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ALJ/CFT/avs DRAFT Agenda ID #10227 (Rev. 1)

BEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA

Order Instituting Rulemaking to Address Utility Cost and Revenue Issues Associated with Greenhouse Gas Emissions.

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ORDER INSTITUTING RULEMAKING

TABLE OF CONTENTS

Title Page

ORDER INSTITUTING RULEMAKING 22

ORDER INSTITUTING RULEMAKING

1. Summary

The Commission opens this rulemaking to address potential utility cost and revenue issues associated with greenhouse gas (GHG) emissions. At this time, our primary focus will be on the possible use of revenues that electric utilities may generate from auction of allowances allocated to them by the California Air Resources Board, the use of revenues that electric utilities may receive from the sale of Low Carbon Fuel Standard credits they may receive from the California Air Resources Board (ARB), and the treatment of possible GHG compliance costs associated with electricity procurement. This rulemaking may also address other GHG issues, particularly those affecting utility costs and revenues related to GHG emission regulations and statutory requirements.

The Commission acknowledges that the ARB has been enjoined by the San Francisco Superior Court from implementing aspects of its GHG regulatory program. This may result in delays or changes to the ARB's regulatory program, but in order to avoid additional future delays, we are opening this rulemaking to ensure that this Commission is prepared to timely address the issues within our jurisdiction when and if the problems identified by the Superior Court are resolved. To the extent ARB changes its regulatory program, the scope and schedule of this rulemaking may also change.

Some issues related to GHG emissions are addressed more appropriately in other Commission proceedings. Specifically, utilities' authorization to buy and sell GHG allowances and offsets is being addressed in the long-term procurement planning proceeding, Rulemaking 10-05-006.

2. Background

The Global Warming Solutions Act of 2006 (Assembly Bill (AB) 32)1 caps California's greenhouse gas (GHG) emissions at the 1990 level by 2020. AB 32 granted the California Air Resources Board (ARB) broad authority to regulate GHG emissions to reach the goal of having GHG emissions in 2020 be no higher than the 1990 level.

Prior to AB 32's enactment, the Commission was taking steps in Phase 2 of Rulemaking (R.) 06-04-009 to implement a load-based GHG emissions allowance cap-and-trade program adopted in Decision (D.) 06-02-032 for the electric utilities, and to address GHG emissions associated with customers' direct use of natural gas. With enactment of AB 32, Phase 2 of R.06-04-009 shifted to support ARB's implementation of the new statute and was undertaken thereafter jointly with the California Energy Commission.

On March 14, 2008, D.08-03-018 in Phase 2 of R.06-04-009 recommended that ARB adopt a mix of direct mandatory/regulatory requirements for the electricity and natural gas sectors. These recommendations included that ARB designate "deliverers" of electricity to the California grid, regardless of where the electricity is generated, as the entities in the electricity sector responsible for compliance with the AB 32 requirements, and that ARB implement a multi-sector GHG emissions allowance cap-and-trade system that includes the electricity sector. That decision addressed the distribution of GHG emissions allowances and recommended that some portion of the GHG emissions allowances available to the electricity sector be auctioned. It also included preliminary recommendations regarding the use of proceeds from the auctioning of GHG emissions allowances allocated to the electricity sector:

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.2

On October 22, 2008, the Commission issued D.08-10-037 in Phase 2 of R.06-04-009, the Final Opinion on Greenhouse Gas Regulatory Strategies. That decision provided more detailed recommendations to ARB as it proceeded with implementing AB 32. Recognizing that it is ARB's role to determine whether implementation of a cap-and-trade program in California is the appropriate policy, D.08-10-037 recommended that ARB allocate 80% of electric sector allowances in 2012 to the "deliverers" of electricity to the California transmission grid and 20% to "retail providers" of electricity (including load serving entities and publicly owned utilities), with the relative proportions changing each year until all allowances would be allocated to retail providers by 2016 and in every year thereafter. As part of this recommendation, the retail providers would be required to sell their allowances through a centralized auction undertaken by ARB or its agent.

Section 5.5 of D.08-10-037 includes discussion of the proper uses for GHG emissions allowance auction proceeds received by retail providers of electricity:

We agree with parties that all auction revenues should be used for purposes related to AB 32. ... In our view, the scope of permissible uses should be limited to direct steps aimed at reducing GHG emissions and also bill relief to the extent that the GHG program leads to increased utility costs and wholesale price increases. It is imperative, however, that any mechanism implemented to provide bill relief be designed so as not to dampen the price signal resulting from the cap-and-trade program.3

Ordering Paragraphs 15 and 16 in D.08-10-037 are particularly relevant to today's rulemaking:

15. We recommend that ARB require that all allowance auction revenues be used for purposes related to Assembly Bill (AB) 32, and that ARB require all auction revenues from allowances allocated to the electricity sector be used to finance investments in energy efficiency and renewable energy or for bill relief, especially for low income customers.

