacts on California Business Competitiveness

ARB has closely analyzed the potential impact of a cap-and-trade program on 

California business competitiveness, and the proposed regulation includes 

methods to reduce competitiveness loss though the allocation process, such as 

through output-based updated free allocation. The proposed allowance 

distribution system is designed to reduce the potential for competitive losses to 

California business such that there should be minimal impact. The allocation 

system is discussed in Appendix J: Allowance Allocation and Appendix K: 

Leakage Analysis. 
VIII-16

Additionally, California is working closely with our partners in the Western 

Climate Initiative (WCI) and with the federal government to implement a larger 

climate change program to further reduce the potential for competitiveness loss 

that could arise from the implementation of a California-only cap-and-trade 

program. The proposed regulation has been designed to facilitate future linkage 

with other cap-and-trade programs. 
VIII-17

Table VIII-8: Range of Impact on Average Percentage of Revenue Spent on Energy

Energy 

Expenditures/ 

Revenue

(without 

program)

Change in Energy Expenditures/ Revenue 

at Given Cap-and-Trade Program Allowance Prices

(2020 Allowance Prices per Metric Ton of CO2e)

Expected

Price Range Reserve Prices

SIC Business Category $15 $30 $60 $67 $75

7215 Coin-Operated Laundries and Cleaning 22.1% 1.4% 2.7% 5.6% 6.2% 7.0%

7219 Laundry and Garment Services 15.3% 0.8% 1.5% 3.2% 3.6% 4.0%

8641 Civic and Social Associations 14.4% 0.6% 1.2% 2.5% 2.8% 3.1%

7021 Rooming and Boarding Houses 14.3% 0.6% 1.3% 2.7% 3.1% 3.5%

7041 Membership-Basis Organization Hotels 13.7% 0.6% 1.3% 2.7% 3.0% 3.4%

7033 Trailer Parks and Campsites 13.3% 0.5% 1.1% 2.2% 2.5% 2.8%

7241 Barber Shops 11.9% 0.5% 1.0% 2.1% 2.4% 2.7%

6719 Holding Companies 11.8% 0.5% 1.0% 2.1% 2.4% 2.7%

7011 Hotels and Motels 11.3% 0.5% 1.0% 2.0% 2.3% 2.6%

7032 Sporting and Recreational Camps 11.0% 0.3% 0.7% 1.5% 1.7% 1.9%

8351 Child Day-Care Services 10.3% 0.4% 0.9% 1.8% 2.1% 2.3%

8231 Libraries 10.2% 0.4% 0.7% 1.6% 1.7% 2.0%

5461 Retail Bakeries 10.1% 0.3% 0.7% 1.5% 1.7% 1.9%

5813 Drinking Places 10.0% 0.4% 0.8% 1.6% 1.8% 2.0%

7231 Beauty Shops 9.9% 0.4% 0.8% 1.6% 1.8% 2.1%

8361 Residential Care 8.9% 0.3% 0.7% 1.4% 1.6% 1.8%

4941 Water Supply 8.7% 0.3% 0.6% 1.3% 1.5% 1.6%

7217 Carpet and Upholstery Cleaning 8.0% 0.2% 0.5% 1.0% 1.2% 1.3%

5441 Candy, Nut, and Confectionery Stores 7.8% 0.2% 0.5% 1.0% 1.1% 1.3%

SIC = Standard Industrial Classification code
VIII-17

K. Potential Impacts on Individual Consumers

Individual consumers will not be directly affected by the cap-and-trade program, 

but will see indirect effects from changes in energy prices. Households that use

less carbon (directly via energy consumption and indirectly via consumption of 

goods and services that are produced or distributed using energy) will be less 

affected than those that use more carbon. Assessing how these price changes 

affect consumer well-being depends on whether and how income from auction of 

allowances is returned to consumers. Further discussion on the uses of 

allowance value for compensation of households can be found in Appendix J: 

Allowance Allocation.

Table VIII-9: Energy 2020 Estimated 2020 Changes in Residential 

Annualized Expenditures

Expected Price Range Reserve Prices

2020 Allowance Prices per 

Metric Ton of CO2e: $15 $30 $60 $67 $75 

Residential $(2007)Millions

Investment* and O+M 1,484 1,643 1,960 2,034 2,122

Fuel** (337) (411) (547) (577) (612)

Total 1,146 1,232 1,413 1,457 1,510

Passenger

Investment* and O+M (106) (192) (363) (403) (448)

Fuel** (484) (558) (700) (732) (768)

Total (591) (751) (1,063) (1,135) (1,216)

Percent Change from No Policy Case

Residential

Investment* and O+M 0.8% 0.9% 1.0% 1.1% 1.1%

Fuel** -1.4% -1.7% -2.3% -2.4% -2.6%

Total 0.5% 0.6% 0.7% 0.7% 0.7%

Passenger

Investment* and O+M -0.1% -0.1% -0.2% -0.3% -0.3%

Fuel** -0.8% -0.9% -1.2% -1.2% -1.3%

Total -0.3% -0.3% -0.5% -0.5% -0.6%

*Includes investment in devices (mechanical end-uses of energy, such as lighting, space heating 

or air conditioning) and process investment (e.g., building shell improvements).

**Fuel expenditures do not include allowance value.

Table VIII-9 details the estimated 2020 changes in investment, operating, and 

maintenance and fuel expenditures for the residential and passenger sectors 
VIII-18

resulting from the cap-and-trade program.99

Under any of the prices analyzed, consumer residential net spending in 2020 

increases by just over one-half of a percent. Passenger investment decreases,

reflecting some price-induced shifts to smaller, less-expensive vehicles. 

 As discussed earlier, devices are 

mechanical end-uses of energy, such as lighting, space heating, or air 

conditioning while process reflects building shell improvements. The fuel 

expenditures do not reflect the allowance value. The combined share of the 

allowance value from the Residential and Passenger sectors could be more than 

40 percent. The allowance value is treated separately from the expenditures in 

the economy-wide analysis. 

L. Potential Cost to Local, State, and Federal Agencies

The proposed regulation would impose direct requirements on local government 

agencies, specifically municipal utilities, that are directly responsible for emitting 

over 25,000 MTCO2e per year. However, municipal utilities should be able to 

use their existing administrative mechanisms to pass on the fee costs to their 

customers. In this case there would be no net fiscal impact. State and Local 

governments will face higher prices for products they purchase as businesses 

pass on costs. 

The proposed regulation would impose direct compliance requirements on the 

State Department of Water Resources, which directly imports power from a coalfired plant with which it has an ownership contract through 2013. However, there 

would be no net fiscal impact if DWR is able to use its existing administrative 

mechanisms to pass the fee costs on to customers. Based on 2006 electricity 

imports, DWR would incur direct costs of about $19.5 million during 2012. ARB 

understands that the DWR contract for Reid Gardner power plant expires in 2013, 

so DWR should owe no costs after the contract expires.

The proposed regulation will impose direct compliance requirements on several 

state universities. Purchase of allowances could be about $10 million.

Table VIII-10 presents an estimate of the potential allowance costs for 

government agencies in California.

 

99 The passenger sector includes passenger cars and trucks, and also contains expenditures 

from commercial passenger transit, such as buses or trains.
VIII-19

Table VIII-10: Government Annual Allowance Purchase Cost

$(2007)Millions Initial Ongoing

University of California $7.8 $7.8 

California State University $2.3 $2.3 

DWR (Reid Gardner)* $19.5 $0.0 

Total $29.7 $10.2 

*DWR contract expires in 2013.
VIII-20

This Page Intentionally Left Blank
IX-1

IX SUMMARY AND RATIONALE FOR PROPOSED REGULATION

The proposed cap-and-trade Regulation is designed to reduce emissions of 

greenhouse gases (GHG) by establishing a cap covering about 85 percent of the 

State’s GHG emissions and allow trading to ensure cost-effective emissions 

reductions. This section discusses the requirements and rationale for each 

provision of the proposed regulation.

Subarticle 1. Table of Contents.

Section 95800. Table of Contents.

This section provides the table of contents for the regulation.

Summary of Section 95800.

This section is necessary to provide the structure of the regulation and help guide 

the public through the regulatory provisions.

Rationale for Section 95800.

Subarticle 2. Purpose and Definitions.

Section 95801. Purpose.

This section states the purpose of the regulations. Specifically, the purpose of 

this regulation is to reduce greenhouse gas emissions by establishing an 

aggregate statewide limit on GHG emissions from sources specified in this 

regulation.

Summary of Section 95801.

This section is needed to ensure that the regulated public and other market 

participants understand that this regulation will reduce emissions to help achieve 

the goals of AB 32.

Rationale for Section 95801.

Section 95802. Definitions.

This section proposes definitions to the terms used in the regulation.

Summary of Section 95802.

It is necessary that ARB defines its terms as they apply to the California cap-andtrade program. Most of these terms are used in other articles and titles in the 

California Code of Regulations, Government Code sections or statutes, and it is 

Rationale for Section 95802.
IX-2

necessary that ARB be consistent with existing definitions to the extent that they 

apply to this regulation.

Subarticle 3. Applicability.

Section 95810. Covered Gases.

This section states the greenhouse gases (GHGs) that are required to be 

covered in AB 32.

Summary of Section 95810.

This section is required to identify the GHGs to which this regulation would apply. 

These gases were included because they are identified in AB 32.

Rationale for Section 95810.

Section 95811. Covered Entities.

Subsection (a) of the proposed regulation identifies the operator of a facility 

within California that has a compliance obligation as stated in subsections (a)(1) 

through (a)(12). 

Summary of Section 95811(a).

This provision is required to identify the industrial processes or operations to 

which this regulation would apply.

Rationale for Section 95811(a).

Subsection (a)(1) proposes to cover annual stationary combustion and process 

emissions from cement production. 

Summary of Section 95811(a)(1), Cement Production.

It is necessary to include these producers because cement production emissions 

represent a large share of California stationary source greenhouse gas 

emissions. 

Rationale for Section 95811(a)(1).

Subsection (a)(2) proposes to cover emissions from electricity and thermal output 

generated at cogeneration units. 

Summary of Section 95811(a)(2), Cogeneration.
IX-3

It is necessary to include emissions from cogeneration units because these units 

are widely used by industries and represent a large share of California GHG 

emissions. The use is expected to grow and the efficiency is expected to 

improve.

Rationale for Section 95811(a)(2).

Subsection (a)(3) proposes to cover annual stationary combustion and process 

emissions from glass production.

Summary of Section 95811(a)(3), Glass Production.

It is necessary to include emissions from glass production because the process 

is highly emissions intensive and represents California GHG emissions.

Rationale for Section 95811(a)(3).

Subsection (a)(4) proposes to cover annual emissions associated with hydrogen 

production processes, flares, and destruction devices.

Summary of Section 95811(a)(4), Hydrogen Production.

It is necessary to include emissions from hydrogen production because the 

process is highly emissions intensive and represents California GHG emissions.

Rationale for Section 95811(a)(4).

Subsection (a)(5) proposes to cover annual combustion and process emissions 

associated with iron and steel production.

Summary of Section 95811(a)(5), Iron and Steel Production.

It is necessary to include emissions from iron and steel production because the 

process is emissions intensive and represents California GHG emissions.

Rationale for Section 95811(a)(5).

Subsection (a)(6) proposes to cover annual combustion and process emissions 

associated with quick lime production.

Summary of Section 95811(a)(6), Lime Manufacturing.

It is necessary to include emissions from lime production because the process is 

emissions intensive and represents California GHG emissions.

Rationale for Section 95811(a)(6).

Summary of Section 95811(a)(7), Nitric Acid Production.
IX-4

Subsection (a)(7) proposes to cover annual N2O mass emissions from each nitric 

acid train.

It is necessary to include emissions from nitric acid production because it is very 

emissions intensive and represents California GHG emissions.

Rationale for Section 95811(a)(7).

Subsection (a)(8) proposes to cover stationary and process sources of the 

following: offshore petroleum and natural gas production facilities, onshore 

natural gas processing facilities, onshore natural gas transmission compression 

facilities, underground natural gas storage facilities, liquefied natural gas storage 

facilities, and liquefied natural gas import and export facilities.

Summary of Section 95811(a)(8), Oil and Natural Gas Systems.

It is necessary to cover emissions from oil and natural gas systems as identified 

in this subsection because production activities are managed best at the state 

level, where regional and local conditions are understood and where regulations 

can be tailored to fit the needs of the local environment. Natural gas systems are 

proposed as additions to those process sources included in the current ARB 

MRR, including cement production, power plants, petroleum refineries, and 

hydrogen plants. The ARB staff proposal would affect all petroleum and natural 

production operations in California where an entity’s emissions equal or exceed 

the cap-and-trade threshold.

Rationale for Section 95811(a)(8).

Subsection (a)(9) proposes to cover emissions from calciners, cat cracking, other 

cat regeneration, process vents, asphalt production, sulfur recovery, flares, and 

destruction devices.

Summary of Section 95811(a)(9), Petroleum Refining.

It is necessary to include emissions from petroleum refineries because refining 

processes emissions represent a large share of California stationary source 

greenhouse gas emissions and are emissions intensive.

Rationale for Section 95811(a)(9).

Subsection (a)(10) proposes to cover annual emissions from a process in the 

manufacture of paper and paperboard, which can be split into three steps: pulp 

making, pulp processing, and paper/paperboard production.

Summary of Section 95811(a)(10), Pulp and Paper Manufacturing.

Rationale for Section 95811(a)(10).
IX-5

It is necessary to include emissions from pulp and paper because during the 

manufacturing process, the individual fibers formed into paper sheets (called 

pulp) create GHG emissions.

Subsection (a)(11) proposes to cover emissions from electricity generated for 

consumption solely onsite. 

Summary of Section 95811(a)(11), Self-Generation of Electricity.

It is necessary to include emissions from electricity self-generation because it is a 

significant source of emissions that is not captured elsewhere. 

Rationale for Section 95811(a)(11).

Subsection (a)(12) proposes to cover annual stationary combustion emissions 

that have not been captured under subsection (a)(1) through (a)(11).

Summary of Section 95811(a)(12), Stationary Combustion.

It is necessary to include emissions from stationary combustion because it 

captures steam-producing units that combust municipal solid waste or solid 

biomass fuels, and it generates GHGs.

Rationale for Section 95811(a)(12).

Subsection (b) proposes to cover first deliverers of electricity delivered to the 

California electricity transmission and distribution system. 

Summary of Section 95811(b), First Deliverers of Electricity.

It is necessary to include electricity deliverers because they represent a 

significant amount of emissions from relatively few sources and accurate 

emissions reporting and monitoring methods exist for these types of sources.

Rationale for Section 95811(b).

Subsection (b)(1) proposes to cover operators of electricity generating facilities in 

California that deliver electricity to the California electricity transmission and 

distribution system. 

Summary of Section 95811(b)(1), Electricity Generating Facilities.

It is necessary to include emissions from all electricity consumed in the State 

according to AB 32 (HSC 38530(b)(2)).

Rationale for Section 95811(b)(1).

Summary of Section 95811(b)(2), Electricity Importers.
IX-6

Subsection (b)(2) proposes to cover electric power entities that import electricity.

It is necessary to include emissions from electric power entities, California retail 

providers, multijurisdictional retail providers, marketers, Western Area Power 

Administration (WAPA), and California Department of Water Resources (DWR) 

because emissions from this sector account for a large share of California GHG 

emissions.

Rationale for Section 95811(b)(2).

Subsection (c) proposes to include emissions associated with the distribution or 

use of natural gas in California.

Summary of Section 95811(c), Suppliers of Natural Gas.

It is necessary to include emissions from distributers and users of natural gas 

because combustion of natural gas is responsible for 26 percent of GHG 

emissions in California.

Rationale for Section 95811(c).

Subsection (c)(1) proposes to include combustion emissions associated with 

public utility gas corporations operating in California.

Summary of Section 95811(c)(1), Public Utility Gas Corporation.

It is necessary to include combustion emissions from public utility gas 

corporations because it is at the most upstream point possible for natural gas 

consumption. LPG consignees who import LPG into California and natural gas 

liquid fractionators are required to report emissions for LPG, to be consistent with 

the desire of cap-and-trade to include suppliers of LPG as covered entities. 

Local Distribution Companies (LDC), which are divided into two categories in 

California—public utility gas corporations and publicly owned natural gas 

utilities—are required to report

Rationale for Section 95811(c)(1). 

Subsection (c)(2) proposes to include combustion emissions associated with 

publicly owned natural gas utilities operating in California.

Summary of Section 95811(c)(2), Publicly Owned Natural Gas Utilities.

It is necessary to include combustion emissions from publicly owned natural gas 

utilities because it captures emissions at the most upstream point possible for 

natural gas consumption.

Rationale for Section 95811(c)(2).
IX-7

Subsection (c)(3) proposes to include combustion emissions associated with 

operators of an intrastate pipeline, not included in subsections (c)(1) or (c)(2), 

that distributes natural gas directly to end users.

Summary of Section 95811(c)(3), Operators of Intrastate Pipelines.

It is necessary to include combustion emissions from every natural gas producer 

or consumer at the most upstream point possible for intrastate pipeline owners 

and operators that distribute natural gas for use in California. 

Rationale for Section 95811(c)(3).

Subsection (d) proposes to include offsite combustion emissions that result from 

petroleum products produced in or imported into California. Suppliers of these 

fuels include a position holder of one or more of the following fuels, or an enterer 

that imports one or more of the following fuels into California: reformulated 

blendstock for oxygenate blending (RBOB), Distillate Fuel Oil No. 1, and Distillate 

Fuel Oil No. 2.

Summary of Section 95811(d), Suppliers of RBOB and Distillate Fuel Oil.

It is necessary to include emissions that result from combustion of petroleum 

products that are mainly used for transportation purposes because these fuels 

result in a large share of the State’s GHG emissions.

Rationale for Section 95811(d).

Subsection (d)(1) proposes to include tailpipe combustion emissions that result 

from blended fuels that contain RBOB produced in or imported into California. 

Suppliers of RBOB include a position holder or an enterer that imports RBOB into 

California.

Summary of Section 95811(d)(1), RBOB.

It is necessary to include tailpipe combustion emissions from RBOB because 

they account for a large share of GHG emissions in California.

Rationale for Section 95811(d)(1).

Subsection (d)(2) proposes to include offsite combustion emissions that result 

from Distillate Fuel Oil No. 1 produced in or imported into California. Suppliers of 

this fuel include a position holder or an enterer that produces or imports Distillate 

Fuel Oil No. 1. The first point of receipt at the terminal is the actual point of 

regulation.

Summary of Section 95811(d)(2), Distillate Fuel Oil No. 1.

Rationale for Section 95811(d)(2).
IX-8

It is necessary to include tailpipe combustion emissions from Distillate Fuel Oil 

No. 1 because they account for a large share of GHG emissions in California.

Subsection (d)(3) proposes to include offsite combustion emissions that result 

from Distillate Fuel Oil No. 2 produced in or imported into California. Suppliers of 

this fuel include a position holder or an enterer that produces or imports Distillate 

Fuel Oil No. 2. The first point of receipt at the terminal is the actual point of 

regulation.

Summary of Section 95811(d)(3), Distillate Fuel Oil No. 2.

It is necessary to include tailpipe combustion emissions from Distillate Fuel Oil 

No. 2 because they account for a large share of GHG emissions in California.

Rationale for Section 95811(d)(3).

Subsection (e) proposes to include combustion emissions that result from 

liquefied petroleum gas produced in or imported into California. Suppliers 

include an operator of a refinery that produces liquid petroleum gas in California, 

an operator of a facility that fractionates natural gas liquids to produce liquid 

petroleum gas, and an importer of liquefied petroleum into California.

Summary of Section 95811(e), Suppliers of Liquefied Petroleum Gas.

It is necessary to include emissions from suppliers of liquefied petroleum gas 

because these fuels result in a large share of the State’s GHG emissions, when 

completely combusted.

Rationale for Section 95811(e).

Subsections (e)(1) through (e)(3)propose to include combustion emissions 

resulting from liquid petroleum gas produced in or imported into California. 

Suppliers include an operator of a refinery that produces liquid petroleum gas in 

California, an operator of a facility that fractionates natural gas liquids to produce 

liquid petroleum gas, and an importer of liquefied petroleum into California.

Summary of Section 95811(e)(1) through (e)(3).

It is necessary to include emissions from suppliers of liquefied petroleum gas 

because these fuels result in a large share of the State’s GHG emissions, when 

completely combusted. The proposed revised regulation will affect all suppliers of 

natural gas, as well as consignees who import liquefied petroleum gas (LPG) into 

the State of California where annual amounts of supplied or imported fuel, when 

completely combusted or oxidized, equals or exceeds the threshold.

Rationale for Section 95811(e)(1) through (e)(3).

Summary of Section 95811 (f).
IX-9

Section 95811(f) specifically includes CO2 emissions from blended fuels.

It is necessary to include emissions from suppliers of blended fuels because 

these fuels result in a large share of the state’s GHG emissions.

Rationale for Section 95811 (f).

Subsection (f) proposes to include CO2 emissions that result from the complete 

release of the product that they place into commerce. Suppliers of CO2 must 

report the mass of CO2 captured from production process units and extracted 

from production wells, and the mass of CO2 that is imported and exported.

Summary of Section 95811(g), Suppliers of Carbon Dioxide.

It is necessary to include emissions from suppliers of carbon dioxide because 

these products placed into commerce generate CO2 which results in emissions of 

GHG.

Rationale for Section 95811(g).

Section 95812. Inclusion of Thresholds for Covered Entities.

Subsection (a) establishes the inclusion thresholds for emissions associated with 

each covered entity based on its reported GHG emissions to U.S. EPA for the 

data year 2010. If an entity’s 2010 reported emissions exceed the inclusion 

threshold, it will be classified as a covered entity when this regulation becomes 

effective. The inclusion threshold for each covered entity is based on the subset 

of GHG emissions that generate a compliance obligation for that entity.

Summary of Section 95812(a).

This subsection is necessary to establish what the emissions threshold is based 

on and derived from.

Rationale for Section 95812(a).

Subsection 95812(b) proposes that if an entity’s aggregated, reported, or verified 

emissions in any data year from 2008 to 2010 equals or exceeds the thresholds 

in subsequent sections, the entity will be classified as a covered entity as of 

January 1, 2012.

Summary of Section 95812(b).

This subsection is necessary to establish under what circumstances an entity can 

trigger the inclusion threshold for covered entities.

Rationale for Section 95812(b).

Summary of Section 95812(b)(1), Operators of Facilities.
IX-10

Subsection (b)(1) establishes the inclusion threshold for emissions that result 

from facilities with operations and processes identified in section 95811(a). In 

their 2008–2009 program design recommendations, the WCI Partners expressed 

the desire to monitor what happens beneath the agreed-upon cap-and-trade 

threshold of 25,000 metric tons carbon dioxide equivalent (MTCO2e) (WCI 

Design Recommendations 2009).100 The Partners adopted a reporting threshold 

of 10,000 MTCO2e, to enable monitoring for leakage of emissions from sources 

below the cap threshold and to assess whether the cap threshold was 

appropriately set. The Partners wanted to be able to recommend subsequent 

action if the cap threshold had unanticipated economic or emissions 

consequences, and the lower reporting threshold would inform their review of 

market impacts. Thus, the threshold is set at 25,000 MTCO2e for the data year 

2010 and every year thereafter.

This inclusion threshold captures emissions from facilities with the largest 

amount of emissions without including small facilities. 

Rationale for Section 95812(b)(1).

Subsection (b)(2) establishes the inclusion threshold for emissions that result 

from first deliverers of electricity.

Summary of Section 95812(b)(2), First Deliverers of Electricity.

This subsection is necessary so first deliverers of electricity know the threshold 

they must exceed to be covered under the program.

Rationale for Section 95812(b)(2).

Subsection (a)(2)(A) proposes to include a threshold for emissions associated 

with in-state electricity generating facilities based on annual emissions from 

facilities at which the electricity originated. The threshold is set at 

25,000 MTCO2e for the data year 2010 and every year thereafter.

Summary of Section 95812(b)(2)(A), Electricity Generating Facilities.

This inclusion threshold captures emissions from facilities with the largest 

amount of emissions without including small facilities. 

Rationale for Section 95812(b)(2)(A). 

 

100 Western Climate Initiative (2008): Design Recommendations for the WCI Regional Cap-andTrade Program. http://www.westernclimateinitiative.org/component/remository/general/designrecommendations/Design-Recommendations-for-the-WCI-Regional-Cap-and-Trade-Program/
IX-11

Subsection (b)(2)(B) proposes to include emissions that result from generating 

electricity imported from a specified facility out-of-state if that facility’s annual 

GHG emissions are equal to or greater than 25,000 MTCO2e for the data year 

2010 and every year thereafter.

Summary of Section 95812(b)(2)(B), Electricity Importers of Specified Electricity.

This provision is necessary to set this emissions threshold to be comparable with 

in-state electricity generators, to comply with the interstate commerce clause.

Rationale for Section 95812(b)(2)(B).

Subsection (b)(2)(C) proposes to include all emissions that result from generating 

electricity imported from unspecified sources out-of-state, meaning that a 

covered entity must account for all emissions from all unspecified electricity 

imports.

Summary of Section 95812(b)(2)(C), Electricity Importers of Unspecified 

Electricity.

This provision is necessary to include all emissions that result from unspecified 

electricity imports because ARB cannot assign emissions to an unspecified 

facility.

Rationale for Section 95812(b)(2)(C).

Subsection (c) proposes to establish a threshold for carbon dioxide suppliers. 

The threshold is 25,000 MTCO2e per year. 

Summary of Section 95812(c).

This provision is necessary because it proposes the threshold for carbon dioxide 

suppliers. The threshold is based on the sum of its imported and exported carbon 

dioxide into and out of California. 

Rationale for Section 95812(c).

Subsection (d) proposes to establish a threshold for emissions that result from 

the combustion of fuels produced or imported from in California.

Summary of Section 95812(d).

This provision is necessary because it proposes the emissions threshold that will 

trigger an entity to be classified as a covered entity as of January 1, 2015.

Rationale for Section 95812(d).

Summary of Section 95812(d)(1), Fuel Suppliers.
IX-12

Subsection (d)(1) proposes to establish under what circumstances fuel suppliers 

may trigger the inclusion threshold before coverage in 2015.

This inclusion threshold captures emissions associated with suppliers with the 

largest amount of emissions without including small suppliers. 

Rationale for Section 95812(d)(1).

Subsection (d)(2) proposes to establish the threshold for an electricity importer of 

specified or unspecified source of electricity, which is zero.

Summary of Section 95812(d)(2), Electricity Importers.

This inclusion threshold is necessary because it proposes the emissions 

threshold that will trigger an entity to be classified as a covered entity as of 

January 1, 2015.

Rationale for Section 95812(d)(2).

Subsection (e) proposes the conditions for a covered entity to avoid a 

compliance obligation for a specified compliance period. 

Summary of Section 95812(e), Effect of Reduced Emissions on an Entity’s 

Compliance Obligation.

An entity that reduces its emissions, becomes more efficient, or produces less 

should not hold a compliance obligation for that compliance period, because it 

did not exceed the inclusion threshold for any year during that compliance period.

Rationale for Section 95812(e).

Subsection (e)(1) proposes to identify an entity whose reported GHG emissions 

drop below its annual threshold for an entire compliance period and will not hold 

a compliance obligation for that compliance period.

Summary of Section 95812(e)(1).

It is necessary to identify the period of time for which an entity’s reported 

emissions drop below its respective threshold, to identify for which compliance 

period the entity does not hold a compliance obligation.

Rationale for Section 95812 (e)(1). 

Subsection (e)(2) proposes to identify an entity whose processes and operations 

shut down permanently. A covered entity must fulfill its compliance obligations 

for that compliance period during which it shuts down and will not be subject to a 

compliance obligation for the following compliance period and any thereafter. A 

Summary of Section 95812 (e)(2). 
IX-13

reporter is not required to verify its emissions for the first full year of nonoperation following a permanent shutdown.

An entity that shuts down its operation and no longer emits GHGs should not 

hold a compliance obligation for compliance periods subsequent to the one in 

which it shuts down, because it will no longer exceed the inclusion threshold in 

subsequent compliance periods because, by default, its emissions will be zero.

This provision is included to prevent unnecessary financial burden of verification 

to reporters that shut down their operations.

Rationale for Section 95812 (e)(2).

Section 95813. Opt-In Covered Entities.

Subsection (a) proposes to include the entities in the categories identified in 

section 95811 that do not meet the inclusion threshold of section 95812 to 

voluntarily become a covered entity. 

Summary of Section 95813(a).

This provision is included to incentivize entities to implement more efficient 

processes and technologies to reduce their associated emissions, to receive a 

higher number of direct allocations of allowances based on the product outputbased benchmarking methodology.

Rationale for Section 95813(a).

Subsection (b) requires entities to apply for approval by the Executive Officer to 

be approved as an opt-in covered entity.

Summary of Section 95813(b).

This provision is necessary so ARB can determine if an entity meets the 

requirements set forth in subsection (a). 

Rationale for Section 95813(b).

Subsection (c) proposes that all opt-in covered entities are subject to all 

regulatory requirements that apply to covered entities, including reporting, 

verification, and compliance obligations.

Summary of Section 95813(c).

This provision is necessary so ARB can assign a compliance obligation to opt-in 

covered entities, and maintain program intensity.

Rationale for Section 95813(c).

Summary of Section 95813(d).
IX-14

Subsection (d) proposes to allow eligible opt-in covered entities to receive direct 

allocations of allowances.

This provision is included to incentivize entities to implement more efficient 

processes and technologies to reduce their associated emissions, to receive a 

higher amount of direct allocations of allowances based on the product outputbased benchmarking methodology.

Rationale for Section 95813(d).

Subsection (e) proposes that the inclusion of opt-in covered entities will not affect 

the California GHG allowances budgets established in Table 6-1 of the 

Regulation.

Summary of Section 95813(e).

This provision is included because staff is uncertain of how many opt-in covered

entities will apply for approval by the Executive Officer. The allowance budgets 

cannot be adjusted each time an opt-in covered entity is approved because the 

cap is set in the regulation to provide certainty to market participants of how 

many compliance instruments are available in all years of the program.

Rationale for Section 95813(e).

Subsection (f) proposes that an opt-in covered entity could opt out of the program 

at the end of each compliance period only if it has fulfilled its compliance 

obligations or has returned to ARB an equivalent number of allowances it 

received through direct allocations in that compliance period.

Summary of Section 95813(f).

Staff proposes that an opt-in covered entity can opt out of the program because 

its emissions are below the inclusion threshold, and it is not required to 

participate in the program in the first place. Staff proposes that an opt-in covered 

entity must stay in the program until its triennial surrender obligation is completed 

after the compliance period ends.

Rationale for Section 95813(f).

Section 95814. Voluntarily Associated Entities and Other Registered 

Participants.

Subsection (a)(1) proposes that an entity not identified as a covered entity or an 

opt-in covered entity could voluntarily register with the accounts administrator to 

become a Voluntary Associated Entity. These entities may acquire and hold 

California Compliance Instruments and participate in auctions. 

Summary of Section 95814(a)(1).
IX-15

This subsection is needed to allow entities that do not have a compliance 

obligation to participate in the cap-and-trade system. Qualifying entities may 

trade compliance instruments and voluntarily retire compliance instruments for 

the benefit of the environment. Allowing additional participants also increases 

market liquidity and creates a larger market.

Rationale for Section 95814(a)(1).

Subsection (a)(2)(A) proposes that an entity not identified as a covered entity or 

an opt-in covered entity could voluntarily register with the accounts administrator 

to become a Voluntary Associated Entity in order to acquire and hold California 

Compliance Instruments. 

Summary of Section 95814(a)(2)(A).

This provision is needed to allow additional participants interested in trading or 

voluntarily retiring compliance instruments to participate, increasing market 

liquidity and creating a larger market.

Rationale for Section 95814(a)(2)(A).

Subsection (a)(2)(B) proposes that an entity operating an offset project could 

voluntarily register with the accounts administrator to become a Voluntary 

Associated Entity. 

Summary of Section 95814(a)(2)(B).

This provision is needed because before ARB can issue offset credits to the 

operator of an offset project registered with ARB, the operator must have a 

Holding Account into which ARB can transfer the offset credits.

Rationale for Section 95814(a)(2)(B).

Subsections (b) through (b)(2) propose to allow entities that do not qualify to 

participate in the market or hold compliance instruments to register with the 

accounts administrator. These entities may include verifiers, verification bodies, 

Offset Project Registries, or other third parties approved pursuant to Subarticle 

14.

Summary of Section 95814(b) through (b)(2), Other Registered Participants.

These provisions are necessary to ensure the integrity of the emissions 

verification and offset credit creation functions. The registration requirement 

gives ARB the opportunity to ensure that verifiers, verification bodies, and Offset 

Project Registries are qualified, free of conflicts of interest, and adhere to the 

provisions of this regulation. ARB can best ensure this by being able to use the 

Rationale for Section 95814(b) through (b)(2).
IX-16

registration process to verify information on the entity, and to revoke registration 

(and prevent further participation) if the entity violates provisions of the regulation.

Subsection (c) proposes that a registered entity that has had its Holding Account 

revoked pursuant to section 95831(b)(1) may not hold compliance instruments.

Summary of Section 95814(c).

This provision is necessary because an entity may not participate in the cap-andtrade program if its Holding Account has been revoked due to a violation, to 

prevent further market disruption. ARB has an interest in protecting the integrity 

of the market.

Rationale for Section 95814(c).

Subarticle 4. Compliance Instruments.

Section 95820. Compliance Instruments Issued by Air Resources Board.

Subsection (a) identifies California Greenhouse Gas Emissions Allowances (CA 

GHG Allowances) as compliance instruments.

Summary of Section 95820(a), California Greenhouse Gas Emissions 

Allowances.

This provision is necessary so those participating in the program know which 

compliance instruments are valid.

Rationale for Section 95820(a).

Subsection (a)(1) proposes that CA GHG Allowances be issued by the Executive 

Officer. The amount of allowances issued by the Executive Officer will be equal 

to the schedule established in section 95841.

Summary of Section 95820(a)(1).

This provision is necessary so those participating in the market know how many 

allowances will be in the market, which creates market stability.

Rationale for Section 95820(a)(1).

Subsection (a)(2) proposes that each individual CA GHG Allowance issued by 

the Executive Officer be assigned a unique serial number that will also identify 

the year for which the allowance is issued.

Summary of Section 95820(a)(2).

Rationale for Section 95820(a)(2).
IX-17

This provision is necessary so that each allowance is uniquely identifiable and 

cannot be used more than once. The serial numbers allow ARB to track the 

owner of the allowance at all times.

Subsection (a)(3) proposes that each CA GHG Allowance is placed into a 

Holding Account that is controlled by ARB.

Summary of Section 95820(a)(3).

This provision is necessary because all allowances belong to ARB until they are 

put into the auction account or directly allocated to covered entities.

Rationale for Section 95820(a)(3).

Subsection (b) identifies offset credits issued by ARB as compliance instruments.

Summary of Section 95820(b), Offset Credits Issued by ARB.

This provision is necessary so those participating in the program know which 

compliance instruments are valid.

Rationale for Section 95820(b).

Subsection (b)(1) proposes that the Executive Officer issue and register offset 

credits.

Summary of Section 95820(b)(1).

This provision is necessary so that all offset credits used for compliance 

purposes meet the same requirements.

Rationale for Section 95820(b)(1).

Subsection (b)(2) limits offset credits’ use to the limit set forth in section 95855.

Summary of Section 95820(b)(2).

This provision is necessary because users of offset credits need to know the use 

of offset credits is limited. For justification of section 95855, please see below.

Rationale for Section 95820(b)(2).

Subsection (c) proposes the properties associated with each compliance 

instrument, specifically that each compliance instrument represents permission to 

emit up to one metric ton of CO2e. Additionally, the Executive Officer retains the 

right to revoke the authorization contained in the compliance instrument. Finally, 

compliance instruments do not constitute property or carry property rights.

Summary of Section 95820(c).
IX-18

This provision is necessary to inform holders of compliance instruments of the 

properties of compliance instruments. ARB has chosen to use a 1:1 ratio for 

compliance instruments to metric tons for administrative ease of calculation. 

Compliance instruments are created by ARB through AB 32, and are to be used 

solely for use as a compliance credit in California’s market. It is necessary for 

the Executive Officer to retain authority to terminate or limit the “authorization to 

emit” so that in the case of fraud or market manipulation, ARB has a mechanism 

to protect the market. Additionally, property rights cannot attach to the 

compliance instruments because, in the event of federal preemption in the capand-trade market or other conditions, California must have the ability to revoke 

the compliance instruments without creating a loss to the people of California.

Rationale for Section 95820(c).

Section 95821. Compliance Instruments Issued by Approved Programs.

Subsections (a) through (d) identify compliance instruments issued by other 

programs approved by ARB as compliance instruments that may be used to 

meet a compliance obligation.

Summary of Section 95821(a) through (d).

These provisions are necessary so those participating in the program know 

which compliance instruments are valid. For justification of the specific 

requirements, please refer to those sections below.

Rationale for Section 95821(a) through (d).

Subsection (e) identifies which compliance instruments issued by other approved 

programs are subject to the quantitative use limit.

Summary of Section 95821(e).

This provision is necessary so those participating in the program know which 

compliance instruments issued by other approved programs are subject to the 

quantitative use limit. For justification of section 95855, please see above.

Rationale for Section 95821(e).

Subarticle 5. Registration and Accounts.

Section 95830. Registration with ARB.

Subsection (a) proposes that the Executive Officer may serve as administrator of 

the accounts and tracking system or contract for the services.

Summary of Section 95830(a).
IX-19

This provision is necessary because ARB has not operated a tracking system of 

such complexity. ARB may find it is more efficient and less expensive to contract 

with a third party.

Rationale for Section 95830(a).

Subsection (b) proposes that the Executive Officer must approve an entity’s 

registration with ARB or that the entity is already registered with an external 

program approved by ARB before it can purchase or receive an allocation of 

allowances, buy offsets, or operate a project that will result in the creation of 

offsets. 

Summary of Section 95830(b).

This provision is necessary because ARB needs to maintain a complete record of 

all transactions involving California compliance instruments. To do this, ARB 

must know what entities are involved in any transaction. The registration 

requirement ensures anyone involved in transactions is subject to ARB 

requirements to report transactions.

Rationale for Section 95830(b).

Subsection (c) proposes that applicants for registration must submit information 

describing why they are participating in the system. They must also designate an 

authorized account representative, who will have the ability to make transactions 

and report them to ARB.

Summary of Section 95830(c), Requirements for Registration.

This provision is necessary because the applicant needs to identify how it 

qualifies for participation so ARB will know which rules to apply to the entity. 

Applicants also must identify any affiliated entities that are also participating in 

the system. This allows ARB to monitor transactions for potential collusion.

Rationale for Section 95830(c).

Subsection (c)(1)(A) requires submission of an application for registration. The 

applicant must supply the name and a description of the organization registering.

Summary of Section 95830(c)(1)(A).

The provision is necessary because ARB needs to collect basic information on 

registrants. 

Rationale for Section 95830(c)(1)(A).

Summary of Section 95830(c)(1)(B).
IX-20

Subsection (c)(1)(B) proposes that the applicant must identify how it qualifies to 

participate in the cap-and-trade system. The types of entities qualified to apply 

are identified in Subarticle 3.

The provision is necessary because Subarticle 3 identifies what types of entities 

may qualify to participate in the cap-and-trade system, as well as some that are 

prohibited from registering. Different rules apply to registrants depending on the 

category for which they are registering.

Rationale for Section 95830(c)(1)(B).

Subsection (c)(1)(C) proposes that applicants must identify affiliated entities that 

are also registering. 

Summary of Section 95830(c)(1)(C).

