Wong Appendices A - D
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ALJ/JSW/tcg DRAFT Agenda ID #10237 (Rev. 1)

Decision PROPOSED DECISION OF ALJ WONG (Mailed 3/15/2011)

BEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA

Application of Pacific Gas and Electric Company Proposing Cost of Service and Rates for Gas Transmission and Storage Services for the Period 2011-2014. (U 39 G)

Application 09-09-013

(Filed September 18, 2009)

(See Appendix D for List of Appearances.)

DECISION REGARDING THE GAS ACCORD V SETTLEMENT

TABLE OF CONTENTS

Appendix A: Gas Accord V Settlement Agreement

Appendix D: List of Appearances

DECISION REGARDING THE GAS ACCORD V SETTLEMENT

1. Summary

Today's decision addresses Pacific Gas and Electric Company's (PG&E) natural gas transmission and storage (GT&S) application for 2011 through 2014. The initial focus of the original application was to address the revenue requirements, cost allocation, and rates associated with PG&E's GT&S facilities that will apply during this four-year rate cycle. However, following the September 9, 2010 San Bruno explosion and fire (San Bruno explosion), a separate safety phase was added to this proceeding. As a result, this decision requires PG&E to provide a semi-annual Gas Transmission and Storage Safety Report (Safety Report). A summary of today's decision follows.

PG&E settled all GT&S issues with the other parties in the Gas Accord V Settlement Agreement (Gas Accord V Settlement), which is attached to this decision as Appendix A. San Diego Gas & Electric Company (SDG&E) and Southern California Gas Company (SoCalGas) objected to two issues addressed by the settlement, and two other issues that pertain to PG&E's GT&S services. Today's decision rejects the issues raised by SDG&E and SoCalGas, and grants the motion of the settlement parties to approve the Gas Accord V Settlement. The terms contained in the Gas Accord V Settlement are adopted.

The Gas Accord V Settlement continues the Gas Accord market structure for PG&E for another four years, with some minor changes. The Gas Accord V Settlement establishes the revenue requirements and the rates for PG&E's GT&S services for this four-year rate cycle. The revenue requirements and rates agreed to in the Gas Accord V Settlement represent a compromise by the various parties of their positions on many different issues. Under the adopted Gas Accord V Settlement, the overall revenue requirement increases in each of the four years (2011: $514.2 million; 2012: $541.4 million; 2013: $565.1 million; and 2014: $581.8 million) over the 2010 revenue requirement of $461.8 million. PG&E had originally requested in its application revenue requirements of $529.1 million for 2011; $561.5 million for 2012; $592.2 million for 2013; and $614.8 million for 2014.

Under the adopted Gas Accord V Settlement, these gas transmission and gas storage rate components will result in an increase to most of PG&E's natural gas customers. As a result of today's decision, a typical residential gas customer in PG&E's service territory, who uses 37 therms per month, will experience a 0.7% increase in their monthly gas bill, from about $51.60 per month to $51.96 per month. Small commercial and large commercial gas customers will experience monthly increases of 0.8% and 0.9%, respectively.

This application was filed and the Gas Accord V Settlement was agreed to prior to the San Bruno explosion. As a result, the Commission initiated efforts in this proceeding to ensure the safe and reliable operation of PG&E's GT&S facilities in the years to come. As part of that effort, this decision requires PG&E to provide the Safety Report to the Commission and to the service list. This Safety Report shall provide details about the pipeline-related and storage safety, reliability, and integrity capital projects and maintenance activities that are being undertaken by PG&E and to track the amounts spent on such projects and activities. In addition, the Safety Report will provide Commission staff with details of whether the gas transmission pipeline projects that PG&E has identified as "high risk" by PG&E are being carried out, whether other replacement projects have been undertaken instead, and to determine PG&E's rationale for the reprioritization of these projects.1 The Safety Report will also allow us to monitor the status of PG&E's compliance with federal pipeline requirements, such as recurring pipeline inspections and pipeline upgrades. Furthermore, this decision directs Commission staff to review these reports to detect whether there are any problems with PG&E's administration of its pipeline-related capital projects and maintenance activities, and whether high risk sections of transmission pipeline are being replaced or upgraded.

A subsequent decision will follow to address other safety-related gas transmission issues raised by the San Bruno explosion such as providing fire personnel throughout PG&E's service territory with training and information about the location of PG&E's transmission pipelines and shutoff valves, and ensuring that PG&E personnel are rapidly dispatched and deployed to the site in an emergency.

It is important to note that this decision, and the decision to follow, is part of a forward-looking process that examines what can be done to ensure the safety and reliability of PG&E's GT&S system during the four-year period covered by this proceeding. This proceeding is not examining the cause of the San Bruno explosion and whether or not things should have been done differently. In addition, the reports of the National Transportation Safety Board and the Independent Review Panel have not yet been completed.

2. Procedural Background

Pacific Gas and Electric Company (PG&E) requests that the Commission grant its application concerning the revenue requirement, cost allocation, and rate design of its gas transmission and storage (GT&S) services for the four-year period from January 1, 2011 through December 31, 2014. Timely protests and a response to PG&E's application were filed by various parties, to which PG&E filed a reply.

A prehearing conference (PHC) was held on December 2, 2009, and a scoping memo and ruling (scoping ruling) was issued on December 18, 2009. In that scoping ruling, evidentiary hearings were originally scheduled for May 2010.2

The scoping ruling also scheduled public participation hearings in conjunction with PG&E's General Rate Case (GRC) proceeding in Application (A.) 09-12-020.3 Eighteen joint public participation hearings were held at eleven different locations in PG&E's service territory during May and June 2010. A summary of the public comments applicable to this proceeding is set forth in section 3.2. of this decision.

In the days following the PHC, PG&E and the parties to the proceeding began settlement discussions. A formal settlement conference was noticed for and held on July 29, 2010. On August 20, 2010, PG&E, joined by the settlement parties, filed a "Joint Motion of Settlement Parties for Approval of `Gas Accord V' Settlement" (Joint Motion).4 The proposed "Gas Accord V Settlement Agreement" (Gas Accord V Settlement or "settlement"), dated August 20, 2010, was attached to the Joint Motion.5

In accordance with the procedure set forth in the August 25, 2010 Administrative Law Judge's (ALJ) ruling, as clarified by the September 15, 2010 ruling, parties were allowed to contest the Joint Motion by serving testimony in opposition to the Joint Motion, or by filing comments on the Joint Motion.

San Diego Gas & Electric Company (SDG&E) and Southern California Gas Company (SoCalGas), who are not signatories to the Gas Accord V Settlement, filed their comments in opposition to the Joint Motion on September 20, 2010. SDG&E and SoCalGas also attached their prepared testimony which addressed their contested issues.

An evidentiary hearing on the issues raised by SDG&E and SoCalGas was held on October 25 and 26, 2010. Opening briefs were filed on November 10, 2010, and reply briefs were filed on November 19, 2010.

Following the September 9, 2010 natural gas pipeline explosion and fire in San Bruno (San Bruno explosion), a ruling was issued on September 15, 2010 which asked the parties to comment on whether the Gas Accord V Settlement was adequate in light of the pipeline safety concerns raised by the San Bruno explosion. On September 20, 2010, PG&E filed comments in response to the ruling, and the other settlement parties filed a reply to PG&E's response on September 30, 2010. On October 15, 2010, a revised scoping ruling was issued, which among other things, added a new safety phase to this proceeding to address the safety concerns raised by the San Bruno explosion. After receiving comments to a series of questions posed in the revised scoping ruling, a ruling was issued on February 3, 2011. That ruling stated, among other things, that a reporting requirement might be imposed in this decision. The issues covered by this phase of the proceeding were submitted following the February 3, 2011 ruling.

As explained later in this decision, the Commission has taken a number of other steps with regard to pipeline safety, and has formed the Independent Review Panel (IRP) to investigate the San Bruno explosion, including an assessment of the events and their root causes, and to make appropriate recommendations. In addition, the National Transportation Safety Board (NTSB) is conducting its own investigation into the cause of the San Bruno explosion, and recently held public hearings on March 1-3, 2011.

As a result of the extensions that were granted in this proceeding, PG&E filed a motion on October 8, 2010 requesting an order allowing the Gas Accord V Settlement revenue requirements and rates to go into effect on January 1, 2011, or to make the revenue requirements resulting from a subsequent final decision in this proceeding to be effective as of January 1, 2011. PG&E filed the motion to allow the settlement parties to realize the benefits of what they negotiated in the Gas Accord V Settlement, in the event the Commission grants the August 20, 2010 Joint Motion. In D.10-12-037, the Commission granted PG&E's request to make the revenue requirements and related elements resulting from a decision on the Joint Motion and the contested issues, to become effective as of January 1, 2011.

3. Discussion

This application covers the costs associated with operating PG&E's GT&S system. PG&E's gas transmission lines consist of about 6,400 miles of intrastate transmission lines. These transmission lines transport natural gas from the interconnections with in-state and out-of-state sources of gas supply to PG&E's gas distribution system and to gas customers who receive transmission-level service.6 Compressor stations and other metering and regulator stations are also part of the transmission system. For its gas storage operations, PG&E has four underground gas storage facilities and associated facilities.7 In addition, PG&E operates and maintains about 50 miles of gas gathering pipes and related equipment. Also included in the GT&S services are PG&E's customer service activities such as meter reading, billing, updating of customer accounts, answering customer inquiries, new transmission customer connections, and providing information about scheduling and nominations.

PG&E's application of September 18, 2009 requested a total revenue requirement for its GT&S services of $529.1 million for 2011, $561.5 million for 2012, $592.2 million for 2013, and $614.8 million for 2014. PG&E's revenue requirement for GT&S services in 2010 was $461.8 million, which was based on a settlement agreed to in 2007 in D.07-09-045.

Under the proposed Gas Accord V Settlement, the settlement parties have agreed to a total revenue requirement of $514.2 million for 2011, $541.4 million for 2012, $565.1 million for 2013, and $581.8 million for 2014.

SDG&E and SoCalGas oppose two elements of the proposed Gas Accord V Settlement, and have raised two other issues that are not directly addressed by the Gas Accord V Settlement. SDG&E and SoCalGas take issue with the Gas Accord V Settlement because: (1) it excludes Gas Schedule G-XF shippers, such as SoCalGas, from the proposed revenue sharing mechanism; and (2) the G-XF rates realize no benefits under the proposed settlement as compared to the noncore rates for the Redwood Path and Baja Path. The two remaining issues have to do with: whether SoCalGas has the right, as a G-XF shipper on PG&E's Redwood Path, to make gas deliveries into both PG&E's citygate in northern California and into Kern River Station in southern California; and whether the gas storage posting requirements of the Federal Energy Regulatory Commission (FERC) should apply to PG&E's gas storage activities.

The sections below address the comments from the public participation hearings, analyze the proposed Gas Accord V Settlement as compared to the original positions of the settling parties, analyze the issues raised by SDG&E and SoCalGas, and adopt measures to respond to issues raised by the San Bruno explosion.

Approximately 425 individuals spoke at the 18 public participation hearings regarding this application and PG&E's GRC proceeding in A.09-12-020. The comments below are pertinent to this proceeding, and have been considered in our deliberations.

A number of speakers spoke favorably about PG&E's partnerships with the different communities and PG&E's monetary and volunteer support of various community programs. These speakers also spoke about the economic benefit of having PG&E employees in the area, and the economic ripple effect of PG&E's infrastructure projects and operations on the local economies. Speakers also spoke in favor of PG&E's outreach for the California Alternate Rates for Energy program, and energy conservation and efficiency programs. Some speakers spoke about the quick response time of PG&E during outages. Others pointed to the need to spend money to upgrade the aging utility infrastructure in order to maintain reliable service. Several speakers stated that the Commission should try to reach a balance between the service reliability concerns that businesses have, and ratepayers' concerns about rate increases.

Numerous other speakers spoke out against any increase in PG&E's rates. Due to the present state of the economy, and with high unemployment, these speakers oppose any rate increase and favor a freeze or roll-back of PG&E's rates. Others pointed out that as the utility bill becomes a larger percentage of the household budget, some customers are forced to decide whether they should pay their utility bill or to buy food or medicine. If service is terminated for non-payment, a large deposit is required before utility service is restored, which is a hurdle for many of those seeking to reestablish utility service. Other speakers noted that the shut-off of utility service has led to fires and death when the use of candles resulted in house fires. Other speakers spoke about how PG&E's cost-cutting measures have led to a reduction in customer service and outage response times. Some agricultural customers spoke about how the proposed increases in gas rates would affect the cost of their fruit drying operations.