16. We recommend that ARB allow the Public Utilities Commission for load serving entities and the governing boards for publicly-owned utilities to determine the appropriate use of retail providers' auction revenues consistent with the purposes of AB 32 and the restrictions recommended in Ordering Paragraph 15.4

Following D.08-10-037, Commission staff has continued to work informally with ARB as it proceeds to develop its regulations implementing AB 32.

ARB's Climate Change Scoping Plan includes a recommendation that California adopt a portfolio of emissions reduction measures, including, if appropriate, a California GHG cap-and-trade program that can link with other programs to create a regional market system.5

On October 28, 2010, ARB staff released its "Proposed Regulation to Implement the California Cap-and-Trade Program." Part I of that document is the "Staff Report: Initial Statement of Reasons for Proposed Regulation to Implement the California Cap-and-Trade Program" (ISOR), which presents the rationale and basis for the proposed regulation. Appendix A to the ISOR contains ARB staff's Proposed Regulation Order.6

The staff-proposed ARB regulations would create a GHG emissions allowance cap-and-trade system, with compliance obligations in the electricity sector applicable to "first deliverers of electricity," generally consistent with the "deliverer" obligations that this Commission and the California Energy Commission had recommended. The proposed regulations would, however, allocate all emissions allowances in the electricity sector to "electrical distribution utilities"7 and require that the "first deliverers of electricity" purchase all of the allowances needed to meet their compliance obligations. The term "electrical distribution utilities" is generally consistent with the "retail providers" recommended by this Commission and the California Energy Commission, except that it does not include Electric Service Providers and Community Choice Aggregators.

Following the receipt of written comments and public testimony on its proposed regulations, ARB staff prepared suggested modifications to the originally proposed regulations attached to the ISOR, and submitted the proposed modifications8 to ARB on December 16, 2010.

On December 16, 2010, ARB considered its staff's recommendations and approved Resolution 10-42.9 Resolution 10-42 authorized ARB's Executive Officer to consider and make several modifications to the proposed regulation, as appropriate, and then to take final action to adopt the revised regulation or bring the revised regulation back to ARB for further consideration.10

One of the ARB staff's recommended modifications was finalization of the methodology for allocation of free GHG emissions allowances to the electrical distribution utilities. Other unaddressed issues that affect the electric industry include the treatment of combined heat and power (CHP) facilities in a cap-and-trade program, and a set-aside for voluntary renewable electricity.

Prior to the decision by the San Francisco Superior Court, ARB was expecting that its cap-and-trade regulation would be finalized in the fall of this year, to go into effect in December 2011, and ARB was planning that the first auction of GHG emissions allowances would occur on February 14, 2012, with auctions to be held quarterly thereafter. These dates are now uncertain, as it is not clear how long it will take for the problems identified by the Superior Court to be resolved. Even with that uncertainty, it is prudent for the Commission to begin thinking about how to possibly implement what appears to be ARB's preferred approach, so that this Commission will be prepared if and when ARB moves forward.

Section 95892(d) of the ARB staff-proposed regulation includes language limiting the use of auction proceeds from allowances allocated to electrical distribution utilities. Sections 95892(d)(2) and 95892(d)(3) are provided below:

(2) Proceeds obtained from the monetization of allowances directly allocated to investor owned utilities shall be subject to any limitations imposed by the California Public Utilities Commission and to the additional limitations set forth in section 95892(d)(3) below.

(3) Auction proceeds obtained by an electrical distribution utility shall be used exclusively for the benefit of retail ratepayers of each electrical distribution utility, consistent with the goals of AB 32, and may not be used for the benefit of entities or persons other than such ratepayers.

(A) Investor owned utilities shall ensure equal treatment of their own customers and customers of electricity service providers and community choice aggregators.

(B) To the extent that an electrical distribution utility uses auction proceeds to provide ratepayer rebates, it shall provide such rebates with regard to the fixed portion of ratepayers' bills or as a separate fixed credit or rebate.

(C) To the extent that an electrical distribution utility uses auction proceeds to provide ratepayer rebates, these rebates shall not be based solely on the quantity of electricity delivered to ratepayers from any period after January 1, 2012.

