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COM/MP1/tcg DRAFT Agenda ID #7357 (Rev. 2)

Decision PROPOSED DECISION OF PRESIDENT PEEVEY (Mailed 2/8/2008)

BEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA

Order Instituting Rulemaking to Implement the Commission's Procurement Incentive Framework and to Examine the Integration of Greenhouse Gas Emissions Standards into Procurement Policies.

Rulemaking 06-04-009

(Filed April 13, 2006)

INTERIM OPINION ON GREENHOUSE GAS REGULATORY STRATEGIES

INTERIM OPINION ON GREENHOUSE GAS REGULATORY STRATEGIES

1. Summary

The California Public Utilities Commission (Public Utilities Commission) and the California Energy Commission (Energy Commission) recommend that the California Air Resources Board (ARB) adopt a number of policies and requirements for greenhouse gas (GHG) emissions reductions from the electricity and natural gas sectors in California. These recommendations should be adopted as part of ARB's scoping plan for its further work in implementing Assembly Bill (AB) 32, which requires that statewide GHG emissions be reduced to 1990 levels by 2020.1

In particular, we recommend that ARB adopt a mix of direct mandatory/regulatory requirements for the electricity and natural gas sectors and a cap-and-trade system that includes the electricity sector. We recognize that, under AB 32, ARB has the ultimate responsibility to determine the appropriate design and mix of mandatory and market-based programs to reduce GHG emissions, as prescribed in the law. We also recognize that, prior to adopting any market mechanisms, ARB must find that such mechanisms meet the tests outlined in Part 4 and Part 5 of AB 32.2 Our task in this decision is to give ARB our best formulation of approaches to the electricity and natural gas sectors so that they may be evaluated along with other options for regulating California GHG emissions. We expect that ARB will fulfill the requirements of Part 4 and Part 5 of AB 32 with our advice and recommendations in mind.

Our recommendations are summarized in more detail below. We also recommend that implementation of all aspects of our recommendations to ARB regarding mechanisms to ensure real GHG reductions in the electricity and natural gas sectors should be regularly monitored and enforced, with mechanisms built in for monitoring, rapid identification of problems, and tools to react to, correct, or penalize non-compliance.

In addition, we continue our commitment to work in collaboration with other states and provinces in the Western Climate Initiative to design a cap-and-trade system for the West. The timeframe set for the Western Climate Initiative to agree on a design framework and principles is quite similar to ARB's AB 32 timeframe. Thus, we are confident that we can develop our California policies to be compatible with a regional cap-and-trade system and in cooperation with our partners in the Western Climate Initiative.

1.1. Electricity Sector

The Energy Action Plan includes a "loading order" for investment in electricity resources that puts energy efficiency as the top priority, followed by renewable energy investment. These are also the priorities and best available approaches to drive GHG reductions in California's electricity sector. Therefore, we recommend that all retail providers in California, regardless of regulatory structure or status, be required to deliver these resources to consumers.

For energy efficiency, we recommend that ARB set its scoping plan requirements at the level of all cost-effective energy efficiency in the State. This would be achieved through a combination of utility and non-utility programs coordinated at the State level, with consistent requirements across all types of retail providers. In addition, energy efficiency should be defined broadly to include any programmatic approach that reduces on-site usage of electricity. For electricity from renewable energy, we recommend that the requirements go beyond the current 20% requirement, consistent with State policy, but leave open consideration of exact percentage requirements or deadlines, pending further analysis. We recognize that the agencies may need to seek Legislative authority to achieve some of these objectives. Fundamentally, the energy efficiency and renewable energy programs provide a base of GHG reductions that are permanent and continuous through 2020. We expect these regulations to continue to be enhanced over the AB 32 period.

Beyond this, we recommend that a multi-sector cap-and-trade program be developed for California that includes the electricity sector, provided that ARB finds that the tests outlined in Part 4 and Part 5 of AB 32 are met. In order to have the AB 32 program in place by 2012, design of all mechanisms should begin now; we recommend against any delay or a wait-and-see approach. A number of policy reasons underlie our recommendation to design a cap-and-trade program now:

· A cap-and-trade program is likely to produce additional real GHG emissions reductions beyond the mandatory programs described above, from a wider variety of sources and at a lower cost than requiring reductions only from additional mandatory measures.

· It would achieve reductions in the least-cost manner by allowing for flexibility in achieving emissions targets through allowing obligated entities to rely on the least-cost abatement options across the entire economy.

· It would encourage investment in research and innovation in technologies that lower GHG emissions by providing a larger market in which new technologies could be introduced.

· It would allow market participants to manage risk.

· It would efficiently distribute the cost of GHG reductions across all capped entities, so that total costs of achieving emission targets are minimized.

· AB 32 establishes an aggressive timetable for implementing reductions in California that persuades us to proceed now to design how the electricity sector could participate in a multi-sector cap-and-trade program, which ARB may choose to pursue if it finds that the tests outlined in Part 4 and Part 5 of AB 32 are met.

In order to obtain real GHG emissions reductions, the design of an effective cap-and-trade program in the electricity sector must address the emissions associated with California's imported power. This is because, while California imports approximately 20% of its electricity from neighboring states, those imports represent more than 50% of the GHG emissions from the sector. Therefore, we conclude that any cap-and-trade program design for California must include an import component.

For the point of regulation in the electricity sector, we recommend that ARB designate deliverers of electricity to the California grid, regardless of where the electricity is generated, as the entities responsible for compliance with the AB 32 requirements. This is a variation of the first seller approach recommended by the Market Advisory Committee. In arriving at this conclusion, we evaluated four options against a set of criteria. The four options are:

· Deliverers (a variation of first sellers),

· Retail providers (also referred to as load-based),

· In-state generators, with no inclusion of imports in the cap-and-trade system, and

· In-state generators, with retail providers as the point of regulation for imports (often referred to as a hybrid option).

We assume that as a threshold matter, all options would have to be consistent with other federal, State, and local environmental requirements, such as those pertaining to criteria pollutants and toxic waste. The four options identified above were evaluated using the following criteria:

· Environmental integrity (i.e., ability to produce real GHG emissions reductions),

· Compatibility with/expandability to potential regional and/or national GHG emissions cap-and-trade markets,

· Accuracy and ease of reporting, tracking, and verifying GHG emissions reductions,

· Compatibility with ongoing reforms in wholesale and retail energy markets, and

· Legal issues.

After evaluating the point of regulation options, we find that the deliverer option best meets the first four criteria listed above. Each of the other options has serious shortcomings regarding one or more of our priorities. The deliverer system provides for obtaining real GHG emissions reductions by covering imported power as well as in-state generation. It also shares a number of common characteristics with a pure generation-based point of regulation, making it likely to be compatible with the eventual design of a cap-and-trade system that is broader in geographic scope (regional and/or national). The deliverer point of regulation also improves the ability to report and track emissions in the sector, which in turn helps provide real GHG reductions. It also minimizes the impact of AB 32 GHG regulations on California's wholesale electricity markets. In addition, it is consistent with the existing methods for regulating criteria pollutants and toxic waste.

Finally, the deliverer method can be supported on legal grounds. For all of these reasons, we recommend deliverers as the point of regulation for a GHG cap-and-trade program as it applies to the electricity sector.

We also address certain policy questions regarding the allocation of GHG emission allowances in a deliverer-based point of regulation system. Fundamentally, determining the point of regulation is independent from determining the method of obtaining allowances or the method of distributing any benefits which might come from allocation. Allocation issues will be addressed in more detail in the next portion of this proceeding.

In addressing allocation issues, we keep in mind that some deliverers of electricity to the California grid are also retail providers of electricity for consumers. We also recognize that allocation policy will have an impact on consumer costs. Our intent in developing additional allocation policy recommendations is to ensure that GHG emissions reductions are accomplished equitably and effectively, at the lowest cost to consumers. While we may wish to reward early actions to reduce GHG emissions in advance of 2012 when the AB 32 compliance period begins, it is not our intent to treat any market participants unfairly based on their past investments or decisions made prior to the passage of AB 32.

We have determined that the next portion of this proceeding can be most focused and productive if a few major design principles are adopted in this decision. As a starting principle, it is important that any policy for distribution of allowances provide that revenues from the sale of allowances be used primarily to benefit consumers in the energy sectors directly. This is because energy sources such as electricity and natural gas are vital commodities. Thus, we believe special focus is warranted for allowance allocation policy in the energy sectors.

The method by which GHG emission allowances are distributed will affect liquidity in the emission allowance market; incentives to invest in low-GHG technologies and fuels, including energy efficiency; the potential for windfall profits; and costs to various groups of stakeholders.

With these impacts in mind, we recommend that some portion of the emission allowances available to the electricity sector should be auctioned. Among the options under consideration would be to phase in auctioning beginning with a small percentage in the first year and transitioning to greater percentages over time as the State and market participants gain experience with auctions. We make the recommendation for some auctioning in order to promote least-cost solutions throughout the California economy, promote liquidity in the emission allowance market, improve the accuracy of emission allowance prices as a reflection of marginal emission reduction costs, improve investment incentives, avoid windfall profits at consumer expense, and allow new market entrants easy access to allowances.

An integral part of this auction recommendation is that the majority of the proceeds from the auctioning of allowances for the electricity sector should be used in ways that benefit electricity consumers in California, such as to augment investments in energy efficiency and renewable energy or to provide customer bill relief. There are multiple ways to accomplish allocation of benefits to consumers.

As we discuss in this decision, additional record development is needed to allow us to make more complete recommendations on allowance distribution issues, including the proper mix between auctions and administrative allocations of emission allowances for the electricity sector, the manner in which auction proceeds should be used for the benefit of electricity consumers, and the manner in which any administrative allocations should be made. We will consider various options for the allocation of allowances, including to retail providers and/or deliverers. The concerns of all parties, along with potential solutions, will be considered carefully.