At several of the hearing locations, PG&E workers and their union representatives spoke about PG&E's outsourcing of various design and engineering projects, and favored keeping such work in-house because outside contracting leads to less reliable, lower quality, and more costly designs and projects. In addition, outside consultants are often not familiar with area conditions and permitting requirements, and that PG&E crews responding to outages need to have knowledgeable in-house resources to call on for assistance.

A number of speakers also criticized the proposed rate increases in light of PG&E's annual profits, the salaries of some of PG&E's executives, and the amount of money that PG&E spent on its unsuccessful Proposition 16 campaign in June 2010. Some speakers spoke out against the installation of smart meters and the associated loss of meter reading positions.

In addition to the public participation hearings, a number of customers sent e-mails and letters to the Commission, almost all of which oppose any rate increase by PG&E.

The proposed Gas Accord V Settlement, a copy of which is attached to the Joint Motion as Exhibit 1, and to this decision as Appendix A, addresses all of the issues associated with the operation of PG&E's GT&S facilities and services for the four-year period beginning January 1, 2011. SDG&E and SoCalGas oppose two issues that are addressed by the settlement, and have raised two other issues that the settlement does not directly address. The Gas Accord V Settlement consists of 12 sections, and three appendices, which are summarized in the paragraphs which follow. If the Gas Accord V Settlement is approved by the Commission, it will establish PG&E's GT&S rates for the four-year period beginning January 1, 2011 and ending on December 31, 2014.

In addition to the Gas Accord V Settlement, four other exhibits were attached to the Joint Motion. Exhibit 2 of the Joint Motion is the "Core Transport Agent (CTA) Settlement Agreement" (CTA Settlement) dated August 20, 2010. The CTA Settlement is referenced in section 11.2 of the Gas Accord V Settlement. Exhibit 3 of the Joint Motion is the signature pages to the Gas Accord V Settlement. Exhibit 4 of the Joint Motion provides tables which compare the agreements reached in the Gas Accord V Settlement to what PG&E filed on May 29, 2009, as updated by PG&E's April 23, 2010 errata testimony. Exhibit 5 of the Joint Motion are the non-rate pro forma tariffs that PG&E proposes be changed. The Joint Motion requests that these pro forma tariffs be approved.8

Section 1 of the Gas Accord V Settlement is labeled as the "Introduction." This section describes, among other things: the background of the Gas Accord market structure; who the settlement parties are and that they support approval of the settlement; that the settlement is a negotiated compromise of issues and is broadly supported by a diverse group of interests; that the settlement is to be treated as a complete package, and not as a collection of separate agreements on discrete issues or proceedings; that the non-rate pro forma tariff sheets attached to the settlement should be approved, and that the tariffs and rates be made effective on January 1, 2011; unless the settlement provides otherwise, all other portions of PG&E's tariffs and provisions approved in prior Commission decisions related to providing GT&S services remain in place through December 31, 2014 unless changed by Commission action; that the parties' preserve their rights in the event the Commission rejects or modifies the settlement; and that PG&E will file a motion for the Commission to approve the settlement rates on January 1, 2011, subject to refund or adjustment, if approval of the settlement is delayed past the end of 2010.

Section 2 of the Gas Accord V Settlement is entitled "Term of Settlement," and provides: the settlement covers the four-year period beginning January 1, 2011 through December 31, 2014; the effective date of the settlement is to be the later of January 1, 2011 or the effective date of the tariffs approved by the Commission to implement the settlement; PG&E is to file its next rate case no later than February 3, 2014, and PG&E may request an extension of this filing date and the non-PG&E parties may object to the request for such an extension; and if approved rates are not in place by January 1, 2015 pursuant to a Commission order in the next rate case, it provides for what the interim GT&S rates will be.

Sections 3, 4 and 5 of the Gas Accord V Settlement describe PG&E's backbone transmission, local transmission, and storage services, respectively. The settlement retains the current Gas Accord market structure and service options, with a few small adjustments. These adjustments are included in sections 3.1, 3.3, 3.4, 5.1, 5.2, and 5.3 of the settlement.

Section 3.1 of the settlement differentiates between core and noncore firm Baja rates. In previous Gas Accords, the core and noncore Baja rates were the same.

Section 3.3 provides that PG&E's retail core customers and wholesale core customers will continue to have the rights to 615.6 thousand decatherms (mdth) per day of Redwood Path vintage firm capacity at vintage rates, which exclude the costs associated with Line 401. Due to the differentiation between the core and noncore Baja rates, existing wholesale customers will have a one-time option before April 1, 2011, to take firm Baja capacity for the term covered by the settlement at the same rate paid by PG&E's Core Gas Supply.

Section 5.1 provides that the assignment of firm storage capacity to PG&E's Core Gas Supply and to pipeline load balancing is the same as in the Gas Accord IV settlement. However, the assignment of firm storage capacity to Market Storage service is increasing due to the completion of various projects, including the Gill Ranch Storage field. Section 5.2 provides that the costs and capacities of PG&E's share of the Gill Ranch Storage field are allocated to Market Storage.

Sections 3.4 and 5.3 provide respectively that PG&E will not be holding an open season at the beginning of the settlement period for existing firm backbone capacity, or for existing firm storage capacity.

Section 6 of the Gas Accord V Settlement provides that the settlement does not alter PG&E's existing authority to negotiate rate discounts for backbone transmission service, storage services, or for bundled end-use services. This section also provides that nothing in the settlement shall modify existing negotiated agreements between PG&E and any end-use customer or other shipper. This section also states that the revenues from discounted backbone transmission, local transmission, and storage transactions will be included in the revenue sharing mechanism that is described in section 10.1 of the settlement.

Section 7 of the Gas Accord V Settlement is entitled "Revenue Requirement," and summarizes the following: the GT&S revenue requirements during the settlement period; the allocation of the revenue requirement between core and noncore customers; the capital expenditure plan; operating and maintenance (O&M) expense; how eight backbone and local transmission adder projects will be included in rates if the projects are actually built; and how the costs that are to be determined in other PG&E proceedings will be adjusted in the Gas Accord V Settlement.

The agreed-upon revenue requirements in the Gas Accord V Settlement are set forth in section 7.1 and provide as follows:

Revenue Requirement by Line of Business ($ millions)

Line of Business

2010

2011

2012

2013

2014

Backbone

$241.0

$226.6

$237.6

$245.5

$247.4

Local Transmission

164.0

197.8

212.1

225.7

239.0

Storage

51.6

85.1

86.7

88.8

90.1

Customer Access Charge

5.2

4.7

4.9

5.1

5.2

Total Revenue Requirement

$461.8

$514.2

$541.4

$565.1

$581.8

The revenue requirement shown in the above table represents PG&E's revenue requirement as presented in this application, plus the negotiated adjustments that are described in sections 7.2, 7.3, and 7.4 of the settlement for capital expenditures, O&M expense, and the backbone and local transmission adder projects, respectively.

Section 8 of the Gas Accord V Settlement describes the gas demand and gas throughput forecasts for establishing the backbone and local transmission rates.

Section 9 of the Gas Accord V Settlement addresses the agreed-upon rates for all customer classes. Tables B-1 and B-2 of Appendix B to the settlement show the illustrative class average rates. Table B-1 illustrates the change between the 2010 rates and the 2011 rates agreed to in the Gas Accord V Settlement. Tables B-3 through B-13 of Appendix B show additional detail about the applicable rates. The settlement provides that all of the rate changes are to be effective on January 1 of the applicable year.

In the Gas Accord IV settlement, the Moss Landing Power Plant Units 1 and 2 (Moss Landing) were provided with a local transmission bill credit of $2 million per year. In section 9.5.1. of the Gas Accord V Settlement, the settlement parties agreed to extend this local transmission bill credit to Dynegy, which is the current owner of Moss Landing, for the settlement period. In addition, the settlement parties agreed in section 9.5.2 of the settlement to extend a local transmission bill credit to the City of Redding, the Modesto Irrigation District, the Turlock Irrigation District, and the City of Santa Clara.9 The total bill credit for these four entities is $260,000 in 2011 and is to be divided equally among them as shown in Table A-7 of Appendix A of the settlement. The bill credits for Moss Landing and for the four public entities are to be effective with the implementation of the local transmission rates, and will increase by two percent per year in 2012-2014.

Section 10 of the Gas Accord V Settlement addresses the "Revenue Sharing Mechanism and Other Cost Adjustment Mechanisms." The Revenue Sharing Mechanism, which is described in section 10.1, provides for the sharing of revenues from backbone transmission, local transmission, and gas storage. The difference between the adopted revenue requirement and recorded revenues from these three functions will be shared between customers and shareholders (i.e., both upside and downside) 10 based on the following sharing percentages:

Function

Customer Share

Shareholder Share

Symmetrical?

Backbone

50%

50%

Yes

Local Transmission

75%

25%

Yes

Storage

75%

25%

No, upside only

Sections 10.1.2 and 10.1.3 describe how PG&E will fund the revenue sharing mechanism with an annual amount of $30 million, and how a balancing account will be established to record the difference between the customer portion of the total revenue over- or undercollections for each function.

Section 10.2.1 addresses the other cost adjustment mechanisms. During the settlement term, the Catastrophic Event Memorandum Account, the Hazardous Substance Mechanism, and the z-factor Mechanism will continue to apply.

Section 10.2.2 provides for PG&E's withdrawal of its Greenhouse Gas Cost Memorandum Account, which was proposed in this application. PG&E reserves its right to request recovery of greenhouse gas-related costs from the Commission in the future, and the other parties retain their rights to protest such a filing. This section also describes likely future advice letters or applications to recover various emission-related costs in excess of the costs authorized in this settlement, and that these future filings may increase gas transmission rates over the rates authorized in the settlement.

Section 11 covers certain operational provisions, CTA issues, PG&E's core seasonal Baja Path firm capacity, and the supplemental report on the Line 57C project.

Section 11.1.1 provides for PG&E's withdrawal of its proposals to establish same day operational flow orders (OFOs) and a fifth nomination cycle. Section 11.1.2 addresses how PG&E must propose solutions to reduce constraints if a certain number of storage withdrawals are curtailed. Section 11.1.3 provides that if other operational issues arise, those issues can be addressed in the OFO Forum that was approved in D.00-02-050. Section 11.1.4 provides that other operational issues and proposed solutions can be brought to the Commission for review and approval during the period covered by the settlement. Section 11.1.5 provides that subject to section 11.1.4, PG&E will continue to call customer specific OFOs as necessary.

Section 11.2 notes that PG&E has reached an agreement with the CTA settlement parties. This agreement is labeled the "Core Transport Agent (CTA) Settlement Agreement" (CTA Settlement), which is dated August 20, 2010 and is attached as Exhibit 2 to the Joint Motion, and is attached to this decision as Appendix B. The CTA agreement addresses the following areas: CTA transmission and storage capacity elections; consumer protection rules; PG&E system enhancements; and other miscellaneous agreements. This section also acknowledges that PG&E no longer has an obligation to promote CTAs and the Core Aggregation Program.

Section 11.3 provides that during the settlement period, PG&E's Core Gas Supply will not reduce its seasonal firm capacity holdings on the Baja Path.

Section 11.4 addresses the supplemental report on PG&E's Line 57C Project that was ordered in D.07-09-045. The supplemental report addresses the reasonableness and ratesetting issues associated with that project. The settlement parties agree that the supplemental report satisfies the requirements of D.07-09-045, and that they do not object to the content and conclusions of the report.

Section 12.1 of the Gas Accord V Settlement provides that the rates specified in this settlement are not subject to adjustment during the settlement period except as provided for in the settlement or as agreed to by the settlement parties and approved by the Commission. This section provides that "the demand forecast underlying the Settlement backbone rates assumes that none of the G-XF contracts except the NCPA [Northern California Power Agency] contract has on-system delivery rights." If any off-system G-XF shipper receives on-system delivery rights during the settlement period, this section provides that "the demand forecast and backbone rates may need to be adjusted to account for displacement of other on-system services by these G-XF shippers."

Section 12.1 also provides that PG&E can make "adjustments to services, capacity assignments, cost allocations, rates or the like in order to comply with Commission orders in other proceedings." In addition, this section prevents a settlement party from making any proposal that conflicts with or alters any term of the Gas Accord V Settlement, and that the settlement parties shall not support proposals of others that would do the same.

Section 12.2 provides that due to other filings and Commission approval of such filings, that certain end-use customer charges will continue to change during the settlement period. The Gas Accord V Settlement does not change any of those procedures and filings.

Attached to the Gas Accord V Settlement are three sets of appendices. The first is Appendix A, which is composed of seven different tables which support various provisions of the settlement. The second is Appendix B, which contains 25 rate tables. The third is Appendix C, which describes how the GT&S Revenue Sharing Mechanism would impact customers and shareholders under different scenarios.