Regarding the use of auction revenues, the ARB resolution adopted on December 16, 2010 states that:

...the [ARB] directs the Executive Officer to work with the California Public Utilities Commission (CPUC) and the publicly owned utilities (POU) to ensure that the proposed allowance value directed to the electric distribution utilities is used for the benefit of residential, commercial, and industrial ratepayers that might otherwise face indirect costs from the implementation of this regulation, with particular consideration of the potential for impacts from this program on low-income customers, and for the purposes of AB 32, which could include investment in energy efficiency programs beyond those already required by California law and in renewable energy projects that achieve environmental and public health co-benefits for Californians.

... the [ARB] strongly advises the CPUC and the POU governing boards to work with local governments and non-governmental organizations to direct a portion of allowance value, if the cap-and-trade regulation is approved, into investments in local communities, especially the most disadvantaged communities, and to provide an opportunity for small businesses, schools, affordable housing associations, and other community institutions to participate in and benefit from statewide efforts to reduce greenhouse gas emissions.11

ARB staff recommends that 97.7 million metric tons (MMT) of allowances be allocated for free to electrical distribution utilities in 2012, with the recommended sector allocation declining linearly to 83 MMT in 2020. ARB staff recommends that all allowances for 2012 through 2020 be allocated to individual utilities at the start of the program, so that each utility would know its yearly allocations and could plan accordingly. ARB staff is evaluating various methods for the allocation of allowances to the individual electrical distribution utilities, and recommends that the final allocation approach take into account ratepayer cost burden, energy efficiency accomplishments, and early action as measured by investments in qualifying renewable resources.

Preliminary estimates by ARB staff provide insights into the total amount of money that may be at stake for the electric utilities we regulate if ARB implements a cap-and-trade program with GHG emissions allowance allocations similar to those under consideration by ARB staff. In the suggested modifications provided to ARB on December 16, 2010, ARB staff included a graphical depiction of its preliminary estimates of allowance allocations to individual electrical distribution utilities during the 2012 through 2020 period.12 We estimate, based on the total multi-year allocations indicated in that figure and the ARB staff-recommended 2012 allowance allocation to the electric sector of 97.7 MMT, that the electric utilities we regulate could receive allowances in the neighborhood of 65 MMT in 2012, if an allocation method similar to those illustrated in the ARB staff proposal is implemented. ARB staff recommends that an auction reserve price for 2012 auctions be set at $10 per metric ton. At that price and using the rough estimate just described, the electric utilities could receive approximately $650 million for the quarterly auctions that ARB has planned to be held during 2012. If auction prices were to exceed $10 per metric ton, the utilities' revenues could be commensurately higher.

ARB has identified a Low Carbon Fuel Standard as a Discrete Early Action Measure consistent with AB 32. ARB has developed and adopted Low Carbon Fuel Standard regulations,13 which ARB put into effect on April 15, 2010.

The Low Carbon Fuel Standard would be applicable to providers of transportation fuels, and would require a 10% reduction in the carbon content of California's transportation fuels by 2020. The providers of transportation fuels can meet annual carbon content level requirements with any combination of fuels they supply or produce, and with Low Carbon Fuel Standard credits acquired in previous years or purchased from other parties. The standard would allow electric utilities, along with other electricity fuel providers, to receive credits for electricity that is used for transportation purposes, subject to certain electricity metering and reporting requirements.

In R.09-08-009, our rulemaking on alternative-fueled vehicle issues, the January 12, 2010 Assigned Commissioner's Scoping Memo stated that R.09-08-009 would consider addressing the disposition of any revenues that utilities may receive from the sale of Low Carbon Fuel Standard credits. However, the Proposed Decision that was published recently in that proceeding and is under consideration would defer that issue because of unresolved details of ARB's regulations. We plan to consider this issue in this rulemaking.

With the potential for implementation of a GHG emissions allowance cap-and-trade system, the utilities may face GHG cost exposure in various ways, including the arrangements for GHG compliance responsibility in bilateral contracts as well as utilities' participation in the GHG emissions allowance and offset markets. Bilateral contract issues may arise in, but may not be limited to, the following four procurement scenarios.

First, the Commission has adopted decisions in Application (A.) 08-11-001 and R.08-06-024 with implications for utility exposure to GHG risk from CHP and Qualifying Facility (QF) resources. In D.10-12-035, the Commission adopted a "Qualifying Facility and Combined Heat and Power Program Settlement Agreement," which resolves outstanding litigation between utilities and QFs, adopts a new short-run avoided cost (SRAC) methodology that incorporates GHG allowance costs, and creates a path forward for the procurement of CHP to meet the goals of GHG emissions reductions under AB 32.