A cap-and-trade market structure must address the potential for volatility in the price of GHG emission allowances. In order to avoid short-term allowance availability problems and send appropriate long-term investment signals, a certain degree of stability in allowance prices is needed. Mechanisms that could be used to help ensure stability of allowance prices include, but may not be limited to, banking or borrowing of allowances, allowance price floors or ceilings, and GHG offsets. We will continue to explore these options and plan to address them in a later decision in this proceeding.

In addition, the modeling work being conducted in coordination with this proceeding is likely to help us answer more analytical questions about the impact of possible allowance distribution policies and other flexible compliance mechanisms on consumers and companies in the electricity sector.

Finally, in response to comments on the proposed decision, we plan to consider further the treatment of combined heat and power (CHP) facilities under this policy framework. We want to avoid unintended negative consequences for CHP, which may be a valuable source of additional GHG emissions reductions in California. Therefore, we intend to consider further the treatment of emissions from CHP facilities in the next portion of this proceeding, and plan to include recommendations on this issue to ARB in our next decision.

1.2. Natural Gas Sector

For purposes of this decision, we include in the natural gas sector combustion of natural gas that is not otherwise likely to be regulated by ARB as a point source. Natural gas combustion for electricity generation is covered under the electricity sector and combustion at large industrial facilities will be covered as industrial emissions. Therefore, for purposes of this decision, the natural gas sector is defined to include end-user combustion at facilities below ARB's reporting threshold for GHG emissions, as well as emissions from natural gas infrastructure, including fugitive emissions from pipelines and compressor stations.

For this portion of emissions associated with the use of natural gas, we recommend that all entities that provide transportation, distribution, and/or retail sales of natural gas to end-users (natural gas providers) in California be required to provide a minimum level of energy efficiency or other demand reduction programs to their customers. Energy efficiency is the best available approach to drive GHG reductions in California's natural gas sector. Therefore, we recommend that all natural gas providers in California, regardless of regulatory structure or status, be required to deliver energy efficiency to consumers. Fundamentally, energy efficiency provides a base of GHG reductions that are permanent and continuous through 2020. We expect these regulations to continue to be enhanced over the AB 32 period. We also expect to consider other programmatic options for reducing demand for natural gas including the use of solar hot water heating equipment.

We recommend that the natural gas sector not be included in a cap-and-trade system at this time. There are several reasons for this recommendation. Key differences between the electricity and natural gas sectors persuade us that it would be premature to include the natural gas sector in a cap-and-trade system:

· Significantly fewer options exist to reduce GHG emissions in the natural gas sector compared to the electricity sector.

· There is currently very limited availability of low-carbon alternative sources of natural gas.

· Energy efficiency and other natural gas demand reduction programs are the best options for reducing GHG emissions in the natural gas sector.

· The incremental benefits from including the natural gas sector in a multi-sector cap-and-trade program are likely to be smaller than those for the electricity sector.

· Reporting protocols for GHG emissions are still under development.

· Relying on programmatic measures to achieve emission allows additional time to develop reporting protocols.

As California gains greater experience with a cap-and-trade system, regional and national frameworks are established, reporting protocols are adopted, and alternative lower-carbon sources of natural gas are developed, we expect that it will become appropriate to add the natural gas sector to the multi-sector GHG emissions allowance cap-and-trade system, and we expect to recommend inclusion of the natural gas end-use sector at that time. Taking direct programmatic actions in the meantime is also compatible with the potential inclusion of the natural gas sector in an upstream form of regulation in the future.

2. Background

In the Order Instituting Rulemaking (OIR) initiating Rulemaking (R.) 06-04-009, the Public Utilities Commission provided that Phase 2 would be used to implement a load-based GHG emissions cap for electricity utilities, as adopted in Decision (D.) 06-02-032 as part of the procurement incentive framework, and also would be used to take steps to incorporate GHG emissions associated with customers' direct use of natural gas into the procurement incentive framework.3

On September 27, 2006, Governor Schwarzenegger signed into law AB 32, "The California Global Warming Solutions Act of 2006." This legislation requires ARB to adopt a GHG emissions cap on all major sources in California, including the electricity and natural gas sectors, to reduce statewide emissions of GHGs to 1990 levels.

We held a prehearing conference (PHC) in Phase 2 on November 28, 2006. The Phase 2 scoping memo, which was issued on February 2, 2007, determined that, with enactment of AB 32, the emphasis in Phase 2 should shift to support implementation of the new statute. Because of the need for "a single, unified set of rules for a GHG cap and a single market for GHG emissions credits in California," the Phase 2 scoping memo provided that "Phase 2 should focus on development of general guidelines for a load-based emissions cap that could be applied ... to all electricity sector entities that serve end-use customers in California,"4 including both investor-owned utilities (IOUs) that the Public Utilities Commission regulates and publicly owned utilities (POUs).

As detailed in the Phase 2 scoping memo, the Public Utilities Commission and Energy Commission are undertaking Phase 2 on a collaborative basis, through R.06-04-009 and Docket 07-OIIP-01, respectively, to develop joint recommendations to ARB regarding GHG regulatory policies as it implements AB 32.

The Phase 2 scoping memo noted that the policies in D.06-02-032 were adopted prior to passage of AB 32. It placed parties on notice that, in the course of Phase 2, the Public Utilities Commission might adopt policies that would modify portions of D.06-02-032 as a result of AB 32, subsequent actions by ARB, or the record developed in the course of this proceeding.5

In D.06-02-032, the Public Utilities Commission stated an intent to apply a load-based GHG emissions cap to the three major IOUs, and also to Community Choice Aggregators (CCAs) and Electric Service Providers (ESPs) operating within the service territory of the three major IOUs. In D.06-10-020 amending the OIR, the Public Utilities Commission specified that, with the passage of Senate Bill (SB) 1368, all ESPs, all CCAs, and all electrical corporations, including all IOUs, multi-jurisdictional utilities, and electric cooperatives, are respondents to this rulemaking. The Phase 2 scoping memo specified that Phase 2 would address whether the load-based GHG emissions cap should apply to the additional respondents added by D.06-10-020.

On April 19, 2007, the Public Utilities Commission and the Energy Commission held a symposium which addressed linking GHG cap-and-trade systems. Reporting issues were also discussed.

As Phase 2 has progressed, the Public Utilities Commission has modified the scope of Phase 2 through D.07-05-059 and D.07-07-018 amending the OIR.6 D.07-05-059 specified that Phase 2 should be used to develop guidelines for a load-based GHG emissions cap for the entire electricity sector and recommendations to ARB regarding a statewide GHG emissions limit as it pertains to the electricity and natural gas sectors. To that end, D.07-05-059 also expanded the natural gas inquiry in Phase 2 to address GHG emissions associated with the transmission, storage, and distribution of natural gas in California, in addition to the use of natural gas by non-electricity generator end-use customers as originally contemplated in the OIR. The list of respondents to this proceeding was amended to include all investor-owned gas utilities, including those that provide wholesale or retail sales, distribution, transmission, and/or storage of natural gas.

D.07-07-018 amended the OIR further to provide for consideration in Phase 2 of issues raised by and alternatives considered in the June 30, 2007 Market Advisory Committee report entitled, "Recommendations for Designing a Greenhouse Gas Cap-and-Trade System for California," to the extent that they were not already within the scope of Phase 2. Thus, D.07-07-018 provided for consideration of alternatives to a load-based cap for the electricity sector, a deviation from the policies adopted in D.06-02-032. In that report to ARB, the Market Advisory Committee considered design of a market-based program to reduce GHG emissions, and described various options for the scope of a cap-and-trade program. For the electricity sector, the Market Advisory Committee recommended a "first seller" approach, with the entity that first sells electricity in the state responsible for meeting the compliance obligation. As discussed in this decision, we are now focusing on a variation on this approach, the "deliverer" approach.

By Administrative Law Judge's (ALJ) rulings, parties were asked to submit comments and legal briefs on issues raised by the Market Advisory Committee report. On August 21, 2007, the Public Utilities Commission and the Energy Commission held a joint en banc hearing addressing the type and point of GHG regulation in the electricity sector, including deliverer/first seller and load-based cap-and-trade approaches. In an ALJ ruling issued on November 9, 2007, parties were provided an opportunity to file additional comments on issues regarding the type and point of regulation for the electricity sector.

By ALJ ruling dated July 12, 2007, parties were asked to file comments on preliminary recommendations of the Public Utilities Commission staff regarding the regulatory treatment of GHG emissions in the natural gas sector. The staff paper attached to the ALJ ruling identified and discussed various policy issues associated with developing regulations to control GHG emissions in the natural gas sector. A prehearing conference was held on August 2, 2007 to address the manner in which regulation of GHG emissions in the natural gas sector should be considered in this proceeding. By ALJ ruling dated November 28, 2007, parties were asked to file comments on the approach to GHG regulation that would be appropriate for the natural gas sector.

ARB is taking the lead on developing reporting protocols and requirements for all entities covered by AB 32, including the electricity and natural gas sectors. In D.07-09-017 and a companion Energy Commission decision, the Public Utilities Commission and the Energy Commission recommended that ARB adopt proposed regulations contained in that decision as reporting and verification requirements applicable to retail providers and marketers in the electricity sector. The reporting requirements for the electricity sector approved by ARB on December 6, 2007 are consistent with the proposed regulations recommended by the two Commissions. ARB has indicated that protocols for some sectors, including the natural gas sector, will be issued later. While staff will continue to coordinate closely with ARB on development of reporting requirements, we do not plan to develop recommendations on reporting requirements for the natural gas sector unless reporting issues arise that are unique to the sector.

The scoping memo specified that Phase 2 would address the appropriate 1990 emissions baseline for the entire electricity sector. ARB adopted statewide 1990 GHG emissions levels on December 6, 2007. No concerns related to 1990 emissions in the electricity and natural gas sectors have been identified in this proceeding to warrant development of recommendations by the two Commissions to ARB. As a result, we have not developed recommendations regarding the 1990 GHG emissions baseline.

Phase 2 is also addressing how to distribute annual emissions allowances under a cap-and-trade mechanism to individual entities, to the extent appropriate, and how such a process should be administered. An October 15, 2007 ALJ ruling requested comments on allowance allocation issues, and a workshop was held on this topic on November 5, 2007.

