Exploring the Interaction Between California’s Greenhouse Gas Emissions Cap-and-Trade Program and Complementary Emissions Reduction Policies

3002000298

EPRI Project Manager

A. Diamant

ELECTRIC POWER RESEARCH INSTITUTE

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Exploring the Interaction Between California’s Greenhouse Gas Emissions Cap-and-Trade Program and Complementary Emissions Reduction Policies

3002000298

Technical Update, March 2013

DISCLAIMER OF WARRANTIES AND LIMITATION OF LIABILITIES THIS DOCUMENT WAS PREPARED BY THE ORGANIZATION(S) NAMED BELOW AS AN ACCOUNT OF WORK SPONSORED OR COSPONSORED BY THE ELECTRIC POWER RESEARCH INSTITUTE, INC. (EPRI). NEITHER EPRI, ANY MEMBER OF EPRI, ANY COSPONSOR, THE ORGANIZATION(S) BELOW, NOR ANY PERSON ACTING ON BEHALF OF ANY OF THEM:

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Exploring the Interaction Between California’s Greenhouse Gas Cap-and-Trade Program and Complementary Emissions Reduction Policies. EPRI, Palo Alto, CA: 2013. 3002000298.

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ACKNOWLEDGMENTS The following organizations prepared this report:

Natsource LLC 100 William Street, Suite 2005 New York, NY 10038

Principal Investigators R. Rosenzweig R. Youngman Electric Power Research Institute (EPRI) 3420 Hillview Avenue Palo Alto, CA 94304

Principal Investigator A. Diamant

This report describes research sponsored by EPRI.

The EPRI project manager would like to thank Richard Rosenzweig and Robert Youngman of Natsource for putting together this excellent, comprehensive, and thought-provoking report. Their keen analysis and perspectives on the key issues highlighted here are very much appreciated. This report should provide high value to anyone with an interest in the development and implementation of market-based programs to reduce greenhouse gas emissions to mitigate climate change.

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ABSTRACT California enacted Assembly Bill 32 (AB 32) to address climate change in 2006. It required the California Air Resources Board (ARB) to develop a plan to reduce the State’s greenhouse gas (GHG) emissions to 1990 levels by 2020. ARB developed a plan (i.e., the “Scoping Plan”) made up of a GHG emissions cap-and-trade program and regulatory measures known as “complementary policies” (CPs) to achieve the 2020 target. The CPs, which were designed to achieve climate policy and other important policy objectives, targeted emissions from sectors covered by the GHG cap-and-trade program and those not covered by the program. ARB estimated that the CPs would achieve approximately 80% of the emissions reductions required to achieve the 2020 emissions target. Other jurisdictions, including the European Union, Australia, and the states that make up the Regional Greenhouse Gas Initiative, have developed a similar hybrid policy approach to achieve climate policy objectives.

Although this approach has been widely used to address climate change, little analysis has been undertaken on the interactions between CPs and GHG cap-and-trade programs and their impacts on program costs and covered entities. The report concludes that the performance of CPs in achieving emission reductions will have a significant impact on the level of abatement that covered sources will need to achieve to meet the fixed emissions cap in the GHG cap-and-trade program and on expected GHG emission allowance prices. In addition, the potential variance in the performance of CPs and other variables, and recent regulatory decisions that have been made regarding program implementation, will complicate the efforts of electric companies to develop an effective risk management strategy to comply with the program. Conclusions regarding the directional impacts of varying levels of CP performance on emission reduction requirements and allowance prices in California’s cap-and-trade program likely will be applicable to other jurisdictions employing the same policy model to address climate change.

Keywords AB 32 California Cap-and-trade Complementary policies Greenhouse gas Offsets

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CONTENTS 1 EXECUTIVE SUMMARY ......................................................................................................1-1

Description of Assembly Bill 32 ..........................................................................................1-1 The GHG Emissions Target and Emissions Sources ..........................................................1-2 The Policy Model ................................................................................................................1-2

Brief Description of Cap-and-Trade Supporters’ Views .................................................1-3 Brief Description of the Views of Supporters of CPs alongside Cap-and-Trade ............1-3 Combining a GHG Cap-and-Trade Program with CPs is not Unique ............................1-3

Better Understanding of the Interaction between GHG Cap-and-Trade Programs and CPs is Needed ...................................................................................................................1-3 General Description of California’s GHG Emissions Cap-and-Trade Program ....................1-4 Overview of Key Complementary Policies ..........................................................................1-5 Review of Economic Analyses of Complementary Policies in CA and their Impacts ...........1-6

Analysis by the California Air Resources Board (ARB) .................................................1-6 Analysis by Charles River Associates (CRA) ................................................................1-7

Complementary Policies’ Performance and Offset Supply Will Impact the Cap-and-Trade Program .............................................................................................................................1-7

Scenarios Which Will Affect California’s Cap-and-Trade Program ................................1-8 Uncertainties make it Challenging for Firms to Develop Compliance Strategy ....................1-9 Regulatory Requirements Could Make Risk Management More Challenging .....................1-9

2 CLIMATE POLICY IN CALIFORNIA.....................................................................................2-1 The Global Warming Solutions Act (Assembly Bill 32) ........................................................2-1 The Magnitude of California’s Challenge ............................................................................2-2 California’s Climate Policy Model .......................................................................................2-4 Better Understanding of the Interaction between GHG Cap-and-Trade Programs and Complementary Policies is Needed ....................................................................................2-5

3 DESCRIPTION OF CALIFORNIA’S GREENHOUSE GAS EMISSIONS CAP-AND-TRADE PROGRAM ..............................................................................................................................3-1

California’s Cap-and-Trade Program and Complementary Policies ....................................3-1 Description of California’s Cap-and-Trade Program ...........................................................3-2

Coverage and Point of Regulation ................................................................................3-2 The emissions cap and compliance periods .................................................................3-3 Allowance Allocation .....................................................................................................3-5 Allowance / Compliance Instrument Surrender .............................................................3-6 Allowance Trading ........................................................................................................3-6 Banking/Borrowing .......................................................................................................3-6 Offsets ..........................................................................................................................3-7 Linking ..........................................................................................................................3-8

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Allowance Auctions ......................................................................................................3-8 Allowance Price Containment Reserve .........................................................................3-8 Non-compliance ...........................................................................................................3-9

4 OVERVIEW OF KEY COMPLEMENTARY POLICIES .........................................................4-1 Renewable Portfolio Standard Program .............................................................................4-2

History and Targets ......................................................................................................4-2 Other Key Provisions of the RPS ..................................................................................4-3

Light Duty Vehicle GHG Emissions Standards ...................................................................4-4 Pavley I Standards: Emissions Standards and Estimated Benefits ...............................4-4 The Advanced Clean Car Program ...............................................................................4-5

Low Carbon Fuel Standard .................................................................................................4-6 Energy Efficiency Programs ...............................................................................................4-7

Zero Net Energy Buildings ............................................................................................4-8 Codes and Standards Strategies ..................................................................................4-8 Strategies for Existing Buildings ...................................................................................4-9 Existing and Improved Utility Program Strategies .........................................................4-9

High Global Warming Potential Gases ............................................................................. 4-10 Refrigerant Tracking, Reporting, Repair and Deposit Program ................................... 4-11

Implications for Cap-and-Trade Program if Complementary Policies Under-perform or Over-perform ................................................................................................................ 4-11

5 REVIEW OF ECONOMIC ANALYSES OF COMPLEMENTARY POLICIES IN CA AND THEIR IMPACTS ON THE CAP-AND-TRADE PROGRAM .....................................................5-1

ARB’s March 2010 Economic Analysis ...............................................................................5-2 Estimated Costs and GHG Emission Reductions Associated with Complementary Measures .....................................................................................................................5-2 Potential Impacts to GHG Allowance Prices Due to Lower-than-Expected Emission Reductions from Complementary Policies ....................................................................5-8

Charles River Associates Economic Modeling Estimates ................................................. 5-11

6 IMPLICATIONS OF COMPLEMENTARY POLICY PERFORMANCE AND OTHER VARIABLES FOR CAP-AND-TRADE COMPLIANCE STRATEGIES .....................................6-1

Scenarios that will Impact Electricity Company Compliance Planning ................................6-1 Complementary policies fail to achieve estimated emission reduction targets ..............6-2 Complementary policies exceed estimated emission reduction targets.........................6-7 Offset supply is significantly lower than the maximum allowed use limit .......................6-8 Offset supply is sufficient to meet the offset use limit ....................................................6-9 Economic and emissions growth is higher than forecasted ...........................................6-9 Economic and emissions growth is lower than forecasted ............................................6-9 Complementary policies in jurisdictions with linked cap-and-trade programs fail to achieve estimated emission reduction targets ............................................................ 6-10 Complementary policies in jurisdictions with linked cap-and-trade programs exceed estimated emission reduction targets.......................................................................... 6-10

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Implications of Complementary Policy Performance and Other Variables for Cap-and-Trade Compliance Planning ....................................................................................................... 6-10 Regulatory Requirements Create Additional Risk Management Challenges for IOUs ....... 6-10

Additional Perspectives and Areas for Further Research ............................................ 6-12

A APPENDIX A: COMPLEMENTARY GHG “POLICIES AND MEASURES” IN OTHER JURISDICTIONS .................................................................................................................... A-1

The EU ETS and Complementary GHG Policies in the EU................................................ A-1 Offsets ......................................................................................................................... A-1 Linking with Australia ................................................................................................... A-2

2020 EU Emission Reduction Targets ............................................................................... A-2 Relationship between Cap-and-Trade and Complementary Measures in the EU versus California ........................................................................................................................... A-3

Differences in the EU and California Programs ............................................................ A-3 The Potential for Complementary Policies to Over-achieve Against their Targets ........ A-4

Regional Greenhouse Gas Initiative .................................................................................. A-5 Australia ............................................................................................................................ A-5 U.S. Federal Government.................................................................................................. A-6

B APPENDIX B: ANALYSTS’ VIEWS ON THE NEED FOR COMPLEMENTARY POLICIES TO BE IMPLEMENTED IN CONJUNCTION WITH A CAP-AND-TRADE PROGRAM ................. B-1

Introduction ....................................................................................................................... B-1 Arguments for complementary policies .............................................................................. B-3 Arguments against complementary policies ...................................................................... B-7

Complementary measures increase the cost of achieving AB 32 goals ....................... B-7 A recent assessment of the case for complementary measures ................................ B-10

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LIST OF FIGURES Figure 2-1 Evolution of ARB’s Estimates of 2020 BAU emissions and Emission Reductions (MtCO2e) ................................................................................................................................. 2-3 Figure 2-2 Estimated Emission Reductions in 2020 by CPs and by Sectors Covered by Cap-and-Trade Program (MtCO2e) ................................................................................................. 2-3 Figure 2-3 California Average Annual GHG Emissions by Sector (2002-04) ........................... 2-4 Figure 3-1 California CO2 Emissions BAU and Emissions-to-Gross Cap 2013-20 ................... 3-4 Figure 3-2 California CO2 Emissions BAU and Emissions-to-Net Cap 2013-20 ...................... 3-4 Figure 3-3 Cumulative Abatement in Covered Sectors if the APCR is Completely Used ......... 3-5 Figure 3-4 California CO2 Gross and Net Emission Caps for Compliance Period (CP) 1, 2 and 3 (2013-20). ............................................................................................................................... 3-9 Figure 5-1 Cumulative GHG Emission Reductions from CPs, Cap-and-Trade and Offsets, as shown in ARB’s March 2010 Analysis ............................................................................. 5-10 Figure 6-1 Impact of CPs on BAU Emissions in Covered Sectors ........................................... 6-3 Figure 6-2 Emissions Abatement in Covered Sectors if CPs Achieve Zero Reductions ........... 6-4 Figure 6-3 Abatement in Covered Sectors Depends on CP Performance and the APCR ........ 6-5 Figure 6-4 CPs Achieve Estimated Emission Reductions, and Maximum Volume of Offsets is Available (MtCO2e) .............................................................................................................. 6-6 Figure 6-5 2020 Base Case Compliance Scenario (Emissions to Net Cap) ............................. 6-6 Figure 6-6 CPs Under-achieve, and Maximum Volume of Offsets is Available (MtCO2e) ........ 6-7 Figure 6-7 CPs Over-achieve, and the Maximum Volume of Offsets is Available (MtCO2e) .... 6-8 Figure 6-8 CPs Under-perform, and Offset Supply is Limited (MtCO2e) .................................. 6-9

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LIST OF TABLES Table 3-1 Annual Allowance Holding Limits ............................................................................ 3-7 Table 5-1 ARB’s Estimated Costs and Emission Reductions Associated with CPs in 2020 .... 5-3 Table 5-2 ARB’s Estimates of Allowance Prices, Impact on Gross State Product, and Cumulative Abatement under Different Scenarios ................................................................... 5-9 Table 6-1 Variables Affecting the Level of Emission Reductions to be Achieved in the Cap-and-Trade Program ......................................................................................................... 6-2

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1 EXECUTIVE SUMMARY Description of Assembly Bill 32 Governor Arnold Schwarzenegger signed Assembly Bill 32 (AB 32) into law in 2006. Assembly Bill 32 –also known as the Global Warming Solutions Act – required California (CA) to reduce its greenhouse gas (GHG) emissions to 1990 levels by 2020.1 The legislation included language indicating the intent of the Legislature that the statewide emission limit would continue past 2020.2 In addition to AB 32, Governor Schwarzenegger also issued Executive Order S-3-05 in 2005, which sets a goal for CA to reduce its GHG emissions 80% below 1990 levels by 2050.3

The legislation provided the California Air Resources Board (ARB) with broad regulatory authority to develop policies to achieve the specified GHG emissions limitations. Specifically, the legislation required ARB to:

• Adopt regulations by January 1, 2010 to implement “discrete early action” GHG emission reduction measures4 prior to the adoption of GHG emission limits and emission reduction measures; and,

• Develop and approve a Scoping Plan (SP) by January 1, 2009 that would achieve the maximum technologically feasible and cost-effective reductions in GHG emissions. “The plan shall identify and make recommendations on direct emission reduction measures, alternative compliance mechanisms, market-based compliance mechanisms5…” The policies included in the plan were to be adopted on or before January 1, 2011.6

A description of the key elements of the legislation is included in Section Two.

In general, AB 32 provided ARB with broad authority to develop market-based compliance mechanisms such as a GHG emissions cap-trade program, and any other policies that it determined were necessary to achieve the emissions reduction requirements included in the legislation. The SP that was developed and ultimately adopted included a GHG cap-and-trade program and many other regulatory policies that are referred to as “complementary policies” (CPs). The cap-and-trade program and the CPs were designed to achieve GHG reductions from all sectors of the State’s economy. The interactions between CPs and the GHG cap-and-trade program are the predominant focus of this paper.

Provisions included in the legislation required ARB to, “Consider other societal benefits, including reductions in other air pollutants, diversification of energy sources and other benefits to the economy, environment and public health7” in adopting regulations to implement the policies in the SP. ARB used these authorities to incorporate 17 categories of CPs in the Scoping Plan. These policies were designed to reduce GHG emissions from the State’s key emitting economic sectors by: (i) requiring greater use of renewable energy; (ii) imposing GHG emissions standards on vehicles and reducing the carbon intensity of transportation fuels; and, (iii) increasing the energy efficiency of the State’s economy. The SP also includes policies to achieve GHG emission reductions from sources and sectors that are not covered by the cap-and-trade program, including policies to address high global warming potential (GWP) gases and

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economic sectors as agriculture and forestry.8 In addition to the requirements for ARB to consider in developing regulations to implement the policies in the SP, the plan also includes several CPs geared to making progress towards the 80% reduction goal incorporated in Governor Schwarzenegger’s executive order.

The climate change program developed by CA represents the most comprehensive effort to date by any jurisdiction in the U.S. to address climate change. Given that CA is the largest state in the U.S. and the 14th largest emitter of GHG emissions in the world,9 the program requires careful consideration and analysis based upon its potential to affect the development of future climate mitigation policies in other jurisdictions.

The GHG Emissions Target and Emissions Sources The ARB has undertaken several analyses since AB 32 became law to quantify the GHG emission reductions required to achieve the 2020 emissions target included in the legislation. The initial analysis estimated that CA’s 2020 business as usual (BAU) GHG emissions, or emissions baseline, would be 596 million tonnes of carbon dioxide equivalent (MtCO2e). Its 1990 emissions were 427 Mt. Thus, achieving the emission target included in the legislation would have required GHG emission reductions of 169 Mt – approximately 30% below the 2020 BAU estimate.10

Subsequent to this analysis, the 2020 BAU estimate has been revised downwards on at least two occasions. ARB attributed these revisions to the deep recession that occurred between 2007-2009, and the need to include in the baseline GHG emission reductions that will be achieved by policies that existed prior to the SP. The effect of these revisions was to reduce the 2020 BAU emissions estimate to 507 Mt. Based on this forecast, 80 Mt of GHG emission reductions are required to achieve the 2020 GHG emissions target.11 A description of the analysis that has been undertaken on this issue is included in Section Two.

California’s emissions sources are diverse. ARB’s initial analysis, based on emissions in 2002-04, forecasted that the leading contributors to the State’s emissions in 2020, by sector, would be transportation (38%), the power sector (23%) and industry (17%).12 Emissions from the commercial sector, high-GWP gases and agricultural activities were estimated to account for the large majority of remaining emissions.13 Given the diverse sources of the State’s emissions, the cap-and-trade program covers emissions from the power and industrial sectors, and fuel from the transportation and other sectors. Similarly, the CPs were designed to reduce emissions from these key emitting sectors.

The Policy Model The SP includes a GHG emissions cap-and-trade program and CPs. California’s decision to strategically combine a cap-and-trade program with multiple CPs is not unique. It is similar in some respects to programs developed by other jurisdictions to address climate change. However, it appears that CA relies on CPs to a greater extent than other jurisdictions to meet its GHG emissions target. The most current analysis of the SP assumes the CPs will achieve 62 Mt, or 78% of the 80 Mt of reductions required to achieve the target.14 The reliance on CPs to achieve the large majority of reductions is important for many reasons, and requires further research. Issues which require further analysis include the impacts of CPs on the ultimate cost of the

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program, and how uncertainties over the performance of CPs affect the GHG cap-and-trade program and the entities covered by it.

The following discussion briefly highlights the views of advocates of the use of a “pure,” economy-wide cap-and-trade program to address climate change, and those that support combining CPs alongside a cap-and-trade program to achieve climate policy objectives.

Brief Description of Cap-and-Trade Supporters’ Views Some observers support a GHG cap-and-trade program to limit emissions because they believe it will address the market failure or externality of the free venting of emissions into the atmosphere by allowing the market to set a price on them. Some also support a cap-and-trade program over other policy approaches because they believe it will achieve climate policy objectives in the most economically efficient manner and at the lowest possible economic cost. Such observers also may believe that combining complementary or regulatory policies with a cap-and-trade system will increase the costs of climate policy by limiting the flexibility inherent in the program.15

Brief Description of the Views of Supporters of CPs alongside Cap-and-Trade Others engaged in the public policy debate over climate change mitigation policies believe regulatory policies or CPs are needed alongside of a cap-and-trade-program to stimulate greater levels of energy efficiency, increase development of renewable energy, and induce higher levels of fuel economy in the transportation sector to achieve climate policy and other objectives. They argue that CPs are necessary to overcome market barriers and failures that serve as obstacles to such investments. Importantly, many advocates of increasing energy efficiency, decarbonizing the transportation sector, and stimulating greater investment in renewable energy believe that in addition to reducing GHG emissions, these programs provide benefits that outweigh their costs. These benefits include: (i) lowering energy bills, (ii) reducing emissions of criteria and toxic air pollutants, (iii) avoiding the cost of building new power plants (iv) diversifying energy supplies; (v) developing new technologies necessary to achieve more ambitious long-term GHG targets; and, (vi) competing for growing domestic and international markets.

Combining a GHG Cap-and-Trade Program with CPs is not Unique Although the development of GHG cap-and-trade programs tends to receive the greatest attention in climate policy debates, all jurisdictions that have developed comprehensive programs to reduce GHG emissions have combined a GHG cap-and-trade program with CPs. Such jurisdictions include the European Union (EU), the states comprising the Regional Greenhouse Gas Initiative (RGGI), and Australia. In addition, legislation debated in the 110th Congress to address climate change combined a GHG cap-and-trade program with energy efficiency standards and a renewable portfolio standard (RPS). A brief description of these jurisdictions’ policy approaches can be found in Appendix A.

Better Understanding of the Interaction between GHG Cap-and-Trade Programs and CPs is Needed There is a significant amount of research regarding the performance of GHG emissions cap-and-trade programs and their impacts on the economy, environment and energy markets. However, there has not been a similar amount of analyses undertaken on the interactions between GHG cap-and-trade programs and CPs and their impacts. It is important to gain a greater understanding of these issues because the policy model could be replicated by governments

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around the world and could have significant impacts. This paper attempts to provide a greater understanding of the issues that may arise within CA’s program, and in other jurisdictions that implement programs incorporating both cap-and-trade and CPs. This paper examines the following issues.

• California’s GHG cap-and-trade program and key CPs included in the Scoping Plan; • Analysts’ views on the impacts of the CPs on the operation of the cap-and-trade program; • Quantitative modeling of CA’s climate change program; • Implications for the cap-and-trade program if CPs do not achieve estimated reductions; • How CPs’ failure to achieve expected GHG emission reductions could affect power

companies’ compliance strategies; • The use of CPs and cap-and-trade in the EU and other jurisdictions, and a comparison of

expected interactions in the EU and CA between CPs and the cap-and-trade program (see Appendix A); and,

• Analysts’ views on the need for GHG cap-and-trade programs and CPs (see Appendix B).

General Description of California’s GHG Emissions Cap-and-Trade Program At the time of ARB’s last analysis, it was estimated that the GHG cap-and-trade program would achieve 18 Mt or 22.5% of the 80 Mt of the GHG emission reductions required to achieve the 2020 target.16 This estimate is based on a “top-down” calculation – i.e., BAU emissions (507 Mt) minus the State-wide emissions limit of 427 Mt. As discussed below, a more precise estimate of emission reductions takes into account reductions within capped sectors, the use of the Allowance Price Containment Reserve (APCR), and reductions outside of capped sectors.)

The overall levels of abatement that will be necessary to achieve the fixed emissions limit in the cap-and-trade program will depend on the performance of the CPs in achieving estimated emissions reductions, whether allowances used to fund an APCR are used, and the level of offset supply. Section Three r includes a description of the key elements of CA’s GHG cap-and-trade program. A brief description of key elements follows.

• Coverage and Point of Regulation. By 2015 the program will cover ~85% of the State’s GHG emissions. Covered emissions include direct emissions from 600 facilities in the power and industrial sectors, and emissions from the combustion of fuels in the industrial, commercial, residential and transportation sectors.

• The Emissions Cap and Compliance Periods. The cap-and-trade program includes three compliance periods that run from 2013-2014, 2015-2017 and 2018-2020. The BAU GHG emissions in 2020 for sectors covered by the trading program are estimated to be approximately 409 Mt in 2020. The gross cap – i.e., the total amount of allowances issued – for the covered sectors will be 334 Mt in 2020.17 The 2020 net cap is approximately 311 Mt. This results from subtracting 23 Mt of allowances in 2020 to fund the APCR.18 Thus, covered sectors would need to reduce emissions in 2020 by 75 Mt to meet the gross cap and 98 Mt to meet the net cap.

• Allowance Allocation. Electricity distribution utilities (EDUs) are provided 90% of their expected allowance needs for free in 2012 for the benefit of their customers, declining to 85% in 2020.19 These allowances are then auctioned quarterly along with other allowances

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being auctioned by the State. In contrast, free allocations to Publicly Owned Utilities (POUs) may be used for compliance, and are not required to be auctioned. Independent Power Providers (IPPs) are allocated zero free allowances in the program, and must purchase all needed allowances at auction or in the market.

• Allowance Trading. Allowance trades can be made subject to rules and various limits.

• Banking/ Borrowing. Covered entities in the cap-and-trade program are permitted to bank excess allowances and use them for future years’ compliance. However, the ability to bank allowances is subject to various restrictions.

• Offsets. Covered entities can use offsets to comply with 8% of their compliance obligation, which translates to a maximum allowed volume of 218 Mt from 2013-2020, and 29 Mt in 2020. Offsets created by forestry, urban forestry, animal waste digesters and projects that destroy ozone depleting substances can be used for compliance conditioned upon the use of ARB approved protocols. ARB also has developed rules governing the invalidation of offsets under certain circumstances, and requires the buyer of invalidated offsets to replace them.

• Linking. California currently is in the process of formally linking its cap-and-trade program with a similar program now in place in Quebec, Canada. CA also is exploring possible linkages with a new cap-and-trade program recently implemented in Australia.

• Auctions. Allowances which are not allocated for free will be auctioned. The first auction was held in November of 2012. These auctions will be held quarterly by the ARB beginning in 2013. Allowances purchased at auction are subject to a floor price.

• Allowance Price Containment Reserve. The ACPR is designed to make allowances available to covered sources at a guaranteed price that rises over time. The reserve is filled by holding back a specified percentage of allowances from 2013-2020. 122 million allowances are set aside for this purpose over the course of the program, and 23 million allowances in 2020.

Overview of Key Complementary Policies The CPs included in the SP are designed to achieve emission reduction in sectors covered by the cap-and-trade program (e.g., power, transportation and industrial sectors), and uncapped sectors (e.g., high-GWP gases). The CPs targeting emissions in sectors covered by the cap-and-trade program are estimated to achieve 49 Mt of reductions and those targeting emissions in uncapped sectors are designed to achieve 13 Mt.20 The performance of CPs targeting covered sector emissions is one of the key variables that will determine the level of emission reductions that covered sectors in the cap-and-trade program must achieve to comply with the fixed cap, and price of allowances in the program. Under-performance of these policies will result in higher emissions in covered sectors, requiring greater emission reductions to meet the fixed cap under the cap-and-trade program. This will result in higher allowance prices.

What follows is a listing of some of the key CPs. More detailed descriptions of the policies can be found in Section Four.

• Renewable Portfolio Standard. California first passed an RPS in 2002. The current RPS is 33% and is estimated to achieve 11 Mt of GHG reductions. An RPS requires retail sellers of

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electricity to source a specified percentage of their generation portfolios from qualified renewable sources.

• Transportation Sector Programs. The programs targeting emissions from this sector include two phases of vehicle GHG emission standards (i.e., Pavley standards), and a low carbon fuel standard (LCFS). Phase 1 of the Pavley standards, which were signed into law in 2002, target GHG emissions from model years 2009-2016, and are estimated to achieve approximately 26 Mt of reductions. These reductions were incorporated in the 2020 emissions baseline. Phase 2 of the Standards target GHG emissions from model years 2017-2025, and are estimated to achieve 3.8 Mt of reductions. The LCFS is designed to reduce the carbon intensity of CA's transportation fuels by at least ten percent by 2020.21 It applies to all transportation fuel providers in CA, and establishes two separate standards for gasoline and diesel fuel.22 The LCFS is estimated to achieve 15 Mt of reductions.

• Energy Efficiency Programs. California has utilized energy efficiency programs since the 1970’s to achieve environmental and energy policy objectives. The CPs in the plan are estimated to achieve 12 Mt of reductions. They attempt to: (i) achieve zero net energy in new buildings; (ii) improve the energy efficiency of existing buildings; (iii) strengthen building codes and broaden appliance efficiency standards; (iv) improve the performance of investor owned utility (IOU) and POU efficiency programs; and (v) increase the use of combined heat and power (CHP).

• CPs Designed to Reduce High-GWP Gas Emissions. These emissions are forecast to grow from 3% of CA’s total in 2002-4 to 8% in 2020. As these emissions are not covered under the cap-and-trade program, the performance of policies addressing high-GWP gases will not impact the level of emission reductions that covered sectors must achieve. It will, however, affect emissions from uncapped sources and sectors, and CA’s ability to achieve its State-wide emissions target incorporated in AB 32. The primary CP to address high-GWP gas emissions – the Refrigerant Tracking/ Reporting/Repair/ Deposit Program – is estimated to achieve 5.8 Mt of reductions.

Review of Economic Analyses of Complementary Policies in CA and their Impacts The ARB conducted an economic analysis on the impacts of the CPs included in the SP in March of 2010 (ARB, March 2010).23 Charles River Associates (CRA) provided input to ARB on its economic analysis, prepared its own analysis, and concluded that the overall costs of implementing the SP would be higher than those estimated by ARB. A description of ARB’s and CRA’s analysis is included in Section Five.

Analysis by the California Air Resources Board (ARB) The ARB’s analysis concluded that implementation of measures in the SP, including the cap-and-trade program and the various CPs, will not adversely affect CA’s economic growth over the next decade, and would result in lower allowance prices than those estimated by CRA. The projected growth rate under BAU is expected to remain unchanged when SP measures are in place, mainly due to estimated savings in fuel expenditures.24

The ARB’s analysis concludes that the RPS, energy efficiency policies, CHP, Pavley II standards (the second phase of the Pavley standards, addressing model years 2017-25), the LCFS, and regional vehicle miles traveled (VMT) reduction measures collectively achieve annual net savings of over $6 billion in 2020.25 These savings are derived primarily from large negative

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costs resulting from the implementation of regional VMT reduction measures, Pavley II standards and energy efficiency programs. The analysis concludes that the VMT reduction program is estimated to result in annual savings of more than $8 billion.

The ARB also undertook a sensitivity analysis of five cases examining the impacts of different levels of CP performance, ranging from the CPs achieving 100% of estimated reductions to achieving 30% of estimated reductions.26 When the CPs achieved estimated levels of reductions, allowance prices were far lower than in cases when they did not.

The results from ARB’s March 2010 analysis, while important, were based on assumptions that have since been revised. ARB has made further changes to its emissions baseline (from 525 Mt in the analysis to 507 Mt), and increased the offset usage limit in the cap-and-trade program from the 4% limit assumed in the analysis to 8%. To augment ARB’s earlier conclusions and illustrate the range of potential impacts of differing levels of CP performance and offset supply, the authors and EPRI developed our own sensitivity scenarios that are described in Section Six, and which are based on updated data.