Once the approved settlement becomes effective (after final approval by the Federal Energy Regulatory Commission (FERC), among other conditions), the newly adopted SRAC is designed such that CHP generators are paid for avoided GHG costs. CHP generators will not be paid for their own GHG compliance costs; rather payment will reflect the avoided GHG compliance costs of the marginal generating unit that would have been built but for the CHP generator. This will be achieved by incorporating GHG compliance costs into the SRAC payment, which is the avoided cost of the marginal generator. Due to uncertainty regarding the extent to which GHG compliance costs will be reflected in wholesale energy prices during 2012 through 2014, a floor test will be in effect to ensure that GHG allowance costs are fully reflected in the market price of energy.14 However, the adopted SRAC will transition to a market-based energy pricing methodology after the first GHG compliance period.15

For CHP that is procured via a competitive solicitation process, sellers will be required to bid two different prices, depending on whether the seller or the purchasing utility accepts GHG compliance responsibility. The utility will weigh the costs and benefits of the different bids to determine who is best positioned to assume GHG compliance cost risks and will decide which option to select.

For "legacy" QF contracts (existing contracts that do not expire in the near term), QFs will have the option of being paid the SRAC described above or choosing from four other pricing options that reflect different GHG cost/risk balances between buyer and seller.16 QF generators with legacy contracts may choose to assume all GHG compliance risk in exchange for a higher fixed heat rate or they may choose between two options to share GHG risk with the utilities in exchange for lower fixed heat rates with GHG allowance price caps (a price above which the seller assumes the risk). The final option available to legacy QFs is to sign a tolling agreement with the purchasing utility, under which the utility would assume the GHG compliance obligation but would be allowed to manage that risk by assuming dispatch rights over the QF. Under any scenario where the utility assumes the GHG compliance risk, any free allowances held by the seller for electricity purchased by the contracting utility must be surrendered to the utility, and any GHG payments will be for costs not covered by those free allowances.17

Second, in D.09-12-042, as modified by D.10-04-055 and D.10-12-055, the Commission adopted rules and terms for a feed-in-tariff program aimed at small, highly efficient CHP. Under this program, the utility will be responsible for GHG compliance costs associated with the electricity it purchases, up to the emissions associated with operating the facility at or above the minimum efficiency level determined by the California Energy Commission.18 The CHP facility is provided the options to procure GHG allowances for electricity sold to the utility and then seek reimbursement from the utility, or to have the utility perform this allowance procurement function.19

Third, similar to the requirement in the CHP settlement that requires QFs responding to competitive solicitations to submit two different bid prices, at least one utility (Pacific Gas and Electric Company) requires all bidders of fossil fuel-based resources in its long-term solicitations to provide two alternate bids for each project - one in which the utility assumes the GHG compliance obligation and one in which the seller assumes the obligation. Under the first option, the facility owner would assume the GHG compliance cost, and therefore the risk that the compliance costs could change dramatically during the term of the power purchase agreement. Under the second option, the facility owner would pass through the costs of GHG compliance to the utility, and the utility would bear the risk of changes in allowance prices.

Fourth, another issue of concern is the treatment of contracts executed between independent generators and utilities before the passage of AB 32 which may extend into 2012 or beyond and may not allow the generator to pass through GHG compliance costs. If required to sell their output under the terms of their existing contracts, generators with such contracts may be faced with significant GHG compliance costs for which they will not be reimbursed or receive allowances. This issue may also be considered by ARB.20

3. Preliminary Scoping Memo

As required by Rule 7.1(d)21 of the Commission's Rules of Practice and Procedure, this Order Instituting Rulemaking (OIR) includes a Preliminary Scoping Memo. In this Preliminary Scoping Memo, we describe the issues to be considered in this proceeding and the timetable for resolving the proceeding.

This new rulemaking is opened to consider potential utility cost and revenue issues associated with GHG emissions. At this time, we plan to examine two broad aspects of the effect of ARB's staff-proposed GHG mitigation programs on electric utilities. The first issue is the direction the Commission should give to the electric utilities about the uses of revenues they may receive to the extent there is auctioning of their GHG emissions allowances by ARB, and revenues they may receive if they sell Low Carbon Fuel Standard credits received from ARB. The second issue is the utilities' potential exposure to GHG compliance costs, and the guidance the Commission should provide to the utilities regarding potential GHG compliance costs associated with electricity procurement.

As this rulemaking progresses, it may be determined that additional GHG issues, particularly those affecting the utilities' potential costs and revenues associated with GHG emissions, should be addressed in this proceeding. While the issues identified in this Preliminary Scoping Memo apply only to electric utilities, it is possible that GHG-related issues affecting the natural gas utilities may be identified subsequently for consideration in this proceeding.22

The Commission recognizes that ARB's proposed regulations for a GHG emissions allowance cap-and-trade program are not final, and that implementation of the Scoping Plan has been enjoined. However, to the extent that ARB is able to proceed as scheduled, and hold the first auction of allowances allocated to the utilities in less than a year, it would be imprudent to delay our consideration of the potential implications for the utilities and their ratepayers. We will proceed with this rulemaking while recognizing that adjustments may be needed as the ARB process unfolds.