As part of our Phase 2 analysis, the Public Utilities Commission hired a consultant to conduct detailed modeling of the electricity sector impacts of potential GHG emissions cap scenarios. The modeling analysis is to take into account the policy options developed in other portions of the proceeding in order to analyze various options for cap design and implementation for the electricity sector. The consultants are also considering the natural gas sector in their modeling process. However, separate, detailed modeling of the natural gas sector is not being undertaken. The modeling effort is examining the level and costs of emission reductions that can be achieved by the electricity and natural gas sectors before the 2020 deadline set by AB 32. It is also addressing the rate at which these types of reductions can be achieved, which will inform our recommendations for annual emissions goals for the electricity and natural gas sectors. A November 9, 2007 ALJ ruling requested comments on modeling-related issues and on a staff paper on emission reduction measures. A workshop on input assumptions and initial model results was held on November 14, 2007.

3. GHG Policies for the Electricity Sector

In this section, we consider policies for the regulation of GHG emissions in the electricity sector. As we explained in D.07-09-017, AB 32 governs statewide GHG emissions including electricity consumed in California (including imports) and in-state generation that is exported out of California. Thus, as a starting point, we consider all such electricity to be within the electricity sector. Because power that is wheeled through California does not fall within the purview of AB 32,7 we do not include power wheeled through California in the electricity sector for purposes of establishing GHG regulations.

The proposed decision suggested that power delivered to the California grid from CHP facilities be regulated as part of the electricity sector. In Section 4.2.2, we defer a determination of the proper treatment of GHG emissions from CHP facilities pending further analysis. Thus, we have not decided yet whether the recommendations developed in this decision for the electricity sector should apply, in whole or part, to electricity generated by CHP facilities.

3.1. Overview of Approaches Considered

In Phase 2, we have considered a variety of approaches to GHG regulation in the electricity sector. All approaches are based on a foundation of mandatory GHG emission reduction programs, including cost-effective energy efficiency and investment in renewable resources. Before describing the positions of the parties, it is useful to provide a brief overview of the major alternatives that have been examined.

First, the type of regulation appropriate to the sector has been considered. By this we mean whether the regulation is of the direct/mandatory type or whether it is market-based. Second, for the market-based options, the point of regulation has been considered. By this we mean the entity with responsibility for compliance with the regulation.

The type of regulation options considered (some in more detail than others) include a carbon tax, upstream regulation of emissions from fossil fuel combustion, a downstream cap (with or without trading), and additional direct mandatory requirements.

The point of regulation options considered include retail providers of electricity, in-state generators (with no direct provision for imported power in the cap-and-trade program), deliverers of electricity to the California grid, and a hybrid in which the point of regulation would be generators for in-state power and retail providers for imports.

In addition, we consider options for the distribution of GHG emissions allowances, should a cap-and-trade system be adopted for California that includes the electricity sector.

3.2. Types of GHG Regulation

In this section, we address various types of GHG regulation for the electricity sector in California.

As described in an Assigned Commissioner ruling revising the scoping memo for this proceeding, we have examined options for further direct programmatic regulations for the electricity sector:

"Regardless of whether a market-based system for GHG regulation is adopted,... regulatory and other strategies will continue to be employed to reduce GHG emissions in the electricity and natural gas sectors in California. In particular,...currently mandated programs such as energy efficiency programs, renewable portfolio standards, and building and appliance efficiency standards will continue. Such programs also may be expanded if such expansion is found to be desirable relative to other emission reduction strategies. Additional emission-reducing mandates could also be imposed. For example, efforts could be undertaken to expand the emission performance standard to apply to short-term contracts and/or non-baseload power. In addition, ARB could impose other emission reduction measures, e.g., on generators in California."8

In particular, we evaluate the requirement that all retail providers of electricity in California be required to provide a minimum level of cost-effective energy efficiency programs and renewable energy delivery.

We also consider the alternative of capping GHG emissions from retail providers, without introducing an emissions trading component. In this approach, California would rely only on strategies not involving emissions trading to reduce emissions toward AB 32 goals, pending implementation of a regional and/or national GHG program. Such a strategy could involve setting entity-specific caps to ensure and track progress toward AB 32 goals in the absence of an emissions trading program.

We also consider the adoption of various forms of a cap-and-trade system that includes California's electricity sector. Options include upstream regulation of fossil fuel combustion, inclusion in a regional and/or a national cap-and-trade system, or inclusion in a multi-sector cap-and-trade system in California.

The Market Advisory Committee, in its recommendations to ARB, presented an option for upstream regulation of fossil fuel combustion in California.9 This model is also currently under consideration in the United States Congress.

As mentioned above, we also consider deferring consideration of a California cap-and-trade system pending implementation of a regional and/or national program. We also consider options for a California cap-and-trade system to coexist with or transition to a regional and/or national system.

3.2.1. Positions of the Parties

In this section, we summarize the input received from parties on the subject of the type of regulation appropriate for the electricity sector in California.

3.2.1.1. Cap-and-Trade System

Most parties support a market-based cap-and-trade system for the electricity sector, including PG&E, SDG&E/SoCalGas, Calpine, IEP, EPUC/CAC, Powerex, Constellation, SMUD, SCPPA, NRDC/UCS, Environmental Defense, Morgan Stanley, WPTF, and AREM.10 They have differing opinions, however, regarding the possible need to wait until a regional and/or national trading system can be implemented. Other parties including LADWP assert that additional information is needed before the desirability of a cap-and-trade system can be determined.

Supporters of a market-based compliance program for the electricity sector in California assert that a well-designed cap-and-trade program would yield numerous benefits.

Supporters submit that, by establishing a market price for carbon (PG&E), providing price visibility and access to the global marginal price of abatement (SDG&E/SoCalGas), and giving the right price signals (DRA, IEP, and EPUC/CAC), a cap-and-trade system would provide the least-cost method of obtaining emission reductions.

Parties submit the following additional reasons for supporting a cap-and-trade program for the electricity sector:

· Emissions trading would maximize flexibility in achieving emissions targets (Calpine).

· The compliance flexibility would direct capital investment to the lowest cost opportunities (PG&E and Morgan Stanley) and allow entities to make the most cost-effective choices (SDG&E/SoCalGas).

· Cap-and-trade would harness the ingenuity of the market to identify the best ways to meet the goal (Morgan Stanley).

· Emissions trading would reward innovation (Calpine) and efficiencies (Powerex).

· Entities would be likely to reduce emissions more (SDG&E/SoCalGas) and sooner (Calpine, IEP) than they would under regulatory mandates. SCPPA views the purpose, however, as achievement of mandated GHG reductions at a reduced cost, not additional emissions reductions.

· Cap-and-trade would advance abatement technology research and accelerate the introduction of leading-edge carbon reduction technologies (PG&E and IEP), and would lead to operational improvements (IEP).

· Cap-and-trade would internalize externalities and consumers would face the proper incentive to curtail electricity use (IEP).

· Cap-and-trade would allow market participants to manage the risks associated with GHG emissions reduction compliance (Constellation).

· It would give options to meet targets given operational and demand fluctuations and would help manage the "blocky" nature of emission reduction measures (SMUD).

· Cap-and-trade would efficiently distribute the cost of greenhouse gas reductions across capped entities (WPTF) and would provide allocative and productive efficiencies (AREM).

PG&E and Morgan Stanley stress that a cap-and-trade approach would help ensure environmental integrity. They assert that a cap-and-trade approach with a specific reduction target would provide a high degree of certainty that the AB 32 reduction goals will be met.

According to Morgan Stanley, a market-based approach may be less complex to administer than command-and-control.

Several parties argue that California should put its primary efforts into collaborating at the regional and national levels in order to develop an effective program. The CAISO submits that a fully-effective GHG policy for the electricity sector must cover the bulk of the electricity sector in the western United States. The CAISO submits that a major goal of California policy should be to facilitate the establishment and implementation of federal or other West-wide policies. Environmental Defense asserts that California needs to take a leadership role in designing an effective cap-and-trade system to shape future federal regulation. Constellation argues that California's development of a well-designed framework for a market-based cap-and-trade program can serve as a model for the development of regional and national systems. Finally, PG&E points out that momentum is building to pass federal cap-and-trade legislation and State actions will help to build this momentum.

Several parties recognize that a cap-and-trade system is likely to provide only a relatively small portion of the overall emissions reductions needs. NRDC/UCS stress, however, that it would reduce emissions lower than could be achieved through existing regulatory programs alone. The CAISO comments that most of the GHG reductions that would be achieved in the electricity sector in the short term likely would result from existing renewable energy and energy efficiency programs. WPTF states similarly that, in the short term, emissions reductions from a market-based approach are not likely to be much larger than those deriving from committed regulatory programs, citing the potential for leakage as one reason. WPTF asserts, however, that a cap-and-trade program has greater potential for greater emission reductions in the long term.

Sectors and Geographic Scope

Several parties see a need for a cap-and-trade program to include multiple sectors, not just the electricity sector, and/or be regional or national in scope. SDG&E/SoCalGas state that a diversity of emissions reduction opportunities would provide the least-cost approach and reduce market power concerns. GPI submits that only a regional approach can prevent abuses to California consumers, and that it favors a delay, if needed for development of a regional approach and a tracking system. The CAISO states that California's dependency on imported power raises doubts about the environmental integrity of a California-only trading system.

DRA states that a liquid market with broad participation is needed to minimize opportunities for market power activities and collusion. LADWP argues similarly that a cap-and-trade program must be robust and economy-wide in order to be successful. LADWP submits that it remains to be determined which sectors, other than electricity, can implement a market-based mechanism effectively. LADWP states that further evaluations are needed to determine if a California-only market-based system can be robust enough to resist market power and/or manipulation, gaming, credit hoarding, and other potentially negative impacts that could affect system reliability and price volatility. Absent such assurances, LADWP recommends that ARB postpone a market-based cap-and-trade program.