Analysis by Charles River Associates (CRA) Charles River Associates (CRA) also undertook a detailed analysis of various scenarios of CA’s program, although the scenarios they utilized are different than those used by ARB. As such, direct comparisons of ARB’s and CRA’s modeling results generally are not possible, with one exception. CRA did model a scenario in which the CPs achieved estimated levels of emission reductions. The analysis concludes that allowance prices would be $52/tCO2e, or 148% higher than the $21 price estimated by ARB for a similar scenario.27

CRA also modeled a scenario that did not include any CPs, in which reductions to comply with the AB 32 target would need to be achieved solely by the cap-and-trade system. Allowance prices in this scenario were estimated to be $78/tCO2e.28 Although ARB did not model a similar scenario, allowance prices were estimated to be $106/tCO2e in their scenario in which CPs achieved only 30% of estimated reductions.29 Charles Rivers’ modeling concludes that the social costs from this scenario are $47 billion, or 50% of the costs of the scenario they modeled in which CPs were assumed to achieve estimated levels of reductions.30

These findings illustrate CRA’s view that CA’s complementary measures significantly increase the overall cost of the combined cap-and-trade/CP program compared to a pure cap-and-trade program, even though they also result in lower allowance prices in the cap-and-trade program. This is because the CPs reduces emissions in covered sectors, and therefore demand for allowances. ARB concludes the opposite. Its estimated losses in gross state product were far lower in the scenario in which the CPs achieve estimated levels of reductions than in the scenario in which they only achieve 30% of estimated reductions.31

Complementary Policies’ Performance and Offset Supply Will Impact the Cap-and-Trade Program The cap-and-trade program incorporates a fixed emissions cap which serves as a backstop for CPs. If CPs under-perform, the effect will be to increase emissions in covered sectors and the level of emission reductions that covered sources must achieve to comply with the cap. In turn, the higher level of emission reductions can be expected to create upward pressure on allowance

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prices. In contrast, if CPs achieve their expected level of emission reductions, covered sector emissions will be reduced from BAU levels, and the level of emission reductions required to meet the fixed cap will decrease, resulting in lower allowance prices.

With respect to the electricity sector, if CPs targeting emissions from the sector – i.e., energy efficiency programs, CHP and the 33% RPS – fail to achieve their emission reduction targets, this will result in higher-than-projected emissions in the sector overall. In this scenario, the sector would confront increased emission reduction obligations under the fixed cap, higher allowance prices, and increased compliance costs. In a different scenario, CPs addressing electricity sector emissions could meet their emission reduction targets, but policies addressing transportation emissions could fall short of their emission reduction targets. Because covered emissions in the transportation sector would increase, allowance prices also would increase, thereby increasing compliance costs for the electric power sector, despite their meeting their emission reduction targets for RPS, energy efficiency and CHP.

There are many policy implementation issues and market dynamics that will affect whether CPs achieve estimate emission reductions. Section Five identifies some of the dynamics which are likely to affect some CPs’ performance. In addition to CP performance, the volume of offset supply is another variable which will affect the level of reductions that covered sources will need to achieve in the cap-and-trade program. Section Six includes several hypothetical scenarios that illustrate how different levels of CP performance and offset supply would impact the level of abatement be required in the cap-and-trade system.

Scenarios Which Will Affect California’s Cap-and-Trade Program As noted above, if the 23 Mt of allowances set aside in the APCR are not used in 2020, covered sectors must reduce emissions by 98 Mt, from 409 Mt to 311 Mt, to meet the cap in the cap-and-trade system. What follows are a few scenarios that illustrate how the program will be affected by CP performance and levels of offset supply.

• Scenario 1. The Program Works as Intended. In this scenario, CPs targeting emissions in the cap-and-trade program achieve 49 Mt of reductions in 2020. Covered sources use the maximum allowable volume of 29 Mt of offsets for compliance. Together, CPs and offsets achieve 78 Mt of reductions. Sectors covered by the cap-and-trade program therefore must reduce emissions by 20 Mt to achieve the 98 Mt of reductions required to meet the cap.

• Scenario 2. CPs Under-perform by 16 Mt, or 33%. In this scenario, CPs targeting emissions in the cap-and-trade program achieve 33 Mt of reductions in 2020. Covered sources use the maximum allowable volume of 29 Mt of offsets for compliance. Sectors covered by the cap-and-trade program reduce emissions by 36 Mt, or 80% more than the 20 Mt of reductions in Scenario 1. This is necessary to compensate for the CPs’ shortfall to achieve the required 98 Mt of reductions. In this scenario, allowance prices likely would likely increase.

• Scenario 3. CPs Under-perform by 16 Mt, or 33%, and Offset Use Declines by 9 Mt, or 33%. This scenario is identical to Scenario 2, with the exception that covered sources are only able to use 20 Mt of offsets for compliance. Sectors covered by the cap-and-trade program must reduce emissions by 45 Mt, or 25 Mt more than in Scenario 1. In this scenario, allowance prices likely would increase.

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There are many possible permutations of CP performance and offset supply levels. In addition, other variables will complicate efforts by electric power companies to develop effective strategies to comply with AB 32. Section Six describes a number of scenarios that could impact the cap-and-trade program, and illustrates their potential impacts on covered sectors in the program, and the challenges for risk management posed by these variables.

Uncertainties make it Challenging for Firms to Develop Compliance Strategy Electric power companies have significant experience developing strategies to manage the risks associated with costs to comply with environmental requirements. However, developing and implementing a strategy to mitigate risk related to AB 32 compliance may present some unique challenges. This is due to the potential variance in outcomes with respect to several key variables that will affect the required volume of emission reductions in the cap-and-trade program, allowance prices, and overall compliance costs. It may be particularly difficult to predict the combined effect of different variables on allowance prices. As discussed in Section Six, required emission reductions in the cap-and-trade program could vary by a factor of four -- from 97-395 Mt – depending on the level of emission reductions achieved by CPs and the extent to which the APCR is used.

In addition to the performance of CPs and the use or non-use of allowances held in the APCR, other variables will affect the level of required emission reductions, and allowance prices, in the cap-and-trade program. These include offset supply, the performance of the CA economy, the level of nuclear and hydroelectric generation relative to expected levels, and the performance, and of CPs in jurisdictions with cap-and-trade programs that will be linked to CA’s program, such as Quebec.

Regulatory Requirements Could Make Risk Management More Challenging Decisions by the California Public Utility Commission (CPUC) could make risk management even more challenging for IOUs. In an April 2012 decision, the CPUC established rules governing IOUs’ purchasing and use of allowances and offsets for compliance.

• Pacific Gas and Electric Company (PG&E), Southern California Edison Company (SCE), and San Diego Gas & Electric Company (SDG&E) may procure allowances via forward and futures contracts (subject to conditions), but may not purchase derivatives (e.g., options and swaps);

• These companies’ purchases of allowances, allowance futures and forwards, and offsets and offset forwards are subject to separately calculated Direct Compliance Obligation Purchase Limits and Financial Exposure Purchase Limits established in the decision. The former Limits set constraints on how many instruments may be bought or sold over a given time period.

• They may not enter into bilateral transactions or use brokers outside of a Request for Offers (RFO);32

• They may only procure offsets certified by ARB, and only through an RFO process; and,

• They may purchase offsets only if the seller contractually assumes the risk of invalidation.

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These restrictions limit the ways an IOU can manage risk and potentially reduce compliance costs. For example, restrictions on the use of options or swaps eliminate an important tool for managing price risk. Limits on purchased volumes of offsets and allowances restrict companies’ ability to hedge price and volume risk. The prohibition on bilateral transactions and the use of brokers to procure compliance instruments potentially may limit IOUs’ options to evaluate a portion of the market that could be favorable. The particular constraints within which IOUs will sell and buy allowances create additional challenges for managing price risk. Prices will fluctuate between the time an IOU sells allowances at auction and the time that it purchases allowances and offsets. During this time when the IOU is exposed to price risk, it will not be able to use options or swaps to manage this price risk. This is one context in which uncertainties relating to CP performance become even more challenging for IOU risk management activities.

In addition, the requirement that the offset seller must assume the risk of offset invalidation will increase the cost of offsets – because sellers that take on that risk will charge a premium to do so. The higher cost of offsets with “invalidation risk guarantees” is likely to reduce their value to IOUs as a lower-cost alternative to allowances.

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2 CLIMATE POLICY IN CALIFORNIA The GHG emissions cap-and-trade program and CPs developed by CA in response to adoption of AB 32 represent an ambitious effort to address the State’s GHG emissions in a comprehensive manner. Only a few other jurisdictions, including Australia, the EU and Japan, have developed such a far-reaching program to control GHG emissions that contribute to climate change. California’s approach to combining an economy-wide cap-and-trade program with CPs – i.e., policies designed to increase energy efficiency, stimulate greater development of renewable energy, and reduce emissions from personal transportation – could serve to influence the development of future policies at the state, regional or national levels to address climate change.

This section of this report describes the goals and specific regulatory mandates of AB 32 which led to the development of CA’s policy response. It describes the magnitude of the GHG emissions reductions CA will need to achieve to meet its GHG emission reduction target, and provides an overview of the policy approach that the State developed to meet its obligations. Lastly, it explains why a greater understanding of the interaction between GHG emissions cap-and-trade programs and complementary policies is necessary.

The Global Warming Solutions Act (Assembly Bill 32) Governor Schwarzenegger signed AB 32 in 2006.33 The legislation required the State’s ARB to “…determine what the statewide greenhouse gas emissions level was in 1990, and approve in a public hearing, a statewide greenhouse gas emissions limit that is equivalent to that level, to be achieved in 2020.”34 Language in the bill also stated that the intent of the legislature was that the emissions limits would continue past 2020.35 Governor Schwarzenegger also issued Executive Order S-3-05, which set a goal of reducing GHG emissions 80% below 1990 levels by 2050.36

Compliance with the GHG emissions limit was to begin on January 1, 2012, but the start of the first compliance period was delayed by the State until January 1, 2013. The legislation represents the most far-reaching effort in the U.S. to date to address GHG emissions that contribute to climate change. Because CA’s economy represents 13%37 of the U.S. Gross Domestic Product and was the 15th largest GHG emitter in the world38 when the legislation was enacted, it may influence the efforts of other jurisdictions considering how to reduce their GHG emissions.

The legislation provided ARB with broad regulatory authority to develop policies to achieve the specified GHG emissions limitations. Specifically, these authorities required ARB to:

• Adopt regulations by January 1, 2010 to implement “discrete early action” GHG emission reduction measures39 that would achieve the maximum technologically feasible and cost effective reductions prior to the adoption of GHG emission limits and emission reduction measures; and,

• Develop and approve a SP by January 1, 2009 that would achieve the maximum technologically feasible and cost-effective reductions in GHG emissions. “The plan shall

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identify and make recommendations on direct emission reduction measures, alternative compliance mechanisms, market based compliance mechanisms40…” The policies included in the plan were to be adopted on or before January 1, 2011.41

In general, ARB was provided with broad authority to develop market-based compliance mechanisms such as the GHG cap-trade program, and any other policies that it determined were necessary to achieve the emissions limits included in the legislation. The ARB’s Climate Change SP included a GHG cap-and-trade program and many other regulatory policies, which are referred to as “complementary policies.” The SP was designed to achieve GHG reductions from all sectors of the State’s economy.

Two specific provisions included in AB 32 provided ARB with its authority to adopt the policies included in the SP. In preparing the plan, the ARB was required to “…evaluate the total potential costs and total potential economic and non-economic benefits of the plan for reducing greenhouse gases to CA’s economy, environment, and public health using the best available economic models, emissions estimation techniques, and other scientific methods.”42 In adopting the regulations to implement the policies included in the plan, ARB was required to, “Consider other societal benefits, including reductions in other air pollutants, diversification of energy sources and other benefits to the economy, environment and public health.”43 ARB used these authorities to include numerous CPs in the SP designed to: (i) require greater use of renewable energy; (ii) reduce GHG emissions from the transportation sector; and, (iii) increase the energy efficiency of the State’s economy. The large majority of emission reductions are estimated to be achieved by these policies. The SP also includes policies to achieve emission reductions from high GWP gases and economic sectors as agriculture and forestry.44

The Magnitude of California’s Challenge To appreciate the context in which ARB developed the SP, it is important to understand the magnitude of emission reductions that the state would be required to achieve to comply with the 1990 statewide GHG emissions limit incorporated in AB 32, which is equivalent to 427 MtCO2e. At the time the SP was published (December 2008), the State developed an initial 2020 BAU emissions forecast of 596 Mt.45 In March 2010, ARB issued its “updated economic analysis,” which included a revised BAU estimate of 525 Mt.46 In October 2010, ARB further revised the BAU estimate, down to 507 Mt.47 These changes mainly reflected the effects of the severe recession between 2007 to 2009, and the inclusion of two key CPs in the baseline (the “Pavley I” GHG performance standards for light-duty vehicles, and the 20% Renewable Portfolio Standard (RPS) target for 2010). Additional details on these revisions are provided in Section Five.

The revisions in the 2020 emissions forecast had the effect of reducing the volume of emission reductions potentially needed to comply with the 2020 target from 169 Mt (based on the 596 Mt BAU estimate) to 98 Mt (based on the 525 Mt estimate) to 80 Mt (based on the 507 Mt estimate). Figure 2-1 illustrates these changes.

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Figure 2-1 Evolution of ARB’s Estimates of 2020 BAU emissions and Emission Reductions (MtCO2e)

Another important implication of the revisions of estimated 2020 BAU emissions is that CPs will play a more important role in achieving the fixed statewide target. Based on ARB’s most recent estimates, if new CPs (i.e., those associated with the SP, and that are not included in the emissions baseline) achieve their estimated emission reductions, they will account for 62 Mt of the 80 Mt, or 77.5%, of emission reductions from BAU, as shown in Figure 2-2. (CPs designed to achieve reductions from sectors covered by the cap-and-trade program are estimated to achieve 49 Mt of reductions. CPs designed to achieve reductions from sectors not covered by the cap-and-trade program are estimated to achieve 13 Mt of reductions.48) In this scenario, the cap-and-trade program would account for just 22.5% of the GHG emissions reductions required to close the gap between expected 2020 emissions and the AB-32 emissions target.49

Figure 2-2 Estimated Emission Reductions in 2020 by CPs and by Sectors Covered by Cap-and-Trade Program (MtCO2e)

California’s emissions sources are diverse. ARB’s initial analysis in the SP estimated that the leading contributors to the State’s emissions in 2020, by sector, will be transportation (38%), the power sector (23%) and industry (17%) (see Figure 2-1). Emissions from the commercial sector,

596 525 507

427

169 98 80

0 100 200 300 400 500 600 700

2020 BAU estimate

(Dec. 2008)

2020 BAU estimate

(March 2010)

2020 BAU estimate

(Oct. 2010)

1990 emissions

(AB 32 target)

BAU to target (Dec. 2008)

BAU to target (March 2010)

BAU to target (Oct. 2010)

62

18

Reductions from Complementary Policies

Reductions from Cap-and-Trade Program

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from gases high in GWP and agricultural activities were estimated to account for the large majority of remaining emissions.50 Given the sources of the State’s emissions, the cap-and-trade program was designed to cover emissions from the power and industrial sectors, and fuels from the transportation and other sectors. Similarly, the CPs were designed to reduce emissions from these key emitting sectors.

Figure 2-3 California Average Annual GHG Emissions by Sector (2002-04)

California’s Climate Policy Model The SP developed by ARB is an ambitious attempt designed to achieve the GHG emissions limits included in AB 32, the 2050 reduction goal included in Governor Schwarzenegger’s executive order, and several other public policy objectives. The Plan includes a GHG emissions cap-and-trade program and 17 categories of CPs. (In some cases, there are multiple policies within each category. For example, the “Light-Duty Vehicle GHG Standards” category includes implementing the “Pavley I” standards and developing the “Pavley II” standards.) California’s decision to strategically combine a cap-and-trade program with multiple CPs is not a unique approach, and is similar in some respects to programs developed by other jurisdictions. However, the State’s reliance on CPs to achieve 78% of the required emission reductions appears to be much higher than that of other jurisdictions.

Some observers engaged in the climate policy debate contend that the approach CA has developed to achieve the GHG emission reduction target included in AB 32 is different than those developed by other jurisdictions. This is because the debate over climate policy tends to focus on the conflicts in the policy development process. Some observers support a cap-and-trade program to limit GHG emissions because they believe it will address the market failure, or externality of the free venting of GHG emissions into the atmosphere by allowing the market to set a price on them. Some also support a cap-and-trade program over other policy approaches

181 Mt (38%)

113 Mt (23%)

42 Mt (9%)

93 Mt (20%)

7 Mt (1%) 13 Mt (3%) 32 Mt (6%)

Transportation

Electricity

Commercial and Residential

Industry

Recycling and Waste

High GWP

Agriculture

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because they believe it will achieve climate policy objectives in the most economically efficient manner and at the lowest possible economic cost. Those with this view argue that once regulated firms’ emissions are constrained by an emissions cap, they will seek out the lowest cost approaches to complying with the cap, whether it be buying emissions rights in the market place, or investing in activities such as energy efficiency or renewable energy which will reduce emissions within their own assets while achieving other important public policy objectives.51 Those supportive of cap-and-trade as the best approach to limiting emissions may believe that adding complementary or regulatory policies to a cap-and-trade system will increase the costs of climate policy by limiting the flexibility inherent in the program.52

Others engaged in the public policy debate over climate change believe that regulatory or CPs are needed along-side of a cap-and-trade-program to stimulate greater levels of energy efficiency, increase development of renewable energy and induce higher levels of fuel economy in the transportation sector to achieve climate policy and other objectives. They argue that CPs are necessary to overcome market barriers and failures that serve as obstacles to such investments. (These market failures are discussed in more detail in Section Four on the debate over the use of CPs in conjunction with a cap-and-trade program.) Importantly, many energy efficiency advocates believe that the benefits of these programs, such as lowering energy bills, reducing emissions of criteria air pollutants, avoiding the cost of building new power plants and developing new technologies necessary to achieve more ambitious long-term GHG targets outweigh program costs. Similarly, advocates of renewable energy may believe that the benefits of increased investment in renewables, such as diversifying fuel supply, serving as a hedge against higher natural gas prices, achieving reductions of criteria air pollutants emitted by fossil-fueled generation, developing new technologies necessary to meet more stringent long-term GHG targets and competing for growing domestic and international markets for these products are worth the costs.

Although the discussion over cap-and trade programs and CPs tends to be characterized as “either-or” in the climate policy debate, governmental programs that have been developed to limit GHG emissions to achieve climate policy objectives typically employ both approaches. Other jurisdictions that have utilized a combination of cap-and-trade and CPs to achieve climate policy objectives include the RGGI, the EU and Australia. In addition, the debate in the 110th Congress over climate policy tended to focus on the controversy and complexities over provisions included in cap-and-trade legislation. However, separate titles were included in the legislation that would have required energy efficiency standards and an RPS that mandated that generators source a specified percentage of their generation portfolios from renewable sources of energy. These jurisdictions’ policy approaches are briefly described in Appendix A.

Better Understanding of the Interaction between GHG Cap-and-Trade Programs and Complementary Policies is Needed The authors believe it is important for policymakers, those regulated by the program, and others engaged in the development of climate policy to better understand the interactions between GHG cap-and-trade programs and CPs, which are designed to achieve public policy objectives in addition to limiting GHG emissions. This is particularly the case given the impacts that such policies may have on the achievement of environmental, energy and economic policy objectives. It is also important to gain a greater understanding of these interactions to inform policymakers

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as the policy model used by CA and others likely will be replicated by other jurisdictions to address climate change.

The purposes of this EPRI report are as follows:

• Describe key CPs included in the Scoping Plan. The report briefly describes the cap-and-trade program that the State has developed and some of the key CPs estimated to achieve the large majority of reductions necessary to achieve the emissions limit included in AB 32.

• Describe analysts’ views on the impacts of the CPs on the operation of the cap-and-trade program. Some analysts believe that CPs will have an adverse impact on the operation of the cap-and-trade system. Specifically, the purpose of a GHG cap-and-trade-program is to provide incentives for regulated firms to comply with an emissions limit at the lowest possible cost. Some believe the CPs will adversely impact the performance of the cap-and-trade program and increase its cost by reducing participants’ flexibility to implement what they may believe are the lowest-cost compliance options. In contrast, ARB’s economic analysis finds that, collectively, CPs included in the SP have negative costs. ARB also concludes that its CPs reduce the costs of the cap-and-trade program by facilitating the implementation of low-cost emission reduction options – such as energy efficiency – by covered sectors. The report describes some of the analysis that has been undertaken on this issue.

• Describe quantitative modeling that has been undertaken on CA’s climate change program. In addition to the analysis of CA’s climate change program that has been undertaken to date by ARB, other analysts have modeled and assessed the program. These analyses differ on the impacts of the complementary programs on overall societal costs and allowance prices within the cap-and-trade program. ARB concludes that the CPs reduce the entire program’s costs principally because of the cost effectiveness of policies which improve energy efficiency, increase fuel economy in the transportation sector and reduce vehicle miles traveled. Other analyses conclude that CPs may have the effect of lowering allowance prices in the cap-and-trade program but lead to an increase in the overall program’s costs. This report describes the results of some of the analysis of AB 32, attempts to explain some of the reasons for the different conclusions, and identifies issues the authors believe should be considered in the implementation of CA’s program and subsequent programs.

• Describe the implications for the cap-and-trade program if CPs do not achieve estimated reductions. The purpose of the SP is to achieve a specified volume of emission reductions necessary to comply with the GHG emissions limitation included in AB 32. Analysis undertaken by ARB concluded that the CPs would achieve 77.5% of the required reductions.53 Many variables will affect whether the CPs achieve estimated reductions. We believe there needs to be a greater understanding of how these policies will work together. For example, this report identifies issues which may arise if the CPs do not achieve estimated GHG reductions. If the CPs do not achieve estimated levels of reductions, emissions in sectors covered by the cap-and-trade program increase, making the program’s emissions limits more stringent. This report explores what may occur in the context of CA’s cap-and-trade program if this situation should arise. Similarly, this report also considers a scenario in which CPs exceed their expected level of emission reductions, and describes the potential impacts of this scenario on the cap-and-trade program. In addition to CPs’ performance in achieving estimated reductions, other variables also will affect the volume of reductions that

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covered sectors must achieve in the cap-and-trade program to comply with the fixed emissions cap in the program, and allowance prices. These include available offset supply, the extent to which the APCR is used, the level of economic growth, and the level of nuclear and hydroelectric generation. Section Six examines a range of scenarios and their impacts on emission reduction requirements in the cap-and-trade program.

• Describe how CPs’ failure to achieve expected GHG emission reductions could affect power companies’ compliance strategies. The development and implementation of a risk management strategy to comply with GHG emissions limits is similar to the process for managing many other risks that electric power companies confront. In general, a regulated firm will assess its risk to GHG emissions limits and develop a risk management strategy to mitigate it. The company will then adopt the strategy to accommodate new knowledge. However, developing and implementing a strategy to mitigate risk from AB 32 may be more difficult than managing the risk associated with other environmental issues. This report describes some of the challenges that electric power companies, particularly IOUs and POUs may face in developing and implementing an effective risk management strategy to mitigate the risks created by CPs’ performance, offset supply and other variables.

• Describe analysts’ views on the need for GHG cap-and-trade programs and CPs. As noted, some observers involved in the public policy debate believe that a cap-and-trade program should be the primary policy instrument adopted to address climate change, while others believe CPs are essential to overcoming market barriers that inhibit the achievement of such important objectives as increased levels of energy efficiency and renewable energy, higher levels of fuel economy in transport and development of less mature technologies. Appendix A describes the divergent views surrounding these issues.

• Describe the use of complementary measures and cap-and-trade in the EU, and compare expected interactions between these approaches in the EU to those in CA. The EU ETS was the first large-scale cap-and-trade program to address CO2 emissions. The EU also adopted a variety of CPs to reduce GHG emissions and achieve a range of other policy objectives. In contrast to CA, relatively little attention has been paid in the EU to the potential for CPs to fail to achieve expected emission reductions by 2020. Due to the recession, emissions have decreased and are forecasted to be significantly lower in 2020 than previous estimates. As a result, there are concerns that the implementation of additional CPs – particularly the Energy Efficiency Directive – will lead to low allowance prices, limiting abatement in the cap-and-trade program, and serving as an impediment to the investment in and implementation of higher-cost abatement options that will be required in the longer term to address climate change. Appendix B considers these issues and discusses their relevance to the situation in California.

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3 DESCRIPTION OF CALIFORNIA’S GREENHOUSE GAS EMISSIONS CAP-AND-TRADE PROGRAM California’s Cap-and-Trade Program and Complementary Policies Although this report provides insight into several important issues regarding CA’s plan to implement AB 32, its primary purpose is to explore how CPs may interact with cap-and-trade programs in general, and the issues that CPs may raise for entities regulated by such programs.

California’s long experience developing and implementing environmental regulations and aggressive energy policies has shaped its views on the need for CPs, which can be seen in its policy rationales in the SP. California has been at the forefront of policies designed to improve energy efficiency, and increase development of renewable energy for many years. It adopted building and appliance efficiency standards in the 1970’s, and legislation creating an RPS in 2002. California’s passage of legislation in 2002 to address GHG emissions from personal transport (i.e., light-duty cars and trucks) was the first such policy adopted in the United States. Fourteen other states followed CA’s lead, and the program influenced the national effort to target GHG emissions from personal transport.54

The SP includes a discussion of the policy rationales and economic, environmental and public health benefits of the CPs. In addition, with respect to GHG emissions, language in the SP mentions several times that the policies are designed not just to achieve the 2020 GHG emission reduction target included in AB 32 at the lowest possible cost, and other important objectives, but also Executive Order 3-05’s long-term goal of reducing GHG emissions 80% below 1990 levels by 2050.55 Achieving the 2050 target will require a comprehensive, sustained effort that transforms key emitting sectors of the economy, such as power generation and transportation. Policies will need to be adopted that enable the development and commercialization of technologies that are not yet in widespread use. In an attempt to do so, policies included in the SP set far-reaching goals for energy efficiency, renewable energy and the development and deployment of non-emitting vehicles for personal transportation. ARB believes that the plan’s long-term focus on achieving the 2050 GHG emissions target and industrial transformation will provide major economic benefits to the State in terms of creating jobs in potential growth industries of the future.

Regardless of whether one agrees with the State’s emphasis on CPs included in the SP, it is clear that the State’s goal was not solely to create a climate change program capable of achieving its near-term targets at the lowest possible societal costs. Further analysis of the plan will need to evaluate not only the policies’ impacts on the cost of achieving the targets and the interaction of the CPs and the cap-and-trade system, but some of the other goals the State has said it is pursuing and a clear understanding of costs and benefits.

What follows is a general description of CA’s cap-and-trade program. A detailed description of some of the key CPs included in the SP is provided in Section Four.

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Description of California’s Cap-and-Trade Program The GHG emissions cap-and-trade program is one of the centerpieces of the SP. The plan, which was published in December 2008, estimated that the cap-and-trade program would achieve 34.4 Mt of reductions in 2020.56 By July 2011, ARB had adjusted this figure down to 18 Mt reductions in 2020, based on a significantly lower emissions baseline, and revisions in estimated reductions from CPs.57

California initially had envisioned that the cap-and-trade program would link to those of six other U.S. states and four Canadian provinces as part of the Western Climate Initiative (WCI). The goal was for all states and provinces in the WCI to adopt cap-and-trade programs and link them in a collective effort to address climate change. There is widespread agreement that this approach would achieve large-scale GHG emission reductions more efficiently than one state could, and that it was necessary to prevent emissions leakage. Many also envisioned that the WCI states’ efforts would inform the federal effort to develop a national cap-and-trade program. However, during the last several years several states withdrew from the WCI, and the federal effort to develop a national program ultimately failed in 2010. As such, the program is now comprised of CA, British Columbia, Manitoba, Ontario, and Quebec. To date, only CA and Quebec have approved cap-and-trade programs. The key elements of CA’s cap-and-trade program are described briefly below.

Coverage and Point of Regulation The CA cap-and-trade program is “economy-wide,” and when it is fully implemented in 2015 it will cover 85% of the State’s emissions from 600 facilities operated by 350 businesses.58 The emissions of in-state electric generation facilities and industrial facilities emitting more than 25,000 Mt per year are covered downstream beginning on January 1, 2013.59 The program also has adopted an approach to regulate so-called First Jurisdictional Deliverers of electricity, which means that imports of electricity from power plants located outside of the State that contribute more than 25,000 Mt also will be covered at that time.60 All emissions associated with imported electricity, whether they are from “specified” or “unspecified” sources, including emissions from sources that emit less than 25,0000 MW, will be covered by the cap-and-trade program by January 1, 2015. This is an important objective, as more than 50% of the State’s electricity emissions were created by sources located outside of the State that supplied approximately 25-30% of CA’s electric power at the time the SP was developed.61 However, the attempt to regulate out-of-state emissions also has raised several complex issues, including potential conflict with the Federal Energy Regulatory Commission regarding the appropriate regulation of wholesale power markets.

In addition to power plant and industrial emissions, the program regulates emissions from fuel combustion. Emissions from industrial, commercial and residential fuel combustion and transportation fuels (e.g., propane, heating oil, natural gas) will be regulated beginning on January 1, 2015. Commercial and residential fuel combustion and transportation fuels will be regulated where the fuel enters into commerce.62 Industrial fuel combustion will be regulated upstream.63

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The emissions cap and compliance periods In the SP, ARB projected that the State’s total 2020 BAU emissions, or “baseline emissions,” would be 596 Mt. Covered sectors’ BAU emissions were estimated to be 512 Mt, and the 2020 emissions cap was set at 365 Mt.64 This would have required 147 Mt or emissions reductions, or approximately 15% below BAU estimates.

In October 2010, ARB reduced its estimated 2020 emissions baseline to 507 Mt, and its BAU estimate for sectors covered by the trading program to 409 Mt.65 These figures have been cited in subsequent ARB documents, and have not been revised in any public documents since October 2010. Importantly, the 409 Mt estimate does not include estimated emission reductions from CPs. The impact of the performance of CPs and other variables on emissions in covered sectors and the level of emission reductions that must be achieved in the cap-and-trade program is discussed in more detail in Section Six.