The action by the San Francisco Superior Court enjoining ARB's implementation of its Scoping Plan23 creates significant uncertainty, both as to the schedule and scope of ARB's ultimate implementation of AB 32 and its Scoping Plan, including the GHG emissions allowance cap-and-trade program. Accordingly, the assigned Commissioner and/or the assigned Administrative Law Judge (ALJ) may make procedural rulings as necessary to address the consequences of this litigation, and may also address this issue further in the Scoping Memo for this proceeding. We intend for the scope of this rulemaking to be broad, and accordingly grant the assigned Commissioner and assigned ALJ discretion to revise the scope to include other relevant GHG issues that may arise, particularly those relating to utility costs and revenues from GHG emission regulations and statutory requirements.

As described in Section 2 above, regulations being considered at ARB would provide some guidance on the use of revenues from the auctioning of GHG emissions allowances to be allocated to the utilities. In this proceeding, the Commission will consider additional guidelines that may be needed. As an example, the Commission could adopt percentages, or dollar amounts, of potential auction revenues to be used for specified purposes, such as customer bill relief, energy efficiency programs, programs that achieve AB 32 environmental justice goals, and research, development and demonstration of GHG emissions reducing technologies. Additionally, the Commission may consider the appropriate use of potential revenues the utilities may receive from the sale of Low Carbon Fuel Standard credits given to them by ARB.

This rulemaking will also address various aspects of the utilities' management of their potential GHG cost exposure, which includes the arrangements for GHG compliance responsibility in bilateral contracts as well as utilities' participation in the GHG allowance and offset markets. Bilateral contract issues may arise in, but may not be limited to, the procurement scenarios described in Section 2.5 above.

In their procurement decisions, the utilities will have to make assumptions regarding the price of potential future GHG emissions allowances in order to choose among competing bids, each having potentially different GHG compliance exposure characteristics and with differing spreads between the prices offered for different GHG exposure options. This proceeding will consider the establishment of rules or guidelines to govern the utilities' evaluations of such options to ensure that ratepayers do not over-compensate generators that take on the GHG compliance risk. Among other issues, such guidelines may address how to evaluate requests for reimbursement from generating facilities when facilities procure allowances on their own behalf but utilities are responsible for the GHG compliance costs associated with the purchased electricity, as may be the case under the CHP feed-in-tariff program. The guidelines may also address legacy contracts, as described in Section 2.5 above.

In R.10-05-006, the long-term procurement planning proceeding, the Commission is considering authorization for utilities to buy and sell GHG emissions allowances and offsets. Either R.10-05-006 or this proceeding may consider the establishment of guidelines for the utilities' possible participation in GHG emissions allowance and offset markets.

4. Schedule

The assigned Commissioner or assigned ALJ will schedule a prehearing conference as soon as practicable. The scope, schedule, and other procedural issues will be discussed at the first prehearing conference. To facilitate these discussions, parties may file Prehearing Conference Statements addressing the scope and schedule of this proceeding, category, need for hearing, and other procedural issues no later than April 21, 2011 and Replies to Prehearing Conference Statements no later than May 5, 2011.

We leave it to the assigned Commissioner and/or assigned ALJ to establish a schedule that sequences the issues most appropriately. The assigned Commissioner or assigned ALJ may adjust the schedule and refine the scope of the proceeding as needed, consistent with the requirements of the Rules of Practice and Procedure.

Consistent with Public Utilities Code Section 1701.5, we expect this proceeding to be concluded within 18 months of the date of the scoping memo.

5. Category of Proceeding
and Need for Hearing

Rule 7.1(d) of the Commission's Rules of Practice and Procedure provides that the order instituting rulemaking "shall preliminarily determine the category and need for hearing..." This rulemaking is preliminarily determined to be ratesetting, as that term is defined in Rule 1.3(e). We anticipate that the issues in this proceeding may be resolved through a combination of workshops and filed comments, and that evidentiary hearings will not be necessary. Any person who objects to the preliminary categorization of this rulemaking as "ratesetting" or to the preliminary hearing determination, shall state the objections in their Prehearing Conference Statements. The assigned Commissioner will determine the need for hearing and will make a final category determination in the scoping memo; this final determination as to category is subject to appeal as specified in Rule 7.6(a).