Timing

Several parties, including Calpine, IEP, EPUC/CAC, WPTF, DRA, Environmental Defense, and NRDC/UCS, urge California to move forward without waiting for a resolution of GHG issues at the regional or federal level. These parties urge California to act as a leader in creating a cap-and-trade program for a 2012 implementation date. WPTF argues that deferral of a market-based system would hinder the development of the most efficient emission reduction tool, delay the development of tracking infrastructure necessary for a trading system, and miss an important opportunity to gain experience with GHG trading. NRDC/UCS state that the longer a cap-and-trade system is in operation, the longer it has to reap benefits. It submits that California has an opportunity for leadership to influence regional and federal systems, whereas waiting would relegate California to being "one voice among many at the table." NRDC/UCS stress that, if California adopts a cap-and-trade program with an allowance distribution scheme that does not reward dirty polluters, it would advantage California, as a relatively clean state, if a similar system were adopted nationally.

These parties urge that California should continue working toward a regional or federal system and, to the extent possible, should design its cap-and-trade program so it can transition smoothly into a regional or federal system (IEP, Calpine, Constellation, WPTF, and Environmental Defense).

Other parties that support an eventual cap-and-trade program, including PG&E and SDG&E/SoCalGas, suggest that deferral of a cap-and-trade market structure until it can be implemented on a regional and/or national basis may be desirable. While recognizing that California must proceed with implementing a compliance program regardless of broader action, PG&E states that deferral of a cap-and-trade program may facilitate integration with a subsequent regional or federal program and could yield significant advantages and efficiencies. In PG&E's view, a key integration issue is the transferability of allowances, and an inability to transfer such allowances could cause significant integration issues and be very costly to complying entities and retail providers' customers.

SDG&E/SoCalGas state similarly that deferral is reasonable given the regional/national nature of GHGs. It is concerned that a California-only program could strand investments, particularly if California implements a retail provider-based program but a later regional or national program is source-based.

The CAISO states that it does not necessarily favor immediate implementation of a cap-and-trade system in California. The CAISO states that it is difficult to justify the cost of establishing a sophisticated trading system that might be abandoned soon in the face of federal preemption. It sees advantages to deferring implementation of trading until the form of federal regulation becomes clear. NCPA takes a similar position, stating that it is not important that a cap-and-trade program be adopted in the near term, but that any system adopted in California should allow for a transition to a regional or federal program that does not affect California investments adversely.

Other parties are more cautious about a cap-and-trade approach to GHG emission reductions. TURN recommends that a cap-and trade program not be implemented for the electricity sector in 2012. It states that California would be better served by promoting existing policies that result in real GHG reductions, by developing a comprehensive regional tracking system for GHGs, and by deferring implementation of a cap-and-trade system, pending further regional or national developments.

DRA states that while, on its face, it seems that the electricity sector should be included in a California cap-and-trade program, that is true only if such a program reduces emissions. It views the on-going modeling effort as being critical to answering whether a market-based system is likely to provide additional reductions. DRA submits that deferral of a cap-and-trade program until there is a broader coverage would avoid contract shuffling and leakage issues.

LADWP supports direct regulation as the least-cost approach, with a cap-and-trade program as a secondary method of compliance. LADWP recommends that a California-only cap-and-trade program be implemented only if it can be determined to cost-effectively provide emission reductions equal to those that can be achieved through direct regulation within the same time period, and if further evaluations determine that the market would be robust enough to avoid market power problems.

3.2.1.2. Other Emission Reduction Approaches

Parties are divided into three distinct groups regarding how emissions from the electricity sector can be reduced most cost-effectively.

Supporters of a cap-and-trade system believe that alternatives would be less effective. Powerex argues that trading should be a key component because "a cap alone unfairly assumes all emitters have the same cost of compliance, penalizes those that have a higher cost of compliance, and does not reward those that may be able to reduce emissions greater than what is required by compliance through being rewarded by the market for such action." Similarly, SCE suggests that, "Given the significant actions of the electric sector in California to reduce GHG emissions to date, it is unlikely that the most cost-effective reductions will come from this sector. Instead, they are likely to come from trading with other sectors and through offsets. Increased programmatic goals are likely to cost more and raise rates more than a market-based approach."

Constellation suggests that, "while there is likely more that can be done with energy efficiency and renewables, these mechanisms will have their limitations, as is evidenced by the increased attention to the real costs of wind power with respect to the need for services that can shape the wind power deliveries and ancillary services necessary to provide contingent power supply." SMUD expresses concern that strict command and control goals in areas such as Renewables Portfolio Standard (RPS), energy efficiency, and solar installations would lead to excessive costs and that, "the compliance costs will not be the most cost effective as required by AB 32. Morgan Stanley adds that, "Command and control mechanisms tend to be more complex to administer than market-based approaches and lead to less than optimal investment in GHG reduction technologies."

A second group echoes TURN's sentiment that, "the state would be better served by promoting existing policies that result in real GHG reductions, by developing a comprehensive regional tracking system for greenhouse gases and by deferring the implementation of a cap-and-trade system for the electric sector pending further regional or national developments." LADWP supports "direct regulation through changes in the generation resource mix and avoidance of emissions through energy and water conservation and demand-side management as the least cost approach to reducing emissions for the electricity sector." DRA asserts that "increased programmatic goals likely would increase cost of electricity but not necessarily more so than a cap-and-trade program."

A third group expresses an interest in a dual approach, whereby a cap-and-trade system would be implemented at the same time that the stringency of existing programs such as RPS, energy efficiency, and the Emissions Performance Standard would be increased. SCPPA contends that, "The continuation and expansion of targeted energy efficiency, renewable portfolio, technology development, and similar programs aimed at retail providers as the GHG point of regulation would be compatible with instituting a cap-and-trade." NRDC/UCS assert that, "a cap-and-trade system provides only a generic innovation signal, and targeted policies are more useful for spurring innovation for specific technologies, and overcoming market barriers." NRDC/UCS argue further that both a cap-and-trade system and increased regulatory measures are necessary because, "regulatory policies in the absence of a cap on absolute emissions would not guarantee that the electric sector will meet the GHG reductions goals of the state for this sector."

Parties generally support the incorporation of flexible compliance mechanisms regardless of whether they prefer a cap-and-trade or command and control approach to emissions reductions. Constellation asserts that, "The use of offsets and other flexible compliance tools will help to achieve emission reductions in a cost effective manner and should be incorporated into any emission reduction strategy, whether those strategies are market-based or not."

SMUD asks that retail providers have general flexibility in meeting their targets through existing energy efficiency and renewable programs.

3.2.2. Discussion

In determining our recommendation for how to regulate the electricity sector in California under AB 32, there are essentially four options that could be adopted individually or in combination: 1) a carbon tax, 2) upstream regulation of emissions from fossil fuel combustion, 3) a downstream emissions cap (with or without trading), and 4) additional direct mandatory/regulatory requirements.

We did not seriously consider the carbon tax option in the course of this proceeding, due to the fact that, if a carbon tax were implemented, it would most likely be imposed on the economy as a whole by the Legislature after recommendations by ARB. Since our focus is on energy sectors only, we did not examine this idea in any detail in this proceeding, nor do we plan to do so.

Similarly, the Market Advisory Committee presented an option for upstream regulation of fossil fuel combustion in California. As the Market Advisory Committee points out, "there is no precedent for using this approach in a cap-and-trade program run by a single agency." However, if this were to be done, ARB may impose it on an economywide basis. While there may be policy reasons for further examination of this approach, which is also under consideration in the United States Congress, we have not undertaken a detailed review of this option for the energy sectors in California. This proposal is not well defined and seems more aimed at a national regulatory regime. Instead, we have focused attention on additional direct mandatory/regulatory requirements and an electricity sector cap or cap-and-trade program.

We begin by examining the direct mandatory/regulatory policies and requirements that California already has in place that contribute to GHG reductions. The State's Energy Action Plan lays out a "loading order" for investment in electricity resources in California that puts energy efficiency as the top priority, with renewable resources second, and clean fossil-fired generation to the extent that other options are not available. To address each of these resource areas, California has three primary policy tools already in place:

In the case of energy efficiency building codes and appliance standards, the Energy Commission updates these approximately every three years and is continuously including more requirements that reduce electricity use and therefore GHG emissions. These regulations provide a base of electricity and GHG reductions that are permanent and continuous through 2020. We expect these regulations to continue to be enhanced over the entire AB 32 period.

In addition, the Public Utilities Commission sets requirements for the amount of energy savings each investor owned utility (IOU) is required to achieve on an annual and cumulative basis. Current requirements are set through 2013 and are being updated this year in R.06-04-010 to include goals through 2020. The goals are generally set according to the availability of cost-effective energy savings in the utilities' service territories. In D.07-09-043, the Public Utilities Commission also set up a risk/reward mechanism for the IOUs, which allows them to earn financial incentives as they approach meeting their energy savings goals and assesses penalties if they fail to meet at least 65% of their goals.

AB 2021 (Levine, Chapter 734, statutes of 2006) required the Energy Commission, in collaboration with the Public Utilities Commission and the publicly owned utilities (POUs), to set statewide energy efficiency targets for 2017 for all utilities in the state. The legislation requires, among other mandates, that the POUs identify all potentially achievable cost-effective electricity energy savings, establish annual targets for achieving feasible and reliable energy efficiency savings and demand reduction for the next 10-year period, and report these targets to the Energy Commission.

Based upon an assessment of energy efficiency potential available, and considering the need for aggressive energy efficiency savings to help meet climate change goals, the Energy Commission has established a statewide target to achieve 100% of the economic potential identified for energy efficiency. This target is significantly higher than the combined goals proposed by the POUs, the IOUs, or other parties. The Energy Commission expects this statewide target to be achieved through a combination of utility and non-utility programs coordinated at the state level by the Energy Commission and the Public Utilities Commission.

No statutory requirements currently exist for Energy Service Providers (ESPs) or Community Choice Aggregators (CCAs) to invest in energy efficiency for their customers, though their customers fund a portion of the IOU energy efficiency programs through their distribution charges and are currently eligible to participate in IOU-administered energy efficiency programs.