The program includes a declining cap in three compliance periods from 2013 to 2020. The start of the program initially was planned for 2012, but was delayed to 2013. As such, the first compliance period begins in 2013 and concludes at the end of 2014. Emissions will be reduced 2% per year from a 2012 baseline. The second and third compliance periods are both three years in length and will run from 2015 through 2017 and 2018 through 2020, respectively. The cap will decline by approximately 3% per year from 2015 to 2020 from the 2012 baseline.66 In the first period, the program covers emissions from the power and industrial sectors (“narrow scope” emissions). Starting in 2015, the program expands to include transportation emissions (“broad scope” emissions).

As shown in Figure 3-1, the emissions cap for covered sectors in 2020 is 334 Mt, and the cumulative emissions cap for the period 2013-20 is 2.51 giga-tonnes (Gt). This cap may be referred to as the “gross cap,” to distinguish it from the “net cap”, which is more stringent, and refers to the gross cap minus the allowances placed into the APCR. To meet the gross cap, covered sectors must reduce their emissions from 409 Mt to 334 Mt in 2020, or 75 Mt. This is the level of emission reductions that must be achieved – through a combination of reductions under the cap-and-trade program, and from CPs – if prices remain below the levels that would trigger the use of allowances held in the APCR.

In 2020, 23 Mt of allowances will be placed in the APCR. If prices do not trigger the use of the APCR, covered sectors must meet the net cap and reduce their emissions by 98 Mt, from 409 Mt to 311 Mt. If the APCR is never used during the 2013-20 period, the reserve would grow to 122 Mt by 2020, and the cumulative net cap in 2013-20 would be 2.39 Gt. The amount of cumulative abatement in 2013-20 required to meet the net cap is 395 Mt (see Figure 3-2).

If all allowances in the APCR are released into the market each year (i.e., the APCR is completely used) in 2013-20, the level of cumulative abatement that covered sectors must achieve is reduced by 122 Mt – i.e., the total amount of allowances in the ACPR. As shown in Figure 3-2, the gross cap for the period 2013-2020 will decline from 2.51 Gt to 2.39 GtCO2e. Additional information on the APCR is provided later in this section.

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Figure 3-1 California CO2 Emissions BAU and Emissions-to-Gross Cap 2013-20

Figure 3-2 California CO2 Emissions BAU and Emissions-to-Net Cap 2013-20

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If all allowances in the APCR are released into the market each year (i.e., the APCR is completely used) in 2013-20, the level of cumulative abatement that covered sectors must achieve is 273 Mt – i.e., the cumulative gap in 2013-20 between BAU emissions and the gross cap (see Figure 3-3). Additional information on the APCR is provided later in this section.

Figure 3-3 Cumulative Abatement in Covered Sectors if the APCR is Completely Used

Allowance Allocation Allowances generally are allocated for free at the beginning of the program, with an increased proportion to be auctioned as implementation of the program progresses. The allocation of emissions allowances to the electric utility, industrial, and refinery participants are calculated differently as described briefly below.

Electric Distribution Companies Electricity distribution utilities (EDUs) are provided 90% of their expected allowance needs for free in 2012, declining to 85% in 2020.67 Allocations are based on the estimated consumer cost burden of each EDU.68 IOUs must consign their allowances to the State for sale. These allowances then are auctioned quarterly along with other allowances being auctioned by the State. The economic value obtained from the sales of these allowances must be provided to IOUs’ customers to compensate them for increased electricity prices.69 In contrast, free allocations to POUs may be used by POUs for compliance, and are not required to be auctioned. Independent Power Providers (IPPs), are allocated zero free allowances in the program, and must purchase allowances at auction or in the market.

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Industrial Facilities Each industrial facility’s allowance allocation is calculated based on three variables: (i) facility-specific product output or energy consumption; (ii) a cap adjustment factor based upon the sector to which the facility belongs; and (iii) an assessment of the sector’s “leakage risk”. The leakage risk factor is designed to protect industries whose competitors outside of the State do not face similar requirements to reduce their GHG emissions.

Oil refiners’ allocations for the first compliance period are based on one of two methods. The two methods are based upon whether or not the facility has an energy intensity index. For the most part, allowances are provided for free at the beginning of the program, with a higher percentage being auctioned as the program moves forward.

Allowance / Compliance Instrument Surrender Each covered entity is required to surrender compliance instruments (allowances and/or offsets) annually equal to 30% of its previous year’s emissions by November 1 of the following year, and to submit compliance instruments equal to their total emissions during the compliance period by November 1 of the following year. This means that an entity with a compliance obligation must surrender allowances and/or offsets equal to 30% of its previous year’s emissions on November 1, 2014 for compliance with its 2013 obligation. Full compliance, or the provision of compliance instruments equal to the sum of an entity’s emissions during the entire compliance period, must occur by November of the year following the end of the compliance period.70 For the first compliance period, covered entities must surrender allowances and offsets equal to their 2013 and 2014 emissions by November 1, 2015. For the second compliance period, a firm with a compliance obligation must surrender allowances and/or offsets equal to its emissions in the 2015-2017 period by November 1, 2018.

Allowance Trading Allowances can be traded within limits. Each covered entity is required to register with ARB and have two accounts. One is a compliance account. The allowances in this account are those transferred to ARB for compliance purposes, and cannot be sold, traded or transferred once they have been placed into this account.71 Covered entities also have a holding account. Allowances held in this account can be transacted. However, there are limits regarding the volumes of allowances held in these holding accounts that can be transacted in current or future years.72 In addition, electric utilities covered by the program have a third account, called a limited use holding account. This account is used to hold allowances that the ARB will auction on behalf of electric utilities in the quarterly auctions. Finally, some entities also will have exchange clearing holding accounts for the allowances they surrender on behalf of others.

Banking/Borrowing Covered entities are permitted to bank excess allowances and utilize them to comply with subsequent years’ emissions limit. However, the ability to bank emissions allowances in the program is severely limited by allowance holding limits that have been adopted by ARB. The holding limit is set by equations in the regulations that are based on a percentage of each year’s annual allowance budget for current and past allowances. The limit on holdings of allowances from future year vintages is based on the upcoming compliance period’s total budget. These holding limits apply to companies and “corporate associations,” not to individual facilities.

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Moreover, the quantitative holding limits are the same for all companies regardless of their size or compliance obligation. Table 3-1 below shows the holding limits adopted by the ARB. Table 3-1 Annual Allowance Holding Limits

Year

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budget (Mt)

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vintages (Mt)

Holding limit for future vintages

(Mt)

2013 162.8 5.9 34.3

2014 159.7 5.9 2015 394.5 11.7

31.6 2016 382.4 11.4 2017 370.4 11.1 2018 358.3 10.8

TBD 2019 346.3 10.5 2020 334.2 10.2

Offsets Covered entities are permitted to use offsets to comply with 8% of their compliance obligation.73 Originally, ARB estimated this would allow entities with a compliance obligation to use up to 232 Mt of offsets from 2012 to 2020.74 However, after delaying the program until 2013, the amount of allowed offsets was revised, and now totals approximately 218 MtCO2e. At this time, the use of offsets is restricted to those created by projects that utilize offset protocols developed and approved by ARB. Currently, ARB has approved four offset protocols: forestry, urban forestry, animal waste (aka dairy) digesters, and projects which destroy ozone depleting substances (ODS).75 The Board has indicated in several public presentations that it intends to adopt additional offset protocols in the future, including coal mine methane (CMM) destruction, methane reduction from rice management, and nitrogen fertilizer management. Other potential new offset types that ARB already has considered and rejected include low-bleed pneumatic valves used in natural gas distribution and landfill gas destruction. Estimates of compliance-eligible offset supplies for the 2013-2010 period range from 100-140 Mt.76

Offsets that have been submitted to the ARB for compliance purposes can be invalidated after they are used for compliance, if ARB determines that the project issuing the offsets: (i) overestimated the amount of offsets created by more than 5%; (ii) has not complied with all local, state or national environmental, health and safety laws; or, (iii) has already sold the offsets in another market where they have been used for compliance.77

If offsets are invalidated, the buyers that submitted the offsets for compliance are required to replace them within a defined time period. Some believe this “buyer liability” requirement will reduce covered entities’ interest in buying offsets for compliance, and adversely impact the development of the offset market, thereby increasing the economic cost of the program.78

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Linking California currently is in the process of linking its program with Quebec’s recently adopted GHG cap-and-trade program, and there have been preliminary discussions about linking the CA program with Australia’s recently adopted GHG cap-and-trade program. Linking programs would create greater opportunities for trade amongst a larger number of emissions sources required to reduce their GHG emissions. This likely would result in cost-saving opportunities for some participants and regions. However, linking to Quebec in particular is expected to increase allowance prices in CA because of the comparatively high marginal abatement costs in Quebec.

Allowance Auctions Allowances that are not allocated to electric companies and industrial emitters are to be auctioned by the State in quarterly auctions. These quarterly auctions are designed to ensure price discovery, market transparency and liquidity. Allowances from previous, current and future compliance years may be sold in each auction. The first auction was held on November 14, 2012. Subsequent auctions will be held quarterly starting in 2013. In 2013 and after, 25% of the current year’s allowances will be auctioned in addition to unsold allowances from previous years. There will be a floor price of $10 for 2013 allowances purchased at auction, increasing 5% plus the rate of inflation annually thereafter.79

The First Allowance Auction ARB held its first GHG allowance auction on November 14, 2012. The auction included a current auction of 2013-vintage allowances and an advance auction of 2015-vintage allowances. A total of 23,126,110 2013 allowances were available for sale at the auction and all of these allowances sold. The market-clearing price for these allowances was $10.09 per allowance. Ninety seven percent of the allowances purchased reportedly were bought by compliance entities. The maximum price bid was $91.13 per allowance and the minimum price was $10.00. The mean price was $13.75 and the median was $12.96.80

In addition, ARB auctioned a total of 39,450,000 2015 vintage allowances for sale, but only 5,576,000 were sold at the auction. These allowances were sold at the price floor level of $10/tCO2e. Ninety one percent of these allowances were purchased by compliance entities. The maximum price bid was $17.25 and the minimum was $10.00. The mean price bid was $11.07 and the median was $10.59.

Allowance Price Containment Reserve In an effort to contain potential spikes in future allowance prices, the program includes an APCR. The reserve is “funded” by withholding 1% of allowances from auctions in 2013-2014, 4% in the years 2015-2017, and 7% in the years 2018-2020.81 In addition, any current year allowances that fail to sell in the annual auctions can be added to the APCR. As illustrated in Figure 3-4, the APCR has the effect of reducing the GHG emissions cap for each year 2013-2020. For example, in 2020 the gross amount of emissions allowances available for compliance is 334 MtCO2e. Once the allowances used to fund the APCR have been removed, the net emissions allowance budget for 2020 is reduced in that year by 23 MtCO2e to 311 MtCO2e

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Figure 3-4 California CO2 Gross and Net Emission Caps for Compliance Period (CP) 1, 2 and 3 (2013-20).

Over the entire term of the program from 2013-2020, the gross emissions budget is 2,509 MtCO2e. The net cap after removing 122 Mt of allowances is 2,387 MtCO2e, assuming no additional unsold allowances are added to it.

Allowances contained in the APCR only can be purchased by entities with compliance obligations. Beginning in 2013, these entities can purchase allowances from the APCR at three predetermined price levels – $40, $45, and $50 – for three equal-sized tranches of allowances. These sales will take place six weeks after each quarterly auction beginning in 2013. Allowances offered for sale by the APCR will increase in price by 5% annually plus the rate of inflation thereafter.

Non-compliance If there is a shortfall in the amount of compliance instruments that regulated firms surrender to ARB for compliance, or if they are late in providing the allowances or offsets to ARB, compliance entities must surrender four allowances for every ton of emissions that was not covered in time.82 Subsequently, ARB will retire one of these allowances for compliance purposes and transfer three allowances to the APCR.

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4 OVERVIEW OF KEY COMPLEMENTARY POLICIES The discussion that follows summarizes some of the key CPs included in the SP. In order to provide a general understanding of some of the potential interactions of the CPs included in the SP and the cap-and-trade system, the last part of the section discusses implications for the cap-and-trade program if CPs under-perform or over-perform, and some of the implementation challenges and market dynamics that will determine whether the CPs achieve estimated levels of GHG reductions.

Complementary policies incorporated in the SP include policies targeting emissions in sectors covered by the cap-and-trade program (e.g., energy efficiency, RPS and transport sector programs), and policies addressing emissions from sectors not covered under the program (e.g., high-GWP gases). As noted earlier, CPs addressing emissions from covered sectors are estimated to achieve 49 Mt of reductions, and CPs addressing emissions from uncapped sectors are estimated to achieve 13 Mt of reductions.

The performance of CPs targeting covered sector emissions is one of the dynamics that will determine the level of emission reductions that covered sectors in the cap-and-trade program must achieve. This is because any under-performance of these policies will result in higher emissions in covered sectors, and therefore greater emission reductions required to meet the fixed cap under the cap-and-trade program.

Other variables impacting the level of required abatement under the cap-and-trade program include economic growth, which affects covered sectors’ emission levels, and the use of the APCR. If allowance prices reach levels that trigger the use of the APCR, it will release allowances into the market, easing upward price pressure and reducing the level of required abatement. As discussed in greater detail in Section Six, emission reduction requirements and compliance costs can vary by as much as a factor of four based on different scenarios. This broad range of potential emission reduction requirements creates unique challenges for covered entities in the development of risk management strategies.

According to the ARB’s most recent analysis (in July 2011), the agency estimated that implementation of five CPs can be expected to achieve 47 Mt of the 62 Mt of GHG emission reductions (76%) that will result from implementation of all of the CPs targeting emissions from covered sectors in the cap-and-trade program in 2020.83 Below we describe these five key CPs:

• The RPS;

• Energy efficiency programs; • California light-duty vehicle GHG standards (“Pavley standards”);

• The Low Carbon Fuel Standard (LCFS); and, • A policy designed to reduce high GWP gases.

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Renewable Portfolio Standard Program Increasing the State’s RPS from 20% to 33% is an important complementary policy included in the SP to achieve AB 32’s emissions limit for 2020.84 The initial SP estimated the RPS would achieve approximately 21 MtCO2e of emissions reductions.85 This estimate subsequently was reduced to approximately 11 Mt as ARB incorporated the 20% RPS into the baseline, because its implementation began prior to the development of the SP.86 Reducing GHG emissions from electricity use is important given the sector comprises more than 20% of the State’s direct emissions.87

California has been at the forefront of efforts designed to stimulate the development of renewable energy. As noted previously, the State has premised its support of renewables (similarly to other CPs) on achieving energy, economic and environmental policy objectives in addition to addressing climate change. The initial 2002 legislation authorizing the development of the State’s RPS includes language that reads, “Increasing California’s reliance on renewable energy resources may promote stable electricity prices, protect public health, improve environmental quality, stimulate sustainable economic development, create new employment opportunities, and reduce reliance on imported fuels.”88 Additional language in the SP reads, “Expanding the State’s RPS goals to 33% will accelerate achievement of longer-term (post-2020) GHG reduction goals, enhance fuel diversity, reduce reliance on fossil fuels, and reduce criteria pollutants. An expanded RPS will also further stimulate economic activity by providing opportunities for California companies that develop, produce, install, or operate renewable equipment.”89

History and Targets California’s RPS “requires that a retail seller of electricity, including electrical corporations, community choice aggregators, and electric service providers, purchase a minimum percentage of electricity generated by eligible renewable energy resources, as defined, in any given year as a specified percentage of total kilowatt hours sold to retail end-use customers each calendar year.”90 In addition to retail sellers of electricity, the program’s requirements also are applicable to POUs.

California has passed several pieces of legislation since 2002 establishing targets for the RPS and defining the program. In addition, Governors Brown and Schwarzenegger both issued related Executive Orders. Senate Bill No. 1078, the initial legislation authorizing the RPS legislation, was signed into law in 2002.91 The legislation required retail sellers of electricity to procure 20% of their electricity from eligible renewable energy sources by December 31, 2017.92 Senate Bill No. 107 amended Senate Bill No. 1078. It expedited the 20% RPS target from 2017 to 2010.93 Senate Bill No. 2 required that the 20% target be achieved from December 31, 2010 to December 31, 2013, established an interim target of 25% for December 31, 2016, and increased the target to 33%, to be achieved by December 31, 2020 and in subsequent years.

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Other Key Provisions of the RPS This section briefly describes some of the key elements of the CA RPS program.

Eligible Renewable Resources Eligible renewable resources include photovoltaics, solar thermal electric, wind, certain biomass resources, geothermal, hydroelectric less than 30 MW, ocean wave, thermal and tidal energy, fuel cells using renewable fuels, landfill gas, and municipal solid waste conversion.94 Facilities outside the State can be eligible as long as certain criteria are met.95

Procurement and Compliance Each electric corporation is required to prepare an annual renewable procurement plan as part of its general procurement process. All retail sellers are required to submit a compliance plan to the California Public Utility Commission (CPUC).96

Renewable Energy Credits RECs represent the renewable and, in some cases, the embedded environmental attributes created by the production of renewable energy. RECs are “unbundled” – i.e., they are sold separately from the electricity with which they are associated – and represent 1 MWh of electricity generated by an eligible renewable resource. In general, firms with an RPS compliance obligation can purchase Tradable RECs from an eligible renewable resource to meet a portion of their compliance requirement. For the most part, RECs are created when renewable electricity is generated and delivered in-state, and in limited conditions, out-of-state.

Costs Provisions are included in the legislation for the purpose of capping the costs that retail sellers would be required to pay for renewables. The most recent RPS legislation required the CPUC to establish a cost limitation on electric corporations’ procurement expenditures for eligible renewables to comply with the RPS. If it was determined that the limitation was not adequate for a corporation to meet the RPS procurement requirement, the corporation would be exempt from entering into contracts beyond what they could procure within the cost limitation unless it could do so without exceeding a de minimus increase in rates.97

Responsibilities of the California Energy Commission and California Public Utility Commission The California Energy Commission (CEC) is responsible for certifying the eligibility of renewable facilities for the RPS, and designing and implementing a tracking and verification system to determine that renewable output is counted only once for RPS compliance. In addition, the CEC is responsible for adopting rules specifying enforcement of the RPS for POUs, monitoring their compliance and referring POUs’ failure to comply with the RPS to ARB, which may impose penalties under AB 32.98

The CPUC is responsible for determining procurement targets and approving compliance, reviewing IOU contracts for RPS eligibility, establishing standard terms and conditions for contracting, and calculating a market price referent (MPR) for non-renewables that establishes the benchmark price for renewables.99 Although the CPUC’s web site references the MPR, the cost limitation approach included in Senate Bill No. 2 was designed to replace the MPR.

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Light Duty Vehicle GHG Emissions Standards The transportation sector was CA’s largest emissions source between 2002-2004, comprising 38% of the State’s emissions (see Figure 2-3). Personal transport (i.e., light-duty cars and trucks) accounted for 74% of the sector’s emissions.100 The transportation sector was forecast to account for 38% of State emissions in 2020. As such, ARB spent significant effort developing policies to reduce emissions from the sector. Under the cap-and-trade program, distributors of transportation fuels are responsible for emissions resulting from the combustion of transportation fuels they distribute (i.e., fuel combustion by motor vehicles), and from the production (i.e., refining) of transportation fuels. In addition, ARB incorporated three CPs in the SP to address the sector’s emissions. These policies reduce GHG emissions per mile traveled (the “Pavley standards”), reduce the carbon intensity of transportation fuels consumed in CA (the LCFS) and lower vehicle miles traveled (regional VMT reduction programs).

The SP includes recommendations to reduce GHG emissions from personal transportation in two phases. Phase 1 encompasses the implementation of the “Pavley standards,” or “Pavley I,” after the author of AB 1493 – former CA Assemblywoman and now CA Senator Fran Pavley. The legislation represented the first attempt to regulate GHG emissions from personal transportation in the U.S. Following passage of the CA statute, 14 other states in the U.S. have followed suit.

The key provision in AB 1493, which was signed into law in 2002, stated, “No later than January 1, 2005, the state board shall develop and adopt regulations that achieve the maximum feasible and cost-effective reduction of greenhouse gas emissions from motor vehicles.”101 The final rules were adopted in December of 2004. In its most recent estimate, ARB estimated that Phase 1 will reduce GHG emissions by about 26 MtCO2e in 2020.102 These reductions are included in the State’s 2020 BAU estimates because implementation of the Pavley I standards began prior to the development of the Scoping Plan.103

Phase 2 of these recommendations combined two existing programs (the Low Emissions Vehicle III and Zero Emissions Vehicle Program) into the Advanced Clean Car Program (aka Pavley II). It is estimated to achieve an additional 3.8 Mt of emissions reductions in 2020.104 These reductions are included as part of the 49 Mt of emission reductions estimated to be achieved by complementary measures in 2020.

Pavley I Standards: Emissions Standards and Estimated Benefits The Pavley I standards, which were denominated in terms of grams of CO2e emissions per mile, utilized the State’s existing LEV program and targeted GHG emissions from model years 2009-2016. They were designed to reduce emissions of CO2, methane (CH4), nitrous oxide (N2O) and hydrofluorocarbons (HFCs). Carbon dioxide, CH4 and N2O are emitted from vehicle operations, and CO2 and HFCs are emitted from air conditioning systems.

The program targeted emissions from category 1 passenger car/light-duty trucks (small trucks/SUVs) and category 2 light duty trucks (Large Trucks/SUVs). Category 1 vehicles were required to meet a standard of 323 grams of CO2 per mile in 2009, declining to 205 grams per mile in 2016. Category 2 vehicles were required to meet a standard of 439 grams of CO2 per mile in 2009, declining to 332 grams in 2016.105

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ARB estimated the Pavley I emissions standards would provide the State with the following benefits.

• GHG Emission Reductions. ARB estimated the Pavley I rule would reduce “climate change” emissions from the light duty passenger vehicle fleet by 18% by 2020 and 27% by 2030.106 The initial SP, which was completed four years after the first estimate was made, estimated the Pavley I standards would reduce emissions by approximately 27 Mt in 2020.

• Economic Benefits. ARB estimated that jobs would increase by 53,000 in 2020 and 77,000 in 2030. Income would increase by $4.7 billion in 2020 and $7.3 billion in 2030.107

• Costs. ARB estimated that the increases in the cost of the vehicles necessary to comply with the rule would be more than offset by savings in operating costs.108

The Advanced Clean Car Program The Advanced Clean Car Program, or Phase 2 of the SP recommendations for the transportation sector, is comprised of the existing LEV III and ZEV. The LEV III program was designed to make reductions necessary to achieve the 2020 GHG emission reduction target. It targeted GHG emissions from model years 2017 to 2025. The program also is designed to reduce criteria air pollutants that contribute to smog and soot from model years 2015 to 2025. This was the first time a program was designed to reduce both GHG and criteria air pollutant emissions. The ZEV program is focused on the State’s long-term effort to transform the personal transportation sector.

The LEV III program relies on existing automobile technologies to reduce GHG emissions and emissions of criteria air pollutants. The rule is designed to improve the performance of advanced gasoline vehicles which are expected to dominate the light duty fleet for the foreseeable future.

Some of the key provisions and estimated benefits of the LEV III program are described briefly below:

• GHG Emission Reductions. These standards required reductions of CO2, CH4 and N2O emissions. Under the program, emissions would be reduced from 251 to 166 grams CO2e per mile in 2025 – a 34 percent reduction from 2016 levels.109 By 2025, CO2e emissions would be reduced by 13 Mt or 12% below baseline levels, 31 Mt by 2035 (27% below baseline levels), and 40 Mt/year by 2050 (33% below baseline levels).110 Compliance with these standards would rely on improving existing technologies, such as increasing engine and transmission efficiency, reducing vehicle energy load, and increasing the use of electric drive trains.

• Criteria Air Pollutant Emission Reductions. The criteria air pollutant component of the LEV III program is designed to achieve the State’s requirements under the Clean Air Act. It requires the reduction of fleet average criteria air emissions from passenger cars, light duty trucks, and light duty trucks to levels achieved by super ultra-low-emission vehicles (SULEV) by 2025. The rule would require NOx emissions responsible for the creation of smog to be reduced by 75% in 2025 from 2014 levels.111 The rule also would require reductions in reactive organic gases and particulate matter (PM) 2.5. According to the State, reductions would be achieved using existing technologies capable of achieving emissions levels of SULEVs. Improvements in catalyst technologies would be necessary to achieve required reductions of precursors that cause smog.

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• Cost Effectiveness and Economic Impacts. ARB estimates that for every dollar spent to comply with the GHG portion of the Pavley II standards, the program would save consumers about $3.112 In addition, ARB’s analysis concludes that increased prices for new and existing vehicles resulting from compliance with the rules would be more than offset by reductions in vehicle operating and fuel costs. ARB also estimated that the rules would create jobs.113

The ZEV program was designed to commercialize zero emissions vehicles that are important to achieving CA’s 2050 target of reducing GHG emissions by 80% below 1990 levels by 2050. The program is technology-forcing, and focused on the need to transform the personal transportation fleet to achieve the State’s 2050 reduction target. In one scenario developed by ARB, it estimated ZEVs would need to represent almost 100% of new vehicle sales in 2040, and comprise 87% of the fleet by 2050 to meet the State’s GHG reduction goal.114 Because of this, the program is focused on the development and commercialization of technologies that are not yet in widespread use. Below is a brief description of some of the key objectives of the ZEV program, provisions to achieve them and environmental benefit.

• Fleet Requirements. The rule is designed to ensure that ZEVs and plug-in hybrids represent 15.4% of new sales by 2025. The sales goal translates to the production of more than 1.4 million ZEVs, and true zero emission vehicles in CA by 2025.115

• Expand Coverage. The rule would require manufacturers representing 97% of the market to comply with the rule’s requirements.116

• Clean Fuels Outlet Regulation. The State projects that hydrogen fuel cell vehicles will comprise an increased portion of the fleet, particularly in 2040 and 2050.117 This rule requires the construction of alternative fuel outlets when 20,000 alternative fuel vehicles use that fuel. To facilitate the addition of necessary infrastructure to encourage the use of hydrogen, the sites in which hydrogen fueling stations could be added will be expanded, and other provisions of the proposal are designed to encourage commercialization.118

• Environmental Benefits. ARB does not estimate the precise reductions in criteria air pollutants and GHG emissions that the ZEV rule may achieve. However, plug-in hybrids, electric vehicles, and fuel cell vehicles all emit far less criteria air pollutants and GHG emissions than advanced gasoline powered vehicles are estimated to emit in 2020 and 2025.119 ARB estimates that the LEV III and ZEV rules will achieve cumulative GHG reductions of approximately 870 Mt by 2050.120

Low Carbon Fuel Standard In January 2007, Governor Schwarzenegger signed Executive Order S-01-07, which called for the establishment of an LCFS to reduce the carbon intensity of CA's transportation fuels by at least ten percent by 2020.121 The LCFS would apply to all transportation fuel providers in CA. By reducing the carbon intensity of transportation fuels, the LCFS would have the effect of lowering emissions associated with the combustion of transportation fuels, which are the responsibility of transportation fuel distributors under the cap-and-trade program. ARB identified the LCFS as a discrete early action measure pursuant to AB 32, which expedited its development. The LCFS regulation received initial approval in April 2010122 and was finalized in June 2012.123

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The SP estimated the LCFS would result in 15 Mt of emission reductions in 2020. This estimate was unchanged in ARB’s July 2011 “Status of SP Recommended Measures.”124 However, there are a number of outstanding questions regarding whether the LCFS target can be met, and at what cost.

The 10% carbon intensity reduction requirement in the LCFS accounts for all GHG emissions in the lifecycle of a transportation fuel, including emissions from the production, transportation and use of each fuel, and from land-use changes associated with some biofuels.125 Two separate standards, or targets, are established for gasoline and diesel fuel. Within the pool of transportation fuels provided by a specified provider of such fuels (a “regulated party”), those alternative fuels that generally substitute for gasoline must meet the annual gasoline target, and alternative fuels that generally substitute for diesel fuel must meet the annual diesel target. The allowable carbon intensities for gasoline and diesel fuel used in CA are reduced each year until 2020 from an initial 2011 level. In addition to increasing the amount of low carbon fuels that it provides, a regulated party may also meet targets by submitting LCFS credits generated from overachieving the intensity limit in previous years, or purchased from other regulated parties.

In addition to reducing GHG emissions, the LCFS is expected to make CA’s economy “more resilient to future petroleum price volatility,” as noted in the SP. By promoting alternative fuels, the LCFS can “provide economic development opportunities and reduce emissions of … criteria pollutants, and toxic air contaminants,” as noted in the Executive Order. Furthermore, by providing flexibility to regulated entities (generally, refiners, blenders, producers or importers) in how they meet the 10% target, the performance standard established by the LCFS allows “price and quality considerations to determine eventual winners” rather than pre-selecting particular alternative fuels to support, thereby driving “least cost compliance.”126 The LCFS differs from the strengthened renewable fuels standard adopted by Congress in 2007 in that the latter requires specific amounts of different biofuels to be sold annually by 2022, while the former does not set fuel-specific target, and incentivizes the production of a wider range of alternative fuels, including electricity, hydrogen and compressed natural gas.127

Energy Efficiency Programs The SP includes several recommendations including new strategies and expansion of existing programs designed to improve CA’s energy efficiency and to reduce energy demand. It set new targets for energy demand reductions of 32,000 gigawatts (GWh) hours of electricity and 800 million therms of natural gas from BAU. This is equal to saving the amount of electricity required to power five million homes, or replacing the need to build ten 500MW power plants.128 The energy demand target subsequently was reduced to 24,000 GWh.129

The SP initially estimated that these programs and other efficiency programs would achieve reductions of more than 26 MtCO2.130 In July 2011, this estimate was revised to approximately 12 Mt.131 These emission reductions are included in the 49 Mt of estimated emission reductions from CPs addressing emissions covered by the cap-and-trade program, and are not included in the AB-32 emissions baseline. As mentioned, improving the efficiency of the electricity sector and reducing demand is important, given that direct emissions from electricity generation comprised more than 20% of emissions at the time the SP was developed.132

In the context of achieving the AB-32 GHG emissions target, the efficiency of CA’s economy will need to continue to improve to take into account population growth and changes in

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consumer behavior. The SP forecasted increased energy use resulting from CA’s population increasing to 44 million by 2020 and consumer trends.133 These trends include population growth in the warmest areas of the state leading to greater use of air conditioning, and increased purchases of larger homes and appliances and electronics.

The remainder of this section describes several of the strategies included in the SP designed to improve CA’s energy efficiency.