6. Service of OIR, Creation of Service List,
and Subscription Service

We will serve this OIR on the service lists (appearances, state service list, and information-only category) in the following proceedings:

· R.03-10-003, the community choice aggregation rulemaking;

· R.06-04-009, the procurement incentive framework rulemaking;

· R.08-08-009, the renewables portfolio standard rulemaking;

· R.10-05-004, the distributed generation rulemaking;

· R.10-05-006, the long term procurement planning rulemaking;

· R.08-06-024, the CHP feed-in-tariff rulemaking;

· A.08-11-001, R.06-02-013, R.04-04-003, R.04-04-025, and R.99-11-022, the QF proceedings;

· A.09-04-008, Application of Southern California Edison Company for authorization to recover costs necessary to co-fund a feasibility study of a California integrated gasification combined cycle generation facility with carbon capture and storage;

· A.07-05-020, Application of Southern California Edison Company for authorization to incur and recover costs necessary to determine feasibility of a clean hydrogen power generation plant;

· R.07-09-008, the California Institute for Climate Solutions rulemaking;

· R.09-08-009, the alternative-fueled vehicles rulemaking;

· R.09-11-014, the post-2008 energy efficiency policies and programs rulemaking; and

· A.08-05-022, Application of Pacific Gas and Electric Company for Approval of the 2009-2011 Low Income Energy Efficiency and California Alternate Rates for Energy Programs and Budget (consolidated with A.08-05-024, A.08-05-025, and A.08-05-026).

Such service of the OIR does not confer party status in this proceeding upon any person or entity, and does not result in that person or entity being placed on the service list for this proceeding.

The Commission will create an official service list for this proceeding, which will be available at http://www.cpuc.ca.gov/published/service_lists. We anticipate that the official service list will be posted before the first filing deadline in this proceeding. Before serving documents at any time during this proceeding, parties shall ensure they are using the most up-to-date official service list by checking the Commission's website prior to each service date.

While all electric and natural gas utilities may be bound by the outcome of this proceeding, only those who notify us that they wish to be on the service list will be accorded service by others until a final decision is issued.

If you want to participate in the Rulemaking or simply to monitor it, follow the procedures set forth below. To ensure you receive all documents, send your request within 20 days after the OIR is published. The Commission's Process Office will update the official service list on the Commission's website as necessary.

Within 20 days of the publication of this OIR, any person may ask to be added to the official service list. Send your request to the Process Office. You may use e-mail (Process_Office@cpuc.ca.gov) or letter (Process Office, California Public Utilities Commission, 505 Van Ness Avenue, San Francisco, CA 94102). Include the following information:

· Docket Number of this Rulemaking;

· Name (and party represented, if applicable);

· Postal Address;

· Telephone Number;

· E-mail Address; and

· Desired Status (Party, State Service, or Information Only).24

If you want to become a party after the first 20 days, you may do so by filing and serving timely comments (including a Prehearing Conference Statement or Reply to Prehearing Conference Statements) in the Rulemaking (Rule 1.4(a)(2)), or by making an oral motion (Rule 1.4(a)(3)), or by filing a motion (Rule 1.4(a)(4)). If you make an oral motion or file a motion, you must also comply with Rule 1.4(b). These rules are in the Commission's Rules of Practice and Procedure, which you can read at the Commission's website.

If you want to be added to the official service list as a non-party (that is, as State Service or Information Only), follow the instructions in Section 6.1 above at any time.

Once you are on the official service list, you must ensure that the information you have provided is up-to-date. To change your postal address, telephone number, e-mail address, or the name of your representative, send the change to the Process Office by letter or e-mail, and send a copy to everyone on the official service list.

When you serve a document, use the official service list published at the Commission's website as of the date of service. You must comply with Rules 1.9 and 1.10 when you serve a document to be filed with the Commission's Docket Office.

The Commission encourages electronic filing and e-mail service in this Rulemaking. You may find information about electronic filing at http://www.cpuc.ca.gov/PUC/efiling. E-mail service is governed by Rule 1.10. If you use e-mail service, you must also provide a paper copy to the assigned Commissioner and ALJ. The electronic copy should be in Microsoft Word or Excel formats to the extent possible. The paper copy should be double-sided. E-mail service of documents must occur no later than 5:00 p.m. on the date that service is scheduled to occur.

If you have questions about the Commission's filing and service procedures, contact the Docket Office.

This proceeding can also be monitored by subscribing in order to receive electronic copies of documents in this proceeding that are published on the Commission's website. There is no need to be on the service list in order to use the subscription service. Instructions for enrolling in the subscription service are available on the Commission's website at http://subscribecpuc.cpuc.ca.gov/.