In deciding whether the Joint Motion should be granted or not, we are guided by Rule 12.1(d) of the Commission's Rules of Practice and Procedure. That subdivision states: "The Commission will not approve settlements, whether contested or uncontested, unless the settlement is reasonable in light of the whole record, consistent with laws, and in the public interest." In determining whether the Gas Accord V Settlement is reasonable in light of the whole record, consistent with the law, and in the public interest, we first compare the original positions of the parties to the recommended outcomes in the Gas Accord V Settlement. After that, we analyze the issues raised by SDG&E and SoCalGas, and the issues raised by the San Bruno explosion.

As we discuss in more detail below, we conclude that the settlement is reasonable in light of the whole record, consistent with the law, and in the public interest. In reaching that conclusion, we have examined the positions of the various parties, reviewed and compared the Gas Accord V Settlement to the original positions of the parties, considered the legal arguments raised by SDG&E and SoCalGas, and the public's concern in the safety and reliability of PG&E's GT&S system.

The original positions of the parties are contained in the testimony which was prepared for this proceeding and admitted into evidence during the October 2010 evidentiary hearings. Also pertinent to this analysis are the protests and response to PG&E's application, the comparison tables that are attached to the Joint Motion as Exhibit 4, and the comments made at the public participation hearings for and against the proposed increases.

The Gas Accord V Settlement has been entered into by many different parties who represent a broad range of interests in the natural gas marketplace. These interests include DRA, which represents customers as a whole, as well as TURN who represents the interests of residential and small commercial customers. Other settlement parties include representatives of large commercial customers, industrial customers, wholesale customers, electric generators, and CTAs. In addition, the settlement parties include representatives of independent storage providers (ISPs), interstate pipelines, and natural gas producers and marketers. Nine of the settlement parties filed a protest or response to PG&E's application. Before the Gas Accord V Settlement was agreed to, the parties to the proceeding participated in extensive discovery and settlement discussions.

PG&E's application requested a GT&S revenue requirement of $529.1 million for 2011. For each of the three following years, PG&E's application sought increases raising PG&E's requested revenue requirement in 2012 to $561.5 million, in 2013 to $592.2 million, and in 2014 to $614.8 million. Under the proposed Gas Accord V Settlement, the agreed-upon revenue requirements for 2011 through 2014 are $514.2 million, $541.4 million, $565.1 million, and $581.8 million, respectively. According to Exhibit 19, DRA estimates that the Gas Accord V Settlement will result in a savings to core customers of about $77 million over the four-year settlement period as compared to PG&E's original position.

Another point to keep in mind is that the underlying elements which make up the revenue requirement for test year 2011 have not been reviewed since the test year 2008 revenue requirement in PG&E's last GT&S proceeding was agreed to in the Gas Accord IV settlement that was approved in D.07-09-045. That test year 2008 revenue requirement was developed based on information in the 2006 to 2007 timeframe. As established by D.07-09-045, the test year 2008 revenue requirement was $446.5 million, and using the escalation factors approved in D.07-09-045, the revenue requirement in 2010 was $461.8 million. Thus, the test year 2011 revenue requirement needs to take into account the cost changes that have occurred since the test year 2008 revenue requirement was first developed. As PG&E points out, the 2010 revenue requirement that was agreed to in the Gas Accord IV settlement was well below PG&E's true cost of service, and was $39 million less than PG&E's litigation position in the last GT&S proceeding. Also, PG&E has experienced increasing outlays of capital that have been well above historical levels and these outlays are forecasted to continue through the rate case period. These increases are a direct result of PG&E's compliance with federal pipeline requirements, as well as to meet growing demand.

In the protests and response to PG&E's GT&S application, some of the parties raised concerns about the amount of PG&E's proposed capital expenditures and O&M expenses. The proposed capital expenditures and O&M expenses are two key drivers of PG&E's overall revenue requirement.

The settlement parties were able to negotiate reductions to the capital expenditure forecast in each of PG&E's "Major Work Categories." (MWCs)11 These capital expenditure reductions, which are addressed in section 7.2 of the settlement, add up a total reduction of about $155.6 million over the settlement period.

In order to maintain and operate PG&E's gas transmission pipeline and gas gathering pipeline, PG&E's GT&S application involves capital expenditures during the four-year period. These capital expenditures are needed to address issues concerning regulatory compliance, safety, reliability, system capacity, efficiency, new customer loads, and facility relocations. Among the MWCs are "Pipeline Integrity Management" in MWC-98, and "Pipeline Safety and Reliability" in MWC-75.

PG&E is required by the United States Department of Transportation's Office of Pipeline Safety, as set forth in Subpart O of Part 192 of Title 49 of the Code of Federal Regulations (Subpart O), to implement a Pipeline Integrity Management Program. Subpart O was issued in December 2003.12 This program requires a pipeline owner to assess and manage the integrity of all of its gas transmission pipelines located in a High Consequence Area (HCA). HCAs are defined in Subpart O as areas with 20 or more occupied dwellings, public gathering places or structures difficult to evacuate. Approximately 1,020 miles of PG&E's gas transmission pipelines are located within an HCA, and as population density increases this number is expected to grow. Subpart O requires that all baseline integrity assessments be completed by December 2012, and reassessment of the HCA pipelines is required at seven-year intervals.13 As part of the proposed work for this program, some of PG&E's gas transmission pipelines will be upgraded to allow PG&E to inspect them with an in-line inspection tool, often referred to as a "smart pig." This category of work is included in MWC-98. Due to operating conditions, design, and other factors, not all of PG&E's pipelines can be inspected using an in-line inspection tool or retrofitted to allow in-line inspection.

MWC-75 covers the capital costs of improving the safety and reliability of PG&E's gas transmission lines. The expenditures in this category include replacement of high-risk pipeline segments and pressure regulating facilities identified by PG&E's pipeline Risk Management Program. The pipeline integrity inspection results are included in PG&E's risk assessments to help prioritize pipeline safety and reliability investments. Capital expenditures in this category also include complying with the construction, maintenance and operation requirements for gas transmission pipelines as required by Part 192 of Title 49 of the Code of Federal Regulations. As population density increases in a particular area, a higher level of safety is required for transmission pipelines located in that area.

In addition to the negotiated reductions to capital expenditures, the settlement parties addressed "adder" treatment for eight planned transmission capital projects. The settlement parties agreed that if PG&E actually builds the capital project, the adder project will be included in rates starting on January 1 following the project's in-service date. The adder provision also provides that each project will be subject to a capital expenditure cap. This adder provision is useful in that if there is a delay, the project will not be included in rates, and if the project is built there is a cap on the expenditures associated with the project.

The other driver of PG&E's revenue requirement is the O&M expenses that are required to operate and maintain its GT&S facilities. PG&E requested $119.9 million for O&M expense in 2011, and additional increases in 2012, 2013 and 2014 to $123 million, $126.3 million, and $129.6 million, respectively. In the Gas Accord V Settlement, the parties agreed to O&M expenses of $104.8 million for 2011, $107.3 million for 2012, $109.7 million for 2013, and $112.6 million for 2014. The costs associated with pipeline integrity management activities make up about 21% of the O&M expenses.

The GT&S O&M expenses also include $1 million for technical training to support workforce diversity in 2011, with an escalation factor in each of the three subsequent years. This expense is part of the funds for PG&E's PowerPathway job-readiness and internship program, which collaborates with various labor and industry groups and educational institutions. With an aging utility workforce, this program helps to identify and prepare a new generation of high school and college students with the necessary skills and internship opportunities to pursue a career in the energy field.

Since the Joint Motion to adopt the Gas Accord V Settlement was filed before the San Bruno explosion, we asked the parties to comment on whether the settlement provides the necessary funds for PG&E to carry out the capital expenditures and O&M activities that are required by Subpart O and related regulations. The settlement parties commented that the Gas Accord V Settlement provides 92% of the monies that PG&E had requested for O&M pipeline integrity, 100% of the capital investment requested for pipeline integrity management in MWC-98, and 98% of the monies that PG&E had requested for pipeline safety and reliability efforts in MWC-75. Since a significant percentage of the monies for pipeline-related safety, integrity, and reliability projects and maintenance activities are contained in the Gas Accord V Settlement, the settlement is reasonable from the point of view that there are sufficient monies during this four-year rate cycle to fund these projects and maintenance activities.

The demand or throughput forecast is an important element for cost allocation and ratemaking purposes. Generally speaking, if the throughput amount is larger, there will be more volume over which to spread the cost of providing a particular service. In PG&E's application, its on-system gas throughput forecast for 2011, 2012, 2013 and 2014 was 1977 mdth/day, 2009 mdth/day, 2007 mdth/day, and 2026 mdth/day, respectively. The Gas Accord Settlement Agreement provides that the on-system gas throughput forecast will be 1996 mdth/day for 2011, 2085 mdth/day for 2012, 2106 mdth/day for 2013, and 2115 mdth/day for 2014.

The demand forecast also includes a forecast of off-system revenues, and the throughput forecast on PG&E's Silverado path. PG&E's application forecasts off-system non-G-XF revenues for 2011-2014 at $3.28 million per year. The Gas Accord V Settlement establishes the non-G-XF revenues at $4.57 million. The $4.57 million is then converted to the equivalent backbone throughput using the 2011 noncore Redwood rate, and then added to the on-system demand forecast for purposes of the backbone rate design. For the Silverado path, the Gas Accord V Settlement agreed to establish the throughput forecast on the Silverado path at 132 mdth/day, which is the same amount that PG&E had forecasted.

Some of the parties raised concerns with the cost allocation and rate design methodologies that should be used to allocate costs and to calculate rates. In past Gas Accord settlements, the capacities of the backbone transmission lines were used to allocate costs to the backbone paths, and a system average load factor was used to calculate rates on each backbone path. PG&E proposed in its application to use forecasted demands instead.14 PG&E also proposed to equalize the core and noncore Redwood and Baja rates. For local transmission rates, concerns were raised about whether the bill credits available to certain electric generation customers should be continued, and whether the revenue shortfalls from discounted contracts should be included in rates. For storage rates, some parties were concerned about the treatment of PG&E's Line 57C for its McDonald Island storage field, and PG&E's 25% interest in the Gill Ranch Storage field.

Although the Gas Accord V Settlement continues the use of the system average load factor methodology, Exhibit 19 describes how the agreed-upon load factors "are the result of negotiations regarding the appropriate calculation methodology and the appropriate inputs to that calculation." As shown in Table 6 of Exhibit 19, the agreed-upon load factors in the Gas Accord V Settlement average about 2.66% higher than the load factors presented by PG&E in Exhibit 1. The agreed-upon load factors result in lower rates.

The Gas Accord V Settlement also negotiated backbone rates that retain distinct rates for each backbone path, instead of using PG&E's proposal to equalize the rates of the Redwood and Baja paths. According to Exhibit 19, the agreed-upon backbone path rate differentials between the Redwood and Baja paths shown in section 9.1.3 of the settlement are the result of "negotiated outcomes that balance the competing interests of Redwood and Baja path shippers and their respective upstream pipelines and producers."

For local transmission rates, the settlement parties agreed to design the rates in the same manner as in the past Gas Accord decisions, as updated by the Gas Accord V Settlement revenue requirement, the on-system demand forecast, and the Cold-Year-January-Demand allocators.

As shown in section 9.5 of the settlement, the settlement parties also agreed to extend the local transmission bill credits to the same electric generation customers who received them previously. These bill credits amount to $2.8 million in 2011, with two percent escalation per year from 2012 through 2014. These bill credits are funded by a surcharge on all backbone rates except Rate Schedule G-XF, a surcharge on Rate Schedule G-EG backbone level service and Rate Schedule G-NT backbone level service, and by PG&E's shareholders. In addition, the settlement parties agreed in section 9.2.3 of the settlement to local transmission discounts for three negotiated contracts.

For the gas storage rates in section 9.3 of the settlement, the rates are designed in the same manner as in the past Gas Accord decisions, as updated by the Gas Accord V Settlement revenue requirement, the increased assignment of storage capacity to PG&E's Market Storage service, and the updated storage billing units used for cost allocation.

Other gas storage rate issues involved how to treat certain recently built gas storage facilities. These facilities include: the Line 57C pipeline built in 2007 at PG&E's McDonald Island storage field; installation of compressors at McDonald Island in 2009; and the construction of the Gill Ranch Storage field in 2010.

For the Line 57C pipeline, which was addressed in PG&E's "Supplemental Report on the Line 57C Project" (supplemental report), the settlement parties agreed that this supplemental report satisfied the requirements of D.07-09-045, and agreed not to object to the content and conclusions of the report. Line 57C was built as a redundant facility to ensure reliable service from the McDonald Island storage field in the event the existing Line 57B fails. The supplemental report recommends that the Line 57C costs be rolled into the rates of all three storage services, i.e., core, market storage, and balancing. Under this rolled-in rate treatment, core storage and load balancing pay a share, while Market Storage pays a greater share of the Line 57C costs. In Exhibit 19, the non-PG&E settlement parties state that this cost allocation is fair and reasonable because the amount that core storage and load balancing pay reflects the reliability benefits they receive, and the share that Market Storage pays reflects both the reliability benefits and the increased Market Storage capacity.