Considering all of this, we recommend that ARB set its scoping plan requirements for energy efficiency at the level of all cost-effective energy efficiency in the State. This requirement would be achieved through a combination of utility and non-utility programs coordinated at the State level, with consistent requirements across all types of retail providers.

The RPS statutes (Senate Bill (SB) 1078 enacted in 2002, as amended by SB 107 in 2006) require IOUs, CCAs, and ESPs to provide a minimum of 20% of delivered energy from renewable sources by 2010. In addition, SB 1078 as amended by SB 107 requires POUs to set RPS targets, but does not specify minimum delivery requirements or the types of renewables that should qualify.

SB 1, enacted in 2006, requires the development of a solar photovoltaic program for California, including both IOUs and the POUs. Production of solar energy at customer sites is another option for reducing GHG emissions from the electricity sector. This program is a direct programmatic measure that will reduce emissions in the sector from customers of several types of retail electricity providers.

SB 1368 enacted in 2006 directed the Public Utilities Commission and the Energy Commission to develop an emissions performance standard for non-renewable, generally fossil-fueled generation resources, for all retail providers of electricity. The Public Utilities Commission adopted regulations for IOUs, ESPs, and CCAs in January 2007 (D.07-01-039), while the Energy Commission adopted regulations for POUs in August 2007; the two sets of requirements are nearly identical. The regulations require all new long-term investments in baseload generation by retail providers to be in power plants that emit no more than 1,100 pounds of carbon dioxide (CO2) per megawatt hour (MWh) produced.

Of the State statutes we have just described, the emissions performance standard statute is the most recent, and it applies its environmental requirements uniformly to all electricity retail providers in California. We agree with the underlying logic of this statutory approach. The goals of AB 32 would be best achieved if all retail providers of electricity, including IOUs, POUs, ESPs, and CCAs, are subject to minimum requirements in the areas of cost-effective energy efficiency and renewables. Such requirements would benefit California customers by ensuring that they receive the GHG emission reductions of cost-effective energy efficiency and renewables. Therefore, we recommend that ARB, as part of its AB 32 regulations, adopt mandatory minimum levels of cost-effective energy efficiency savings required from POUs, at levels recommended by the Energy Commission. Likewise, ARB should adopt mandatory minimum levels of cost-effective energy efficiency consistent with the programs and goals adopted by the Public Utilities Commission for IOUs, CCAs and ESPs.

The POU governing boards have already set 20% renewables goals. Some of the largest POUs plan to achieve that level by 2010, a few have already obtained it, and the rest plan to do so by 2017. We recommend that ARB require that the POUs deliver at least 20% renewable electricity to their customers by no later than 2017 and incorporate this assumption into its scoping plan. ARB should include enforcement mechanisms in its plan, so that it can be assured that the related GHG reductions will be achieved.

In making these recommendations, we have not analyzed whether ARB has the authority to implement these regulations as part of AB 32. Our preliminary analysis suggests that they do. However, if ARB believes that such authority does not exist, we recommend that it seek such authority from the Legislature.

In addition, we also recognize that existing RPS requirements are limited to 20% renewables by 2010. The Public Utilities Commission is prohibited by statute (SB 107 enacted in 200611) from requiring that IOUs obtain more than 20% of their power from renewables. In order to meet the AB 32 goals, the IOUs and POUs should be required to go beyond a 20% level of renewable electricity delivered. Therefore, we recommend that the Energy Commission, Public Utilities Commission, and ARB jointly seek legislation that requires retail electricity providers to obtain a greater proportion of their power from renewables by a date certain, with flexibility to allow the Public Utilities Commission and/or ARB to require exceeding that level under certain conditions (subject to a cost-effectiveness evaluation, for example). The Energy Action Plans jointly adopted by the Public Utilities Commission and the Energy Commission commit us to "evaluate and develop implementation plans for achieving 33 percent renewables by 2020, in light of cost-benefit and risk analysis." While achieving renewable energy deliveries at this level would contribute significantly to attainment of the emissions reductions required by AB 32, we leave open consideration of the appropriate statutory percentage requirements and deadlines, pending further analysis.

We do not adopt the policy, as suggested by some parties, that we should eliminate mandatory targets for energy efficiency and/or renewables, and allow an AB 32 cap to govern instead. As recognized in D.07-12-052, long-term integrated resource planning is now, and will continue to be, an essential component of achieving sustained GHG emissions reductions within the electricity and natural gas sectors. We firmly believe that our existing energy efficiency, renewables, and emissions performance standard policies are the foundation upon which other AB 32 policies should be built. We intend to work with ARB to determine appropriate levels of requirements for each of these types of resources and programs.

With this basis, we turn our attention to the question of whether a cap-and-trade system should be implemented in California for the electricity sector, in addition to the programmatic measures identified above. Before examining in detail the cap-and-trade option, we note that it would be possible to cap emissions from the electricity sector, most likely at the retail provider level, without a provision for trading of allowances among entities in the sector. In D.06-02-032, which was adopted prior to the passage of AB 32, the Public Utilities Commission concluded that GHG emissions should be capped in the electricity sector, but deferred the question of whether emission allowance trading should be implemented. At that time, the Public Utilities Commission contemplated that the GHG cap would apply to the electricity sector only. Now that AB 32 requires an economy-wide cap in California, we see little advantage to a cap system without a trading component, compared to the direct programmatic approaches described above. In addition, a cap without a trading component would offer many fewer advantages than those we describe below for a cap-and-trade program. Therefore, we decline to recommend a cap-only system for the electricity sector in California.

As summarized in Section 3.2.1.1 above, most parties support the inclusion of the electricity sector in a market-based, multi-sector, cap-and-trade program for GHG emission allowances. However, some parties, including TURN, CAISO, CMUA, DRA, PG&E, and SDG&E/SoCalGas, would prefer that California wait to establish a cap-and-trade program until there is either a regional or national system in place.

Our recommendation to ARB is to proceed now to design a multi-sector cap-and-trade system for California that includes the electricity sector. We have a number of reasons for this recommendation. First and foremost, we are cognizant that ARB must develop comprehensive plans by the end of this year for the major sectors of the California economy to meet the 2020 goal. All of the major mechanisms will need to be included in ARB's scoping plan, as required by AB 32, by January 1, 2009. ARB should not simply include a placeholder for cap-and-trade and develop its key provisions later. We believe that the scoping plan should be a blueprint for what California will do if the mechanism is to be in place by 2012, the first year for compliance with AB 32. If ARB determines that market measures are an appropriate means of achieving ARB's and AB 32's goals and ARB further determines that cap-and-trade is the preferred market mechanism, then in order to meet this goal, initial development of a cap-and-trade program should be undertaken now. Detail on how a cap-and-trade program could be implemented in the electricity sector will aid ARB in its assessment of the feasibility and net benefits of a multi-sector program. Our purpose in adopting this recommendation is to provide detail to ARB for its evaluation of a cap-and-trade program design for the electricity sector. We fully recognize that ARB may decide not to adopt a cap-and-trade program for California.

However, we favor inclusion of the electricity sector in a cap-and-trade program for a number of policy reasons. While we fundamentally favor a certain minimum level of mandatory reductions from existing programs as described above, a cap-and-trade system in combination with these mandatory reductions should be able to produce the GHG emissions reductions required by AB 32 at a lower cost than sole reliance on additional mandatory reductions. This is because emission allowance trading would maximize flexibility in achieving emissions targets by allowing obligated entities to rely on the least-cost abatement options throughout the economy. This, in turn, would provide strong incentives for investment in research and innovation in technologies that lower GHG emissions. A trading system also would allow market participants to manage risk associated with compliance obligations. Finally, it would internalize GHG externalities and should distribute the cost of GHG reductions efficiently across all capped entities. This is valuable because the impacts of GHG emissions are felt by all Californians.

We agree with several parties, including NRDC/UCS, that the cap-and-trade system need only produce a relatively small portion of the overall emissions reductions in the short term. We recommend that ARB design it as a complement to existing policies and their expansions as noted above. As described above, a large portion of the emissions reductions in the electricity sector will come from mandated investments in energy efficiency and other demand reduction programs, as well as renewable energy goals. The additional reductions due to a cap-and-trade system from the electricity sector will likely be small beginning in 2012, but may expand as experience with the mechanism and compliance obligations increase over the AB 32 time period. Furthermore, one of the advantages of a cap-and-trade system is that it facilitates cost-effective GHG reductions from other sectors within the multi-sector cap. This opportunity to gain experience with the cap-and-trade mechanism, in addition to finding real least-cost reductions, is a major reason for our recommendation to proceed now with cap-and-trade for the electricity sector.

In addition, AB 32 requires that ARB design any cap-and-trade program to ensure that there be no increase in the emissions of toxic air contaminants or criteria air pollutants and that localized impacts in communities already adversely impacted by air pollution be minimized. Our recommendation is consistent with other federal, State, and local environmental requirements pertaining to criteria pollutants, and we are confident that these tests can be met.

Finally, we are confident that California can design its cap-and-trade program in collaboration with the other states in the Western Climate Initiative. The timeframe set for the Western Climate Initiative to agree on a design framework and principles is similar to ARB's AB 32 timeframe. Therefore, we intend to continue to work with the other states to develop a coordinated approach. While the approach recommended by the Western Climate Initiative might not be identical to the system we propose for California, we believe that there will be adequate time prior to 2012 to ensure consistency among the cap-and-trade designs.

3.3. Point of GHG Regulation in a Cap-and-Trade System

In this section, we consider the point of regulation or entity in the electricity sector with responsibility for compliance in a multi-sector cap-and-trade system in California. There are four primary options under consideration for point of regulation in the electricity sector:

Retail Providers. In what has been called a "load-based" or "retail provider-based" approach, the regulated entities would be the retail providers of electricity to California customers. Retail providers would be required to obtain and surrender emission allowances for the GHG emissions associated with all power (including both in-state generation and imported electricity) sold to end users in California. Generators would not have a compliance obligation under this approach, except possibly for exported power. We agree with CMUA that "retail provider" is a more accurate and descriptive terminology, and use that term herein.