The provision is necessary because identification of affiliates is needed for ARB 

to monitor the transactions in the market. An entity has a “direct corporate 

association” if it has a specified level of ownership or control over another entity. 

An entity has an “indirect corporate association” if it has a direct corporate 

association with a second entity, which in turn has a direct corporate association 

with a third entity.

Rationale for Section 95830(c)(1)(C).

Subsection (c)(1)(D) proposes that applicants must disclose if they intend to hold 

compliance instruments which are actually owned by another entity.

Summary of Section 95830(c)(1)(D).

The provision is necessary because ARB must be able to determine who is 

making the decisions on transactions in the market. ARB must also be able to 

evaluate a limit on how many compliance instruments an entity may control.

Rationale for Section 95830(c)(1)(D).

Subsection (c)(1)(E) proposes that the Executive Officer may reject an 

application based on information contained in the application or withheld from the 

application.

Summary of Section 95830(c)(1)(E).

The provision is necessary because ARB needs to ensure the integrity of the

program and regulating participants contributes to that integrity. ARB may deny 

registration if it concludes the applicant does not qualify to participate. In addition, 

ARB may use information it collects from monitoring the market to determine if 

Rationale for Section 95830(c)(1)(E).
IX-21

the applicant has provided false or misleading information, or has withheld 

information. These are grounds for disqualifying an applicant.

Subsection (c)(2) proposes that an applicant must designate individuals who are 

authorized to act on the applicant’s behalf to actually conduct transactions. 

Section 95832 contains the specific requirements for authorized account 

representatives.

Summary of Section 95830(c)(2).

The provision is necessary because ARB needs a record of who may file 

transactions or information on behalf of the applicant for administrative purposes. 

ARB will reject transactions or information filed by anyone not designated as an 

authorized account representative. 

Rationale for Section 95830(c)(2).

Subsection (d)(1) proposes that entities qualifying as covered entities must 

register.

Summary of Section 95830(d)(1).

The provision is necessary because ARB will need the registration information to 

administer the program.

Rationale for Section 95830(d)(1).

Subsection (d)(1)(A) proposes that an entity which becomes a covered entity 

after the cap-and-trade regulation is effective must register within 45 days of the 

deadline for reporting its emissions.

Summary of Section 95830(d)(1)(A).

The provision is necessary to ensure the new covered entity registers promptly. 

ARB believes that 45 days will be sufficient for the entity to complete the 

registration process.

Rationale for Section 95830(d)(1)(A).

Subsection (d)(1)(B) states that if an entity has crossed the 25,000 MTCO2e

annual emissions threshold for any data year 2008 through 2010, it must register 

within 30 days of the effective date of this regulation. 

Summary of Section 95830(d)(1)(B).

The registration deadline provision is necessary for two reasons. First, based on 

the reporting deadlines in the Mandatory Reporting Regulation (MRR), it ensures 

Rationale for Section 95830(d)(1)(B).
IX-22

that an entity which becomes a covered entity will have enough time to complete 

registration by the proposed deadline. Second, the provision gives ARB enough 

time to process the registrations for the start of the program in 2012.

Subsection (d)(2)(A) proposes that an entity must register by December 31, 2011,

if it chooses to participate in the cap-and-trade system in 2012 as an opt-in 

participant, as allowed in section 95813.

Summary of Section 95830(d)(2)(A).

The provision is necessary because Section 95813 allows an entity with reported 

emissions below the threshold to voluntarily subject itself to the compliance 

requirements of the cap-and-trade regulation. To be eligible to receive direct 

allocations of allowances, and to allow ARB to correctly calculate their 

compliance obligations in 2012, these entities must complete their registration 

before December 31, 2011. ARB believes this schedule gives the entity time to 

complete the registration process.

Rationale for Section 95830(d)(2)(A).

Subsection (d)(2)(B) proposes that an entity choosing to participate as an opt-in 

participant, as allowed in section 95813, must register by November 30 of the 

year before which it chooses to participate in the cap-and-trade system.

Summary of Section 95830(d)(2)(B).

The provision is necessary to allow ARB to correctly calculate an entity’s 

compliance obligations and create the necessary accounts. ARB believes this 

schedule gives the entity time to complete the registration process.

Rationale for Section 95830(d)(2)(B).

Subsection (d)(3) proposes that an entity registering as a voluntarily associated 

entity or in the category of other market participant must complete registration 

prior to holding compliance instruments or fulfilling other functions such as 

verification. However, they do not face any other deadlines for registration.

Summary of Section 95830(d)(3).

The provision is necessary because entities that do not have a compliance 

obligation must register before they perform any other functions within the capand-trade system, such as holding allowances or conducting transactions, 

operating offset projects, or performing verifications. ARB believes this schedule 

gives the entity time to complete the registration process.

Rationale for Section 95830(d)(3).
IX-23

Subsection (e) proposes that the Executive Officer determines when the 

registration is complete, approves the registration, and informs both the applicant 

and the accounts administrator of the approval. The accounts administrator will 

then create the accounts relevant for the type of registration approved.

Summary of Section 95830(e).

This provision is necessary because approval of registration is not automatic. 

ARB must review the applicant’s information for accuracy, and then determine 

whether the applicant is eligible to participate. ARB may need to review reporting 

data and information contained in the application, as well as the applicant’s 

history of participation in the system.

Rationale for Section 95830(e).

Section 95831. Account Types.

Subsection (a)(1) states that the Executive Officer will authorize only one set of 

accounts for an entity which has completed registration.

Summary of Section 95831(a)(1).

This provision is needed to serve two purposes. First, it ensures that ARB can 

effectively monitor the holdings of registered entities. Second, it ensures that 

ARB can effectively discipline an entity that violates the regulations by 

suspending, restricting, or revoking the entity’s account.

Rationale for Section 95831(a)(1).

Subsection (a)(2) proposes that the Executive Officer will create a Holding 

Account for any entity that completes registration as a covered entity, opt-in 

covered entity, or a voluntarily associated entity.

Summary of Section 95831(a)(2).

The provision is necessary because an entity will need a Holding Account to 

keep compliance instruments.

Rationale for Section 95831(a)(2).

Subsection (a)(3) proposes that some covered entities that receive a direct 

allocation will be given a Limited Use Holding Account in addition to their Holding 

Account for holding their allowances.

Summary of Section 95831(a)(3).
IX-24

The provision is necessary because some covered entities in the electricity retail 

distribution sector will receive a direct allocation of allowances from ARB. 

However, the allocation comes with restrictions on what the covered entities can 

do with their allowances. The creation of these special accounts will allow ARB 

to enforce the restrictions efficiently.

Rationale for Section 95831(a)(3).

Subsection (a)(3)(A) proposes that an entity with a Limited Use Holding Account 

may not transfer instruments from a Holding Account into this account.

Summary of Section 95831(a)(3)(A).

The provision is necessary because entities with a Limited Use Holding Account 

may sell the allowances at the consignment auction. The restriction on transfers 

into this account prevents the entity from selling other allowances at consignment. 

Rationale for Section 95831(a)(3)(A).

Subsection (a)(3)(B) proposes that allowances placed into the Limited Use 

Holding account may not be transferred to any account other than the Auction 

Holding Account under the control of the Executive Officer.

Summary of Section 95831(a)(3)(B).

The provision is necessary because allowances allocated to Limited Use Holding 

account holders are intended to be used for the benefit of electricity ratepayers. 

ARB will ensure this by requiring the covered entities to auction the allowances 

through the consignment option and use the proceeds to reduce electricity costs 

for ratepayers.

Rationale for Section 95831(a)(3)(B).

Subsection (a)(4) proposes that the Executive Officer will create a Compliance 

Account for any entity that completes registration as a covered entity or opt-in 

covered entity.

Summary of Section 95831(a)(4).

The provision is necessary because when an entity needs to surrender a 

compliance instrument, it will transfer the instrument from its Holding Account to 

its Compliance Account.

Rationale for Section 95831(a)(4).
IX-25

Subsection (a)(4)(A) proposes that a covered entity may transfer compliance 

instruments to its Compliance Account at any time.

Summary of Section 95831(a)(4)(A).

The provision is necessary because ARB sees no reason to restrict when a 

covered entity can transfer instruments to its Compliance Account. In addition, 

instruments placed in a Compliance Account do not count toward a covered 

entity’s holding limit, which is described in section 95920.

Rationale for Section 95831(a)(4)(A).

Subsection (a)(4)(B) proposes that when a covered entity transfers a compliance 

instrument into its Compliance Account it may not remove it later.

Summary of Section 95831(a)(4)(B).

The provision is necessary because ARB is imposing this restriction as a method 

of giving a covered entity an exemption from the holding limit for compliance 

instruments it has accumulated to cover its surrender obligation. If ARB is going 

to give covered entities the exemption, the entities should not be able to transfer 

the instruments to another registered entity.

Rationale for Section 95831(a)(4)(B).

Subsection (b)(1) proposes that the Executive Officer may revoke or suspend the 

registration of a voluntarily associated entity for violations of the regulation.

Summary of Section 95831(b)(1).

The provision is necessary because this option ensures that entities violating the 

regulation do not continue to disrupt the market.

Rationale for Section 95831(b)(1).

Subsection (b)(1)(A) proposes that if the Executive Officer revokes an entity’s 

registration, the entity will be given thirty days to sell or voluntarily retire any 

compliance instruments in its Holding Account.

Summary of Section 95831(b)(1)(A).

The provision is necessary because once an entity’s registration is revoked or 

suspended, its Holding Account is revoked or suspended as well, and it can no 

longer hold compliance instruments. ARB believes thirty days should give an 

entity sufficient time to transfer its instruments before it can no longer access its 

account.

Rationale for Section 95831(b)(1)(A).
IX-26

Subsection (b)(1)(B) proposes that if an entity whose registration and Holding 

Account have been suspended does not sell or voluntarily retire the compliance 

instruments in its account, ARB will transfer the allowances to the consignment 

auction for sale and return the auction proceeds to the entity. Any remaining 

offsets will be retired by ARB.

Summary of Section 95831(b)(1)(B).

The provision is necessary because ARB must have a method of dealing with an 

entity which refuses to remove compliance instruments from its holding account 

when its registration has been revoked or suspended. This approach ensures 

that the entity receives value for the allowances sold at auction. ARB has no 

comparable way to sell offsets, so the offsets will be retired and the account 

holder compensated through the consignment auction pursuant to section 

95910(d)

Rationale for Section 95831(b)(1)(B).

Subsection (b)(2)(A) proposes that the Holding Account of any entity may be 

restricted for violations of the regulation to hold a number of compliance 

instruments that is less than the holding limit.

Summary of Section 95831(b)(2)(A).

The provision is necessary to allow ARB to restrict holdings below the usual 

holding limit, as a response to rule violations. Normally, an entity may hold as 

many compliance instruments as it wishes, up to a number set by the holding 

limit. Restricting the number of compliance instruments held may be the only 

remedy available to prevent violations. For example, ARB could not suspend or 

revoke the account of a covered entity, which needs the accounts for compliance 

purposes, but ARB could penalize the entity by removing some of the flexibility 

afforded to covered entities under the rules.

Rationale for Section 95831(b)(2)(A).

Subsection (b)(2)(B) proposes that the Holding Account of any entity may be 

restricted for violations of the regulation to limit or prohibit transfers in or out of 

the account.

Summary of Section 95831(b)(2)(B).

The provision is necessary to allow ARB to respond to rule violations by 

restricting an entity’s ability to accumulate instruments or participate in market 

activity. These could be implemented by prohibiting further transfers into or out 

of the entity’s account. 

Rationale for Section 95831(b)(2)(B).
IX-27

Subsection (c) proposes that there will be several accounts under the control of 

the Executive Officer.

Summary of Section 95831(c), Accounts Under the Control of the Executive 

Officer.

The provision is necessary to allow the Executive Officer to serve essential 

functions of the system, such as the creation or approval of compliance 

instruments, auction operation, direct allocations to entities, voluntary retirements, 

surrender compliance, and the maintenance of a list of compliance instruments 

that have been retired in the California system or a GHG emissions trading 

system (ETS) to which California has linked.

Rationale for Section 95831(c).

Subsection (c)(1) proposes that the Executive Officer will control the Allocation 

Holding Account, into which the serial numbers of allowances will be recorded 

when the allowances are created.

Summary of Section 95831(c)(1).

The provision is necessary because the Executive Officer must be able to 

introduce new allowances into the system. Allowances and offset credits do not 

exist outside of the system of accounts. Allowances are created when they are 

assigned serial numbers and the numbers are placed in the Allocation Holding 

Account. This account will be the source account when the Executive Officer 

transfers them to some other account for direct allocation or for auction.

Rationale for Section 95831(c)(1).

Subsection (c)(2) proposes that the Executive Officer will control the Auction 

Holding Account, into which the serial numbers of allowances will be transferred 

for sale at auction.

Summary of Section 95831(c)(2).

The provision is necessary because the Executive Officer must be able to 

transfer allowances from several source accounts to a central account for auction.

Rationale for Section 95831(c)(2).

Subsection (c)(2)(A) proposes that the Allocation Holding Account will be the 

source of allowances allocated by ARB directly to auction.

Summary of Section 95831(c)(2)(A).
IX-28

The provision is necessary because in each budget year ARB will designate a 

number of newly created allowances to be auctioned. Before each quarterly 

auction, ARB will need to transfer allowances to the Auction Holding Account.

Rationale for Section 95831(c)(2)(A).

Subsection (c)(2)(B) proposes that the Executive Officer may transfer allowances 

from accounts that are to be suspended or revoked.

Summary of Section 95831(c)(2)(B).

The provision is necessary to allow allowances previously allocated or auctioned 

to registered entities to be transferred to the auction if the entities’ registration 

and accounts are to be suspended or revoked. In those cases, if the entities do 

not transfer all compliance instruments out of the account, ARB will consign them 

for sale at the auction.

Rationale for Section 95831(c)(2)(B).

Subsection (c)(2)(C) proposes that covered entities may transfer allowances from 

Limited Use Holding Accounts to the Auction Holding Account.

Summary of Section 95831(c)(2)(C).

The provision is necessary to permit allowances previously allocated to covered 

entities to be transferred to the auction.

Rationale for Section 95831(c)(2)(C).

Subsection (c)(3) proposes that the Executive Officer will transfer instruments 

from individual Compliance Accounts to the Retirement Account when 

compliance deadlines occur. Individual account holders may also voluntarily 

retire allowances by transferring them from their Holding Accounts to the 

Retirement Account.

Summary of Section 95831(c)(3).

The provision is necessary because the transfer of a compliance instrument to 

the Retirement Account is the way instruments will be removed permanently from 

the system. 

Rationale for Section 95831(c)(3).

Subsection (c)(3)(A) proposes that an instrument transferred to the Retirement 

Account cannot be further transferred to any holding or Compliance Account.

Summary of Section 95831(c)(3)(A).
IX-29

The provision is necessary because any instrument transferred to the Retirement 

Account must be removed from the system, and no further transfers may be 

permitted.

Rationale for Section 95831(c)(3)(A).

Subsection (c)(3)(B) proposes that If California retires an instrument, it would 

then inform any linked ETS that the retirement has occurred.

Summary of Section 95831(c)(3)(B).

The provision is necessary to guarantee that any compliance instrument retired 

by California will not then be traded on any system to which California chooses to 

link.

Rationale for Section 95831(c)(3)(B).

Subsection (c)(3)(C) proposes that once an instrument has been transferred to 

the Retirement Account, the Executive Officer will publish the retirement by 

recording the serial number of the retired instrument in a public registry.

Summary of Section 95831(c)(3)(C).

The provision is necessary because placing the serial number in a public registry 

will ensure the public can observe that entities are complying with their surrender 

obligations and that retired instruments are no longer circulating.

Rationale for Section 95831(c)(3)(C).

Subsections (c)(4)(A) through (c)(4)(D) propose that the Allowance Price 

Containment Reserve Account will be a Holding Account into which the 

Executive Officer will transfer allowances from several sources: allowances 

initially allocated for auction, but which remain unsold when an auction settles at 

the reserve price; allowances directly allocated to the Reserve; and allowances 

submitted in fulfillment of an excess emissions obligation.

Summary of Section 95831(c)(4)(A) through (c)(4)(D).

Subsection (c)(4)(D) proposes that section 95913 contains the rules governing 

the operation of the Allowance Price Containment Reserve Account.

Subsections (c)(4)(A) through (c)(4)(D) are needed to define the three sources of 

allowances that fund the Allowance Price Containment Reserve Account.

Rationale for Section 95831(c)(4)(A) through (c)(4)(D).

The first source is allowances remaining unsold at auction. Allowances would be 

unsold when an auction is settled at the auction reserve price. This could occur if 
IX-30

allowances are temporarily oversupplied to the market. Placing the unsold 

allowances in the Reserve helps eliminate the temporary oversupply and makes 

the allowances available if prices are much higher in the future.

The second source is direct allocation of a large number of allowances from 

future vintages. ARB chose this method to create a reserve of sufficient size to 

provide credible cost containment.

The third source is allowances surrendered to meet an excess emissions 

obligation when entities fail to comply in a timely manner with surrender 

obligations. However, the excess emissions obligation could reduce supplies of 

allowances to the market. This could result in higher prices for all entities. 

Placing the allowances used to meet the excess emissions obligation into the 

Allowance Price Containment Reserve keeps the allowances available for 

purchase in times of high market prices.

Subsection (c)(4)(D) is necessary to define the process by which allowances are 

removed from the Allowance Price Containment Reserve Account. Allowances 

may be withdrawn from the Allowance Price Containment Reserve Account as a 

source of an additional supply of allowances, which covered entities may 

purchase during times of high prices. The rules governing these sales from the 

Reserve are contained in section 95913.

Subsection (c)(5)(A) proposes that the Executive Officer will ensure that a 

percentage of the offsets issued by ARB for projects approved under the 

Compliance Offset Protocol for Forest Projects are placed in a Holding Account 

known as the Forest Buffer Account.

Summary of Section 95831(c)(5)(A).

The provision is necessary because the Forest Buffer Account will be used to 

replace offset credits that are invalidated due to an unintentional reversal of a 

forest project. The Compliance Offset Protocol for Forest Projects contains a 

procedure to determine the proportion of the offset credits issued for a project 

that must be placed into the Reserve. The Executive Officer must ensure this 

transfer takes place so that the Reserve may contain enough offset credits to 

replace invalidated offset credits.

Rationale for Section 95831(c)(5)(A).

Subsection (c)(5)(B) proposes that the Executive Officer will remove offset 

credits from the Forest Buffer Account when an unintentional reversal occurs. 

These offset credits will be transferred to the Retirement Account.

Summary of Section 95831(c)(5)(B).

Rationale for Section 95831(c)(5)(B).
IX-31

The provision is necessary because the Executive Officer will use offset credits in 

the Forest Buffer Account to ensure the integrity of the retirement process.

Subsection (c)(6) is reserved for a possible future account for a voluntary 

renewable energy allowance set-aside.

Summary of Section 95831(c)(6), Voluntary Renewable Energy Allowance SetAside Account.

The cap-and-trade program could have negative effects on the voluntary 

renewable energy (VRE) market that could be addressed through a voluntary 

renewable energy allowance set-aside. The proposed regulation does not 

currently provide for allocation of voluntary renewable energy allowance setaside, but leaves this subsection as a placeholder for establishing an account to 

use as part of such a provision in the future.

Rationale for Section 95831(c)(6).

Section 95832. Designation of Authorized Account Representative.

Subsections (a)(1) through (a)(5) require that every application for registration 

pursuant to 95830 must designate a single authorized account representative 

and a single alternate authorized account representative who may act on behalf 

of the authorized account representative.

Summary of Section 95832(a)(1) through (a)(5).

Subsections (a)(1) through (a)(5) list the required elements for the application. 

These include names and addresses of individuals named as representatives; 

name of the organization applying; statements of beneficial ownership and 

relationships between beneficial owners; and a certification statement signed by 

the authorized representatives.

These provisions are necessary to identify the individuals authorized to transact 

on behalf of the account holder.

Rationale for Section 95832(a)(1) through (a)(5).

Subsection (b) proposes that the Executive Officer, not the accounts 

administrator, has the responsibility to evaluate the documentation supporting 

authorizations.

Summary of Section 95832(b).

Rationale for Section 95832(b).
IX-32

The provision is necessary because the accounts administrator simply processes 

transactions under the direction of the Executive Officer. The Executive Officer 

has the sole responsibility to recognize authorized account representatives.

Subsections (c)(1) through (c)(3) contain requirements for the accounts 

administrator to perform when a registration application is received. Subsection 

(c)(1) requires creation of the account for the registrant. Subsection (c)(2) 

requires the registering entity owning any instruments in the account be bound by 

any action of the authorized account representative or alternate authorized 

account representative. Subsection (c)(3) requires the registering entity owning 

any instruments in the account be bound by orders issued by a court or the 

Executive Officer to the authorized account representative or alternate authorized 

account representative.

Summary of Section 95832(c)(1) through (c)(3).

These subsections are necessary so that the account holder owning any 

instruments in an account is bound by the actions of courts, the Executive Officer,

or the authorized account representative or alternate authorized account 

representative.

Rationale for Section 95832(c)(1) through (c)(3).

Subsection (d) and (e) propose the requirements for certifications that must 

accompany any submission concerning the account by the account holder. 

Section (e) requires the accounts administrator to accept submissions only if 

accompanied by the proper certification.

Summary of Section 95832(d) and (e).

These provisions are essential to ensuring that transaction submissions are only 

made by the persons authorized to do so.

Rationale for Section 95832(d) and (e).

Subsections (f)(1) through (f)(4) contain the rules for changing an authorized 

account representative or alternate authorized account representative or a 

change to the entities that own compliance instruments in an account.

Summary of Section 95832(f)(1) through (f)(4).

These provisions are necessary so that the accounts administrator can properly 

process changes of the authorized account representative or alternate authorized 

account representative or a change to the entities that own compliance 

instruments in an account.

Rationale for Section 95832(f)(1) through (f)(4).
IX-33

Subsections (g)(1) through (g)(3) contain requirements for the processing of 

objections concerning the authorized account representative or alternate 

authorized account representative. The accounts administrator will recognize the 

representatives named in completed registration applications until new 

applications are completed.

Summary of Section 95832(g)(1) through (g)(3).

These provisions are necessary to maintain the ability of the accounts 

administrator to recognize an authorized account representative or alternate 

authorized account representative and process transactions submitted until 

representatives are changed through the registration process. The accounts 

administrator will not be involved with objections or disputes, and will only deal 

with submissions from the representatives designated through the registration 

process.

Rationale for Section 95832(g)(1) through (g)(3).

Subsections (h)(1) through (h)(5) contain a process that must be followed for the 

authorized account representative or alternate authorized account representative 

to delegate the authority to another person. These requirements include notice 

that must be provided to the accounts administrator; a certification statement; 

processing of the delegation and superseding delegations by the accounts 

administrator, and handling of electronic submissions.

Summary of Section 95832(h)(1) through (h)(5).

These provisions are necessary in case the authorized account representative or 

alternate authorized account representative need to delegate their authority. The 

provisions ensure that the accounts administrator will always only recognize a 

single authorized account representative or alternate authorized account 

representative as being able to submit transactions concerning accounts.

Rationale for Section 95832(h)(1) through (h)(5).

Subarticle 6. California Greenhouse Gas Allowance Budgets.

Section 95840. Compliance Periods.

This section proposes the three compliance periods. A compliance period 

represents a three-year window for which covered entities’ greenhouse gas 

emissions will be summed to calculate a triennial compliance obligation. 

Covered entities must surrender an equivalent number of compliance 

instruments to match their compliance obligation for each three-year period. 

Summary of Section 95840. 

Rationale for Section 95840.
IX-34

This section is necessary to establish multiyear compliance periods, which

enhance flexibility for covered entities and help smooth allowance price volatility 

related to variations in emissions levels due to changes in weather, market 

conditions, or other variables. However, very long compliance periods cannot 

provide regular assurance that emissions targets are being met and that covered 

entities are acquiring sufficient compliance instruments to match their obligations. 

Staff concluded that three-year compliance periods—with interim partial 

surrenders annually—will appropriately balance the goals of flexibility and 

environmental integrity. In reaching this conclusion, staff relied on the advice of 

the Market Advisory Committee, deliberations with Western Climate Initiative 

partners, and the example set by the Regional Greenhouse Gas Initiative. 

Section 95841. Annual Allowance Budgets for Calendar Years 2012–2020.

This section proposes the total amount of allowances that will be created for 

each year. These annual allowance budgets, when coupled with permissible 

offset credit usage, represent a set of annual emissions targets for the covered 

entities. 

Summary of Section 95841. 

The allowance budgets begin with the expected level of emissions from the 

narrow scope covered sources in 2012 and expand in 2015 to account for 

coverage of additional sources. This framework was adopted to allow one year 

of program coverage prior to any required emissions reductions, to ensure a 

smooth transition as a category of covered entities enters the program.

Rationale for Section 95841.

The allowance budget levels were based on an analysis of historical, current, and 

projected future emissions levels relative to the 2020 economy-wide target set 

forth by AB 32. In developing these budgets, staff synthesized the results of 

multiple analyses of GHG abatement opportunities and costs for the covered 

entities. In addition, staff considered California Executive Order S-3-05 that 

requires an 80 percent reduction of GHGs from 1990 levels by 2050, input from 

WCI partner deliberations, targets in existing GHG cap-and-trade systems, 

proposed federal climate legislation, the work of the United Nations’ 

Intergovernmental Panel on Climate Change, and stakeholder comment. 

Subarticle 7. Compliance Requirements for Covered Entities.

Section 95850. General Requirements.

Subsection (a) proposes that covered entities be subject to ARB’s Mandatory 

Reporting Regulation.

Summary of Section 95850(a), Reporting Requirements.
IX-35

This provision is necessary because covered entities must first report so that 

ARB can determine if they should be classified as covered entities and if they 

exceed the emissions threshold. Also, a covered entity’s compliance obligation 

is calculated based on its reported emissions.

Rationale for Section 95850(a).

Subsection (b) proposes that emissions data reports should be kept for 10 

consecutive years by each covered entity and they must provide them to ARB 

within 20 days of a request.

Summary of Section 95850(b), Record Retention Requirements.

This provision is necessary to cover all three compliance periods and the 

following year of the last compliance period. Covered entities must give records 

within 20 days to give them sufficient time to collect the information without 

delaying ARB’s review.

Rationale for Section 95850(b).

Subsection (b)(1) specifies that covered entities must retain data and provide it to 

ARB upon request.

Summary of Section 95850(b)(1).

This provision is necessary to allow covered entities to know what documentation 

they need to retain and provide to ARB upon request.

Rationale for Section 95850(b)(1).

Subsection (b)(2) specifies that covered entities must keep, and provide to ARB if 

requested, records that are used to calculate their compliance obligations.

Summary of Section 95850(b)(2).

This provision is necessary for ARB to ensure that the compliance obligation is 

correctly calculated over time.

Rationale for Section 95850(b)(2).

Subsection (b)(3) requires covered entities to keep, and provide to ARB if 

requested, their verification statements. 

Summary of Section 95850(b)(3).

This provision is necessary for ARB to ensure that the emissions data used for 

purposes of (b)(2) was verified by an ARB accredited verification body.

Rationale for Section 95850(b)(3).
IX-36

Section 95851. Phase-in of Compliance Obligation for Covered Entities.

Subsection (a) provides which covered entities have a compliance obligation in 

the first compliance period beginning in 2012. These include: operators of 

facilities, first jurisdictional deliverers of electricity, and suppliers of CO2 that 

exceed the emissions threshold.

Summary of Section 95851(a).

This provision is included because not all covered entities have a compliance 

obligation beginning in the first compliance period, and other sectors are phased 

in later in the program. These emissions sources are regulated in the context of 

clean air regulations; therefore, it is practical to cover these sectors from the start 

of the program in 2012.

Rationale for Section 95851(a).

Subsection (b) provides which covered entities have a compliance obligation in 

the second compliance period beginning in 2015. These emissions sources 

include: suppliers of natural gas, transportation fuels, and natural gas liquids that 

exceed the emissions threshold.

Summary of Section 95851(b).

These emission sources are included beginning in 2015 because there are 

currently no reporting requirements in place for these sources. This additional 

time will give these sources enough time to collect and verify their emissions data 

and provide it to ARB. 

Rationale for Section 95851(b).

Section 95852. Emissions Categories Used to Calculate Compliance 

Obligations.

This section identifies how ARB will calculate and assign compliance obligations 

to entities in the case of positive or qualified positive verification statements and 

in the case that an entity does not submit an emissions data report or complete 

verification.

Summary of Section 95852.

This section is included because entities must know in advance how their 

emissions data reports will ultimately be assigned a compliance obligation under 

these different scenarios.

Rationale for Section 95852.

Summary of Section 95852(a), Operators of Facilities.
IX-37

Subsection (a) proposes which GHG emissions operators of facilities will hold a 

compliance obligation for. Operators of facilities have a compliance obligation for 

every metric ton of CO2e of positive or qualified positive GHG emissions, either 

as a process emission or a stationary combustion emission.

This provision is included because operators of facilities may combust both 

process and stationary emissions, each of which will be covered under this 

program. It is important to identify the emissions categories used to calculate 

compliance obligations for operators of facilities.

Rationale for Section 95852 (a).

Subsection (b) proposes that a first deliverer of electricity has a compliance 

obligation for every metric ton of CO2e of positive or qualified positive GHG 

emissions, stationary combustion emissions, or emissions associated with 

electricity imported into California.

Summary of Section 95852(b), First Deliverers of Electricity.

This provision is included because first deliverers of electricity may combust 

stationary emissions, or emissions associated with electricity, each of which will 

be covered under this program. It is important to identify the emissions 

categories used to calculate compliance obligations for first jurisdictional 

deliverers of electricity.

Rationale for Section 95852(b).

Subsection (c) proposes that a supplier of natural gas has a compliance 

obligation for every metric ton of CO2e of GHG emissions that would result from 

full combustion or oxidation of all fuel delivered to end users in California, less 

the fuel that is delivered to other covered entities.

Summary of Section 95852(c), Suppliers of Natural Gas.

This provision is included because it is necessary to identify the emissions 

categories used to calculate compliance obligations for suppliers of natural gas.

Rationale for Section 95852(c).

Subsection (d) identifies that a supplier of petroleum products has a compliance 

obligation for every metric ton of CO2e of GHG emissions that would result from 

full combustion or oxidation of the quantities of RBOB, Distillate Fuel Oil No. 1, 

and Distillate Fuel Oil No. 2.

Summary of Section 95852(d), Suppliers of RBOB and Distillate Fuel Oils.

Rationale for Section 95852 (d).
IX-38

This provision is included because it is necessary to identify the emissions 

categories used to calculate compliance obligations for suppliers of petroleum

products. It is necessary to identify the specific fuels in (d)(1), (d)(2) and (d)(3) to 

ensure there is no confusion about which fuels generate a compliance obligation.

Subsection (e)(1) identifies that a producer of liquefied petroleum gas has a 

compliance obligation for every metric ton of CO2e of GHG emissions that would 

result from full combustion or oxidation of all fuel sold, distributed, or otherwise 

transferred for consumption in California.

Summary of Section 95852(e)(1), Producers of Natural Gas Liquids; Producers 

of Liquefied Petroleum Gas.

This provision is included because it is necessary to identify the emissions 

categories used to calculate compliance obligations for producers of natural gas 

liquids.

Rationale for Section 95852(e)(1).

Subsection (e)(2) identifies that an importer of liquefied petroleum gas has a 

compliance obligation for every MT of CO2e of GHG emissions that would result 

from full combustion or oxidation of all fuel imported into California.

Summary of Section 95852(e)(2), Producers of Natural Gas Liquids: Importer 

consignees of Liquefied Petroleum Gas.

This provision is included because it is necessary to identify the emissions 

categories used to calculate compliance obligations for importers of natural gas 

liquids.

Rationale for Section 95852(e)(2).

Subsection (f) identifies suppliers of blended fuels as entities with compliance 

obligations under this regulation based on the constitution of the blended fuel.

Summary of Section 95852(f), Suppliers of Blended Fuels.

This section is necessary to ensure that suppliers of blended fuels are aware that, 

even though the blended fuel itself may not have a compliance obligation under 

the regulation, the different parts of the blend are subject to the regulation and 

incur a compliance obligation if the parts of the blended fuel meet the 

requirements of the regulation.

Rationale for Section 95852(f).

Summary of Section 95852(g), Suppliers of Carbon Dioxide.
IX-39

Subsection (g) identifies that a supplier of carbon dioxide has a compliance 

obligation for GHG emissions that would result from imported and exported 

quantities of carbon dioxide.

This provision is included because it is necessary to identify the emissions 

categories used to calculate compliance obligations for suppliers of carbon 

dioxide.

Rationale for Section 95852(g).

Subsection (h) identifies that the compliance obligation is calculated from the 

CO2, CH4, and N2O emissions from fossil fuel combustion, the CH4 and N2O 

emissions from all biomass-based fuel combustion, the CO2 emissions from the 

combustion of unverifiable biomass-derived fuels listed in 95852.2, the CO2

emissions from the combustion of biomass-derived fuels not listed in 95852.2, 

and the CO2, CH4, and N2O from all process and fugitive emissions specified in 

the Mandatory Reporting Regulation, except those listed in 95852.2(a)(6)

Summary of Section 95852(h).

This provision is included because CO2e may or may not include biomassderived fuel. The current U.S. EPA requirement for facilities reporting annual 

emissions of CO2, CH4, N2O, and each fluorinated GHG includes annual biogenic 

CO2 emissions as aggregated for all GHGs from all applicable source categories.

Rationale for Section 95852(h).

Section 95852.1. Compliance Obligations for Biomass-Derived Fuels.

This section states that entities that have emissions from the combustion of 

biomass-derived fuels incur a compliance obligation for every metric ton of CO2e 

emissions emitted from biomass-derived fuels.

Summary of Section 95852.1, Compliance Obligations for Biomass-Derived 

Fuels.

This section is necessary to ensure that all possible emissions of CO2e from fuel 

combustion incurs a compliance obligation.

Rationale for Section 95852.1.

Subsection (a) specifies that combustion emissions from source categories not 

listed under section 95852(g) do not hold a compliance obligation.

Summary of Section 95852.1 (a).

Rationale for Section 95852.1 (a).
IX-40

This provision is included because entities whose aggregate emissions include 

biomass-derived fuels will not count those emissions toward their total 

compliance obligation when reporting.

Subsection (b) specifies emissions from source categories that are listed under 

95852(g), but are not verifiable under MRR section 95131(i).

Summary of Section 95852.1 (b).

This provision is included because some biomass-derived fuels may be verifiable, 

and others may be reported, but unverifiable.

Rationale for Section 95852.1 (b).

Section 95852.2. Emissions Without a Compliance Obligation.

This section identifies emissions from specific sources that count toward the 

reporting threshold for the Mandatory Reporting Regulation, but do not count 

toward a cap-and-trade compliance obligation threshold.

Summary of Section 95852.2, Emissions Without a Compliance Obligation.

This section is included because emissions from specified sources are not 

required to hold a compliance obligation under AB 32; however, ARB maintains 

the need to collect the emissions data from these sources in the event that they 

are covered in the future. Emissions from specified source categories may be 

required to report, but will not hold a compliance obligation.

Rationale for Section 95852.2.

Subsections (a) through (e) propose facilities using biomass, municipal solid 

waste, geothermal, hydropower, or biodiesel are subject to the additional 

resource or fuel-specific requirements described here.

Summary of Section 95852.2 (a) through (e). 

These provisions summarize the requirements for a facility, which qualify for the 

Renewables Portfolio Standard (RPS). These categories are excluded from 

holding a compliance obligation because these facilities are subject to a separate 

regulation regarding RPS.

Rationale for Section 95852.2(a) through (e).

Subsection (f) identifies fugitive emissions that do not hold a compliance 

obligation. These emissions include CO2 emissions from geothermal generating 

units, CO2 and CH4 emissions from geothermal facilities, and CO2 emissions 

Summary of Section 95852(f) Fugitive and Process Emissions.
IX-41

from hydrogen fuel cells. This includes emissions at petroleum refineries such as 

asphalt-blowing operations, equipment leaks, storage tanks, and loading 

operations and leak detection and leaker emission factors, and stationary fugitive 

and stationary vented sources on offshore oil platforms at petroleum and natural 

gas system facilities.

This provision is included because entities whose aggregate emissions include 

fugitive emissions from the activities described will not count those emissions 

toward their total compliance obligation when reporting.

Rationale for Section 95852(f). 

Section 95852.3. Effect of Status Verification Statement on Calculation of 

Compliance Obligations.

Subsection (a) specifies that in the case of a positive or qualified positive 

verification statement, the compliance obligation will be calculated by using the 

reported and verified emissions, as outlined in section 95131 of the Mandatory 

Reporting Requirements.

Summary of Section 95852.3 (a).

This provision is necessary to specify how different types of verification 

statements will be used to calculate a compliance obligation.

Rationale for Section 95852.3 (a).

Subsection (b) specifies that in the case of an adverse verification statement, for 

every metric ton of CO2e of GHG emissions, as determined by ARB, the 

compliance obligation will equal the ARB-assigned emissions, as outlined in 

section 95131 of the Mandatory Reporting Regulation.

Summary of Section 95852.3 (b).

This provision is necessary to specify how different types of verification 

statements will be used to calculate a compliance obligation.

Rationale for Section 95852.3 (b).

Subsection (c) specifies that in the case than an entity does not submit an 

emissions data report or complete verification, the EO will determine its 

compliance obligation, as set forth in section 95103 of the Mandatory Reporting 

Regulation.

Summary of Section 95852.3 (c).

Rationale for Section 95852.3 (c).
IX-42

This provision is necessary to specify how different types of verification 

statements will be used to calculate a compliance obligation.

Section 95853. Calculation of Covered Entity’s Triennial Compliance 

Obligation.

This section states that any entity that exceeds the compliance threshold in any 

of the three years before the start of a compliance period is an entity covered by 

the regulation for the entire next compliance period. It further specifies that the 

entity’s compliance obligation will be calculated based on the total verified 

emissions from the entire compliance period.

Summary of Section 95853(a)

This section is necessary to ensure that all entities that may be covered entities 

pursuant to this regulation are aware of the conditions that would make an entity 

a covered entity. This section is also necessary to inform all covered entities of 

their ongoing compliance obligations even though the entity may not exceed the 

threshold in subsequent years.

Rationale for Section 95853(a)

This section states that if a covered entity initially exceeds the threshold stated in 

the regulation during the first year of a compliance period, that entity is a covered 

entity for all three years of the compliance period. It further specifies that the 

entity’s compliance obligation will be calculated based on the total verified 

emissions from the entire compliance period.

Summary of Section 95853(b)

This section is necessary to inform an entity that had not previously been subject 

to the regulation and whose emissions exceed the threshold in the first year of a 

compliance period, that the entity remains a covered entity for the entire 

compliance period.

Rationale for Section 95853(b)

This section is also necessary to inform all covered entities of their ongoing 

compliance obligations even though the entity may not exceed the threshold in 

subsequent years.

This section states that if a covered entity initially exceeds the emissions 

threshold during the second year of a compliance period, the entity is a covered 

entity for the second and third years of the compliance period only. 

Summary of Section 95853(c)
IX-43

It further specifies that, for an entity that first exceeds the regulation threshold in 

the second year of a compliance period, the entity’s compliance obligation will be 

calculated based on the total verified emissions from the second and third year of 

the compliance period.

This section is necessary to clarify when an entity that had not previously been 

subject to the regulation and whose emissions exceed the threshold in the 

second year of a compliance period becomes a covered entity under the 

regulation, and when the newly covered entity’s compliance obligation begins.