For the compressor units added to McDonald Island in 2009, the settlement parties agreed to rolled-in rate treatment instead of incremental rate treatment. With rolled-in treatment, the allocation of costs to core storage and load balancing is lower than under incremental rate treatment.

For PG&E's 25% share of the Gill Ranch Storage field, the revenue requirement for this field is combined with Market Storage's cost allocation from the three other storage fields, from which a single slate of Market Storage services and rates is developed. This rate treatment and structure is consistent with the Commission's and PG&E's commitment in the Gill Ranch Storage proceeding to shield core ratepayers from the costs of Gill Ranch Storage. (See D.09-10-035, Finding of Fact 6 at 67, Ordering Paragraph 19 at 75.)

Another major concern with PG&E's application was its proposal for a GT&S revenue sharing mechanism. The protests and response to PG&E's application voiced concerns about whether the mechanism would create a competitive advantage for PG&E's Market Storage unit over ISPs, whether the mechanism violated the Gill Ranch Storage certificate conditions, and whether it would result in improper cross-subsidies between PG&E's GT&S services.

The agreed-upon revenue sharing mechanism is addressed in section 10.1 of the Gas Accord V Settlement and is different from what PG&E had proposed in its application. PG&E's application proposed that excess GT&S revenues, as well as revenue shortfalls, be equally shared on a 50/50 basis with PG&E's shareholders and PG&E's customers and returned through backbone rates in the following year. In contrast, the agreed-upon revenue sharing mechanism provides that: backbone over- and under- collections will be shared 50%; local transmission over- and under- collections will be shared 75% with customers and 25% to PG&E's shareholders; and storage over-collections will be shared 75% with customers and 25% to PG&E's shareholders, while storage under-collections are absorbed 100% by PG&E.

In addition, the agreed-upon sharing mechanism provides for a "seed value" of $30 million per year, which is credited to the GT&S revenue requirement and rates immediately. This seed amount is allocated to all backbone and local transmission services, except for Rate Schedule G-XF, in the same percentages as their respective allocated revenue requirements.

The revenue sharing mechanism agreed to in the Gas Accord V Settlement provides significant ratepayer benefits through the $30 million seed, as well as the enhanced sharing of over- and under- collections.

The objection that SoCalGas and SDG&E raised with respect to the revenue sharing mechanism agreed to in the Gas Accord V Settlement is discussed later in this decision.

The issues that the CTAs raised during the December 2, 2009 prehearing conference were summarized in the scoping ruling as "whether the commitments that PG&E made in the original Gas Accord with respect to customer and the core aggregators are being adhered to in this application." PG&E and the CTAs were able to agree on the CTA Settlement, a copy of which is attached to this decision as Appendix B. The CTA Settlement addresses four areas.

The first is the CTA transmission and storage capacity elections, which is to become effective on April 1, 2012. Prior to the CTA Settlement, CTA pipeline capacity elections were to change when the CTA market share reached 10%. Under the CTA Settlement, PG&E and the CTAs have agreed that the CTAs will be given an annual election for long-term storage capacity, and a three-times-a-year election for long-term transmission capacity. According to the non-PG&E settlement parties, these new procedures balance the CTAs' interests in retaining flexibility in the election process, and the interests of PG&E and DRA in ensuring that the CTAs bear their share of the cost responsibility for those elections.

The second area addressed by the CTA Settlement covers the development of new consumer protection rules through the collaborative efforts of PG&E, the CTAs, and the Commission. The new rules are to be based on certain guiding principles. The development of these new rules is intended to help protect core gas customers from potential slamming by CTAs, and from fraudulent, deceptive, or abusive marketing activities. The new consumer protection rules are to be incorporated into the Core Gas Aggregation Service Agreement and all applicable PG&E tariffs.

The third area that the CTA Settlement addresses is enhancements to PG&E's system. PG&E agrees to implement eight system enhancements by various deadlines. These system enhancements are intended to improve the tools that are currently provided to the CTAs, and which will help them better manage their businesses.

The fourth area of the CTA Settlement addresses ten other CTA issues. These other issues include PG&E's agreement to make or consider adjustments to various elements of the core aggregation program so that CTAs have access to more timely and accurate information to allow them to better manage their businesses.

PG&E's application also included some operational proposals to: (1) establish a same day OFO that would be called on the same gas day to which it would apply; (2) establish a fifth nomination cycle that is limited to transactions with on-system storage providers; and (3) change Gas Rule 14 to clarify that shutoffs can be used to ensure system integrity should an emergency flow order or involuntary diversion fail to alleviate the emergency condition. Concerns were raised in the protests and response about how the change in the OFO protocol could limit a customers' flexibility to manage imbalances, and whether this change in the OFO protocol was an appropriate remedy to address natural gas swings associated with the integration of renewable resources. None of these three proposals have been included in the Gas Accord V Settlement.

Two of the ISPs raised concerns about whether PG&E's backbone capacity was adequate to fully utilize the storage facilities of PG&E and the ISPs, and whether the existing rules that allocate backbone capacity to as-available service were adequate. Section 11.1.2 of the settlement addresses these concerns by providing that if the independent storage withdrawal capacity allocation method, as described in Gas Rule 14 of PG&E's tariffs, is applied five or more times between any April and March, and in two of these applications at least 10% of the volumes are curtailed, PG&E must provide specific solutions in the next GT&S rate case to reduce this constraint.

Other operational issues were raised in the protests and response to PG&E's application and during the settlement discussions. Sections 11.1.3 through 11.1.5 of the settlement provide that these and other issues may be raised in other forums at any time.

Several parties questioned PG&E's proposal to reduce the Baja seasonal firm capacity holdings of the Core Gas Supply (CGS) department. Section 11.3 of the settlement provides that PG&E will not reduce these holdings during the term of the settlement, and that CGS is free to continue to broker its backbone capacity.

Other parties raised concerns about PG&E's proposals to include its market concentration rules in its backbone rate schedules, to increase the long-term (greater than five years) firm contracting limit on the Redwood path to 800 mdth/day, and to eliminate the on-system delivery option for off-system firm contracts with straight fixed-variable rate design. None of these PG&E proposals were incorporated into the Gas Accord V Settlement.

The above comparisons of the original positions of PG&E and the concerns of the market participants to the Gas Accord V Settlement demonstrate that the settlement parties have negotiated a number of different issues and have been able to reach agreed-upon resolutions. Although the agreed-upon revenue requirements will result in rate increases, it is less than what PG&E had requested in its application. In addition, one must take into account that the increase in the revenue requirement over the years used the 2006-2007 timeframe as the starting point to develop the test year 2008 revenue requirement that was agreed to in the Gas Accord IV settlement. Since that time, costs have steadily increased. TURN, who represents the interests of residential and small commercial customers, as well as DRA, had an opportunity to thoroughly review PG&E's request. Both TURN and DRA, as well as other settlement parties who represent other ratepayer interests, have joined in the Gas Accord Settlement. As we discuss in the summary section at the end of this decision, the Gas Accord V Settlement is reasonable in light of the whole record.15

SDG&E and SoCalGas, who did not join in the Gas Accord V Settlement, have raised four contested issues, two of which are directly addressed by the settlement. These four issues are addressed here as part of our analysis into whether the settlement is reasonable in light of the whole record, consistent with the law, and in the public interest. We first address the two issues raised within the context of the proposed Gas Accord V Settlement.

The first issue that SDG&E and SoCalGas raise is that G-XF shippers, such as SoCalGas, should be allowed to participate in the revenue sharing mechanism that is contained in the Gas Accord V Settlement.

Section 10.1 of the Gas Accord V Settlement provides for the establishment of a revenue sharing mechanism for the four-year period covered by the settlement. For PG&E's backbone gas transmission, the settlement provides: "The difference between the adopted backbone revenue requirement and recorded backbone revenues, whether an over-collection or an under-collection, will be shared 50% to customers and 50% to PG&E shareholders." For PG&E's local gas transmission, the settlement provides: "The difference between the adopted local transmission revenue requirement and recorded local transmission revenues, whether an over-collection or an under-collection, will be shared 75% to customers and 25% to PG&E shareholders." For storage, any over-collection is to be shared 75% to customers and 25% to PG&E's shareholders, and PG&E is to be at risk for 100% of any net under-collection. Section 10.1.2 specifically excludes Schedule G-XF from being allocated any of the $30 million in annual seed money to fund the revenue sharing mechanism.

SDG&E and SoCalGas contend there is no reason to exclude G-XF shippers from the revenue sharing mechanism, and that such an exclusion is arbitrary, unreasonable, and discriminatory. SDG&E and SoCalGas further contend that since SoCalGas is the largest G-XF shipper on PG&E's Redwood Path, that this exclusion adversely impacts the core customers of SoCalGas and SDG&E. SDG&E and SoCalGas contend that modifying the Gas Accord V Settlement to allow G-XF shippers to participate in this revenue sharing mechanism is an appropriate and equitable remedy.

PG&E and some of the other settlement parties maintain that G-XF shippers should not be allowed to participate in the revenue sharing mechanism. They contend that the G-XF contracts that were entered into with shippers pay for the incremental costs of PG&E's Line 401 expansion project. Also, PG&E points out that a 95% load factor assumption has always been used to set the G-XF rate. Thus, PG&E contends it is not appropriate for G-XF shippers to receive credits or to incur costs for revenues associated with backbone and local transmission, and market storage. PG&E and the other settlement parties also contend that since G-XF customers have not participated in any form of revenue sharing on the PG&E system, that they should not expect to participate in the revenue sharing mechanism agreed to in the Gas Accord V Settlement. PG&E also points out that if G-XF shippers are allowed to participate in the revenue sharing mechanism, and the G-XF rates are lowered by the same proportion that the noncore Redwood rates were in the Gas Accord V Settlement, that this would effectively result in PG&E subsidizing SoCalGas and SDG&E.

We are not persuaded by the argument of SDG&E and SoCalGas that the exclusion of G-XF shippers from participating in the Gas Accord V Settlement's revenue sharing mechanism is arbitrary, unreasonable or discriminatory. We reach that conclusion based on the well-documented history of how PG&E's Schedule G-XF customers have been responsible for the incremental costs of PG&E's Line 401 expansion project, as PG&E and some of the other settlement parties have pointed out in their testimony and citations to Commission decisions. The rate design methodology for G-XF rates has remained unchanged since Line 401 was first authorized, as well as in the series of Gas Accord decisions.16 There is a clear separation between how the G-XF rate is designed, and how the rates for PG&E's backbone transmission and local transmission are designed. The latter rates are affected by various inputs that have nothing to do with the Line 401 costs. Furthermore, G-XF customers have not participated in any revenue sharing on PG&E's system in the past. We also note that SoCalGas and SDG&E did not contest section 9.5 of the Gas Accord V Settlement where G-XF shippers were excluded from having to pay the local transmission bill credit surcharge. All of these reasons justify excluding G-XF customers from participating in the revenue sharing mechanism. Therefore, we conclude that the exclusion of G-XF shippers from participating in the revenue sharing mechanism is not arbitrary, unreasonable, or discriminatory, and the request of SoCalGas and SDG&E to revise this part of the settlement to allow G-XF customers to participate in the revenue sharing mechanism is not adopted.

The second issue that SDG&E and SoCalGas have raised with the Gas Accord V Settlement is with the rate that G-XF customers will have to pay. SDG&E and SoCalGas believe that the G-XF rate should be lower than what the Gas Accord V Settlement provides. SDG&E and SoCalGas contend that the G-XF rates PG&E proposes are basically the same as to what was agreed to in the Gas Accord V Settlement. In contrast, other noncore backbone transmission rates are lower in the Gas Accord V Settlement than what PG&E had proposed in its application. As a result, SDG&E and SoCalGas contend there is a glaring discrepancy in the benefits that other backbone transmission rates receive as compared to the G-XF rates. SDG&E and SoCalGas recommend that to achieve a fairer distribution of the benefits, that the G-XF rates in the Gas Accord V Settlement be lowered by the same percentage that the noncore Redwood Path rates were lowered, i.e., by 20.8%.