7. Public Advisor

Any person or entity interested in participating in this Rulemaking who is unfamiliar with the Commission's procedures should contact the Commission's Public Advisor in San Francisco at (415) 703-2074 or (866) 849-8390 or e-mail public.advisor@cpuc.ca.gov; or in Los Angeles at (213) 576-7055 or (866) 849-8391, or e-mail public.advisor.la@cpuc.ca.gov. The TYY number is (866) 836-7825.

8. Intervenor Compensation

Any party that expects to claim intervenor compensation for its participation in this Rulemaking shall file its notice of intent to claim intervenor compensation no later than 30 days after the first prehearing conference or pursuant to a date set forth in a later ruling which may be issued by the assigned Commissioner or assigned ALJ.

9. Ex parte Communications

Pursuant to Rule 8.2(c), ex parte communications will be allowed in this ratesetting proceeding subject to the restrictions in Rule 8.2(c) and the reporting requirements in Rule 8.3.

Therefore, IT IS ORDERED that:

1. A rulemaking is instituted on the Commission's own motion to address utility cost and revenue issues associated with greenhouse gas (GHG) emissions. While other issues may be considered, the rulemaking will consider, in particular, the use of GHG emissions allowance auction revenues that electric utilities may receive from the California Air Resources Board (ARB), the use of revenues that electric utilities may receive from the sale of Low Carbon Fuel Standard credits the electric utilities may receive from ARB, and the treatment of potential GHG compliance costs associated with electricity procurement. This rulemaking may also address other issues affecting electric and/or natural gas utility costs and revenues related to GHG emission regulations and statutory requirements.

2. The assigned Commissioner or Administrative Law Judge shall schedule a prehearing conference in this rulemaking as soon as practicable. Parties may file Prehearing Conference Statements no later than April 21, 2011 and may file Replies to Prehearing Conference Statements no later than May 5, 2011.

3. The assigned Commissioner or assigned Administrative Law Judge may adjust the schedule and refine the scope of the proceeding as needed, consistent with the requirements of the Rules of Practice and Procedure.

4. This rulemaking is preliminarily determined to be ratesetting, as that term is defined in Rule 1.3(e). It is preliminarily determined that evidentiary hearings are not needed in this proceeding. Any persons objecting to the preliminary categorization of this rulemaking as "ratesetting" or to the preliminary determination that evidentiary hearings are not necessary shall state their objections in their Prehearing Conference Statements.

5. The Executive Director shall cause this Order Instituting Rulemaking to be served on the service lists in the following proceedings:

· Rulemaking (R.) 03-10-003, the community choice aggregation rulemaking;

· R.06-04-009, the procurement incentive framework rulemaking;

· R.08-08-009, the renewables portfolio standard rulemaking;

· R.10-05-004, the distributed generation rulemaking;

· R.10-05-006, the long term procurement planning rulemaking;

· R.08-06-024, the combined heat and power feed-in-tariff rulemaking;

· Application (A.) 08-11-001, R.06-02-013, R.04-04-003, R.04-04-025, and R.99-11-022, the qualifying facility proceedings;

· A.09-04-008, Application of Southern California Edison Company for authorization to recover costs necessary to co-fund a feasibility study of a California integrated gasification combined cycle generation facility with carbon capture and storage;

· A.07-05-020, Application of Southern California Edison Company for authorization to incur and recover costs necessary to determine feasibility of a clean hydrogen power generation plant;

· R.07-09-008, the California Institute for Climate Solutions rulemaking;

· R.09-08-009, the alternative-fueled vehicles rulemaking;

· R.09-11-014, the post-2008 energy efficiency policies and programs rulemaking; and

· A.08-05-022, Application of Pacific Gas and Electric Company for Approval of the 2009-2011 Low Income Energy Efficiency and California Alternate Rates for Energy Programs and Budget (consolidated with A.08-05-024, A.08-05-025, and A.08-05-026).

6. Interested persons shall follow the directions in Section 6 of this Order Instituting Rulemaking to become a party or be placed on the official service list.

7. Any party that expects to request intervenor compensation for its participation in this rulemaking shall file its notice of intent to claim intervenor compensation in accordance with Rule 17.1 of the Commission's Rules of Practice and Procedure, no later than 30 days after the first prehearing conference or pursuant to a date set forth in a later ruling which may be issued by the assigned Commissioner or assigned Administrative Law Judge.

This order is effective today.

Dated , at San Francisco, California.