Zero Net Energy Buildings The primary emphasis of the zero net energy (ZNE) buildings program is to offset all of the energy use of buildings. This program initially was included in the CEC’s 2007 Integrated Energy Policy Report (IEPR) and proposed by the CPUC in 2007. The program requires all new residential and commercial buildings to be ZNE by 2020 and 2025 respectively. The SP details several elements that need to be implemented prior to meeting ZNE targets. They include:

• Intermediate targets and stretch goals. In the intermediate targets, all building and appliance standards would be tightened in future revisions of the standards.

• Zero energy heating and/or cooling technologies. This strategy would require electric and gas utilities to provide performance-based incentives for buildings to utilize zero or very low emitting technologies to heat and cool buildings.

• Integrated design. This strategy would bring together the key professions in building construction and performance to develop a strategy to ensure energy efficient buildings.

• Passive solar design. This strategy would use passive solar design in buildings so they use less energy than today’s buildings.

• Enable sales of surplus generation into the grid. This strategy would require utilities to purchase surplus power from buildings in a manner that considers the time value of generation, production costs and the environmental and grid benefits of solar and other renewable generation.

• Moving toward ZNE existing buildings. This strategy would focus on creating ZNE existing residential and commercial buildings. Residential buildings could combine non-emitting power for heating water, and electricity with efficiency improvements for systems such as heating, cooling and lighting. The SP recommends that commercial buildings could move towards ZNE by combining efficiency upgrades with the use of renewable generation.

Codes and Standards Strategies This element of the SP focuses on increasing the stringency of CA’s building and appliance energy efficiency standards, covering all energy used in buildings and emphasizing compliance and enforcement. Public Resource Codes Sections 25402 and 25402.1 adopted in the 1970’s “require the CEC to adopt, implement, and periodically update energy efficiency standards for both residential and nonresidential buildings.” The standards target new buildings, and additions and alterations to existing buildings. They are divided into three sets – mandatory requirements that apply to buildings, and performance standards that apply to local conditions. In addition, there are alternatives to the performance standards.

The appliance standards are designed to improve the efficiency of appliances and apply to those sold in CA and offered for sale in the State. Similar to building standards, appliance standards

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may be updated by the CEC at its discretion. It is expected that the standards will be updated several times before 2020.

Below is a brief description of the codes and standards strategies included in the SP:

• More stringent building codes and appliance standards. This strategy recommends that the CEC promulgate new building standards that require on-site renewable energy production.

• Broader standards for new types of appliances and water efficiency. This strategy would impose standards on products that are not yet regulated such as plasma televisions and internal power supplies. In addition, the plan recommends that appliance standards be developed for flat screen TV’s, computers and portable electronics. These appliances represent 15% of home energy use.134

• Improved compliance and enforcement for existing standards. This strategy recommends devoting greater resources to compliance and enforcement activities as they have been identified as barriers in the application of standards.

• Voluntary targets for efficiency and green buildings beyond mandatory codes. This strategy recommends providing incentives for going beyond required levels of building codes. The SP also recommends developing voluntary green building codes to stimulate best practices in low carbon building and construction.

Strategies for Existing Buildings Many of CA’s existing buildings were built in accordance with building standards that were less stringent than current standards, or to none at all. The SP communicates that significant opportunities exist to improve the efficiency of existing buildings, and that this represents the “…most important activity to reduced GHG emissions within the electricity and natural gas sector.”135 The CPUC’s Energy Efficiency Strategic Plan established strategies and goals for reducing energy consumption in existing homes by 20% in 2015 and 40% in 2020, as follows.136

• Voluntary and mandatory whole-building retrofits for existing buildings. This strategy would require establishing rating systems for homes and requiring retrofits for buildings that do not meet performance standards.

• Innovative financing to overcome first-cost and split incentives for energy efficiency, on-site renewables, and high efficiency distributed generation. This strategy is designed to address the barriers of upfront costs of investment in energy efficiency and renewable energy for building owners, which can be cost-effective for the lifetime of the investment.

Existing and Improved Utility Program Strategies IOUs and POUs play a key role in implementing energy efficiency and demand reduction programs in CA. Their efforts will have a direct influence on the potential success of other SP energy efficiency recommendations in achieving their goals, such as ZNE buildings, strengthening building and appliance efficiency standards, and improving the efficiency of existing buildings. The CPUC approved three-year funding of $3.1 billion for IOUs’ energy efficiency portfolios from 2010 through 2012.137 The programs are funded by a public goods charge and procurement funding. Over $2 billion was targeted towards improving the efficiency of the residential, commercial, industrial and agricultural sectors. Significant funds also were devoted towards increasing the efficiency of lighting and HVAC systems. Much of these funds

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were provided for education, audits and technical assistance. Other funds were provided to customers in the form of financial incentives such as rebates to support purchases of more efficient technologies and equipment.

• More aggressive IOU utility programs to achieve long-term savings. This strategy involves increasing the goals and effectiveness of efficiency programs implemented by IOUs and POUs. The utilities’ goals for energy efficiency savings are based on economic potential. This is defined as “a theoretical maximum savings for which the value of the energy saved exceeds the theoretical social cost.”138 Savings targets are based on 70% of economic potential. At the time of the SP, the CPUC implemented a mechanism that would provide IOUs with increased returns based on achieving greater than 85% of the targets and lower returns if they achieved less than 65% of the targets.

• Publicly Owned Utility Energy Efficiency Programs. POUs’ energy efficiency programs are not as institutionalized as IOUs’ efficiency programs. Although they provide 25% of the State’s electricity, POUs account for only 5% of utility efficiency savings.139 Recently passed statutes have required POUs to implement a non bypassable surcharge to fund efficiency programs, and require the CEC to establish statewide energy savings targets for POUs. There is no requirement in the statute for POUs to meet these targets. The CPUC, CEC and ARB support mandatory levels of energy efficiency for POUs.

High Global Warming Potential Gases High-GWP gases are not covered under the cap-and-trade program. Consequently, the performance of policies addressing high-GWP gases will not impact the level of emission reductions that covered sectors must achieve, but will affect emissions from uncapped sources and sectors, and CA’s ability to achieve its statewide emissions target incorporated in AB 32. In view of the risk that CPs in uncapped sectors will under-perform, the SP includes what it calls a “margin of safety” – i.e., “additional greenhouse gas emissions reduction strategies to account for measures in uncapped sectors that do not achieve the greenhouse gas emissions reductions estimated in the Scoping Plan.” It further notes that, “Along with the certainty provided by the cap, [the margin of safety] will ensure that the 2020 target is met.”140

Gases high in GWP and which are regulated by AB 32 comprised approximately 3% of CA’s GHG emissions at the time the SP was developed.141 However, they are estimated to grow to nearly 8% of 2020 estimated BAU emissions.142 These gases are not emitted from any distinct economic sector. They are mostly utilized in refrigeration and air conditioning systems, and in other applications including electric transmission, fire suppression and semiconductors.

High- GWP gases are comprised of two categories. The first category is ODS. They include chlorofluorocarbons (CFCs), and hydrochlorofluorocarbons (HCFCs). Production of these ODS were phased out by the Montreal Protocol because of concerns about their impact on stratospheric ozone depletion. They are not included in California’s inventory of GHGs and are not regulated.

The second category of high GWP gases includes HFCs and perfluorocarbons (PFCs), which were developed as substitutes for CFCs and HCFCs. They are regulated by AB 32 in CA, and the Kyoto Protocol internationally. Sulfur hexafluoride (SF6) is another high-GWP gas that also is regulated by AB 32 and the KP.

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ARB estimates that high-GWP-gas measures will reduce emissions by approximately 6.5 Mt143. These emission reductions are counted as part of the estimated 13 Mt of emission reductions resulting from CPs addressing uncapped sources and sectors, and ARB does not include them as part of the AB 32 emissions baseline.

Refrigerant Tracking, Reporting, Repair and Deposit Program This program was one of two policies that comprise the stationary refrigerant management program. The SP estimated it would achieve reductions of 6.3 Mt.144 This number was adjusted downward to 5.8 Mt in July 2011.145

This program attempts to reduce non-residential air conditioning and refrigerant emissions from leaky stationary commercial and public facilities above a certain size through reporting/ leak detection and repair/improved servicing and end-of-life controls. The program was implemented by rule.146 It applies to anyone: (i) operating a facility with a refrigerant system charged with more than 50 pounds of high GWP refrigerant; (ii) who maintains or repairs a refrigeration/air conditioning appliance using a high GWP refrigerant; and, (iii) who distributes or reclaims a high GWP refrigerant. What follows are key elements of the rule, which classifies these systems according to the amount of refrigerants they use.

• Registration of refrigerant systems is required by a certain date based on size of the systems. • Requires leak detection or quarterly or annual leak inspection and monitoring for facilities

with stationary refrigerant systems. • Leak repairs are required by certain dates once they are detected. • Retrofits or retirements of systems are required if repairs of detected leaks cannot be made. • Annual reporting is mandatory for refrigerant systems that required services and leak repairs

and for purchases and use of refrigerants. • Recordkeeping of documents for five years is required to document compliance. • Services practices are required for high GWP appliances specific to high GWP refrigerants

based on EPA regulations of ODS refrigerants. • Sales prohibitions will be imposed on all high GWP refrigerants based on EPA regulations

specific to ODS refrigerants. • Annual reporting requirements are imposed on refrigerant distributors, wholesalers and

reclaimers of refrigerant purchased, sold, or reclaimed units for certified reclaimer reporting. • Recordkeeping of documents is required for five years by distributors, wholesalers and

reclaimers to document compliance.

Implications for Cap-and-Trade Program if Complementary Policies Under-perform or Over-perform There are a number of variables including policy implementation and market dynamics which are likely to affect whether the key CPs included in the AB-32 SP achieve estimated levels of GHG emission reductions. If CPs targeting emissions from sectors covered by the cap-and-trade program fail to achieve their forecasted level of emission reductions, entities covered under the cap-and-trade program will need to achieve higher-than-expected emission reductions to comply with the program’s fixed emissions cap. This can be expected to increase marginal abatement

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costs, allowance prices, offset prices, and overall program costs. ARB’s updated economic analysis considers scenarios in which CPs deliver less than their expected amount of emission reductions, and shows how under-performance of CPs may impact allowance prices, and the distribution of cumulative abatement among the cap-and-trade program, offset use and CPs. These results are described in Section Five. Section Six provides additional scenarios – based on ARB’s updated BAU emissions estimates – to consider the impact of CP performance and other variables on emission reduction requirements in the cap-and-trade program.

With respect to the electricity sector, if CPs targeting emissions from the sector – i.e., energy efficiency programs, CHP, and the 33% RPS – fail to achieve their emission reduction targets, this will result in higher-than-projected emissions in the sector. In this scenario, the sector would confront increased emission reduction obligations under the fixed cap, higher allowance prices, and increased compliance costs.

In a different scenario, CPs targeting electricity sector emissions could meet their emission reduction targets, but policies addressing transportation emissions described in Section Four could fall short of their emission reduction targets. Because covered emissions in the transportation sector would increase, allowance prices would increase, thereby increasing compliance costs for the electric power sector, despite their meeting their emission reduction targets for RPS, energy efficiency and CHP.

Other scenarios also are certainly plausible. For example, CPs could surpass their estimated targets of 62 Mt of reductions to be achieved in 2020. This would reduce covered sectors’ emissions in the cap-and-trade program. As a result, the level of emission reductions needed to comply with the cap would decline, and allowance prices would fall. These scenarios are considered further in Section Five in the discussion on economic analysis of the SP, and in Section Six, in the discussion on the implications of different scenarios for compliance planning for regulated entities in the cap-and-trade program.

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5 REVIEW OF ECONOMIC ANALYSES OF COMPLEMENTARY POLICIES IN CA AND THEIR IMPACTS ON THE CAP-AND-TRADE PROGRAM As required by AB 32, ARB prepared an economic analysis of the SP, and released an “updated economic analysis” in March 2010 (ARB, March 2010). CRA provided input to ARB on its economic analysis, prepared its own analysis, and concluded that the overall costs of implementing the SP would be higher than those estimated by ARB.

In contrast to CRA’s analysis, ARB’s analysis concluded that implementation of measures in the SP, including the cap-and-trade program and the various CPs, will not adversely affect CA’s economic growth over the next decade. The projected growth rate under BAU is expected to remain unchanged when SP measures are in place, mainly due to estimated savings in fuel expenditures.147 In its comments on ARB’s updated economic analysis, the Economic and Allocation Advisory Committee (EAAC), appointed by the California Environmental Protection Agency and ARB, noted that the CRA study estimated higher costs, but that these costs were small relative to the size of the CA economy.148 Despite this broad conclusion, differences among the cost estimates in the studies, relative to each other, are significant, and reflect major differences of opinion regarding the impact of energy efficiency measures and other CPs on the costs of the Scoping Plan. These differences of opinion are examined in detail in Appendix B.

The discussion that follows summarizes key estimates in, and describes issues arising from, ARB’s economic analysis – including:

• Estimated costs and emission reductions associated with key CPs; • Factors that may affect the ability of complementary measures to achieve their estimated

emission reductions; • How the performance of complementary measures impacts allowance prices in ARB’s

modeling scenarios; • Critiques of ARB’s assumptions and estimates relating to the costs and emission reductions

associated with key complementary measures; • The two very different scenarios that companies planning to comply with the cap-and-trade

program may need to consider – one in which complementary measures under-perform, and allowance prices increase above expected levels, and, another in which complementary measures over-perform, and allowance prices fall.

This discussion is focused on CA’s CPs, and their impacts on the cap-and-trade program, their interactions, and analyses of the impact of the performance of CPs incorporated in the SP on CA’s cap-and-trade program. As such, it considers various details of the programs and specific results of economic analyses. More generally, however, we expect that the types of interactions and dynamics between the cap-and-trade program, CPs, and other variables such as available

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offset supply that can be seen in CA will have broader relevance, and may be applicable to other jurisdictions that utilize CPs alongside a cap-and-trade program to address climate change.

ARB’s March 2010 Economic Analysis ARB’s March 2010 economic analysis is based on two economic models. Energy 2020149 is a multi-regional energy model, which simulates fuel supply and demand and can be used to investigate the impacts of GHG emissions constraints on the energy system. E-DRAM (the Environmental Dynamic Revenue Assessment Model) is a computable general equilibrium model of the CA economy that can be used to analyze economy-wide impacts of policies.

ARB’s March 2010 analysis incorporates a BAU statewide baseline GHG emissions forecast of 525 MtCO2e in 2020, compared to the 596 MtCO2e forecast contained in the SP, published in December 2008. As noted in Section Two, ARB’s most recent 2020 BAU emissions forecast is 507 Mt (ARB, October 2010).150 The difference between the 525 Mt baseline estimate in the March analysis and the 507 Mt estimate in the October update appears to correspond to: (i) a larger downward adjustment of BAU emissions estimates from the initial 596 Mt forecast to account for the effects of the recession (51 Mt in ARB, October 2010, versus 25 Mt in ARB, March 2010); and, (ii) a smaller estimate of emission reductions policies that pre-dated the SP (i.e., the Pavley I standards and the 20% RPS) and should be incorporated in the baseline (38 Mt in ARB, October 2010, versus 50 Mt in ARB, March 2010). 151 Since ARB has so far not provided a complete updated economic analysis to reflect more recent GHG baseline emission estimates, the discussion below focuses on the March 2010 analysis based on the 525 MtCO2e baseline.

Estimated Costs and GHG Emission Reductions Associated with Complementary Measures Table 5-1 summarizes ARB’s estimates of the costs and emission reductions associated with key complementary measures contained in the March 2010 economic analysis. In addition, Table 1 shows the estimated costs per tCO2e emissions mitigated by each measure.

Based on these results, the largest sources of expected emission reductions among the CPs in 2020 are the 33% RPS (20 Mt), the LCFS (14 Mt), and energy efficiency programs (12 Mt). (Note that the 20 Mt estimate for the 33% RPS in the updated economic analysis considers only incremental reductions from increasing the RPS from 20% to 33%; this estimate later was further revised down to 11.4 Mt in ARB’s July 2011 status update document.)

Other emission reduction estimates also were revised in ARB’s July 2011 update, as discussed below. The estimated costs of these programs vary significantly. The RPS is the most expensive policy, costing an estimated $5.5 billion in 2020. It is also the least cost-effective policy, with an estimated cost of $277/tCO2e. Measures to increase the use of CHP are almost as expensive on a per-tonne basis, at $274/tCO2e. Importantly, the $277/tCO2e estimate for the RPS does not include the costs for any new transmission systems needed to meet a 33% RPS. The analysis cites a $1.8 billion cost estimate made by the consulting firm E3 and the CPUC for new transmission facilities necessary to meet the 33% RPS.152 Including this additional cost – after converting it into an equivalent annualized cost – would increase the total estimated cost of the RPS.

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Table 5-1 ARB’s Estimated Costs and Emission Reductions Associated with CPs in 2020 153

33% RPS1

Energy Efficiency2

Combined Heat and

Power Pavley

II

Low Carbon

Fuel Standard

Regional VMT

Reduction Measures

Totals

Total GHG Emissions Reduction (Mt CO2e)

20 12 5 4 14 5 60

Fuel Expenditures (2007 M$/Yr)

994 -4720 -864 -1722 1316 -1945

Annualized Investment and Operating Costs (2007 M$/Yr)3

4545 1073 2233 279 512 -6736

Annual Economic Cost4

(2007 M$/Yr) 5539 -3647 1369 -1443 523 -8681 -6340

Total Cost/tCO2e ($/tCO2e) 277 -304 274 -361 131 -1736 -106

1. Costs do not include the cost of new transmission, estimated to be on the order of $1.8 billion ($2008) in 2020. 2. Costs include actual equipment upgrades associated with these efficiency gains, but not utility program and administration costs. 3. Capital costs are annualized over the lifetime of the investment using a 5 percent real-capital-recovery factor. 4. Totals are derived by the authors from estimates in Table 13 of ARB’s March 2010 economic analysis, and did not take into account any rounding that ARB may have applied to those estimates.

ARB estimates that the economic costs associated with three key CPs – energy efficiency, Pavley II, and regional VMT reduction measures – are negative, as shown in Table 1. The estimated net cost for the VMT reduction program – -$8.7 billion – is particularly striking, as it is sufficient to outweigh the positive economic costs of the RPS, the LCFS and CHP programs combined, resulting in a combined negative cost estimate of -$1.7 billion, and an overall cost effectiveness of -$106/tCO2e for the key CPs.

ARB cautions that the economic analysis “does not compute an exact measure of economic impact” and that individual CPs that will require new regulations will be evaluated in separate economic analyses.154 Given this caveat, the discussion that follows considers more recent cost and emission reduction estimates that have been prepared in relation to the programs considered in ARB, March 2010. It also highlights some assumptions and estimates in ARB’s analysis that have been questioned by other analysts, and available information on the likelihood that emission reduction targets will be achieved for these programs. This is necessary to provide additional context for ARB’s estimates, and for considering the potential impact of CPs on the cap-and-trade program and whether they will achieve their estimated level of reductions.

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Renewable Portfolio Standard CRA’s economic analysis of the SP does not appear to call into question ARB’s estimated costs or emission reductions for the 33% RPS, and notes that “intermittent resources comprise between 12%-15% of generation, suggesting integration of intermittent resources may be manageable.”155 In a February 2011 analysis, Barclay’s Capital adopted as its base case a scenario in which CA meets 75% of its RPS requirement for 2020 in light of challenges relating to planning, transmission constraints, transmission and scheduling challenges for imported renewable generation, and limits on equipment supply.156 Barclay’s maintained this base case in its October 2011 update.157

ARB revised its emission reduction estimates for CPs in its July 2011 “Status of Scoping Plan Recommended Measures.” Emission reductions from the 33% RPS were revised from 20 Mt to 11.4 Mt. It appears that the 20 Mt emission reduction estimate combined reductions resulting from the 20% RPS that already was being implemented and the incremental reductions resulting from increasing the RPS to 33%. ARB’s July 2011 estimate of 11.4 Mt considers only the incremental reductions from the 33% RPS, and takes into account changed economic conditions.158 Similar to ARB, ICF International estimates that the program will achieve 11 Mt of emission reductions in 2020, and noted that “some portion will be achieved by Tradable RECs, and will not reduce emissions in California.”159

Although good progress has been made in achieving the 33% RPS target, policy challenges and commercial issues will need to be addressed. Policies need to developed and implemented that lead to the addition of new transmission, the permitting of new facilities, and the integration of new renewables into the State’s power supply while maintaining electric system reliability. The State has developed several ongoing initiatives in an attempt to address these issues. In addition, some have concluded there is a need to simplify contract negotiations and the RPS program.

According to a review of the companies’ procurement progress reports, the State’s three large IOUs served 20.6% of their electricity with eligible renewables at the end of 2011 – a greater-than-15% increase from the 17% they had supplied by the end of 2010. Pacific Gas & Electric (PG&E) was at 20.1%. Southern California Edison (SCE) was at 21.1%, and San Diego Gas & Electric (SDG&E) was at 20.8%.160

Despite this performance, significant work remains to achieve the 33% target by 2020. In addition to existing renewable facilities continuing to supply generation, the CEC estimates CA will need to add an incremental 35,000 to 47,000 gigawatt hours to meet the target.161 The report concludes that if the facilities represented by signed and pending contracts get built and come on-line by 2020, it would be possible to do so.162 However, the estimate of potential generation from existing facilities includes contracts that may not be renewed and others from facilities that may shut down. Also, there has been a contract failure rate in the range of 30% since the start of the program, increasing to 40% when considering those that have been delayed.163 If this rate of failure occurs, electric utilities would need to contract for between 55,000 gigawatt hours (based on the 30% failure rate) to 85,000 gigawatt hours (based on the 40% failure rate) to achieve the target.

Although compliance with the 33% RPS is mandatory, there are various conditions in implementing regulations of the 20% RPS that would allow the CPUC to waive compliance penalties. If a load serving entity does not meet the conditions, it is subject to a penalty set at

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5 cents/kWh, up to a limit of $25 million. The CPUC currently is in the process of developing a rule regarding compliance with the 33% RPS which would address penalties for non-compliance.

Energy Efficiency Policies ARB’s March 2010 analysis assumes that energy efficiency programs can increase process and device efficiencies in the residential, commercial and industrial sectors, reducing electricity sales by 24,000 GWh and natural gas sales by 800 million therms by 2020.164 (The SP called for 32,000 GWh of end-use energy efficiency. This amount was reduced in ARB, March 2010, in line with updated (reduced) estimates of economic growth.165) The Energy 2020 model estimates the costs of equipment upgrades, but does not attempt to estimate program and administration costs, and assumes that “efficiency potential exists without being specific as to what market failures are being corrected by the policy intervention.”166

CRA states that attaining the targeted level energy savings from energy efficiency may require the adoption of measures that are not cost-effective at prevailing allowance prices.167 This view is consistent with the views of analysts that question the effectiveness of energy efficiency programs. As discussed in Appendix B, some analysts believe that energy efficiency program costs can be significant168, that programs can impose other economic costs that are not addressed by bottom-up estimates169, and that such estimates typically fail to provide proof of, or insights on, the market failures that energy efficiency policies are intended to address.170 These views are at odds with the findings of numerous studies concluding that energy efficiency programs yield net savings.

ARB’s July 2011 status update document estimates that energy efficiency programs, including CHP, will achieve 11.9 Mt of reductions,171 which is approximately equal to the 12 Mt estimate in the updated economic analysis, but significantly lower than the approximately 26 Mt in reductions estimated in the original SP.

Some implementation issues that are likely to affect the expected future performance of energy efficiency programs include:

• Uncertainty related to performance of energy efficiency programs. Analysts have identified several challenges associated with measuring energy efficiency program performance. These include the short-term nature of the programs, whether or not consumers increase their energy use when costs go down (referred to as the rebound effect), and if consumers will continue to implement efficiency measures when financial subsidies or incentives provided by governments or utilities come to an end.172

• Building codes and energy efficiency standards related to existing and new buildings. Appliance and building energy efficiency standards can help to reduce GHG emissions resulting from electricity and gas use. The SP describes problems in assuring compliance with, and enforcement of, these programs, particularly related to remodeled and retrofitted buildings, and recommends providing greater state resources to local governments to address these issues.173 Local government responsibility for overseeing these programs has become a greater concern recently giving ongoing resource constraints. The CEC 2009 IEPR describes the permits required for any alteration that changes the energy use of the building which includes the installation of heating, ventilation and air conditioning equipment (HVAC). The CPUC Long Term Energy Efficiency Strategic Plan reports that less than 10% of installed

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HVAC systems obtain permits, and the industry estimates that less than 5% obtain permits. The CEC IEPR concludes, “…This represents a major problem that makes it impossible for building departments to verify compliance and represents a huge lost opportunity for energy efficiency savings.”174

The CEC 2009 IEPR estimated that 30% of new residential buildings are out of compliance with the 2005 building efficiency standards, resulting in the loss of 180 gigawatts of energy saving per year.175 Addressing these challenges will be extremely difficult as city and local governments are responsible for implementing these programs, and will require additional resources to do so.

Combined Heat and Power In its economic analysis of the Scoping Plan, CRA estimates that, based on estimated allowance prices, 17 TWh of CHP would be implemented in response to a pure cap-and-trade program. This estimate is 43% lower than the 30 TWh estimated to result from implementation of the complementary policy.176 CRA concludes “…it appears impossible to achieve the 30,000 TWh goal using only cost-effective CHP projects.”177 CRA’s assessment raises questions about the potential for the CHP complementary policy to achieve the 5 Mt of GHG emission reductions estimated by ARB, or at least the ability to cost-effectively achieve these emissions reductions. This is consistent with the estimate shown in Table 5-1 that emission reductions from CHP programs may cost $274/tCO2e. In its July 2011 status update report, ARB reduced its emission reduction estimate for CHP programs to 4.8 Mt.178

Pavley II (Light-Duty Vehicle GHG Performance) standards In its comments on ARB’s March 2010 analysis, the EAAC expressed the view that the cost assumptions associated with the Pavley II standards are likely to be optimistic, because they are more stringent than federal fuel economy standards, and achieving incremental fuel economy improvements would entail higher capital costs than ARB assumed.179 The EAAC also notes that the creation of more stringent fuel economy standards in CA can lead to emissions leakage because automakers would be able to sell cars with lower performance outside of CA, and still meet the federal standard through averaging. It is possible that these points have been overtaken by the announcement by ARB that it would review its regulation and allow compliance with the federal standard to satisfy the Pavley II standards.180 Moreover, the National Highway Traffic Safety Administration estimated that the new federal Corporate Average Fuel Economy standards for model years 2017-25 would result in $7 -$17 billion in cumulative net benefits, with fuel savings outweighing the costs of technological improvements.181 This would appear to validate the notion that fuel economy standards can be a relatively cost-effective source of GHG emission reductions.

Low Carbon Fuel Standard As discussed earlier in this section, CRA concluded that fuels qualifying for the LCFS are likely to have limited availability in the 2015-20 period, and that this may force emission reductions to be achieved by reductions in fuel consumption (via increased gasoline prices), and a switch to plug-in hybrid electric vehicles and electric vehicles, leading to an increase in overall AB 32 compliance costs of over 40%.182,183

With respect to the availability of certain fuels, ARB has revised earlier views that informed the LCFS cost and emission reduction estimates in the updated economic analysis. In December

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2011, ARB and its LCFS Advisory Panel noted that in 2009-11, mandated and projected volumes of cellulosic ethanol had been drastically reduced from levels established by Congress.184 ARB’s economic analysis in 2009 for the proposed regulation to implement the LCFS assumed CA would receive its proportional share of the cellulosic ethanol volumes mandated in the federal RFS2.185 To reflect this change in the emerging markets for low-carbon fuels, ARB prepared updated illustrative scenarios describing how the 2020 LCFS target could be met using different combinations of fuels.186

Although ARB staff believes the scenarios are feasible, petroleum fuel providers on ARB’s LCFS Advisory Panel believe there will not be sufficient supply of low carbon fuels to meet targets. In addition, a group of panelists suggested that ARB consider a flexible compliance mechanism that would come into effect if limited supplies of low carbon fuels or LCFS credits in the market prevent regulated parties from meeting compliance obligations.187 ARB said that such a mechanism could “…provide greater confidence in near-term investment decisions that are predicated on a sustained requirement that the anticipated amounts of low carbon fuels will be required in later years and that the LCFS compliance obligation will be maintained.”188

ARB’s decision to consider such a mechanism in greater detail may suggest there is a fair amount of uncertainty about the attainability of the LCFS targets. ICF has noted that, of all the emission-reducing measures in the SP, the LCFS is the “biggest wildcard.”189 Indeed, there is a very broad range of estimated costs per tCO2e reduced for renewable fuel substitutions, with some estimates of more than $500/tCO2e and others as low as -$300/tCO2e.190

Another analysis191 suggests that the LCFS may only be able to deliver 0.4 Mt of emissions reductions, rather than the 14 Mt of emission reductions estimated in ARB’s March 2010 analysis (or the 15 Mt estimated in ARB’s July 2011 status update192). This PhD dissertation also estimated that this relatively small amount of LCFS-related emissions reductions would be achieved at a total cost of approximately $33 billion over the 2010-20 decade,193 or $3.3 billion per year, based on a wide range of potential scenarios and best estimates of various uncertainties.

A further concern about the LCFS raised by the EAAC and others is that it could divert some low carbon fuel to CA that otherwise would have been consumed elsewhere in the U.S., leading to higher emissions outside of CA than would be the case in the absence of the LCFS.194 Like the emissions leakage issues relating to electricity imports, leakage associated with the LCFS raises questions about the ability of a sub-national jurisdiction, such as CA, to reduce its GHG emissions without unintentionally increasing GHG emissions outside its borders.