In-State Generators. In what has been called a "pure source-based" approach, the regulated entities would be generators (owners or operators of power plants) located in California. Emissions attributed to all in-state generation, whether used to serve California load or exported, would be included in a cap-and-trade system. Under such a system, electricity use associated with imports would not be directly regulated under the cap-and-trade system, but could be included in determining whether California economy-wide emission reduction goals are reached consistent with AB 32.

Deliverer. The structure of what has been called the "first seller" approach was a matter of some discussion in this proceeding. The Market Advisory Committee suggested that the point of regulation should be the "first seller" of power into California electricity markets.12 As explained in Section 3.3.2.6, we recommend a variation of the first seller approach, in which the point of regulation would be specified as the entity that owns the electricity as it is delivered to the grid in California. We use the term "deliverer" to describe this regulatory approach.

In-State Generators/Retail Providers for Imports. A fourth point of regulation approach that has received consideration is a hybrid system in which the point of regulation would be the generators (owner or operators of power plants) for in-state generation with the retail providers responsible for imported electricity.

3.3.1. Positions of the Parties

In this section, we summarize the positions of the parties on the appropriate point of regulation in the electricity sector for a cap-and-trade program in California.

3.3.1.1. Retail Providers as the Point of Regulation

The retail provider (or load-based) point of regulation imposes the obligation on retail providers to retire allowances corresponding to the emissions associated with the electricity generated or procured to serve customer loads. Parties' positions are divided about the desirability of this approach to regulating GHGs. Generally, the retail provider approach is supported by POUs and opposed by IOUs, ESPs, marketers, and generators.

LADWP believes that the retail provider-based approach "remains the superior and only feasible approach," if applied to a California-only GHG emission reduction program. According to LADWP, its advantages include consistency with energy efficiency and renewable initiatives, minimized costs of retail providers instead of relying on high market prices to change generation dispatch, and that it is least susceptible to legal challenge.

SCPPA states that "the number of regulated entities would be minimized in contrast to either the first seller or the hybrid approach, leading to administrative simplicity."

SMUD also supports the retail provider approach, expressing its view that, "Assumptions about the carbon content of market purchases would have to be made but these assumptions would be required under the first seller concept as well. The retail service provider would be in the best position to balance the level of energy efficiency, renewable energy or other low carbon strategies needed to meet its GHG goals."

While TURN's overall recommendation is to delay implementation of a cap-and-trade program, TURN recommends further analysis of the feasibility and relative benefits of a retail provider-based regulatory system using tradable emission attribute certificates (TEACs), an option described in more detail below.

PG&E and SCE are strongly opposed to a retail provider-based approach for a number of reasons, most of which stem from their concerns regarding inaccuracies that may arise in reporting and tracking emissions and may result in gaming opportunities and market distortions. Furthermore, PG&E argues that, "because a national system is likely to be source-based, California would have to invest a large amount of money and effort to create a system that would quickly become obsolete..."

The CAISO Market Surveillance Committee asserts that a retail provider-based system is inferior to the other options. It states that load-based and source-based systems are essentially the same on the issues of determining the GHG content of power imports and incentives for investments in energy efficiency and renewable energy. However, it contends that a retail provider-based system has serious disadvantages in other respects: administrative complexity, adverse impacts on the efficiency and costs of dispatching generation units, and incompatibility with likely federal GHG legislation.

The CAISO Market Surveillance Committee contends that a retail provider-based system in which retail providers signed contracts with individual generators to minimize the cost of serving load results in the same cost to load as a source-based system in which generators maximize profit and emission allowances are allocated to retail providers for subsequent auction to generators.13 It asserts, however, that due to the effects of a retail provider-based system on wholesale markets, particularly the CAISO markets, it would lead to the deployment of a less-efficient generation mix, thereby resulting in higher, not lower, energy costs for consumers. The CAISO Market Surveillance Committee concludes that the resulting cost of energy to consumers would likely be higher under a load-based cap.

Although NRDC/UCS would support any of three point of regulation options (retail provider, deliverer, or hybrid), they state that each has different strengths. NRDC/UCS support LADWP's and SCPPA's comments that a retail provider-based cap will produce stronger incentives for retail providers to invest in low-GHG emitting technologies.

Tracking, including TEACs and CO2RCs

Several parties argue that difficulties in tracking the contractual responsibility for the electricity used to serve a retail provider's load back to the ultimate sources constitutes a serious weakness to the retail provider approach. Powerex argues that the use of "broadly estimated regional intensity factors" would decrease not only accuracy but also the likelihood of real reductions. SCE states that the inability to accurately match load to sources is the fundamental and unavoidable flaw in a load-based approach. Morgan Stanley believes that, largely due to issues associated with unspecified power, a retail provider approach would be more administratively complex than the deliverer approach.

In contrast, other parties believe that issues regarding accurately tracking retail provider responsibility for GHG emissions can be overcome. SCPPA states that the retail provider approach may actually be superior to the deliverer approach and less costly due to the ability to use contracts and settlements data of a retail provider to identify the sources of energy derived from a third party.

GPI argues that a comprehensive regional tracking system is needed to improve the accuracy of GHG attribution to retail providers, and that this effort could piggy-back on multi-attribute tracking systems that have already been developed in other parts of the country. SMUD prefers a tracking system that uses existing settlements and reporting data as much as possible, stating that accuracy for unspecified sources would improve as more parties opt in to the tracking system. However, SCPPA believes that developing, and requiring the use of, a universal source-to-sink accounting would have the potential to impede energy market trading and to reduce market liquidity.

An alternative form of retail provider point of regulation that would use TEACs for compliance was proposed by WPTF. As proposed, this system would work by giving a certificate to generators for every MWh of output that represents the GHG emissions associated with that output. Similar to the use of tradable renewable energy certificates (RECs), retail providers would be required to obtain certificates to match each MWh of load served. A punitive high default rate would be assigned for every MWh of a retail provider's load that is not covered by a certificate. WPTF explained its view that using TEACs could improve accuracy by reducing the need for default emission rates for unspecified purchases, and that improved accuracy in attribution of emissions also would send the right economic signals to all generators. WRA submitted a similar proposal that would assign CO2 reduction credits (CO2RCs) to generators based on the difference between generators' emission rates and a high default rate.

Some parties believe that the TEAC/CO2RC approach deserves serious consideration. IEP likes the CO2RC or TEAC approach should a retail provider-based point of regulation be chosen. DRA supports WRA's CO2RC proposal, arguing that favorable aspects of this approach include administrative simplicity, likelihood of achieving real reductions by mitigating contract shuffling, compatibility with source-based systems, and low legal risk.

Several parties, including WPTF, Calpine, Constellation, and AREM, state that, while they prefer a source-based system, the TEAC approach would offer significant advantages if California adopts a retail provider point of regulation. Calpine states that, since "TEACs would provide a carbon signal directly to generators, it would provide a strong incentive for both investment in, and dispatch of, low-emission generation."

By contrast, the CAISO Market Surveillance Committee states that a TEAC approach would be functionally and economically equivalent to a source-based approach with output-based allocation of allowances, and argues that the additional administrative complexity of a TEAC system is unnecessary. PG&E and SCE similarly assert that the costs of creating and administering a TEAC system would outweigh any possible advantages that it might offer. SCPPA contends that, rather than being simple, this approach itself would need to track all power that is generated and delivered to retail providers in California.

Compatibility with CAISO Markets

Some parties argue that, because a retail provider-based system would depend on default emission rates for unspecified power purchases, it may have deleterious effects on CAISO's pooled markets with the averaging of emissions in the pool reducing the incentive for generators in the pool to reduce emissions. They assert that clean generators with emission rates lower than the default rate would negotiate bilateral contracts that enable them to capture some of the value of their lower emissions and that this increased reliance on specified contracts and self-scheduling would dampen the efficiencies in dispatch and transmission that the Market Redesign and Technology Upgrade (MRTU) is designed to provide.

The CAISO Market Surveillance Committee states its additional view that, "Another reason why more self-scheduling is likely to occur is because each [retail provider] will be trying to self-manage its supply portfolio to stay within [its] emissions limitation." The CAISO Market Surveillance Committee expresses concern that, "The [CAISO] markets for energy and ancillary services will become significantly thinner... Furthermore, thinner markets would likely also be less competitive markets. Ultimately, all of these increased costs would be passed on to consumers." PG&E, SCE, and SDG&E/SoCalGas express similar positions.

Contract Shuffling

The CAISO Market Surveillance Committee expresses concern that the ability to regulate the GHG content of imported electricity may be grossly overstated because of contract shuffling concerns. It submits that there is enough "clean" generation available in the West-wide market, "such that there is likely to be more than enough clean generation that can be assigned, on paper, to California imports, without actually changing system operations, or investment, in the West." Several parties argue that there is no way to entirely combat contract shuffling, except through a national or at least region-wide source-based system.

PG&E, SCE, and WPTF express the view that, while the potential magnitude of contract shuffling for imported electricity is likely to be similar for all points of regulation, it may be of greater concern under a retail provider point of regulation since in-state sources could be shuffled as well. PG&E contends that there would be the possibility of "greenwashing through exports," in which a high-GHG in-state generator could export power from California and import cleaner power to sell to a California retail provider.

NRDC/UCS contend that contract shuffling concerns would be approximately the same under a retail provider-based, first seller or hybrid system. They contend, however, that contract shuffling would become less of a concern over time because of the Western Climate Initiative or, potentially, a federal system and, moreover, that new infrastructure investments will require long-term financial commitments that would lend themselves to easier emissions tracking and therefore be less prone to contract shuffling.

Some parties, including SCPPA, CMUA, and SMUD, believe that the threat of contract shuffling does not warrant much concern. CMUA states that, "...there is little threat of actual contract shuffling within a California-only retail provider-based program. Robust verification procedures will serve as an adequate deterrent to virtually eliminate actual contract shuffling by retail providers." SMUD contends that other Western states' RPS requirements limit the potential for contract shuffling.