1 Statutes of 2006, Chapter 488.

2 D.08-03-018 at 9. See also at 98 - 99, Finding of Fact 30 and Ordering Paragraph 9.

3 D.08-10-037, at 227.

4 D.08-10-037, at 299.

5 ARB Resolution 10-42 at 3.

6 The ARB documents cited in this paragraph are available at http://www.arb.ca.gov/regact/2010/capandtrade10/capandtrade10.htm.

7 ARB staff's proposed regulations define "electrical distribution utilities" to include "an Investor Owned Utility as defined in the Public Utilities Code section and 218 [sic] or a local publicly owned electric utility that provides electricity to retail end users in California." (Proposed Regulations at A-14.) We note that Public Utilities Code Section 218 defines "electrical corporation," not "investor owned utility." We assume, absent clarification otherwise from ARB, that the proposed regulations use the term "Investor Owned Utility" to mean "electrical corporation." The electrical corporations that provide electricity to retail end users in California include Bear Valley Electric Service, California Pacific Electric Company, Mountain Utilities, Pacific Gas and Electric Company, PacifiCorp, San Diego Gas & Electric Company, and Southern California Edison Company.

8 Attachment B to ARB Resolution 10-42, available at http://www.arb.ca.gov/regact/2010/capandtrade10/capandtrade10.htm.

9 The final Resolution 10-42, updated to reflect changes directed by ARB on December 16, 2010, is available at http://www.arb.ca.gov/regact/2010/capandtrade10/capandtrade10.htm.

10 The previously proposed schedule for these activities is posted at http://www.arb.ca.gov/cc/capandtrade/capandtrade/programactivities.pdf.

11 ARB Resolution 10-42, December 16, 2010, at 13.

12 Attachment B to ARB Resolution 10-42 , Appendix 1, Figure 2, available at http://www.arb.ca.gov/regact/2010/capandtrade10/capandtrade10.htm.

13 Available at http://www.arb.ca.gov/regact/2009/lcfs09/lcfscombofinal.pdf. See also ARB's Resolution 09-31, available at http://www.arb.ca.gov/regact/2009/lcfs09/res0931.pdf, and Resolution 10-49, available at http://www.arb.ca.gov/fuels/lcfs/Resolution_10_49.pdf.

14 Upon commencement of a cap-and-trade program in California, the adopted QF and CHP settlement "establishes a floor test which compares an energy price developed with a market-based heat rate to an energy price developed with either a negotiated heat rate, or a heat rate from a period prior to the start of a cap-and-trade program, plus the market price of GHG allowances. The higher of the two energy prices is the one chosen as SRAC." D.10-12-035 at 20.

15 D.10-12-035 at 41.

16 See Qualifying Facility and Combined Heat and Power Program Settlement at Section 11, accessible through links in Appendix A to D.10-12-035.

17 See QF Facility and Combined Heat and Power Program Settlement at Section 10.2.3.

18 D.09-12-042 at 49. Final guidelines issued by the California Energy Commission in February 2010 require a CHP system to not exceed a GHG emission standard of 1,100 pounds of carbon dioxide equivalent emissions per megawatt-hour in order to be eligible for this program.

19 Applications for rehearing filed jointly by Pacific Gas and Electric Company and San Diego Gas & Electric Company and separately by Southern California Edison Company on January 18, 2011 seek rehearing of D.10-12-055, based partially on the treatment of GHG compliance costs. The Commission has not yet ruled on these applications for rehearing.

20 The ARB staff's October 28, 2010, ISOR states that "Some generators have reported that some existing contracts do not include provisions that would allow full pass-through of cap-and-trade costs. These contracts pre-date the mid-2000s and many may be addressed through the recently announced combined heat and power settlement at the California Public Utilities Commission. Staff is evaluating this issue to determine whether some specific contracts may require special treatment on a case-by-case basis." (ISOR at II-32, ft. 22.)

21 "Rulemakings. An order instituting rulemaking shall preliminarily determine the category and need for hearing and shall attach a preliminary scoping memo. The preliminary determination is not appealable, but shall be confirmed or changed by assigned Commissioner's ruling pursuant to Rule 7.3, and such ruling as to the category is subject to appeal under Rule 7.6."

22 Under the ARB staff-recommended cap-and-trade regulations, natural gas distribution utilities would be responsible, beginning in 2015, for the emissions associated with natural gas delivered to customers not directly covered under the proposed cap-and-trade program, including residential, commercial, and small industrial customers. (ISOR at II-35.)

23 Association of Irritated Residents et al. v. California Air Resources Board, Case No. CPF-09-509562, March 18, 2011.

24 If you want to file comments or otherwise actively participate, choose "Party" status. If you do not want to actively participate but want to follow events and filings as they occur, choose "State Service" status if you are an employee of the State of California; otherwise, choose "Information Only" status.

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