In addition to these concerns, legal actions against the LCFS ultimately may prevent or delay its implementation. Plaintiffs in a lawsuit contend that the LCFS violates the interstate commerce clause of the Constitution because it discriminates against imported fuels by counting in these fuels’ carbon intensity score the emissions associated with transporting fuels to CA. An injunction of the LCFS was imposed in early 2012, but was removed in April 2012, allowing the State to implement the standard pending a final decision in the case. The Ninth U.S. Circuit Court of Appeals heard arguments from ARB and plaintiffs in October and as of this writing have not issued their decision.195

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Regional VMT reduction measures As noted above, ARB estimates that regional VMT reduction measures will reduce costs – mainly those associated with automobile purchases and fuel use – by $8.7 billion, which is more than two times the combined net savings estimated for the five other principal complementary measures. These supposed net economic savings are the key driver of an important outcome of ARB’s economic analysis. Because of these large savings, ARB estimates the five principal CPs with the largest emission-reduction impacts have net negative expected costs, or equivalently, net economic benefits. With respect to the 5 Mt of emission reductions attributed to regional VMT reduction measures, the economic analysis states that “no assumptions were made with regards to how this reduction would be achieved. For example, an increase in public transit use was not assumed in the modeling.”196 However, as noted by the EAAC, achieving regional VMT reductions is likely to require new transit systems, restrictions on land use, or other costly measures that are not accounted for in ARB’s estimated net savings of $8.7 billion.197

ARB’s July 2011 status update does not explicitly revise the estimate of 5 Mt of emission reductions to be achieved from regional VMT reduction measures, but does cite an estimate of 3 Mt. This reportedly represents “the aggregate from the regional passenger vehicle GHG reduction targets established for the 18 Metropolitan Planning Organizations approved in 2010.”198

Potential Impacts to GHG Allowance Prices Due to Lower-than-Expected Emission Reductions from Complementary Policies In its March 2010 economic analysis, ARB conducted sensitivity analyses to explore how allowance prices in the cap-and-trade program, and overall economic costs, might be impacted if CPs deliver fewer emission reductions than expected. ARB considers five cases, as follows.

• Case 1: Cap-and-Trade with Offsets (i.e., all CPs shown in Table 1 achieve their emission reduction target by 2020);

• Case 2: Cap-and-Trade without Offsets (identical to Case 1, but with no use of offsets);

• Case 3: Transportation Policy Sensitivity with Offsets (i.e., the LCFS and Pavley II achieve 50% of their expected emission reductions, regional VMT reductions are excluded (i.e., they are absent from the analysis, and achieve zero reductions), and other CPs achieve their expected emission reduction targets;

• Case 4: Electricity and Natural Gas Sensitivity with Offsets (i.e., energy efficiency and CHP achieve 50% of their expected emission reductions, 33% RPS is excluded, and other measures achieve their targets;

• Case 5: Combined Sensitivity with Offsets (33% RPS and regional VMT reduction are excluded, and other measures achieve one-half of their expected emission reductions).

ARB’s analysis provides estimated allowance prices for each of these scenarios, and estimated cumulative emissions abatement from the CPs, the cap-and-trade program, and offsets from 2012-2020, which are recreated below in Table 5-2.

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Table 5-2 ARB’s Estimates of Allowance Prices, Impact on Gross State Product, and Cumulative Abatement under Different Scenarios199

Case 1 Case

Case 3 Case 4 Case 5

Allowance price in 2020 ($/tCO2e) 21 106 40 87 102

Gross State Product (% change from 2020 reference case -0.2% -0.9% -1.0% -0.8% -1.4%

Cumulative abatement, 2012-20 (Mt) and % of cumulative abatement

From CPs 319.2 (63%)

319.2 (63%)

234.1 (49%)

202.3 (42%)

136.8 (30%)

From reduced economic growth 4.1 (1%)

20.3 (4%)

23.9 (5%)

18.0 (4%) 32.3 (7%)

From covered sources due to cap-and-trade

99.9 (20%)

170.0 (33%)

118.0 (25%)

166.7 (34%)

180.1 (39%)

From offsets due to cap-and-trade

86.8 (17%) 0 (0%) 102.2

(21%) 98.6

(20%) 111.0 (24%)

Cumulative GHG abatement In Cases 1 and 2, CPs achieve their expected emission reductions, and account for 63% of cumulative abatement. In the other three cases, complementary measures do not achieve expected levels of emission reductions. In Case 3, in which policies targeting transportation sector emissions do not achieve their estimated level of reductions, the percentage of cumulative abatement associated with the CPs declines to 49%. This percentage decreases even further, to 42%, in Case 4, in which energy efficiency and CHP deliver only one-half of expected reductions, and the RPS delivers zero reductions. In Case 5, transportation and electricity/natural gas-related policies both fail to perform as estimated in the Base Case, and the percentage of abatement associated with the CPs declines to 30% in this case. In short, cumulative abatement resulting from CPs declines from approximately 319 Mt in Case 1 to approximately 137 Mt in Case 5 – a decline of more than 180 Mt. The abatement attributed to cap-and-trade ranges from 20% in Scenario 1 to 39% in Scenario 5. It increases from approximately 100 Mt in Case 1 to approximately 180 Mt in case 5.

Figure 5-1 illustrates how emission reductions from the cap-and-trade program and offsets adjust to changes in the performance of CPs targeting emissions in covered sectors. In Case 2, the prohibition on offset use results in a higher level of abatement from covered sectors than in Case 1. In Case 5, emission reductions from CPs decrease significantly, requiring covered sectors to increase their emission reductions under the cap-and-trade program. This additional burden, however, is shared with offsets. Emission reductions from offsets increase relative to Case 1, and are able to do so because offset use is not at the maximum level in Case 1. The quantitative impacts on covered sector emission reductions of these and other factors, such as the level of economic growth in covered sectors, and whether the APCR is used, are explored further in Section Six.

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Case 1 Case 2 Case 5

MtC

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Reduced Economic Growth

C&T

Offsets

Figure 5-1 Cumulative GHG Emission Reductions from CPs, Cap-and-Trade and Offsets, as shown in ARB’s March 2010 Analysis

GHG emissions offsets The estimates of offset use in ARB’s March 2010 analysis are far lower than the 218 Mt offset use limit in the final cap-and-trade regulation because the analysis limited offset use to 49% of emission reductions below initial cap levels, as assumed in the December 2008 Scoping Plan. ARB calculated that this limit theoretically could range from about 80 Mt to 120 Mt.200 The offset use limit in the cap-and-trade program was later changed to 8% of each entity’s compliance obligation, or approximately 218 Mt on a cumulative basis from 2013-20. As a result, the ARB March 2010 analysis’ estimates of offset use (in scenarios in which offset use is allowed) range from 86 Mt to 111 Mt.

In scenarios in which CPs fail to deliver their expected level of emission reductions, ARB estimates that offset use will increase. In Case 5, offset use rises to 24% of cumulative abatement, from 17% in Case 1. Offsets therefore are assumed to fill the void left by CPs that fail to achieve their estimated emission reductions, subject to the maximum offset use limit, and to the extent they are cost-effective and available. (Regarding availability, ARB assumes that offsets will not be available at prices of $8 or less in 2020.) If offsets are not able to fill the void left by CPs that fail to achieve their estimated emission reductions, covered sources in the cap-and-trade would necessarily achieve more of the reductions required to meet the targets.

In Case 2, which is identical to Case 1 with respect to performance of CPs but assumes no use of offsets, allowance prices increase to $106 from $21/tCO2e in Case 1 – a five-fold increase. As noted above, ARB’s analysis assumes an offset usage limit equal to 49% of the reductions from the cap, as originally proposed for the cap-and-trade program.201 This limit translates to approximately 4% of a covered entity’s compliance that can be addressed using offsets, or one-

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half of the 8% limit adopted in the final cap-and-trade regulation.202 The incorporation of the (lower) 4% offset use limit in the updated economic analysis could produce an upward bias in its allowance price estimates – all else being equal – because the (higher) 8% offset use limit likely would have reduced the marginal cost of abatement in the cap-and-trade program. However, as discussed in Section Six, a number of analyses project that offset supply will fall far short of the 8% offset use limit. As a result, ARB’s March 2010 assumptions on offset use could be relatively close to actual offset use, based on available supply estimates.

GHG emissions allowance prices Table 5-2 illustrates that estimated allowance prices are likely to increase significantly if complementary measures do not deliver their expected levels of emission reductions, and the covered sources in the cap-and-trade program must achieve additional emissions reductions. To illustrate this situation further, we can consider Case 5, in which the CPs achieve their lowest levels of emission reductions. Case 5 assumes that CPs achieve only 30% of cumulative emission reductions , compared to 63% in Case 1. In this case, the cap-and-trade program acts as a backstop for the overall program, and is required to effectively compensate for the shortfall in emissions reductions achieved by the complementary policies. This increases the cumulative emission reductions to be achieved from the cap-and-trade program from 99.9 Mt in Case 1 to 180.1 Mt in Case 5, resulting in an increase of the percentage of overall emissions reductions attributable to the cap-and-trade program from 20% to 39%. As a consequence of the additional emission reductions needed to be achieved in Case 5 under the cap-and-trade program, 2020 allowance prices are estimated to increase to $102/tCO2e – approximately 5 times the $21 allowance price estimated for Case 1. As noted in ARB, March 2010,

“Successful implementation of the complementary measures has the effect of reducing emissions for sources covered by the cap-and-trade program, meaning that fewer emissions reductions need to be found through the cap-and-trade mechanism than would otherwise be the case. Less effective implementation of these measures results in a small negative effect on the economy both through increased allowance prices and through the lack of cost savings that derive from many of the complementary measures in the main policy case.”203

Charles River Associates Economic Modeling Estimates CRA used its integrated MRN-NEEM model to analyze the SP measures. The MRN (Multi-Regional National) model is a “forward-looking dynamic CGE [computable general equilibrium] model of the U.S.,” and the NEEM (North American Electricity and Environment Model) is a “partial equilibrium model of the continent’s electricity market that can simultaneously model system expansion and environmental compliance.”204

In its summary report, CRA provided relatively few estimates allowing for direct comparisons with ARB estimates for most scenarios. However, the conclusions of the report illustrate analysts’ differing views regarding the impacts of CPs on the overall costs of a climate control program that also includes a GHG cap-and-trade program.. These conclusions are consistent with the views expressed by other analysts, as discussed further in Appendix B. For example, in a recent analysis, Ann Carlson of UCLA’s School of Law contends that complementary

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measures adversely impact the performance of a cap-and-trade program by reducing overall flexibility.

When CRA adopted the same assumptions as those in ARB’s case 1 (i.e., CPs achieve their expected level of emission reductions, and offsets may be used for compliance), CRA estimated that allowance prices would be approximately $52/tCO2e or 148% higher than ARB’s estimate of $21/tCO2e, based on CRA’s cost assumptions regarding alternative transportation fuels and the availability of CHP.205 The estimated “social cost” of this scenario (i.e., the total economic cost of the scenario) from 2012-20 would be approximately $95 billion (no directly comparable estimate is provided by ARB).206

CRA also provided estimates for a scenario (CRA scenario 8c) not considered by ARB – a scenario completely without complementary measures, meaning that the targets would be achieved entirely through a cap-and-trade program.207 It estimated that allowance prices would be approximately $78/tCO2e, versus ARB’s estimate of $102 for case 5 (case 5 assumes 57% less emission reductions from complementary measures than case 1, and is the closest approximation to scenario CRA 8c).208 Social cost resulting from the program would be approximately $47 billion, or approximately 50% of the cost of case 1, which includes a full set of complementary measures.209 However, allowance prices would be 50% higher in this scenario than in Scenario 1. These findings illustrated CRA’s view that complementary measures significantly increased the overall cost of the program compared to a pure cap-and-trade program even though they result in lower allowance prices.

In contrast, the effect of adding in complementary measures in ARB’s analysis was to reduce the costs of the program. For example, as shown in Table 2, the estimated change in gross state product in case 5 (which assumes 136.8 Mt of emission reductions from complementary measures) is -1.4%. This loss is significantly greater than the -0.2% estimated for case 1, in which complementary polices achieve 319.2 Mt of reductions. CRA also concludes that complementary measures result in increased costs also has implications for the effectiveness of offsets. Based on its different scenarios, CRA concluded that offsets are less effective in reducing costs when CPs are implemented, “because offsets cannot undo the effect of costly regulatory requirements and mandates.”210

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6 IMPLICATIONS OF COMPLEMENTARY POLICY PERFORMANCE AND OTHER VARIABLES FOR CAP-AND-TRADE COMPLIANCE STRATEGIES Electric power companies confront a wide range of risks and uncertainties in the context of their ongoing operations, and their planning for compliance with multiple environmental and energy regulations. The development and implementation of a risk management strategy to comply with GHG emissions limits may be similar to the process for assessing, monitoring and managing many other business risks. In general, a regulated firm will assess its risks associated with GHG emissions limits – e.g., the risk that allowance prices, fuel prices, and/or electricity prices will change unexpectedly – and will try to develop a robust and cost-effective risk management strategy to mitigate it. The company then will adopt the strategy to accommodate new knowledge and information.

Developing and implementing a strategy to mitigate risk to AB 32 may present some unique challenges that could be more difficult to manage than the risks associated with other environmental issues. As discussed throughout this report and in this section, there is significant uncertainty with respect to several variables that are likely to impact allowance prices and overall compliance costs. It may be particularly difficult to predict the combined effect of different variables on allowance prices. In addition, regulatory constraints and other circumstances facing firms that are regulated differently in the electric power sector may prevent the implementation of optimal risk management strategies. This could expose firms to risks relating to the performance of CPs and other variables. Based on discussions with electric power companies in CA, there are varying levels of concern about these potential risks, but they are generally acknowledged as factors that companies need to incorporate in their compliance planning.

This section identifies and discusses a set of risks and uncertainties relating to the performance of complementary measures, and other variables that will affect the volume of abatement that must be achieved by the cap-and-trade program. It then considers the context in which IOUs will confront these risks as they plan their compliance, with a focus on rules relating to IOUs’ trading and compliance activity.

Scenarios that will Impact Electricity Company Compliance Planning As discussed in Section Five, regulated firms that are required to comply with CA’s GHG emission limits in the cap-and-trade program may need to plan for two different scenarios with respect to the performance of complementary measures. Complementary measures could under-perform relative to their estimated level of emission reductions for a number of reasons as discussed earlier. In this scenario, emissions in covered sectors would increase due to the failure of complementary policy to achieve estimated reductions. If this occurs, allowance prices likely would rise above forecasted levels. Alternatively, complementary measures could over-perform, achieving more emission reductions than expected. In this scenario, allowance prices would

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likely be lower than expected. This could occur if ARB’s aggregate estimate of emission reductions from CPs is too conservative (i.e., low).

In addition to the question of the performance of CPs, other variables will affect the level of required emission reductions, and allowance prices, in the cap-and-trade program. These include the performance of the CA economy relative to the assumptions reflected in ARB’s BAU emissions baseline estimate incorporated in its economic modeling of AB 32; the supply of offsets available in the market; and the performance of CPs in jurisdictions with cap-and-trade programs that will be linked to CA’s program, such as Quebec. In addition, the use or non-use of allowances held in the APCR also may have a direct impact on the required emissions reductions necessary to be achieved in the covered sectors.

Table 6-1 identifies a number of variables affecting the level of GHG emission reductions to be achieved in the cap-and-trade program, and illustrates their likely impact on allowance prices, all else being equal. After the table, scenarios are used to illustrate the impacts of these variables.

Table 6-1 Variables Affecting the Level of Emission Reductions to be Achieved in the Cap-and-Trade Program

Variable and Performance Scenario

Increases Allowance Prices in

2020

Decreases Allowance Prices in

2020 CPs fail to achieve estimated emission reduction targets X

CPs exceed estimated emission reduction targets X

Offset supply is significantly lower than the maximum use limit of 218 Mt X

Offset supply is sufficient to meet the maximum use limit X

Economic and emissions growth is higher than forecasted X

Economic and emissions growth is lower than forecasted X CPs in jurisdictions with linked cap-and-trade programs fail to achieve estimated emission reduction targets X

CPs in jurisdictions with linked cap-and-trade programs exceed estimated emission reduction targets X

Complementary policies fail to achieve estimated emission reduction targets Some factors that could lead to CPs under-performing against their estimated emissions reduction targets are discussed in detail in Sections Three and Five. For example, the LCFS may not be met due to insufficient supply of eligible low-carbon fuels. The 33% RPS may not be met due to various policy-related issues such as transmission constraints, transmission and scheduling challenges for imported renewable generation, challenges in siting new facilities, and commercial issues such as high contract failure rates. Energy efficiency policies may not achieve estimated levels of emission reductions due to challenges in enforcement and in monitoring compliance and consumer behavior.

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Figure 6-1 illustrates how the performance of CPs impacts the emissions baseline for covered sectors in the cap-and-trade program. In 2020, BAU emissions are forecast to be 409 Mt. If CPs targeting emissions in covered sectors achieve their estimated emission reductions of 49 Mt, emissions in covered sectors will be reduced to approximately 360 Mt. In the extreme scenario in which CPs fail to achieve any emission reductions, covered sector emissions will remain at 409 Mt. In this scenario, the cap-and-trade program would need to reduce emissions by 75 Mt to meet the program’s gross cap of 334 Mt in 2020, and by 98 Mt to meet the program’s net cap of 311 Mt in 2020. The net cap accounts for the 122 million allowances that are used to fund the APCR.

Figure 6-1 Impact of CPs on BAU Emissions in Covered Sectors

On a cumulative basis in 2013-20, covered sectors would need to achieve cumulative emission reductions of 273 Mt to meet the program’s gross emissions cap, and 395 Mt to meet the program’s net emissions cap (see Figure 6-2). As discussed in Section Three, the net cap would need to be met if allowance prices never rise to levels that trigger the use of the APCR. Covered sectors only would need to meet the gross cap only if the APCR were completely used in each year, and all APCR allowances were released into the market.

334.2

408.8

310.8

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2013 2014 2015 2016 2017 2018 2019 2020

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Baseline Shift

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Figure 6-2 Emissions Abatement in Covered Sectors if CPs Achieve Zero Reductions

Based on these figures, the level of cumulative abatement in covered sectors can vary up to a factor of four. As shown in Figure 6-3, if CPs targeting covered sector emissions achieve their estimated level of reductions, BAU emissions in 2020 will be approximately 359 Mt. If the APCR is completely used in 2013-20, covered sectors must meet the gross cap, and would need to reduce emissions to 334 Mt in 2020, or by only 25 Mt. In this scenario, cumulative abatement in 2013-20 would be 97 Mt. This is only one-quarter of the 395 Mt of cumulative abatement that would need to occur if CPs achieved zero reductions and the APCR was never used in 2013-20. The wide range of potential abatement in covered sectors (97-395 Mt) and uncertainties relating to the performance of CPs, offset supply, economic growth and other factors pose unique challenges to regulated entities as they plan for compliance, as further discussed below.

408.8

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Figure 6-3 Abatement in Covered Sectors Depends on CP Performance and the APCR

Figures 6-4 and 6-5 illustrate how emission reductions from covered sectors may vary in response to lower-than-expected emission reductions from CPs. In Figure 6-4, it is assumed that covered sectors must reduce emissions from the BAU level of 409 Mt to the net cap of 311 Mt, or by 98 Mt (i.e., it is assumed that the APCR is not used). In this “base case” scenario, CPs targeting covered sector emissions achieve their estimated level of emission reductions in 2020 – 49 Mt – and account for 50% of emission reductions by covered sectors. The maximum allowable volume of offsets consistent with the 8% offset usage limit – 29 Mt – is assumed to be available. Covered sectors under the cap-and-trade program then must address the remaining gap of 20 Mt, which is equal to approximately 20% of compliance.

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Figure 6-4 CPs Achieve Estimated Emission Reductions, and Maximum Volume of Offsets is Available (MtCO2e)

Figure 6-5 2020 Base Case Compliance Scenario (Emissions to Net Cap)

Figure 6-6 illustrates how abatement in the cap-and-trade program may be impacted by the failure of CPs to achieve their estimated emission reductions. In this scenario, it is assumed that: (i) CPs targeting covered sector emissions achieve only 33 Mt of reductions, or two-thirds of

Covered Sectors: 20

Offsets: 29

Pavley II: 3.8

LCFS: 15

Regional VMT: 3

Energy Efficiency: 7.8

CHP: 4.1

RPS 33%: 11.4

Complementary Policies: 49

6 10 28 40 52

75 86 98

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ARB’s 49 Mt estimate; and, (ii) the maximum allowance volume of offsets (29 Mt) is available. In this circumstance, covered sectors must compensate for the shortfall in emission reductions from CPs, and increase their emission reductions from 20 Mt in the base case to 36 Mt, or by 80%. The sharp increase in abatement in the cap-and-trade program could be expected to result in a potentially significant increase in allowance prices. As discussed in Section 5, the cap-and-trade program acts as a backstop, ensuring that the program’s hard cap is reached, even if CPs under-perform. Here, CPs’ share of emission reductions declines to 34% from 50% in the base case, and covered sectors’ share increases from 20% in the base case to 37%. As discussed below, if available offset supply is lower than 29 Mt, covered sectors must further increase their level of emission reductions.

Figure 6-6 CPs Under-achieve, and Maximum Volume of Offsets is Available (MtCO2e)

Complementary policies exceed estimated emission reduction targets If complementary policies achieve emission reductions that exceed ARB’s estimates, the cap-and-trade program’s emission reduction requirements will decline. In Figure 6-7, CPs targeting covered sector emissions achieve 56 Mt of abatement, or 15% more than the 49 Mt estimated by ARB. If the maximum level (29 Mt) of offsets is available, covered sectors only would be required to reduce emissions by 13 Mt, which is 35% lower than the 20 Mt of abatement in the base case. The lower level of abatement likely would result in lower allowance prices. These trends would be further reinforced if economic and emissions growth were lower than forecast, or nuclear and hydroelectricity generation were higher than forecast, as discussed below. This would result in significant downward pressure on allowance prices, which presumably would approach the auction price floor.

Covered Sectors: 36

Offsets: 29

Pavley II: 2.9

LCFS: 7.5

Regional VMT: 2.3

Energy Efficiency: 5.9

CHP: 3.1

RPS 33%: 8.6

CPs: 33

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Figure 6-7 CPs Over-achieve, and the Maximum Volume of Offsets is Available (MtCO2e)

Offset supply is significantly lower than the maximum allowed use limit Existing analyses of expected cumulative offset supply from 2013-20 for the CA market range from 66 Mt to 140 Mt, which is far below the 218 Mt maximum use limit for the period. For example, the American Carbon Registry (ACR) estimates that there will be a 67% (134 Mt) shortage of offsets by 2020 if demand reaches the offset use limit. ACR estimates the maximum allowable usage limit at just over 200 Mt. The 67% shortage estimate is based only on the four existing offset protocols, and implies a cumulative supply of approximately 66 Mt (i.e., 200 Mt – 134 Mt). If three additional protocols are approved (low-bleed pneumatic valves, CMM, and rice management), ACR estimates that approximately 130 Mt of cumulative supply will be available.211 Other estimates of supply include Barclay’s212 (140 Mt, based on existing protocols) and Point Carbon/Thomson Reuters213 (89.5 Mt, based on existing protocols, to 121 Mt, assuming the addition of CMM, rice management, and nitrogen management in agriculture).

Based on these estimates, offset supply could be far lower than the use limit if ARB does not approve new protocols that can generate significant additional supply, and if allowance prices are not high enough to bring large volumes of forestry offsets into the market. As shown in ARB’s modeling in Section Five, the availability of offsets is a key determinant of allowance prices. ARB’s case 1 and case 2 both assume that CPs achieve their emission reduction targets, but case 1 assumes assume full use of offsets and case 2 assumes no offsets are used for compliance. In case 2, allowance prices increase to $106/tCO2e from $21 in Case 1.

Figure 6-8 illustrates how a combination of lower-than-expected emission reductions from CPs and limited offset supply would impact the level of emission reductions that the cap-and-trade program must achieve. In this scenario, CPs deliver 33 Mt of abatement, as assumed in Figure 6-5, but only 20 Mt of offsets are available, rather the maximum of 29 Mt. This would

Covered Sectors: 13

Offsets: 29

Pavley II: 4.4

LCFS: 17.3

Regional VMT: 3.5

Energy Efficiency: 9.0

CHP: 4.7

RPS 33%: 13.1

CPs: 56

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force covered sectors to increase abatement from 20 Mt in the base case to 45 Mt, or 126%. This sharp increase in covered sector emission reductions likely would put significant upward pressure on allowance prices. If prices reached levels triggering the use of the APCR, the release of allowances into the market could mitigate the price increase.

Figure 6-8 CPs Under-perform, and Offset Supply is Limited (MtCO2e)

Offset supply is sufficient to meet the offset use limit If allowance prices are sufficiently high to attract large forestry offset projects to the market, supply could increase significantly. In addition, if ARB approves other offset protocols for project types with significant supply potential, this will change market expectations. For example, Barclay’s notes that ARB could give a large boost to supply if it approved offset protocols for CMM and landfill methane. However, the latter is currently regulated, and therefore less likely to become an eligible offset category.

Economic and emissions growth is higher than forecasted This scenario could arise because the pace of the economic recovery is difficult to accurately predict, and future economic growth could be higher than estimated. Higher economic and emissions growth would result in higher allowance prices.

Economic and emissions growth is lower than forecasted Some believe that even ARB’s revised 2020 BAU baseline of 507 Mt is too high because it was based on a report (the 2009 IEPR) which was said to have underestimated the duration of the recession. If BAU emissions prove to be lower than ARB’s forecast, fewer emission reductions will be required to meet the cap, and allowance prices will be lower than forecasted.

Covered Sectors: 45

Offsets: 20

Pavley II: 2.9

LCFS: 7.5

Regional VMT: 2.3

Energy Efficiency: 5.9

CHP: 3.1

RPS 33%: 8.9

CPs: 33

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Complementary policies in jurisdictions with linked cap-and-trade programs fail to achieve estimated emission reduction targets If CA links its cap-and-trade program with its WCI partner jurisdiction Quebec, which it is in the process of doing, then variables that affect Quebec’s allowance price are expected to have some impact on CA’s allowance price. For example, if Quebec adopts an LCFS or other policies to address its transportation emissions (in addition to its fuel efficiency standards, which are similar to CA’s214), then any under-performance of the transportation policies will lead to higher allowance prices in Quebec. This would likely increase CA allowance prices, all else equal. In addition, higher-than-expected economic growth in Quebec would lead to higher emissions and would put upward pressure on CA allowance prices.

Complementary policies in jurisdictions with linked cap-and-trade programs exceed estimated emission reduction targets Performance of Quebec’s CPs could exceed expectations, leading to lower allowance prices. This scenario could reduce allowance prices in CA. In addition, lower-than-expected economic growth in Quebec would lead to lower emissions, and in turn would put downward pressure on CA allowance prices.

Implications of Complementary Policy Performance and Other Variables for Cap-and-Trade Compliance Planning Regulated firms’ assessments of these variables will inform the development of their compliance strategies. For example, a firm may develop central estimates for each of the variables considered above, and may incorporate them in its own models to forecast future emission reduction requirements and allowance prices. Firms will consider other issues as well, including but not limited to, the timing and magnitude of emission reductions they will achieve through CPs; and, the availability, timing and cost-effectiveness of non-mandated emission reductions that can be achieved in the firm’s own assets. Based on these and other assessments, firms will develop a risk management strategy that likely will include a mix of internal reductions and purchases of allowances and offsets in the market to comply with its emissions limit in the current and subsequent compliance periods.

Given the uncertainties surrounding these variables, and their nature (i.e., they are not random variables for which relevant historic data points are available), it will be challenging for firms to estimate risk (e.g., standard deviation) for these variables, and how they will relate to one another over time (e.g., covariance). This situation may not be uncommon in compliance planning, but it will affect firms’ confidence in their compliance strategies, and may influence behavior. This may be particularly relevant for IPPs, which are not guaranteed a return on investment, and are the entities most exposed to the consequences of failing to manage price risk effectively.

Regulatory Requirements Create Additional Risk Management Challenges for IOUs The preceding discussion identifies scenarios that may make it difficult for electric companies to develop an effective risk management strategy for complying with their requirements under the cap-and-trade program. In addition, decisions by the CPUC could make risk management even

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more challenging for IOUs. In an April 2012 decision, the CPUC established rules governing IOUs’ purchase and use of allowances and offsets for compliance. In part, the decision215 specified the following:

• Pacific Gas and Electric Company (PG&E), Southern California Edison Company (SCE), and San Diego Gas & Electric Company (SDG&E) may procure allowances via forward and futures contracts (subject to conditions), but may not purchase derivatives (e.g., options and swaps);

• These companies’ purchases of allowances, allowance futures and forwards, and offsets and offset forwards are subject to separately calculated Direct Compliance Obligation Purchase Limits and Financial Exposure Purchase Limits established in the decision. The former Limits set constraints on how many instruments may be bought or sold over a given time period.

• They may not enter into bilateral transactions or use brokers outside of an RFO (Request for Offers);216

• They may only procure offsets certified by ARB, and only through an RFO process; and,

• They may purchase offsets only if the seller contractually assumes the risk of invalidation.

These restrictions limit the ways an IOU can manage risk and potentially reduce compliance costs. For example, restrictions on the use of options or swaps eliminate an important tool for managing price risk. Limits on purchased volumes of offsets and allowances restrict companies’ ability to hedge price and volume risk. In addition, the prohibition on bilateral transactions and the use of brokers to procure compliance instruments can potentially limit IOUs’ options to evaluate a portion of the market that could be favorable.

The particular constraints within which IOUs will sell and buy allowances create additional challenges for managing price risk. Allowance allocations to IOUs must be consigned (sold) through the State allowance auction. The value of the proceeds is provided to IOUs’ customers – not shareholders – to compensate them for increased electricity prices.217 To ensure compliance, IOUs must purchase allowances in the auction, or exchanges, subject to conditions in the CPUC’s decision. Prices will fluctuate between the time an IOU sells allowances at auction and the time that it purchases allowances and offsets. During this time when the IOU is exposed to price risk, it will not be able to use options or swaps. This is one context in which uncertainties relating to complementary policy performance become even more challenging for IOU risk management activities.

In addition, the requirement that the offset seller must assume the risk of offset invalidation will increase the cost of offsets – because sellers that take on that risk will charge a premium to do so. For example, so-called “golden offsets” in the CA market for which the offset seller assumes liability typically trade at a premium to regular offsets in which the buyer accepts potential future liability.