PG&E contends that its Schedule G-XF rate reflects the incremental costs that are associated with PG&E's Line 401 expansion project. A description of how the rates for G-XF shippers are calculated is described in Exhibit 18 at 2-2. The G-XF rate has always been calculated in this manner since PG&E was granted permission to construct Line 401, and the same rate design methodology was continued in all the Gas Accord decisions. Since the G-XF rate is associated with the cost of Line 401, PG&E contends it would be inappropriate to reduce the G-XF shipper rates by the same percentage reductions that the noncore Redwood Path rates received in the Gas Accord V Settlement as compared to the rates that were originally proposed in PG&E's application. PG&E also notes that part of the difference between the backbone transmission rates is that Line 400 and Line 300 are older pipelines than Line 401.

As mentioned earlier, we have reviewed the historical development of the Schedule G-XF rates, as well as how the noncore Redwood Path and the noncore Baja Path rates were developed in the Gas Accord V Settlement and in prior Gas Accord decisions. We agree with PG&E that the G-XF rates, as set forth in the Gas Accord V Settlement, should not be reduced as proposed by SoCalGas and SDG&E. The G-XF rates have always been associated with the cost of Line 401, and those rates have been developed in the same manner since Line 401 was first constructed. The reduction in the noncore Redwood Path and noncore Baja Path rates, as compared to PG&E's application and as agreed to in the Gas Accord V Settlement, are the result of a number of different factors that the settlement parties negotiated and which affect the inputs that generate the rates for the noncore Redwood Path and noncore Baja Path. The impact of how these different inputs affect the noncore Redwood Path and noncore Baja Path rates are described in Exhibit 18, and are shown in Table 2-1 of that exhibit. SoCalGas' witness acknowledged that "the G-XF rate is not impacted by every element that goes into the calculation of other rates such as throughput on the system...." (11 R.T. 1043.) It is these kinds of differences in how the G-XF rates and the other noncore transmission rates are designed that results in a greater percentage reduction for the noncore Redwood Path and noncore Baja Path rates. Accordingly, the proposal of SoCalGas and SDG&E to reduce the Schedule G-XF rates by the same percentage reduction that the noncore Redwood Path rates experience in the Gas Accord V Settlement is not adopted.

SDG&E and SoCalGas contest two other issues that are not directly addressed by the Gas Accord V Settlement. The first is whether SoCalGas should be allowed to use its capacity as a Schedule G-XF shipper on PG&E's Line 401 backbone transmission path to deliver gas into PG&E's citygate. This capacity on Line 401 is used by SoCalGas to bring in gas from Canada to supply its core customers.

SDG&E and SoCalGas contend that SoCalGas has the contractual right to deliver up to 51,932 decatherm (dth) per day into PG&E's intrastate distribution system in northern California, or to the southern terminus at Kern River Station, i.e., to the SoCalGas border. SDG&E and SoCalGas contend that this right is contained in the latest version of Exhibit A to SDG&E's Firm Transportation Service Agreement (FTSA), which was executed in November 1997 by SDG&E and PG&E, and attached to and admitted into evidence as Exhibit 21. The FTSA was originally executed on December 31, 1991 between SDG&E and PG&E.17 Pursuant to D.07-12-019, SoCalGas assumed SDG&E's right to make deliveries on PG&E's Redwood Path in April 2008. In the original Exhibit A to the FTSA, the only delivery point that was specified was to the southern terminus of the PG&E expansion project, which is located at Kern River Station. (Ex. 18, Att. 1A.)

Sometime around 2008, PG&E and SoCalGas first discussed whether the November 1997 version of Exhibit A allowed SoCalGas to deliver into PG&E's citygate. PG&E disagrees with SoCalGas' interpretation, and currently restricts SoCalGas' use of its G-XF capacity on Line 401 to transport gas from Malin, Oregon to the SoCalGas system at Kern River Station.18 SDG&E and SoCalGas contend that SoCalGas should be allowed the option to use its G-XF contract to deliver gas off-system or to the PG&E citygate. SDG&E and SoCalGas point out that oftentimes the total price of the gas coming in from Malin and transported to the SoCalGas border is higher than the total price of gas that SoCalGas can obtain at other receipt points on its system. By exercising its right under the November 1997 version of Exhibit A, SoCalGas would be able to deliver and sell natural gas into northern California using its Line 401 capacity for the benefit of SoCalGas' core customers. If SoCalGas does not use some or all of its capacity on Line 401, PG&E's shareholders could benefit by selling SoCalGas' unused capacity.

SDG&E and SoCalGas rely on the November 1997 document to support their claim that they have a contractual right to use the capacity on Line 401 to deliver into the PG&E citygate or to Kern River Station. This document shows two delivery points, one at Kern River Station, and the other "Into the PG&E Intrastate Distribution System in Northern California." SDG&E and SoCalGas contend that this November 1997 document is valid, and is the most recent version of Exhibit A to the FTSA. SDG&E and SoCalGas contend that if this latest version of Exhibit A was executed in error, PG&E did not attempt to void this document and to execute a corrected version, nor did PG&E inform SDG&E that this document mistakenly listed two delivery points instead of one.

In deciding whether SoCalGas should be allowed under its FTSA to use its capacity on Line 401 to deliver gas into the PG&E citygate, we need to examine the background and context of the Schedule G-XF contracts and the Gas Accord market structure.

There are also other competing considerations that pit the interests of PG&E's customers against the interests of the core customers of SoCalGas and SDG&E. Although SoCalGas argues that transporting Canadian gas to the SoCalGas border is no longer attractive, that has not always been the case. Also, Canadian gas provides core customers in southern California with a diversified gas portfolio. It is only recently, due to the availability of shale gas and Canadian gas economics, that SoCalGas imports more of its gas from the southwest, while reducing its imports of Canadian gas. The price dynamics for natural gas could change again when the Ruby pipeline from Wyoming to Malin, Oregon is completed. The testimony in Exhibits 20 and 23 point out that if SoCalGas is allowed to deliver gas to PG&E's citygate under its G-XF contract, that SoCalGas is likely to do so because the G-XF rate ($0.2053 per dth) is lower than the noncore Redwood rate ($0.2865 per dth). The delivery of that gas by SoCalGas into PG&E's citygate is likely to cause PG&E to suffer a revenue loss as a result of a reduction in PG&E's sales of backbone transmission capacity to northern California shippers. This in turn will cause rates to increase on PG&E's backbone transmission system for both the core and noncore unless PG&E is ordered by the Commission to absorb this loss.

SoCalGas and SDG&E agree with PG&E that the G-XF contracts were entered into as a result of the development and construction of the Line 401 expansion project, which was completed in 1993. Before the first Gas Accord market structure was agreed to in D.97-08-055, PG&E's Schedule G-XF tariff allowed delivery point flexibility. As shown under the "Delivery Points" section of the Schedule G-XF tariff which preceded the first Gas Accord decision, the tariff states in part: "Shipper may nominate any Delivery Point on the Pipeline Expansion between Malin, Oregon and Kern River Station, California." (See Ex. 18, Att. 1D.) SDG&E was made aware of this delivery point flexibility in a letter to SDG&E from PG&E in January 18, 1996. (See Ex. 18, Att. 1C.)

However, with the change in the gas market structure from a bundled gas transportation system to an unbundled transportation system, PG&E pointed out the need in A.96-08-043, the first Gas Accord proceeding, to limit the Line 401 expansion shippers to a single delivery point, instead of to multiple delivery points. (See Ex. 18 at 1-4 to 1-6.) In the original Gas Accord settlement that was approved in D.97-08-055, the revision to the Schedule G-XF tariff limiting delivery to a single delivery point was adopted.19 The revised Schedule G-XF tariff was filed with the Commission on December 1, 1997 in Advice Letter No. 2052-G, and approved by the Commission in Resolution G-3288 with an effective date of March 1, 1998. Under the "Delivery Points" section of that tariff, it was revised to state in part: "Customer may nominate only to the Delivery Point set forth in Exhibit A to the Customer's FTSA." (See Ex. 18, Att. 1E.)

Based on SDG&E's support of the Gas Accord as set forth in section 9 of the December 1996 amendment to the FTSA, SDG&E appears to have been aware of PG&E's proposal to limit G-XF shippers to a single delivery point.20 In addition, section 7 of the December 1996 amendment states:

For the period beginning on the first day of the Negotiated Period and ending on the last day of the Negotiated Period, SDG&E agrees to deliver all gas transported under this amendment off PG&E's system, using the delivery point specified in Exhibit A attached to the original FTSA. Following the Negotiated Period, SDG&E shall have a right to whatever delivery point options are available in effective CPUC-approved tariffs applicable to long-term firm Expansion service. (Emphasis added.)21

Under the interpretation of SDG&E and SoCalGas, the November 1997 version of Exhibit A had an effective date of August 1, 2003. Although the Exhibit A that SoCalGas and SDG&E rely on contains two delivery points, it is clear from various provisions in the December 1991 FTSA and in the December 1996 amendment to the FTSA that the delivery point options of SoCalGas are subject to PG&E's current G-XF tariff.22 PG&E's current Schedule G-XF tariff regarding the "Delivery Points" is unchanged from the G-XF tariff that was approved in Resolution G-3288, and states in pertinent part that "Customer may nominate only to the Delivery Point set forth in Exhibit A to the Customer's FTSA." In addition, the Gas Accord market structure, which limited delivery on Line 401 to a single delivery point, has essentially remained unchanged since this market structure was first adopted in D.97-08-055, and PG&E's Schedule G-XF with respect to the delivery point has not been revised. Also, the November 1997 version of Exhibit A did not replace or modify the operative provisions of the December 1996 amendment to the FTSA. Accordingly, we conclude that SoCalGas does not have a right to use its capacity on Line 401 to deliver into PG&E's citygate because SoCalGas' delivery point options are subject to PG&E's G-XF tariff, which limits the delivery point to a single delivery point as set forth in Exhibit A to the FTSA. Since the November 1997 version of Exhibit A is subject to PG&E's Schedule G-XF tariff, SoCalGas only has the right to deliver to Kern River Station.

Since this decision decides the delivery point issue in favor of PG&E, there is no need to address the argument of TURN, DRA, and some of the other non-PG&E settlement parties that if this issue is decided in SoCalGas' favor, that the Commission should then place the responsibility on PG&E's shareholders, and not on PG&E's customers, to bear any revenue loss associated with SoCalGas' delivery into PG&E's citygate.

The other issue that SDG&E and SoCalGas raised, which is not addressed by the Gas Accord V Settlement, is whether PG&E should be required to post on its Pipe Ranger website the same kind of gas storage information that the FERC requires of gas storage providers under its jurisdiction as set forth in section 284.13 of Title 18 of the Code of Federal Regulations. Specifically, SDG&E and SoCalGas recommend that PG&E be required to post the following:

1. Posting of all firm storage service transactions, and that these postings be made no later than the first nomination under the transaction and be accessible for a period no less than 90 days from the date of posting.

2. Posting of all interruptible storage transactions, using the same timing and duration in number 1.

3. Posting of all firm storage capacity release transactions, using the same timing and duration in number 1.

4. Index of firm storage customers, and that this be done on the first business day of each calendar quarter and be available until the next quarterly index is posted.

5. Daily design and operating storage capacity, daily available storage capacity, whether this capacity is available from storage provider or through capacity release, and daily scheduled injection and withdrawal quantities.

SDG&E and SoCalGas contend that customers shopping for SoCalGas' unbundled storage services also shop for competitive storage alternatives in northern California, including PG&E's storage services. SoCalGas posts gas storage information on its website, and according to the SoCalGas witness the information "is more extensive than what is required under FERC regulations." SDG&E and SoCalGas contend that PG&E's current posting practices falls short of the FERC posting requirements. According to SDG&E and SoCalGas, this lack of transactional information leads to imperfect and less-than-optimal pricing. Storage competitors of SoCalGas can see SoCalGas' posted prices, but SoCalGas cannot see its competitors' prices. SDG&E and SoCalGas recommend that the Commission create a more transparent market for gas storage services by requiring PG&E to use the FERC posting requirements, and that such a requirement should eventually apply to the ISPs when they apply to expand their existing gas storage capacity. SDG&E and SoCalGas contend that this market transparency will allow potential storage customers to choose or negotiate the lowest cost storage services from the different storage providers, which will increase market efficiency and produce more competitive storage prices.

PG&E contends that the FERC posting requirements should not apply to PG&E's gas storage services. PG&E contends that the northern California storage market is a competitive market without a monopoly provider, unlike the southern California storage market where SoCalGas is the only provider of gas storage services. PG&E is also concerned that it will be placed at a competitive disadvantage if the FERC posting requirements are imposed on PG&E because none of the ISPs would be subject to the same requirement. PG&E also contends that SoCalGas is not an active participant in the northern California gas storage market, and SoCalGas' storage marketing activities do not directly compete with PG&E's storage marketing.