Rationale for Section 95853(c)

This section states that if a covered entity initially exceeds the emissions 

threshold during the third year of a compliance period, the entity has a 

compliance obligation for the third year of the compliance period only. The 

section also states that the compliance obligation for its emissions from the third 

year of the compliance period is not due until the subsequent compliance period. 

The covered entity’s compliance obligation for the third year will be added to the 

subsequent compliance period obligations.

Summary of Section 95853(d)

This section is necessary to clarify that the compliance obligation for an entity 

that becomes a covered entity during the third year of the compliance period is 

not due immediately. The section further clarifies that the compliance obligation 

is not forgiven, but, for purposes of ease of administration, the obligation is 

added to the subsequent compliance period’s compliance obligations.

Rationale for Section 95853(d)

Subsection (e) states that if a new covered entity is eligible to receive a direct 

allocation of allowances, it will not receive an allocation until the year following 

the first year the covered entity exceeds the threshold of this regulation. In that 

year, it will receive twice the number of allowances which it is eligible to receive 

for a single year.

Summary of Section 95853(e)

This provision is necessary because the verified information needed to allocate 

allowances will not be available until the year following the first time the entity 

exceeds the threshold of this regulation.

Rationale for Section 95853(e)

Section 95854. Quantitative Usage Limit on Designated Compliance 

Instruments – Offset Credits.

Summary of Section 95854.
IX-44

Section 95854 proposes that a covered entity may use compliance instruments 

identified in sections 95821(b), (c), and (d) to meet up to 8 percent of its annual 

or triennial compliance obligation. Compliance instruments identified in section 

95821(d) may only be used to meet up to 25 percent of this 8 percent limit (i.e., a 

maximum of 2 percent) during the first and second compliance periods, and up to 

50 percent of this 8 percent limit (i.e., a maximum of 4 percent) during the third 

compliance period. 

This section is needed to identify which compliance instruments may be used to 

meet up to 8 percent of a covered entity’s compliance obligation. The purpose of 

this is to create a limit on offsets to balance emissions reductions from covered 

entities and offset projects.

Rationale for Section 95854.

Section 95855. Annual Compliance Obligation.

Subsection (a) states that a covered entity will incur an annual compliance 

obligation each year that it is a covered entity, except when the entity becomes a 

covered entity during a reporting data year. In that case the entity will not owe an 

annual obligation for that year.

Summary of Section 95855(a).

This provision is needed to define when an entity will incur an annual compliance 

obligation. The entity will owe an annual compliance obligation for any year 

when it is a covered entity for the entire year.

Rationale for Section 95855(a).

ARB staff is proposing an annual compliance obligation primarily as a safeguard 

against defaults by emitters. With a three-year compliance period, an entity 

could run up a large amount of emissions before defaulting. This would leave 

ARB in the position of having to either make up for the defaulted emissions from 

another source of reduction or risk having emissions exceed the cap. ARB 

chose the three-year compliance period to give entities the flexibility to emit early 

and purchase allowances later in the period. Nonetheless, staff believes a 

prudent entity would accumulate at least some allowances, even if it chose such 

a strategy. A partial annual surrender obligation would thus not be a hardship.

This provision is needed because the annual compliance obligation is due in the 

middle of the year following the actual emissions. ARB was concerned that new 

covered entities may not have sufficient time to acquire allowances for the annual 

obligation. Waiving the first annual compliance obligation does not result in any 

“forgiveness” of emissions. Rather, the entity will simply have to cover the 

emissions at the end of the three-year compliance period.

Summary of Section 95855(b).
IX-45

Subsection (b) defines the annual compliance obligation for a covered entity as 

30 percent of the entity’s reported and verified emissions from the previous year.

This provision is necessary because staff believes that setting the annual 

compliance obligation to 30 percent of an entity’s emissions for the previous year 

will not pose a hardship for a prudent entity, even one that intends to purchase 

allowances late in the compliance period to cover its emissions. However, it may 

allow ARB to identify entities failing to meet the 30 percent requirement as risks 

for eventual default. Staff believes this approach balances the flexibility given to 

emitters through the three-year compliance period against the need to identify 

and prevent defaults.

Rationale for Section 95855(b).

Section 95856. Timely Surrender of Compliance Instruments by a Covered 

Entity.

Subsection (a) requires that a covered entity must surrender one compliance 

instrument for each metric ton of GHG emissions (in CO2 equivalent) contained in 

the entity’s surrender obligation. Some of the instruments must be surrendered 

each year, while others are surrendered at the end of the three-year compliance 

period.

Summary of Section 95856(a).

This provision is needed to clarify the basic compliance requirement for covered 

entities. They must turn in allowances or offset credits in amounts equal to their 

emissions during the compliance period. Covered entities will make a partial 

surrender each year and cover the remaining emissions at the end of the threeyear compliance period. 

Rationale for Section 95856(a).

Subsection (b)(1) identifies the California compliance instruments; instruments 

issued by GHG ETS to which California links, and offset credits that are valid for 

compliance.

Summary of Section 95856(b)(1).

This provision is needed to clarify which instruments will be accepted by ARB for 

surrender compliance.

Rationale for Section 95856(b)(1).

Subsection (b)(2) states that compliance instruments are issued for a specific 

allowance budget year, also known as a vintage year. With limited exceptions, a 

Summary of Section 95856(b)(2).
IX-46

compliance instrument must be issued for a vintage year within or before the 

year or years for which the obligation is calculated to be valid to meet a surrender 

obligation.

This provision is needed because ARB will issue allowances for vintage years 

through 2020 at the beginning of the program. In some cases, such as 

allowances sold at the advance auction, allowances from future vintage years 

can be purchased and held, but not used for surrender. 

Rationale for Section 95856(b)(2).

The use of compliance instruments from future vintage years for current 

compliance is known as “borrowing.” Staff is proposing to prohibit borrowing to 

avoid a scenario known as “cascading borrowing.” If borrowing were allowed, 

the added supply would reduce current market prices for instruments. This 

would lead to a reduction in the level of direct emissions reductions, as well as a 

greater surrender of instruments compared with a scenario of no borrowing. In 

turn, this would lead to a smaller supply of instruments in future compliance 

periods, leading to an even greater reliance on borrowing. Ultimately, either the 

borrowing would lead to the cap being violated or covered entities having to 

make drastic reductions in a short period of time. 

Subsection (b)(2)(A) states that covered entities will be able to use future vintage 

allowances years if the allowances are purchased from the Allowance Price 

Containment Reserve.

Summary of Section 95856(b)(2)(A).

This provision is necessary because ARB needed a source of allowances in 

order to fund a credible cost containment reserve. The only source was future 

vintage allowances, which would be useless as a cost-containment mechanism if 

they could not be used for compliance when purchased.

Rationale for Section 95856(b)(2)(A).

Subsection (b)(2)(B) proposes that covered entities be able to use allowances 

from future vintages if the allowances are used to fulfill excess emissions 

obligations.

Summary of Section 95856(b)(2)(B).

This provision is needed because excess emissions obligations would only be 

incurred in the year after the year for which a compliance obligation is calculated. 

There would not be time to accumulate a supply of instruments from the 

appropriate vintages. In addition, ARB staff wants to avoid having the excess 

Rationale for Section 95856(b)(2)(B).
IX-47

emissions obligations excessively tighten the market for instruments at the time 

of compliance deadlines. 

Subsection (c) states that in order to comply with a surrender obligation, a 

covered entity simply transfers the serial number of valid compliance instruments 

from its Holding Account to its Compliance Account by the compliance deadline.

Summary of Section 95856(c).

This provision is needed to simplify the surrender process. The covered entity 

does not have to submit any documentation on its surrender other than filing a 

transactions report with the accounts administrator. These transactions are 

time-stamped and can only be made by the account holder’s authorized account 

representative, so it will not be difficult to verify timely compliance.

Rationale for Section 95856(c).

Subsection (d)(1) requires that covered entities that report by April 1 under 

section 95103 of the MRR must complete their annual compliance obligation by 

May 15 of the following year.

Summary of Section 95856(d)(1).

This provision is needed to inform a covered entity of the specific date by which 

all transfers of compliance instrument to its Compliance Account must be 

completed.

Rationale for Section 95856(d)(1).

Subsection (d)(2) requires that covered entities that report by June 1 under 

section 95103 of the MRR must complete their annual compliance obligation by 

July 15 of the following year.

Summary of Section 95856(d)(2).

This provision is needed to inform a covered entity of the specific date by which 

all transfers of compliance instrument to its Compliance Account must be 

completed.

Rationale for Section 95856(d)(2).

Subsection (e)(1) states that the Executive Officer will determine the covered 

entity’s triennial obligation compliance based on a review of the positive or 

qualified verifications statement for the third year of the compliance period.

Summary of Section 95856(e)(1).

Rationale for Section 95856(e)(1).
IX-48

This provision is needed to allow the Executive Officer to review verifications 

reports and resolve any issues involving verification reports, so that the covered 

entity can complete timely transfers of compliance instrument to its Compliance 

Account.

Subsection (e)(2) states that in the absence of a positive or qualified verifications 

statement for the third year of the compliance period, the Executive Officer will 

determine the covered entity’s triennial obligation assigning emissions, according 

to the requirements set forth in section 95130 of the MRR.

Summary of Section 95856(e)(2).

This provision is needed to allow the Executive Officer to resolve any issues 

involving missing data or negative verification reports, so that the covered entity 

can complete timely transfers of compliance instrument to its Compliance 

Account.

Rationale for Section 95856(e)(2).

Subsection (e)(3) states that the Executive Officer will issue a final determination 

of the covered entity’s triennial compliance obligation following a data review and 

reconciliation process pursuant to section 95104 of the MRR.

Summary of Section 95856(e)(3).

This provision is needed to allow the Executive Officer to resolve any issues 

involving missing or problematic data, so that the covered entity can complete 

timely transfers of compliance instruments to its Compliance Account.

Rationale for Section 95856(e)(3).

Subsection (f)(1) requires that a covered entity must complete the transfer of 

compliance instruments to fulfill its triennial compliance obligation by November 1 

of the calendar year following the third year of the compliance period.

Summary of Section 95856(f)(1).

This provision is needed to inform a covered entity of the specific date by which 

all transfers of compliance instrument to its Compliance Account must be 

completed.

Rationale for Section 95856(f)(1).

Subsection (f)(2) requires that the number of offset credits used to fulfill the 

combined annual and triennial surrender obligations is subject to the quantitative 

use limit on offset credits.

Summary of Section 95856(f)(2).
IX-49

This provision is needed to inform a covered entity of the maximum number of 

offset credits it is allowed to transfer to its Compliance Account to complete the 

triennial compliance obligation.

Rationale for Section 95856(f)(2).

Subsection (f)(3) states that the triennial surrender obligation will account for 

compliance instruments already surrendered pursuant to the annual compliance 

obligation.

Summary of Section 95856(f)(3)

This provision is necessary to clarify that the triennial surrender obligation will 

account for previously surrendered compliance documents so the covered entity 

will not be required to resubmit compliance instruments.

Rationale for Section 95856(f)(3)

Subsection (g)(1) states that when the Executive Officer has determined that the 

covered entity has met a surrender obligation, the Executive Officer shall retire 

the compliance instruments surrendered.

Summary of Section 95856(g)(1).

This provision is needed to ensure that surrendered instruments can never be 

used again in California. 

Rationale for Section 95856(g)(1).

Subsection (g)(2) states that when the Executive Officer has determined that the 

covered entity has met a surrender obligation, the Executive Officer shall inform 

programs to which California has linked or that California recognizes that the 

surrendered compliance instruments have been retired. 

Summary of Section 95856(g)(2).

This provision is needed to ensure that surrendered instruments can never be 

used again in programs California recognizes or to which California is linked. 

Rationale for Section 95856(g)(2).

Section 95857. Untimely Surrender of Compliance Instruments by a 

Covered Entity.

Subsection (a)(1) states that when a covered entity or opt-in covered entity that 

does not meet the compliance deadline for annual or triennial compliance is 

subject to the compliance obligation for excess emissions. 

Summary of Section 95857(a)(1).
IX-50

This provision is needed to clarify when the excess emissions obligation applies.

Rationale for Section 95857(a)(1).

Subsection (a)(2) states that when an entity that fails to meet its triennial or 

annual compliance obligation only because it submitted offset credits that were 

invalidated upon review by the Executive Officer will not incur an excess 

emissions obligation.

Summary of Section 95857(a)(2).

This provision is needed because the Executive Officer may invalidate offset 

credits after they are issued. ARB staff believes it is possible that the entity 

submitting the offset credit for compliance may be unaware of the defect, and 

therefore should only have to replace the invalidated offset credit with a valid 

compliance instrument, and not face an excess emissions obligation.

Rationale for Section 95857(a)(2).

Subsection (b)(1) defines the quantity of excess emissions as the difference 

between the compliance obligation and any compliance instruments surrendered 

by the compliance deadline by the covered entity.

Summary of Section 95857(b)(1).

This provision is needed to define the calculation for excess emissions using two 

quantities known immediately after the compliance deadline.

Rationale for Section 95857(b)(1).

Subsection (b)(2) defines the covered entity’s compliance obligation for untimely 

surrender as four times the entity’s excess emissions

Summary of Section 95857(b)(2).

This provision is needed to provide the calculation for the excess emissions 

obligation using two quantities known immediately after the compliance deadline. 

ARB staff is proposing the excess emissions obligation to ensure that no covered 

entity would knowingly fail to meet its compliance obligations. ARB staff is 

proposing an in-kind obligation instead of a financial obligation, so that the 

obligation results in further environmental improvement.

Rationale for Section 95857(b)(2).

Summary of Section 95857(b)(3).
IX-51

Subsection (b)(3) states that a covered entity’s compliance obligation for untimely 

surrender may only be fulfilled with allowances issued by California or by a GHG 

ETS to which California has linked.

This provision is needed because ARB staff proposes to not allow the use of 

offset credits to satisfy the excess emissions obligation so that the obligation 

results in further environmental improvement.

Rationale for Section 95857(b)(3).

Subsection (c)(1) states that an excess emissions obligation is immediately due.

Summary of Section 95857(c)(1).

This provision is needed because having the obligation due immediately allows 

the Executive Officer to implement a procedure to obtain the required allowances 

if the covered entity continues to fail to meet its obligations.

Rationale for Section 95857(c)(1).

Subsection (c)(2) states that immediately upon determining that a covered entity 

has excess emissions, the Executive Officer shall prevent any transfers of 

compliance instruments from the Holding Account controlled by the covered 

entity.

Summary of Section 95857(c)(2).

This provision is needed to prevent entities intending to default on their 

obligations from transferring instruments from their accounts.

Rationale for Section 95857(c)(2).

Subsection (c)(3) states that the Executive Officer shall transfer any remaining 

allowances from the Holding Account controlled by the covered entity with 

excess emissions to its Compliance Account until the retirement obligations of 

this section are met.

Summary of Section 95857(c)(3).

This provision is needed to give the Executive Officer authority to withdraw 

compliance instruments from a Holding Account of an entity that has not met its 

compliance obligations. 

Rationale for Section 95857(c)(3).

Subsection (c)(4) states that a if the Executive Officer is unable to withdraw 

sufficient allowances from an entity’s Holding Account, the Executive Officer shall 

Summary of Section 95857(c)(4).
IX-52

provide the deficient covered entity 30 days to secure the allowances needed to 

cover its untimely surrender obligation.

This provision is needed because ARB staff believes a covered entity would 

need time to acquire compliance instruments to meet its excess emissions 

obligations.

Rationale for Section 95857(c)(4).

Subsection (c)(5) details a procedure to recover compliance instruments from a 

covered entity which defaults on its obligations.

Summary of Section 95857(c)(5).

This provision is needed because ARB must anticipate cases, however unlikely, 

in which a defaulting entity takes steps to shield compliance instruments from 

retirement.

Rationale for Section 95857(c)(5).

Subsection (c)(5)(A) allows the Executive Officer to identify Holding Accounts 

controlled by affiliates of the deficient covered entity, to which the covered entity 

has transferred compliance instruments during the compliance period for which a 

compliance obligation remains unfilled.

Summary of Section 95857(c)(5)(A).

This provision is needed to allow the Executive Officer to attempt to recover 

compliance instruments that should have been surrendered.

Rationale for Section 95857(c)(5)(A).

Subsection (c)(5)(B) allows the Executive Officer to prevent transfers from the 

Holding Accounts belonging to entities with a corporate association to the 

deficient entity to which a deficient covered entity has transferred allowances, 

and retrieve allowances from those accounts to meet the untimely surrender 

obligation.

Summary of Section 95857(c)(5)(B).

This provision is included to allow the Executive Officer to attempt to recover 

compliance instruments which should have been surrendered.

Rationale for Section 95857(c)(5)(B).

Subsection (c)(6) states that if the covered entity does not surrender sufficient 

allowances equal to its untimely surrender obligation by the end of the 30-day 

Summary of Section 95857(c)(6).
IX-53

period, the Executive Officer may undertake enforcement activities pursuant to 

Subarticle 15.

This provision is needed so that ARB may use additional enforcement measures 

in case a covered entity does not comply with its untimely surrender obligation 

following the 30-day period.

Rationale for Section 95857(c)(6).

Subsection (d) details the activities the Executive Officer will undertake when the

covered entity has complied with its untimely surrender obligations.

Summary of Section 95857(d).

This provision is needed because there are standard activities that the Executive 

Officer must undertake after the covered entity has complied with its untimely 

surrender obligations.

Rationale for Section 95857(d).

Subsection (d)(1) requires the Executive Officer to remove the restrictions on 

transfers from the Holding Accounts controlled by the covered entity and affiliated 

entities.

Summary of Section 95857(d)(1).

This provision is needed because once the untimely compliance obligation has 

been satisfied, there is no further need for the account restrictions.

Rationale for Section 95857(d)(1).

Subsection (d)(2) states that the Executive Officer must perform the usual postsurrender activities of retiring the surrendered compliance instruments and 

informing the programs and GHG ETS to which California is linked of the 

retirements.

Summary of Section 95857(d)(2).

This provision is needed because once the untimely compliance obligation has 

been rectified, the retirement process is the same as for timely compliance.

Rationale for Section 95857(d)(2).

Subsection (d)(3) states that the Executive Officer must transfer the allowances 

used to fulfill the untimely surrender obligation to the Price Containment Reserve.

Summary of Section 95857(d)(3).

Rationale for Section 95857(d)(3).
IX-54

This provision is needed because ARB staff is proposing this feature so that the 

fulfillment of the untimely surrender obligation does not overly reduce the supply 

of compliance instruments, and consequently raise their price. Placing these 

instruments in the Reserve will make them available at the Reserve release 

prices.

Subarticle 8. Disposition of Allowances.

Section 95870. Disposition of Allowances.

Section 95870 specifies how the total number of allowances available from each 

allowance budget will be divided. Each allowance is dedicated to one of the 

following categories: Allowance Price Containment Reserve, Advance Auction, 

Allocation to Electrical Distribution Utilities, Allocation to Industrial Covered 

Entities, or Auction Proceeds for AB 32 Statutory Objectives.

Summary of Section 95870, Disposition of Allowances.

This section is necessary to divide the value embodied by the tradable 

allowances among various AB 32 purposes. The first two categories—Allowance 

Price Containment Reserve and Advance Auction—enhance the operation of the 

allowance market by containing allowance price and providing a long-term signal 

about expected future prices. Dedicating allowances to electrical distribution 

utilities protects ratepayers from the costs of AB 32 programs. Distributing 

allowances to industrial covered entities helps to maintain the competitiveness of 

California industry and minimizes the risk of emissions leakage. Allocating 

allowances for the purpose of auction allows the Legislature to use auction 

proceeds for AB 32 purposes and protects fuel customers from the costs of 

AB 32 programs. 

Summary of Section 95870.

Subsection (a) proposes to allocate allowances to the Allowance Price 

Containment Reserve. One percent of the allowances from the first compliance 

period will be allocated to the price containment reserve. Four percent of the 

allowances from the second compliance period will be allocated to the price 

containment reserve. Seven percent of the allowances from the third compliance 

period will be allocated to the price containment reserve.

Summary of Section 95870(a). Allowance Price Containment Reserve.

The price containment reserve is expected to assist in maintaining allowance 

prices within a specific price range. The desired range was determined through 

the economic analysis of the cap-and-trade program, consideration of similar 

proposals in federal climate policy, and feedback from stakeholders. 

Rationale for Section 95870(a).
IX-55

The amount of allowances dedicated to the Reserve was selected based on an 

understanding of what size of reserve was necessary to provide the desired price 

containment. The level of allowances placed in the Reserve was matched with 

an introduction of additional offsets due to an expansion of the quantitative offset 

limit (relative to the level proposed in the Preliminary Draft Regulation). Placing a 

greater percentage of allowances to the Reserve from later periods enhances 

surety of price containment goals in the early years of the program.

Subsection (b) proposes to designate 2 percent of allowances from budget years 

2015 through 2020 for auction in prior compliance periods. Selling allowances 

from future compliance periods in the current period is known as advance 

auctioning. Subsection (b)(2) proposes that proceeds from the sale of 

allowances from future budget years be used in the same way as proceeds from 

other allowances auctioned pursuant to subsection 95870(e).

Summary of Section 95870(b). Advance Auction.

Auctioning allowances from future budget years in a current compliance period 

provides a price signal to the market about expectation of future prices. This is 

valuable for covered entities planning long-term investments in GHG abatement. 

Staff determined that advance auctioning 2 percent of the budgets from the 

second and third compliance periods ensured that enough allowances will be 

available for other purposes in these later years, while still allowing for a future 

price signal to be established.

Rationale for Section 95870(b).

AB 32 requires that all proceeds raised through programs enacted under the 

authority of AB 32 be placed into the Air Pollution Control Fund for appropriation 

by the Legislature (HSC 38597). Therefore, proceeds raised through advance 

auction will be placed into this fund. 

Subsection (c) describes how allowances will be given to public utilities. It 

includes allowances allocated to electrical distribution utilities and natural gas 

distribution utilities. 

Summary of Section 95870(c). Allocation to Public Utilities.

Free allocation of allowances to public utilities on behalf of their customers is 

designed to help offset the cost impacts of AB 32 policies. This is described in 

more detail for each type of utility below. 

Rationale for Section 95870(c).

Subsection (c)(1) describes how allowances will be given to electrical distribution 

utilities on behalf of the ratepayers in their distribution service territory. The 

Summary of Section 95870(c)(1), Electrical Distribution Utilities. 
IX-56

utilities will receive a total of 89 million allowances from budget year 2012, and 

this amount will decline at the rate established for the cap decline factor in 

subsequent years through 2020. These allowances will be placed into the 

accounts of distribution utilities annually.

Free allocation of allowances to electrical distribution utilities on behalf of their 

customers (ratepayers) is designed to help offset the cost impacts of AB 32

policies. The initial allocation to distribution utilities was selected by comparing 

the historical proportionate share of emissions produced from electricity 

(generated and placed on California’s transmission and distribution network) 

relative to total emissions covered in the cap-and-trade program. In making this 

calculation, staff used 2008 emissions shares to determine the percentage for 

the 2012–2014 budget years. This value was then adjusted downward

consistent with the cap decline factor, which is set consistent with the rate of 

decline of the overall cap during the first compliance period.

Rationale for Section 95870(c)(1).

Subsection (c)(2) is reserved for any possible future allocation to natural gas 

distribution utilities on behalf of their customers. 

Summary of Section 95870(c)(2). Natural Gas Distribution Utilities. 

The natural gas utilities have requested allowances on behalf of their customers. 

The proposed regulation does not currently provide for allocation to natural gas 

distribution utilities but leaves this subsection as a placeholder for such a 

provision in the future. 

Rationale of Section 95870(c)(2). 

Subsection (d) proposes to allocate allowances to industrial sectors for the 

purposes of industry assistance. The allowances will be transferred annually to 

each eligible covered entity’s Holding Account. The amount of allowances that 

each eligible industrial sector receives will be based on the assistance factors, as 

provided in Table 8-1 of Regulation. Subsection (d)(3) ensures that the total 

amount allocated to the Allowance Price Containment Reserve, advance auction,

electrical distribution utilities, and to industrial covered entities does not exceed 

the total allowance budget levels.

Summary of Section 95870(d). Allocation to Industrial Covered Entities. 

Industry assistance is necessary to provide a smooth transition into the cap-andtrade program for industrial covered sources that face a competitiveness risk. 

The level of assistance allocated will decline over time to a minimum level 

necessary to prevent emissions leakage as industrial sources adapt to carbon 

constraints. To align with federal mandatory reporting requirements for product 

Rationale for Section 95870(d).
IX-57

output reporting, allocation to industrial covered entities is based on an annual 

cycle. The table included in this section reflects ARB’s assessment of industry 

needs to ensure that covered entities can plan for future compliance obligations.

Subsection (e) is reserved for any possible future allocation to a voluntary 

renewable energy allowance set-aside.

Summary of Section 95870(e), Allocation to Voluntary Renewable Energy 

Allowance Set-Aside.

The cap-and-trade program could have negative effects on the voluntary 

renewable energy (VRE) market that could be addressed through a voluntary 

renewable energy allowance set-aside. The proposed regulation does not 

currently provide for allocation of voluntary renewable energy allowance setaside, but leaves this subsection as a placeholder for such a provision in the 

future.

Rationale for Section 95870(e).

Subsection (e) describes how the remaining allowances will be sold at auction, 

and how the proceeds will be placed in the Air Pollution Control Fund and made 

available for appropriation by the California Legislature. The Legislature will then 

direct how these proceeds will be used to protect fuel consumers and accomplish 

the statutory objectives of AB 32. 

Summary of Section 95870(f). Auction Proceeds for AB 32 Statutory Objectives.

AB 32 requires that all proceeds raised through programs enacted under the 

authority of AB 32 be placed into the Air Pollution Control Fund for appropriation 

by the Legislature (HSC 38597).

Rationale for Section 95870(f).

Subarticle 9. Direct Allocations of California GHG Allowances.

Section 95890. General Provisions for Direct Allocations.

Section 95890 specifies the requirements that entities must meet to be eligible 

for free allowances. This requirement includes complying with the MRR and 

obtaining a positive or qualified positive verification statement.

Summary of Section 95890. General Provisions for Direct Allocations.

This section is necessary because the amount of allowances that a covered 

entity receives annually must be based on verified output data reported through 

the MRR process. Verified data ensures the level of free allowances that a 

Rationale for Section 95890.
IX-58

covered entity receives is accurate and has been checked by an ARB accredited 

verifier.

Section 95891. Allocation for Industry Assistance.

Subsection (a) explains how ARB will determine which benchmarking 

methodology will be used to calculate the number of free allowances that each 

leakage-exposed industrial covered entity will receive. For entities that are listed 

in both tables 8-1 and 9-1 of the Regulation, the benchmarking methodology will 

be based on product output. For entities that are listed in Table 8-1 but not in 

Table 9-1 the benchmarking methodology will be based on energy consumption. 

Entities that are not listed in Table 8-1 will not receive free allocation under this 

provision. 

Summary of Section 95891(a).

Product-based benchmarks set an allocation level based on a unit of output. 

Staff proposes to apply product-based allocation as the preferred methodology to 

provide transition assistance and prevent leakage. This section is necessary 

because product-based allocation creates all of the correct incentives to produce 

a given product in the most GHG-efficient way possible and to minimize leakage.

Rationale for Section 95891(a).

For industrial activities with a competitiveness or leakage risk for which a 

product-based allocation cannot be developed, staff proposes a ”fallback”

allocation methodology based on benchmarking energy consumption choices. 

Subsection (b) proposes a formula to calculate the number of allowances given 

to each eligible covered entity based on the product output-based benchmarking 

methodology. The number of allowances for each eligible, covered entity will be 

determined by multiplying a facility’s output by the sector-wide emissions 

efficiency benchmark specified in Table 9-1. A facility’s output is based on the 

three most recently reported data years. The allocation is then adjusted by the 

sector-wide assistance factor specified in Table 8-1, and the sector-specific cap 

adjustment factor specified in Table 9-2 of the Regulation. 

Summary of Section 95891(b), Product Output-Based Allocation Calculation 

Methodology. 

This provision is necessary to calculate how many allowances each eligible 

covered entity will be given for industry transition assistance and leakage 

prevention and to provide certainty to covered entities.

Rationale for Section 95891(b).

Summary of Section 95891(c), Thermal Energy-Based Allocation Calculation 

Methodology.
IX-59

Subsection (c) proposes a formula to calculate the number of allowances given 

to each eligible covered entity based on benchmarking of energy consumption 

practices. The number of allowances for each eligible covered entity will be 

determined by multiplying the sector-specific assistance factor specified in 

Table 8-1 of the Regulation by the program-wide cap adjustment factor specified 

in Table 9-2, and an energy consumption term. The energy consumption term is 

dependent on the uses of fuel and steam at a given facility during the 2000–2010 

historical baseline period.

This provision is necessary to calculate how many allowances each eligible,

covered entity will be given for industry assistance using the energy-based 

allocation. The energy-based allocation is used because the only alternative is to 

calculate the allocation based on specifics of each facility or develop a productbased allocation for all industry, which is not feasible at this time. 

Rationale for Section 95891(c).

Staff proposes that entities should receive either direct or indirect allocations to 

reduce GHG costs for energy consumed in a leakage-exposed manufacturing 

process. Energy embodied in steam consumed in the process and energy from 

direct fire applications receives a direct allocation through the thermal energy 

formula. Energy for electricity produced and consumed on-site also receives a 

direct allocation to offset direct GHG costs in the manufacturing process. 

Thermal energy used to produce steam and electricity exported off-site receives 

no compensation because staff assumes that GHG costs can be passed on to 

the consumer of this energy.

Electricity purchased from off-site is not part of the thermal energy-based 

allocation equation but receives indirect compensation through distribution utility 

to offset the expected indirect GHG costs, as described in Section 95892. 

The thermal energy consumed from the fuel combustion benchmark is based on 

GHG emissions levels from natural gas combustion, the dominant fuel used in 

California manufacturing facilities. 

For energy embodied in the steam consumed by each facility, the benchmark is 

based on comparison to a theoretical boiler combusting natural gas with an 

assumed efficiency of 85 percent. This is intended to represent a highly efficient 

industrial boiler. 

Subsection (c)(1) indicates the data sources that staff proposes ARB employ 

when calculating baseline levels of allocation to covered entities under the 

thermal energy-based methodology. 

Summary of Section 95891(c)(1), Data Sources.

Rationale for Section 95891(c)(1).
IX-60

Staff proposes that establishing the facility baselines under the thermal energybased allocation method would employ data reported to ARB under the MRR. 

Any data that can be third-party verified and reported to ARB for the 2000–2010 

base period will be evaluated by the Executive Officer. Staff proposes 

supplementing these data with an analysis of third-party verified data reported to 

the California Climate Action Registry (CCAR) for years 2000–2007 as available. 

These data sources have been chosen because staff believes that the third-party 

verified data reports submitted to ARB and CCAR represent the most accurate 

data for California facilities currently available.

Subsection (c)(2) establishes an absolute limit on the level of free allocation 

under the thermal energy-based allocation relative to historical GHG emissions

levels from a given facility. This limit is set at 110 percent of the maximum 

annual emissions during the baseline period. 

Summary of Section 95891(c)(2), Maximum Free Allocation.

The thermal energy-based allocation is intended to reward facilities that have 

taken early action and chosen low-GHG fuels and/or employed efficient steamgeneration systems. This reward occurs through allocating free allowances 

greater than expected compliance obligation to these facilities. This section is 

necessary to prevent the level of this reward from becoming excessive, and is 

constrained by other desired uses of allowance value. Staff proposes that the 

110 percent of maximum historical emissions levels is sufficient reward to 

recognize early action and to ensure that early actors who have already taken on 

reductions equal to that required by the decline in allowance budgets over the 

2012–2020 period are buffered from the impact of the declining (cap adjustment 

factor) term.

Rationale for Section 95891(c)(2).

Subsection (c)(3) describes how covered entities for eligible industrial facilities 

new to the cap-and-trade program will receive allowances under the thermal 

energy-based allocation. 

Summary of Section 95891(c)(3), New Entrants.

The thermal energy-based allocation relies on information from a historical base 

period. To the extent that facilities did not operate or exist during this base 

period, the Executive Officer will need to assign a baseline level of allocation 

based on anticipated energy use to allocate allowances to these facilities. 

Rationale for Section 95891(c)(3).

Summary of Section 95891(c)(4), Facility Closures.
IX-61

Subsection (c)(4) clarifies that covered entities will not continue to receive free 

allocation for any facilities that close or are no longer covered by the cap-andtrade program. 

Staff believes that continuing free allocation to covered entities that cease 

activities in California would create an incentive for leakage. Therefore, firms 

that close operations in California will no longer receive free allocations. 

Rationale for Section 95891(c)(4).

Firms that fall below the emissions inclusion thresholds due to GHG abatement 

can voluntary choose to remain in the cap-and-trade program as opt-in covered 

entities and continued to receive free allocation.

Section 95892. Allocation to Electrical Distribution Utilities for Protection 

of Electricity Ratepayers.

Subsection (a) is reserved for the formula by which electrical distribution utilities 

will receive allowances on behalf of their ratepayers. 

Summary of Section 95892(a).

The allocation formula for distribution of allowances to electrical distribution 

utilities must further the cap-and-trade emissions-reduction objectives, including 

providing incentives to reduce emissions cost-effectively. Additionally, the 

allocation must enable all the utilities to serve their customers reliably and 

affordably. Details of the formula will be developed based on comments received 

during the 45-day comment period on the proposed regulation, and will be 

circulated for review in a subsequent 15-day comment period.

Rationale for Section 95892(a).

Subsection (b) explains that investor-owned utilities (electrical corporations) will 

receive free allocation into a special type of account called a Limited Use Holding 

Account. Publicly owned utilities will have the option to have allocations 

distributed to their limited use Holding Accounts or to their Compliance Accounts.

Summary of Section 95892(b). Transfer to Utility Accounts.

Distribution utilities that plan to monetize allowances on behalf of their ratepayers 

will receive a free allocation into limited use Holding Accounts. All allowances 

given to investor-owned utilities are required to be monetized. The publicly

owned utilities have more flexibility. The transactions of allowances to and from 

limited use Holding Accounts will have special restrictions in the market tracking 

system. 

Rationale for Section 95892(b).
IX-62

Subsection (c) requires that distribution utilities offer each freely allocated 

allowance placed into a limited-use Holding Account at auction at least once in 

the calendar year corresponding to the budget year from which that allowance 

was issued. 

Summary of Section 95892(c), Monetization Requirement.

If an allowance is not sold in the calendar year corresponding to the allowance’s 

budget year (i.e., if the auction reserve price is not met for that allowance) the 

retail provider must offer this allowance at auction at least once in each of the 

following calendar years until it is sold. 

Monetization of allowances through auction is intended to ensure that the amount 

of value given to distribution utilities is transparent to the public, and that this 

value is used on behalf of electricity ratepayers. This practice will also ensure 

that freely allocated allowances to a distribution utility will not impact competition 

in the electricity generation market (where utilities compete with merchant power 

producers).

Rationale for Section 95892(c).

This condition on allocating allowance value to distribution utilities was 

recommended to ARB by the California Public Utilities Commission and the 

California Energy Commission.

Subsection (d) establishes limitations on how a distribution utility can use 

proceeds raised from the sale of allowances at auction.

Summary of Section 95892(d), Limitations on the Use of Auction Proceeds.

These limitations ensure that allowance value given to a distribution utility will be 

used on behalf of ratepayers and in ways that are consistent with AB 32 statutory 

objectives. 

Rationale for Section 95892(d).

Subsections (d)(1) and (d)(2) clarify that distribution utility proceeds from the sale 

of allowances at auction will be subject to limitations imposed by either the 

California Public Utilities Commission or by the governing bodies of publicly 

owned utilities. 

Summary of Section 95892(d)(1) and 95892(d)(2).

Proceeds from sale at allowances at auction will generate a new revenue stream

for a distribution utility. This revenue stream will need to be accounted for along 

Rationale for Section 95892(d)(1) and 95892(d)(2).
IX-63

with all other revenues and costs in the ratemaking actions of the CPUC and the 

governing bodies of the POUs. 

Subsection (d)(3) clarifies that the statutory goals of AB 32 apply to all utility 

proceeds raised through auctioned allowances and that all proceeds must be 

used to the benefit of ratepayers rather than for the benefit of shareholders (or 

any other entities). Further limitations are placed on how rebates directly to 

customers must function.

Summary of Section 95892(d)(3).

Limiting the use of proceeds on behalf of ratepayers and for the purposes of 

AB 32 ensures that distribution utility adopt programs that support GHG

reductions and minimize cost of these programs to their customers. 

Rationale for Section 95892(d)(3).

Limiting customer rebates such that they appear on the fixed portion of customer 

bills and cannot be based solely on the amount of electricity consumed in any 

period after 2012 is intended to create an incentive to use less electricity and 

create a GHG price signal in retail electric rates. 

Subsection (e) requires that distribution utilities report to ARB on how they use 

proceeds generated from the sale of allowances at auction. 

Summary of Section 95892(e), Reporting on the Use of Auction Proceeds.

This provision will ensure transparency on how distribution utilities use allowance 

value and demonstrate that this value is used for the purposes of AB 32 

implementation.

Rationale for Section 95892(e).

Section 95893. Reserved for Allocation to Natural Gas Distribution Utilities 

for Protection of Natural Gas Ratepayers.

Section 95893 is reserved for the details of any possible future allocation method 

to individual natural gas distribution utilities on behalf of their customers. 

Summary of Section 95893.

The natural gas utilities have requested allowances on behalf of their customers. 

The proposed regulation does not currently allow for allocation to natural gas 

distribution utilities but leaves this section as a placeholder for such a provision in 

the future. 

Rationale for Section 95893.
IX-64

Subarticle 10. Auction and Sale of California Greenhouse Gas Allowances.

Section 95910. Timing of Auction of California GHG Allowances.

Subsection (a) sets a quarterly schedule for auctions.

Summary of Section 95910(a), Timing of Allowance Auctions.

The provision is needed because ARB must inform potential auction participants 

of the schedule for the quarterly auctions. ARB chose a quarterly auction to 

balance the costs of running auctions against the need to have a frequent price 

signal to the market.

Rationale for Section 95910(a).

Subsection (a)(1) states that the first auction will take place on February 14, 2012.

Summary of Section 95910(a)(1).

The provision is needed because ARB must inform potential auction participants 

of the schedule for the quarterly auctions. This schedule places an auction close 

to the beginning of the program. Some stakeholders indicated they intend to 

purchase allowances as they emit, so ARB must get a supply into the market at 

the beginning of the program.

Rationale for Section 95910(a)(1).

Subsection (a)(2) states that after the first auction, quarterly auctions will take 

place on the twelfth business day of the first month of each calendar quarter.

Summary of Section 95910(a)(2).

The provision is needed because ARB must inform potential auction participants 

of the schedule for the quarterly auctions.

Rationale for Section 95910(a)(2).

Subsection (b) states that ARB may auction allowances created for future 

allowance budget years during each auction.

Summary of Section 95910(b).

The provision is needed because ARB will allow entities to purchase allowances 

from future budget years to allow them to plan their purchases over a longer time 

horizon. However, they will not be able to use these allowances for compliance 

prior to their vintage year.

Rationale for Section 95910(b).
IX-65

Subsection (c)(1) states that ARB will auction one-fourth of the allowances 

designated for auction each year at each quarterly auction.

Summary of Section 95910(c)(1).

The provision is needed because ARB believes spreading the auction of 

allowances evenly through the year will provide for a more predictable entry of 

new supply to the market. This should allow for easier planning of allowances 

purchases by auction participants.

Rationale for Section 95910(c)(1).

Subsection (c)(2) states that ARB will auction one-fourth of the allowances from 

future budget years, which are designated for auction each calendar year, at 

each quarterly auction.

