4. The Settlement Agreement

The Settlement Agreement is attached to this decision as Attachment 1. The Settling Parties state that the principal public interest affected by this GRC is delivery of safe, reliable electric and gas service at reasonable rates, asserting that the Settlement Agreement advances this interest because it sets forth a compromise that significantly reduces the revenue requirement sought by PG&E while providing PG&E a test year revenue requirement increase and predictable attrition allowance, albeit at a lower level than PG&E sought. The Settling Parties further assert that, taken as a whole, the Settlement Agreement is reasonable in light of the entire record, consistent with law, and in the public interest and request that it be approved.

4.1. The Settling Parties

The Settling Parties include PG&E; DRA; TURN; Aglet; California
City-County Street Light Association (CAL-SLA); California Farm Bureau Federation (CFBF); Coalition of California Utility Employees (CCUE); Consumer Federation of California (CFC); Direct Access Customer Coalition (DACC); Disability Rights Advocates (DisabRA);⁴ Energy Producers and Users Coalition (EPUC); Engineers and Scientists of California, Local 20 (ESC); Merced Irrigation District (Merced ID);⁵ Modesto Irrigation District (Modesto ID);⁶ South San Joaquin Irrigation District (SSJID); Western Power Trading Forum (WPTF); and Women's Energy Matters (WEM).

The Settling Parties represent a variety of interests other than that of the Applicant. For example, DRA, TURN, Aglet, CFC, and others represent
wide-spread interests of consumers of gas and electricity, including low-income consumers. CAL-SLA represents the interests of street light customers. CCUE represents the interests of represented utility employees at PG&E and most electric utilities in California. CFBF represents the interests of agricultural customers. DACC represents the interests of direct access customers. DisabRA represents the interests of the disabled. EPUC represents the interests of larger industrial customers. ESC represents the interests of the engineers, scientists, and other professional and technical employees of PG&E. Merced ID, Modesto ID, and SSJID represent the interests of irrigation districts. WPTF represents the interests of its membership in encouraging competition in Western states electric markets. Finally, WEM represents women and men working for a rapid transition to an efficient, renewable energy system.

4.2. Non-Settling Parties

This is not an all party settlement. Active parties that did not join in the Settlement Agreement include SCE, the Greenlining Institute (Greenlining), and the City and County of San Francisco (CCSF). SCE submitted the testimony of one witness, while Greenlining submitted testimony of two witnesses. Also, CCSF participated in this proceeding through the cross examination of a number of witnesses during evidentiary hearings. Neither SCE, nor Greenling, nor CCSF filed comments on the proposed settlement.

4.3. The Settling Parties' Litigation Positions

4.3.1. PG&E's Position

At the end of hearings, and as reflected in the Joint Comparison Exhibit,⁷ PG&E's litigation position would result in base revenue requirements of
$3,534 million for electric distribution, $1,293 million for gas distribution, and $1,820 million for electric generation, resulting in increases over currently authorized revenues of $527 million for electric distribution, $208 million for gas distribution, and $329 million for electric generation. In addition, adoption of PG&E's litigation position would result in attrition increases of $181 million in 2012 and $223 million in 2013 for electric distribution, $49 million in 2012 and
$64 million in 2013 for gas distribution, and $33 million in 2012 and $47 million in 2013 for electric generation.

4.3.2. DRA's Position

At the end of hearings, and as reflected in the Joint Comparison Exhibit, DRA's litigation position recommended a total 2011 revenue requirement of $3,151 million for electric distribution, $1,072 million for gas distribution, and $1,540 million for electric generation, resulting in an increase of $144 million, a decrease of $12 million, and an increase of $49 million, respectively, over currently authorized electric and gas distribution and generation-related revenues.

Regarding attrition, adoption of DRA's litigation position would permit PG&E to file an advice letter seeking attrition relief that DRA estimated would result in increases of $63 million and $58 million for electric distribution in 2012 and 2013, respectively; $21 million and $20 million for gas distribution in 2012 and 2013, respectively; and $31 million and $28 million for electric generation in 2012 and 2013, respectively.

DRA's litigation position reflects significant decreases to PG&E's forecast Administrative and General (A&G) expenses; electric and gas distribution Operations and Maintenance (O&M) expenses; electric generation expenses; Customer Accounts expenses; Information Technology (IT) and other Shared Services costs; income tax expenses; electric, gas, and common plant; depreciation; and rate base; as well as increases to Other Operating Revenues.