The higher cost of offsets with “invalidation risk guarantees” reduces their value to IOUs as a lower-cost alternative to allowances. To avoid the higher cost of “seller-guaranteed” offsets, IOUs may seek to focus their offset purchases on offsets that have received two validations and so become “golden.” Offsets created from ODS projects that are validated by two different

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accredited validators within the first three years of offset issuance are no longer subject to potential invalidation by ARB.218 ARB may invalidate offsets created from any of the other three eligible offsets project types – livestock, forestry and urban forestry projects – within eight years of issuance of an ARB offset credit, if the following conditions are met: (i) the invalidation takes place within the project’s first three reporting periods (typically three years, although the initial period may be as short as six months or as long as two years); and, (ii) an Offset Project Data Report for the project issued subsequent to the first Report was not verified by a different verification body, and did not receive a Positive Offset Verification Statement or a Qualified Positive Offset Verification Statement within three years of issuance of the offset credit.219

Since there is no invalidation risk for such projects, sellers would not need to include in the offset price a premium associated with their invalidation risk exposure. On the other hand, demand for such offsets is likely to be high, given their lower risk profile. This is likely to reduce the price spread between them and “seller-guaranteed” offsets which have not been validated twice.

It should be noted that the IOUs are well-placed to carefully monitor and predict the performance of CPs addressing electricity sector emissions, as they implement energy efficiency programs and contract for renewable energy, RECs and CHP. However, with respect to CPs addressing transportation sector emissions, such as the LCFS and Pavley II standards, IOUs likely will not have insights on likely performance comparable to those of companies in the oil & gas and biofuels sectors. Furthermore, based on questions about the ability to meet the LCFS target, and ARB’s decision to consider the use of alternative compliance payments for the LCFS, it appears that LCFS performance will be particularly difficult to predict. As a result, IOUs are exposed to the risk that allowance prices will change in response to unexpected events relating to CPs’ performance.

Additional Perspectives and Areas for Further Research One reason why the debate over the value of including CPs in conjunction with a cap-and-trade program may have received little critical attention to date is that, unlike many debates over energy and environmental policies, this debate is a relatively new one. In addition, many of the issues and related arguments – such as the incremental costs and benefits of implementing energy efficiency programs when a cap-and-trade program is in place – are the primary domain of economists. Policymakers could benefit from gaining a better understanding of the divergent views of economists and other technical specialists, and from efforts to identify areas of disagreement and others requiring further analysis. In this context, it is important to recognize there is a fairly strong consensus among policymakers regarding the benefits of reducing energy use, and the cost-effectiveness of energy efficiency programs relative to most other GHG mitigation options. Energy efficiency programs generally have been favorably viewed by policymakers over the past several decades compared to other options available to achieve energy and environmental policy objectives.

Carlson, 2012 lays out a case for energy efficiency programs that appears to present relatively little “downside” to some observers – i.e., even if there are uncertainties about the nature and extent of market failures and the incremental effectiveness of energy efficiency policies relative to cap-and-trade, they appear to be a relatively cost-effective way to address the efficiency gap

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and access more low-cost abatement opportunities. If this is true, then perhaps more is at stake in the debate over other CPs, which appear to entail higher costs.

For example, RPSs are being implemented throughout the U.S. and in other countries. Supporters of these policies point to the supposed co-benefits of these programs, such as fuel diversity, reduced air pollution, potential job creation, exports, and avoiding locking-in carbon intensive technologies. Furthermore, some may argue that implementing an RPS ensures that cost-effective abatement options will be available in the future, and that it reduces the long-term costs of meeting increasingly stringent GHG emission reduction targets. Indeed, Carlson, 2012 notes a finding in an MIT study on RPS and cap-and-trade that “earlier investments in wind energy make the overall welfare losses that result from the higher expense of a combined RPS/cap-and-trade program lower in later years because the early investments lower costs in later years.”220 However, perhaps the main conclusion of the study is that “…when a 20% RPS is added to a cap-and-trade program that reduces emissions by 80% by 2050, then adding an RPS requiring 20 percent renewables by 2020 to a cap that reduces emissions by 80% below 1990 levels by 2050 increases [emphasis added] the net present value welfare cost of meeting such a cap by 25 percent over the life of the policy.”221 This suggests that CPs that mandate investments in renewables today will not lead to GHG emission reduction cost savings over time. Similar conclusions could be reached for other policies. More specifically, there is significant disagreement about the costs and cost-effectiveness of such policies as CA’s LCFS.

In order to have a clear and open debate about the long-term costs of adding CPs such as an RPS or an LCFS to a cap-and-trade program, it is necessary to consider various assumptions embedded in economic models. These include assumptions incorporated in technology adoption curves, and any others intended to capture the ways in which the cost and scale of emission reductions from different technologies may evolve over time. Such assumptions play an important role in determining the conclusions of economic modeling efforts, and yet could receive much greater attention in the policy development process. Although there may be significant disagreement on these topics, there is significant value to further exploring them and making uncertainties more explicit to policymakers, particularly in light of the proliferation of CPs to address climate change and the popularity of utilizing them in conjunction with a cap-and-trade program to address climate change. Such discussions would be timely, as the EU may be rethinking its approach to providing direct financial support for renewables, and some Member States are showing an interest in moving to a “technology neutral” climate policy.222

One way to focus policy-makers’ views on the issue of CPs would be for economic analyses of climate policies to attempt to better quantify the costs and benefits associated with these policies, not limited to GHG emissions mitigation. This would allow policymakers to get a broader picture of the magnitude of costs and benefits. The EAAC appears to have endorsed such an approach, as it noted that ARB’s and CRA’s economic analyses all overestimate the net costs of measures in the SP because they disregard co-benefits.223 Even if this approach is adopted, however, methodologies to estimate certain economic benefits and costs will remain complex, and disagreements likely will persist among qualified economists and other technical experts.

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In addition, policymakers could require that economic analyses explicitly address the long-term cost-effectiveness of climate policies, similar to the approach incorporated in the MIT study cited by Carlson. This approach could lead to more open discussions on determining the best long-term approaches to transition to a low-carbon economy, and the various uncertainties, methodological challenges and disagreements involved.

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A APPENDIX A: COMPLEMENTARY GHG “POLICIES AND MEASURES” IN OTHER JURISDICTIONS In addition to CA, several other jurisdictions have implemented or will implement complementary policies designed to reduce GHG emissions in conjunction with cap-and-trade programs. This discussion provides an overview of these CPs and cap-and-trade programs in the EU, the Northeastern and Mid-Atlantic U.S. states, and Australia. It also describes CPs included in proposed U.S. federal climate legislation that would have created a national GHG cap-and-trade program. The discussion also compares and contrasts interactions that may occur between CPs and the cap-and-trade program in CA, with those in the EU.

The EU ETS and Complementary GHG Policies in the EU The EU Emission Trading Scheme became operational in January 2005. It was the first GHG emissions trading scheme, and continues to be the largest cap-and-trade program in the world.224 Phase 1 of the EU ETS operated from 2005-07, and served as a “pilot phase” for the scheme. Phase 2 has operated from 2008-12, which also corresponds to the first commitment period of the Kyoto Protocol. Phase 3 begins in 2013 and will run until 2020. The program now includes 30 countries – the 27 EU Member States plus Iceland, Liechtenstein and Norway. It covers 11,000 installations225 from the iron and steel sector; cement, glass, and ceramics; pulp and paper; electric-power generation; and refineries. Phase 3 extends coverage to CO2 emissions from petrochemicals, ammonia and aluminum; N2O emissions from the production of nitric, adipic and glyocalic acid; perfluorocarbons from the aluminum sector; and (starting in 2012) CO2 emissions from all flights taking off from or landing at EU airports – although this provision has been put on hold pending additional negotiations with international air carriers. These emissions account for approximately half of the EU’s CO2 emissions and 40% of its GHG emissions. The remainder of the EU’s emissions is addressed through other policies and measures, as discussed below. Other important changes to the program in Phase 3 include the establishment of an EU-wide emissions cap instead of nationally-set caps in Phase 1 and 2; an increase in the percentage of emissions allowances that is auctioned, from less than 4% in Phase 2 to more than half; and harmonization of rules for free allocations across countries.

Offsets In 2004, the EU Linking Directive established rules for the use of Certified Emission Reductions (CERs) from the Clean Development Mechanism (CDM) and Emission Reduction Units (ERUs) from Joint Implementation, for compliance with the EU ETS.226 The revised EU Trading Directive allows for the use of CERs and ERUs up to 50% of EU-wide reductions over the 2008-20 period, consistent with the requirement in the Kyoto Protocol that use of the “flexible mechanisms” should be supplemental to domestic action.227 Given that the EU ETS has been the predominant source of demand for CERs and ERUs, the collapse in the market for these instruments in 2012 is due in large part to the reduction in EU emissions resulting from global economic recession.

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Linking with Australia In August 2012, the European Commission and Australia announced an agreement to link the EU ETS with the Australian emissions trading scheme. An interim one-way link will allow Australian businesses to use EU emission allowances to meet their emission reduction requirements starting in July 2015, and full two-way linking will start no later than July 2018.228 The two programs are already indirectly linked, as they both recognize offsets created by the CDM for compliance.

2020 EU Emission Reduction Targets In its 2009 climate and energy package, the EU made a unilateral, binding commitment to reduce its 27 Member States’ total GHG emissions to 20% below 1990 levels by 2020.229,230 It also increased the target share of EU energy consumption produced from renewable resources to 20% by 2020, and pledged to improve energy efficiency by 2020. The EU ETS is the cornerstone of the EU’s strategy for achieving its GHG reduction target, and will reduce the emissions of covered sources to 21% below 2005 levels by 2020.

GHG emissions also will be reduced through a number of EU-wide policies and measures, particularly the Renewable Energy Directive and the Energy Efficiency Directive. The Renewable Energy Directive establishes binding, differentiated national targets for raising the share of renewable energy in their energy consumption to 20% by 2020, or roughly twice the 2010 target of 9.8%.231 Member States’ individual targets range from 10% for Malta to 49% for Sweden.232

The EU’s pledge to improve energy efficiency by 2020 materialized in the Energy Efficiency Directive, which was approved by the European Parliament in September 2012. It allows Member States to set their own targets for energy efficiency, which may achieve an indicative EU-wide target of a 20% improvement, but some believe a 17% improvement is more likely.233 Measures in the Directive are expected to achieve energy savings of 15%, and an additional 2% savings is expected to result from automobile fuel efficiency regulations and new standards for boilers and water heaters. The European Commission will evaluate national efficiency programs, which will be submitted in April 2013. If its analysis shows the EU is not on track to meet the 20% target, the Commission must add more binding measures to the Directive.234

For sectors not covered by the EU ETS, such as housing and buildings (particularly heating), agriculture, waste and transport (excluding aviation), Member states have taken on differentiated, binding annual targets for reducing GHG emissions under the “Effort Sharing Decision.” These sectors will reduce their emissions by 10% below 2005 levels by 2020. Combined, these reductions and those from the EU ETS sectors would reduce emissions to 14% below 2005 levels, which is equivalent to 20% below 1990 levels.

Member States will design and implement a wide range of State-specific policies and measures to target emissions in non-ETS sectors. States that miss their annual targets for non-ETS sectors – despite the availability of flexibility measures, such as banking and borrowing of non-ETS emission reductions – are subject to increased emission reduction requirements in the following year, and must submit a corrective action plan. 235

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Other policies that will contribute to the GHG reductions achieved in non-ETS sectors include the Landfill Directive, which will be implemented in 2016 and will reduce the landfilling of biodegradable waste236; measures to reduce emissions of fluorinated gases237; and the Fuel Quality Directive (Low Carbon Fuel Standard).238 In addition, Member States are also allowed to use CERs and ERUs to meet their effort sharing targets for non-ETS sectors, up to 3% of 2005 emissions, with some exceptions.239

Relationship between Cap-and-Trade and Complementary Measures in the EU versus California California’s cap-and-trade program is economy-wide, covering approximately 85% of the State’s GHG emissions. It has also adopted a range of CPs alongside the trading program to achieve the state’s GHG emissions targets for 2020 and beyond, and to achieve other objectives. If CPs addressing GHG emissions in the electricity and transport sectors do not achieve their expected level of GHG emission reductions, then the emissions cap in the cap-and-trade program will act as a backstop that ensures the state’s emissions target is met.

For example, if CA falls short of its goal of achieving its 33% RPS, electric sector emissions will automatically increase due to the higher carbon intensity of the electricity sources that were used to compensate for lower levels of renewable sources. Since the cap on these entities’ emissions would remain the same, they would need to achieve higher levels of emission reductions (or purchase more compliance instruments) under the cap-and-trade program to achieve compliance. Similarly, if CA does not achieve the level of emission reductions that it estimated from its LCFS, emissions ascribed to distributors of transportation fuels under the cap-and-trade program will increase. In this circumstance, they will need to purchase more compliance instruments to meet their emissions cap, resulting in higher allowance prices as demand increases.

Differences in the EU and California Programs An important difference between the EU ETS and the CA cap-and-trade program is that EU ETS sectors include the electricity sector, but not the transportation sector, while CA includes both. If the Renewable Energy Directive and/or the Energy Efficiency Directive fall short of achieving their expected level of emission reductions, the EU ETS will act as a backstop. Power sector emissions will increase, and it will need to increase its emission reductions under the EU ETS to meet its fixed emissions cap under the program. However, the EU ETS does not serve as a backstop for CPs in the transportation sector because emissions from transport are not covered under the EU ETS. If fuel economy standards and various other measures to address transportation emissions do not achieve their expected levels of emission reductions, increased levels of reductions will not be required in the EU ETS to compensate for higher-than-expected transport emissions. The failure of particular CPs to achieve expected emission reductions would need to be considered in subsequent reviews of those policies, and those policies could be revised and strengthened accordingly in new EU-wide Directives. Given the time required to formulate, negotiate and implement policy directives, this approach does not allow for near-term adjustments to ensure that overall emission reduction targets are met. However, individual EU Member States which do not achieve targeted levels of emission reductions for transport and other non-ETS sectors could address their shortfalls by purchasing CERs or ERUs up to the prescribed limit. In contrast, if complementary measures targeting uncapped sectors in CA do not achieve their expected level of emission reductions, the State is not permitted to use CERs or

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other instruments to compensate for this shortfall, and the State’s emissions target may be jeopardized.

Another important distinction between the EU and CA is that EU allowance prices are unaffected by the performance of complementary measures in the transport sector. In contrast, and as illustrated by ARB’s scenario modeling described earlier, covered sectors in the CA cap-and-trade program will face higher allowance prices if complementary measures targeting transportation sector emissions fail to achieve their estimated emission reductions.

The Potential for Complementary Policies to Over-achieve Against their Targets While complementary measures can under-perform, they also could achieve or even surpass their emission reduction targets. If a sector addressed by complementary measures is also covered under a cap-and-trade program, over-achievement of estimated emission reductions by complementary measures will reduce the sector’s covered emissions and result in lower allowance prices. This may raise concerns that allowance prices will not be high enough to spur investments in lower-emitting technologies – particularly in times of slow economic growth when emissions are expected to grow slowly or fall.

Concerns that the Energy Efficiency Directive will reduce allowance prices have been expressed in the EU,240 particularly in light of recent record-low allowance prices (approximately €4/tCO2 as of January 25, 2013241). Related points that have been raised include the argument that allowance prices currently are insufficient to incentivize investment needed to achieve long-term emission reduction targets, that carbon pricing is more effective than energy efficiency mandates for achieving emission reductions,242 and that the EU ETS should remain the central element of the EU’s climate strategy.

Others disagree with such concerns, arguing that the purpose of both the Efficiency Directive and the EU ETS is to reduce emissions, and that if there is concern over low allowance prices, this should be addressed by fixing the EU ETS by strengthening its targets.243 To increase allowance prices in the short term, the European Commission has taken the step of postponing the auctioning of 900 million allowances from the years 2013-15 until 2019-20. The Commission also is assessing various other options to increase allowance prices, including increasing the EU’s 2020 emissions target from 20% to 30% below 1990 levels. Any proposal would need to go through the normal legislative and assessment process before being adopted.244

The current tension between CPs and the EU ETS has the potential to emerge in CA. By designing the cap-and-trade program with an escalating floor price for allowance auctions, ARB may have helped avoid the problem of low prices faced currently by the EU ETS. Covered sectors in CA’s cap-and-trade program nevertheless are exposed to significant uncertainties regarding the effectiveness of CPs. If they outperform ARB’s, or the market’s expectations – particularly in a scenario in which economic and emissions growth is lower than forecast – pricing in the cap-and-trade program could fall to levels that do not support investment in lower emitting technologies. On the other hand, if CPs fail to achieve their expected levels of emission reductions, allowance prices would increase and cap-and-trade compliance costs would increase for covered sectors.

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Regional Greenhouse Gas Initiative RGGI is the first multi-state GHG cap-and-trade program in the United States. It covers CO2 emissions from fossil-fired electric generating units 25 megawatts and larger across 9 Northeast and Mid-Atlantic states.245 It went into effect in January 2009, and set a cap of 188 million short tons for 2009 to 2014, after which the cap will decline 2.5% each year through 2018. More than 85% of allowances are allocated through auctions.246 Because the program has been over-allocated, leading to low allowance prices and no use of offsets, participating states are considering tightening the cap that has been established for the second control period (2012-14).

Similar to CA’s approach, several of the RGGI states have established GHG emission reduction targets for 2020 and beyond247, and either have implemented CPs alongside the cap-and-trade program to achieve their targets or are considering doing so. These policies, together with the RGGI cap-and-trade program, are designed to help achieve participating states’ GHG targets and other objectives. They include, but are not limited to, state-level energy efficiency programs, including energy efficiency resource standards248; state-level Renewable Portfolio Standards249; and a Northeast/Mid-Atlantic Clean Fuels Standard that has been under discussion in the Northeast States for Coordinated Air Use Management.250 In addition, many of the RGGI states have adopted CA’s Pavley light-duty vehicle greenhouse gas standards.251

Australia252 Australia’s approach to climate policy, including its mix of cap-and-trade and CPs, may be of particular interest to the U.S., given the two countries’ similarities with respect to high per-capita GHG emissions and high levels of vehicle use.253

Australia has adopted a cap-and-trade program that differs somewhat from the EU’s and RGGI’s programs, while also pursuing a number of complementary measures. Its Clean Energy Future legislation started as a fixed-price trading program in July 2012, under which approximately 300254 to 500255 large GHG sources must purchase compliance certificates to cover their CO2, CH4, N2O and perfluorocarbon (from aluminum smelting) emissions. These sources fall within the following emissions categories: stationary energy, heavy on-road vehicles (from July 2014), industrial process, fugitive emissions, and “non-legacy waste.256” Initially, certificates are priced at AUD$23/tCO2e (USD$23.49257), and will increase in real terms by 2.5% each year until June 30, 2015. Starting in July 2015, certificate prices will be allowed to float up to a price ceiling of AUD$20 above the “expected international carbon price.” The ceiling will increase by 5% in real terms each year. In addition, a price floor will be set at $15 in July 2015, and will rise by 4% in real terms each year.

Covered entities may use CERs under the CDM, ERUs under Joint Implementation, as well as compliance instruments from eligible linked emission trading programs for up to 50% of compliance starting in July 2015. In addition, Kyoto-compliant permits issued under the Carbon Farming Initiative258 (a domestic GHG offset program) can be used for up to 5% of compliance prior to July 2015, and without limit starting in July 2015. It should be noted that the final shape of Australia’s cap-and-trade program is uncertain, given that the political coalition seeking to unseat Prime Minister Julia Gillard in the second half of 2013 supports an alternative plan – the Direct Action Plan – which may share some elements of the Clean Energy Future program but is not clearly defined.259

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Complementary policies included in the Clean Energy Future program include a Clean Technology Program to improve energy efficiency, and support research and development in lower-emitting technologies in manufacturing industries; and funding for clean energy projects through the Clean Energy Finance Corporation. Other CPs that existed prior to the Clean Energy Future legislation included the Carbon Farming Initiative, energy efficiency requirements for new buildings, and major refurbishments in the National Construction Code; the National Strategy on Energy Efficiency to accelerate energy efficiency improvements; and the Renewable Energy Target (RET) Scheme, under which 20 per cent of Australia’s electricity supply will come from renewable sources by 2020.260 The federal government in Australia has not yet established mandatory automotive fuel economy standards.261 However, the administration of Prime Minister Julia Gillard has indicated that it will introduce mandatory CO2 emission standards for light vehicles by 2015.262,263

U.S. Federal Government In the future, if the U.S. federal government adopts a comprehensive GHG cap-and-trade program or a carbon tax, these policies likely will be adopted in combination with CPs that attempt to reduce GHG emissions from personal transportation, improve energy efficiency, increase the use of renewable energy, and impose requirements on coal-fired power plants which may quicken retirements of a large portion of the fleet. Prominent CPs at the federal level include, but are not limited to, the following policies:264

• Reduced Emissions from Personal Transportation. The U.S. recently developed rules mandating fuel economy standards, and GHG emissions standards for light duty vehicles, requiring that the U.S. auto fleet achieve an average fuel economy of 35.5 miles per gallon by 2016 (equivalent to 250 grams of CO2 per mile), and 54.5 miles per gallon by 2025 (equivalent to 163 grams CO2 per mile).265 California and states that have adopted CA’s fuel economy standards played an important role in the development and negotiation of these standards.266

• Reduced Emissions from Commercial Transportation. The Obama Administration promulgated fuel economy standards for trucks, buses and other medium- and heavy-duty vehicles.

• Reducing the Carbon Intensity of Transportation Fuels. Congress approved a renewable fuel standard in the Energy Policy Act of 2005, and made the standard more ambitious in the Energy Independence and Security Act of 2007. Under the latter, the volume of renewable fuel to be blended into transportation fuel will be increased from 9 billion gallons in 2008 to 36 billion in 2022.267

• Increased Appliance Efficiency Standards. More stringent appliance efficiency standards were included in the Energy Policy Act of 2005 and the Energy Independence and Security Act of 2007.268

• Incentives to Increase Renewables Use. Congress incorporated production tax credits (PTC) in the Energy Policy Act of 1992 to stimulate increased production of renewable energy. The provision has expired and been extended a number of times. On January 2, 2013, Congress temporarily extended the PTC for wind, and allowed wind and other eligible projects that

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begin construction in 2013 to: (i) qualify for the PTC, and qualify for a 30% investment tax credit in lieu of the PTC.

• Increased Use of Renewables. The American Recovery and Reinvestment Act of 2009 provided $90 billion in federal support for renewable energy in the form of appropriations, loan guarantees and tax incentives.269

In addition to the policies above, rules recently have been developed under the Clean Air Act that targeted GHG emissions from coal-fired power plants. The Obama Administration proposed a Carbon Pollution Standard for New Power Plants under the New Source Performance Standard provision of the Clean Air Act. For the most part, it would limit GHG emissions at a new power plant to levels emitted by a highly-efficient natural gas-burning plant.

In addition to these policies, the Waxman-Markey bill – which is the only GHG cap-and-trade bill to pass either house of Congress – included a national building code for new commercial and residential buildings; performance standards for new coal-fired power plants; energy efficiency standards for lighting products, commercial furnaces, and other products; and, a renewable portfolio standard of 20% by 2020.270

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B APPENDIX B: ANALYSTS’ VIEWS ON THE NEED FOR COMPLEMENTARY POLICIES TO BE IMPLEMENTED IN CONJUNCTION WITH A CAP-AND-TRADE PROGRAM Introduction Although there is no shortage of reports analyzing the benefits of cap-and-trade policies in terms of economic efficiency and cost savings relative to command-and-control regulations,271 relatively few recent analyses have focused on the environmental and cost-effectiveness of CPs when they are implemented in conjunction with a cap-and-trade program.272 In the U.S., CA has provided the first significant opportunity to consider this question, as debates surrounding federal climate legislation focused mainly on whether or not to implement a cap-and-trade program, and not the CPs included in proposed climate legislation.

Given that CA has designed an economy-wide cap-and-trade program, and is the first jurisdiction to do so, it may be surprising that analysis concluded that 63% of the SP’s estimated emission reductions will be created by CPs, while only 20% and 17% will result from direct reductions from covered sectors in the cap-and-trade program, and offsets, respectively.273 However, this result is consistent with the State’s long experience with many of the CPs included in the SP. By the time the SP was developed, CA already had a long track record implementing ambitious policies.

In contrast, the use of a cap-and-trade program to address GHG emissions is relatively new in the U.S., and policymakers may not be as comfortable relying on this market mechanism as the primary element for the State’s efforts to address its GHG emissions. Differing levels of comfort with command-and-control regulations versus cap-and-trade are reflected in the language of AB 32. The legislation cited CA’s leadership role in implementing air quality regulations, energy efficiency requirements, renewable energy standards, and GHG emission standards for passenger vehicles. In contrast, it specified that ARB “may [emphasis added] include… the use of market-based compliance mechanisms to comply with the regulations,” provided that ARB “consider… localized impacts in communities that are already adversely impacted by air pollution,” and “design any market-based compliance mechanism to prevent any increase in the emissions of toxic air contaminants or criteria air pollutants.”274 In addition, as discussed in Section Two, AB 32 included language regarding the achievement of many policy objectives other than cost effectively reducing GHG emissions, including, but not limited to, technology development, reductions in other air pollutants, and diversification of energy sources.

Based in part on the views of the Market Advisory Committee (MAC), the final SP emphasized the key role of the cap-and-trade program, under which a fixed number of allowances will be issued, thereby providing “a measure of certainty about the total quantity of emissions that will be released from entities covered under the program.”275 In addition, by establishing a market price for carbon, the program establishes “an enduring price signal for GHG emissions across the

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economy… [which] provides incentives for the market to find new ways to reduce emissions.”276 Importantly, however, the Plan included this caveat: “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.”277

This reference to a “strong economic and public policy basis,” in the final SP provides no indication of the existence of opposing views on the merits of CPs. In the context of the economic analysis of actual cap-and-trade programs and CPs that will be implemented – rather than hypothetical programs – different perspectives exist regarding the relative merits and roles of cap-and-trade and CPs.

One perspective focuses almost solely on the relative effectiveness of these policies in reducing GHG emissions, and doing so cost-effectively. The other perspective provides greater weight to additional benefits to be derived from CPs that may not be captured in traditional economic analysis of GHG policies, with its emphasis on cost-effectiveness of achieving emissions reductions.

As illustrated by the economic analysis of AB 32, there are different estimates of the costs of these programs. Some of the differences are directly influenced by underlying views on such topics as: (i) whether energy efficiency programs have low costs, and are effective in eliminating barriers to increased efficiency; and, (ii) whether the relatively high cost of policies to support the development and deployment of renewable energy technologies can be justified in terms of benefits in the short and long term. Other differences simply relate to different methodologies used to estimate economic costs and assumptions (e.g., with respect to regional VMT reduction measures). As a result of these differences – particularly the former – analysts supportive of pure cap-and-trade, and others supportive of a “hybrid” policy consisting of cap-and-trade plus various CPs, can seem as if they are “talking past one another.” This dynamic can prevent a full and clear consideration of the environmental and economic impacts of these programs, and related policy, economic and technological debates and uncertainties.

It also should be noted that some would consider this debate to be settled, insofar as all jurisdictions that have committed to GHG emissions caps (i.e., the EU, Japan, Australia, and New Zealand) have adopted multiple policies to control emissions, although some jurisdictions have not adopted cap-and-trade programs (e.g., Japan). In addition, as described in Appendix A, jurisdictions that have implemented, or plan to implement, GHG cap-and-trade programs also have adopted, or will adopt, multiple CPs (e.g., the EU, Australia, New Zealand and Northeastern and Mid-Atlantic States in the U.S.). Furthermore, no jurisdiction has implemented a pure cap-and-trade program (i.e., one that is not accompanied by CPs). In the context of this apparent consensus, however, relatively little attention has been focused on the potential tradeoffs associated with implementing CPs, particularly with respect to their cost-effectiveness.

The following discussion describes analysts’ different views on these policies, and frameworks for assessing their relative merits. It also considers whether and how the policies can be assessed from a more unified perspective that takes into account their economic benefits and long-term costs. Some analyses considered in this section relate specifically to CA’s climate policies (e.g., the views expressed by ARB in the SP, and the views of CRA in its assessment of ARB, March 2010). Other analyses described below speak more generally to the merits or

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disadvantages of implementing CPs alongside a cap-and-trade program (e.g., Carlson, 2012278 and Stavins, 2007279).

While the public may benefit from making some of the assumptions and value judgments in policymaking more explicit, it is inevitable that choosing between implementing an economy-wide cap-and-trade, and implementing a hybrid policy of cap-and-trade plus various CPs, will involve important policy tradeoffs.

For example, the use of CPs alongside cap-and-trade can provide CA policymakers and the public with greater assurance that particular abatement options, such as some renewable technologies will be available to deploy at scale, and be more cost-effective than at present, when the economy must be de-carbonized to achieve a target of 80% below 1990 levels by 2050.280 These policies also can serve as a hedge against possible spikes in the prices of natural gas and transportation fuels, provide health benefits from reduced air pollution, and in the view of some, lead to economic benefits such as job creation and increased exports in industries important to the transition to a clean energy economy.

At the same time, CPs can negatively impact the functioning of the cap-and-trade program. By requiring the implementation of certain abatement options, a hybrid policy approach can reduce the spatial and temporal flexibility provided by the cap-and-trade program and undermine its greatest strength – the ability to achieve a given level of emissions reductions at the lowest economic cost. A cap-and-trade program allows regulated entities to develop compliance plans that utilize internal abatement and market instruments, such as allowances and offsets, in a way that minimizes compliance costs over time for both the regulated parties and society overall. Complementary measures reduce this flexibility because they limit covered entities’ choices about how they will meet their emission reduction targets. This is particularly the case in CA, because the SP analysis concludes that such measures account for the large majority of emission reductions. In addition, some argue that by favoring (i.e. imposing) some abatement options and technologies by implementing mandatory CPs, overall economic costs over time will be higher because these options will displace other more cost-effective options that would have emerged if the cap-and-trade program was allowed to function unencumbered by CPs.

Arguments for complementary policies Various arguments for the need to supplement a cap-and-trade program with a range of targeted CPs are provided in the final SP itself, and the economic analysis of the Plan. In addition, support for this approach was also provided by the MAC established to advise ARB on the development of the cap-and-trade program, the Economic and Technical Advancement Advisory Committee (ETAAC), which ARB created to facilitate and expedite the development of new policies and technologies, and the Environmental Justice Advisory Committee.