Summary of Section 95910(c)(2).

The provision is needed because ARB believes spreading the auction of 

allowances evenly through the year will provide for a more predictable entry of 

new supply to the market. This should allow for easier planning of allowances 

purchases by auction participants.

Rationale for Section 95910(c)(2).

Subsection (c)(3) states that ARB will conduct separate auctions for current and 

future vintage allowances during each quarter.

Summary of Section 95910(c)(3).

The provision is needed because auctions must be conducted separately, as 

future vintage allowances cannot be used for current compliance. ARB expects 

that separate auctions would result in different prices for current and future 

vintage allowances because the auction price of future vintage allowances will 

reflect bidders’ evaluation of future prices and the added interest costs of buying 

and holding allowances that cannot be used for compliance right away.

Rationale for Section 95910(c)(3).

Subsection (d)(1) states that ARB will not just auction allowances from its annual 

allowance budget. ARB will allow electrical distribution utilities to have ARB 

auction some allowances held by the entities, in what is known as a consignment 

auction. Only an entity with Limited Use Holding Account may use the 

consignment feature.

Summary of Section 95910(d)(1).

Rationale for Section 95910(d)(1).
IX-66

The provision is needed because ARB has identified instances in which electrical 

distribution utilities should be allowed to sell allowances through ARB’s auction. 

ARB intends to directly allocate allowances to the electrical distribution utilities for 

the benefit of their ratepayers. ARB chose the consignment auction feature to 

ensure that proceeds from the sale of the allowances benefit the ratepayers. 

ARB will assign the electrical distribution utilities Limited Use Holding Accounts to 

receive direct allocations of allowances from ARB. Once allowances are in the 

Limited Use Holding Account, the electrical distribution utilities may only consign 

them to the auction and cannot use them for any other purpose.

Subsection (d)(2) states that pursuant to 95831, ARB may close or revoke a 

Holding Account due to rule violations or a lack of activity by an entity. In these 

cases ARB will give the entity time to sell or retire the allowances in the account. 

If the entity does not do this, ARB will consign the allowances to the auction and 

then close the account. If the account contains offset credits, then the Executive 

Officer will review the validity of the offset credits. If they are valid, the Executive 

Officer will retire them, withdraw the same number of allowances from the 

Auction Holding Account, and consign them to the next auction in place of the 

offset credits.

Summary of Section 95910(d)(2).

The provision is needed because if an entity is no longer participating in the 

system, its account must be closed. ARB must be able to transfer any remaining 

allowances to another account. The only method available is to consign them to 

the auction. This is straightforward for allowances, but ARB will not be 

auctioning offset credits. If offset credits are withdrawn from a closed account, 

the Executive Officer will determine if they are valid. If they are not, they will 

immediately be invalidated and their serial numbers removed from the tracking 

system. The account holder will receive no payment for them. If the review 

shows the offset credits are valid, they will be retired and the Executive Officer 

will withdraw the same number of allowances from the Auction Holding Account 

and consign them to the auction in place of the offset credits.

Rationale for Section 95910(d)(2).

Subsection (d)(3) states that anyone using the consignment option agrees to 

accept the auction settlement price.

Summary of Section 95910(d)(3).

The provision is needed because auction results are uncertain. Those entities 

using the consignment auction must commit to the auction before they know the 

auction settlement price. 

Rationale for Section 95910(d)(3).

Summary of Section 95910(d)(4).
IX-67

Subsection (d)(4) states that entities must have consigned allowances at least 60 

days before the auction date for them to be sold at the next auction. Otherwise, 

ARB will hold the consigned allowances for the next auction.

The provision is needed because ARB must have time to complete the 

administrative procedures for the consignment auction before the auction takes 

place, including publishing the number of allowances that will be sold at the next 

auction.

Rationale for Section 95910(d)(4).

Section 95911. Format for Auction of California GHG Allowances.

Subsection (a)(1) requires a single-round auction. 

Summary of Section 95911(a)(1).

The provision is needed because ARB staff determined that a single-round 

format would reduce costs to auction participants and to ARB, compared with a 

multiple-round auction format. 

Rationale for Section 95911(a)(1).

Subsection (a)(2) requires auction participants to submit sealed bids.

Summary of Section 95911(a)(2).

The provision is needed to reduce the chances for collusion among auction 

participants. Other sections in this subarticle contain rules designed to prevent 

participants from sharing information that could result in collusion.

Rationale for Section 95911(a)(2).

Subsection (a)(3) requires auction participants to submit bids for allowances in 

multiples of 1,000 metric tons.

Summary of Section 95911(a)(3).

The provision is needed to simplify the auction process. Covered entities face a 

minimum threshold of 25,000 tons. Even with a minimum quantity of 1,000 tons 

per bid the smallest covered entity could spread out its purchases over a large 

number of auctions or bid prices.

Rationale for Section 95911(a)(3).

Subsection (a)(4) requires auction participants to submit bids in whole dollars 

and whole cents.

Summary of Section 95911(a)(4).
IX-68

The provision is needed to simplify bidding and auction operations.

Rationale for Section 95911(a)(4).

Subsections (b)(1) and (b)(2) set a reserve price for each auction. The auction 

operator will not accept bids below the reserve price. No allowances can be 

awarded to bids below the reserve price.

Summary of Section 95911(b)(1) and (b)(2).

These provisions are needed because staff determined that a reserve price, 

which is a minimum price for an auction, should be used for the auction. The 

reserve price will be announced prior to the deadline for submitting bids.

Rationale for Section 95911(b)(1) and (b)(2).

Most auctions use a reserve price. There are many reasons for using a reserve 

price. First, someone auctioning a good may have another way to sell or use the 

item. They would not accept an auction price for less than the value they could 

get from an alternative use or method of sale. Second, auction operators may 

use a reserve price to deter collusion. Collusion can occur if bidders are capable 

of communicating with other bidders and agreeing to submit low bids. The 

reserve price limits how far collusion could drive down prices. Third, in the case 

of GHG allowances, ARB may choose to use a reserve price to incent direct 

reductions by compliance entities or to support investment in offset projects. If 

allowances are abundant and there is no reserve price, it may be cheaper for 

covered entities to purchase allowances and not make any direct reductions. A 

reserve price would create an incentive for covered entities to find direct 

reductions that cost less than the reserve price. Similarly, if allowances are 

overabundant then they may cost less than what it would cost to operate a 

project to create offset credits. ARB could determine a price at which investment 

in some offset projects would be cost-effective. 

ARB proposes an auction reserve price to provide a price floor to support 

investment in direct reductions and offset credit projects. ARB’s cost 

containment approach requires the steady production of offset credits. If these 

do not materialize the Allowance Price Containment Reserve will not provide 

price stability because market participants will realize that the diversion of future 

vintage allowances to the Allowance Price Containment Reserve will result in a 

shortage of allowances in later compliance periods. ARB has also observed that 

a prolonged period of low allowance prices in the Northeast Regional 

Greenhouse Gas Initiative (RGGI) market has not supported incentives for the 

creation of offset credits.

Subsection (b)(3) describes how the auction operator will award allowances 

when an auction settlement price equals the minimum reserve price.

Summary of Section 95911(b)(3).
IX-69

The provision is needed because when the settlement price equals the reserve 

price there will be allowances left over. Since the allowances at any given 

auction may come from several sources, ARB needs to determine in what order

allowances will be sold from each source.

Rationale for Section 95911(b)(3).

Subsection (b)(3)(A) lists the sources of allowances that are auctioned. When 

the auction results in some allowances left over, the auction operator will sell 

allowances from one source until all the allowances from that source are sold. 

The operator will then move on to the next source. The sales will be conducted 

from sources in the following order: allowances consigned from closed, revoked, 

or suspended accounts; allowances consigned from Limited Use Holding 

Accounts; and finally, allowances allocated directly to auction by ARB.

Summary of Section 95911(b)(3)(A).

The provision is needed because ARB may need to return unsold allowances to 

their source accounts. Since this is not possible for allowances from closed, 

suspended, or revoked accounts, this source is given the first sales priority. The 

next sources are those entities consigning allowances. ARB intends to give 

these sources the next sales priority to simplify the consignment process. The 

lowest priority source is the ARB Auction Holding Account. ARB assigns this the 

lowest priority because it is easy for ARB to redirect the unsold allowances from 

this source to the Allowance Price Containment Reserve.

Rationale for Section 95911(b)(3)(A).

Subsection (b)(3)(B) states that if the auction operator fills all winning bids before 

exhausting all allowances from one of the consigned sources, the auction 

operator will sell an equal number of allowances from each consigning entity in 

that source category.

Summary of Section 95911(b)(3)(B).

The provision is needed because as the auction operator sells from one of the 

consignment source categories described above, it may fill all winning bids 

before every allowance from that source is sold. In this case, the auction 

operator will sell an equal number of allowances from each entity in that 

consignment category.

Rationale for Section 95911(b)(3)(B).

Subsection (b)(4) states that allowances designated by ARB for a quarterly 

auction which remain unsold will be transferred to the highest price tier of the 

Allowance Price Containment Reserve Holding Account.

Summary of Section 95911(b)(4).
IX-70

The provision is needed because allowances transferred from the Allocation 

Holding Account to the Auction Holding Account will not go back to the Allocation 

Holding Account if they remain unsold. Instead, ARB will transfer them to the 

Allowance Price Containment Reserve Holding Account. Once in that account, 

they may be purchased by covered entities pursuant to 95913. Allowances will 

remain unsold during times of oversupply and lower prices. ARB considered 

holding them over until the next auction, but that simply continues the oversupply. 

Placing them in the Reserve will make them available during periods of shortage 

and higher prices. ARB proposes to place them in the highest price tier because 

it is possible that all of the allowances in the lower tiers may be sold, at which 

point ARB will close those tiers to further sales.

Rationale for Section 95911(b)(4).

Subsection (b)(5)(A) states that allowances consigned to auction from Limited 

Use Holding Accounts that remain unsold at auction will be returned to their 

source accounts.

Summary of Section 95911(b)(5)(A).

The provision is needed if the auction settlement price equals the Reserve Price, 

then some allowances remain unsold. ARB must return them to the accounts 

from which they were consigned. This allows the account holders to determine 

when is the best time to consign the allowances.

Rationale for Section 95911(b)(5)(A).

Subsection (b)(5)(B) states that allowances removed from closed Holding 

Accounts that remain unsold at auction will be held in the Auction Holding 

Account until the next auction.

Summary of Section 95911(b)(5)(B).

The provision is needed because once a Holding Account is closed, allowances 

cannot be transferred back to it. The only option for allowances transferred from 

a closed account to the auction is to retain the allowances in the Auction Holding 

Account until they are sold, and the proceeds sent on to the entity with the closed 

account.

Rationale for Section 95911(b)(5)(B).

Subsection (b)(6)(A) states that for auctions conducted during 2012, the auction 

Reserve Price shall be $10 for the auction of allowances from the 2012 

allowance budget year, and $11.58 for the auction of allowances from the 2015 

allowance budget year.

Summary of Section 95911(b)(6)(A).
IX-71

Staff proposes a $10 initial reserve price for auctions beginning in 2012 to 

provide incentives for direct emissions reductions and the investment in offset 

credit projects. The reserve price for the advance auction will start at $11.58 to 

reflect the rate at which the reserve price will increase each year. (Subsection 

95911(b)(6)(B) explains how staff determined the inflator mechanism.)

Rationale for Section 95911(b)(6)(A).

Staff chose the $10 reserve price for two reasons. First, staff are concerned that 

through recessionary economic conditions or forecasting error the cap-setting 

procedure may accidently lead to the creation of excess allowances. Throughout 

the regulatory process, staff heard concerns from environmental groups that the 

cap would be unintentionally set too lax—a condition sometimes referred to as 

oversupply or over-allocation. The over-allocation condition occurs if too many 

allowances are supplied to covered entities relative to expected business-asusual emissions levels. If the cap is set too loose, prices will be lower than 

expected, and a weakened incentive to reduce emissions will be created. The 

reserve price mechanism would correct this condition by transferring excess 

allowances to the Allowance Price Containment Reserve, where they will be 

available in times of high prices.

Second, staff is adapting the approach used in the federal Waxman-Markey 

proposal (HR 2454), which proposed a reserve price of $10 with an inflator 

mechanism of 5 percent per year plus inflation. 

Subsection (b)(6)(B) states that for auctions conducted after 2012, the auction 

reserve prices for the current and advance auctions from the previous year will 

each be increased by 5 percent plus the Consumer Price Index for All Urban 

Consumers.

Summary of Section 95911(b)(6)(B).

Staff proposes an inflator mechanism based on the expectation that marginal 

abatement costs and offset project costs will increase over time as lower costabatement measures are undertaken first, and due to inflation. Auction reserve 

prices would need to increase to reflect the increased marginal abatement cost 

and the inflation rate; otherwise, the reserve price would no longer support direct 

reductions and offset projects as intended.

Rationale for Section 95911(b)(6)(B).

ARB’s staff economic analysis assumed a rate of increase in marginal abatement 

costs of 7 percent, without factoring in inflation. Staff proposes to increase the 

reserve price by 5 percent, plus inflation each year, so that the reserve price 

continues to support direct reductions and offset investment as those become 

more expensive. At the same time, the reserve price will rise more slowly than 

the expected marginal abatement cost so that the reserve price does not make 

the program unnecessarily more expensive.
IX-72

Subsection (c) states that ARB will limit the share of the allowances at an auction 

that can be purchased by an entity or group of entities that has a corporate 

association under section 95914 to a fixed percentage. The limit will apply from 

2012 through 2014.

Summary of Section 95911(c).

The provision is needed because ARB has determined that a purchase limit 

should apply at each auction, to ensure that a few entities do not obtain market 

power through purchases at the auctions. Purchase limits are common features 

at existing auctions. For example, RGGI applies a 25 percent purchase limit to its 

auctions of GHG allowances. 

Rationale for Section 95911(c).

ARB is proposing the limit for the first compliance period and will set the limit for 

subsequent periods in a later rulemaking. ARB is proposing this approach for 

three reasons. First, ARB will have a better understanding of the compliance 

needs of larger entities when new reporting data become available for the 

expanded scope of the program during the second compliance period. Second, 

ARB recognizes that the market will take time to develop, and it may be 

necessary to revise the limit based on actual market experience. Third, ARB 

intends to link with WCI jurisdictions at some point, but WCI has not arrived at a 

decision on purchase limits. ARB may have to revise the limit to account for the 

size distribution of covered entities in the WCI.

Subsection (c)(1) states that the purchase limit will be 10 percent for covered 

entities and opt-in covered entities.

Summary of Section 95911(c)(1).

The provision is needed to base the purchase limit on an assessment of the 

holding limit and limited exemption for the larger covered entities in California. 

The holding limit with the limited exemption, contained in 95920, would constrain 

the largest covered entities in California to about 10 percent of the allowances 

issued annually. The purchase limit constrains them to purchase no more than 

the same share at auction. Staff believes this level will allow them to purchase 

sufficient allowances at auction given the direct allocations planned for the first 

compliance period. Smaller entities will have more flexibility. 

Rationale for Section 95911(c)(1).

Subsection (c)(2) states that the purchase limit will not apply to electrical 

corporations receiving a direct allocation of allowances which they may only 

consign to auction. The section may not be interpreted to exempt the entities 

Summary of Section 95911(c)(2).
IX-73

from any other requirements, especially the holding limit contained in 

Subarticle 11.

This provision is needed due to the complexity of evaluating the compliance 

obligations of electrical corporations which import large amounts of electricity. 

ARB proposes to exempt these entities for three reasons. First, the only way to 

accommodate their compliance needs would be to raise the purchase limit to a 

point at which the limit has no effect on any entity. Second, these entities do not 

receive an allocation of allowances that they can use for their own compliance 

needs. They must purchase their entire obligation at auction or in the secondary 

market. Other covered entities participating in the auction do not face this 

constraint. Third, these entities are also regulated by the California Public 

Utilities Commission. The exemption from the purchase limit does not exempt 

them from other requirements of this regulation.

Rationale for Section 95911(c)(2).

Subsection (c)(3) states that the purchase limit will be 4 percent for voluntarily 

associated entities.

Summary of Section 95911(c)(3).

The provision is needed to base the purchase limit on an assessment of the 

holding limit without the limited exemption. Voluntarily associated entities do not 

qualify for the exemption. Based on current estimates of the 2012 allowance 

budget, the holding limit will allow voluntarily associated entities to hold about 

4 percent of the annual allowance budget. The purchase limit allows them to 

purchase at auction in the same proportion

Rationale for Section 95911(c)(3).

Subsection (d) states that the auction process will generate a single, or “uniform,” 

auction settlement price. All entities winning allowances will pay the same price 

for them.

Summary of Section 95911(d).

The provision is needed to use a single price auction format instead of a “pay-asbid” format. Staff concluded that the uniform price format would make it easier 

for bidders to bid their true valuation of the allowances with less risk of 

overpaying for allowances. 

Rationale for Section 95911(d).

Summary of Section 95911(d)(1).
IX-74

Subsection (d)(1) states that each bid will consist of a price and the number of 

allowances to be purchased at that price. The quantity must be in multiples of 

1,000 metric tons.

The provision is needed to conduct a single-round, uniform price auction. The 

requirement that bid quantities be in units of 1,000 allowances was chosen to 

simplify the auction process. Since covered entities would have obligations 

greater than 25,000 metric tons per year, staff concluded that the requirement 

would not prevent them from being able to spread out their purchases over a 

large number of separate bids. 

Rationale for Section 95911(d)(1).

Subsection (d)(2) states that each bidder may submit multiple bids.

Summary of Section 95911(d)(2).

The provision is needed because bidders may use multiple bids to attempt to get 

most of their allowances when prices are low. Allowing multiple bids means that 

bidders can speculate on what the settlement price may be, while still ensuring 

they can purchase at least some allowances. For example, an entity may place 

one high bid because it has decided it needs at least that number of allowances 

at no more than a particular price. It may then place one or more bids at much 

lower prices, perhaps even below the price the entity expects, just in case the 

auction settles at an unusually low price. The only constraints on the bids are the 

purchase limit and the value of the bids compared to the value of the bid 

guarantee the bidder is willing to supply.

Rationale for Section 95911(d)(2).

Subsection (d)(3) states that the auction operator will place the bids in declining 

order, from highest to lowest bid price.

Summary of Section 95911(d)(3).

The provision is needed because placing the bids in declining price order allows 

the auction operator to determine whether the bids meet various auction rules. 

The auction operator will apply the rules to an entity’s highest bid first, then 

proceeds to lower bids. This procedure will preserve an entity’s more 

competitive bids if the auction administrator does not accept all the entity’s bids.

Rationale for Section 95911(d)(3).

Subsection (d)(3)(A) states that the auction operator will not accept a bid if 

acceptance of the bid would violate the purchase limit.

Summary of Section 95911(d)(3)(A).
IX-75

The provision is needed because the action operator will evaluate the cumulative 

bids submitted by an entity against the purchase limits for individual or 

associated entities as appropriate. If a bid would result in an entity exceeding a 

limit, the auction operator will not accept it. If a bid is not accepted, the bid is 

disqualified. It will not be used to determine winning bids or the auction 

settlement price. 

Rationale for Section 95911(d)(3)(A).

Subsection (d)(3)(B) states that the auction operator will not accept a bid if 

acceptance of the bid would violate the holding limit.

Summary of Section 95911(d)(3)(B).

The provision is needed because the action operator will evaluate the cumulative 

bids submitted by an entity against the holding limits for individual or associated 

entities as appropriate. If a bid would result in an entity exceeding a limit, the 

auction operator will not accept it. If a bid is not accepted, the bid is disqualified. 

It will not be used to determine winning bids or the auction settlement price.

Rationale for Section 95911(d)(3)(B).

Subsection (d)(3)(C) states that the auction operator will not accept a bid if 

acceptance of the bid would result in the total value of the accepted bids 

exceeding the value of the bid guarantee submitted by the entity.

Summary of Section 95911(d)(3)(C).

The provision is needed because the auction operator will calculate the value of 

a bid as the bid price times the quantity. The auction operator will add the value 

of each bid submitted by the entity in declining price order until all of the entity’s 

bids have been counted or the cumulative value of the bids becomes greater 

than the value of the bid guarantee submitted by the entity. The auction operator 

will disqualify a bid that causes the cumulative value of bids to exceed the bid 

guarantee. 

Rationale for Section 95911(d)(3)(C).

Subsection (d)(4) states that the auction operator will award allowances 

beginning with the highest bid and proceeding in declining bid price order.

Summary of Section 95911(d)(4).

The provision is needed to implement the uniform price auction. While most 

bidders do not generally pay their bid price in a uniform price auction, bidding 

Rationale for Section 95911(d)(4).
IX-76

high helps ensure that the bidder wins allowances. Allowances are awarded to 

the bids in declining price order until the auction operator meets a stopping point.

Subsection (d)(4)(A) states that the auction operator will stop awarding 

allowances when the next lower bid price is less than the auction reserve price. 

At that point the auction operator declares the last winning bid as the auction 

settlement price.

Summary of Section 95911(d)(4)(A).

The provision is needed because the auction operator cannot sell allowances 

below the reserve price. The auction operator must then set the auction 

settlement price equal to the reserve price. All winning bidders will pay the 

auction settlement price.

Rationale for Section 95911(d)(4)(A).

Subsection (d)(4)(B) states what will happen if the quantity of allowance bids at 

the next lower bid price is greater than the number of allowances left to award. 

In this case the auction operator declares that price to be the auction settlement 

price, and will apply the tie-breaking procedure in 95911(d)(5). 

Summary of Section 95911(d)(4)(B).

The provision is needed because the auction operator sets the settlement price 

at the level that will exhaust all bids. In this case, there remain more bids than 

unawarded allowances. The auction operator must begin the tie-breaking 

procedure to award the last remaining allowances.

Rationale for Section 95911(d)(4)(B).

Subsection (d)(5)(A) states that the auction operator may have to deal with 

instances in which there are more bids than allowances left. The auction 

operator will use a random number generator to assign a number to each bundle 

of 1,000 allowances contained in each bid submitted at the auction settlement 

price. 

Summary of Section 95911(d)(5)(A).

The provision is needed because when the auction settles at a price higher than 

the reserve price, the auction operator may not have enough allowances to fill all 

the bids submitted at the settlement price. ARB staff proposes a modification of 

the tie bid resolution process used by RGGI to break ties. In the RGGI 

procedure, a random number is assigned to each bid submitted at the settlement 

price, regardless of the quantity bid. Beginning with the lowest random number 

and proceeding to the highest, the auction operator awards allowances until all 

Rationale for Section 95911(d)(5)(A).
IX-77

are awarded. The last bidder winning allowances may get only part of the 

allowances for which it bid. The RGGI process treats each bidder equally, but 

could result in a situation in which one entity could win a disproportionate share 

of the remaining allowances. 

Staff decided to modify the RGGI procedure by assigning a random number to 

each 1,000 metric ton bundle in each participant’s bid. The auction operator 

would use random numbers to award allowances as in the existing RGGI 

procedure. However, in the staff proposal, one random number would be 

assigned to each of the 1,000 metric ton bundles for which an entity bids, instead 

of assigning one random number for the entire quantity bid. For example, in the 

RGGI approach someone bidding for 10,000 metric tons would receive one 

random number. In the staff proposal, the entity would receive ten random 

numbers. 

ARB also considered prorating the allowances among the tied bidders. However, 

this might result in awards of allowances in bundles of less than 1,000 metric 

tons, which would add to the auction’s complexity. 

Subsection (d)(5)(B) states that having assigned a random number to each 

bundle of 1,000 allowances contained in each tied bid, the auction operator will 

begin awarding allowances to the bidder with the lowest number. The auction 

operator will award allowances to the holder of the next lowest random number 

until all allowances are awarded. 

Summary of Section 95911(d)(5)(B).

The provision is needed because this approach will treat each tied bidder equally 

while reducing the chance that a bidder could win a disproportionate share of the 

remaining allowances. 

Rationale for Section 95911(d)(5)(B).

Section 95912. Auction Administration and Registration

Subsection (a) states that the Executive Officer may serve as auction 

administrator or designate an entity to serve as auction administrator.

Summary of Section 95912(a).

This provision is needed to give ARB the flexibility to contract with an outside 

auction operator. 

Rationale for Section 95912(a).

Summary of Section 95912(b).
IX-78

Subsection (b) states that if California links with other jurisdictions’ cap-and-trade 

systems, then California may participate in a joint allowance auction with those 

jurisdictions, provided the joint auction rules conform to the proposed regulation.

The provision is needed because California may link with cap-and-trade systems 

in other U.S. or Canadian jurisdictions in order to form a regional market. A 

regional market would operate more efficiently if the member jurisdictions jointly 

auctioned their allowances. However, California could only participate in a joint 

auction if the rules of that auctioned conformed with rules in this regulation.

Rationale for Section 95912(b).

Subsection (c) states that an entity that intends to participate in an auction must 

complete an auction registration at least 30 days prior to the auction.

Summary of Section 95912(c).

The provision is needed because ARB is requiring a separate auction registration, 

even though all participants are already registered account holders, for several 

reasons. First, it ensures the participants provide updated information. Second, 

the applications will inform the auction operator of the number of participants to 

expect. Third, the application will include agreement by the entity with the rules 

of the auction and any procedures set out by the auction operator.

Rationale for Section 95912(c).

Subsection (c)(1) states that the auction operator will publish a notice describing 

the auction and auction registration process at least 60 days before each auction. 

Summary of Section 95912(c)(1).

The provision is needed because auction participants must have sufficient time to 

prepare the auction application.

Rationale for Section 95912(c)(1).

Subsection (c)(2) explains the information auction participants must submit with 

their auction applications.

Summary of Section 95912(c)(2).

The provision is needed because the auction operator must collect information 

on auction participants in order to correctly evaluate purchase and holding limits, 

assess the financial capability of participants to execute bids, and conduct 

oversight of the auction.

Rationale for Section 95912(c)(2).
IX-79

Subsection (c)(2)(A) states that the auction applicant must supply information 

and documentation on corporate identity, ownership, and capital structure.

Summary of Section 95912(c)(2)(A).

The provision is needed because the auction operator must have correct 

information on the identity of bidders.

Rationale for Section 95912(c)(2)(A).

Subsection (c)(2)(B) states that the auction applicant must supply information 

and documentation on corporate associations, as described in section 95914.

Summary of Section 95912(c)(2)(B).

The provision is needed because the auction operator must have correct 

information on corporate associations in order to correctly apply the holding limit 

to purchases by bidders that are affiliated through a corporate association.

Rationale for Section 95912(c)(2)(B).

Subsection (c)(2)(C) states that the auction applicant must supply information on 

beneficial holdings that may result from auction purchases or may already exist. 

The information must disclose the existence of associations with any other 

auction bidders.

Summary of Section 95912(c)(2)(C).

The provision is needed because the auction operator must have correct 

information in order to understand relationships between auction participants. 

One type of association is between bidders. The auction operator must know of 

these arrangements in order to correctly apply purchase and holding limits. The 

calculation of both of these limits takes into account when one entity is holding or 

purchasing allowances on behalf of another. This is known as a beneficial

holding. Ultimately, ARB must be aware of these relationships to perform 

effective market monitoring.

Rationale for Section 95912(c)(2)(C).

Subsection (c)(2)(D) states that the auction applicant must supply information on 

any criminal history of officials of the bidding entity.

Summary of Section 95912(c)(2)(D).

The provision is needed because the Executive Officer must be able to 

determine whether the applicant should be allowed to participate in the auction.

Rationale for Section 95912(c)(2)(D).
IX-80

Subsection (c)(2)(E) states that the auction applicant must supply information on 

previous or pending investigations of allegations that the bidding entity or its 

officials were involved in violations of rules, regulations, or law associated with 

any commodity market or exchange.

Summary of Section 95912(c)(2)(E).

The provision is needed because the Executive Officer must be able to 

determine whether the applicant should be allowed to participate in the auction.

Rationale for Section 95912(c)(2)(E).

Subsection (c)(2)(F) states that all auction participants must supply their Holding 

Account number. 

Summary of Section 95912(c)(2)(F).

The provision is needed because once the auction operator has the applicant’s 

Holding Account number, it can verify the applicant’s registration status, identify 

the authorized account representative, and access other information on the 

applicant. The applicant must also already have a Holding Account in order to be 

able to purchase any allowances awarded to it at auction. If it does not have a 

Holding Account, or if it has been suspended, the applicant cannot participate in 

the auction.

Rationale for Section 95912(c)(2)(F).

Subsection (d)(1) states that auction participants may not release confidential 

information. Staff is proposing a sealed-bid auction format in part to prevent 

collusion. If the contents of an entity’s bids or other information are circulated 

among participants, those with access to the information could collude to reduce 

the auction settlement price.

Summary of Section 95912(d)(1).

The provision is needed to prevent participants from colluding during the auction.

Rationale for Section 95912(d)(1).

Subsections (d)(1)(A) through (d)(1)(E) state the types of information that auction 

applicants shall not release, including their qualification status, bidding strategy, 

bid prices or quantity, the financial security they provide to the auction 

administrator, or other information contained in the application that the auction 

administrator considers sensitive and will designate as confidential.

Summary of Section 95912(d)(1)(A) through (d)(1)(E).

Rationale for Section 95912(d)(1)(A) through (d)(1)(E).
IX-81

These provisions are needed to clarify to auction participants the information that 

must not be released. The provision is needed to prevent participants from 

colluding during the auction.

Subsection (d)(2) states that if an entity participating in the auction retains the 

services of an advisor, the entity must ensure the advisor does not transfer 

information to other participants.

Summary of Section 95912(d)(2).

The provision is needed because auction participants must ensure that persons 

with access to their confidential bidding strategy do not disclose the information 

to other participants. This requirement is necessary to prevent collusion or 

market manipulation.

Rationale for Section 95912(d)(2).

Subsection (d)(3) states that the Executive Officer will treat the information 

contained in the auction application as confidential to the extent permitted by 

State law.

Summary of Section 95912(d)(3).

The provision is needed because ARB staff will not voluntarily make the 

information contained in the applications public, to avoid aiding collusion or 

market manipulation. However, the Executive Officer must comply with State law 

concerning what information ARB must make public.

Rationale for Section 95912(d)(3).

Subsections (d)(4)(A) and (d)(4)(B) describe the information the Executive Officer 

may release after an auction has concluded. The information includes the 

names of participating bidders and the auction settlement price

Summary of Section 95912(d)(4)(A) and (d)(4)(B).

These provisions are needed because making some information on auction 

results available to the public balances the risk of disclosing information on 

participants’ business strategies with the benefits for market transparency.

Rationale for Section 95912(d)(4)(A) and (d)(4)(B).

Subsection (d)(4)(C) states that the Executive Officer may disclose aggregated 

or distributional information purchases with the names of the entities withheld. 

Aggregated data would refer to data summarized for different classifications of 

entities; for example, covered entities versus voluntarily associated entities. 

Summary of Section 95912(d)(4)(C).
IX-82

Distributional information could include the number of allowances purchased by 

each winner, without identifying the entities themselves.

The provision is needed because releasing the data without identifying the 

winning entities by name would not reveal any confidential business information.

Rationale for Section 95912(d)(4)(C).

Subsection (e) states that the Executive Officer may bar any auction participant 

from participating in future auctions if that participant has provided false or 

misleading information, or violated any other rules governing the auction. This 

prohibition would be in addition to any other enforcement action taken concerning 

the violations themselves.

Summary of Section 95912(e).

The provision is needed because the prohibition is the surest method of 

maintaining the integrity of the auction, and should be an option available in 

addition to other enforcement actions.

Rationale for Section 95912(e).

Subsection (f) states that auction participants must already be registered as 

participants in the California cap-and-trade system.

Summary of Section 95912(f).

This provision is needed for two reasons. First, registration is required before an 

entity is provided with a Holding Account. Without a Holding Account, the entity 

could not purchase allowances at auction. Second, registration provides the 

Executive Officer with information of the entity which is necessary for market 

monitoring.

Rationale for Section 95912(f).

Subsection (g) states that an entity whose Holding Account has been revoked or 

is currently suspended cannot participate in an auction.

Summary of Section 95912(g).

The provision is needed because suspension or revocation of registration and 

accounts is needed as an enforcement mechanism of the cap-and-trade system. 

The action is applicable only to voluntarily associated entities which have no 

surrender compliance obligation. Without an active Holding Account, an entity 

cannot purchase and hold allowances.

Rationale for Section 95912(g).
IX-83

Subsection (h) states that the Executive Officer will specify the form and manner 

for submission of bids, and the bids will be considered binding offers to purchase 

allowances.

Summary of Section 95912(h).

The provision is needed because the Executive Officer needs flexibility in using 

different methods of operating the auction, including the use of online bid 

mechanisms. Submitted bids must be considered binding so that the auction 

operator can process bid payments and access the bid guarantee mechanism, if 

needed.

Rationale for Section 95912(h).

Subsection (i) states that registrants must provide a bid guarantee to the auction 

administrator at least one week before the auction.

Summary of Section 95912(i).

The bid guarantee is needed in case a winning bidder fails to pay in a timely 

manner for allowances it is awarded. It must be submitted at least one week 

before auction to give the auction operator an opportunity to determine if it meets 

requirements.

Rationale for Section 95912(i).

Subsection (i)(1)(A) states that the bid guarantee may be in the form of a bond 

issued by a financial institution with a United States banking license.

Summary of Section 95912(i)(1)(A).

The U.S. banking license is required to ensure that the auction operator will not 

have difficulty accessing the bond.

Rationale for Section 95912(i)(1)(A).

Subsection (i)(1)(B) states that the bid guarantee may be in cash in the form of a 

wire transfer or certified funds, such as a bank check or cashier’s check.

Summary of Section 95912(i)(1)(B).

The provision is needed because these instruments can be evaluated by the 

auction operator and processed quickly in the event of untimely payment by a 

bidder.

Rationale for Section 95912(i)(1)(B).

Summary of Section 95912(i)(1)(C).
IX-84

Subsection (i)(1)(C) states that an irrevocable letter of credit issued with a United 

States banking license.

The provision is needed because the auction operator would obtain payment 

from a financial institution with which the bidder has established credit.

Rationale for Section 95912(i)(1)(C).

Subsection (i)(1)(D) states that the auction operator will accept qualifying 

financial instruments from financial institutions with a Canadian banking license if 

California links to programs in one or more Canadian provinces.

Summary of Section 95912(i)(1)(D).

The provision is needed because if California links its system with GHG ETS in 

one or more Canadian provinces, it is possible that some California allowances 

will be purchased at auction by entities located in Canada. These entities may 

need to use Canadian financial institutions, so the auction operator needs to 

accept instruments from institutions with Canadian banking licenses.

Rationale for Section 95912(i)(1)(D).

Subsection (i)(2) states that the value of the bid guarantee must be greater than 

or equal to the sum of the value of the bids submitted by the auction participant.

Summary of Section 95912(i)(2).

The provision is needed because bid guarantees are common features of 

auctions to deter manipulative bidding. Without such a mechanism, bidders 

could submit multiple bids, then default on paying if the auction settlement price 

was higher than they desired. This practice would jeopardize the integrity of the 

auction. 

Rationale for Section 95912(i)(2).

Subsections (j)(1) through (j)(6) describe the information the Executive Officer 

must make public at least 60 days before an auction. The notice shall include 

the date and time of the auction; instructions for applying for auction participation; 

instruction on how to submit bids; the procedures the auction operator will follow 

to conduct the auction; the administrative requirements for participation; and the 

number of GHG allowances to be auctioned.

Summary of Section 95912(j)(1) through (j)(6).

Rationale for Section 95912(j) through (j)(6).
IX-85

These provisions are needed because public notice is necessary so that potential 

participants can complete the registration process, develop a bidding strategy, 

and arrange financing in time for the auction.

Subsection (k)(1) states that the auction operator will process the bid guarantees.

Summary of Section 95912(k)(1).

The provision is needed because the auction operator will need to determine the 

value of bids for which a participant has submitted a valid guarantee.

Rationale for Section 95912(k)(1).

Subsection (k)(2) states that the auction operator will determine that the bids 

submitted by a participant conform to the holding and purchase limits and value 

of the bid guarantee submitted.

Summary of Section 95912(k)(2).

The provision is needed because the auction operator will disqualify individual 

bids that exceed any of the limits. 

Rationale for Section 95912(k)(2).

Subsection (k)(3) states that the auction operator will determine the winning bids 

and auction settlement price.

Summary of Section 95912(k)(3).

The provision is needed because the auction operator has responsibility for these 

functions.

Rationale for Section 95912(k)(3).

Subsection (k)(4) states that the auction operator will inform the Executive Officer 

of the results.

Summary of Section 95912(k)(4).

The provision is needed because the Executive Officer is responsible for 

ensuring the integrity of the auction. The results must be reported to the 

Executive Officer for approval before actual awarding of and payment for 

allowances occurs.

Rationale for Section 95912(k)(4).

Summary of Section 95912(l).
IX-86

Subsection (l) describes the actions the Executive Officer must take after an 

auction concludes.

The provision is needed because the auction operator only conducts the auction 

and determines winners. All transactions involving distribution of allowances 

require action by the Executive Officer. No payments can be processed until this 

occurs.

Rationale for Section 95912(l).

Subsection (l)(1) states that after the auction, the Executive Officer will certify 

that the auction was conducted pursuant to the regulation.

Summary of Section 95912(l)(1).

This provision is needed to ensure no allowances are awarded or payments 

processed until the Executive Officer is certain that the auction rules have been 

followed.

Rationale for Section 95912(l)(1).

Subsection (l)(2)(A) states that after certifying the auction was conducted 

properly, the Executive Officer will instruct the auction operator to collect 

payment from winning bidders.

Summary of Section 95912(l)(2)(A).

The provision is needed because the auction operator must collect payments 

before the Executive Officer will transfer allowances to the winners’ Holding 

Accounts.

Rationale for Section 95912(l)(2)(A).

Subsection (l)(2)(B) states that after certifying the auction was conducted 

properly, the Executive Officer will instruct the auction operator to declare the bid 

guarantee mechanism forfeit by any entity that fails to make full payment for 

awarded allowances when payment is due. The auction operator will access the 

bid guarantee to make up any shortfall in payment.

Summary of Section 95912(l)(2)(B).

The provision is needed because the auction operator must collect payments 

before the Executive Officer will transfer allowances to the winners’ Holding 

Accounts.

Rationale for Section 95912(l)(2)(B).
IX-87

Subsection (l)(2)(C) states that after certifying the auction was conducted 

properly, the Executive Officer will instruct the auction operator to deposit the 

proceeds for allowances allocated by ARB into the Air Pollution Control Fund.

Summary of Section 95912(l)(2)(C).

The provision is needed because proceeds for allowances allocated for auction 

by ARB must go to a State account where they are available for appropriation by 

the Legislature. 

Rationale for Section 95912(l)(2)(C).

Subsection (l)(2)(D) states that after certifying the auction was conducted 

properly, the Executive Officer will instruct the auction operator to distribute 

auction proceeds to entities that consigned allowances to the auction under the 

provisions of section 95910.

Summary of Section 95912(l)(2)(D).

The provision is needed to provide authority for the Executive Officer to ensure 

that those entities that consigned allowances are paid for them.

Rationale for Section 95912(l)(2)(D).

Subsection (l)(3) states that after determining that allowances have been paid for, 

the Executive Officer will instruct the accounts administrator to transfer the serial 

numbers of allowances to the Holding Accounts of the winning bidders.

Summary of Section 95912(l)(3).

The provision is needed because allowances belong to purchasers after payment 

has been received. Until payment has been received, the allowances either 

belong to ARB or have been consigned to the Executive Officer for auction. 

Therefore, the Executive Officer must determine when payment has been 

completed and instruct the accounts administrator to transfer the allowances.