4.3.3. TURN's Position

TURN made a number of recommendations, including reducing overall A&G spending, rejecting ratepayer funding of the Short Term Incentive Plan (STIP), reducing Customer Care costs, excluding SmartMeter costs from the GRC, reducing electric and gas distribution capital and expense items, reducing electric generation capital and expense items and adopting policies to limit capital spending to new hydro projects that are cost-effective, suspending accrual of Allowance for Funds Used During Construction (AFUDC) for ten Business Transformation software projects (called "Transform Operations"), reducing depreciation and rate base for numerous items, reducing electric and gas revenue requirements and various tax expenses for specific tax adjustments, rejecting or reducing funding for numerous real estate projects and activities, requiring PG&E to move toward vehicle leasing rather than ownership, writing off gross plant for the IT Business Transformation Foundational Project, reducing overall IT spending, rejecting certain political costs, reducing supply chain capital and expenses, and adopting DRA's proposed forecast for electric emergency recovery.

4.3.4. Aglet's Position

Aglet made several proposals, including generally contesting PG&E's policy arguments regarding industry leadership, customer satisfaction, financial health, and economic impact of capital spending; reducing PG&E's Reserve Fund and Efficiency Fund; reducing PG&E's Customer Care expenses to reflect SmartMeter benefits; recommending that all SmartMeter costs be removed from the GRC, and recommending that PG&E file an application for review of the reasonableness of all SmartMeter costs; adopting an uncollectibles factor of 0.2853%; denying PG&E's entire request for customer retention and economic development activities; reducing PG&E's request and ordering specific compliance items for Diablo Canyon Power Plant expense and capital items; ordering that total factor productivity studies should no longer be required; recommending that labor productivity factors be incorporated into PG&E's 2011 revenue requirements calculation; rejecting PG&E's requests for new balancing accounts; reducing PG&E's requested attrition adjustments for 2012 and 2013; finding that Z-factor protection should be limited to five specific costs; and reducing PG&E's IT request and recommending an investigation into PG&E's procurement of IT products and services.

4.3.5. CAL-SLA's Position

CAL-SLA recommended that the Commission not approve PG&E's proposed streetlight light emitting diode (LED) conversion program; and that the Commission reduce PG&E's request for streetlight rate base, O&M expenses, and expenses for burnouts and group replacements.

4.3.6. CFBF's Position

CFBF generally supported DRA's recommendations but proposed to increase DRA's distribution maintenance expense recommendation by
$71 million.

4.3.7. CCUE's Position

CCUE recommended that PG&E should be authorized and required to do more pole replacement work than PG&E requested funding for, be required to do all gas leak survey and repair work needed even if it is more work than PG&E sought funding for, attain and maintain staffing levels sufficient to perform all needed gas work, hire a steady flow of new apprentices for electric distribution work and maintain an apprentice to journeyman ratio of 1:2, be required to achieve the goals of the 2008 Equipment Requiring Repair Report and to work off the equipment requiring repair backlog by the end of 2011, and be required to reduce the backlog of items tagged out of compliance with Commission regulations. CCUE proposed enforcement mechanisms, such as balancing accounts and contempt proceedings, to ensure PG&E performs this work. CCUE also recommended that the Commission not rely on the Total Compensation Study.

4.3.8. CFC's Position

CFC recommended that PG&E should postpone charging costs of new programs that are not essential or not well-developed; should use a different base year than 2008; should not receive funding for Distribution and Integrity Management Program (DIMP), Technical Training, or LED streetlight replacement; should be required to use a standard forecasting model to predict future costs; should reduce labor escalation and attrition adjustments; should quantify cost savings for various programs; should be required to use Federal Energy Regulatory Commission accounts to record costs; should not be permitted to have balancing accounts for Rule 20A, major emergencies, healthcare, research development and demonstration (RD&D), renewable generation, or uncollectible accounts expense; should not contribute to the revitalization of the California economy; should not monopolize the provision of recharging or filling stations; should have its SmartMeter and SmartGrid funding reduced; should be audited regarding its Proposition 16 spending; and should not receive funding for RD&D or the transfer of PG&E Corporation employees to the Utility.

4.3.9. DACC's Position

DACC recommended that electric RD&D generation project costs be tracked separately from distribution and that results of PG&E's electric RD&D be placed in the public domain. DACC also supported the conditional adoption of PG&E's proposal for revised Direct Access (DA) fees, subject to review in a future proceeding.