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The Need to Address Barriers to Implementation of Abatement Options One important category of arguments in favor of CPs relates to barriers that are said to prevent the implementation of cost-effective emission reductions. In its final recommendations to ARB, the MAC stated,

“…At the same time, the cap-and-trade program does not eliminate the need for other policies that are directly focused on promoting new technologies. The reason is that the cap-and-trade program addresses the failure of market prices to capture the climate-change externality associated with GHG emissions. It remedies this market failure by creating a price signal for avoided emissions. Technology- promoting policies may still be needed, however, to address other market failures that impede the development of new technologies, such as the “innovation market failure” that results from the inability of inventors to reap all of the rewards from new knowledge generated by their investments. Technology-promoting policies such as tax incentives for research and development, California’s motor vehicle regulations, and Low-Carbon Fuels Standards confront these types of market failures. A cap-and-trade program does not obviate the need for such technology polices. To the contrary, it complements technology policies.”281

The MAC’s report listed a number of market failures that are not addressed by a cap-and-trade program, which only addresses the failure of market prices to capture the external costs associated with GHG emissions. According to the MAC and ETAAC, these market failures, and (in parentheses) examples of types of policies designed to address them, include the following:

• Step-change technology deployment: Temporary incentives are required to encourage technology deployment at large scale, and overcome existing disincentives created by technology, market and policy risk (RPS, biofuel requirements and the LCFS);

• Fragmented supply chains: Economically rational investments are not made because investors in technology are not rewarded (e.g., building developers do not benefit from savings from investments in energy efficiency) (building codes); and,

• Consumer behavior: Consumers may apply a high discount rate for investment in energy efficiency that is “inconsistent with the public good;” (vehicle and appliance efficiency standards and rebate programs).282

The ETAAC expands on the discussion of market failures and barriers to investment. ETAAC commented in its final recommendations,

“As the Market Advisory Committee notes, however, placing a price on GHG emissions addresses only one of many market failures that impede solutions to climate change. Additional market barriers and co-benefits would not be addressed if a cap and trade system were the only state policy employed to implement AB 32. Complementary policies will be needed to spur innovation, overcome traditional market barriers, (e.g., lack of information available to energy consumers, different incentives for landlords and tenants to conserve energy, different costs of investment financing between individuals, corporations and the

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state government, etc.) and address distributional impacts from possible higher prices for goods and services in a carbon-constrained world.”283

As noted below, these and other market failures and barriers are elaborated upon, and in some cases challenged, in other analyses.

California and its partners in the WCI have expressed their intention to use CPs to “address barriers that might otherwise limit the adoption of least-cost emission reductions.”284 These least-cost options are expected to include investments in energy efficiency, and WCI’s 2008 report providing design recommendations for a regional cap-and-trade system noted that McKinsey found significant opportunities in energy efficiency to reduce GHG emissions at “negative cost.”285 In the view of one analysis, if market failures exist that would “inhibit the proper functioning” of a cap-and-trade system – i.e., generating emission reductions at the lowest cost, then complementary measures such as energy efficiency measures should be considered.286 If such failures do not exist, and if the sole objective is to achieve GHG emission reductions at the lowest cost, CPs should not be used, in this view.287

Ensuring all sectors contribute to emission reductions A second argument in favor of CPs is that the potential stringency of future emission reduction targets, and projected BAU emissions growth in certain sectors, will require achievement of emission reductions in all sectors, even if some reductions are not cost-effective.

For example, ARB notes that emission reduction options in the transport sector need to be identified because the sector accounts for the largest share of the State’s emissions, and it would be difficult for other sectors to provide sufficient emission reductions to compensate if the transport sector does not contribute a significant volume of reductions.288

With respect to energy efficiency, ARB points out that statewide population is projected to increase to 44 million by 2020, and that population growth rates are highest in areas of the state – the Southland’s Inland Empire and the Sacramento and San Joaquin Valleys – that have warmer and longer summers, leading to more energy demand linked to air conditioning. Other trends that could increase per-capita energy consumption include the purchase of increasingly larger homes, larger appliances and more electronic items. This increasing consumption must be countered by “much more aggressive energy efficiency measures.”289

Complementary policies are cost-effective A third argument for the use of CPs – which may be seen as the most important argument in the context of a typical economic analysis – is that they are cost-effective. ARB’s economic analysis of the SP finds that some CPs in the Plan will have negative costs, but others will have high positive costs. On balance, however, ARB estimates that the net impact of implementing CPs in conjunction with a cap-and-trade program is to lower costs significantly, as discussed in detail in Section Five. ARB’s low estimated cost of energy efficiency measures is consistent with MAC’s view that “modeling has shown that increased investment in end-use energy efficiency can substantially reduce the cost of complying with an emissions cap in the electric sector.”290 Another analysis (Carlson, 2012) discussed below cites comprehensive reports concluding that the benefits of energy efficiency programs exceeded their costs.

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Other benefits of complementary policies ARB’s economic analysis touts many other benefits that result from complementary measures in the SP that are not explicitly linked to GHG cost-effectiveness, or at least are not quantified as part of the GHG cost-effectiveness estimates. Although these benefits are not quantified, they are critical for assessing the net impacts of the Scoping Plan, particularly in light of some views that ARB’s cost-effectiveness estimates are too optimistic.

Many of these benefits are included in the language of AB 32 and the SP. This is to be expected, as AB 32 prescribed the objectives ARB must seek to achieve in developing the SP and the criteria they must meet. For example, AB 32 requires that in preparing the plan, ARB must “…evaluate the total potential costs and total potential economic and non-economic benefits of the plan for reducing greenhouse gases to California’s economy, environment, and public health…”291 Similarly, in adopting regulations needed to implement the Plan, ARB must “consider overall societal benefits, including reductions in other air pollutants, diversification of energy sources, and other benefits to the economy, environment, and public health.”292

The final SP states that measures have been designed to accelerate “the necessary transition to the low-carbon economy required to meet the 2050 target... and set ourselves on a path towards a clean low carbon future.”293 Benefits of CPs cited in the SP include, but are not limited, to the following:

• Creating 100,000 new jobs (all policies)294;

• Creating exports and additional jobs and economic benefits resulting from technology innovations associated with policies that enhance energy efficiency and renewable technologies;295

• Delivering additional air-quality-related public health and environmental benefits (estimated in the SP at $4.4 billion by 2020) (all policies);296

• Making the economy more resilient to oil price volatility (LCFS);

• Providing fuel savings for new car buyers (Pavley II), and fuel and electricity savings for consumers (energy efficiency);297

• Developing new technologies that reduce dependence on fossil fuels, which is required to meet the long-term goal of reducing GHG emissions by 80% below 1990 levels (all policies);298

• Making the improvements in development and transportation infrastructure planning needed to meet the 2050 emissions target (regional transportation-related GHG targets);

• Accelerating the introduction of low-GHG-emitting vehicles (GHG standards);

• Enhancing “fuel diversity, reduc[ing] reliance on fossil fuels, reduc[ing] criteria pollutants… and providing opportunities for California companies that develop, produce, install, or operate renewable equipment” (RPS);299

• “Transform[ing] the rooftop solar market by driving down costs over time,” (RPS);300 and,

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• Diversifying the electricity supply and accelerating the transformation of the electricity sector, “including investment in the transmission infrastructure and system changes to allow integration of large quantities of intermittent wind and solar generation” (RPS).301

In addition to these benefits, CPs are described by the MAC as representing “another category of cost-containment mechanism” which may lower allowance prices and reduce price volatility.302 As discussed below, other analyses also find that CPs have the effect of lowering allowance prices, but conclude that they increase the overall economic cost of meeting the AB 32 emissions target.

The notion of CPs playing a key role in the State’s transition to a low carbon future is particularly important. It suggests that certain actions, such as implementing an RPS in the near term, may become cost-effective over the longer term by reducing the costs of these technologies, and ensuring that a sufficient volume of cost-effective emission reductions are available to meet the 2050 target. This argument appears to be largely implicit in ARB’s analysis, and it is a familiar one.303 However, at least one study shows that the short-term costs of an RPS outweigh later cost savings. This raises questions on whether: (i) it is better to focus solely on an economy-wide cap-and-trade program, which ensures that abatement is achieved in the most economically efficient manner, and sends a long-term price signal that could, by itself, ensure that cost-effective abatement options will emerge to achieve stringent emissions targets; or, (ii) particular CPs are needed to address market failures that are impediments to the implementation of important cost-effective abatement options when they are needed to achieve stringent reduction targets in the future.

Arguments against complementary policies CAR collaborated with ARB staff in analyzing the economic impacts of the SP and providing perspectives on how to conduct such an analysis.304 Given that CRA has provided the most thorough critique of ARB’s economic analysis and underlying assumptions, and that it focuses to a large extent on the negative impact of including CPs in the SP, CRA’s analysis provides a number of arguments against the need for CPs. Other important perspectives on this topic have been provided by Harvard economist Robert Stavins. Below is a brief summary of the arguments against including CPs along with GHG emissions cap-and-trade programs, both in CA and more broadly.

Complementary measures increase the cost of achieving AB 32 goals The results of CRA’s economic analysis of AB 32 differ from ARB’s, particularly with respect to the impact of complementary measures. CRA believes that complementary measures – particularly the RPS and the LCFS305 – require the implementation of more expensive abatement options than would otherwise be implemented under a pure cap-and-trade program.306

Consequently, CRA estimates that complementary measures increase the cost of meeting the AB 32 target by approximately 50% relative to a pure cap-and-trade program. This is in contrast to ARB’s analysis, which concludes that including complementary measures results in lower costs.307 In CRA’s view, the negative impact of CPs on overall program costs is obscured because they lower allowance prices.308 Based on the results of a series of modeling scenarios, CRA estimated that a cap-and-trade program combined with a full set of complementary measures – i.e., a combination of policies comparable to those included in the SP – would result

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in nearly the highest overall costs. In contrast, a pure cap-and-trade scenario would result in the lowest overall societal costs, despite having the highest allowance prices.309 By mandating emission reductions from specified abatement options and technologies, CPs lower the quantity of emission reductions that CA’s economy-wide cap-and-trade program must achieve, thereby reducing the program’s marginal abatement cost (i.e. allowance price).

As explained by CRA, these divergent results can be attributed to different views about market failures. As noted in Section Two, ARB identifies a range of market failures that lead to incorrect economic decisions, and believes that energy efficiency standards can correct these failures. CRA posits that market failures are relatively small, and finds that requiring complementary measures increases costs by limiting compliance flexibility under the cap-and-trade program.310 It notes that “[w]hen complementary measures are excluded, program costs are less sensitive to technology uncertainty because the market is no longer constrained in its choice of technologies.”311 When this constraint exists, the electricity sector makes fewer emission reductions than under pure cap-and trade because the RPS increases its average abatement cost.312 In addition, offsets are less effective in reducing policy costs (i.e., the overall costs of AB 32), because the high cost of certain abatement options is locked in by complementary measures. Offsets may be substituted for higher-cost abatement options in a cap-and-trade program, but cannot play that role with respect to measures mandated by CPs.313

CRA concluded that fuels qualifying for the LCFS will have limited availability in 2015-20. As a result, it assumes that emission reductions will need to come from reductions in fuel consumption (via increased gasoline prices), and a switch to plug-in hybrid electric vehicles and electric vehicles.314 CRA estimates that these assumptions will increase overall AB 32 compliance costs by more than 40%.315 As discussed in Section Five, more recent analyses may provide further indication that LCFS implementation costs will be higher than estimated by ARB. In addition, CRA estimates that cost-effective levels of new CHP and demand side management (DSM) that would be achieved under pure cap-and-trade would be 43% and 59% lower, respectively, than levels required by the complementary measures. The implication is that the marginal cost of emission reductions achieved by the CPs requiring CHP and DSM would be far more expensive than the CHP and DSM-related emission reductions achieved by the cap-and-trade program.316

Complementary policies increase the cost of meeting GHG targets under a pure cap-and-trade program Harvard economist Robert Stavins has written extensively on the topic of energy efficiency, and the benefits and costs of programs designed to improve end-use energy efficiency. In contrast to the case made for support of energy efficiency measures in the SP and related documents, Stavins contends that estimates of cost-effective energy efficiency measures can be “too good to be true.” In a 2007 paper, he writes:

“…most economists maintain that, while technology diffusion is typically a gradual process, energy efficiency improvements that truly yield cost savings largely will be adopted without the need for government intervention. Moreover, economists note that many of the barriers that slow or prevent broader adoption of more energy-efficient technologies reflect real economic costs associated with their adoption. Where this is the case, policy intervention that requires or encourages adoption of those technologies would be socially costly.”317

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Stavins, 2007 cites some examples of economic costs associated with the imposed adoption of more energy-efficient technologies that may not be accounted for in bottom-up318 analyses of policy costs. These examples include:

• Adverse impacts on valued attributes, such as reduced power in automobiles that meet GHG performance standards;319

• The small costs to individual consumers associated with learning about and adapting to new technologies which, when aggregated, can become significant;320 and,

• The larger share of electricity suppliers’ fixed costs that ratepayers must bear due to reductions in electricity use resulting from energy efficiency policies.321

Stavins makes several additional points that challenge claims that large volumes of “no-cost” emission reductions can be created by implementing energy efficiency measures, and that argue for an economy-wide cap-and-trade program rather than a hybrid approach with complementary measures.

Additional views and findings on these topics were provided by CRA in a June 2007 economic analysis for EPRI322 on a range of policy implementation scenarios to meet AB 32’s 2020 emission target, and in Stavins’ April 2010 analysis of CA’s climate policies.323 They include the following.

• The failure to internalize the cost of emissions is the core GHG market failure. Market-based policies address this failure more cost-effectively than standards.324

• Even if market failures are present, the cost of policies to address them may exceed savings.325

• High discount rates applied in investments in energy efficient technologies may not reflect market failures. Sunk costs, uncertain returns, and the option to delay investment are all factors that can justify the use of a higher discount rate.326

• Estimates of the effectiveness of energy efficiency policies are often based on controlled studies that do not reflect real-world conditions; 327and rarely provide definitive evidence of market failures,328 or evidence that market failures are large enough to make cost-savings estimates plausible.329

• Policies to capture legitimate no-cost emission reduction opportunities need to be carefully tailored and narrowly targeted to address specific market failures. However, clear insights on the nature and extent of market failures are rarely provided by bottom-up studies.330

• Economic models do not have all of the information and criteria that businesses and households use in their decisions on energy use and fuel choice, and therefore cannot completely characterize these decisions. As a result, models cannot capture the various ways in which command-and-control regulations fail to equalize marginal costs and increase economic losses.331

These critiques were directed at three economic analyses done in 2006 that concluded that CA could meet its 2020 emissions target at no net economic cost. It is not obvious whether the

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critiques would also apply to the models utilized in ARB’s updated economic analysis, because the analysis provides little information on how it estimates the costs of energy efficiency policies. Two of Stavins’ critiques – (i) that studies tend to underestimate costs, and (ii) that they do not provide insights on the nature or extent of market failures – may be applicable to the ARB’s updated economic analysis, because it does not include utility program and administration costs,332 and it assumes that “efficiency potential exists without being specific as to what market failures are being corrected by the policy intervention.”333 In addition, when CRA explains the differences between its (higher) cost estimates and ARB’s, it states that ARB assumes that market failures are pervasive, while CRA’s model reflects Stavins’ view that market failures are relatively small. CRA also notes that imposing efficiency standards leads to market distortions.334 As discussed above, some of Stavins’ key views and critiques appear to be shared by CRA, and may be applicable to ARB’s analysis.

A recent assessment of the case for complementary measures A 2012 analysis by Ann Carlson of UCLA’s School of Law seeks to begin to resolve some of the competing arguments regarding whether CPs “are a good idea in the presence of a well- designed cap-and-trade system,” which she describes as a “subject of surprisingly little analysis.”335 Carlson, 2012 expresses the view that CPs may be justifiable based on such considerations as increased energy independence or promoting economic development. However, the analysis purposefully sets aside the ancillary benefits and costs associated with CPs to focus solely on the matter of cost-effectiveness in reducing GHG emissions.336

In Carlson’s formulation, complementary measures are necessary only if they are needed to ensure that a cap-and-trade program operates properly, and is able to effect the implementation of all cost-effective abatement options up to the market clearing price.337 Based on this criterion, Carlson, 2012 concludes that energy efficiency measures are necessary. The analysis acknowledges arguments that there are rational reasons for some individuals to choose not to make investments in energy efficiency, and makes a point similar to those raised in Stavins, 2007: “[W]e lack data sufficient to know precisely what causes the efficiency gap and therefore exactly how to tackle it.”338 However, in Carlson’s view, a National Academy of Sciences review of the literature released in 2010339 confirms the existence of a significant efficiency gap.

In addition, a review of major studies of energy efficiency studies published in 2000340, and other studies suggest that appliance standards and building standards can achieve real reductions in energy use and emissions that are cost-effective. For example, one study estimated a ratio of consumer benefits to costs of 2.7 to 1.341 In addition, a study by the National Renewable Energy Laboratory – which considered different combinations of a pure cap-and-trade program, energy efficiency mandates, and an RPS – found that electricity prices do not increase dramatically with a cap-and-trade program that is accompanied by energy efficiency programs and an RPS.342 In light of energy efficiency’s greater cost-effectiveness than RPSs, Carlson, 2012 concludes that energy efficiency measures must be responsible for keeping electricity prices down, presumably by reducing electricity demand, which would lead to a movement down the dispatch curve to units with lower marginal costs.343

In contrast to energy efficiency, an RPS does not satisfy the test that it is needed to ensure the proper functioning of a cap-and-trade program. Carlson, 2012 cites an MIT study which considered a cap-and-trade program combined with a 20% RPS, and concluded that it would

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achieve the same level of emission reductions as a pure cap-and-trade program, but with costs that are 25% higher.344 Carlson, 2012 also cites an estimate made by the CPUC that the 33% RPS will achieve emission reductions at a cost of $133/mtCO2, versus $30 for a cap-and-trade program.345 These findings are comparable to many other analyses that have concluded that an RPS has high costs compared to energy efficiency programs.346 Based on these findings, the Carson analysis concludes that renewable energy simply has higher abatement costs than other options such as energy efficiency, and that combining an RPS with a cap-and-trade program doesn’t address market failures, but instead simply “subsidizes renewable energy at the expense of other abatement options” and increases the cost of reducing emissions.347 While an RPS may be justifiable on the basis of other benefits, such as job creation, energy independence or reduced emissions of criteria pollutants, Carlson writes that

“…policymakers should be aware of the very real tradeoffs before committing to such a choice, and should be aware that by committing to certain mandatory emissions reductions they are limiting the theoretical promise that cap-and-trade [in terms of cost-effectiveness and technological innovation348] will result in greenhouse gas emissions at the lowest cost.”349

Importantly, she adds that there are also “…tradeoffs… in technological innovation that come from an unfettered cap-and-trade system absent evidence that the policies are warranted to overcome persistent market failures.”350

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ENDNOTES 1 California Global Warming Solutions Act of 2006, http://www.leginfo.ca.gov/pub/05-06/bill/asm/ab_0001-0050/ab_32_bill_20060927_chaptered.pdf. 2 Ibid, Section 38550. 3 State of California, Executive Order S-3-05, June 1, 2005, http://www.dot.ca.gov/hq/energy/ExecOrderS-3-05.htm. 4 California Global Warming Solutions Act of 2006, op. cit., Section 38560.5(a). 5 Ibid, Section 38561(b). 6 Ibid, Section 38562(a). 7 Ibid, Section 38562(b)(6). 8 Air Resources Board, “Climate Change Scoping Plan: A Framework for Change,” December 2008, p. 17, http://www.arb.ca.gov/cc/scopingplan/document/adopted_scoping_plan.pdf. 9 Air Resources Board, “California Greenhouse Gas Emissions Inventory: 2000-2009,” December 2011, p. 3, http://www.arb.ca.gov/cc/inventory/pubs/reports/ghg_inventory_00-09_report.pdf. 10 Air Resources Board, December 2008, op. cit., p. 12. 11 Air Resources Board, “Status of SP Recommended Measures,” July 2011, http://www.arb.ca.gov/cc/scopingplan/status_of_scoping_plan_measures.pdf. 12 Air Resources Board, December 2008, op. cit., p. 11. 13 Ibid. 14 Air Resources Board, July 2011, op. cit. 15 Ann E. Carlson, “Designing Effective Climate Policy: Cap-and-Trade and Complementary Policies,” Harvard Journal on Legislation, volume 49, 2012, http://www.harvardjol.com/wp-content/uploads/2012/08/Carlson_Article.pdf; Charles River Associates, “Analysis of the California ARB’s SP and Related Policy Insights, March 2010, pp. 10-12, http://crai.com/uploadedFiles/analysis-of-ab32-scoping-plan.pdf; Todd Schatzki (Analysis Group, Inc.), Robert N. Stavins (Harvard University), “Next Steps for Climate Policy II: Moving Ahead under Certain Circumstances,” April 2010. http://www.arb.ca.gov/cc/capandtrade/meetings/121409/additionalcomments/stavins_100428.pdf 16 Air Resources Board, July 2011, op. cit. 17 Air Resources Board, “California GHG Emissions – Forecast (2008-20), October 28, 2010, http://www.arb.ca.gov/cc/inventory/data/tables/2020_ghg_emissions_forecast_2010-10-28.pdf. 18 Subchapter 10 Climate Change, Article 5, Section 95913, http://www.arb.ca.gov/regact/2010/capandtrade10/ctfro.pdf.

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19 Air Resources Board, “Appendix A: Staff Proposal for Allocating Allowances to the Electric Sector,” 2011, p. 1, http://www.arb.ca.gov/regact/2010/capandtrade10/candtappa2.pdf. 20 Air Resources Board, July 2011, op. cit. 21 State of California, Executive Order S-01-07, January 18, 2007, http://www.arb.ca.gov/fuels/lcfs/eos0107.pdf. 22 Information in this paragraph derives from Air Resources Board, “California’s Low Carbon Fuel Standard: Final Statement of Reasons,” December 2009, p. 5, http://www.arb.ca.gov/regact/2009/lcfs09/lcfsfsor.pdf. 23 Air Resources Board, “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/updated-analysis/updated_sp_analysis.pdf. 24 Air Resources Board, March 2010, op. cit., p. ES-2. 25 Ibid, Table 13, p. 37. 26 Ibid, pp. 35, 51. 27 Charles River Associates, March, 2010, op. cit., pp. 10-12. 28 Ibid, pp. 10-11. 29 Air Resources Board, March 2010, op. cit., Table 23, p. 51. 30 Charles River Associates, March 2010, op. cit., p. 13. 31 Air Resources Board, March 2010, op. cit., Table ES-2, p. ES-7. 32 Frank Harris (Southern California Edison), “Update: Implementing California’s Cap-and-Trade Program, Session 1 Webinar,” presentation for the Edison Electric Institute, November 15, 2012. 33 California Global Warming Solutions Act of 2006, op. cit. 34 Ibid, Section 38550. 35 Ibid, Section 38551(b). 36 State of California, Executive Order S-3-05, 2005, op. cit. 37 U.S. Department of Commerce, Bureau of Economic Analysis, http://www.bea.gov/iTable/iTableHTML.cfm?ReqID=70&step=1&isuri=1&acrdn=1 38 Air Resources Board, December 2008, op. cit., p. 11. 39 California Global Warming Solutions Act of 2006, op. cit., Section 38560.5(a). 40 Ibid, Section 38561(b). 41 Ibid, Section 38562(a). 42 Ibid, Section 38561(d). 43 Ibid, Section 38562(b)(6).

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44 Air Resources Board, December, 2008, op. cit., p. 17. 45 Ibid, p. 12. 46 Air Resources Board, March 2010, op. cit., p. ES-3. 47 Air Resources Board, “California GHG Emissions – Forecast (2008-20), October 2010, op. cit. 48 Air Resources Board, July 2011, op. cit. 49 Ibid. 50 Air Resources Board, December, 2008, op. cit., p. 11. 51 Ann E. Carlson, 2012, op. cit.; Charles River Associates, March 2010, op. cit.; Todd Schatzki, PhD (Analysis Group Inc.) and Robert N. Stavins (Harvard University), “Using the Value of Allowances from California’s Cap-and-Trade System,” Analysis Group Inc., August 27, 2012, p. 14, http://www.analysisgroup.com/uploadedFiles/Publishing/Articles/Value_Allowances_California_GHG_Cap_Trade_System.pdf. 52 Carlson, 2012, op. cit.; Charles River Associates, March, 2010, op. cit.; Schatzki and Stavins, April 2010, op. cit. 53 Air Resources Board, July 2011, op. cit. 54 See http://sierraclubcalifornia.org/campaigns/drive-green-california/light-duty-vehicle-greenhouse-gas-emissions-standards/. 55 Air Resources Board, December, 2008, op. cit., pp. ES-8 - ES-14. 56 Air Resources Board, December, 2008, op. cit., p. 22. 57 Air Resources Board, “Attachment D, Final Supplement to the AB 32 Scoping Plan, Functional Equivalent Document, released August 19, 2011, considered at the August 24, 2011 Board Hearing, Modified Text (Clean Copy),” p. 21, http://www.arb.ca.gov/cc/scopingplan/document/final_supplement_to_sp_fed.pdf. 58 Air Resources Board, “Overview of ARB Emissions Trading Program,” revised October 20, 2011, http://www.arb.ca.gov/newsrel/2011/cap_trade_overview.pdf; Air Resources Board, “Climate Change SP Appendices, Volume I: Supporting Documents and Measure Detail, Appendix C: Sector Overviews and Emission Reduction Strategies,” December 2008, p. C-16, http://www.arb.ca.gov/cc/scopingplan/document/appendices_volume1.pdf. 59 Air Resources Board, “Climate Change SP Appendices, Volume I, Appendix C,” December 2008, op. cit., p. C-15. 60 Ibid, p. 2. 61 Air Resources Board, “Climate Change SP Appendices, Volume I, Appendix C,” December 2008, op. cit., p. C-89. 62 Ibid, p. C-15. 63 Ibid.

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64 Ibid, p. C-17. 65 Air Resources Board, “California GHG Emissions – Forecast (2008-20), October 28, 2010, op. cit. 66 Air Resources Board, October 20, 2011, op. cit. 67 Air Resources Board, “Appendix A: Staff Proposal for Allocating Allowances to the Electric Sector,” 2011, op. cit. 68 Subchapter 10 Climate Change, Article 5, see Section 95892 and Table 9-3, http://www.arb.ca.gov/regact/2010/capandtrade10/ctfro.pdf. For a clear description of allocation methodologies, see International Emissions Trading Association, “Summary of Final Rules for California’s Cap-and-Trade Program,” February 14, 2012, http://www.ieta.org/assets/US-WG/ieta_summary_of_california_ct_regulations.pdf. 69 Ibid, pp. 119-120; Air Resources Board, “Appendix A: Staff Proposal for Allocating Allowances to the Electric Sector,” 2011, op. cit., p. 5. 70 Air Resources Board, “Cap-and Trade Regulation Instructional Guidance: Chapter 1: How Does The Cap-and-Trade Program Work?” September, 2012, p. 17, http://www.arb.ca.gov/cc/capandtrade/guidance/chapter1.pdf; Subchapter 10 Climate Change, Article 5, Section 95856 subsections (a) to (g), op. cit. 71 Subchapter 10 Climate Change, Article 5, Section 95831, op. cit. 72 Ibid, Section 95920, op. cit. 73 Air Resources Board, October 20, 2011, op. cit. 74 Air Resources Board, August 19, 2011, op. cit., p. 49. 75 Air Resources Board, October 20, 2011, op. cit. 76 For estimates of offset supply see, Winrock International/American Carbon Registry, “Compliance Offset Supply Forecast for California’s Cap-and-Trade Program (2013-2020),” September 2012, http://americancarbonregistry.org/acr-compliance-offset-supply-forecast-for-the-ca-cap-and-trade-program. Also see Barclay’s Capital, “Carbon Flash, California: Still dreaming,” October 21, 2011. 77 Subchapter 10 Climate Change, Article 5, Section 95985, op. cit. 78 “Overview of the California Greenhouse Gas Offsets Program,” Background Paper for the EPRI Greenhouse Gas Emissions Offset Policy Dialogue Workshop #10, April 2011, pp. 21-22, http://globalclimate.epri.com/doc/EPRI_Offsets_W10_Background%20Paper_CA%20Offsets_040711_Final2.pdf. 79 Subchapter 10 Climate Change, Article 5, Subarticle 10, op. cit. 80 California Air Resources Board, California Environmental Protection Agency, “Quarterly Auction 1 results,” November 19, 2012, http://www.arb.ca.gov/cc/capandtrade/auction/november_2012/auction1_results_2012q4nov.pdf. 81 Subchapter 10 Climate Change, Article 5, Section 95913, op. cit.

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82 Air Resources Board, October 20, 2011, op. cit. 83 Air Resources Board, July 2011, op. cit. 84 Air Resources Board, “Climate Change SP Appendices, Volume I, Appendix C,” December 2008, op. cit., pp. 126-130. 85 Air Resources Board, December 2008, op. cit., p. 17. 86 Air Resources Board, July 2011, op. cit. 87 Air Resources Board, December 2008, op. cit., p. 12. 88 California Renewables Portfolio Standard Program, Senate Bill No. 1078, Section 3, 399.11(b), September 2002, http://www.energy.ca.gov/portfolio/documents/documents/SB1078.PDF. 89 Air Resources Board, “Climate Change SP Appendices, Volume I, Appendix C,” December 2008, op. cit., p. C-129. 90 California Renewable Energy Resources Act, Senate Bill No. 2, April 2011, http://www.leginfo.ca.gov/pub/11-12/bill/sen/sb_0001-0050/sbx1_2_bill_20110412_chaptered.html. 91 California Renewables Portfolio Standard Program, Senate Bill No. 1078, September 2002, op. cit. 92 Ibid. 93 Senate Bill No. 107. September 2006, http://www.energy.ca.gov/portfolio/documents/documents/sb_107_bill_20060926_chaptered.pdf 94 U.S. Department of Energy et al., “Database of State Incentives for Renewables and Efficiency,” October 2012, http://www.dsireusa.org/. 95 Senate Bill No. 107, September 2006, op. cit. 96 California Renewable Energy Resources Act, Senate Bill No. 2, April 2011, op. cit. 97 Ibid. 98 See www.energy.ca.gov/portfolio/index.html. 99 See www.cpuc.ca.gov/PUC/energy/Renewables/ 100 Air Resources Board, “Climate Change SP Appendices, Volume I, Appendix C,” December 2008, op. cit., p. C-56. 101 Assembly Bill 1493, Section 43018.5(a), July 2002, http://www.arb.ca.gov/cc/ccms/documents/ab1493.pdf. 102 Air Resources Board, “Greenhouse Gas Reductions from Ongoing, Adopted and Foreseeable SP Measures,” October 28, 2010, http://www.arb.ca.gov/cc/inventory/data/tables/reductions_from_scoping_plan_measures_2010-10-28.pdf.