3.3.1.2. In-State Generators as the Point of Regulation, Imports not in Cap-and-Trade

PacifiCorp is the only party to support an in-state generator-only point of regulation. DRA supports the CO2RC method described by WRA, but DRA suggests a source-based point of regulation as a second choice, stating that it would be simpler and easier to track, and would minimize legal risk.

Morgan Stanley states that, "a source-based approach for in-state resources is necessary to ensure that dispatch decisions reflect the price signal for GHG emissions. This in turn, will provide market participants with incentives to alter behavior." However, it concludes that the deliverer approach would be superior to other alternatives for dealing with imports.

Compatibility with AB 32

Parties were asked whether a pure source-based program would be compliant with AB 32, which requires that ARB adopt GHG reporting requirements that account for the GHG emissions associated with electricity imported into and consumed in California. Several parties, including SDG&E/SoCalGas, Calpine, IEP, LADWP, SCPPA, GPI, and AREM, assert that the exclusion of import-related emissions from a tradable cap would violate the requirements of AB 32.

DRA counters with an alternative view that, while AB 32 requires ARB to adopt regulations that account for imports, it does not require direct regulation of emissions associated with imported electricity as long as the overall emissions goal is achieved.

Leakage

NRDC/UCS argue that a pure source-based point of regulation likely would fail AB 32 requirements to minimize leakage. Several other parties express similar concern about leakage under a pure source-based program. WPTF states that a system that solely covers in-state generation would impose a cost differential between in-state and imported power and contribute to leakage, at least in the short term. SCE and Calpine express similar views. SMUD asserts that a source-based system has to be West-wide or national, and that an in-state-only system would drive generation out-of-state.

Other parties are less concerned about leakage under a pure source-based system. These parties cite four principal factors that, in their view, would limit leakage. First, DRA submits that the existing surplus transmission capacity for importing additional power is limited. Second, several parties, including PG&E, PacifiCorp, SDG&E/SoCalGas, SCE, IEP, and Constellation, view the implementation of the Emissions Performance Standard as an important factor limiting leakage. Third, some parties argue that the current Western Electricity Coordinating Council generation mix and capacity factors of coal-fired resources limit the potential for leakage. PG&E and PacifiCorp state that marginal generators are often gas combined cycle units, so that leakage would merely cause in-state combined cycle usage to be shifted to out-of-state combined cycle. Parties argue that out-of-state coal plants have such low running costs that they will run at high capacity factors regardless of programs California imposes. Fourth, Constellation, PacifiCorp, PG&E, and WPTF consider the likelihood of a regional or national GHG emission reduction program as largely mitigating the threat of a long-term shift of production to regions outside the state.

Other Requirements in Conjunction with Generator Cap-and-Trade

Parties were asked to comment on whether expanding programmatic approaches to mitigate GHG emissions would be needed to meet AB 32 goals if an in-state source-based point of regulation were adopted.

Many parties express concern about the costs and effectiveness of expanding "command and control" approaches. Calpine states that, "Because out-of-state generators would not be subject to the emissions cap, a variety of indirect actions would need to be taken to...ensure emissions reductions...and would likely place additional burdens on in-state resources, ...increasing the costs to reduce emissions. Such an approach to ensuring compliance with AB 32 is clearly less efficient than a system that simply makes emissions from imported power subject to a cap."

Constellation urges that policies that create more incentives for offsets should be given special attention in the event imports are excluded.

DRA and NRDC/UCS believe that some additional programs are desirable in any event, as described in Section 3.2.1.2. NRDC/UCS argue that, if emissions from imports are excluded, it will be all the more critical for the State to expand energy efficiency and renewable energy programs. WPTF suggests that the current suite of policies be applied uniformly across retail providers if imports are not included in the cap-and-trade program. AREM strongly opposes extension of energy efficiency programs to ESPs as "inappropriate and unnecessary."

Several parties submit that strengthening the Emissions Performance Standard would not be an effective means of mitigating additional leakage that could occur from a California-only source-based cap-and- trade regime. They contend that the Emissions Performance Standard is not a suitable mechanism for reducing emissions from imports that fall below the 1,100 pounds (lbs)/MWh threshold, and that such imports, if they are not included in a California cap, could displace a substantial portion of cleaner in-state generation.

3.3.1.3. Deliverers as the Point of Regulation

A threshold issue is the best formulation of a "deliverer" approach. This approach evolved out of the "first seller" approach recommended by the Market Advisory Committee. The Market Advisory Committee recommended that the point of regulation be either the owner or operator of the California power plant, or the importing contractual party, depending on whether the electricity is generated in-state or out-of-state. In comments, parties take differing positions regarding the proper formulation of a first seller approach, or a variation thereof.

PG&E suggests that, for in-state power, the owner or operator of the generating unit would be the point of regulation, since it is usually the first to deliver the power to the busbar, which is usually the first delivery point on the transmission grid in California. PG&E suggests that, for imports, the entity with ownership of or title to the power at the first point of delivery in California would be the point of regulation. In this view, for those imports that have E-tags, the deliverer would be the Purchasing/Selling Entity listed on the E-tag14 at the first point of delivery in California. Because intra-balancing authority15 imports would not have E-tags when they are delivered to the California grid, PG&E suggests a technical working group to address information sources for such imports.

SCPPA asserts that, in a deliverer approach, entities that control plants through tolling agreements should be the point of regulation rather than the generator. While such entities are neither owners nor operators, SCPPA states that they "are tantamount to being owners or operators" by virtue of their tolling agreements.

SCE takes the position that, rather than identifying the deliverer of imports based on the point of delivery within California, the deliverer should be identified based on the first delivery point for which the balancing authority is a California entity. SCE explains that this would include delivery points outside the State that are controlled by a California balancing authority.

Parties take differing positions regarding whether marketers and brokers should have compliance obligations under a deliverer approach. SCE submits that marketers and brokers should be treated as any other Purchasing/Selling Entity, except that generators would be responsible for all in-state transactions. Several parties take the position that marketers would be first sellers, but not brokers since they do not own or schedule the power (LADWP, SCPPA, WPTF/AREM, and DRA). Morgan Stanley states that, for imported power, the party responsible for scheduling the energy into California should be the point of regulation.

Several parties support a deliverer approach, including PG&E (if multi-sector California only), SDG&E/SoCalGas, SCE, Calpine, Powerex, Constellation (until a regional source-based system is implemented), Environmental Defense, Morgan Stanley, WPTF, and AREM.

Contract Shuffling and Leakage

Several parties that comment on the risks of contract shuffling and leakage submit that any system that includes imports in the cap faces the same contract shuffling and leakage concerns for the imports. For example, Morgan Stanley states that each approach for dealing with imports "is only an administrative approximation and is vulnerable to leakage and contract shuffling. The challenges for dealing with imports are essentially the same for each ... and the flaws for each approach are roughly equal."

Several parties assert that a deliverer system would reduce contract shuffling for in-state resources. WPTF submits that, under a retail provider-based system that uses contracts and settlement data to assign emissions to retail providers, there would be on-going potential for contract shuffling but that contract shuffling would be reduced under a deliverer approach since the portion of load for which it would be necessary to assign emissions, i.e., some imports, would be smaller than under a retail provider-based system.

EPUC/CAC cite the Market Advisory Committee report as observing that linkage with other regional GHG programs is required to eliminate the leakage problem. EPUC/CAC state that contract shuffling issues result similarly where regulation does not address all potential sources of emissions. While they see the adopted Emissions Performance Standard as a good step toward reducing leakage and contract shuffling for long-term import contracts, they argue that inclusion of imports in California's GHG regulatory scheme is important to mitigate the potential for short-term leakage and shuffling.

Consistency with Potential Federal Programs

Morgan Stanley asserts that the deliverer approach is superior to other alternatives for dealing with imports because it "is the most consistent with a source-based approach for in-state resources, and is therefore superior to the others." WPTF believes similarly that a deliverer-based approach should be pursued on the grounds that it could be most easily adapted to the source-based approaches being considered at the federal level. Calpine states that both a source-based system and a deliverer approach likely would be consistent with expected regional and federal source-based systems. Powerex asserts that the deliverer approach is suitable as a model for a national or regional program and, if adopted by California, can be easily scaled and integrated with broader regional or national programs.

Incorporation of Price of Carbon into Energy Market Prices

Several parties, including SCE, PG&E and Powerex, assert that, because electricity deliverers would be responsible for obtaining allowances, the deliverer approach would incorporate GHG compliance costs within electricity costs, thereby providing the correct price signal to the market to place generation in the appropriate dispatch order. SDG&E/SoCalGas describe that some deliverers may not have adequate information to include carbon costs into their offers in the day ahead or real-time auctions, specifically sellers making intraday trades. SDG&E/SoCalGas submit however that, if that information became valuable, it is likely that the needed information would become available.

PG&E argues that this approach would provide stronger price signals for development of low-emitting or zero-emitting renewable energy supplies. It contends, in particular, that the profitability and competitiveness of renewable energy producers bidding into wholesale power markets would be increased under this approach, compared to a retail provider-based approach which would not directly internalize the cost of GHG emissions.

Morgan Stanley states that "a source-based approach for in-state resources is necessary to ensure that dispatch decisions reflect the price signal for GHG emissions. This in turn will provide market participants with incentives to alter behavior."

TURN is concerned that adoption of a source-based or deliverer-based regulatory framework could increase the cost of electricity for California ratepayers.

Interaction with MRTU and Wholesale Markets

SCPPA views the impact of a deliverer approach on the real-time or forward markets as a "direct interference" that would increase the cost of the GHG reduction program. However, the CAISO Market Surveillance Committee strongly favors a deliverer approach due to what it sees as reduced interference in the efficient operation of its markets. SCE asserts a related advantage with respect to imported energy, that an entity that delivers power to California must take responsibility for that energy before it is bid into the CAISO market. In SCE's view, this addresses the attribution challenge of market bids from imports.

SCPPA is concerned that this approach may discourage importers from selling into the California market, "thereby reducing California electricity market liquidity, increasing wholesale electricity prices, and decreasing reliability."