Rationale for Section 95912(l)(3).

Subsection (l)(4) states that after certifying the auction was conducted properly, 

the Executive Officer will inform any GHG ETS to which California is linked of the 

allowances distributed.

Summary of Section 95912(l)(4).
IX-88

The provision is needed because California must inform linked systems of the 

allowances that it has distributed, so that the other systems can recognize them 

as valid.

Rationale for Section 95912(l)(4).

Subsection (l)(5) states that the Executive Officer will publish the results 

at 

Summary of Section 95912(l)(5).

www.arb.ca.gov.

This provision is necessary to ensure transparency of the auction proceedings.

Rationale for Section 95912(l)(5).

Section 95913. Sale of Allowances from the Allowance Price Containment 

Reserve Account.

Subsection (a) states that the Executive Officer may administer sales from the 

Allowance Price Containment Reserve Account (also referred to as the Reserve) 

or designate an entity to serve as auction administrator.

Summary of Section 95913(a).

This provision gives the Executive Officer the flexibility to contract with an outside 

entity to administer transactions.

Rationale for Section 95913(a).

Subsection (b) states that if California links with other GHG ETS, the linkage 

agreement will specify whether entities registered into the linked systems will be 

eligible to purchase from the Reserve.

Summary of Section 95913(b).

This provision is needed because staff cannot make a determination on eligibility 

before linking agreements have been created. Under the current staff proposal, 

entities must be registered into the California cap-and-trade system under 

section 95830 before they can participate in the Reserve sales.

Rationale for Section 95913(b).

Subsection (c)(1)(A) states that only covered entities, including opt-in covered 

entities, are eligible to participate in sales from the Reserve.

Summary of Section 95913(c)(1)(A).
IX-89

This provision is needed because staff is proposing a Reserve to mitigate price 

increases during periods of short supplies, especially when these occur near to 

compliance deadlines. Since voluntarily associated entities do not have a 

compliance obligation, they can simply avoid purchasing allowances when prices 

are high.

Rationale for Section 95913(c)(1)(A).

Subsection (c)(1)(B) states that covered entities may only purchase from the 

Reserve if they do not hold any compliance instruments in their Holding Accounts.

Summary of Section 95913(c)(1)(B).

This provision is needed because staff is proposing the Reserve to help ensure 

that compliance may be achieved at a reasonable cost. Staff intends the benefit 

to go to entities that have had difficulty finding compliance instruments at a 

reasonable cost, not those that can meet their compliance needs and still 

maintain a balance in their Holding Accounts for speculative purposes. 

Rationale for Section 95913(c)(1)(B).

Subsection (c)(2) states that all of the allowances in the Reserve will be available 

for purchase at each sale.

Summary of Section 95913(c)(2).

This provision is needed because staff concluded that if shortages occur close to 

a compliance deadline, then the Reserve needs to be available in its entirety.

Rationale for Section 95913(c)(2).

Subsections (c)(3)(A) and (c)(3)(B) state that the first Reserve sale will be 

conducted on March 4, 2012. After the first Reserve Sale, further Reserve sales 

will take place three weeks after each quarterly allowance auction.

Summary of Section 95913(c)(3)(A) and (c)(3)(B).

Staff propose this date to allow entities to complete the registration process and 

for the first auction to conclude. Staff proposes this schedule so that entities may 

use the Reserve sales to supplement their auction purchases.

Rationale for Section 95913(c)(3)(A) and (c)(3)(B).

Subsection (c)(3)(C) states that the sale administrator will publish a notice for 

each sale four weeks prior to the sale.

Summary of Section 95913(c)(3)(C).
IX-90

This provision is needed because covered entities will need time to prepare their 

purchase strategies following each auction, to submit their bids, and to arrange 

financing.

Rationale for Section 95913(c)(3)(C).

Subsection (c)(4) states that purchases of allowances from the Reserve will be 

subject to the holding limit.

Summary of Section 95913(c)(4).

This provision is necessary because the Reserve is intended to aid entities that 

need allowances for compliance rather than speculative purposes. Covered 

entities have a limited exemption for allowances held in their Compliance 

Accounts. The exemption is intended to allow them to meet compliance 

obligations. If they exceed that limit they should have no need to access the 

Reserve.

Rationale for Section 95913(c)(4).

Subsection (d)(1) states that the allowances in the Reserve will be evenly divided 

into three pools, referred to as tiers.

Summary of Section 95913(d)(1).

This provision is needed because staff proposes the division to allow the 

allowances to be available at different prices.

Rationale for Section 95913(d)(1).

Subsections (d)(2)(A) through (d)(2)(C) list the prices for each tier to be used in 

2012. The price for allowances will be $40/metric ton for the first tier, $45/metric 

ton for the second tier, and $50/metric ton for the third tier.

Summary of Section 95913(d)(2)(A) through (d)(2)(C).

These provisions are needed because ARB will specify prices for 2012, then use 

an inflator to raise prices in later years. 

Rationale for Section 95913(d)(2)(A) through (d)(2)(C).

ARB proposes the use of fixed prices for sales from the Reserve so that program 

administrators do not need to make a determination that market conditions 

require an intervention. This certainty of the Reserve being available at 

established prices is an important aspect of the design.

ARB proposes setting the prices for the three tiers at $40, $45, and $50 because 

if allowance prices remain within the anticipated range (as described in 
IX-91

Appendix N: Supporting Documentation for the Economic Analysis), no 

allowances will be purchased from the Reserve because the established sales 

prices would be higher than the estimated market price of allowances. 

Consequently, when no allowances are purchased from the Reserve, the total 

number of instruments that can be used for compliance (allowances plus the 

offset limit) is unchanged by the creation of the allowance reserve. Under these 

conditions, the environmental integrity of the program is maintained, and the 

emissions reductions required by covered sources remains unchanged. 

Appendix N examines scenarios that could result in allowance prices that are 

substantially above the price estimated under the main policy case for 2020. An 

allowance reserve could potentially prevent the higher allowance prices in these 

circumstances if it is large enough to accommodate the estimated shortfalls in 

emissions reductions from the complementary measures. ARB estimated that 

the allowance reserve needed to accommodate potential shortfalls in direct 

reductions would be in the order of 2 percent to 5 percent of the total allowance 

budget.

This protection against high prices is limited, however, because the number of 

allowances in the Reserve is limited. Once the allowances in the Reserve are all 

purchased, there is no additional buffer against higher-than-expected prices. 

The limited nature of the proposed reserve distinguishes it from a hard allowance 

price cap. Under a hard price cap, a maximum allowance price is established, 

and additional allowances are made available at the cap price, typically in 

unlimited quantity. Under such conditions, the environmental integrity of the 

program is not maintained if additional allowances are sold at the price cap. The 

allowance reserve discussed here does not share these features with a hard 

price cap.

Subsection (d)(3) proposes that after 2012, the tier prices for a given calendar 

year will equal the prices for the previous calendar year, plus five percent and a 

measure of inflation, the Consumer Price Index for All Urban Consumers.

Summary of Section 95913(d)(3).

Staff proposes an inflator mechanism based on the expectation that marginal 

abatement costs and allowance prices will increase over time as lower cost 

abatement measures are undertaken first. Reserve sale prices would need to 

increase to reflect the increased marginal abatement cost and the inflation rate, 

otherwise the Reserve would no longer be the seller of last resort as intended.

Rationale for Section 95913(d)(3).
IX-92

Subsection (e) describes how covered entities must submit their bids to purchase 

allowances from the Reserve. The bids are due to the sales administrator two 

weeks before each sale is conducted.

Summary of Section 95913(e).

The provision is necessary so that the sales administrator has time to process 

the bids. Staff is proposing minimal requirements on the bids themselves. The 

requirements are necessary to ensure that the sales proceed efficiently.

Rationale for Section 95913(e).

Subsection (e)(1) states that the bids will include the number of allowances the 

covered entity wishes to purchase from each of the three tiers, in multiples of 

1,000 metric tons.

Summary of Section 95913(e)(1).

The provision is necessary to simplify the bidding and award process. The bid 

must specify the number of allowances from each tier. The total number of 

allowances, combined with the entity’s existing holdings, must be less than the 

holding limit.

Rationale for Section 95913(e)(1).

Subsection (e)(2) states that bidders must provide a bid guarantee equal to the 

value of the bids they submit.

Summary of Section 95913(e)(2).

The provision is necessary because without this requirement, bidders could 

default on their bids. This might force the sales administrator to rerun the sale. 

Rationale for Section 95913(e)(2).

Subsection (e)(2)(A) states that the bid guarantee may be in the form of a bond 

issued by a financial institution with a U.S. banking license.

Summary of Section 95913(e)(2)(A).

The provision is necessary because the sales administrator could easily recover 

payment for the allowances from a bond.

Rationale for Section 95913(e)(2)(A).
IX-93

Subsection (e)(2)(B) states that the bid guarantee may be in the form of cash, in 

the form of a wire transfer, or certified funds, such as a bank check or cashier’s 

check.

Summary of Section 95913(e)(2)(B).

The provision is necessary because the sales administrator could easily recover 

payment for the allowances from these instruments.

Rationale for Section 95913(e)(2)(B).

Subsection (e)(2)(C) states that the bid guarantee may be in the form of an 

irrevocable letter of credit issued by a financial institution with a U.S. banking 

license.

Summary of Section 95913(e)(2)(C).

The provision is necessary because the sales administrator could easily recover 

payment for the allowances from letters of credit. The requirement for a U.S. 

banking license is included to simplify transactions.

Rationale for Section 95913(e)(2)(C).

Subsection (e)(2)(D) states that if California links with GHG ETS operated by one 

or more Canadian Provinces, then bonds or irrevocable letters of credit from 

financial institutions with Canadian banking licenses would be acceptable.

Summary of Section 95913(e)(2)(D).

The provision is necessary if California links with GHG ETS operated by 

Canadian Provinces, because the linking agreements may allow Canadian 

entities to purchase from the Reserve. In this case, the entities may well be 

transacting through Canadian banks.

Rationale for Section 95913(e)(2)(D).

Subsection (f)(1) states that the sales administrator will conduct sales from each 

tier starting with the lowest-priced tier and proceeding to the highest.

Summary of Section 95913(f)(1).

The provision is necessary because the sales administrator will be evaluating 

each purchase against the holding limit. By conducting sales from each tier from 

lowest to highest price, the administrator will disqualify the higher-priced bids.

Rationale for Section 95913(f)(1).
IX-94

Subsection (f)(2)(A) states that the sales administrator will disqualify bids once 

purchases exceed the bidding entity’s holding limit.

Summary of Section 95913(f)(2)(A).

The provision is necessary because no entity’s holdings may exceed the holding 

limit.

Rationale for Section 95913(f)(2)(A).

Subsection (f)(2)(B) states that the sales administrator will disqualify bids once 

the value of purchases exceeds the value of the bidding entity’s bid guarantee.

Summary of Section 95913(f)(2)(B).

The provision is necessary because if the sales administrator accepts the bids 

beyond the value of the bid guarantee, there is risk that an entity may not pay for 

the allowances. This would affect the integrity of the auction.

Rationale for Section 95913(f)(2)(B).

Subsection (f)(3) states that if the total number of bids for a tier is less than the 

total available, bidders will receive all the allowances for which they bid.

Summary of Section 95913(f)(3).

The provision is necessary because the sales administrator will fill all the 

qualified bids from a tier if the tier is not depleted.

Rationale for Section 95913(f)(3).

Subsection (f)(4) describes the process the sales administrator will use if the 

number of qualified bids for a tier exceeds the number of allowances in the tier.

Summary of Section 95913(f)(4).

The provision is necessary because there must be a procedure in place if a tier 

becomes depleted.

Rationale for Section 95913(f)(4).

Subsection (f)(4)(A) states that if there are more bids for a tier than there are 

allowances remaining, the share of allowances to be awarded to each bidder will 

equal the number of allowances for which one entity bids, divided by the total 

number of bids.

Summary of Section 95913(f)(4)(A).
IX-95

The provision is necessary because if a tier becomes depleted during a sale, the 

administrator will prorate the purchases among qualified bids. Once a tier is 

depleted, it will not be replenished. ARB is filling the Reserve with allowances 

issued at the beginning of the program and does not intend to replenish the 

Reserve with allowances issued through 2020. However, ARB does intend to 

transfer allowances remaining unsold at auction to the Reserve.

Rationale for Section 95913(f)(4)(A).

Subsection (f)(4)(B) states that the number of allowances awarded to each 

bidder will equal the bidder’s share, as calculated in 95913(f)(4)(A), times the 

number of allowances in the tier, rounded to the lowest whole number.

Summary of Section 95913(f)(4)(B).

The provision is necessary because it allows the administrator to empty the tier 

while treating each bidder equally.

Rationale for Section 95913(f)(4)(B).

Subsection (F)(5) states that the sales administrator will inform the Executive 

Officer of the sales results.

Summary of Section 95913(f)(5).

The provision is necessary because the Executive Officer will have to certify that 

the sale was conducted properly under the regulation.

Rationale for Section 95913(f)(5).

Subsections (g)(1) through (g)(2) detail the post-sale actions by the Executive 

Officer. The Executive Officer must certify that the sale was conducted 

according to the regulation. After approving the sale, the Executive Officer will 

authorize the reserve sale administrator to process payments for the allowances 

purchased.

Summary of Section 95913(g)(1) through (g)(2).

These provisions are necessary because some actions must be taken by the 

Executive Officer after the sale. The Executive Officer must determine that the 

sale administrator conducted the sale appropriately before allowances can be 

distributed. The reserve sale administrator cannot process payments until the 

Executive Officer approves the conduct of the sale.

Rationale for Section 95913(g) (1) through (g)(2).
IX-96

Subsection (g)(3) states that after determining that the payments have been 

placed into the Air Pollution Control Fund, the Executive Officer will authorize the 

accounts administrator to transfer the allowances purchased from the Reserve 

account to the winning bidders’ Compliance Accounts.

Summary of Section 95913(g)(3).

The provision is necessary because the Executive Officer will authorize 

allowance transfers once payment has been processed. The allowances are 

placed in the winning bidders’ Compliance Account because the Reserve is 

intended for use by those entities finding it difficult to acquire allowances during 

times of tight supply. ARB does not intend the allowances to be available for 

further speculation.

Rationale for Section 95913(g)(3).

Subsection (g)(4) states that the Executive Officer will inform the GHG ETS to 

which California has linked of the serial numbers of the allowances sold.

Summary of Section 95913(g)(4).

The provision is necessary because when California links to other GHG ETS, the 

systems must inform each other when compliance instruments have been placed 

into circulation, so that the instruments may be recognized as valid in each 

system.

Rationale for Section 95913(g)(4).

Subsection (g)(5) states that the Executive Officer will publish all sales results 

online.

Summary of Section 95913(g)(5).

The provision is necessary because staff proposes to have all results be a matter 

of public record. The cost-containment mechanism was designed in part to 

provide information on the compliance costs of the program. In addition, staff 

believes the public should know who is benefitting from this distribution of 

allowances.

Rationale for Section 95913(g)(5).

Section 95914. Disclosure of Direct and Indirect Corporate Associations.

Subsection (a) requires that entities disclose direct and indirect corporate 

associations when they register. This subsection contains the definitions of the 

associations.

Summary of Section 95914(a).
IX-97

This provision is necessary because registered entities may have corporate 

associations that allow them to coordinate their market activities. Staff is 

proposing disclosure of these relationships so that market monitors will be able to 

identify transactions involving affiliates. In addition, if ARB were to be unaware of 

these relationships it would be unable to apply holding and purchase limits in a 

meaningful way. Corporate affiliates would be able to control a much larger 

share of the market for compliance instruments.

Rationale for Section 95914(a).

Subsections (a)(1)(A) through (a)(1)(E) contain the criteria for determining 

whether two entities have a direct corporate association. These include the 

share of share ownership, appointment of directors, voting power, or other 

means of control of another entity. In addition, subsection (a)(1)(E) states that a 

corporate association would exist if one entity holds compliance instruments in 

which the other has an ownership interest.

Summary of Section 95914(a)(1)(A) through (a)(1)(E).

These provisions are needed to give clear guidance about how to determine 

which corporate associations must be disclosed.

Rationale for Section 95914(a)(1)(A) through (a)(1)(E).

Subsection (a)(2) contains the criteria for determining whether two entities have 

an indirect corporate association. This type of association occurs when an entity 

has an association with an entity through a third entity, or a chain of entities.

Summary of Section 95914(a)(2).

This provision is needed to give clear guidance about how to determine which 

corporate associations must be disclosed.

Rationale for Section 95914(a)(2).

Subsection (b) requires that if California links to other GHG ETS, then registered 

entities must disclose corporate associations with entities in those systems.

Summary of Section 95914(b).

This provision is needed to give clear guidance about how to determine which 

corporate associations must be disclosed.

Rationale for Section 95914(b).
IX-98

Subsections (c)(1) and (c)(3) contain the list of information which entities must 

provide when disclosing corporate associations. This includes names of the 

other entities, the type of corporate association, and a brief description of the 

association, such as subsidiary, partnership, corporate parent, sister company, or 

other. 

Summary of Section 95914(c)(1) through (c)(3).

Subsection (c)(2) gives the entity the opportunity to report the share of the 

corporate association’s purchase and holding limits allocated to each entity in the 

association.

These provisions are necessary to provide basic identification of the members of 

a corporate association. In addition, subsection (c)(2) is needed to enable the 

auction administrator to apply purchase and holding limits to members of a 

corporate association. The limits treat the holdings and purchases of members 

of an association as if they were held by one entity. Staff is proposing that 

members of an association be able to allocate the limit among the members so 

that each entity will always know how the limitations apply to it. When the 

allocation is disclosed, the auction operator and the Executive Officer will ensure 

that the sum of the allocated shares is less than the holding and purchase limits.

Rationale for Section 95914(c)(1) through (c)(3).

Subsections (d)(1) through (d)(4) contain the list of times when corporate 

associations must be disclosed or the disclosure updated. Subsection (d)(1) 

requires that disclosure be made when an entity initially registers under section 

95830. Subsection (d)(2) requires that disclosure be made any time an 

association is created or exists. Subsection (d)(3) requires disclosure whenever 

there is a material change in the information already disclosed. Subsection (d)(4) 

requires disclosure at least 60 days before an auction.

Summary of Section 95914(d)(1) through (d)(4).

These provisions are necessary so that entities understand their responsibilities 

of when they must report or update the information retained by ARB.

Rationale for Section 95914(d)(1) through (d)(4).

Subsection (e)(1) makes the total number of allowances purchased at auction by 

a group of entities with a corporate association subject to the purchase limit as if 

they were one entity. 

Summary of Section 95914(e)(1).

Rationale for Section 95914(e)(1).
IX-99

This provision is needed to correctly apply the purchase limit. ARB intends the 

limit to restrict the ability of an entity or group of entities from gaining a dominant 

share of the market for instruments.

Subsection (e)(2) allows members of a corporate association to allocate shares 

of the limit among themselves. The sum of shares allocated to the members of 

the corporate association must sum to the purchase limit. After they inform the 

Executive Officer of the allocation, the auction administrator will treat the entity’s 

allocated share as its purchase limit.

Summary of Section 95914(e)(2)(A) through (e)(2)(C).

Subsections (e)(2)(A) through (e)(2)(C) are necessary so that members of a 

corporate association can clarify their share of their association’s purchase limit 

between themselves. By informing the Executive Officer, they can ensure that 

the limit will be applied correctly.

Rationale for Section 95914(e)(2)(A) through (e)(2)(C).

These provisions describe how the purchase limit will be applied to members of a 

corporate association if they do not inform the Executive Officer of an allocation 

of the shares of the purchase limit among themselves. To evaluate the purchase 

limit, the auction administrator will pool the bids from all members of the 

association, and order them from highest to lowest bid price. The administrator 

will then accept the bids in declining price order until the association’s purchase 

limit is reached. The administrator will then disqualify any remaining bids. The 

auction administrator will conduct this process before the auction itself.

Summary of Section 95914(e)(3)(A) through (e)(3)(C).

These provisions are necessary to instruct the administrator how to apply the 

purchase limit to members of a corporate association when they have not 

allocated the purchase limit among themselves. 

Rationale for Section 95914(e)(3)(A) through (e)(3)(C).

Subsection (f)(1) makes the total number of compliance instruments held by 

members of a corporate association subject to the holding limit as if the 

association were one entity.

Summary of Section 95914(f)(1).

This provision is necessary to correctly apply the holding limit. ARB intends the 

limit to restrict the ability of an entity or group of entities from gaining a dominant 

share of the market for instruments. Without this requirement, a corporate 

Rationale for Section 95914(f)(1).
IX-100

association could expand its share of the market by creating and registering 

more affiliates.

Subsections (f)(2)(A) and (f)(2)(B) describe how entities that are part of a 

corporate association may allocate the holding limit among themselves. The 

sum of shares allocated to each member must sum to the holding limit. The 

association must inform the Executive Officer of the allocation before the limit 

can be correctly applied.

Summary of Section 95914(f)(2)(A) and (f)(2)(B).

These provisions are necessary because ARB is proposing that the holding limit 

applies to members of a corporate association as if they were one entity. 

Rationale for Section 95914(f)(2)(A) and (f)(2)(B).

Subsection (f)(3) requires that if the members of a corporate association do not 

inform the Executive Officer of a an allocation of the holding limit among 

themselves, then the accounts administrator will not record a transaction that 

would result in the holdings of the members of a corporate association exceeding 

the holding limit.

Summary of Section 95914(f)(3).

Subsection (f)(3) is necessary in the event that members of a corporate 

association do not report an allocation of the holding limit to the Executive Officer. 

This subsection gives the default treatment of the limit, unless the members of 

the association take advantage of the allocation option.

Rationale for Section 95914(f)(3).

Section 95915. Identifying Disclosable Bidding Associations.

Subsection (a) requires entities registering for the auction to disclose the 

existence of bidding associations with any entities registered into the California 

cap-and-trade system or into a GHG ETS with which California has linked.

Summary of Section 95915(a).

The provision is needed to require entities participating in California’s auction to 

disclose if they are participating in the auction with another registered entity. 

Staff is proposing the requirement so that ARB can monitor auctions for collusive 

behavior.

Rationale for Section 95915(a).
IX-101

Subsections (b)(1) through (b)(3) provide a list of criteria for determining whether 

a bidding association exists. These include whether the entity has an agreement 

with another entity; is partnered with another entity for bidding purposes; or has 

agreed to provide advisory services except for investment advice.

Summary of Section 95915(b)(1) through (b)(3).

These provisions are necessary to inform auction participants of the criteria 

governing disclosure of bidding associations.

Rationale for Section 95915(b)(1) through (b)(3).

Subsection (c)(1) requires that bidding associations be disclosed during the 

auction registration process. Subsection (c)(2) lists the disclosure requirements 

for bidding associations. These include a description of the agreement, 

relationships between members of the association, including which entity may be 

holding instruments on behalf of another, and a copy or description of any 

agreement.

Summary of Section 95915(c)(1) and (c)(2).

Subsection (c)(1) is necessary to ensure the Executive Officer has the 

information prior to the auction. Subsection (c)(2) is necessary to make clear to 

the auction participants what type of information must be disclosed. The 

disclosed information will help the Executive Officer monitor the bidding behavior 

of participants.

Rationale for Section 95915(c)(1) and (c)(2).

Subsections (d)(1) through (d)(3) contain the requirements for when disclosures 

must be made and when an entity can communicate information on its auction 

participation. Subsection (d)(1) requires disclosure at least 30 days prior to the 

auction. Subsection (d)(2) prohibits communication by an entity with another 

auction participant if there has been no disclosure of a bidding association 

between the two. Subsection (d)(3) prohibits an entity from participation in the 

auction if it has a material change to its bidding association disclosure less than 

30 days from the auction.

Summary of Section 95915(d)(1) through (d)(3).

These provisions are necessary to ensure that there is no undisclosed 

communication between bidders at an auction. Subsection (d)(1) is needed to 

ensure all associations have been disclosed a sufficient interval prior to the 

auction, so that the auction can be properly monitored. Subsection (d)(2) is 

needed to prohibit communication between bidders. Subsection (d)(3) prohibits 

Rationale for Section 95915(d)(1) through (d)(3).
IX-102

the creation of new bidding associations after the auction disclosure deadlines

have passed.

These provisions will ensure that the auction can be monitored for potential 

collusion between bidders.

Subsection (e)(1) applies the purchase limit at an auction to the members of a 

bidding association which are designated as “the recipient” of a beneficial 

purchase by another entity.

Summary of Section 95915(e)(1).

The provision is needed to address when an entity has other registered entities 

make purchases on its behalf. An entity could easily escape the purchase limit 

by such arrangements. However, part of the required disclosure is to have a 

purchasing entity identify the ultimate recipient of the purchased instrument. The 

purchase limit will then correctly be applied to the recipient, not to the apparent 

purchaser.

Rationale for Section 95915(e)(1).

Subsections (e)(2)(A) and (e)(2)(B) permit the entities within a bidding 

association to allocate the purchase limit among those entities in the association 

and inform the Executive Officer of the allocation. The sum of the shares 

allocated must be less than or equal to the purchase limit. The share allocated to 

an individual entity becomes its purchase limit.

Summary of Section 95915(e)(2)(A) and (e)(2)(B).

These provisions are needed so that entities that are part of a bidding 

association may enter an auction knowing exactly the number of allowances 

each will be allowed to purchase on its own behalf. The Executive Officer must 

be aware of the allocation before the auction to evaluate whether it was correctly 

calculated.

Rationale for Section 95915(e)(2)(A) and (e)(2)(B).

Subsection (e)(3) requires the auction operator to calculate shares of the 

purchase limit if entities in a bidding association fail to declare an allocation to the 

Executive Officer. The limit for entities designated as “purchaser” is the 

purchase limit less the sum of bids submitted by entities in the association 

designated as “recipient,” divided by the number of entities designated as 

“purchaser.” Thus, all “purchasers” would end up with an equal share of the limit 

as a default.

Summary of Section 95915(e)(3).
IX-103

The provision is necessary in case entities in a bidding association do not 

allocate the purchase limit among themselves.

Rationale for Section 95915(e)(3).

Subarticle 11. Trading and Banking.

Section 95920. Trading.

Subsection (a) contains a list of actions that are explicitly prohibited in the 

California cap-and-trade system.

Summary of Section 95920(a).

The list of prohibited actions is needed to enable ARB to take enforcement 

actions against entities that attempt to manipulate the market. The list of 

prohibited activities attempt to capture actions that are part of manipulative 

activities.

Rationale for Section 95920(a).

Subsection (a)(1) requires that transaction reports include the names of 

authorized account representatives of those involved in a trade.

Summary of Section 95920(a)(1).

The provision is needed because ARB needs to know who has an ownership 

interest in the instruments being traded, in order to detect the exercise of market 

power. 

Rationale for Section 95920(a)(1).

Subsections 95920(a)(2)(A) through (a)(2)(F) prohibit trades involving a number 

of techniques used to manipulate markets, including manipulative or deceptive 

devices; attempts to corner a market; fraud; false, misleading, or inaccurate 

reporting or documentation; or other efforts to falsify or conceal material facts.

Summary of Sections 95920(a)(2)(A) through (a)(2)(F).

The prohibitions are needed to because ARB must be able to take enforcement 

against an entity attempting to manipulate markets or deceive other market 

participants. 

Rationale for Section 95920(a)(2)(A) through (a)(2)(F).

Section (b)(1) defines the holding limit as the maximum number of California 

compliance instruments that can be held by an entity or a group of entities with a 

Summary of Section 95920(b)(1) and (b)(2).
IX-104

corporate association. Section (b)(2) applies the limit to any entity with a Holding 

Account.

Sections (b)(1) and (b)(2) are needed to define the holding limit that will apply to 

each entity with a Holding Account. The limit applies to entities that have a 

corporate association with each other, as defined in section 95914.

Rationale for Section 95920(b)(1) and (b)(2).

The purpose of a holding limit is to prevent a market participant, or a group of 

market participants that can coordinate their buying and selling, from gaining too 

large a share of the goods in a market. The limits are common features in 

commodity markets.

Section (b)(3) contains the formula for calculating the holding limit. The formula 

calculates the holding limit in millions of metric tons:

Summary of Section 95920(b)(3).

Holding Limit = 2.5 million metric tons + 0.025*(Annual Allowance Budget – 2.5 

million metric tons).

The holding limit is calculated for each year using that year’s Annual Allowance 

Budget. ARB selected this formula based primarily on recommendations by a 

consultant to the WCI Markets Committee.101 

The provision is needed because account holders must know at all times the 

holding limit that applies each year. The formula adjusts the holding limit for 

changes in the allowance budget. This will allow the holding limit to increase 

when the scope of the system is enlarged in the second period, and to decrease 

when the cap decreases over time. 

Rationale for Section 95920(b)(3).

The size of the limit, coupled with the limited exemption, represents a trade-off 

between having a limit that is small enough to reduce opportunities for market 

manipulation and a limit that is so small that it reduces banking and market 

liquidity by restricting the activity of non-covered entities. As the WCI consultant 

 

101 Harris, Jeffrey H. Western Climate Initiative Markets Committee Report on Holdings Limits. 

May 6, 2010.
IX-105

concluded, economic theory provides little practical guidance to setting the tradeoff for a market that does not yet exist.102

Subsection (b)(4)(A) provides a limited exemption from the holding limit for 

allowances placed in a compliance account by covered entities within a single 

calendar year. The limit to the transfer of allowances added to an entity’s 

compliance account is equal to the verified emissions reported for the entity for 

the previous year. The verification statement must be a positive or qualified 

positive statement.

Summary of Section 95920(b)(4)(A)

This provision is needed to have a holding limit that treats all covered and 

voluntarily associated entities equally. The exemption applies only to allowances 

transferred to a compliance account in a single year.

Rationale for Section 95920(b)(4)(A)

Staff concluded that the verified emissions would be the best available estimate 

of an entity’s current emissions. Using the verified emissions to set the 

exemption means that the exemption would not be large enough to exempt 

allowances an entity accumulates to cover growth in emissions.

Subsection (b)(4)(B) states that the total number of allowances which can be 

held in a compliance account during a calendar year is the sum of previous 

annual transfer limits.

Summary of Section 95920(b)(4)(B)

Rationale for Section 95920(b)(4)(B)

This provision is needed in order for the limited exemption to be cumulative. The 

approach allows the exemption to be high enough to accommodate holdings 

needed prior to the triennial compliance.

Subsection (b)(4)(C) states that on December 31 of the calendar year following 

the end of a compliance period the limited exemption will be reduced by the sum 

of the entity’s verified emissions over that compliance period.

Summary of Section 95920(b)(4)(C)

 

102 Harris, Jeffrey H. Western Climate Initiative Markets Committee Report on Holdings Limits.

May 6, 2010, p. ii.

Rationale for Section 95920(b)(4)(C)
IX-106

This provision is needed in order for the limited exemption to reflect changes in 

the number of allowances a covered entity would need to hold over the triennial 

compliance cycle. The limit is reduced by the entity’s total emissions over a 

compliance period after that entity has met the triennial compliance deadline. 

The limit will still be high enough to allow the entity to begin accumulating 

allowances for the next compliance period. At the same time, the exemption 

does not continue to grow in an unlimited fashion so that the covered entity is 

effectively no longer bound by the holding limit.

Subsection (b)(4)(B) states that if a positive or qualified positive verification 

statement is not available then ARB will calculate the exemption based on 

emissions assigned to the entity.

Summary of Section 95920(b)(4)(D)

This provision is needed to allow ARB to calculate the holding limit exemption for 

covered entities when they do not have a positive or qualified positive verification 

statement for their emissions from the previous year.

Rationale for Section 95920(b)(4)(D)

Subsection 95920(b)(5) states that if the Executive Officer determines that a 

transaction by an entity would result in the number of compliance instruments 

held by that entity being greater than the holding limit, the Executive Officer will 

not approve the transaction.

Summary of Section 95920(b)(5).

This provision is needed to enforce the holding limit. ARB has two choices on 

how to enforce the limit. First, it could allow transactions to proceed, then review 

them for conformance. If violations were found, ARB would have to penalize an 

entity involved in the trade and then arrange to unwind the transaction. Second, 

it could rely on the section 95921 requirement that each trade must conform to 

the proposed rules for holding or trading compliance instruments or it will not be 

accepted by the accounts administrator. This means all trades would be 

monitored for conformance to the holding limit and other rules, and would not be 

recorded if a violation is detected. Staff concluded that the second approach 

would be less resource-intensive to operate.

Rationale for Section 95920(b)(5).

Subsection 95920(b)(6) states that the holding limit will treat holdings of entities 

with a corporate association as being held by a single entity. This restriction will 

not apply if existing law or regulation prohibits coordinated market activity by the 

associated entities, including the transfer of compliance instruments between 

accounts controlled by the associated entities.

Summary of Section 95920(b)(6).
IX-107

This provision is needed to deal with the possibility that individual entities 

registered into the cap-and-trade system may be coordinating their market 

activities with other entities that have a corporate association. The main purpose 

of a holding limit is to prevent an entity from acquiring a large enough share of 

compliance instruments that it can influence market prices. Entities subject to an 

individual holding limit could jointly control enough compliance instruments to 

affect market prices if they coordinated their market activity.

Rationale for Section 95920(b)(6).

Subsection 95920(b)(7) states that the holding limit treat beneficial holdings by 

an agent as part of the holding of the owner. A beneficial holding refers to 

compliance instruments held by one entity on behalf of another entity that has an 

ownership interest.

Summary of Section 95920(b)(7).

This provision is needed to calculate the holding limit to reflect the entity that 

actually controls compliance instruments. Without this provision, entities could 

escape the holding limit by simply having agents purchase and hold allowances 

on their behalf. At the same time, the provision protects entities interested in 

buying and selling on behalf of clients from having their actions curtailed by the 

holding limit.

Rationale for Section 95920(b)(7).

Subsection 95920(c)(1) states that the Executive Officer may restrict the number 

of compliance instruments held by a covered entity or opt-in covered entity in 

response to violations by the entity. The restriction will allow the entity to 

accumulate sufficient compliance instruments to meet obligations but not enough 

to participate in speculative transactions.

Summary of Section 95920(c)(1).

This provision is needed as a response to rule violations. Obviously the 

Executive Officer cannot suspend or revoke the registration of covered entities. 

Staff instead proposes to restrict the number of instruments the violator could 

hold. This would allow the entity to meet its obligations without giving it more 

opportunities to violate market rules.

Rationale for Section 95920(c)(1).

Subsection 95920(c)(2) states that the Executive Officer may raise the annual 

surrender obligation for covered entities and opt-in covered entities in response 

to violations.

Summary of Section 95920(c)(2).
IX-108

This provision is needed as a response to rule violations. The provision would 

reduce some of the flexibility given to covered entities through the three-year 

compliance period by forcing them to meet a greater percentage of their triennial 

compliance obligation through the annual compliance “payment.” 

Rationale for Section 95920(c)(2).

Subsection 95920(c)(3) states that the Executive Officer may suspend or revoke 

the registration of opt-in covered entities, voluntarily associated entities, and 

other registered market participants

Summary of Section 95920(c)(3).

This provision is needed as a response to rule violations. The Executive Officer 

must have the authority to remove participants for serious or repeated violations.

Rationale for Section 95920(c)(3).

Section 95921. Conduct of Trade.

Subsection (a) requires that the accounts administrator will examine all 

transactions reports submitted by account holders prior to recording them. The 

accounts administrator will not accept transactions if the administrator 

determines that the transaction does not conform to the cap-and-trade system 

rules. For example, if the administrator will determine if a transaction would 

result in an account holder exceeding the holding limit set forth in 95920(b), the 

administrator will inform the parties to the trade that the transaction was not 

recorded into the accounts system.

Summary of Section 95921(a).

This provision is needed because the system of accounts maintained by the 

accounts administrator is the final record of who owns each compliance 

instrument. The cap-and-trade system rules are set up to ensure the integrity of 

transactions. ARB has determined that the system would operate more 

efficiently if the administrator examined the transactions at the time of reporting 

rather than reviewing and possibly reversing the transactions at a much later 

date.

Rationale for Section 95921(a).

Subsection (b) states the information that must be submitted along with each 

transaction report by account holders when they wish to transfer allowances 

between accounts.

Summary of Section 95921(b).

Rationale for Section 95921(b).
IX-109

The information requested allows the accounts administrator to determine that a 

valid transaction has taken place.

Subsection (b)(1) states that transaction reports must include the Holding 

Account number and name of the authorized account representative of the seller.

Summary of Section 95921(b)(1).

The provision is needed because ARB must ensure that the person filing the 

transaction to sell a compliance instrument has the authority to do so. ARB will 

compare this information with the information supplied when the selling entity 

originally registered with ARB for an account.

Rationale for Section 95921(b)(1).

Subsection (b)(2) states that transaction reports must include the Holding 

Account number and name of the authorized account representative of the buyer.

Summary of Section 95921(b)(2).

The provision is needed because ARB must ensure that the person filing the 

transaction to buy a compliance instrument has the authority to do so. ARB will 

compare this information with the information supplied when the buying entity 

originally registered with ARB for an account.

Rationale for Section 95921(b)(2).

Subsection (b)(3) states that the transaction report must include the serial 

numbers of the compliance instruments being transferred.

Summary of Section 95921(b)(3).

The provision is needed because all tracking of transfers of compliance 

instruments is done through the serial number of the instrument.

Rationale for Section 95921(b)(3).

Subsection (b)(4) states that the transaction report must include the date and 

time of the transaction agreement.

Summary of Section 95921(b)(4).

The provision is needed because the accounts administrator needs to know 

when an agreement to transact was reached, so that it may maintain an accurate 

history of transfers.

Rationale for Section 95921(b)(4).

Summary of Section 95921(b)(5).
IX-110

Subsection (b)(5) states that the transaction report must include the date and 

time of the settlement of a transfer, if it is different than the date and time of the 

transaction agreement.

The provision is needed because in some cases, parties to a trade may agree to 

transfer allowances at a future date, on terms specified in a contract. ARB will 

need to know when compliance instruments need to be transferred. For market 

monitoring purposes, ARB will need to know when instruments are being held in 

one account for the benefit of another entity. A beneficial holding means that 

someone other than the account holder may have ownership interest in the 

instrument.

Rationale for Section 95921(b)(5).

Subsection (b)(6) states that the transaction report must include the price paid for 

the instrument.

Summary of Section 95921(b)(6).

The provision is needed because ARB needs to know the prices paid for 

instruments in order to monitor market developments for potential manipulation 

or short supplies.

Rationale for Section 95921(b)(6).

This subsection states that in cases where the buyer or seller are acting on 

behalf of a third party that has an ownership interest in the instrument, known as 

a beneficial holding, the transaction report must include the Holding Account

number and name of the authorized representative of the entity with the 

ownership interest.

Summary of Section 95921(b)(7).

The provision is needed because the accounts administrator must track the 

actual ownership interest in an instrument for market monitoring purposes. 

Some rules, such as the holding limit, are applied based on ownership rights, not 

only in whose account the instrument is located.

Rationale for Section 95921(b)(7).

Subsection states that the seller and buyer must report each transaction within 

three days of settlement of the transaction agreement.

Summary of Section 95921(c).

Rationale for Section 95921(c).
IX-111

The provision is needed because the accounts administrator needs to know 

when an agreement to transact was reached so that it may maintain an accurate 

history of transfers. If the reporting period is too long, additional transactions 

involving an instrument could take place before problems with previous 

transactions could be resolved. 

Section 95922. Banking, Expiration, and Voluntary Retirement.

Subsection (a) states that allowances issued by ARB or approved for use in 

California in the current year or a previous year may be held, or banked, by 

entities registered in the California cap-and-trade system.

Summary of Section 95922(a).