PG&E also notes that it currently posts on a monthly basis all negotiated gas storage contracts, and provides a quarterly report of the names of its firm storage contract holders. The report on the negotiated contracts include the tariff schedule, maximum daily quantity, dates effective during the month, the rate charged, and affiliate information. PG&E also posts daily information about each storage provider's injection and withdrawal activity. PG&E does not post capacity release information because such a program is not offered. PG&E also notes that no active participant in the northern California market has approached PG&E or the Commission for the need to have PG&E post additional storage information.

Wild Goose Storage, LLC (Wild Goose Storage), and Gill Ranch Storage contend that since this GT&S proceeding focuses solely on PG&E's system, this is not the appropriate proceeding in which to consider new storage posting requirements that may apply to all storage providers in northern California. Wild Goose Storage and Gill Ranch Storage also contend that the gas storage market in northern California is competitive, and additional ISPs are seeking to enter the market. In the absence of complaints from gas storage customers and gas storage competitors, they do not believe the FERC posting requirement is needed. They also point out that SoCalGas is the monopoly provider of gas storage services in southern California. Also, SoCalGas voluntarily agreed to its storage posting requirements as part of a settlement adopted in D.07-12-019. Wild Goose Storage and Gill Ranch Storage also point to D.10-10-001 in which the Commission rejected SoCalGas' proposal to impose storage information requirements on Central Valley Gas Storage. Wild Goose Storage and Gill Ranch Storage also contend that SoCalGas' reference to other instances where the FERC or the state of Texas imposed reporting requirements are not relevant to the gas storage market in northern California.

We agree with PG&E and the two ISPs that the gas storage market in northern California is quite different from the gas storage market in southern California. In northern California, although PG&E controls a large percentage of the available gas storage, PG&E faces storage competition from several ISPs. In contrast, SoCalGas is the only provider of gas storage services in southern California, and ISPs have not filed applications as readily to offer gas storage in southern California. With the competition in northern California for gas storage customers, gas storage customers can easily compare storage prices by checking with the various ISPs as testified to by the witnesses for Wild Goose Storage and Gill Ranch Storage. In addition, PG&E is already required to post certain gas storage information on its Pipe Ranger website, from which storage customers can obtain the kind of information that SoCalGas wants to impose on PG&E. Also, although SoCalGas would like to extend the FERC posting requirements to the ISPs in the future, this proceeding is not the proper proceeding in which to raise that issue. For all those reasons, we decline to adopt the proposal of SoCalGas and SDG&E to impose the FERC gas storage posting requirements on PG&E.

In the preceding paragraphs in section 3.3.2.2, we addressed the objections of SoCalGas and SDG&E to the settlement, which included legal concerns. No other party has argued that the settlement is inconsistent with the law, nor have we found any such inconsistencies. We conclude that the Gas Accord V Settlement is consistent with the law.

The Gas Accord V Settlement must also be evaluated to determine if it is in the public interest. One element of the public interest in the Gas Accord V Settlement relates to the safety concerns that have been highlighted in recent months as a result of the San Bruno explosion. Since this proceeding covers the operations and maintenance of PG&E's GT&S facilities over the next four years, it is appropriate that we address in this decision how we can track and monitor PG&E's capital projects and O&M activities to ensure pipeline safety, integrity, and reliability over the four-year rate cycle and beyond. Also, in a subsequent safety phase decision, we will address other actions that can be taken in the near term to address other safety-related issues raised by the San Bruno explosion, such as providing fire personnel throughout PG&E's service territory with training and information about the location of PG&E's transmission pipelines and shutoff valves, and ensuring that PG&E personnel are rapidly dispatched and deployed to the site of an emergency.

Other pipeline safety issues raised by the San Bruno explosion, as well as determining the cause of the explosion, are being examined and addressed elsewhere. In addition to the investigation by the NTSB, the Commission authorized the formation of the IRP to conduct its own fact-finding investigation into the cause of the San Bruno explosion and the safety and integrity of PG&E's gas transmission lines. The IRP is also examining the Commission's operations and procedures to determine whether there were lapses in the Commission's oversight, and to make recommendations on how the Commission's processes can be improved.

The Commission has also taken a number of other steps. As described below, a separate safety phase was opened in this proceeding. In various directives, the Commission ordered PG&E: (1) to reduce the gas pressure on certain of its gas lines; (2) to undertake an integrity assessment of all of its natural gas facilities around the San Bruno area; (3) to conduct a leak survey of all of PG&E's gas transmission lines; (4) to review all gas transmission valve locations to determine where to replace manually operated valves with automated valves; (5) to search for all gas transmission records relating to pipeline system components in class 3 and class 4 locations, and in class 1 and class 2 high consequence areas that have not had a maximum allowable operating pressure established through prior hydrostatic testing, in light of the NTSB's discovery that the pipeline that exploded was not seamless as reported by PG&E; and (6) to use the traceable, verifiable, and complete records located by implementation of the NTSB's Safety Recommendation P-10-2 to determine the valid maximum allowable operating pressure (MAOP), based on the weakest section of the pipeline or component to ensure safe operation, of PG&E's gas transmission lines in class 3 and class 4 locations and in class 1 and class 2 high consequence areas that have not had a MAOP established through prior hydrostatic testing.

More recently, the Commission opened an Order Instituting Rulemaking (R.) 11-02-019, which is examining on a statewide basis whether new safety and reliability regulations should be adopted for gas pipelines, and to integrate into R.11-02-019 the work and reports of the NTSB, the IRP, and other pipeline safety and reliability initiatives that may be adopted in this proceeding. In addition, the Commission opened an Order Instituting Investigation (I.) 11-02-016 into the accuracy of the records of PG&E's gas transmission lines.

In this proceeding, one of the issues raised by the San Bruno explosion is whether the capital expenditure projects that were previously identified by PG&E's Risk Management Program as high risk were actually completed. In particular, in PG&E's prior GT&S proceeding (A.07-03-012), in which the Gas Accord IV settlement was approved, PG&E identified a 1.42 mile section of Line 132 located in South San Francisco as high risk and needing replacement. This identified section of pipe is part of the same Line 132 that exploded in San Bruno, but is located further away in South San Francisco at mile post 42.13 to 43.55. PG&E had proposed in A.07-03-012 that this high risk section be replaced as part of PG&E's capital expenditures for the three-year rate case period from 2008-2010.

The parties to A.07-03-012 agreed to the Gas Accord IV settlement, which the Commission approved in D.07-09-045. The revenue requirement agreed to in the Gas Accord IV settlement includes an allowance for capital expenditure projects. According to established rate case procedures, with a revenue requirement authorized by the Commission, the utility then has the discretion to use those allocated funds for work activities relating to capital expenditures. During the 2008 through 2010 period, PG&E reprioritized its projects, and those with higher risk assessments were undertaken. As a result of this reprioritization process, the identified section of Line 132 was not replaced by PG&E.23

PG&E's capital expenditures request in this proceeding includes work for MWC-75. Part of the work contemplated in MWC-75 for the 2011 through 2014 period is the same section of Line 132 in South San Francisco that was previously identified in A.07-03-012. (See Exhibit 10 at WP-3 and WP 6-56.)

As a result of this repeat capital expenditure request for this same section of Line 132, the assigned Commissioner and ALJ issued the September 15, 2010 ruling in which parties were asked to comment on whether the agreed-upon amounts in the Gas Accord V Settlement "provides sufficient funds to undertake a thorough safety inspection of [PG&E's] gas transmission system during the 2011-2014 period, whether [O&M] work activities and capital expenditures for transmission line projects have been adequately prioritized in terms of work activities and projects involving transmission lines in high consequence areas and with high risk assessments, and whether a mechanism is in place to ensure that these safety-related pipeline O&M work activities and capital expenditures are actually performed in 2011-2014."

As mentioned earlier, reply comments to the September 15, 2010 ruling described how the Gas Accord V Settlement provides most of the monies that PG&E had requested for O&M for pipeline integrity activities, for the capital investment requested for pipeline integrity management in MWC-98, and for the monies that PG&E had requested for pipeline safety and reliability efforts in MWC-75. PG&E and the other settlement parties also recognized that PG&E commits to spending the full amount that the Gas Accord V Settlement has set aside for pipeline integrity activities and for pipeline safety and reliability efforts, and that the one-way balancing account agreed to in section 7.3.1 of the settlement will help ensure that PG&E spends all of the designated O&M monies for pipeline integrity management activities.24

Following those comments, the revised scoping ruling was issued on October 15, 2010 which added a safety phase to this proceeding to address, among other things: "What procedures should PG&E have in place to ensure that it timely notifies the Commission of its reprioritization of its capital expenditures associated with its gas transmission lines, and what procedures should the Commission staff adopt to review and monitor the reprioritization of these capital expenditures."

PG&E's comments stated that it is committed to spending the full amount of capital that is contemplated in the Gas Accord V Settlement for pipeline integrity management and pipeline safety and reliability during the rate case period. PG&E also stated that since the conditions on its gas system are constantly changing, and to maximize the safety and reliability of its system, it must continue to have the flexibility to reassess which projects should have the highest priority. Due to PG&E's commitment to spend the full amount of funds that are allocated to pipeline safety capital programs, PG&E stated it was not necessary for the Commission to adopt procedures to monitor the capital spending prioritization process. No other parties filed any comments.

On February 3, 2011, a further ruling was issued. This ruling stated that "in the proposed decision addressing whether the motion to adopt the Gas Accord V Settlement should be granted or not, the Commission may want to impose certain reporting requirements concerning the reprioritization of capital expenditure projects, and how the funds allocated for pipeline integrity management and pipeline safety and reliability are being spent."

Although PG&E and the other settlement parties to the Gas Accord V Settlement acknowledge that the settlement provides most of the monies needed for PG&E's planned pipeline safety, reliability, and integrity efforts over the four-year rate cycle, and that PG&E is committed to spending all of the funds budgeted for these pipeline safety, reliability, and integrity projects and activities, PG&E should be required to provide a report to allow Commission staff to verify PG&E's use of these monies for their intended purpose. As noted earlier, many of these planned projects involve compliance with Subpart O, and will result in upgrading or retrofitting of transmission pipelines to accommodate inspections by a smart pig, as well as inspection of all transmission pipelines on a regularly scheduled basis. Other planned projects involve the replacement of sections of transmission pipeline that have been prioritized by PG&E as high risk, and "station reliability" capital projects. These station reliability projects consist of projects in MWC-76 and MWC-96, which are the capital costs associated with maintaining and/or improving the safety, reliability, and/or capacity of the gas compression stations and underground gas storage facilities.

Since this proceeding addresses the cost of operating and maintaining PG&E's GT&S facilities for the four-year period from 2011-2014, it is appropriate to require PG&E to take certain steps in connection with the revenue requirement associated with these facilities to ensure their safe and reliable operation. In order to track PG&E's capital expenditures for pipeline integrity under MWC-98 and pipeline safety and reliability under MWC-75, safe and reliable gas storage under MWC-76 and MWC-96, and its O&M pipeline integrity activities, we will require PG&E to provide a semi-annual "Gas Transmission and Storage Safety Report" (Safety Report) beginning October 1, 2011 to the directors of the Energy Division and the Consumer Protection and Safety Division (CPSD), and to serve a copy on the service list in this proceeding. This Safety Report shall provide the information set forth in Appendix C of this decision.

This Safety Report will provide Commission staff with the necessary details to: (1) monitor what storage and pipeline-related safety, reliability and integrity capital projects and maintenance activities are being undertaken by PG&E and the amounts spent on such activities; (2) determine whether projects which have been identified by PG&E with high risk assessments are being carried out or whether other higher risk projects have been undertaken instead; (3) determine PG&E's rationale for reprioritization of projects; and (4) to monitor the status of PG&E's compliance with Subpart O.

CPSD staff shall review these reports to monitor PG&E's storage and pipeline-related activities, to assess whether the projects which have been identified by PG&E to be high risk are being carried out, and to track whether PG&E is spending its allocated funds on these storage and pipeline-related safety, reliability, and integrity activities.

Should CPSD detect any problems with PG&E's prioritization or administration of the storage or pipeline capital projects or O&M activities, CPSD shall bring these problems to the Commission's attention immediately. The Energy Division shall provide CPSD with the necessary assistance to review and monitor these reports.

This Safety Report requirement does not end this Commission's inquiry into the safety-related issues raised by the San Bruno explosion. As mentioned earlier, a separate safety phase decision in this docket will issue shortly. This decision will address safety-related concerns involving actions which can be taken during the rate cycle period covered by this proceeding to help ensure that safe and reliable gas service will be provided to PG&E's customers in the coming years using the equipment and facilities funded by the revenue requirement authorized in today's decision. In addition, the Commission has already opened other proceedings related to the San Bruno explosion, and is awaiting the results of the NTSB and IRP reports before other proceedings arising out of the San Bruno explosion are initiated.