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103 Air Resources Board, “Climate Change SP Appendices, Volume I, Appendix C,” December 2008, op. cit., p. C-56. 104 Air Resources Board, July 2011, op. cit. 105 Air Resources Board, Climate Change Emissions Control Regulations Fact Sheet, December 2004, http://www.arb.ca.gov/cc/factsheets/cc_newfs.pdf. 106 Ibid. 107 Air Resources Board, December 2004, op. cit. 108 Ibid. 109 Air Resources Board, Advanced Clean Car Summary, p. 5, http://www.arb.ca.gov/msprog/clean_cars/acc%20summary-final.pdf. 110 Ibid, p. 8. 111 Air Resources Board, Facts about the Advanced Clean Car Program, November 2011, http://www.arb.ca.gov/html/fact_sheets/advanced_clean_cars.pdf. 112 Air Resources Board, Advanced Clean Car Summary, p. 9, op. cit. 113 Air Resources Board, “California Air Resources Board Approves Clean Car Rules,” January, 27, 2012, http://www.arb.ca.gov/newsrel/newsrelease.php?id=282. 114 Air Resources Board, Advanced Clean Car Summary, p. 4, op. cit. 115 Ibid, p. 13, op. cit. 116 Ibid, p. 12, op. cit. 117 Ibid. 118 Air Resources Board, Advanced Clean Car Summary, p. 5, op. cit. 119 Air Resources Board, Advanced Clean Car Summary, p. 16, op. cit. 120 Air Resources Board, ” January, 27, 2012, op. cit. 121 State of California, Executive Order S-01-07, January 18, 2007, http://www.arb.ca.gov/fuels/lcfs/eos0107.pdf 122 See http://www.arb.ca.gov/regact/2009/lcfs09/oalapplcfs.pdf. 123 See http://www.arb.ca.gov/fuels/lcfs/CleanFinalRegOrder_02012011.pdf. 124 Air Resources Board, July 2011, op. cit. 125 Information in this paragraph derives from Air Resources Board, “California’s Low Carbon Fuel Standard: Final Statement of Reasons,” December 2009, p. 5, http://www.arb.ca.gov/regact/2009/lcfs09/lcfsfsor.pdf. 126 David Crane and Brian Prusnek, “The Role of a Low Carbon Fuel Standard in Reducing Greenhouse Gas Emissions and Protecting Our Economy,” White Paper prepared for ARB, January 8, 2007, http://www.arb.ca.gov/fuels/lcfs/lcfs_wp.pdf.

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127 Air Resources Board, December 2009, op. cit., p. 11. 128 Air Resources Board, December 2008, p. 41, op. cit. 129 The 32,000 GWh of end-use energy efficiency called for in the SP was reduced in the Updated Economic Analysis “to reflect the 2009 IEPR forecast, which is lower than the 2007 IEPR and includes new efficiency programs that were formerly considered uncommitted.” Air Resources Board, March 24, 2010, op. cit., p. 26 (footnote 24). 130 Air Resources Board, “Climate Change SP Appendices, Volume I, Appendix C,” December 2008, op. cit., p. C-117. 131 Air Resources Board, July 2011, op. cit. 132 Air Resources Board, December 2008, op. cit., p. 12. 133 Ibid. 134 Air Resources Board, “Climate Change SP Appendices, Volume I, Appendix C,” December 2008, op. cit., p. C-106. 135 Ibid, p. C-108. 136 California Public Utility Commission, “California Long Term Energy Efficiency Strategic Plan: Achieving Maximum Energy Savings in California for 2009 and Beyond,” 2008, http://www.cpuc.ca.gov/NR/rdonlyres/D4321448-208C-48F9-9F62-1BBB14A8D717/0/EEStrategicPlan.pdf. 137 California Economic Commission, “2009 Integrated Energy Policy Report,” December 2009, p. 73, http://www.energy.ca.gov/2009_energypolicy/. 138 Air Resources Board, “Climate Change SP Appendices, Volume I, Appendix C,” December 2008, op. cit., p. C-111. 139 Ibid, p. C-113. 140 Air Resources Board, December 2008, op. cit., p. 2. 141 Ibid, p. 13. 142 Ibid, p. 13. 143 Air Resources Board, “Greenhouse Gas Reductions from Ongoing, Adopted and Foreseeable SP Measures,” October 28, 2010, op. cit. 144 Air Resources Board, “Climate Change SP Appendices, Volume I, Appendix C,” December 2008, op. cit., p. C-191. 145 Air Resources Board, July 2011, op. cit. 146 Air Resources Board, Regulation for the Management of High Global Warming Potential Refrigerants for Stationary Sources, 2009, http://www.arb.ca.gov/regact/2009/gwprmp09/finalfro.pdf. 147 Air Resources Board, March 2010, op. cit., p. ES-2.

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148 Ibid, p. 3. 149 Systematic Solutions, Inc. and ICF International, “Modeling of Greenhouse Gas Reduction Measures to Support the Implementation of the California Global Warming Solutions Act (AB32): Energy 2020 Model Inputs and Assumptions,” February 1, 2010 (revision date), p. 5, http://www.arb.ca.gov/cc/scopingplan/economics-sp/models/book1002.pdf. Systematic Solutions, Inc. (SSI) and ICF International developed a version of Energy 2020 to allow ARB to model the impacts of the Scoping Plan.. 150 Air Resources Board, “California GHG Emissions – Forecast (2008-20), October 28, 2010, op. cit. 151 See Air Resources Board, March 2010, op. cit., , p. 21, and Air Resources Board, July 2011, op. cit., p. 8 (attachment). 152 Ibid, footnote 1 to Table 13, p. 37. 153 Air Resources Board, March 2010, op. cit., Table 13, p. 37. 154 Ibid, p. 5. 155 Charles River Associates, March 2010, op. cit., p. 25. 156 Barclays Capital, “Carbon Flash: I Wish They All Could Be California,” February 2, 2011, by Trevor Sikorski, pp. 7-8. 157 Barclays Capital, October 21, 2011, op. cit., p. 4. 158 Air Resources Board, July 2011, op. cit., p. 3. 159 Steve Fine (ICF International), “Complementary Measures in AB 32 & Potential Market Impacts,” presentation to the IETA’s Carbon Forum North America, October 2, 2012, p. 5, http://ietacarbonforum.org/2012/wp-content/uploads/2012/10/Fine-CFNA2012.pdf. 160 California Public Utilities Commission, Renewable Portfolio Standard Quarterly Report, 1st and 2nd Quarter 2012, p. 3, http://www.cpuc.ca.gov/PUC/energy/Renewables/RPS_Q1Q2_2012_report_to_leg.htm. 161 California Energy Commission, 2011 Integrated Energy Policy Report, February 2012, http://www.energy.ca.gov/2011_energypolicy, p. 29. 162 Ibid. 163 Ibid, p. 31. 164 Systematic Solutions, Inc. and ICF International, 2010, op. cit., p. 25. 165 As noted in Section 3, the SP called for 32,000 GWh of end-use energy efficiency. This amount was reduced in the Updated Economic Analysis “to reflect the 2009 IEPR forecast, which is lower than the 2007 IEPR and includes new efficiency programs that were formerly considered uncommitted.” Air Resources Board, March 2010, op. cit., p. 26 (footnote 24). 166 Ibid, pp. 26-27. 167 Charles River Associates, March 2010, op. cit., p. 25.

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168 Stavins et. al, 2007, op. cit., p. 14. 169 Ibid, pp. 14, 19, 20. 170 Ibid, pp. 32, 27. 171 Air Resources Board, July 2011, op. cit., p. 3. 172 For a description of these issues see California Energy Commission, 2009 Integrated Energy Policy Report, December 2009, pp. 57-58, http://www.energy.ca.gov/2009_energypolicy/. 173 Air Resources Board, “Climate Change SP Appendices, Volume I, Appendix C,” December 2008, op. cit., p. C-107. 174 California Energy Commission, 2009, op. cit., p. 67. 175 California Energy Commission, 2009, op. cit., p. 66. 176 Charles River Associates, March 2010, op. cit., p. 19. 177 Ibid, p. 25. 178 Air Resources Board, July 2011, op. cit., p. 3. The Air Resources Board notes that, “The CPUC recently approved a settlement designed to increase the amount of CHP operated by Independently Owned Utilities (IOUs) in the State. The settlement identifies a 4.8 Mt incremental GHG emission reduction goal by 2020. However, due to accounting differences between the SP and the settlement, actual reductions in 2020 may differ from the 4.8 Mt.” 179 Economic and Allocation Advisory Committee, “Comments on the Air Resources Board’s Updated Economic Impacts Analysis by the Economic Impacts Subcommittee of the Economic and Allocation Advisory Committee,” (revised 18 April 2010), pp. 6-7, http://www.arb.ca.gov/cc/scopingplan/economics-sp/updated-analysis/revised_eaac_appendix.pdf. 180 Air Resources Board, News Release: “Air Resources Board Chairman Applauds Announcement of Federal Greenhouse Gas Fuel Economy Standards (2017-2025),” August 28, 2012, http://www.arg.ca.gov/newsrel/newsrelease.php?id=347. 181 NHTSA, Final Regulatory Impact Analysis, Corporate Average Fuel Economy for MY 2017-MY 2025, Passenger Cars and Light Trucks, Office of Regulatory Analysis and Evaluation, National Center for Statistics and Analysis, August 2012, Table 1, p. 10, http://www.nhtsa.gov/staticfiles/rulemaking/pdf/cafe/FRIA_2017-2025.pdf. 182 Ibid, pp. 20, 25. 183 Ibid, p. 3. 184 Air Resources Board, “Low Carbon Fuel Standard 2011 Program Review Report,” final draft, December 8, 2011, p. 16, http://www.arb.ca.gov/fuels/lcfs/workgroups/advisorypanel/20111208_LCFS%20program%20review%20report_final.pdf. 185 Ibid.

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186 In its December 2011 LCFS program review report, Air Resources Board also updated its previous economic analysis for the proposed LCFS regulation. However, the results of the December 2011 analysis cannot be directly compared to those of the 2010 updated economic analysis of the Scoping Plan, as they are presented in terms of the estimated incremental cost per gallon of gasoline and diesel fuel in 2011 through 2020 for each of 11 scenarios. See Table VII-11, p. 129, and Table VII-13, p. 130 in Air Resources Board, December 8, 2011, op. cit. 187 Ibid, p. 16. 188 Ibid. 189 Steve Fine, ICF International, October 2, 2012, op. cit., p. 9. 190 See Figure ES-2 (p. ES-3) and Table 5 (pp. 17-18) in Schatzki and Stavins, August 27, 2012, op. cit. 191 Ryan Keefe, “Reconsidering California Transport Policies: Reducing Greenhouse Gas Emissions in an Uncertain Future,” Dissertation, Pardee RAND Graduate School, 2012, Table 1, p. x, http://www.rand.+++-+++-*9+9+9org/content/dam/rand/pubs/rgs_dissertations/2012/RAND_RGSD292.pdf . 192 Air Resources Board, July 2011, op. cit., p. 3. 193 Ibid, pp. xii, 183. 194 Economic and Allocation Advisory Committee, 2010, op. cit, pp. 6-7. 195 “California Low Carbon Fuel Standard accused of discriminating against out-of-state businesses,” Jason Dearen, Associated Press, October 16, 2012, http://www.huffingtonpost.com/2012/10/16/california-low-carbon-fuel-standard_n_1971819.html. 196 Systematic Solutions, Inc. and ICF International, 2010, op. cit., p. 26. 197 Economic and Allocation Advisory Committee, 2010, op. cit., pp. 5-6. 198 Air Resources Board, July 2011, op. cit., p. 3. 199 See Air Resources Board, March 2010, op. cit., Table 23, p. 51, and Table ES-2, p. ES-7. 200 Ibid, p. 29. 201 Ibid. 202 Air Resources Board, “The Role of Offsets in Cap-and-Trade: Consideration of a Process for the Adoption of Offset Accounting Protocols for Compliance Purposes,” presentation, February 25, 2010, p. 9, http://www.arb.ca.gov/cc/capandtrade/meetings/022510/pres.pdf. 203 Air Resources Board, March 24, 2010, op. cit., pp. ES-6, ES-7. 204 Ibid, p. 91. 205 Charles River Associates, March 2010, op. cit., pp. 10-12. 206 Ibid, p. 13.

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207 Ibid, pp. 10-11. 208 If CRA had assumed the inclusion of complementary policies from Air Resources Board’s case 5, presumably its estimated social cost would be higher and its estimated allowance price would be lower than in CRA 8c. 209 Ibid, p. 13. 210 Charles River Associates, March 2010, op. cit., p. 14. 211 Winrock International/American Carbon Registry, September 2012, op. cit. 212 Barclays Capital, October 21, 2011, op. cit. 213 Point Carbon/Thomson Reuters, “Carbon price forecast: Still need more offsets,” Olga Chistyakova, presentation at IETA’s Carbon Forum North America, October 2, 2012, http://ietacarbonforum.org/2012/wp-content/uploads/2012/10/Chistyakova-CFNA2012.pdf. 214 David Suzuki Foundation, “All Over the Map 2012: A Comparison of Provincial Climate Change Plans,” March 2012, p. 7, http://www.davidsuzuki.org/publications/downloads/2012/All%20Over%20the%20Map%202012.pdf. 215 See http://docs.cpuc.ca.gov/word_pdf/FINAL_DECISION/164799.pdf. 216 Harris, November 15, 2012, op. cit. 217 See Air Resources Board, “Appendix A: Staff Proposal for Allocating Allowances to the Electric Sector,” 2011, op. cit., p. 5. See also Subchapter 10 Climate Change, Article 5, Section 95892, op. cit., pp. 119-120. 218 Section 95985 of the final California cap-and-trade regulation, September 1, 2012, http://www.arb.ca.gov/cc/capandtrade/september_2012_regulation.pdf. 219 Ibid. 220 Ibid, p. 236. 221 Morris et al., 2010, op. cit., cited in Carlson, 2012, op. cit, p. 235. 222 See Robert Gross et al., “On Picking Winners: The Need for Targeted Support for Renewable Energy,” ICEPT Working Paper, Centre for Energy Policy and Technology, Imperial College London, supported by WWF UK, October 2012, ICEPT/WP/2012/013, pp. 3,7, http://assets.wwf.org.uk/downloads/on_picking_winners_oct_2012.pdf. 223 Economic and Allocation Advisory Committee, 2010, op. cit., p. 17. 224 Sources for information on the EU ETS include: http://ec.europa.eu/clima/policies/ets/faq_en.htm, http://www.co2offsetresearch.org/policy/EUETS.html, http://ec.europa.eu/clima/policies/ets/index_en.htm. 225 See http://ec.europa.eu/clima/policies/ets/index_en.htm

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226 See http://eur-lex.europa.eu/LexUriServ/LexUriServ.do?uri=OJ:L:2004:338:0018:0023:EN:PDF. 227 Ibid, item 7 (p. 2 in pdf pagination). 228 See http://ec.europa.eu/clima/policies/ets/linking/index_en.htm. 229 See http://ec.europa.eu/clima/policies/package/index_en.htm. 230 The EU would increase its target up to 30% if developed countries take equivalent measures under an international agreement. 231 Note that the metric for this target differs from that of California’s Renewable Portfolio Standard (RPS), which requires investor-owned utilities, electric service providers, and community choice aggregators to increase electricity procurement from eligible renewable energy resources to 33% of total procurement by 2020. California’s Low Carbon Fuel Standard (LCFS) addresses renewable energy in transportation by requiring a reduction of at least 10 percent in the carbon intensity of California's transportation fuels by 2020. 232 See http://ec.europa.eu/clima/policies/package/index_en.htm. 233 See http://www.euractiv.com/energy-efficiency/uk-government-waters-eu-energy-e-news-513333. 234 http://www.euractiv.com/energy-efficiency/european-parliament-gives-final-news-514732. 234 Ibid. 235 Information in this paragraph was sourced from http://ec.europa.eu/clima/policies/effort/faq_en.htm. 236 http://ec.europa.eu/clima/policies/effort/faq_en.htm. 237 http://ec.europa.eu/clima/policies/f-gas/index_en.htm. 238 http://ec.europa.eu/clima/policies/transport/fuel/index_en.htm. 239 http://ec.europa.eu/clima/policies/effort/faq_en.htm. 240 Climate Strategies, “Strengthening the EU ETS: Creating a Stable Platform for EU Energy Sector Investment,” 2012, http://www.climatestrategies.org/research/our-reports/category/60/343.html, p. 14. 241 www.eex.com/en/Market%20Data/Trading%20Data/Emission%20Rights/EU%20Emission%20Allowances%20%7C%20Spot. 242 http://theenergycollective.com/davidhone/93166/limits-energy-efficiency. 243 http://qceablog.wordpress.com/2011/06/17/missing-the-point-eu-ets-pits-itself-against-energy-savings/. 244 ec.europa.eu/clima/policies/ets/reform/index_en.htm.

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245 The following states participate in RGGI: Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New York, Rhode Island, and Vermont. New Jersey dropped out of the program at the end of 2011. New Hampshire’s legislature was contemplating leaving the program due to concerns that RGGI acts as a tax on consumers. In 2012, it passed a law that will keep New Hampshire in the program, but will shift some RGGI auction revenue away from energy efficiency programs to provide rebates to ratepayers. http://www.concordmonitor.com/article/338194/bill-that-reforms-rggi-becomes-law?SESSc3bcc3f01c7dfda2c9ba08cafc0a28ff=google. 246 See http://www.co2offsetresearch.org/policy/RGGI.html. 247 See http://www.c2es.org/sites/default/modules/usmap/pdf.php?file=5902. 248 See http://www.dsireusa.org/documents/summarymaps/EERS_map.pdf for a summary of states’ energy efficiency resource standards. 249 States’ RPS targets are summarized at http://www.epa.gov/chp/state-policy/renewable_fs.html. 250 NESCAUM (Northeast States for Coordinated Air Use Management) is a non-profit association of air quality agencies in the Northeast – see http://www.nescaum.org/about-us/overview. The final economic analysis of the Clean Fuels Standard was published in September 2011 (http://www.nescaum.org/documents/cfs-econ-for-stakeholder-mtgs-sep-2011.pdf/). 251 See “Impacts of State-Level Limits on Greenhouse Gases per Mile In the Presence of National CAFE Standards,” Lawrence Goulder, Mark Jacobsen and Arthur van Benthem, May 2009, p. 6, http://www.aere.org/meetings/documents/Jacobsen.pdf. 252 Information on Australia’s Clean Energy Future was sourced from http://www.cleanenergyfuture.gov.au/clean-energy-future/an-overview-of-the-clean-energy-legislative-package/, http://www.cpaaustralia.com.au/cps/rde/xbcr/cpa-site/Summary-of-australian-governments-climate-change-plan.pdf, and Ben Keogh, “Preparing for Carbon Trading in Australia,” Australia Carbon Traders, in the International Emissions Trading Association’s “Greenhouse Gas Market 2012: New Markets, New Mechanisms, New Opportunities,” 2012. 253 See http://www.brookings.edu/research/opinions/2012/07/02-carbon-australia-meltzer. 254 Keogh, 2012, op. cit. 255 See http://www.cpaaustralia.com.au/cps/rde/xbcr/cpa-site/Summary-of-australian-governments-climate-change-plan.pdf. 256 “Legacy waste” is “waste that has been or would normally be deposited in landfill prior to the commencement of carbon price on 1 July 2012.” http://www.climatechange.gov.au/~/media/publications/carbon-farming-initative/CFI-Preliminary-estimates-of-abatement.pdf. 257 Exchange rate obtained from www.oanda.com on October 10, 2012.

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258 Eligible offset categories currently include the capture and combustion of landfill gas, the destruction of methane generated from manure in piggeries, savanna burning, and environmental plantings (planting and/or seeding native tree species on cleared or partially cleared land, and savanna burning). http://www.climatechange.gov.au/en/government/initiatives/carbon-farming-initiative/methodology-development.aspx. 259 Keogh, 2012, op. cit. 260 See http://www.climatechange.gov.au/government/initiatives/ncc.aspx. 261 See http://www.unep.org/transport/gfei/autotool/case_studies/apacific/australia/Australia%20CASE%20STUDY.pdf. 262 See http://www.alp.org.au/getattachment/97cd68c5-087f-4ff8-b1d5-ee2aadae31c9/emission-standards-for-cars/. 263 The future of this and other key climate actions is uncertain, as the opposition political coalition may seek to make the next election a referendum on the carbon tax (see Keogh, 2012, op. cit.). There is already a history of stops and starts in Australia’s climate policy; the Clean Energy Future legislation was introduced and passed only after the Carbon Pollution Reduction Scheme, a cap-and-trade program with broader coverage than the Clean Energy Future’s trading program, was rejected twice in Parliament (see http://www.climatechange.gov.au/en/government/reduce/carbon-pricing.aspx). 264 Information on U.S. federal government GHG policies sourced from http://www.c2es.org/publications/candidates-climate-energy-guide-key-policy-positions-president-obama-governor-romney#ghg-regulations, unless otherwise noted. 265 See http://www.epa.gov/oms/climate/documents/420f12051.pdf. 266 See http://wheels.blogs.nytimes.com/2012/09/04/californias-quiet-but-crucial-role-in-shaping-fuel-economy-standards/. 267 See http://www.epa.gov/otaq/fuels/renewablefuels/index.htm. 268 See http://www.dsireusa.org/incentives/incentive.cfm?Incentive_Code=US04R&re=1&ee=1. 269 See http://www.dsireusa.org/incentives/incentive.cfm?Incentive_Code=US02F. 270 Carlson, 2012, op. cit., p. 227; and, http://grist.org/article/2009-06-03-waxman-markey-bill-breakdown/. 271 See for example A. Denny Ellerman, Paul L. Joskow, and David Harrison, Jr., “Emissions Trading in the U.S. : Experience, Lessons, and Considerations for Greenhouse Gases,” prepared for the Pew Center on Global Climate Change, May 2003, http://www.c2es.org/publications/emissions-trading-us-experience-lessons-and-considerations-greenhouse-gases. 272 Carlson, 2012, op. cit., pp. 207, 227. 273 Air Resources Board, March 2010, op. cit., Table 14, p. 38, case 1.

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274 California Global Warming Solutions Act of 2006, op. cit., Section 38570. 275 Air Resources Board, December 2008, op. cit., p. 18. 276 Ibid. 277 Ibid. 278 Carlson, 2012, op. cit.; Charles River Associates, March 2010, op. cit.; and Analysis Group Inc., August 27, 2012, op. cit., p. 14. 279 Stavins et al., 2007, op. cit., pp. 11-12. 280 The 80% target was established in Governor Schwarzenegger’s Executive Order S-3-05, which was issued on June 1, 2005. To date, it has not been adopted into law. Nevertheless, ARB’s rulemakings to implement GHG emission reduction measures in the SP reference the 80% target and seek to be compatible with meeting that target. 281 Market Advisory Committee, “Recommendations for Designing a Greenhouse Gas Cap and Trade System in California,” recommendations of the Market Advisory Committee to the California Air Resources Board, June 30, 2007, p. 19, http://www.energy.ca.gov/2007publications/ARB-1000-2007-007/ARB-1000-2007-007.PDF. 282 Ibid. 283 Economic and Technical Advancement Advisory Committee (ETAAC), “Recommendations of the ETAAC, Final Report, Technologies and Policies to Consider for Reducing Greenhouse Gas Emissions in California,” February 14, 2008, pp.1-4, http://www.arb.ca.gov/cc/etaac/ETAACFinalReport2-11-08.pdf. 284 Air Resources Board, “Climate Change SP Appendices, Volume I: Supporting Documents and Measure Detail,” December 2008, Appendix D: September 23, 2008 “Western Climate Initiative Design Recommendations,” p. 59, http://www.arb.ca.gov/cc/scopingplan/document/appendices_volume1.pdf. 285 Ibid, p. 58. 286 Carlson, 2012, op. cit., p. 248. 287 Ibid. 288 Air Resources Board, Climate Change SP Appendices, Volume I, Appendix C,” pp. C-55,56. 289 Ibid, pp. C-91, 92. 290 Market Advisory Committee, 2007, op. cit., p. 50. 291 California Global Warming Solutions Act of 2006, op. cit., Section 38561(d). 292 See http://www.leginfo.ca.gov/pub/05-06/bill/asm/ab_0001-0050/ab_32_bill_20060927_chaptered.pdf. 293 Air Resources Board, December 2008, op. cit., pp. 19, 20. 294 Air Resources Board, “Climate Change SP Appendices, Volume I, Appendix C,” December 2008, op. cit.,p. ES-9.

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295 Ibid, p. C-97. 296 Ibid, p. ES-11. 297 Ibid, p. ES-10. 298 Ibid, p. ES-2. 299 Ibid, p. C-129, 300 Ibid, p. 20. 301 Ibid. 302 Market Advisory Committee, 2007, op. cit., p. 68. 303 For example, the economist William Nordhaus recently wrote, “My study is just one of many economic studies showing that economic efficiency would point to the need to reduce CO2 and other greenhouse gas emissions right now, and not to wait for a half-century. Waiting is not only economically costly, but will also make the transition much more costly when it eventually takes place.” William D. Nordhaus, “Why the Global Warming Skeptics Are Wrong,” The New York Review of Books, March 22, 2012. 304 Charles River Associates, March 2010, op. cit., p. 6. 305 Ibid, p. 2. 306 Ibid, p. 13. 307 Ibid, p. 3. 308 Ibid, p. 2. 309 Ibid, p. 12. 310 Ibid., p. 22. 311 Ibid, p. 15. 312 Ibid, p. 25. 313 Ibid, p. 24. 314 Ibid, pp. 20, 25. 315 Ibid, p. 3. 316 Ibid, p. 19. 317 Stavins et al., 2007, op. cit., pp. 11-12. 318 Stavins defines “bottom-up” analyses as analyses that “build an estimate of an individual policy’s costs from the bottom up by piecing together the components of those costs, including any offsetting savings resulting from the policy’s implementation.” Ibid, p. 2. 319 Ibid, p. 14. 320 Ibid.

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321 Ibid, pp. 19-20. 322 EPRI, “Program on Technology Innovation: Economic Analysis of California Climate Initiatives: An Integrated Approach, Volume 1: Summary for Policymakers,” Palo Alto, CA: 2007, 1014641, p. 3-5, http://www.crai.com/uploadedFiles/RELATING_MATERIALS/Newsletters/BC/CRA%20Analyzes%20California%20Climate%20Policy.pdf. 323 Schatzki and Stavins, 2010, op. cit. 324 Stavins et al., 2007, op. cit., pp. 35-36. 325 Ibid, p. 14. 326 Ibid, p. 22. 327 Ibid, p. 19. 328 Ibid, p. 37. 329 Ibid, p. 32. 330 Ibid, p. 37. 331 EPRI, 2007, op. cit., p. 3-5. 332 Air Resources Board, March 2010, op. cit., p. 26. 333 Ibid, pp. 26-27. 334 Charles River Associates, March 2010, op. cit., p. 22. 335Carlson, 2012, op. cit., p. 228. 336 Ibid, pp. 230-231. 337 Ibid, p. 248. 338 Ibid, p. 246. 339 America’s Energy Future Panel on Energy Efficiency Technologies, “Real Prospects for Energy Efficiency in the United States,” 2010; cited in Carlson, 2012, op. cit, p. 245. 340 Kenneth Gillingham, Richard Newell & Karen Palmer, “The Effectiveness and Cost of Energy Efficiency Programs,” 155 Resources 22, 24 (2004); cited in Carlson, 2012, op. cit., p. 246. 341 Stephen Meyers, James McMahon & Barbara Atkinson, Lawrence Berkeley National Lab., “Realized and Projected Impacts of U.S. Energy Efficiency Standards for Residential and Commercial Appliances,” 2008; cited in Carlson, 2012, op. cit, p. 246. 342 Lori Bird, Caroline Chapman, Jeff Logan, Jenny Sumner & Walter Short, National Renewable Energy Lab., “Evaluating Renewable Portfolio Standards and Carbon Cap Scenarios in the U.S. Electric Sector,” 2010, 342Carlson, 2012, op. cit., p. 228. 342 Ibid, pp. 230-231.

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342 Ibid, p. 248; http://www.nrel.gov/docs/fy10osti/48258.pdf; cited in Carlson, 2012, op. cit, p. 236. 343 Carlson, 2012, op. cit, p. 239. 344 Jennifer F. Morris, John M. Reilly & Sergey Paltsev, MIT Joint Program on the Sciences and Policy of Global Change, “Combining a Renewable Portfolio Standard with a Cap-and-Trade Policy: A General Equilibrium Analysis,” 2010; cited in Carlson, 2012, op. cit, p. 235. 345 California Public Utilities Commission, Division of Ratepayer Advocates, DRA Response to Union of Concerned Scientists, Natural Resources Defense Council and Environment California’s letter regarding DRA’s Renewable Portfolio Standard Cost Chart Discussed at the March 3rd Senate Energy Committee Hearing, ftp://ftp.cpuc.ca.gov/.

DRALegis/Position%20Letters/pdfs/DRA%20Response%20to%20Enviro%20Letter.pdf; cited in Carlson, 2012, op. cit, p. 238. 346 See for example, National Action Plan for Energy Efficiency, “Understanding Cost-Effectiveness of Energy Efficiency Programs: Best Practices, Technical Methods, and Emerging Issues for Policy Makers,” Energy and Environmental Economics, Inc. and Regulatory Assistance Project, November 2008, p. 4-14, http://www.epa.gov/cleanenergy/documents/suca/cost-effectiveness.pdf. This report estimated that the cost of meeting California’s 20% RPS target was $130/tCO2e (p. 4-14), and provides several examples of cost-effectiveness studies of energy efficiency programs which concluded that savings exceeded costs (Table 3-5, p. 3-5). 347 Carlson, 2012, op. cit, pp. 238-239. 348 Carlson makes this point later in the document. Carlson, 2012, op. cit, p. 248. 349 Ibid, p. 240. 350 Ibid, p. 248.

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