The provision is needed because all those holding compliance instruments must 

be registered so that the accounts administrator can place the instruments in the 

correct account. For market monitoring purposes, ARB must know the identity of 

anyone holding instruments.

Rationale for Section 95922(a).

Subsection (b) states that allowances issued by ARB or approved for use in 

California may be held by registered entities.

Summary of Section 95922(b).

The provision is needed because all those holding compliance instruments must 

be registered so that the accounts administrator can place the instruments in the 

correct account. For market monitoring purposes, ARB must know the identity of 

anyone holding instruments. Unlike instruments issued for the current or 

previous year, there are restrictions in other parts of this regulation on the use of 

instruments issued for future compliance periods. 

Rationale for Section 95922(b).

Subsection (c) states that California compliance instruments do not have an 

expiration date. They remain valid until some action is taken by a registered 

entity to retire the allowance. This section provides a list of actions that may 

result in the retirement of an instrument by the Executive Officer. Once the 

retirement has been processed by the Executive Officer, the accounts 

administrator will prevent the instrument from appearing in another account in the 

system.

Summary of Section 95922(c).

Rationale for Section 95922(c).
IX-112

The provision is needed because ARB will allow account holders to hold 

allowances until they need them for compliance or voluntary retirement purposes.

Subsection (c)(1) states that an instrument will be removed from the tracking 

system when it is surrendered as part of a compliance obligation.

Summary of Section 95922(c)(1).

The provision is needed to prevent double-counting. Once an instrument has 

been submitted for retirement, ARB must ensure that it cannot be transferred 

again between accounts on the system.

Rationale for Section 95922(c)(1).

Subsection (c)(2) states that an instrument will be removed from the tracking 

system when it is voluntarily surrendered.

Summary of Section 95922(c)(2).

The provision is needed to prevent double-counting. Once an instrument has 

been submitted for retirement, ARB must ensure that it cannot be transferred 

again between accounts on the system.

Rationale for Section 95922(c)(2).

Subsection (c)(3) states that an instrument will be removed from the tracking 

system when it is surrendered within a GHG emissions-trading system with which 

the California cap-and-trade system has linked.

Summary of Section 95922(c)(3).

To prevent double-counting, once a compliance instrument has been submitted 

for retirement, either in California or in a GHG emissions-trading system to which 

California has linked, ARB must ensure that it cannot be transferred again 

between accounts on the system.

Rationale for Section 95922(c)(3).

Subsection (d)(1) states that a registered entity may voluntarily retire at any time 

any instrument it holds in its Holding Account.

Summary of Section 95922(d)(1).

The provision is needed because entities without a compliance obligation may be 

interested in offsetting their emissions or contributing voluntarily to achieve 

program goals.

Rationale for Section 95922(d)(1).
IX-113

Subsection (d)(2) states that to voluntarily retire instruments, a registered entity 

simply files a transaction report with the accounts administrator listing the serial 

numbers of the instruments and the Retirement Holding Account controlled by 

the Executive Officer as the destination account.

Summary of Section 95922(d)(2).

The provision is needed because ARB intends to keep the voluntary surrender 

process as simple as possible by having the entity involved use the standard 

transaction reporting process. The ARB Retirement Holding Account will have 

an account number like any other account.

Rationale for Section 95922(d)(2).

Subarticle 12. Linkage to External Greenhouse Gas Emissions Trading 

Systems.

Section 95940. General Requirements.

Section 95940 proposes that only approved compliance instruments issued by 

approved programs may be used for compliance in the cap-and-trade program.

Summary of Section 95940.

This section is necessary to establish which types of compliance instruments 

issued by other programs may be approved for use under this article.

Rationale for Section 95940.

Section 95941. Procedures for Approval of External GHG ETS.

Section 95941 proposes that the Board must approve each linkage after public 

notice and opportunity for public comment. In approving linkage, the Board will 

approve which compliance instruments issued by the program may be used for 

compliance.

Summary of Section 95941.

This section is necessary to provide consistency among linked programs 

approved by the Board. This is ensured by requiring that the Board approves 

each program for linkage and determines that they meet the regulatory 

requirements. 

Rationale for Section 95941.

Section 95942. Approval of Compliance Instruments from External GHG 

ETS.

Summary of Section 95942(a).
IX-114

Subsection (a) proposes that once a linkage has been approved by the Board, 

the specified compliance instruments in Subarticle 12 can be used for 

compliance in this program.

This provision is necessary to ensure that compliance instruments issued by 

other programs can only be used for compliance once the Board has approved 

them at a programmatic level.

Rationale for Section 95942(a).

Subsection (b) proposes that allowances issued by linked programs should not 

be subject to the quantitative usage limit specified in section 95855.

Summary of Section 95942(b).

This provision provides that allowances issued by linked programs should not be 

subject to the quantitative limit on offsets because an allowance from a linked 

program is fungible in the same way that a California allowance is within the capand-trade system.

Rationale for Section 95942(b).

Subsection (c) proposes that an offset credit or a sector-based credit issued by 

linked program should be subject to the quantitative usage limit specified in 

section 95855.

Summary of Section 95942(c).

This provision provides that offset and sector-based credits issued by linked 

programs should be subject to the quantitative limit on offsets because California 

offsets and sector-based credits are also subject to this limit, and they should be 

treated equally.

Rationale for Section 95942(c).

Section 95943. Reserved for Linkage.

Section 95943 is reserved as a placeholder for linkages approved by the Board 

in the future.

Summary of Section 95943.

This section is necessary to ensure that provisions in the regulation are reserved 

to incorporate linkages that may be approved in the future, and to send a signal 

that California is serious about linking to programs in the future.

Rationale for Section 95943.

Subarticle 13. Offset Credits Issued by ARB.
IX-115

Section 95970. General Requirements for Offset Credits Issued by ARB.

Section 95970 establishes the requirements for an offset credit issued by ARB.

Summary of Section 95970.

This section is necessary to show the requirements that an offset credit must 

meet to be issued by ARB. This section will help guide the reader through the 

credit issuance process.

Rationale for Section 95970.

Subsection (a) requires that a greenhouse gas emission reduction be real, 

additional, quantifiable, permanent, verifiable, and enforceable.

Summary of Section 95970(a).

Offset credits may only be issued for reductions that meet these qualities 

because Health and Safety Code section 38562(d)(1) states that these qualities 

are what constitute a greenhouse gas reduction. Since offset credits will be used 

in lieu of reducing emissions in California, those credits must be based on the 

same criteria.

Rationale for Section 95970(a).

Subsection (b) limits offset credits’ use to the limit set forth in section 95855.

Summary of Section 95970(b).

This subsection is necessary because users of offset credits need to know the 

use of offset credits is limited. For justification of section 95855, please see 

above.

Rationale for Section 95970(b).

Subsection (c) states that any offset credit issued must comply with protocols 

adopted by the Board.

Summary of Section 95970(c).

This subsection is necessary because there are many different types of offset 

credits available, but not all of them meet the standards included in Boardadopted protocols. By including this section, ARB ensures that offset credits are 

subjected to uniform standards of integrity.

Rationale for Section 95970(c).

Summary of Section 95970(d).
IX-116

Subsection (d) states that offset projects must meet the requirements of section 

95973.

This subsection is necessary because there are many different offset projects. 

By including this section, ARB ensures that offset projects are subjected to 

uniform standards.

Rationale for Section 95970(d).

Subsection (e) states that offset projects must be listed pursuant to requirements 

in section 95975.

Summary of Section 95970(e).

This subsection is necessary to ensure that ARB has all the relevant information 

regarding offset projects using Board-approved protocols.

Rationale for Section 95970(e).

Subsection (f) states that offset projects must meet the requirements for 

monitoring, reporting, and records retention.

Summary of Section 95970(f).

This subsection is necessary because there are many different offset projects. 

By including this section, ARB ensures that offset projects are subjected to 

uniform requirements for monitoring, reporting, and record retention.

Rationale for Section 95970(f).

Subsection (g) states that reductions from offset projects must meet the 

requirements for verification.

Summary of Section 95970(g).

This subsection is necessary because there are many different offset projects. 

By including this section, ARB ensures that all reductions from offset projects are 

subjected to uniform requirements for verification.

Rationale for Section 95970(g).

Subsection (h) states that offset credits must be issued according to sections 

95980 and 95981.

Summary of Section 95970(h).

Rationale for Section 95970(h).
IX-117

This subsection is necessary because all offset credits issued under compliance 

offset protocols must meet the same requirements.

Subsection (i) states that offset credits must be registered.

Summary of Section 95970(i).

This subsection is necessary for ARB to track offset credits and the owners of 

offset credits at all times.

Rationale for Section 95970(i).

Section 95971. Procedures for Approval of Compliance Offset Protocols.

Section 95971 establishes the process for how compliance offset protocols will 

be approved. Each compliance offset protocol must be approved by the Board 

after public notice and the opportunity for the public to submit comments. These 

protocols can then be used to generate offsets.

Summary of Section 95971.

This section is necessary because the Board must determine if compliance offset 

protocols meet the criteria and requirements of this regulation for offset credits to

be used for compliance purposes. It is also required by AB 32 that the Board 

adopt methodologies for the quantification of GHG emissions reductions (HSC 

§ 38571) used for compliance purposes. Compliance offset protocols will be 

incorporated by reference in the regulation.

Rationale for Section 95971.

Section 95972. Requirements for Compliance Offset Protocols.

Subsection (a) establishes the criteria that a compliance offset protocol must 

meet to be adopted by the Board.

Summary of Section 95972(a).

This provision is necessary to provide consistency among compliance offset 

protocols that are adopted by the Board. Since each offset equals one metric ton 

of CO2e, it is necessary that the rules governing the creation of offset credits are 

consistent.

Rationale for Section 95972(a).

Subsection (a)(1) requires that compliance offset protocols approved by the 

Board contain accurate quantification methods to determine the total number of 

GHG emission reductions or GHG removal enhancements.

Summary of Section 95972(a)(1).
IX-118

This provision is necessary because measurements and estimates associated 

with quantification must be as accurate as possible to ensure that GHG 

emissions reductions and GHG removal enhancements are real.

Rationale for Section 95972(a)(1).

Subsection (a)(2) requires that compliance offset protocols approved by the 

Board contain monitoring procedures and processes for collecting data.

Summary of Section 95972(a)(2).

Rules for monitoring procedures and data collection are essential for calculating 

the GHG emissions reductions or GHG removal enhancements that are 

controlled by the operator of the offset project. 

Rationale for Section 95972(a)(2).

Subsection (a)(3) requires that compliance offset protocols approved by the 

Board use a principle of conservativeness for estimating project baselines and 

business-as-usual emissions. 

Summary of Section 95972(a)(3).

To ensure GHG emissions reductions or GHG removal enhancements are real,

the compliance offset protocol must contain factors that provide an accurate and 

realistic reflection of the project baseline and the business-as-usual (BAU) 

scenario.

Rationale for Section 95972(a)(3).

Subsection (a)(4) requires that compliance offset protocols approved by the 

Board account for activity-shifting and market-shifting leakage.

Summary of Section 95972(a)(4).

A compliance offset protocol must contain methods for leakage assessments to 

ensure that GHG emissions reductions and GHG removal enhancements are 

real. If leakage exists, emissions are displaced from one area to another and 

provide no net decrease in GHG emissions in the atmosphere.

Rationale for Section 95972(a)(4).

Subsection (a)(5) requires that compliance offset protocols approved by the 

Board account for any uncertainties when quantifying GHG emission reductions 

or GHG removal enhancements.

Summary of Section 95972(a)(5).
IX-119

Compliance offset protocols must account for uncertainty to ensure that GHG 

emissions reductions or GHG removal enhancements are real. The greater the 

uncertainty in calculating GHG emissions reductions or GHG removal

enhancements from project activities, the less confidence there is that all offsets 

generated by a project are real.

Rationale for Section 95972(a)(5).

Subsection (a)(6) requires that compliance offset protocols approved by the 

Board ensure that GHG emission reductions are permanent. 

Summary of Section 95972(a)(6).

This provision is necessary to comply with Health and Safety Code section 

38562(d)(1) that requires GHG reductions to be permanent.

Rationale for Section 95972(a)(6).

Subsection (a)(7) requires that compliance offset protocols approved by the 

Board include mechanisms to ensure that GHG emissions reductions and GHG 

removal enhancements from sequestration offset projects are permanent.

Summary of Section 95972(a)(7).

This provision is necessary if there is a risk of reversal, as is the case in most 

biological sequestration offset projects. In this case mechanisms must be in 

place to replace any reversed offset credits. Compliance offset protocols must 

include mechanisms to replace reversed offset credits to ensure permanence. 

Greenhouse gas emissions reductions and GHG removal enhancements

credited as offsets must endure for a period of time, comparable to the 

atmospheric lifetime of anthropogenic CO2 emissions, because the use of an 

offset allows a covered entity to emit one metric ton of CO2e. If the offset credit 

is reversed while the emitted metric ton from the covered entity is still in the 

atmosphere, the atmospheric result is a net increase in GHG emissions.

Rationale for Section 95972(a)(7)

Subsection (a)(8) requires that compliance offset protocols approved by the 

Board include the length of the crediting period.

Summary of Section 95972(a)(8).

Compliance offset protocols must include the period of time a specific type of

offset project is allowed to be issued compliance offset credits (the crediting 

period). The length of crediting periods may vary based on project type; 

therefore, ARB must include the length in the compliance offset protocol. 

Rationale for Section 95972(a)(8).
IX-120

Subsection (b) proposes a range for the length of crediting periods. The crediting

period for non-sequestration projects is between 7 and 10 years and for 

sequestration-based projects between 10-30 years.

Summary of Section 95972(b), Crediting Periods.

The length of a crediting period must be finite because ARB wants flexibility in 

the future to decide if certain offset project types are no longer valid for AB 32 

compliance. This approach allows ARB to reevaluate and readjust project 

baseline and additionality requirements in the future if the regulatory environment 

changes and ARB determines offset projects are no longer additional. Staff 

proposes the range of 7 to 10 years for non-sequestration projects and 10 to 30 

years for sequestration projects, to incentivize investment in these offset project

types. Offset project developers need a guarantee of return on their investment. 

The most efficient way to do this is to establish a crediting period in which the 

emission reductions or removals from their projects will be eligible for compliance 

purposes.

Rationale for Section 95972(b).

Section 95973. Requirements for Offset Projects Using ARB Compliance 

Offset Protocols.

Subsection (a) establishes the requirements that offset projects must meet to be 

issued offset credits.

Summary of Section 95973(a), General Requirements for Offset Projects.

This provision is necessary to ensure that all offset projects meet the same 

criteria and are held to consistent standards.

Rationale for Section 95973(a).

Subsection (a)(1) proposes that all offset projects are required to use a 

compliance offset protocol, if the project wants to be issued offset credits.

Summary of Section 95973(a)(1).

This provision is necessary to provide consistency among offset projects of the 

same type. Since each offset equals one metric ton of CO2e, it is necessary that 

the rules governing the creation of offset credits are consistent. This can be 

achieved by requiring that all offset projects use the standardized compliance 

offset protocols.

Rationale for Section 95973(a)(1).
IX-121

Subsection (a)(2) proposes that all offset projects meet the same additionality 

requirements, and that additionality be assessed as of the date the offset project 

commences.

Summary of Section 95973(a)(2).

This provision is necessary to provide consistency among offset projects of the 

same type. To ensure that each offset equals one metric ton of CO2e, it is 

necessary that the rules for determining additionality are consistent for all offset 

projects. 

Rationale for Section 95973(a)(2).

Subsection (a)(2)(A) proposes that GHG emissions reduction or GHG removal 

enhancement activities undertaken to comply with any federal, state, or local law, 

or regulation in the jurisdiction where the offset project is located, or would occur 

anyways under a conservative BAU scenario, not be eligible for offset credits. 

Summary of Section 95973(a)(2)(A).

This provision is necessary because AB 32 states that an emission reduction 

used for compliance purposes must be “in addition to any greenhouse gas 

emission reduction otherwise required by law or regulation, and any greenhouse 

gas emission reduction that otherwise would occur” (HSC §38562(d)(2)). Since 

offset projects can be located anywhere in North America, the laws and 

regulations applicable where the offset project is located will determine whether 

the project is additional.

Rationale for Section 95973(a)(2)(A).

Subsection (a)(2)(B) proposes that an offset project must commence after 

December 31, 2006 to be considered additional.

Summary of Section 95973(a)(2)(B).

This provision is necessary because establishing the eligibility date for an offset 

project is critical to determining if it is additional. December 31, 2006, reflects the 

implementation date of AB 32 and makes the bounds more clear for ARB to 

determine if an offset project was implemented to achieve AB 32 goals.

Rationale for Section 95973(a)(2)(B).

Subsection (a)(2)(C) proposes that GHG emissions reductions and GHG removal 

enhancements must exceed the project baseline established in a compliance 

offset protocol to be considered additional. There are four protocols referenced 

in the regulation, and they include: U.S. Ozone Depleting Substances Projects 

Summary of Section 95973(a)(2)(C).
IX-122

Protocol incorporated by reference date: October 2010; Livestock Manure 

(Digesters) Projects Protocol incorporated by reference date: October 2010; 

Urban Forest Projects Protocol incorporated by reference date: October 2010; 

and U.S. Forest Projects Protocol incorporated by reference date: October 2010.

This provision is necessary to ensure that GHG emissions reductions and GHG 

removal enhancements are additional. The project baseline reflects the 

conservative BAU scenario that would likely occur in the absence of the offset 

project. The offset project must prove that its emissions are less than the project 

baseline to receive offset credits. The number of offset credits each project 

receives is based on the difference of its measured emissions and the emissions 

in the BAU scenario.

Rationale for Section 95973(a)(2)(C).

Subsection (a)(3) proposes that offset projects must be located in the United 

States, Canada, or Mexico to be eligible to generate offset credits.

Summary of Section 95973(a)(3).

This provision is necessary for ARB to have practical oversight over the offset 

projects that generate offsets. This geographic scope allows ARB to have 

oversight of its third-party verifiers, while also ensuring an ample supply of offsets. 

Limiting the geographic scope to only projects in California would not provide 

enough offset supply to meet total offset demand. 

Rationale for Section 95973(a)(3).

Subsection (b) proposes that an offset project meet all local, regional, and 

national requirements for environmental impact assessments that are applicable 

in its jurisdiction.

Summary of Section 95973(b), Local, Regional, and National Environmental 

Impact Assessment Requirements.

This provision is necessary to ensure that those responsible for offset projects 

are not implementing activities that do not comply with their local environmental 

laws and regulations.

Rationale for Section 95973(b).

Section 95974. Authorized Project Designee.

Subsection (a) proposes to allow an operator of an offset project to give certain 

rights and responsibilities to a third party. Those responsible for an offset project 

Summary of Section 95974(a), General Requirements for Designation of 

Authorized Project Designee.
IX-123

must say who these third parties are at the time they submit their project for 

listing.

This provision is necessary so ARB or an Offset Project Registry (OPR) knows 

which parties to contact when it issues offset credits or sends correspondence 

regarding an offset project.

Rationale for Section 95974(a).

Subsection (a)(1) proposes that an operator of an offset project can allow a third 

party to own the offset credits issued to its project, as long as the third party is 

allowed to hold compliance instruments. 

Summary of Section 95974(a)(1).

This provision is necessary because a landowner or project operator may have 

financial arrangements with third parties for the ownership of a project’s offsets in 

which it invested. These third parties must be reported to ARB or an OPR so it 

knows which party to transfer the offset credits to.

Rationale for Section 95974(a)(1).

Subsection (a)(2) proposes that an operator of an offset project can allow a third 

party to perform certain responsibilities associated with an offset project. These 

include: listing an offset project; monitoring, reporting and record retention; and 

verification.

Summary of Section 95974(a)(2).

This provision is necessary because a landowner or project operator may 

contract with a third party to implement all or some aspects of their offset project 

on their behalf. These third parties must be reported to ARB or an OPR so it 

knows which party to contact regarding the offset project.

Rationale for Section 95974(a)(2).

Subsection (b) proposes to allow an operator of an offset project to change 

and/or modify approved third parties or their approved activities once within each 

calendar year for a listed offset project.

Summary of Section 95974(b), Modifications to Authorized Project Designee and 

Activities.

This provision is necessary to allow operators of offset projects to conduct their 

private business and contracts as it wishes. Staff proposes to limit the number of 

Rationale for Section 95974(b).
IX-124

times an operator may do this to prevent any potential fraud or gaming of the 

program.

Section 95975. Listing of Offset Projects Using ARB Compliance Offset 

Protocols.

Subsection (a) proposes requirements that those responsible for an offset project 

must meet before an offset project can be listed.

Summary of Section 95975(a), General Requirements for Offset Project 

Operators and Authorized Project Designees Who Are Submitting an Offset 

Project for Listing.

This provision is necessary to ensure that ARB or an OPR has all the relevant 

information regarding those responsible for the offset project and details about 

the offset project itself.

Rationale for Section 95975(a).

Subsection (a)(1) proposes to require those responsible for an offset project to 

register with ARB, before an offset project that they are involved with is listed. 

Summary of Section 95975(a)(1).

This provision is necessary to ensure that ARB has all the relevant information 

regarding those responsible for the offset project. To hold compliance 

instruments, the party must register with ARB and open a Holding Account.

Rationale for Section 95975(a)(1).

Subsection (a)(2) proposes that those responsible for an offset project may not 

be subject to any Holding Account restrictions, before an offset project that they 

are involved with is listed.

Summary of Section 95975(a)(2).

This provision is necessary to ensure that those subject to a Holding Account 

restriction are not allowed to list or be involved with further offset projects.

Rationale for Section 95975(a)(2).

Subsection (a)(3) proposes that the party responsible for listing an offset project

must list their offset project with ARB or an OPR.

Summary of Section 95975(a)(3).
IX-125

This provision is necessary so that ARB or an OPR has all information related to 

the offset project if it intends to be issued offset credits.

Rationale for Section 95975(a)(3).

Subsection (b) proposes that the party responsible for listing an offset project

must make attestations and submit information related to the offset project to 

ARB or an OPR.

Summary of Section 95975(b), General Requirements for Offset Project Listing.

This provision is necessary to ensure that ARB or an OPR has all the relevant 

information regarding an offset project and that ARB has a legal and enforcement 

connection to those involved with offset projects.

Rationale for Section 95975(b).

Subsection (b)(1) proposes that the party responsible for listing an offset project

attest to ARB that all information they submit to ARB or an OPR is complete and 

accurate.

Summary of Section 95975(b)(1).

This provision is necessary to ensure that the information that the party 

responsible for listing the offset project submits is accurate and complete, and 

that ARB has a legal and enforcement connection to those involved with offset 

projects.

Rationale for Section 95975(b)(1).

Subsection (b)(2) proposes that the party responsible for listing an offset project 

attest to ARB that they are subject to all regulatory requirements and 

enforcement mechanisms of the cap-and-trade program.

Summary of Section 95975(b)(2).

This provision is necessary to ensure that the party responsible for listing the 

offset project acknowledges they are subject to all cap-and-trade regulatory and 

enforcement requirements and that ARB has a legal and enforcement connection 

to those involved with offset projects.

Rationale for Section 95975(b)(2).

Subsection (b)(3) proposes to require the party responsible for listing an offset 

project to submit all documentation required to list an offset project in section 

95975(c).

Summary of Section 95975(b)(3).
IX-126

This provision is necessary so that ARB or an OPR has all information related to 

the offset project and assess if the offset project may be eligible to be issued 

offset credits.

Rationale for Section 95975(b)(3).

Subsection (b)(4) proposes that if an offset project is listed with an OPR, the 

attestations required in sections 95975(b)(1) and (b)(2) be submitted to ARB at 

the time of listing or when the party responsible of the offset project wishes to be 

issued ARB offset credits pursuant to section 95981(d)(1).

Summary of Section 95975(b)(4).

This provision is necessary to ensure that the information that the party 

responsible for listing the offset project submits is accurate and complete, and 

that ARB has a legal and enforcement connection to those involved with offset 

projects.

Rationale for Section 95975(b)(4).

Subsection 95975(c) proposes that the party responsible for listing an offset 

project submit all the listing information required in a compliance offset protocol. 

There are four protocols referenced in the regulation and they include: U.S. 

Ozone Depleting Substances Projects Protocol incorporated by reference date: 

October 2010; Livestock Manure (Digesters) Projects Protocol incorporated by 

reference date: October 2010; Urban Forest Projects Protocol incorporated by 

reference date: October 2010; and U.S. Forest Projects Protocol incorporated by 

reference date: October 2010.

Summary of Section 95975(c), Offset Project Listing Information Requirements.

This provision is necessary so that the party responsible for listing an offset 

project knows what information and documentation they must submit to ARB or 

an OPR for their project to be listed.

Rationale for Section 95975(c).

Subsection (d) proposes that ARB or an OPR notify the party responsible for 

listing an offset project that all listing information is complete and the offset 

project may be listed. If the information submitted is incomplete, the party 

responsible for listing an offset project will also be notified of what is deficient.

Summary of Section 95975(d), Notice of Completeness for Offset Project Listing 

Information.
IX-127

This provision is necessary so the party responsible for listing an offset project 

knows that ARB or an OPR has received their listing information and that it can 

be processed for listing. If it is not complete, they will be told why and be given 

the opportunity to submit the correct and complete information.

Rationale for Section 95975(d).

Subsection (e) proposes that the party responsible for listing an offset project in 

an initial crediting period submit its listing information no later than when it 

submits its monitoring and reporting data, as required in section 95976, to ARB 

or an OPR.

Summary of Section 95975(e), Timing for Offset Project Listing in an Initial 

Crediting Period.

This provision is necessary to ensure that ARB or an OPR has listed an offset 

project before it begins accepting monitoring and reporting data for the offset 

project in an initial crediting period.

Rationale for Section 95975(e).

Subsection (f) proposes that once the party responsible for listing an offset 

project in an initial crediting period submits its listing information, and ARB or an 

OPR has reviewed the information against the requirements for additionality, it 

will be listed as a “Proposed Project.” This subsection also proposes that if an 

OPR denies the listing of an offset project in an initial crediting period, the party 

responsible for the offset project may request ARB to make a final decision as to 

whether or not the offset project meets the requirements for listing.

Summary of Section 95975(f), Listing Status of Offset Projects in an Initial 

Crediting Period.

This provision is necessary so that all offset projects listed by ARB or an OPR in 

an initial crediting period are reviewed against the same requirements for 

additionality. A more in-depth analysis of additionality will be performed by an 

ARB-accredited third-party verifier. The project will be listed as a “proposed 

project” for transparency purposes on a publicly available website. The project is 

considered a “proposed project” at this time because it has not yet received a 

positive offset or qualified positive offset verification statement. This section is 

necessary so ARB can have the final determination as to whether an offset 

project meets the requirements for listing in an initial crediting period.

Rationale for Section 95975(f).
IX-128

Subsection (g) proposes that the party responsible for listing an offset project in a 

renewed crediting period submit its listing information no earlier than 18 months

before the conclusion of its initial crediting period or a previous renewed crediting 

period, and no later than 9 months before conclusion of its initial crediting period 

or a previous renewed crediting period.

Summary of Section 95975(g), Timing for Offset Project Listing in a Renewed

Crediting Period.

This provision is necessary to establish a range of time in which additionality will 

be assessed for offset projects seeking a renewed crediting period.

Rationale for Section 95975(g).

Subsection (h) proposes that once the party responsible for listing an offset 

project in a renewed crediting period submits its listing information, and ARB or 

an OPR has reviewed the information against the requirements for additionality

as of the date the renewed crediting period begins, it will be listed as a “Proposed 

Renewal.” This subsection also proposes that if an OPR denies the listing of an 

offset project in renewed crediting period, the party responsible for the offset 

project may request ARB to make a final decision as to whether or not the offset 

project meets the requirements for listing. This section is necessary so ARB can 

have the final determination as to whether an offset project meets the 

requirements for listing in an initial crediting period.

Summary of Section 95975(h), Listing Status of Offset Projects in a Renewed

Crediting Period.

This provision is necessary so that all offset projects listed by ARB or an OPR in 

a renewed crediting period are reviewed against the same requirements for 

additionality. A more in-depth analysis of additionality will be performed by an 

ARB-accredited third-party verifier. The project will be listed as a “proposed 

renewal” for transparency purposes on a publicly available website. The project 

is considered a “proposed renewal” at this time, because it has not yet received a 

positive or qualified positive verification statement in its renewed crediting period.

Rationale for Section 95975(h).

Subsection (i) proposes that an offset project’s crediting period may be renewed 

if it meets the requirements for additionality.

Summary of Section 95975(i), Limitations for Crediting Period Renewals.

This provision is necessary to allow offset projects that meet the additionality 

criteria for a period of time to continue to reduce GHG emissions. A renewed 

Rationale for Section 95975(i).
IX-129

crediting period also allows for ARB to reevaluate the offset project’s baseline 

and additionality before it can be renewed. 

Subsection (i)(1) proposes that a non-sequestration offset project may be 

renewed twice, for the length of the crediting period that is specified in a

compliance offset protocol.

Summary of Section 95975(i)(1).

This provision is necessary to allow non-sequestration projects to be renewed. 

The period of time represented by the total renewal periods represents the length 

of time that staff believes these types of offset projects will continue to be 

additional. Crediting periods may be renewed to continue to allow offset projects 

to generate offset credits, as long as they continue to meet the eligibility 

requirements for offset projects.

Rationale for Section 95975(i)(1).

Subsection (i)(2) proposes that a sequestration offset project may be renewed for 

a total of 100 years, regardless of the length of the crediting period that is 

specified in a compliance offset protocol.

Summary of Section 95975(i)(2).

This provision is necessary to allow sequestration offset projects to be renewed. 

The period of time represented by the total renewal periods represents the length 

of time that staff believes these types of offset projects will continue to be 

additional and will continue to store carbon. Crediting periods for sequestration 

offset projects may be renewed as long as they continue to meet the eligibility 

requirements for offset projects, because they require long-term investment and 

commitment by project developers and achieve gradual GHG removals over long 

timescales.

Rationale for Section 95975(i)(2).

Section 95976. Monitoring, Reporting, and Record Retention Requirements 

for Offset Projects.

Section 95976 provides the monitoring, reporting, and record retention 

requirements for offset project.

Summary of Section 95976.

This provision is needed to provide enforceable monitoring, reporting, and record 

retention requirements, to provide consistent and accurate information to ARB 

Rationale for Section 95976.
IX-130

and for program transparency. The document retention requirements will support 

verification and ARB audits of the project.

Subsection (a) specifies that equipment used to monitor emissions from offset 

projects must be maintained and calibrated as required by the manufacturer at 

the level of accuracy stated in the Compliance Offset Protocol. Other 

measurements must be consistent with the applicable offset protocol.

Summary of Section 95976(a).

This provision is needed to ensure accurate accounting of project related 

emissions data. It is necessary to specify basic requirements for the accuracy 

and measurement of GHG emissions for consistence in data quality across all 

offset projects.

Rationale for Section 95976(a).

Subsection (b) requires any applicable missing data provisions in each 

Compliance Offset Protocol to be followed by the project developer.

Summary of Section 95976(b).

This provision is necessary to ensure that those developing offset projects of the 

same project type are held to the same standard when accounting for missing 

data. Some Compliance Offset Protocols may offer these methods when there is 

a requirement for continuous monitoring of project performance.

Rationale for Section 95976(b).

Subsection (c) requires that all monitoring equipment must be installed as 

specified in each Compliance Offset Protocol. Each Compliance Offset Protocol 

contains specific monitoring requirements to support quantification of GHG 

reductions or GHG removals.

Summary of Section 95976(c).

This provision is necessary to ensure that those developing offset projects are 

correctly installing the required monitoring equipment specific to each project 

type. It is important to have the correct monitoring equipment to accurately 

quantify baseline emissions, project emissions, GHG removals, and GHG 

reductions. 

Rationale for Section 95976(c).

Subsection (d) requires those developing an offset project to submit an Offset 

Project Data Report to ARB or an OPR for a calendar year.

Summary of Section 95976(d).
IX-131

This provision is necessary to have annual reporting of data for offset projects 

that may be eligible to be issued offset credits by ARB. This data also provides 

transparency in the program, as all stakeholders will be able to see a public 

report on the performance of each offset project.

Rationale for Section 95976(d).

Subsections (d)(1) through (d)(4)require those developing offset projects to 

annually submit the types of data for each project provided in the applicable 

Compliance Offset Protocol to ARB or an OPR. 

Summary of Section 95976(d)(1) through (d)(4).

These subsections are needed for program transparency, as the information will 

be made available to all stakeholders, and to ensure a consistent level of 

reporting between project types.

Rationale for Section 95976(d)(1) through (d)(4).

Subsection (d)(5) requires those developing offset projects to attest to ARB that 

the information provided in the Offset Project Data Report is accurate and 

complete.

Summary of Section 95976(d)(5).

This provision is necessary to ensure that the information that the party 

responsible for submitting the Offset Project Data Report is accurate and 

complete and that ARB has a legal and enforcement connection to those 

involved with offset projects.

Rationale for Section 95975(d)(5).

Subsection (d)(6) requires all Offset Project Data Reports covering the previous 

year of reporting to be submitted by an April 1 deadline. For sequestration 

projects, there are still annual reports, but GHG removals may be aggregated 

into an annual report to cover up to six years of GHG removals.

Summary of Section 95975(d)(6).

This subsection is necessary to provide timely and consistent flow of data for the 

transparency of the program. Sequestration projects take a long time to 

sequester carbon, and it makes sense to allow those developing offset projects 

to report multiple years of GHG removals, by year, on a single report. During 

verification of that annual report, all GHG removals for each year would be 

verified at the same time, thus making it more cost-effective for those developing 

offset projects.

Rationale for Section 95975(d)(6).
IX-132

Subsection (d)(7) states that any Offset Project Data Reports that are not 

submitted covering the project performance for the previous year are ineligible to 

receive ARB offset credit for the GHG removals or GHG reductions quantified 

and reported in that report.

Summary of Section 95975(d)(7).

This provision is necessary to help enforce the reporting deadline of April 1. 

Participation in the compliance offset program is voluntary, and this provides a 

mechanism to ensure that all data required for an offset project is provided in a 

timely manner for program transparency, and for compliance entities to be aware 

of the types and amounts of compliance instruments they may be able to use.

Rationale for Section 95975(d)(7).

Subsection (e) requires those developing offset projects to retain all information 

used to develop the Offset Project Data Report, including documentation of the 

project boundary, fuel usage, model inputs, and other descriptions of the project. 

Specific document type retention requirements are included.

Summary of Section 95976(e).

This provision is necessary to provide careful documentation that allows for the 

verification of the Offset Project Data Report by a verification body and also

allows for any audits by ARB.

Rationale for Section 95976(e).

Subsection (e)(1) provides a detailed list of the types of documentation those 

developing an offset project must retain for their offset project. 

Summary of Section 95976(e)(1).

This provision is necessary so that all project-relevant data is maintained to 

support a successful verification of the offset project and for ARB to review as 

part of its offset project auditing. This list provides a consistent requirement for 

all data retention across all offset projects.

Rationale for Section 95976(e)(1).

Subsection (e)(2) specifies the length of project related data document retention, 

that they must be able to support verification, and that the documents must be 

made available to ARB or an OPR if requested.

Summary of Section 95976(e)(2).
IX-133

This provision is necessary to ensure that ARB or an OPR has access to the 

documents even after a crediting period has ended, in case a problem is found 

with the offset project.

Rationale for Section 95976(e)(2).

Subsection (e)(3) specifies that documents required for retention must be 

extensive enough for verification of each Offset Project Data Report.

Summary of Section 95976(e)(3)

This provision is necessary to ensure that ARB or an OPR will have enough data 

to confirm the crediting project has been operating in accordance with the 

appropriate ARB-approved protocol.

Rationale for Section 95976(e)(3)

Subsection (e)(4) specifies that entities that operate an offset project must 

provide all documents required to be retained pursuant to the regulation within 

ten days to either ARB or an Offset Project Registry.

Summary of Section 95976(e)(4)

This provision is necessary so that ARB or an Offset Project Registry can 

conduct an audit of the offset project to ensure the offset project is complying 

with all provisions of the appropriate ARB-approved protocol.

Rationale for Section 95976(e)(4)

Section 95975(f) provides a process for those developing an offset project to 

make a request to ARB for an alternate method to monitor project data if there is 

a breakdown in the existing monitoring equipment. The proposed method must 

meet criteria to demonstrate it will provide accurate data to support any projectrelated calculations.

Summary of Section 95976(f), General Procedure for Interim Gas or Fuel 

Analytical and Monitoring Equipment Data Collection.

This provision is necessary because in the real world, sometimes monitoring 

equipment may break down. This provision provides some flexibility to those 

developing an offset project to propose an alternative monitoring method, so that 

the project may continue to accurately generate data for offset credits.

Rationale for Section 95976(f).

Summary of Section 95976(f)(1).
IX-134

Subsection (f)(1) provides the conditions under which those developing an offset 

project may request an interim data collection method. Those criteria include a 

threshold of 20 percent missed data, hardship in fixing the failed monitoring 

equipment, and that the request must be made within 30 days of monitoring 

equipment failure.

This provision is needed to apply the interim data collection method only in very 

limited circumstances. Those developing an offset project must be diligent in 

their own maintenance and implementation of their offset projects. However, 

even under the best maintenance plans, there can be unforeseen problems, and 

this provision is to provide recourse to those developing an offset project in those 

cases. 

Rationale for Section 95976(f)(1).

Subsection (f)(2) provides the process and information that those developing an 

offset project must meet to request an interim data collection method.

Summary of Section 95976(f)(2).

This provision is needed to ensure that ARB has all of the relevant information on 

which to make a decision on whether or not to approve a request for an interim 

data collection method. 

Rational for Section 95976(f)(2).

Subsection (f)(3) provides ARB the right to limit the duration of the interim data 

collection method or request additional information before making a 

determination on a interim data collection method request.

Summary of Section 95976(f)(3).

This provision is needed to require that those developing an offset project 

expeditiously fix the issue with their monitoring equipment and return to collecting 

data, as required under the applicable Compliance Offset Protocol. The interim 

data collection method is meant to only be used for a limited time, until the 

protocol requirements for monitoring may be restarted. Additional information 

may be needed to fully understand the extent of the equipment failure and the 

time needed to repair it. 

Rationale for Section 95976(f)(3).

Subsection (f)(4) stipulates how ARB will treat the data collected under an interim 

data collection method.

Summary of Section 95976(f)(4).

Rationale for Section 95976(f)(4).
IX-135

This provision is necessary for verifiers and those developing an offset project to 

understand how to treat data that is not collected as required in a Compliance 

Offset Protocol. Data collected under an interim method is considered captured 

data, and ARB will determine its treatment during the verification assessment for 

material misstatement.

Section 95977. Verification of GHG Emission Reductions or GHG Removal 

Enhancements from Offset Projects.

Section 95977 includes general verification requirements for those developing 

offset projects that submit Offset Project Data Reports.

Summary of Section 95977.

This section is necessary because AB 32 requires any offset credits used for 

compliance to be subject to regulatory verification.

Rationale for Section 95977.

Subsection (a) requires all Offset Project Data Reports to be verified by an ARBaccredited verification body.

Summary of Section 95977(a), General Requirements.

This provision is necessary to ensure that only ARB-accredited verification 

bodies that meet certain regulatory criteria provide verification services to the 

those developing offset projects. 

Rationale for Section 95977(a).

Subsection (b) specifies that verification must be done annually for nonsequestration projects (such as digesters).

Summary of Section 95977(b), Schedule of Verification Services of NonSequestration Projects.

This provision is necessary because annual verification follows annual reporting 

of Offset Project Data Reports. This facilitates a scheduled stream of potential 

offsets for non-sequestration projects. Annual verification provides a dependable 

schedule for stakeholders to understand the supply of offsets in the compliance 

program. 