As a result of the safety concerns raised by the San Bruno explosion, the Gas Accord V Settlement takes on added importance as to whether the settlement is in the public interest. The public interest includes the safety concerns discussed above. Because the amount of funds that were negotiated in the settlement preserve almost all of the capital projects and O&M work activities related to pipeline safety, reliability, and integrity that PG&E finds necessary for this rate case cycle, PG&E will have sufficient funds during the rate cycle to meet the Subpart O requirements and to carry out the necessary gas transmission projects and maintenance work to ensure safe and reliable service. The public semi-annual Safety Report requirement will also provide Commission staff with the necessary tools to monitor and evaluate PG&E's administration of this gas storage and pipeline-related work. Accordingly, we conclude that the Gas Accord V Settlement is in the public interest.

Based on the agreements reached in the Gas Accord V Settlement, the original positions of the parties and the various interests that they represent, and the concerns raised by PG&E's customers, the settlement represents a negotiated compromise of many different interests. As a result of the settlement, many of the original PG&E proposals have not been incorporated into the settlement, and instead various parties have negotiated concessions and compromises on a number of different issues in order to arrive at a settlement that is acceptable to most of the parties to this proceeding. Thus, the original revenue requirement request of PG&E has been reduced from $529.1 million in 2011 to a settlement revenue requirement in 2011 of $514.2 million. DRA estimates that over the four-year rate cycle period, core customers will save about $77 million over what PG&E originally requested.

The revenue requirement agreed to in the settlement will also provide PG&E with the necessary funds to carry out its pipeline safety, reliability, and integrity capital projects and O&M activities over the rate cycle period and to meet Subpart O requirements. In addition, the Gas Accord V Settlement continues a gas market structure in northern California that has benefitted all market participants. As discussed in section 3.3.2.2, we have also heard testimony, reviewed, and rejected the concerns and legal arguments raised by SoCalGas and SDG&E on four different issues.

The agreed-upon outcomes in the Gas Accord V Settlement represent negotiated outcomes that reasonably balance the competing interests of many different parties who utilize PG&E's gas transmission and storage facilities. The agreed-upon revenue requirements also provide the funds that PG&E has determined will be needed for the activities and costs associated with operating and maintaining the GT&S infrastructure and providing safe and reliable service to customers. Based on all of the reasons discussed in today's decision, we conclude that the Gas Accord V Settlement is reasonable in light of the whole record, is consistent with the law, and is in the public interest. Accordingly, the Joint Motion to approve the Gas Accord V Settlement is granted, and the terms contained in the Gas Accord V Settlement are adopted.

The Joint Motion also requests that the non-rate pro forma tariff sheets be approved. These pro forma tariff sheets reflect the agreements reached in the Gas Accord V Settlement, and were developed in consultation with the settlement parties. The pro forma tariff sheets, which are attached to Exhibit 5 of the Joint Motion, have been reviewed for consistency with the Gas Accord V Settlement. With the exception of the concerns expressed by SoCalGas and SDG&E, which have been discussed and rejected, no one else raised any objections to these pro forma tariffs. Accordingly, the pro forma tariffs set forth in Exhibit 5 of the Joint Motion are approved and PG&E may use them as the basis for its advice letter filings to implement the adopted Gas Accord V Settlement.

Previously, the Commission in D.10-12-037 granted PG&E's request to make the revenue requirements and related elements of the Gas Accord V Settlement to be effective as of January 1, 2011, in the event the Joint Motion was granted. The purpose of that decision is to allow PG&E to make the 2011 revenue requirement effective as of January 1, 2011 and to allow PG&E to fully collect the 2011 rates over the remaining months of 2011, and to allow other time-sensitive elements of the settlement to go into effect. PG&E should be authorized to collect its 2011 revenue requirement over the remaining months of 2011.

4. Assignment of Proceeding

Timothy Alan Simon is the assigned Commissioner and John S. Wong is the assigned ALJ in this proceeding.

5. Comments on Proposed Decision

The proposed decision of ALJ John S. Wong in this matter was mailed to the parties in accordance with Section 311 of the Public Utilities Code and comments were allowed pursuant to Rule 14.3 of the Commission's Rules of Practice and Procedure. Opening comments were filed by SDG&E and SoCalGas, and PG&E, and reply comments were filed by PG&E and the Indicated Settlement Parties. Those comments have been reviewed and appropriate changes have been incorporated into the decision.

1. The Joint Motion to approve the Gas Accord V Settlement was filed on August 20, 2010, to which SDG&E and SoCalGas filed comments in opposition to the Joint Motion.

2. An evidentiary hearing on the issues raised by SDG&E and SoCalGas was held on October 25 and 26, 2010.

3. Following the San Bruno explosion, rulings were issued in this proceeding to open a safety phase.

4. D.10-12-037 granted PG&E's request to make the revenue requirements and related elements in the Gas Accord V Settlement effective as of January 1, 2011 in the event the Joint Motion is granted.

5. PG&E's application covers the costs associated with operating its GT&S system.

6. PG&E's application requested a total revenue requirement of $529.1 million for 2011; $561.5 million for 2012; $592.2 million for 2013; and $614.8 million for 2014.

7. PG&E's revenue requirement in 2010 was $461.8 million, which was based on a settlement agreed to in 2007 and approved by D.07-09-045.

8. SDG&E and SoCalGas, who did not join in the settlement, oppose two elements of the Gas Accord V Settlement, and have raised two other issues that are not directly addressed by the Gas Accord V Settlement.

9. The concerns of PG&E's customers were expressed at the public participation hearings and in e-mails and letters to the Commission.

10. The Gas Accord V Settlement addresses all of the issues associated with the operation of PG&E's GT&S facilities and services for the four-year period beginning January 1, 2011 and ending on December 31, 2014.

11. Pertinent to our analysis of the Gas Accord V Settlement are the original positions of the parties which are contained in the prepared testimony, the protests and response to PG&E's application, the comparison tables attached to the Joint Motion, the comments at the public participation hearings, the issues raised by SDG&E and SoCalGas, and the safety-related issues raised by the San Bruno explosion.

12. The Gas Accord V Settlement has been agreed to by many different parties who represent a broad range of interests in the natural gas marketplace, and extensive discovery and settlement discussions took place before the settlement was agreed to.

13. DRA estimates that the Gas Accord V Settlement will result in a savings to core customers of about $77 million over the four-year period as compared to PG&E's original position.

14. The underlying elements which make up the agreed-upon revenue requirement for 2011 have not been thoroughly examined since the 2006 to 2007 timeframe, which resulted in the test year 2008 revenue requirement that was agreed to in the Gas Accord IV settlement that was approved in D.07-09-045.

15. PG&E has experienced increasing outlays of capital that have been well above historical levels and is forecasted to continue through the rate case period.

16. PG&E's proposed capital expenditures and O&M expenses are two key drivers of the overall revenue requirement, which the settlement parties were able to negotiate reductions amounting to approximately $220 million over the four-year period.

17. The Commission recognized in D.03-12-061 that Subpart O, which was issued in December 2003, would require gas utilities such as PG&E to implement a Pipeline Integrity Management Program, which requires gas utilities to assess, inspect and manage the integrity of all gas transmission lines located in a HCA.

18. Since the Joint Motion to approve the Gas Accord V Settlement was filed shortly before the San Bruno explosion, a ruling was issued asking parties to comment on whether the settlement provides the necessary funds for PG&E to carry out the capital expenditures and O&M activities that are required by Subpart O and related regulations.

19. In response to the ruling, the settlement parties commented that the Gas Accord V Settlement provides 92% of the monies that PG&E had requested for O&M pipeline integrity, 100% of the capital investment requested for pipeline integrity management in MWC-98, and to 98% of the monies that PG&E had requested for pipeline safety and reliability efforts in MWC-75.

20. The demand or throughput forecast is an important element for cost allocation and ratemaking purposes, and generally speaking, a larger throughput amount will result in more volume over which to spread the cost of providing a particular service.

21. The throughput forecasts in the Gas Accord V Settlement are higher than what PG&E had forecasted, except for the Silverado path.

22. The load factors agreed to in the Gas Accord V Settlement are the result of negotiations over the appropriate calculation methodology and inputs to use.

23. The non-PG&E settlement parties support the cost allocation of the Line 57C project costs because the amount that core storage and load balancing will pay reflects the reliability benefits they receive, and the amount that Market Storage will pay reflects the reliability benefits and increased Market Storage capacity that it receives.

24. The settlement agreed to rolled-in rate treatment for the additional McDonald Island compressors, which results in a lower allocation of costs to core storage and load balancing than under an incremental rate treatment.

25. The rate treatment in the settlement of PG&E's 25% share of the Gill Ranch Storage filed is consistent with the Commission's and PG&E's commitment to shield core ratepayers from the costs of that project.

26. The agreed-upon revenue sharing mechanism in the settlement provides significant ratepayer benefits through the $30 million annual seed amount, as well as the enhanced sharing of over- and under- collections.

27. The issues that the CTAs raised were addressed in the CTA Settlement, which is part of the Gas Accord V Settlement.

28. Other operational concerns about PG&E's GT&S system were raised by the settlement parties and were addressed or resolved by the Gas Accord V Settlement.

29. The original positions and concerns of PG&E and other market participants compared to the Gas Accord V Settlement demonstrate that the settlement parties have negotiated a number of different issues and have been able to reach agreed-upon resolutions.

30. The revenue sharing mechanism agreed to in the Gas Accord V Settlement excludes Schedule G-XF customers from being allocated any of the $30 million in annual seed money to fund this mechanism.

31. There is a well-documented history of how PG&E's Schedule G-XF customers have been responsible for the incremental costs of PG&E's Line 401 expansion project, and the rate design methodology for G-XF rates has remained unchanged since Line 401 was first authorized.

32. There is a clear separation between how the G-XF rate is designed, and how the rates for PG&E's backbone transmission and local transmission are designed, and the latter rates are affected by various inputs that have nothing to do with the Line 401 costs.

33. The reduction in the noncore Redwood Path and noncore Baja Path rates, as compared to PG&E's application and as agreed to in the Gas Accord V Settlement, are the result of a number of different factors that the settlement parties negotiated and which affect the inputs that generate the rates for the noncore Redwood Path and noncore Baja Path.

34. The SoCalGas' witness acknowledged that the G-XF rate is not impacted by every element that goes into the calculation of other rates, such as system throughput.

35. The rate design differences between G-XF rates and other noncore transmission rates result in a greater percentage reduction in the settlement for the noncore Redwood Path and noncore Baja Path rates as compared to the G-XF rate.

36. If SoCalGas is allowed to use its G-XF capacity to deliver gas into the PG&E citygate, PG&E is likely to suffer a revenue loss as a result of a reduction in sales of backbone transmission capacity to northern California shippers, which in turn will cause rates to increase on PG&E's backbone transmission system for both the core and noncore unless PG&E is ordered to absorb this loss.

37. Before the first Gas Accord market structure was agreed to in D.97-08-055, PG&E's Schedule G-XF tariff allowed delivery point flexibility.

38. With the change in the gas market structure from a bundled gas transportation system to an unbundled system, PG&E pointed out the need in A.96-08-043 to limit Line 401 expansion shippers to a single delivery point, instead of to multiple delivery points.

39. The quote in Exhibit 18 at 1-6, which is cited in footnote 20 of this decision, supports the argument that the Gas Accord market structure restricted delivery point flexibility.

40. Although the Exhibit A that SoCalGas and SDG&E rely on contains two delivery points, it is clear from various provisions in the December 1991 FTSA and the December 1996 amendment to the FTSA that the delivery point options of SoCalGas are subject to PG&E's current G-XF tariff.

41. PG&E's current Schedule G-XF tariff regarding the "Delivery Points" is unchanged from the G-XF tariff that was approved in Resolution G-3288, and states that "Customer may nominate only to the Delivery Point set forth in Exhibit A to the Customer's FTSA."

42. Although PG&E controls a large percentage of available gas storage in northern California, PG&E faces storage competition from several ISPs, and potential storage customers can easily compare storage prices by checking with the ISPs.

43. SoCalGas is the only provider of gas storage in southern California, and ISPs have not filed applications as readily to offer gas storage in southern California.

44. PG&E is already required to post certain gas storage information on its Pipe Ranger website.

45. One element of the public interest in the Gas Accord V Settlement relates to the safety concerns that have been highlighted as a result of the San Bruno explosion.

46. One of the issues raised by the San Bruno explosion is whether the capital expenditure projects that were previously identified by PG&E as high risk were actually completed, or whether other higher priority projects were built instead.

47. In response to the September 15, 2010 ruling, PG&E and the other settlement parties recognize that PG&E has committed to spending the full amount that the Gas Accord V Settlement has set aside for pipeline integrity activities and for pipeline safety and reliability efforts, and that the one-way balancing account agreed to in section 7.3.1 of the settlement will help ensure that PG&E spends all of the designated O&M monies for pipeline integrity management activities.