4.3.10. DisabRA's Position

In lieu of providing independent testimony in the GRC, DisabRA negotiated a Memorandum of Understanding with PG&E regarding improved access: to PG&E's local offices and pay stations, around construction sites and pole locations, and to PG&E's communications materials (including written communications, telecommunications, communications with medical baseline customers, and bill design) and website. It also sets forth procedural requirements including reporting and a dispute resolution process. On May 26, 2010, DisabRA and PG&E jointly submitted this Memoranda of Understanding (MOU) as part of Exhibit PG&E-16.

4.3.11. EPUC's Position

EPUC recommended that the Commission reduce PG&E's proposed hydroelectric capital expenditures; retain the current authorization for recovery of carrying costs of nuclear fuel inventory and reject PG&E's proposal to include $378 million in rate base; and reject PG&E's requests for a 1% increase in rate of return for decommissioning Kilarc-Cow, to recover abandonment costs, and to hold Tesla Power Plant Costs in Plant Held for Future Use (PHFU).

4.3.12. ESC's Position

ESC recommended that all typical technical and professional work be performed by PG&E employees, not contractors, with certain exceptions; that PG&E monitor and evaluate the performance of contracts and report to the Commission; and that PG&E work with its employee unions to develop a workforce plan to address projected workload, employee attrition, and knowledge transfer.

4.3.13. Merced ID and Modesto ID Position

Merced ID and Modesto ID recommended that the Commission deny PG&E's entire request for customer retention activities; require PG&E to reimburse ratepayers for amounts spent on customer retention activities from 2007 to 2011; enjoin PG&E from spending further ratepayer funds on customer retention activities; and require PG&E to equitably allocate expenses for distribution projects among distribution planning areas.

4.3.14. SSJID's Position

SSJID recommended that the Commission maintain PG&E's distribution capital expenditures at 2008 levels; disallow 54.375% of PG&E's STIP funding, set up a one-way balancing account, reduce the STIP payout to 50% of the maximum potential payout, and redesign STIP targets; disallow all holding company costs; examine PG&E's below-the-line (BTL) guidelines and reduce funding for departments that engage in BTL activities; deny funding for customer retention activities; disallow any RD&D funding; disregard PG&E's claims regarding economic stimulus; and change the ratemaking treatment of PG&E's income tax expense for this and future PG&E GRCs.

4.3.15. WPTF's Position

WPTF recommended rejection of PG&E's request for recovery of costs associated with the Tesla Power Plant and PG&E's request for recovery of up to $27 million in renewable energy development costs in a one-way balancing account.

4.3.16. WEM's Position

WEM recommended reductions to electric distribution, Customer Care, SmartMeter, Energy Supply, and A&G funding; proposed enhanced procedures and an audit for BTL activities; recommended that PG&E provide specific information to assist renewable projects to interconnect to its distribution system; recommended procedures to better ensure attention to distribution system maintenance, including in the territories of Community Choice Aggregators; and recommended imposing automatic penalties if PG&E continues to fund customer retention and economic development activities.

4.4. The Non-Settling Parties' Litigation Positions

4.4.1. Greenlining

In its testimony, Greenlining opposed PG&E's executive compensation bonus system, opposed PG&E's use of the Global Insight Study as support for its capital spending proposals; supported PG&E's proposal to increase and improve supplier diversity and inclusion; and opposed the level of PG&E's requested Economic Development Program expenses.

4.4.2. SCE

SCE presented rebuttal testimony that opposed DRA's proposal to set PG&E's AFUDC rate at a short-term debt rate, Aglet's comments on the Global Insight Study proposal of the economic impacts of PG&E's capital expenditure program, and certain Aglet comments on productivity.

4.4.3. CCSF

CCSF did not serve prepared testimony, but conducted cross examination in such areas as quality of service, above and below-the-line customer engagement activities, reprioritization of customer care expenses, SmartMeter deployment, community choice aggregation (CCA) fees, and customer satisfaction.

4.5. Terms of the Settlement Agreement

The Settlement Agreement is included as Attachment 1 to this decision. The related results of operation tables are included as Attachment 2. Key terms of the Settlement Agreement include:

· A revenue requirement increase in 2011 amounting to
$183 million (6.1%) for electric distribution, $47 million (4.3%) for gas distribution, and $166 million (11.1%) for electric generation. This is in contrast to PG&E's request of $527 million (17.5%) for electric distribution, $208 million (19.2%) for gas distribution, and $329 million (22.1%) for electric generation.

· A further revenue requirement increase in 2012 amounting to
$123 million (3.9%) for electric distribution, $35 million (3.1%) for gas distribution, and $22 million (1.3%) for electric generation. This is in contrast to PG&E's request of $181 million (5.1%) for electric distribution, $49 million (3.8%) for gas distribution, and $33 million (1.8%) for electric generation.