Administrative Issues

SCPPA and GPI submit that a deliverer approach would involve a larger number of regulated entities, and that this would complicate administration of the program. SDG&E/SoCalGas and Environmental Defense state that, while there would be more points of regulation for imports, the number would not be overly burdensome. As a potential benefit, Calpine suggests that having more actors in the market may help to increase liquidity and reduce the risk of market power.

SCPPA contends that no GHG emissions tracking device is available to permit identification of GHG emissions associated with imported electricity. SDG&E/SoCalGas submit that the same type of contract information would be used to assign emissions to imported energy under either a retail provider-based approach or a deliverer-based approach, and that there is nothing that makes this undertaking more challenging under the deliverer approach, as long as the required parties report the information.

Other parties (SCE, Calpine, and Morgan Stanley) assert that a deliverer approach would be less complex administratively than a retail-provider approach because only imports would have to be tracked under a deliverer approach while under the retail provider-based model all wholesale power transactions must be tracked in order to assign emissions to retail providers.

SDG&E/SoCalGas view emissions tracking and verification associated with the deliverer approach as being relatively transparent, because most of the participants in such a program would have close ties to the generation that they are selling. It states that the use of generator data would be a significant advantage for the deliverer approach compared to the retail provider approach, which would use default emissions values for all purchases of unspecified power, including power generated in California. However, GPI points to the dependence on default factors for many imports.

3.3.1.4. In-State Generators, Retail Providers for Imports as Point of Regulation

The only party in the proceeding that advocated for this model is EPUC/CAC, which later changed its position to support the deliverer approach. EPUC/CAC cited several possible advantages to a hybrid approach. According to EPUC/CAC, a hybrid approach: 1) "best aligns the incentives to reduce emissions with the source of those emissions," 2) "allows for greater accuracy in the tracking of emissions," 3) facilitates expandability, 4) "offers administrative simplicity," and 5) "can overcome legal challenge." While EPUC/CAC acknowledged that a hybrid approach would treat out-of-state sources differently, it asserted that the program could be designed to not disadvantage them and thus mitigate susceptibility to Commerce Clause challenge. It contends that, since the hybrid approach also would not directly regulate wholesale transactions, it should also overcome Federal Power Act (FPA) challenges.

EPUC/CAC asserted that, with an in-state generator/retail provider for imports hybrid, roughly 75-80% of California's load would be captured at the source. It argued that using a retail provider approach for imports could give California greater leverage in dealing with imported emissions, and that discovery of out-of-state sources could be incentivized by attributing a high default GHG emission rate to unspecified purchases.

Several parties contend a hybrid design would have significant disadvantages. SDG&E/SoCalGas, SCE, WPTF, and Calpine submit that a major problem with the hybrid approach would be its impacts on the CAISO markets. Calpine contends that such an approach would bestow a competitive advantage on out-of-state sources since they would not have to include a carbon price in their bids into the CAISO markets. SCE argues that carbon costs would not be imposed on imports bidding into the CAISO markets, and thus that importers would receive higher prices from the CAISO market with no emissions obligation. EPUC/CAC cited such concerns in reply comments and abandoned its support of a hybrid approach in favor of a deliverer approach.

Several parties contend that a hybrid approach would be at least as administratively complex as a deliverer approach. They submit that all load would need to be tracked to sources for the system to work. SMUD, Constellation, and PG&E are also concerned that a hybrid system would require extensive accounting to avoid double counting. DRA similarly states that such a system would require all of the reporting and tracking protocols associated with a retail provider-based system to account for imports, and would require the regulatory enforcement and compliance standards for generators associated with a source-based approach.

SDG&E/SoCalGas and SCE express concern that this option is vulnerable to challenges under the FPA and the Commerce Clause.

3.3.2. Discussion

As described in Section 3.2.2, we recommend that ARB adopt a cap-and-trade program that includes the electricity sector in California provided that ARB finds that the tests outlined in Part 4 and Part 5 of AB 32 are met. An integral component of a cap-and-trade program is the point of regulation. That is: which entities should have the compliance obligation within a cap-and-trade system for delivering GHG emissions reductions within the electricity sector?

To answer this question, we focus on what we believe are the five most important criteria. Those criteria are:

1. Environmental integrity. Here we focus on how each option deals with the problems of unspecified system purchases and imports in order to minimize the potential for leakage and/or contract shuffling, leading to real GHG emissions reductions from the electricity sector.

2. Compatibility with/expandability to potential regional and/or national GHG emissions cap-and-trade markets.

3. Accuracy and ease of reporting, tracking, and verifying GHG emissions reductions. Without accurate tracking, we cannot ensure that reductions are real, quantifiable, verifiable, and valid.

4. Compatibility with ongoing reforms of wholesale and retail energy markets. We focus, in particular, on potential interactions with the CAISO's new market design and the MRTU, while keeping in mind that some California entities are less involved with CAISO markets.

5. Legal issues.

We assume that, as a threshold matter, all options would have to be consistent with other federal, State, and local environmental requirements, such as those pertaining to criteria pollutants and toxic waste.

Below, we address each of the first four criteria in turn and discuss how each option for point of regulation does or does not meet the criteria. We stress at the outset, however, that none of the options meets all criteria fully. With any one-state cap-and-trade design in the electricity sector, there are inherent pros, cons, and tradeoffs. Our job is to weigh the pros and cons against our most important criteria. We note that there are other criteria that could be applied to this choice, as discussed in several ALJ rulings that have helped us reach this decision point and upon which parties have commented extensively. However, in this decision, we focus on those criteria that have led us to our recommendation for point of regulation in the electricity sector. We also discuss some other secondary criteria as they relate to the options under consideration.

As explained below, we conclude that the deliverer point of regulation best meets these four criteria. We then address some details regarding formulation and application of the deliverer point of regulation and consider legal issues (the fifth criterion listed above) related to the deliverer approach.

3.3.2.1. Environmental Integrity and Real GHG Emissions Reductions

In assessing the viability of the four options for point of regulation, obtaining real GHG emission reductions is our most important consideration. With any design, we must ensure that the system will deliver real reductions in GHG emissions into the atmosphere as required by AB 32. The two chief concerns here for California's electricity sector are that, while California imports approximately 20% of its electricity from neighboring states, those imports represent more than 50% of the GHG emissions from the sector and that, within California, unspecified system purchases are a substantial portion of purchases. Thus, to be effective, any system we design must address imported power and unspecified system purchases in some way. Since in Section 3.2.2 we recommend design of a cap-and-trade system for California that includes the electricity sector, we now examine how well options for cap-and-trade design address both in-state generation and imported power.

First we consider the option where in-state generators would be the point of regulation, without imports included in the cap-and-trade system. By not covering imports directly in the system, it is likely that there would be incentives for the electricity sector in California to reduce its GHG emissions by importing more power from out-of-state, without necessarily reducing emissions into the atmosphere at all. This is certainly true in the long term and likely true in the short term as well. As environmental costs begin to make in-state generation more expensive, the economic incentive to begin importing more power from uncapped out-of-state power plants would be strong. Therefore, this option appears to be the least desirable from the standpoint of environmental integrity.

The other three options (retail providers; deliverers; and a hybrid in which the point of regulation includes in-state generators and, for imports, retail providers) address imported power and unspecified in-state purchases in different ways.

With retail providers as the point of regulation, integrity of the system would be addressed by holding retail providers responsible for all of the power they deliver to consumers. In the hybrid option, retail providers would be responsible only for imported power. In order to make either of these retail provider-based systems function more accurately, it is likely that a tracking system and/or an emission attribute certificate system would need to operate parallel to the cap-and-trade system to ensure that contract shuffling is minimized under the model. It is impossible to track accurately all generation from each power plant to the retail provider that delivers it to a consumer. One option to deal with this problem is the development of default factors, but those factors are inherently inaccurate and create unintended and negative incentives for market participants. To reduce inaccuracies in retail provider-based systems, development of a mandatory emissions attribute tracking system which included imports likely would be needed.

For the deliverer point of regulation, the entity that first delivers the power to the electricity grid in California would be held responsible for its emissions. This would capture emissions from electricity generated within California and electricity imported into California from out-of-state. The problem of in-state unspecified purchases would disappear, and this would be a major advantage. The carbon attributes of imports would be determined by the entity most likely to know what has been purchased and in the best position to provide verification documentation. Because of the increased accuracies of the deliverer approach in identifying the generating source of electricity, reported GHG emission reductions would also be more accurate and reliable. As a result, we conclude that the deliverer approach is the preferable alternative regarding the ability to ensure that reported GHG emission reductions are real.

3.3.2.2. Compatibility With/Expandability to Potential Regional and/or National Cap-and-Trade Markets

We want to design a system that is likely to be compatible with any regional and/or federal cap-and-trade system that may be established within the next few years. Negotiations are underway to design a Western region cap-and-trade system through the Western Climate Initiative, and a number of proposals are currently pending in the United States Congress. Thus, it appears likely that a regional and/or federal cap-and-trade system could be established within the next few years. It also appears likely that initiation of the compliance period for a regional and/or federal system could follow California's 2012 compliance initiation by at least a few years. Thus, at some point in the near future, a California cap-and-trade system will likely need to be linked to, or adapted to be compatible with a regional or national system.

Some parties have argued that it is not necessary to worry about compatibility of the design of the cap-and-trade system with a regional or federal system, because a regional or national program would render the California system obsolete. Others have argued that certain designs of a cap-and-trade system for California could co-exist with or link to a parallel federal or regional program. Both of these things could be true; it likely depends upon the ultimate design of each system. In the face of this uncertainty, we think it would be beneficial to design a system that is most likely to be similar to a federal or regional system.

As most parties have noted, all cap-and-trade systems operating to date have been source-based systems. These include not only the European Union Emissions Trading System, but also a number of cap-and-trade systems for controlling criteria pollutants within the United States. Therefore, this is the type of cap-and-trade system with which entities in the electricity sector in California, and the rest of the country, are familiar.