48. The Safety Report will provide the Commission staff with the information it needs to verify PG&E's use of the monies for their intended purpose, and to detect any problems with PG&E's prioritization or administration of its storage or pipeline capital projects or O&M activities.

49. The amount of funds that were negotiated in the settlement to preserve almost all of the capital projects and O&M work activities related to pipeline safety, reliability, and integrity provides assurance that PG&E will have sufficient funds during the rate cycle to meet the Subpart O requirements and to carry out the necessary projects and maintenance work to ensure safe and reliable service.

50. The pro forma tariff sheets reflect the agreements reached in the Gas Accord V Settlement, and were developed in consultation with the settlement parties.

1. In deciding whether the Joint Motion should be granted or not, we examine whether the settlement is reasonable in light of the whole record, consistent with the law, and in the public interest.

2. The exclusion of G-XF shippers from participating in the revenue sharing mechanism is not arbitrary, unreasonable, or discriminatory, and the request of SoCalGas and SDG&E to revise this part of the settlement to allow G-XF customers to participate in this mechanism is not adopted.

3. The proposal of SoCalGas and SDG&E to reduce the Schedule G-XF rates by the same percentage reduction that the noncore Redwood Path rates experience in the Gas Accord V Settlement is not adopted.

4. SoCalGas does not have a right to use its capacity on Line 401 to deliver into PG&E's citygate because SoCalGas' delivery point options are subject to PG&E's G-XF tariff, which limits the delivery point to a single delivery point as set forth in Exhibit A to the FTSA.

5. This proceeding is not the proper proceeding in which to lay the groundwork for storage posting requirements that could apply to all the ISPs in the future.

6. The proposal of SoCalGas and SDG&E to impose the FERC gas storage posting requirements on PG&E is not adopted.

7. Beginning October 1, 2011, PG&E should be required to provide the semi-annual Safety Report, which contains the information set forth in Appendix C of this decision, to the directors of the Energy Division and CPSD, and to the service list in this proceeding.

8. CPSD shall review the Safety Reports to monitor PG&E's storage and pipeline-related activities, to assess whether the projects which have been identified as PG&E to be high risk are being carried out, and to track whether PG&E is spending its allocated funds on these storage and pipeline-related safety, reliability, and integrity activities.

9. Should CPSD detect any problems with PG&E's prioritization or administration of the storage or pipeline capital projects or O&M activities, CPSD should bring the problems to the Commission's attention immediately.

10. The Gas Accord V Settlement is reasonable in light of the whole record, is consistent with the law, and is in the public interest.

11. The Joint Motion to approve the Gas Accord V Settlement is granted, and the terms contained in the Gas Accord V Settlement are adopted.

12. The pro forma tariffs set forth in Exhibit 5 of the Joint Motion are approved, and PG&E may them as the basis for its advice letter filings to implement the Gas Accord V Settlement.

13. Pursuant to D.10-12-037, PG&E should be authorized to collect its 2011 revenue requirement over the remaining months of 2011.

ORDER

IT IS ORDERED that:

1. The August 20, 2010 "Joint Motion of Settlement Parties for Approval of `Gas Accord V' Settlement" is granted, and the terms contained in the Gas Accord V Settlement Agreement, which is attached to this decision as Appendix A, are adopted.

2. The pro forma tariff sheets set forth in Exhibit 5 of the Joint Motion of Settlement Parties for Approval of "Gas Accord V" Settlement are approved, and Pacific Gas and Electric Company may use them as the basis for its advice letter filings to implement the approved and adopted Gas Accord V Settlement Agreement.

3. Within 30 days from today's date, Pacific Gas and Electric Company (PG&E) must file the necessary advice letters with the Energy Division under Tier 1 of General Order 96-B to implement and carry out the terms of the Gas Accord V Settlement Agreement, and to present the necessary tariff revisions.

4. Pursuant to Decision 10-12-037, Pacific Gas and Electric Company is authorized to collect its 2011 revenue requirement over the remaining months of 2011.

5. Pacific Gas and Electric Company (PG&E) must prepare on a semi-annual basis a "Gas Transmission and Storage Safety Report" (Safety Report) containing the information set forth in Appendix C to this decision and as described in this decision.

a. PG&E must serve the first Safety Report on October 1, 2011 on the directors of the Commission's Consumer Protection and Safety Division and the Energy Division, and to the service list in this proceeding, and PG&E must continue to serve semi-annual Safety Reports as set forth in Appendix C.

6. The Commission's Consumer Protection and Safety Division (CPSD) must review the Gas Transmission and Storage Safety Reports, and establish the necessary procedures to monitor Pacific Gas and Electric Company's (PG&E) storage and pipeline-related activities set forth in the reports, to assess whether the projects which PG&E identified in this proceeding as high risk are being carried out, and to track whether PG&E is spending its allocated funds on the storage and pipeline-related safety, reliability, and integrity activities.

a. Should CPSD detect any problems with PG&E's prioritization or administration of the storage or pipeline capital projects or O&M activities, CPSD must bring the problems to the Commission's attention immediately.

b. The Energy Division must provide CPSD with the necessary assistance to review and monitor these reports.

7. This proceeding remains open to address other issues raised in the safety phase.

This order is effective today.

Dated ___________________________, at San Francisco, California.

1 PG&E uses a Risk Management Program to assess the risk of every segment of gas transmission line within its system. Part of the formula for developing the risks associated with different pipeline segments are the physical characteristics of the pipe, such as when the pipe was installed, pipeline condition and inspection reports, method of construction, and other traits. In addition, the formula considers location factors such as population density, structures nears the pipeline, and environmental conditions. Using its formula, risk numbers are then developed for each segment of the transmission line. These risk numbers are then issued to identify, quantify, and prioritize the work for high risk pipeline segments. This work could consist of inspection by a smart pig, pipeline replacement, pipeline relocation, or other risk mitigation techniques.

2 Through other motions and rulings, the evidentiary hearings were reset three different times, and evidentiary hearings were held on October 25-26, 2010.

3 A.09-12-020 addressed PG&E's revenue requirement for the costs of providing its electric generation and electric distribution services, and its natural gas distribution service.

4 The settlement parties are as follows: PG&E; ABAG Publicly Owned Energy Resources (ABAG Power); California Cogeneration Council; California Manufacturers & Technology Association; Calpine Corporation; Canadian Association of Petroleum Producers; City of Palo Alto; Commercial Energy; Division of Ratepayer Advocates (DRA); Dynegy Moss Landing, LLC and Dynegy Morro Bay, LLC; El Paso Corporation; Gas Transmission Northwest Corporation; Gill Ranch Storage, LLC; Indicated Producers; Lodi Gas Storage LLC; Mirant California, LLC and Mirant Delta, LLC; Northern California Generation Coalition; Sacramento Municipal Utility District; School Project for Utility Rate Reduction; Southern California Generation Coalition; Spark Energy; The Utility Reform Network (TURN); Tiger Natural Gas Inc.; Vista Energy Marketing L.P.; and Wild Goose Storage, LLC.

5 The term "Gas Accord" refers to the establishment and settlement of the gas market regulatory structure for PG&E's GT&S facilities and services that started with Decision (D.) 97-08-055 [73 CPUC2d 754], and except for 2004 (D.03-12-061), was followed by subsequent settlements in D.02-08-070, D.04-12-50, and D.07-09-045. This gas market structure is characterized by the unbundled GT&S service offerings for non-core customers.

6 The revenue requirement associated with PG&E's gas distribution facilities is handled in PG&E's GRC proceeding (A.09-12-020), and the cost allocation of PG&E's gas distribution facilities is addressed in its cost allocation proceeding which was most recently addressed in D.10-06-035.

7 The fourth gas storage facility is the Gill Ranch Storage, LLC (Gill Ranch Storage) field, in which PG&E owns a 25% interest.

8 We have attached the CTA Settlement to this decision as Appendix B. The signature pages, the comparison tables, and the pro forma tariffs are not attached to this decision, but are attached as exhibits to the August 20, 2010 Joint Motion for approval of the Gas Accord V Settlement, and are incorporated by reference.

9 These four public entities are members of the Northern California Generation Coalition.

10 For storage, the settlement provides that PG&E is to be at risk for 100% of a net undercollection.

11 MWCs are used by PG&E to consolidate and categorize capital expenditures by asset and work activities. The capital expenditures proposed by PG&E are covered by 12 different MWCs, and are described in detail in Chapter 6 of Exhibit 1, and in section 7.2 of the Gas Accord V Settlement.

12 The Commission recognized in D.03-12-061 that PG&E would begin incurring costs as this federal program began, and that these expenses would increase in the coming years as more inspections of PG&E's pipelines are required. The revenue requirements that were authorized for PG&E in D.04-12-050 and D.07-09-045 included the costs of meeting these program requirements.

13 According to its testimony, "To date, PG&E has met all requirements of the Pipeline Integrity Management regulations and is on schedule to meet future requirements." (Ex. 1 at 5-11.)

14 Although PG&E preferred the use of forecasted demands, PG&E's testimony also included the development of system average load factors in Chapter 11B of Exhibit 1.

15 Section 3.3.2.3 of this decision explains why the Gas Accord V Settlement is in the public interest from a safety and reliability perspective, and that the subsequent safety phase decision will address other pipeline safety measures to be taken over the four-year rate cycle.

16 Although the first Gas Accord adopted a partial roll-in of the costs of Line 400 and Line 401, that roll-in did not apply to the G-XF shippers serving southern California.

17 At the time the FTSA was entered into, the G-XF service was provided under PG&E's Schedule XT-1. In March 1994, SDG&E and PG&E executed a Pipeline Expansion Transportation Service Agreement, which allowed PG&E to transport gas for SDG&E on Line 401 until the December 1991 FTSA was approved by the Commission. Exhibit A to the March 1994 agreement specified the delivery point to Kern River Station. (See Ex. 18, Att. 1B.) Subsequently, an amendment to the FTSA was agreed to in December 1996, but this amendment did not change the Exhibit A attached to the December 31, 1991 FTSA. Section 9 of the December 1996 amendment provides that SDG&E agrees to "actively support PG&E's Gas Accord before the CPUC." (See Ex. 18, Att. 1F.)

18 PG&E contends that the November 1997 Exhibit A was generated as the result of a request by SDG&E to assign a portion of its expansion capacity to Husky Oil and Gas Marketing, Inc. (Husky) for a limited term, and at the end of the term, all of the capacity would revert to SDG&E. When this Exhibit A was revised, PG&E contends that a clerical error resulted in two delivery points instead of a single delivery point to Kern River Station. PG&E contends that at no time did SDG&E or Husky request an additional delivery point, nor did PG&E state it was agreeing to an additional delivery point.

19 In section II.B.1 of the first Gas Accord settlement for "G-XF Firm Service," it states "Delivery point as set forth in Exhibit A to each firm contract." (73 CPUC2d at 804.)

20 PG&E's testimony in Exhibit 18 at 1-6 quotes from the motion to adopt the original Gas Accord settlement in A.96-08-043 to support its argument that the Schedule G-XF tariff would be modified. The quote states in part that "Since at least 1991, two years before the commercial operation of the [Line 401] Expansion, PG&E has clearly stated to firm Expansion shippers that delivery-point flexibility would not be permitted if it created a revenue shortfall for PG&E." Section 9 of the December 1996 amendment to the FTSA states in part that "SDG&E agrees to ... actively support PG&E's Gas Accord before the CPUC." (Ex. 18, Att. 1F.)

21 The Negotiated Period under the December 1996 amendment began "on the date the CPUC approves this amendment and shall continue until the later of (a) five years from the date or (b) the end of the Gas Accord period, as approved by the CPUC."

22 For example, section 7.10 of the FTSA provides that the FTSA is "subject to the applicable provisions of PG&E's Rate Schedule XT-1, or superseding rate schedule(s) and [PG&E's] General Terms and Conditions," and "in the event of a conflict or ambiguity between this Agreement and PG&E's Rate Schedule XT-1 or PG&E's General Terms and Conditions applicable for service provided Shippers, the terms of this Agreement shall govern. Section 7 of the December 1996 amendment provides in part that "Following the Negotiated Period, SDG&E shall have a right to whatever delivery point options are available in effective CPUC-approved tariffs applicable to long-term firm Expansion service. (Also see Exhibit 18 at 1-5, and 12 R.T. 1191, lines 8-20.)

23 This proceeding does not address the reasonableness of PG&E's conduct in not pursuing that particular pipeline replacement project earlier.

24 We also note that in R.11-02-019, the Commission is examining whether additional expenditures are needed for pipeline safety and how ratemaking policies, practices, and incentives can be better aligned to reflect and to ensure safe and reliable gas service.

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