Rationale for Section 95977(b).

Subsection (c) specifies that verification must be done at least once every six

years for sequestration projects (such as forestry).

Summary of Section 95977(c), Schedule of Verification of Sequestration Projects.
IX-136

This provision is necessary because sequestration projects sequester 

incremental amounts of carbon per year, it is acceptable to decrease the 

frequency of verification from annually to at least once every six years. This 

allows enough carbon to be sequestered and potentially issued credits to make 

verification cost-effective.

Rationale for Section 95977(c).

Subsection (d) specifies that verification reports must be submitted by October 1.

Summary of Section 95977(d), Timing of Submittal of Offset Verification 

Statements to ARB or an OPR.

This provision is necessary to provide a consistent date for Offset Project Data 

Reports to be verified and issued credits each year. 

Rationale for Section 95977(d).

Subsection (e)(1) specifies that verification bodies and verifiers may only work for 

those developing offset projects for six consecutive years before rotating to a 

different verification body.

Summary of Section 95977(e)(1), Rotation of Verification Bodies.

This provision is necessary because rotation of verification bodies requires an 

entirely new verification team to evaluate the emissions data report, to minimize 

any biases and avoid familiarity or complacency between those developing offset 

projects and the verification body. 

Rationale for Section 95977(e)(1).

Subsection (e)(2)(A) specifies the information that must be provided in the Notice 

of Verification Services submittal requirement for offset projects. The notice is 

also sent to an OPR, if applicable.

Summary of Section 95977(e)(2)(A), Notice of Verification Services.

This provision is needed to ensure that the verification body provides information 

to identify a verification team with any applicable project specialists and that ARB 

or an OPR has an opportunity to plan to observe the site visit as part of an audit 

during oversight of its regulatory verification program. 

Rationale for Section 95977(e)(2)(A).

Subsection (e)(2)(B) requires the verification body to update the information 

provided in the Notice of Verification Services.

Summary of Section 95977(e)(2)(B).
IX-137

This provision is necessary for ARB to have accurate documentation of the team 

members that actually provided verification services for a facility, to ensure 

rotation of verification bodies and verifiers. The updated information on site visits 

will allow ARB staff to make any changes necessary in their schedule if the 

verification was previously chosen for an audit. 

Rationale for Section 95977(e)(2)(B).

Subsection (e)(2)(C)(i) requires the verification team to obtain information from 

those developing offset projects to develop a verification plan. 

Summary of Section 95977(e)(2)(C)(i), Verification Plan for Offsets.

This provision is necessary to ensure that all verification teams request 

consistent and similar information to develop a verification plan. The verification 

plan is needed to define the scope and timing of verification services for a client.

Rationale for Section 95977(e)(2)(C)(i).

Subsection (e)(2)(C)(ii) contains lists the minimum requirements for what a 

verification plan should include for all verifications.

Summary of Section 95977(e)(2)(C)(ii).

This provision is needed to ensure consistency for all verification plans and 

provides a written record as to what the verification team will do as part of 

verification, as well as the expected dates of completion. 

Rationale for Section 95977(e)(2)(C)(ii).

Subsection (e)(2)(C)(iii) requires the verification team to explain the scope of 

verification services to the client and review original documentation as part of 

providing verification services.

Summary of Section 95977(e)(2)(C)(iii).

This provision is needed to ensure that the verification team communicates its 

planned activities for verification services to those developing offset projects and 

that original documentation is reviewed, to limit the opportunity of fraud by those 

developing offset projects. It is important for those developing offset projects to 

understand the verification process so that they can be prepared to provide 

information to the verification team.

Rationale for Section 95977(e)(2)(C)(iii).

Summary of Section 95977(e)(2)(C)(iv)(a), Site Visits for Offset Projects.
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Subsection (e)(2)(C)(iv)(a) requires the verification team to make a site visit to 

each offset project site when they are verifying GHG emission reductions or GHG 

removals. While on site the verification team must conduct an array of activities 

to confirm the eligibility of the offset project and an accurate project boundary, 

review project monitoring techniques, and confirm that all of the monitoring and 

measuring requirements are in conformance. The requirements in this section 

only have to be checked the first year of the offset project verification, as it is 

unlikely they will change year to year. 

This provision is needed to validate the offset project. The check on the eligibility 

requirements is often a separate validation step. ARB has combined this step 

into the first year of verification to streamline the offset project program. This 

check reassures those developing offset projects that their projects are set up to 

conform to the applicable Compliance Offset Protocol.

Rationale for Section 95977(e)(2)(C)(iv)(a).

Subsection (e)(2)(C)(iv)(b) requires the verification team to review the sources 

and sinks in the project boundary and review all equipment and data systems 

that are collecting or processing offset project-related data. It also requires the 

verification to ensure that the offset project meets all environmental laws. If the 

offset project does not meet all applicable environmental laws, it is ineligible to 

receive ARB offset credit.

Summary of Section 95977(e)(2)(C)(iv)(b).

This provision is necessary to ensure that the offset project continues to operate 

in accordance with the Compliance Offset Protocol, so that all reported GHG 

reductions or GHG removals are accurately quantified. It also ensures that the 

offset project continues to be implemented in a manner that does not adversely 

affect the environment.

Rationale for Section 95977(e)(2)(C)(iv)(b).

Subsection (e)(2)(C)(v) requires the verification team to review the offset project 

to ensure that all sources and sinks are included in the Offset Project Data 

Report.

Summary of Section 95977(e)(2)(C)(v).

This provision is necessary to ensure the verification team take stock of all the 

GHG emission sources and sinks that are required to be included in the Offset 

Project Data Report for the applicable Compliance Offset Protocol. This ensures 

completeness of reporting for the project and accounts for any sources impacted 

by the offset project.

Rationale for Section 95977(e)(2)(C)(v).
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Subsection (e)(2)(C)(vi) requires those developing offset projects to provide all 

offset project-related data to the verification team.

Summary of Section 95977(e)(2)(C)(vi).

This provision is necessary to ensure that verification teams have access to all of 

the information related to an offset project during verification. If a verification 

team could not corroborate the data in the Offset Project Data Report with 

underlying data or other sources of information, they would have to submit an 

adverse offset verification statement.

Rationale for Section 95977(e)(2)(C)(vi).

Subsection (e)(2)(C)(vii) requires the verification team to develop a sampling plan 

that ranks the sources, sinks, and reservoirs by their relative contribution to the 

emissions of the offset project, and by their risk of uncertainty in quantification. 

The risk of uncertainty is based on the verification team’s assessment of 

document reviews, data collection and management systems, and the general 

diligence of those developing offset projects in maintaining the project and all 

related systems. 

Summary of Section 95977(e)(2)(C)(vii), Sampling Plan for Offset Project Data 

Reports.

This provision is necessary to isolate the GHG sources, sinks, or reservoirs that 

will be targeted for a more in-depth review by the verification team. During the 

course of verification services, the verification team does not recalculate the 

entire accounting and inventory of GHGs in the Offset Project Data Report.

Greenhouse gas verification is a risk-based review of a GHG assertion in 

international standards. The development of a sampling plan facilitates a riskbased review of the Offset Project Data Report.

Rationale for Section 95977(e)(2)(C)(vii).

Subsection (e)(2)(C)(viii) requires the verification team to identify the specific 

GHG sources, sinks, or reservoirs that will be subject to data checks and review 

for conformance. The verification team must document the information reviewed 

for these sources.

Summary of Section 95977(e)(2)(C)(viii).

This provision is necessary to document the verification process, to enable ARB 

audits and to ensure that the verification team has conducted its due diligence in 

its data checks. The use of data checks is based on international best practices 

for GHG verification. This also provides a consistent requirement for all 

verifications and provides program consistency.

Rationale for Section 95977(e)(2)(C)(viii).
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Subsection (e)(2)(C)(ix) requires the sampling plan to be updated prior to the 

completion of verification services.

Summary of Section 95977(e)(2)(C)(ix).

This provision is necessary because during the course of verification, the 

verification team may uncover information that requires them to look more closely 

at something not contained in the original sampling plan. An updated sampling 

plan provides a written record of the verification process, to allow for ARB audits.

Rationale for Section 95977(e)(2)(C)(ix).

Subsection (e)(2)(C)(x)requires the verification team to continuously revise the 

sampling plan as evidence becomes available.

Summary of Section 95977(e)(2)(C)(x).

This provision is necessary to ensure that the verification team is diligent in its 

recording of information during the course of providing verification services. All 

findings during the verification services must be recorded to support ARB audits 

and transparency in the performing of verification services upon which the 

verification team forms its findings.

Rationale for Section 95977(e)(2)(C)(x).

Subsection (e)(2)(C)(xi)provides the document and data retention requirements 

for verification bodies.

Summary of Section 95977(e)(2)(C)(xi).

This provision is necessary to ensure that all verification-related information is 

retained to enable ARB audits, and that there is a clear, documented evidence 

upon which a verification body made its findings when it issued an Offset 

Verification Statement.

Rationale for Section 95977(e)(2)(C)(xi).

Subsection (e)(2)(C)(xii) specifies which data checks must be performed by the 

verifier, including the evaluation of methods and factors, emission sources, and 

other Compliance Offset Protocol requirements.

Summary of Section 95977(e)(2)(C)(xii).

This provision is necessary to define data checks so that all verification bodies 

are held to the same standards when completing Offset Verification Services. A 

clear listing of requirements provides some certainty to both those developing 

Rationale for Section 95977(e)(2)(C)(xii).
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offset projects and verifiers as to how data checks must be completed. Data 

checks are critical in a risk-based assessment for Offset Material Misstatement 

and conformance.

Subsection (e)(2)(C)(xiii) requires those developing offset projects to fix any 

errors in the Offset Project Data Report, if possible.

Summary of Section 95977(e)(2)(C)(xiii).

This provision is necessary because in a cap-and-trade program, it is necessary 

to have the data as accurate as possible. 

Rationale for Section 95977(e)(2)(C)(xiii).

Subsection (e)(2)(C)(xiv) requires verifiers to conduct their own calculations of 

sources that were identified as having high risk for potential error in the sampling 

plan and to review the calculations of the GHG emissions or GHG reductions for 

those sources for conformance with the regulation or applicable Compliance 

Offset Protocol.

Summary of Section 95977(e)(2)(C)(xiv).

This provision is necessary so that all verifiers are held to a consistent standard 

that requires them to recalculate emissions sources for select sources and 

review those same sources for conformance. A verifier’s recalculation of the 

GHG sources, sinks, or reservoirs provides a comparison for what the verifier 

believes should be the number based on the Compliance Offset Protocol versus 

what those developing an offset project included in the Offset Project Data 

Report. This process is based on international best practices for GHG 

verification.

Rationale for Section 95977(e)(2)(C)(xiv).

Subsection (e)(2)(C)(xv) specifies how the log of issues is developed by the 

verifier, and how the verifier must describe the impact of any identified issues on 

the Offset Verification Statement.

Summary of Section 95977(e)(2)(C)(xv).

This provision is necessary because the log of issues is required to ensure that 

those developing offset projects understand how each of the identified issues 

could impact the Offset Verification Statement, helping to ensure a transparent 

process between the verification body and those developing offset projects. The 

issues log can also inform ARB as to any problems discovered during the course 

of verification.

Rationale for Section 95977(e)(2)(C)(xv).
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Subsections (e)(2)(C)(xvi) through (e)(2)(C)(xvii) describe when and how an 

Offset Material Misstatement is evaluated, including an equation that relates the 

errors and omissions to the accuracy of the reported data.

Summary of Section 95977(e)(2)(C)(xvi) through (e)(2)(C)(xvii).

These provisions are necessary because a single equation for Offset Material 

Misstatement ensures that all verifiers are consistently evaluating emissions for 

each project using the same calculation. Without a consistent method, verifiers 

may reach different conclusions when reviewing the same data. This equation is 

rooted in financial auditing and is consistent with other regulatory or voluntary 

offset verification programs.

Rationale for Section 95977(e)(2)(C)(xvi) through (e)(2)(C)(xvii).

Subsection (e)(2)(C)( xviii)(a) requires the verification body to prepare an Offset 

Verification Statement that documents the findings for the verification of the 

Offset Project Data Report, and that those findings are independently reviewed 

within the verification body.

Summary of Section 95977(e)(2)(C)(xviii)(a), Offset Verification Statement.

This provision is necessary to bring the verification process to a close, provide 

findings, and have internal verification body checks on those findings as a quality 

control/quality assurance (QC/QA) measure on the services provided by the 

verification body.

Rationale for Section 95977(e)(2)(C)(xviii)(a).

Subsection (e)(2)(C)( xviii)(b) requires an independent reviewer to review key 

decisions made by the verification body during the course of verification services.

Summary of Section 95977(e)(2)(C)(xviii)(b).

Rationale for Section 95977(e)(2)(C)(xviii)(b).

This provision ensures that the independent reviewer focus on key points that 

could easily affect the outcome of a verification and provide a check on decisions 

made by the verification team at those critical points. 

Summary of Section 95977(e)(2)(C)(xviii)(c).

Subsection (e)(2)(C)( xviii)(c) requires the independent reviewer to remain 

completely out of the verification process until they objectively review the 

verification teams findings. The independent reviewer also confirms that the 

verification team met all of its obligations under the regulation when providing 

verification services.
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Rationale for Section 95977(e)(2)(C)(xviii)(c).

This provision is necessary to ensure that even within the verification body, there 

truly is an objective review of the verification team’s findings before an Offset 

Verification Statement is issued for the Offset Project Data Report. The 

verification body takes responsibility for the work of its staff under the regulation 

and must be sure that it has met all of the requirements of the regulation before 

submitting the Offset Verification Statement. The concept of an internal review is 

also consistent with international best practices for GHG verification.

Summary of Section 95977(e)(2)(C)(xviii)(d).

Subsection (e)(2)(C)(xviii)(d) requires the verification team to compile a detailed 

verification report of key documents developed during the verification process, 

include in the verification statement whether or not the Offset Project Data Report 

contains an Offset Material Misstatement, and whether or not the report conforms 

to the regulation and applicable Compliance Offset Protocol. The lead verifier on 

the verification team must attest that all information provided in the Offset 

Verification Statement is accurate and complete, and that all verification 

requirements have been met. 

Rationale for Section 95977(e)(2)(C)(xviii)(d).

This provision is necessary to ensure those developing offset projects 

understand the verification process and findings that led to the Offset Verification 

Statement. It also ensures the verification body compiles a final report of all the 

evidence that supports the Offset Verification Statement. This report can also 

provide information to ARB during an audit, to ensure consistency and quality of 

its verification program. The attestation statement holds the lead verifier for the 

verification accountable to ARB for the findings in the Offset Verification 

Statement.

Summary of Section 95977(e)(2)(C)(xix).

Subsection (e)(2)(C)(xix) requires the verification body to provide those 

developing offset projects with 10 working days in which to modify the Offset 

Project Data Report if the those developing offset projects are about to receive 

an Adverse Offset Verification Statement. This section also describes the 

process for ARB or an OPR to review the Offset Verification Statement and 

provide a final resolution to any dispute issues that cannot be resolved between 

the verification body and those developing offset projects. If those developing 

offset projects are not satisfied by a review provided by the OPR, they may 

appeal to ARB to conduct a second review.

Rationale for Section 95977(e)(2)(C)(xix).

This provision provides those developing offset projects with 10 working days to 

modify and correct the Offset Project Data Report and provides enough time for 
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those developing offset projects to make the necessary changes to the report,

while balancing the need to complete the verification in a timely fashion. The 

dispute resolution process provides a mechanism for the verification body and 

those developing offset projects to have an Offset Project Data Report reviewed 

under certain circumstances before an Offset Verification Statement is issued.

Summary of Section 95977(e)(2)(C)(xx).

Subsection (e)(2)(C)(xx) states that no changes may be made to Offset Project 

Data Reports after an Offset Verification Statement has been submitted to ARB. 

Rationale for Section 95977(e)(2)(C)(xx).

This provision is necessary in a cap-and-trade program so that ARB can issue 

offset credit to verified GHG reductions or removals. Verified data is considered 

accurate and complete as it has been through the verification process and 

subject to scrutiny by an independent eye. ARB does not anticipate those 

developing offset projects needing to change their data after the completion of 

verification.

Summary of Section 95977(e)(2)(C)(xxi).

Subsection (e)(2)(C)(xxi) specifies that if a high conflict is discovered, the Offset 

Project Data Report must be re-verified by a different verifier. 

Rationale for Section 95977(e)(2)(C)(xxi).

This provision is necessary because a verification body that contracts with those

developing offset projects within one year of submitting an Offset Verification 

Statement in order to provide a high-conflict service may not have provided an 

independent and unbiased Offset Verification Statement. It is necessary to 

invalidate any verification where there is an identified high conflict of interest, and 

that verification body may have their accreditation revoked in response to that 

activity. Because it is important to ensure the Offset Verification Statement is 

provided by an unbiased verifier, any high conflicts discovered during or after 

verification triggers re-verification so that the accuracy of the report can be 

assessed by a truly independent verifier. 

Summary of Section 95977(e)(2)(C)(xxii).

Subsection (e)(2)(C)(xxii) requires those developing offset projects to provide 

ARB with all data available to the verifier for review by ARB staff. 

Rationale for Section 95977(e)(2)(C)(xxii).

This provision is necessary because in order for ARB to have effective oversight 

of the program and to audit reports, ARB staff must have access to all data used 

to develop the Offset Project Data Report. ARB must be able to request all 
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project-related data in order to ensure Offset Project Data Reports are accurate 

and complete.

Summary of Section 95977(e)(2)(C)(xxiii).

Subsection (e)(2)(C)(xxiii) requires the verification body to provide ARB with a 

detailed verification report.

Rationale for Section 95977(e)(2)(C)(xxiii).

This provision is necessary because for ARB to evaluate the work of verification 

bodies, it is necessary to review and audit their detailed verification reports. 

Summary of Section 95977(e)(2)(C)(xxiv).

Subsection (e)(2)(C)(xxiv) requires a verification body to make itself available for 

ARB audit.

Rationale for Section 95977(e)(2)(C)(xxiv).

This provision is necessary because for ARB to have effective oversight of the 

program, ARB may need to audit verification bodies and verifiers to evaluate the 

quality of verification services provided under this section.

Summary of Section 95977(f)

Subsection (f) requires that offset projects must meet both the verification 

requirements of the regulation as well as any additional verification requirements 

of the specific Compliance Offset Protocol, if any.

Rationale for Section 95977(f)

This provision is necessary to ensure that all offset projects comply with both the 

regulation and any project specific verification requirements. The verification 

requirements are necessary to ensure that GHG reductions reported are actually 

occurring.

Section 95978. Offset Verifier and Verification Body Accreditation.

Summary of Section 95978.

Section 95978 requires offset project verifiers and verification bodies to meet the 

requirements in Subarticle 4, section 95132 of the Mandatory Reporting 

Regulation.

Rationale for Section 95978.

This section is necessary so all verifiers and verification bodies providing 

verification services under the mandatory reporting program or offset program 
IX-146

will be held to the same rigorous standards for accreditation. These standards 

are based on existing accreditation requirements in other voluntary and 

regulatory GHG reporting and offset programs. The requirements are also 

consistent with international best practices for verification body accreditation.

Section 95979. Conflict of Interest for Verification Bodies for Verification of 

Offset Project Data Reports.

Summary of Section 95979(a).

Subsection (a) stipulates that the conflict-of-interest requirements apply to each 

verification body and the individual verifiers.

Rationale for Section 95979(a).

This provision is necessary because conflict of interest must apply at the 

company and individual level to ensure a truly unbiased review of any Offset 

Project Data Report.

Summary of Section 95979(b)(1).

Subsection (b)(1) specifies that a high conflict of interest exists where the 

operator and verification body share specified staff within the previous three

years.

Rationale for Section 95979(b)(1).

This provision is necessary because in order to provide an impartial and 

independent verification statement, it is necessary to avoid any relationships 

between parties that may be perceived as a conflict. If specified staff is shared 

between these parties, it would be perceived as a conflict of interest and would 

jeopardize the integrity of the program. Only verification bodies that are truly 

independent and can provide an objective opinion on the report may provide 

Offset Verification Services.

Summary of Section 95979(b)(2)(A) through (b)(2)(T).

Subsections (b)(2)(A) through (b)(2)(T) specify that a high conflict exists where 

the verification body staff has provided any of the listed non-verification services, 

including developing a GHG inventory, providing appraisal services, and 

providing any legal services.

Rationale for Section 95979(b)(2)(A) through (b)(2)(T).

These provisions are needed because in order for the verification body to remain 

independent and objective when providing Offset Verification Services, it is 

necessary to specify some services that are not allowed to have been provided 

during the past three years to the Offset Project Operator. These services are so 
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closely related to the type of work done during GHG verification that they must be 

considered a high risk for a conflict and potential for bias in review. Any staff that 

has provided any listed service means the verification body is not eligible to 

provide Offset Verification Services under this regulation until three years have

passed from the date of those previous services.

Summary of Section 95979(b)(3).

Subsection (b)(3) specifies that any incentive provided to the Offset Project 

Operator by the verification body in order to provide verification services is a high 

conflict.Rationale for Section 95979(b)(3).

This provision is necessary because providing an incentive to the verifier would 

bias the verifier in the Offset Project Operator’s favor.

Summary of Section 95979(b)(4).

Subsection (b)(4) states that any Offset Verification Services provided in the past 

three years to the Offset Project Operator, except for Offset Verification Services,

as allowed for six years, is a high conflict of interest.

Rationale for Section 95979(b)(4).

Subsection (b)(4) is necessary to prevent complacency or bias in review. This 

section limits verifiers who have done these Offset Verification Services in the 

last three years from providing Offset Verification Services unless those services 

were provided as part of the allowed six years.

Summary of Section 95979(c).

Subsection (c) specifies that conflict of interest is low where no business 

relationship exists, or the services provided in the past three years were valued 

less than 20 percent of the fee for the proposed verification.

Rationale for Section 95979(c).

This provision is necessary because ARB has determined that some existing 

business relationships are acceptable if the dollar amount is small relative to the 

fee expected to be paid for verification. If the fee for verification is low relative to 

the consulting services, there may be an incentive to provide a positive or 

qualified positive offset verification statement in order to continue to be paid for 

other non-verification services. Having a dollar threshold allows the Offset 

Project Operator and verification body to determine if an existing business 

relationship is acceptable for future verification work.

Summary of Section 95979(d).
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Subsection (d) specifies that a conflict is medium if the conflict is not high or low. 

The verification body would need to submit a mitigation plan to remove any 

conflicts, if possible, or if there are any personal or familiar relationships between 

the verification body and Offset Project Operator.

Rationale for Section 95979(d).

This provision is needed because ARB understands that some relationships may 

have existed between a verification body and an Offset Project Operator. If that 

relationship does not include any of the situations that constitute a high conflict of 

interest, then the verification body is afforded an opportunity to mitigate any other 

conflicts.

Summary of Section 95979(e).

Subsection (e) specifies requirements for submittal of information about potential 

conflicts of interest between the verification body and the Offset Project Operator. 

This information includes whether the conflict is high, medium, or low; whether 

any member of the verification team has provided any services to the Offset 

Project Operator in the past three years; and an attestation that the submitted 

information is accurate and complete.

Rationale for Section 95979(e).

This provision is necessary because the conflict-of-interest submittal allows the 

verification body to demonstrate that it has evaluated that potential for conflict of 

interest according to the regulation and certifies to the nature of any existing 

relationship under penalty of perjury. 

Summary of Section 95979(f)(1).

Subsection (f)(1) requires the verification body to monitor and disclose conflicts 

of interest after commencement of verification services for an Offset Project 

Operator. The disclosure must also present details about the conflict of interest 

and how the verification body will mitigate or neutralize the potential for conflict of 

interest.

Rationale for Section 95979(f)(1).

This provision is necessary so that a verification body is diligent and careful not 

to engage in any activities beyond GHG verification that could be perceived as a 

potential conflict of interest. This is important to the integrity of the program. 

Summary of Section 95979(f)(2).

Subsection (f)(2) requires the verification body to monitor for conflicts of interest 

for up to one year after the completion of verification services. The verification 

body must disclose to ARB within 30 days once it enters into another contract for 
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non-verification services with the Offset Project Operator. ARB or an OPR will 

make a decision as to whether the conflict of interest is high and jeopardizes the 

Offset Verification Statement and the accreditation of the verification body.

Rationale for Section 95979(f)(2).

This provision is necessary to maintain the integrity of the program and ensure 

there is no bias by the verification body by the promise of future work for the 

Offset Project Operator.

Summary of Section 95979(f)(3).

Subsection (f)(3) requires the verification body to disclose any emerging conflicts 

of interest that may become apparent during the course of verification services.

If the conflict is determined to be high, the verification body will not be allowed to 

continue providing the verification services.

Rationale for Section 95979(f)(3).

This section is necessary to maintain the integrity of the program and ensure that 

even during the course of verification services, the verification body does not do 

anything that would be perceived as a conflict of interest under the regulation. 

Summary of Section 95979(f)(4).

Subsection (f)(4) requires the verification body to notify ARB of any changes to 

their business structure within one year of providing Offset Verification Services.

Rationale for Section 95979(f)(4).

This provision is necessary because ARB must ensure that a financial 

arrangement or promise of financial arrangement is not made between the 

verification body and the Offset Project Operator in order to win a positive offset 

verification statement. ARB must be notified if any changes to the verification

body, such as mergers or acquisitions, are made; especially any that involve the 

Offset Project Operator.

Summary of Section 95979(f)(5).

Subsection (f)(5) allows ARB to rescind an Offset Verification Statement and 

provides 90 days for an Offset Project Operator to hire another verification body if 

the first verification body violates the conflict-of-interest requirements.

Rationale for Section 95979(f)(5).

This provision is necessary because if a verification body violates the conflict-ofinterest requirements, it is necessary to provide the Offset Project Operator with 

additional time in which to hire another verification body. A violation of the 
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conflict of interest means the Offset Verification Statement may not have been 

objective and a new Offset Verification Statement must be submitted by a 

different verification body.

Summary of Section 95979(f)(6).

Subsection (f)(6) allows ARB to rescind the accreditation of the verification body 

or verifiers if they violate the conflict-of-interest requirements.

Rationale for Section 95979(f)(6).

This provision is necessary because the penalty for violating the conflict-ofinterest requirements must be specified so that all parties understand what the 

consequences of providing services to an Offset Project Operator are when a 

previous relationship with an Offset Project Operator is not disclosed to ARB. 

Rescinding the accreditation of a verification body means that company would no 

longer be allowed to verify data in ARB’s cap-and-trade program.

Section 95980. Issuance of Offset Credits.

Summary of Section 95980(a).

Subsection (a) proposes the requirements that GHG emissions reductions or 

GHG removal enhancements must meet to be issued offsets. This section also 

proposes that an offset credit is equal to one metric ton of CO2e and that the 

GHG emissions reductions or GHG removal enhancements must occur at the 

location where the reduction activity is implemented (direct). 

Rationale for Section 95980(a).

This provision is necessary to ensure that all offset credits issued under ARB 

protocols meet the same requirements. An offset credit should be equal to one 

metric ton of CO2e, so that it is equivalent to an allowance. Direct GHG 

emissions reductions or direct GHG removal enhancements are the simplest and 

most straightforward to incorporate into an offset project because they occur onsite and can therefore, be easily verified. Crediting direct reductions that occur 

on-site also makes ownership of offset credits that result from an offset project 

clearer, and the risk of double-counting is reduced.

Summary of Section 95980(a)(1).

Subsection (a)(1) proposes that an offset credit may only be issued to an offset 

project that has been listed with ARB or an OPR.

Rationale for Section 95980(a)(1).

This provision is necessary to ensure that ARB or an OPR has all the relevant 

information regarding an offset project, that information regarding the offset 
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project has been made publicly available, and that ARB has a legal and 

enforcement connection to those involved with offset projects.

Summary of Section 95980(a)(2).

Subsection (a)(2) proposes that offset credits may only be issued if the offset 

project was issued a positive offset or qualified positive offset verification 

statement by an ARB-accredited offset verifier.

Rationale for Section 95980(a)(2).

This provision is necessary to ensure that GHG emissions reductions or GHG 

removal enhancements are qualified by an ARB-accredited third-party verifier. 

Having an accredited verifier issue a positive offset or qualified positive offset 

verification statement ensures confidence in the verification by the public, ARB,

and an OPR.

Summary of Section 95980(a)(3).

Subsection (a)(3) proposes that offset credits may only be issued if an ARBaccredited offset verifier has submitted a positive offset or qualified positive offset 

verification statement to ARB, or an OPR and has been attested to by an ARBaccredited offset verifier.

Rationale for Section 95980(a)(3).

ARB or an OPR must receive the positive offset or qualified positive offset 

verification statement and review it to determine if offset credits should be issued. 

Summary of Section 95980(b), Determination for Timing and Duration of Initial 

Crediting Periods.

Subsection (b) proposes that an offset project’s initial crediting period will begin 

on the date that its first offset verification statement says that GHG emission 

reductions or GHG removal enhancements actually occurred.

Rationale for Section 95980(b).

This provision is necessary to establish when the offset project’s initial crediting 

period begins. This timing is appropriate because it sometimes takes a while for 

the offset project to be fully implemented and the crediting period should reflect 

the timeframe that the project reduces GHG emissions or stores GHGs.

Summary of Section 95980(c), Determination for Timing and Duration of 

Renewed Crediting Periods.
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Subsection (c) proposes that an offset project’s renewed crediting period will 

begin on the date following the conclusion of the offset project’s initial crediting 

period or previously renewed crediting period.

Rationale for Section 95980(c).

This provision is necessary to establish when the offset project’s renewed 

crediting period begins. This timing is appropriate because, unlike the initial 

crediting period, the project should already be implemented at the time it renews 

its crediting period. 

Section 95981. Process for Issuance of Offset Credits.

Summary of Section 95981(a).

Subsection (a) proposes the timing for offset credits being issued by ARB or an 

OPR. Offset credits will be issued by ARB or an OPR within 45 days of receiving 

a positive offset or qualified positive offset verification statement.

Rationale for Section 95981(a).

This provision is necessary so the party identified to receive offset credits knows 

when they will receive them. 45 days will give staff enough time to review the 

offset verification statements and contact the offset verifier if there are any 

questions regarding the statement.

Summary of Section 9598(b), Change of Listing Status.

Subsection (b) proposes that once offset credits have been issued by ARB or an 

OPR to an offset project, the listing status of the offset project will be changed to 

either an “Active Project” or “Active Renewal.”

Rationale for Section 95981(b).

This provision is necessary for transparency purposes, so the public knows 

whether or not an offset project has been issued offset credits. This information 

will be available on a public website, and the number of offset credits issued to 

the offset project for each offset verification statement will also be made available.

Summary of Section 95981(c), Notice of Determination of Issuance of Offset 

Credits.

Subsection (c) proposes that ARB or an OPR will notify the party identified to 

receive offset credits, within15 days of issuance, that the credits have been 

issued.

Rationale for Section 95981(c).
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This provision is necessary so that the party identified to receive offset credits 

knows that ARB or an OPR has issued them. The 15-day timeframe is designed

to allow staff to prepare the necessary notification and, if applicable, any 

documentation to send to the recipient of the offset credits.

Summary of Section 95981(d), Requirements for Offset Projects Submitted 

Through an Offset Project Registry Seeking Issuance of ARB Offset Credits.

Subsection (d) proposes requirements for offset projects whose documentation 

was submitted through an OPR, if the party responsible for the offset project is 

seeking offset credits issued by ARB.

Rationale for Section 95981(d).

This provision is necessary because an offset credit must ultimately be issued by 

ARB to be used for compliance under this article.

Summary of Section 95981(d)(1).

Subsection (d)(1) proposes the information that the party responsible for the 

offset project must submit to be issued offset credits by ARB.

Rationale for Section 95981(d)(1).

This provision is necessary because ARB must obtain all information submitted 

to an OPR for the offset project including: listing, monitoring, reporting, and 

verification information, to issue an offset credit. The attestations must also be 

made available to ARB so that it can enforce against those responsible for offset 

projects, if necessary.

Summary of Section 95981(d)(2).

Subsection (d)(2) proposes that the verification body that submitted offset

verification statements to an OPR must attest to ARB the truthfulness and 

accuracy of its findings.

Rationale for Section 95981(d)(2).

This provision is necessary so that ARB can enforce against the verification 

bodies and verifiers that provided verification services to an offset project through 

an OPR.

Summary of Section 95981(d)(3).

Subsection (d)(3) proposes that ARB will notify the party responsible for the 

offset project within 30 days, whether the information they submitted is complete, 

and if not, what is deficient.
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Rationale for Section 95981(d)(3).

This provision is necessary so that the party responsible for the offset project 

knows if the information they submitted is complete, and if not, what additional 

information they must submit. The 30-day timeframe is designed to allow staff 

adequate time to review the material submitted for issuance of ARB offsets.

Summary of Section 95981(d)(4).

Subsection (d)(4) proposes that ARB will issue offset credits within 30 days of 

determining that the information submitted for issuance of ARB offsets is 

complete.

Rationale for Section 95981(d)(4).

This provision is necessary so that the parties involved in the offset project know 

that ARB has issued offsets. The 30-day timeframe is designed to allow staff to

prepare the necessary notification and, if applicable, any documentation to send 

to those involved in the offset project.

Summary of Section 95981(d)(5).

Subsection (d)(5) proposes that ARB may request additional information for 

issuance of ARB offsets, as needed, before issuing offset credits.

Rationale for Section 95981(d)(5).

This provision allows those responsible for the offset project, or those that 

verified the project, to provide any additional information that ARB deems 

necessary to the issuance of ARB offsets.

Summary of Section 95981(d)(6).

Subsection (d)(6) proposes that ARB may deny issuance of ARB offset credits. 

The party responsible for the offset project may petition to be allowed to resubmit 

its information and respond to any issues that prevented ARB from issuing offset

credits.

Rationale for Section 95981(d)(6).

This provision is necessary to allow ARB to deny issuance of ARB offsets if the 

information submitted is insufficient to warrant issuance. It is also necessary to 

give the party responsible for an offset project one last opportunity to show it 

qualifies to be issued ARB offset credits.

Summary of Section 95981(e).
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Subsection (e) proposes that any offset credits issued by an OPR must be retired 

in its registry system before ARB can register the offset credits in its tracking

system.

Rationale for Section 95981(e).

This provision is necessary to avoid double-counting of offset credits in multiple 

systems, and to ensure that the same offset credits cannot be bought, sold, or 

retired if they have already been used.

Summary of Section 95981(f), Receipt of Offset Credits Issued by ARB.

Subsection (f) proposes that ARB offset credits will be registered to the party 

identified to receive offset credits within 15 days of notification.

Rationale for Section 95981(f).

This provision is necessary to ensure that the party identified to receive offset 

credits knows they have been deposited into their account. The 15-day 

timeframe is designed to allow ARB time to transfer the offset credits to the 

correct party and process the transactions in the tracking system correctly.

Section 95982. Registration of Offset Credits Issued by ARB.

Summary of Section 95982.

This section proposes that offset credits issued by ARB must be registered in 

ARB’s tracking system.

Rationale for Section 95982.

This section is necessary for ARB to track offset credits it issues, as well as

owners of offset credits at all times.

Summary of Section 95982(a).

Subsection (a) proposes that each offset credit be given a unique serial number.

Rationale for Section 95982(a).

This section is necessary so that each offset credit cannot be used more than 

once and ARB is able to track who owns each offset at all times.

Summary of Section 95982(b).

Subsection (b) proposes that ARB offset credits will be transferred to the account 

of the party identified to receive offset credits.

Rationale for Section 95982(b).
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This provision is necessary to ensure that the party identified to receive offset 

credits knows they have been deposited into their account. 

Section 95983. Offset Reversals.

Summary of Section 95983(a).

Subsection (a) proposes that a portion of offset credits issued to forestry projects 

developed under the U.S. Forest Projects Protocol must be placed into the 

Forest Buffer Account. If the offset project originated with an OPR, these offset 

credits must be transferred to ARB.

Rationale for Section 95983(a).

This provision is necessary to develop an ARB insurance mechanism that can be 

used to protect against unintentional reversals that may occur in forest projects.

Summary of Section 95983(a)(1).

Subsection (a)(1) proposes that the amount of offset credits that must be placed 

into the Forest Buffer Account is specified in the U.S. Forest Projects Protocol,

incorporated by reference.

Rationale for Section 95983(a)(1).

This provision is necessary to determine how many offset credits must be placed 

into the Forest Buffer Account. This amount is based on a number of default and 

calculated factors that differ depending on the individual project. The factors and 

equations that must be used to determine each project’s reversal risk rating are 

provided in the U.S. Forest Projects Protocol.

Summary of Section 95983(a)(2).

Subsection (a)(2) proposes that offset credits be placed into the Forest Buffer 

Account at the time offset credits are registered.

Rationale for Section 95983(a)(2).

This provision is necessary to ensure offset credits are immediately placed into 

the Forest Buffer Account, as opposed to the account of the party identified to 

receive offset credits.

Summary of Section 95983(a)(3).

Subsection (a)(3) proposes that all offset credits initially held by an OPR for 

unintentional reversals be transferred to ARB’s Forest Buffer Account, and then 

retired in its own registry system.

Rationale for Section 95983(a)(3).
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This provision is necessary to ensure that the size of the Forest Buffer Account is 

adequate enough to cover a large loss of stored carbon in the forest sector. If 

each OPR maintains its own buffer account and does not transfer the offset 

credits to ARB there may not be enough offset credits in the Forest Buffer 

Account if a large loss occurs. 

Summary of Section 95983(b), Unintentional Reversals.

Subsection (b) proposes that the party responsible for an offset project must 

notify ARB within six months when an unintentional reversal is discovered.

Rationale for Section 95983(b).

This provision is necessary so that ARB is informed that an unintentional reversal 

occurred.

Summary of Section 95983(b)(1).

Subsection (b)(1) proposes the information that a party responsible for a forest 

offset project must submit to ARB in the event of an unintentional reversal.

Rationale for Section 95983(b)(1).

This provision is necessary so that ARB can assess why a reversal occurred, 

whether it was unintentional, and how many metric tons of GHGs were reversed.

Summary of Section 95983(b)(1)(A).

Subsection (b)(1)(A) proposes that a party responsible for a forest offset project 

must explain to ARB the nature of the unintentional reversal.

Rationale for Section 95983(b)(1)(A).

This provision is necessary so that ARB can assess why a reversal occurred to 

determine if it was unintentional.

Summary of Section 95983(b)(1)(B).

Subsection (b)(1)(B) proposes that a party responsible for a forest offset project 

must verify the level of carbon stored in its forest within a year of when the 

unintentional reversal was discovered.

Rationale for Section 95983(b)(1)(B).

This provision is necessary so that ARB can determine how many metric tons of 

GHGs were reversed.

Summary of Section 95983(b)(2).
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Subsection (b)(2) proposes that ARB will retire offset credits from the Forest 

Buffer Account in the amount of the reversal.

Rationale for Section 95983(b)(2).

This provision is necessary to ensure the permanence of offset credits issued for 

stored carbon. If credited GHGs have been released back into the atmosphere,

an equivalent amount of offset credits must be retired to replace it. If it is not 

replaced by another offset or an allowance, there is a net increase of GHGs in 

the atmosphere.

Summary of Section 95983(c), Intentional Reversals.

Subsection (c) proposes the requirements for the parties responsible for the 

forest offset projects in the event of an intentional reversal.

Rationale for Section 95983(c).

This provision is necessary to establish the requirements for intentional reversals.

Summary of Section 95983(c)(1).

Subsection (c)(1) proposes that within 30 days of an intentional reversal, the 

party responsible for the project must give written notice to ARB of the 

occurrence. They must also explain and describe the nature of the intentional 

reversal.

Rationale for Section 95983(c)(1).

This provision is necessary for ARB to be notified that an intentional reversal 

occurred and evaluate the nature of the intentional reversal.

Summary of Section 95983(c)(2).

Subsection (c)(2) proposes that ARB will evaluate the information submitted to 

determine if an intentional reversal has occurred. If ARB determines that an 

intentional reversal has occurred, it will notify the party responsible for the offset 

project of its findings.

Rationale for Section 95983(c)(2).

This provision is necessary so that the party responsible for the offset project is 

informed of ARB’s determination that it believes an intentional reversal has

occurred.
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Summary of Section 95983(c)(3).

Subsection (c)(3) proposes that three months within receiving ARB’s notification 

pursuant to section 95983(c)(2), the party responsible for a forest offset project 

must verify the level of carbon stored in its forest.

Rationale for Section 95983(c)(3).

This provision is necessary so that ARB can determine how many metric tons of 

GHGs were reversed, and if necessary, take enforcement action.

Summary of Section 95983(d), Disposition of Forest Sequestration Projects After 

an Unintentional Reversal.

Subsection (d) proposes that if an unintentional reversal occurs, and its stored 

carbon levels are below its project baseline, the project will be automatically 

terminated.

Rationale for Section 95983(d).

This provision is necessary because the project baseline is no longer applicable 

and can no longer be used to determine project performance.

Summary of Section 95983(d)(1).

Subsection (d)(1) proposes that if an offset project has been terminated due to 

an unintentional reversal, the party responsible for the offset project may 

resubmit the offset project for listing.

Rationale for Section 95983(d)(1).

This provision is necessary to allow projects that suffer unintentional reversals 

the ability to submit a new project with a new revised baseline calculation. 

Summary of Section 95983(d)(2).

Subsection (d)(2) proposes that if an unintentional reversal occurs, and its stored 

carbon levels are above its project baseline, it may continue to operate as long 

as the number of released GHGs have been replaced with an equivalent amount 

of offset credits from the Forest Buffer Account. This subsection also proposes 

that the party responsible for the forest project must continue to contribute to the 

Forest Buffer Account in the future.

Rationale for Section 95983(d)(2).

This provision is necessary to allow a forest project that undergoes an 

unintentional reversal to continue generating offset credits utilizing the same 

baseline.
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Summary of Section 95983(e), Disposition of Forest Sequestration Projects After 

an Intentional Reversal.

Subsection (e) proposes what should happen to a forest offset project in the 

event on an intentional reversal.

Rationale for Section 95983(e).

This provision is necessary so that the party responsible for a forest offset project 

knows what will happen if there is an intentional reversal of a forest project.

Summary of Section 95983(e)(1).

Subsection (e)(1) proposes that if ARB determines an intentional reversal has 

occurred, the forest offset project will be automatically terminated.

Rationale for Section 95983(e)(1).

This provision is necessary to ensure the additionality of credited reductions. This 

provision prevents projects from intentionally reversing credited carbon stocks 

below allowable levels, and registering a new project that would yield credits from 

the intentionally reduced stocks.

Summary of Section 95983(e)(2).

Subsection (e)(2) proposes that if an intentional reversal has occurred, a new 

forest offset project may not be initiated within the same project boundary.

Rationale for Section 95983(e)(2).

This provision is necessary to ensure that, in the case of an intentional reversal, 

an amount of offset credits equivalent to the reversed carbon previously issued to 

the project is invalidated and replaced.

Summary of Section 95983(e)(3).

Subsection (e)(3) proposes that offset credits issued to a terminated forest offset 

project due to an intentional reversal may be invalidated pursuant to section 

95985.

Rationale for Section 95983(e)(3).

This provision is necessary because the stored carbon is no longer considered 

permanent in the event of a reversal. Offset projects may not draw from the 

Forest Buffer Account to replace offset credits for intentionally reversed forest 

projects. Pursuant to section 95985(e), in the event of an intentional reversal, 

the party responsible for the forest offset project must replace any lost metric 

tons with other approved offset credits or allowances.
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Section 95984. Ownership and Transferability of Offset Credits Issued by

ARB.

Summary of Section 95984.

Section 95984 proposes that initial ownership of offset credits will be with the 

party identified to receive offset credits. It also purposes that offset credits may 

be sold, traded, or transferred except in limited circumstances, as identified in 

this section.

Rationale for Section 95984.

This provision is necessary for those responsible for offset projects to know who 

receives ownership of offset credits and which transactions are allowed.

Summary of Section 95984(a).

Subsection (a) proposes that an offset credit that has been retired or surrendered 

in any program may not be sold, traded, or transferred.

Rationale for Section 95984(a).

This provision is necessary to avoid double-counting of offset credits.

Summary of Section 95984(b).

Subsection (b) proposes that offset credits in the forest buffer may not be sold, 

traded, or transferred.

Rationale for Section 95984(b).

This provision is necessary because offset credits in the Forest Buffer Account

may only be retired by ARB in the event of an unintentional reversal.

Summary of Section 95984(c).

Subsection (c) proposes that an offset credit that has been invalidated pursuant 

to section 95985 may not be sold, traded, or transferred.

Rationale for Section 95984(c).

This provision is necessary because once an offset credit is invalidated, ARB will 

cancel the offset credit in the tracking system, and it may no longer be sold, 

traded, or transferred.
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Section 95985. Invalidation of Offset Credits.

Summary of Section 95985(a).

Subsection (a) proposes the circumstances for offset credits to be considered 

valid.

Rationale for Section 95985(a).

This provision is necessary so that those developing offset projects or those 

purchasing offset credits know which offset credits are valid.

Summary of Section 95985(a)(1).

Subsection (a)(1) proposes that offset credits are considered valid and can be 

used for compliance unless they have been retired or used in any voluntary or 

regulatory program.

Rationale for Section 95985(a)(1).

This provision is necessary to avoid double-counting of offset credits in multiple 

systems, and to ensure that the same offset credits cannot be bought, sold, or 

retired if they have already been used.

Summary of Section 95985(a)(2).

Subsection (a)(2) proposes that offset credits are considered valid and can be 

used for compliance unless they have been invalidated under this section.

Rationale for Section 95985(a)(2).

This provision is necessary because once an offset credit is invalidated, ARB will 

cancel the offset credit in the tracking system, and it may no longer be sold, 

traded, or transferred.

Summary of Section 95985(b).

Subsection (b) proposes the circumstances for an offset credit to be invalidated.

Rationale for Section 95985(b).

This provision is necessary so those developing offset projects or those 

purchasing offset credits know which offset credits are valid. In the event of 

fraud or malfeasance on the part of project developers or verifiers, there may be 

cause to invalidate offset credits after they have been issued, to protect the 

environmental integrity of the program.
IX-163

Summary of Section 95985(b)(1).

Subsection (b)(1) proposes that an offset credit may be invalidated if a reversal 

occurred in a forest sequestration project.

Rationale for Section 95985(b)(1).

This provision is necessary because if a reversal occurs in a forest project, the 

offset credits are no longer permanent and, therefore, no longer meet the 

requirements of AB 32.

Summary of Section 95985(b)(2).

Subsection (b)(2) proposes that an offset credit may be invalidated if a deficiency 

or errors were found on behalf of the project developers or verifiers for an offset 

project. 

Rationale for Section 95985(b)(2).

This provision is necessary so those developing offset projects or those 

purchasing offset credits know which offset credits are valid. In the event of 

fraud or malfeasance of project developers or verifiers, there may be cause to 

invalidate offset credits after they have been issued, to protect the environmental 

integrity of the program.

Summary of Section 95985(c).

Subsection (c) proposes what will happen if an offset is determined to be invalid.

Rationale for Section 95985(c).

This provision is necessary so those that have used or are currently holding an 

invalid offset credit know the procedures for completing the invalidation process.

Summary of Section 95985(c)(1).

Subsection (c)(1) proposes that an invalid offset will be cancelled or removed 

from any Compliance or Holding Accounts, as well as the Forest Buffer Account.

Rationale for Section 95985(c)(1).

This provision is necessary so those that are currently holding or attempting to 

comply with an invalid offset credit know the procedures for completing the 

invalidation process.

Summary of Section 95985(c)(2).

Subsection (c)(2) proposes that the current holder or the entity that retired the 

offset credit will be notified.
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Rationale for Section 95985(c)(2).

This provision is necessary so that participants know if an offset they currently 

hold or have used is invalidated.

Summary of Section 95985(c)(3).

Subsection (c)(3) proposes that ARB will notify any linked program if any offset 

credits are invalidated.

Rationale for Section 95985(c)(3).

This provision is necessary so that the linked program can remove the offset 

credits from within their own tracking system, and they do not allow it to be used 

for compliance in their programs.

Summary of Section 95985(d).

Subsection (d) proposes that if an offset credit is invalidated after it has been 

used or retired, for any reason except a reversal in the forest sector; the party 

that retired or used the offset credit must replace it to ARB within 30 days. If the 

user or retiree is no longer in business, ARB will notify the developer of the offset 

project that they must replace the offset credits within 30 days. If they do not 

replace it within that time frame, each offset credit constitutes a violation.

Rationale for Section 95985(d).

This provision is necessary to ensure that purchasers and users of offset credits 

do their due diligence in seeking out high-quality offset credits. Also, ARB has 

clear enforcement authority over covered entities that will be using ARB offsets 

for compliance. 

Summary of Section 95985(e).

Subsection (e) proposes that if an offset credit is invalidated due to an intentional 

reversal in the forest sector, the party responsible for the offset project must 

replace the offset credits that are reversed. 

Rationale for Section 95985(e).

This provision is necessary because those with an interest in the land must 

ensure permanence. If the forest owner is not the one to replace the offset 

credits in this case, they have no incentive to uphold their obligations to ensure 

permanence.
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Summary of Section 95985(f).

Subsection (f) proposes that if an offset credit is invalidated due to an 

unintentional reversal the offset credits will be retired from the Forest Buffer 

Account.

Rationale for Section 95985(f).

This provision is necessary because ARB’s Forest Buffer Account is intended to 

act as an insurance mechanism that can be used to protect against unintentional 

reversals that may occur in forest projects.

Section 95986. Executive Officer Approval Requirements for Offset Project 

Registries.

Summary of Section 95986.

This section provides requirements that must be met and demonstrated by an 

Offset Project Registry that wishes to be approved by the Executive Officer to 

provide registry services for projects developed using ARB compliance offset 

protocols.

Rationale for Section 95986.

This section is necessary to have some basic requirements for all registries that 

wish to be approved as an Offset Project Registry, to ensure quality and stability 

in this role.

Summary of Sections 95986(a) through (c).

Subsections (a) through (c) require an Offset Project Registry to provide 

information about its organization, demonstration of $50 million of liability 

insurance, and demonstration of a rigorous internal conflict-of-interest policy and 

mechanisms to disclose and prevent conflicts of interest. 

Rationale for Sections 95986(a) through (c).

These provisions are necessary because beyond the basic information about the 

management of the Offset Project Registry, it is important for the registry to carry 

insurance to provide a way to compensate operators if, for some reason, the 

registry fails to provide quality or accurate registry services and the result is a 

loss of potential compliance credits for the operator. This level of insurance is 

based on expected volumes of potential compliance offsets and potential 

monetary value of those offsets the registry may reasonably oversee. It is 

important that all members of an approved Offset Project Registry remain 

impartial as they provide services to operators when those services potentially 

will generate offsets that count in a compliance program.
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Summary of Section 95986(d).

Subsection (d) limits any other roles an Offset Project Registry can fill while it is 

providing registry services.

Rationale for Section 95986(d).

This provision is necessary because as an Offset Project Registry, the 

organization must take a step back from any other roles that could lead to a 

perceived or actual conflict of interest in the process of generating potential 

compliance offsets. This provision will add integrity to the program and remove 

the threat of self-interest in the process by the registry.

Summary of Sections 95986(e) through (f).

Subsections (e) through (f) ensure that the requirements that must be 

demonstrated at the time of approval are always met during any time the 

approved Offset Project Registry is providing registry services under the 

regulation.

Rationale for Sections 95986(e) through (f).

These provisions are necessary for the stability of the program. It is imperative 

that once an Offset Project Registry demonstrates that it meets the regulation’s 

standards, it maintains those standards from that point forward while providing 

registry services.

Summary for Section 95986(g).

Subsection (g) requires attestations statements to hold the Offset Project 

Registry accountable to ARB for information that it submits to ARB and 

acknowledgement that the registry is voluntarily choosing to become part of a 

regulatory program, and as such is subject to all enforcement mechanisms of the 

program and that any information provided to ARB will be accurate and complete. 

Rationale for Section 95986(g).

This provision is necessary because all parties that are part of the compliance 

program must be held accountable for their actions, registry services, and 

information submittals for the integrity of the program.

Summary for Section 95986(h).

Subsection (h) requires management staff for an OPR to take ARB training on 

the ARB program.
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Rationale for Section 95986(h).

This provision is necessary because it is important to the integrity of the 

compliance program that any approved registry understand the requirements of 

the regulatory program and be able to communicate those requirements to 

operators that use their registry services.

Summary of Section 95986(i).

Subsection (i) lays out the process for actual approval for an Offset Project 

Registry once all of the requirements have been met. The approval is valid for 

five years and may be renewed if the registry has not been subject to 

enforcement and still meets all of the requirements.

Rationale for Section 95986(i).

This provision is necessary to limit the approval to five years, which allows ARB 

to periodically ensure that all requirements for registry approval are met and 

ensure the quality of registries by not allowing any registries that have been 

subject to enforcement to be eligible to be renewed for approval by ARB. 

Summary of Section 95986(j).

Subsection (j) provides a process for modifying, suspending, or revoking the 

approval of an Offset Project Registry for good cause. It also stipulates that the 

OPR must not provide registry services during an approval revocation and must 

notify all operators of its status.

Rationale for Section 95986(j).

This provision is necessary so that the registry is afforded due process under 

California statute before ARB revokes its approval. Operators must be given 

notice by the registry if it can no longer provide registry services, so they may 

transfer to another registry or to ARB.

Section 95987. Offset Project Registry Requirements.

Summary of Section 95987.

This section provides the registry services an approved Offset Project Registry 

must provide for operators and information it must provide to ARB under the 

regulation.

Rationale for Section 95987.

The regulation provides standardized services so that every registry will provide 

the same level of service and information related to the generation of potential 
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offset credits. The information requirements will be used by ARB as oversight of 

its compliance offset program and approved OPRs.

Summary of Section 95987(a).

Subsection (a) stipulates that only ARB Board-approved protocols can be used to 

generate offsets for potential ARB issuance.

Rationale for Section 95987(a).

This provision is necessary because AB 32 is clear that the Board must approve 

all offset protocols.

Summary for Section 95987(b).

Subsection (b) stipulates what information related to project listing and reporting 

the registry has to make available to the public in a timely manner.

Rationale of Section 95987(b).

This provision ensures that all registries provide information in a transparent 

manner for each offset project with the potential for ARB to issue credits.

Summary of Section 95987(c).

Subsection (c) requires the OPR to use the conflict-of-interest requirements in 

the regulation to make a determination about the level of conflict between a 

verification body and the Offset Project Operator. This section also requires the 

OPR to ensure the information on the conflict-of-interest form is complete.

Rationale for Section 95987(c).

This provision is necessary to ensure that all OPRs apply the regulatory conflictof-interest requirements and review each form for completeness. This ensures 

program integrity and consistency.

Summary of Section 95987(d).

Subsection (d) allows an OPR to provide guidance on questions or issues related

to compliance offset protocols if there is no clear direction on that issue. The 

registry must inform ARB of any guidance it provides on a Compliance Offset 

Protocol.

Rationale for Section 95987(d).

This provision is necessary because there may be a circumstance where an 

operator or verifier may not know how to apply the requirements of a Compliance 

Offset Protocol, and this allows the OPR to provide such guidance and inform 

ARB in a timely manner. ARB can track such inquiries and decide if such issues 
IX-169

need to be addressed in an update to the protocol, of it the registry has provided 

guidance that is in conflict of the regulatory offset program and the operator 

should be notified quickly to avoid losing any potential offset credits.

Summary of Section 95987(e).

Subsection (e) requires approved registries to have in place an audit program of 

their projects and verifications that includes specific tasks that must be 

conducted in the audits, and they must provide that information to ARB.

Rationale for Section 95987(e).

This provision is necessary because it is important for all registries to have some 

oversight of their own program as they provide registry services, to ensure 

integrity and quality at each step. This information will also be provided to ARB to 

inform ARB staff, to support their efforts to oversee the regulatory verification 

program.

Summary of Section 95987(f).

Subsection (f) requires that an OPR provide all information related to an offset 

project, if requested by ARB.

Rationale for Section 95987(f).

This provision is necessary because ARB may need such information to audit a 

project or as part of its registry audit, conducted as part of its compliance offset 

program oversight.

Summary of Section 95987(g).

Subsection (g) requires an OPR to make all of its information and staff available 

to ARB for audit.

Rationale for Section 95987(g).

This provision is necessary because the OPRs are participating in a compliance 

program. ARB must have complete authority to oversee all facets of the program, 

including the OPRs. This access enables ARB to gather information or talk to 

staff as part of the OPR oversight.

Summary of Section 95987(h).

Subsection (h) requires the OPR to retire any credits in its system that will be 

issued offset credit in ARB’s compliance offset program.
IX-170

Rationale for Section 95987(h).

This provision is necessary because an offset credit may only be used once. This 

requirement ensures that someone is not able to have an offset credit doublecounted in any program once ARB decides to issue an offset credit for use in its 

regulatory program.

Summary of Section 95987(i).

Subsection (i) requires an OPR to provide annual information to ARB related to 

any offset projects that are at least listed for the previous year using a 

Compliance Offset Protocol.

Rationale for Section 95987(i).

This provision is necessary so that ARB can monitor the performance of its offset 

program. It also allows ARB to understand and respond to any unintended or 

unexpected issues that may occur during the implementation of the compliance 

offset program.

Section 95988. Record Retention Requirements for Offset Project 

Registries.

Summary of Section 95988.

This section requires registries to retain specific documentation for at least the 

project lifetime plus ten years for projects that are listed at an OPR and 

eventually receive ARB-issued credit.

Rationale for Section 95988.

This provision is necessary because as with all participants in the cap-and-trade 

program, the registry must maintain a rigorous record retention program to 

support any regulatory inquiries about a project or verification that was conducted 

through the registry.

Subarticle 14. Recognition of Compliance Instruments from Other 

Programs.

Section 95990. Recognition of Offset Credits for Early Action.

Summary of Section 95990(a).

Subsection (a) proposes that ARB recognizes early action offset credits issued 

by third-party programs approved pursuant to this section, if the offset credits 

meet the requirements of this section.
IX-171

Rationale for Section 95990(a).

This section is necessary to establish that early action offset credits must meet 

specific criteria. This ensures that early action offset credits are subjected to 

uniform standards.

Summary of Section 95990(b), Criteria for Approval of Offset Credits Issued by 

Third Parties.

Subsection (b) proposes the criteria that offsets issued by third-party programs 

must meet to be recognized for compliance.

Rationale for Section 95990(b).

This section is necessary to ensure that all early action offset credits issued by 

third-party programs meet the same standards.

Summary of Section 95990(b)(1).

Subsection (b)(1) proposes that the GHG reductions or GHG removal 

enhancements credited as offsets by third-party programs must occur between 

January 1, 2005, and December 31, 2014.

Rationale for Section 95990(b)(1).

This provision is necessary so those using offsets for compliance know which 

early action offset credits are eligible to be used for compliance. The date 

January 1, 2005, reflects the date that offset projects began verifying their GHG 

reductions and GHG removal enhancements, based on the protocols approved in 

this section for recognizing early action. The date December 31, 2014, reflects 

the date that the first compliance period ends. Staff proposes this cut-off date to 

ensure that offset projects switch to a Board-approved protocol, while still 

allowing a supply of offset credits to come in during the first compliance period. 

Summary of Section 95990(b)(2).

Subsection (b)(2) proposes that offsets issued by third-party programs must be 

verified according to the requirements in section 95990(f).

Rationale for Section 95990(b)(2).

This provision is necessary to ensure that early action offset credits issued by 

third-party programs meet the same requirements for verification as offset credits 

issued by ARB.
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Summary of Section 95990(b)(3).

Subsection (b)(3) proposes that qualified early action offset credits must originate 

from offset projects that commence prior to January 1, 2012.

Rationale for Section 95990(b)(3).

This provision is necessary so those using offsets for compliance know which 

early action offset credits are eligible to be used for compliance. This also

ensures that once ARB’s compliance offset program is implemented in 2012, that 

offset projects are using ARB Board-approved protocols, as opposed to those 

approved in this section for early action purposes.

Summary of Section 95990(b)(4).

Subsection (b)(4) proposes that qualified early action offset credits must originate 

from offset projects that are located in the United States.

Rationale for Section 95990(b)(4).

This provision is necessary so those using offsets for compliance know which 

early action offset credits are eligible to be used for compliance. Up to this point, 

staff has only evaluated protocols based on applicability in the United States.

Summary of Section 95990(b)(5)(A) through (b)(5)(D).

Subsections (b)(5)(A) through (b)(5)(D) propose which offset protocols are 

eligible to be used for the recognition of early action offset credits. 

Rationale for Section 95990(b)(5)(A) through (b)(5)(D).

These provisions are necessary so that those using offsets for compliance know 

which early action offset credits are eligible to be used for compliance. Staff 

chooses these particular protocols because they are the same types of offset 

projects that staff is proposing that the Board adopt as ARB compliance offset 

protocols. Staff has knowledge of these project types and has also based the 

development of its proposed compliance protocols on these early versions.

Summary of Section 95990(b)(5)(E).

Subsection (b)(5)(E) proposes that offset projects using Climate Action Reserve 

Forestry Protocol versions 3.0 through 3.2 meet specific requirements for 

permanence, including: a conservation easement or contribution to a forest buffer 

pool.
IX-173

Rationale for Section 95990(b)(5)(E).

This provision is necessary to ensure that early action offset credits meet the 

same requirements for permanence as offset credits issued by ARB.

Summary of Section 95990(c), Approval of Third-Party Offset Programs for 

Purposes of Accepting Offset Credits for Early Action.

Subsection (c) proposes the requirements that a third-party offset program must 

meet for offset credits it issues to be used for early action.

Rationale for Section 95990(c).

This provision is necessary to ensure that all third-party offset programs meet the 

same requirements for offset credits as those that they issue to be used for early 

action. The third-party offset program must meet the requirements of this section 

or have an Executive Order issued pursuant to section 95986(d).

Summary of Section 95990(c)(1).

Subsection (c)(1) proposes that a third-party offset program must carry at least 

two million dollars of liability insurance.

Rationale for Section 95990(c)(1).

This provision is necessary to ensure that the third-party offset program has 

insurance to provide a way for compensation to project developers if, for some 

reason, the third-party program fails to provide quality or accurate services and 

the result is a loss of potential compliance credits for the project developer. The 

amount of insurance differs for these program in comparison to those for OPRs 

because the volume of early action offset credits is significantly lower than that 

which can be issued by an OPR under a Compliance Offset Protocol.

Summary of Section 95990(c)(2).

Subsection (c)(2) proposes that the third-party offset program has specific 

registration and tracking abilities for offset credits, as well as entities who are 

registered in its system.

Rationale for Section 95990(c)(2).

This provision is necessary to ensure that the third-party offset program can 

locate an offset credit or its owner at any given time within its registry system. 

Summary of Section 95990(c)(3).

Subsection (c)(3) proposes that the third-party offset program’s primary business 

be operating a voluntary or regulatory offset program.
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Rationale for Section 95990(c)(3).

This provision is necessary to prevent conflict of interest.

Summary of Section 95990(c)(4).

Subsection (c)(4) proposes that the third-party offset program must submit to 

ARB any documentation that an offset project using a protocol approved for early 

action submits to the third-party program.

Rationale for Section 95990(c)(4).

This provision is necessary so that ARB has all information regarding offset 

projects from which offset credits are used for compliance under the program.

Summary of Section 95990(c)(5).

Subsection (c)(5) proposes that the third-party offset program must retire offset 

credits in its registry system before ARB can register the offset credits in its 

tracking system and allow them to be used for compliance.

Rationale for Section 95990(c)(5).

This provision is necessary to avoid double-counting of offset credits in multiple 

systems, and to ensure that the same offset credits cannot be bought, sold, or 

retired if they have already been used.

Summary of Section 95990(c)(6).

Subsection (c)(6) proposes that a representative of the third-party offset program 

must attest to ARB that they meet the requirements of this section, and that

everything they submit is truthful and accurate.

Rationale for Section 95990(c)(6).

This provision is necessary to ensure that the third-party offset program follows 

the requirements of this regulation and that ARB can take enforcement against 

them if necessary.

Summary of Section 95990(d), Registration of Offset Credits Issued by Third 

Parties.

Subsection (d) proposes that any offset credits issued by a third-party offset 

program must be retired in its registry system before ARB can register the offset 

credits in its tracking system.
IX-175

Rationale for Section 95990(d).

This provision is necessary to avoid double-counting of offset credits in multiple 

systems, and to ensure that the same offset credits cannot be bought, sold, or 

retired if they have already been used.

Summary of Section 95990(e), Ineligible Offset Credits Issued by Third Parties

Subsection (e) proposes that if an offset credit issued by a third-party offset 

program has been cancelled, used or, retired, it is no longer eligible to be 

recognized by ARB.

Rationale for Section 95990(e).

An offset credit may only be used once. This requirement ensures that someone 

is not able to have an offset credit double-counted in any program once ARB 

decides to recognize an offset credit for use in its regulatory program.

Summary of Section 95990(f), Regulatory Verification of Offset Credits for Early 

Action.

Subsection (f) proposes that all offset credits recognized from a third-party offset 

program must be verified according to requirements in this subsection.

Rationale for Section 95990(f).

AB 32 requires all offset credits used for compliance purposes to be subject to 

regulatory verification.

Summary of Section 95990(f)(1).

Subsection (f)(1) proposes that an offset credit must be verified by an ARBaccredited third-party verifier.

Rationale for Section 95990(f)(1).

All verifiers and verification bodies providing Offset Verification Services under 

the compliance offset program will be held to the same rigorous standards for

accreditation. These standards are based on existing accreditation requirements 

in other voluntary and regulatory GHG reporting and offset programs. The 

requirements are also consistent with international best practices for verification 

body accreditation.

Summary of Section 95990(f)(2).

Subsection (f)(2) proposes that verification bodies be subject to conflict-ofinterest standards, and that the conflict of interest be assessed against those 
IX-176

responsible for offset projects, if the offset credits from those programs are 

recognized by ARB.

Rationale for Section 95990(f)(2).

All verification bodies and verifiers are subject to regulatory conflict-of-interest 

requirements to ensure that there is an unbiased review of each Offset Project 

Data Report. This provision ensures that any verification bodies with previous 

relationships with any party with a financial interest in the offset credits are not 

allowed to verify those offset credits.

Summary of Section 95990(f)(3).

Subsection (f)(3) proposes that verification bodies must conduct all the 

verification services as specified in section 95977 for offset projects, if the offset 

credits from those program are recognized by ARB. The verification services are 

provided for the project as a whole, and not separately for each vintage year of 

credits.

Rationale for Section 95990(f)(3).

This provision is necessary so that all offset credits that can be used for 

compliance purposes meet the same requirements for verification. This provision

helps to provide consistency among offset credits. The existing offset credits 

from a program recognized by ARB may be held by several parties who do not 

have access to the underlying data or other project information to support 

regulatory verification of the offset credits. This section applies the regulatory 

verification requirements across all vintage years for a project, so that any parties 

that hold existing credits may contract with a single verification body together,

and the project information to support verification only has to be gathered once.

Section 95991. Sector-Based Offset Credits.

Summary of Section 95991.

This section establishes the requirements that offsets originating from developing 

countries or from subnational jurisdictions within those developing countries, with 

the exception of those identified in Article 13, must come through a sector-based 

crediting program that has been approved by the Board. 

Rationale for Section 95991.

This provision is necessary because it defines the most basic terms for allowing 

international offset credits into California’s cap-and-trade program and the 

specific developing countries generating offset credits.
IX-177

Section 95992. Procedures for Approval of Sector-Based Crediting 

Programs.

Summary of Section 95992.

This section establishes that each sector-based crediting program must be 

approved by the Board after public notice and the opportunity for the public to 

submit comments in accordance with the Administrative Procedures Act,

Government Code section 11340 et seq. The offset credits generated from these 

programs can be used to generate compliance offset credits accepted by ARB. 

Rationale for Section 95992.

This provision ensures the integrity of the program by requiring that each 

program undergo a staff analysis and full public review prior to Board approval. 

Section 95993. Sources for Sector-Based Offset Credits.

Summary of Section 95993(a).

Subsection (a) lists a specific type of sector-based offset credit for consideration 

in the California cap-and-trade program, known as Reducing Emissions from 

Deforestation and Forest Degradation (REDD). 

Rationale for Section 95993(a).

This provision is necessary to propose that forest-sector offset credit programs 

be eligible for Board review and approval for recognition in the California capand-trade program.

Summary of Section 95993(b).

Subsection (b) is reserved for additional sources of sector-based credits for 

consideration in the California cap-and-trade program. 

Rationale for Section 95993(b).

This subsection is reserved for additional sources of sector-based credits for 

consideration in the California cap-and-trade program, as other programs 

become available. 

Section 95994. Requirements for Sector-Based Offset Crediting Programs.

Summary of Section 95994(a).

Subsection (a) establishes the general requirements that all sector-based offset 

crediting programs approved by the Board may be required to meet. 
IX-178

Rationale for Section 95994(a).

This provision is necessary to inform program developers of the minimum criteria 

that programs may be required to meet for Board consideration and approval; it 

is also necessary to ensure consistency by setting minimum standards by which 

each program will be assessed. 

Summary of Section 95994(a)(1).

Subsection (a)(1) proposes that the sector-based offset crediting program include

a plan for how the jurisdiction will reduce emissions from the sector in order to be 

considered for Board approval. 

Rationale for Section 95994(a)(1).

This provision is necessary because it sets forth what could be incorporated in a 

jurisdiction’s sector-level plan to inform ARB and the Board as to the jurisdiction’s 

approach toward reducing emissions. This document will be used by staff to 

assess a proposed sector-based offset crediting program as part of Board 

approval. 

Summary of Section 95994(a)(2).

Subsection (a)(2) establishes that a sector-based crediting program has a 

system in place for monitoring, inventory, reporting, and verification of GHG 

emissions for that sector, as well as enforcement capability over activities related 

to the program. 

Rationale for Section 95994(a)(2).

This provision ensures integrity to the program because it requires activities to 

determine whether the credits meet the quality criteria under AB 32.

Summary of Section 95994(a)(3).

Subsection (a)(3) establishes the offset criteria that all sector-based offset credits 

issued by a sector-based program and approved by the Board be real, additional, 

quantifiable, permanent, verifiable, and enforceable, as required by AB 32.

Rationale for Section 95994(a)(3).

This provision is necessary because AB 32 requires that all offset credits be real, 

additional, quantifiable, permanent, verifiable, and enforceable, and covered 

entities and program developers of sector-based crediting programs need to 

know the basic requirements. 
IX-179

Summary of Section 95994(a)(4).

Subsection (a)(4) establishes that a Board-approved sector-based offset 

crediting program has a transparent system in place to evaluate the overall 

performance of the program. 

Rationale for Section 95994(a)(4).

This provision is necessary so that ARB and those participating in the program 

know how the program is operating relative to the sector’s reference level 

emissions, and whether the program is appropriately issuing offset credits based 

on reductions that occur after the program meets its crediting baseline.

Summary of Section 95994(a)(5).

Subsection (a)(5) proposes that a Board-approved sector-based offset crediting

program has established public participation and participatory management 

mechanisms that provide for the participation and consultation of the public in 

the relevant jurisdiction during the program design process. 

Rationale for Section 95994(a)(5).

As with programs designed and implemented by ARB directly, other programs,

such as sector-based crediting programs, should allow for public involvement 

and consultation in the planning process in order to be eligible for ARB Board 

approval. 

Summary of Section 95994(a)(6)(A).

Subsection (a)(6)(A) requires that for a sector-based crediting program to use a 

nested approach, emissions-reduction projects must follow a methodology to 

ensure the inventory, quantification, monitoring, verification, enforcement, and 

accounting for all project-level activities.

Rationale for Section 95994(a)(6)(A).

This provision is necessary because it provides guidance to jurisdictions and 

project developers pursuing a nested approach to sector-based crediting that 

individual projects follow an offset project methodology that is consistent with the 

requirements of AB 32.

Summary of Section 95994(a)(6)(B).

Subsection (a)(6)(B) establishes that when a sector-based crediting program 

uses a nested crediting pathway, emission reductions at the project level can be 

credited if the program has established a clear accounting system, whereby 

project-level emissions reductions can be properly accounted for and reconciled 

with emission reductions that occur at the jurisdictional level. 
IX-180

Rationale for Section 95994(a)(6)(B).

This provision is necessary because it ensures that all GHG sources and sinks 

are accounted for at both the project level and at the sectoral level, which 

substantially reduces the risk that credits are unintentionally counted twice and 

therefore violate AB 32’s requirement that emission reductions from offsets must 

be real and additional. 

Summary of Section 95994(b).

Subsection (b) establishes that pursuant to Section 95996, sector-based 

crediting programs may have requirements that are specific to that sector and in 

addition to the general requirements set out in Section 95994(a).

Rationale for Section 95994(b).

This provision is necessary because it reserves the ability of the Board to 

establish other requirements for sector-based crediting programs that are unique 

to the specific sector generating offset credits in a jurisdiction. 

Section 95995. Quantitative Usage Limit.

Summary of Section 95995.

Section 95995 references section 95821(d), which identifies that sector-based 

credits recognized by the Board pursuant to 95991–95997 may be used by a 

covered entity to meet its compliance obligation. It also references section 95854,

which further specifies that covered entities may submit sector-based credits of 

up to 25 percent, 25 percent, and 50 percent of their total offset quantitative limit 

during the first, second, and third compliance periods, respectively.

Rationale for Section 95995.

This section is necessary because it establishes which offset credits a covered 

entity may use from sector-based crediting programs and specifies to covered 

entities that a limited supply of international offset credits from Board-approved 

sector-based crediting programs may be used toward a compliance obligation. 

Section 95996. Reserved for Sector-Specific Requirements.

Summary of Section 95996.

Section 95996 is reserved for sector-specific requirements for specific sectorbased crediting programs. 
IX-181

Rationale for Section 95996.

This section is reserved for sector-specific requirements for specific sector-based 

crediting programs. 

Section 95997. Reserved for Approved Sector-Based Crediting Programs.

Summary of Section 95997.

Section 95997 is reserved for approved sector-based crediting programs.

Rationale for of Section 95997.

This section is reserved for approved sector-based crediting programs.

Subarticle 15. Enforcement and Penalties.

Section 96010. Jurisdiction.

Summary of Section 96010(a) through (d).

Subsections (a) through (d) contain a list of actions that will establish a person’s 

consent to be subject to the jurisdiction of the State of California. These include 

registration with ARB; the purchase or holding of a compliance instrument issued 

by ARB; receipt of compensation of any kind from any transfer of compliance 

instruments issued by ARB; and verification of an offset credit to be issued by 

ARB.

Rationale for Section 96010(a) through (d).

These provisions are necessary because not all participants in the California capand-trade program will be located in California. ARB needs clear jurisdiction over 

all participants in order to enforce these regulations.

Section 96011. Authority to Suspend, Revoke, or Modify.

Summary of Section 96011(a).

Subsection (a) authorizes the Executive Officer to suspend, revoke, or place 

restrictions on the Holding Account of a voluntarily associated entity.

Rationale for Section 96011(a).

This provision is needed because in addition to conventional penalties, ARB may 

need to limit the ability of a registered entity to fully participate in the market as a 

response to violations by the entity. For voluntarily associated entities, ARB staff 

proposes that the Executive Officer be able to suspend, revoke, or place 

transaction restrictions on the Holding Accounts of violators.
IX-182

Summary of Section 96011(b)

Subsection (b) authorizes the Executive Officer to place restrictions on the 

Holding Account of a covered entity or opt-in covered entity.

Rationale for Section 96011(b).

This provision is needed because the Executive Officer may need to supplement 

conventional penalties with restrictions on the accounts of entities that violate 

rules in order to prevent further violations. 

Summary of Section 96011(c).

Subsection (c) authorizes the Executive Officer to suspend or revoke the 

registration of an entity registered pursuant to 95814(b) as an Other Registered 

participant. 

Rationale for Section 96011(c).

This provision is needed to allow the Executive Officer to terminate the 

participation of some registered entities to prevent further violations.

Summary of Section 96011(d).

Subsection (d) authorizes the Executive Officer to suspend, revoke, or modify an 

existing Executive Order in response to violations by an entity.

Rationale for Section 96011(d).

This provision is necessary if the Executive Officer believes that conventional 

penalties may not deter further violations.

Section 96012. Injunctions.

Summary of Section 96012.

Section 96012 cites existing authority for ARB to enjoin violations of this article.

Rationale for Section 96012.

This section is needed to clarify that ARB has authority in existing Health and 

Safety Code provisions to enjoin violations of its regulations. 

Section 96013. Penalties.

Summary of Section 96013.

Section 96013 cites existing authority for ARB to set penalties for violations of its 

regulations.
IX-183

Rationale for Section 96013.

This section is needed to clarify that ARB has authority in existing Health and 

Safety Code provisions to set penalties for violations of its regulations. 

Section 96014. Violations.

Summary of Section 96014 (a) through (c).

Subsections (a) through (c) establish a separate violation for each required 

compliance instrument that has not been surrendered; for each day or portion of 

a day that each required compliance instrument has not been surrendered; and 

for each day or portion of a day in which any other violation of the regulations 

occurs.

Rationale for Section 96014 (a) through (c).

These provisions are necessary so that ARB can set penalties based on the 

magnitude or duration of the violations of compliance instrument surrender 

provisions. These surrender provisions are unique to cap-and-trade programs.

Subarticle 16. Other Provisions.

Section 96020. Severability, Effect of Judicial Order.

Summary of Section 96020.

Section 96020 states that that if one provision of the regulations is declared 

invalid by a court or other authority, the remaining provisions will remain in full 

force and effect.

Rationale for Section 96020.

This section is necessary because it ensures that if ARB has enacted a provision 

in the proposed regulatory article that is illegal or unconstitutional, the remaining

regulatory provisions remain intact.

Section 96021. Confidentiality.

Summary of Section 96021(a).

Subsection (a) describes that all emissions data submitted to ARB is public 

information and may not be designated as confidential per reporter’s discretion.

Rationale for Section 96021(a).

This provision is necessary to implement the requirements set forth in Health and 

Safety Code sections 39600 and 39601.
IX-184

Summary of Section 96021(b).

Subsection (b) describes the confidentiality requirements for all reports and 

information provided by a covered entity, opt-in cover entity, voluntarily 

associated entity, and other registered participants to the ARB.

Rationale for Section 96021(b).

This provision is necessary to ensure that the regulated entities understand how

reports and information are managed, to ensure compliance with title 17 of the 

California Code of Regulations, sections 91000 to 91022.

Section 96022. Reserved Provisions.

Summary of Section 96022.

Section 96022 is reserved for future provisions. 

Rationale for Section 96022.

Section 96022 is reserved for future provisions.
References-1

X REFERENCES

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California Air Resources Board (2008): Early Reductions and Design Elements 

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California Air Resources Board (2009): Programs and Environmental Justice –

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California Air Resources Board (2009): San Joaquin Valley Air Quality 

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California Air Resources Board (2009): West Oakland Study. 

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California Air Resources Board (2009): Western Mojave Desert Air Quality 

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