· A further revenue requirement increase in 2013 amounting to
$123 million (3.7%) for electric distribution, $35 million (3.0%) for gas distribution, and $27 million (1.6%) for electric generation. This is in contrast to PG&E's request of $222 million (6.0%) for electric distribution, $64 million (4.8%) for gas distribution, and $33 million (1.8%) for electric generation.

· A reduction of $44 million (revenue requirement) to reflect TURN's position to allow no rate of return on undepreciated electric and gas meters replaced by SmartMeter devices. The parties agreed to brief this dispute for the Commission's decision in this proceeding. If PG&E prevails on the issue, the test year revenue requirement will be increased accordingly, effective January 1, 2011.

As detailed in the Settlement Agreement, the Settling Parties resolved a number of specific issues in reaching agreement on these revenue requirement increase amounts and levels. However, the resolution of many cost issues raised during this proceeding is considered subsumed in the overall settled revenue requirement amounts for the various segments of PG&E's operations such as electric distribution, gas distribution, energy supply, customer care, A&G expenses, shared services, depreciation, and capital-related costs. Also, the Settlement Agreement provides direction and guidance with respect to cost recovery, future GRC, and other filing requirements; customer service; accounting and accounting mechanisms; an audit of SmartMeter costs; and modification of the results of operations model for use in PG&E's next GRC.

4.6. Standard of Review

We have reviewed settlements as far back as at least 1988.⁸ In doing so, we have often acknowledged California's strong public policy favoring settlements. This policy supports many worthwhile goals, such as reducing litigation expenses, conserving scarce resources of parties and the Commission, and allowing parties to reduce the risk that litigation will produce unacceptable results.

In assessing settlements we consider individual settlement provisions but, in light of strong public policy favoring settlements, we do not base our conclusion on whether any single provision is the optimal result. Rather, we determine whether the settlement as a whole produces a just and reasonable outcome.

We have specific rules regarding approval of settlements:

"The Commission will not approve stipulations or settlements whether contested or uncontested, unless the stipulation or settlement is reasonable in light of the whole record, consistent with law, and in the public interest."⁹

4.7. Discussion

We have reviewed the Settlement Agreement, and, as discussed below, conclude that it is consistent with law, reasonable in light of the whole record, and in the public interest. However, as also discussed, certain requirements will be imposed on PG&E with respect to reprioritization and deferral of costs.

4.7.1. Consistency with Law

The Settlement Agreement is consistent with law. We do not detect, and it has not been alleged, that any element of the Settlement is inconsistent in any way with Public Utilities Code Sections, Commission decisions, or the law in general.

Regarding the process for developing the Settlement, the Settling Parties note that Rule 12.1(a) provides that parties may propose settlements for adoption within 30 days after the last day of hearings. Evidentiary hearings were completed on July 22, 2010, and on August 4, 2010, PG&E, DRA, TURN and Aglet advised the ALJ and all parties that they were currently engaged in settlement discussions, which led to a variety of rulings postponing the procedural schedule for the matter. To the extent that Rule 12.1(a) pertains to the matter at hand, the Settling Parties ask that the 30-day limit be extended or waived. The Settling Parties indicate that they have devoted substantial time and effort to achieving this Settlement Agreement. Furthermore, the Settling Parties state that because the Settlement Agreement leaves only one issue unresolved, its consideration and adoption will promote the "just, speedy, and inexpensive determination of the issues presented." (Rule 1.2.)

We agree with the Settling Parties. While the development of the Settlement Agreement extended beyond the time allowed by the rules, it has significantly reduced the time and expense associated with Commission's deliberation of a fully litigated case. The 30-day limit is waived. In all other respects the process used by the Settling Parties in developing the Settlement Agreement, conducting settlement conferences, and filing the motion to adopt the Settlement Agreement are consistent with the Commission's Rules.

4.7.2. Reasonableness in Light of the Whole Record

PG&E's request has been sufficiently scrutinized through the direct testimony, rebuttal testimony and evidentiary hearing processes. As described above, in this proceeding, there were 20 active parties with diverse interests. The evidentiary record is substantial, consisting of 415 exhibits, including the testimony of 120 witnesses, as well as 2,911 pages of evidentiary hearing transcripts. The Joint Comparison Exhibit, which portrays parties' positions after evidentiary hearings were concluded, details hundreds of issues raised during the proceeding.

The following table compares the DRA and PG&E positions at the time of the Joint Comparison Exhibit with the Settlement Agreement proposal on a total GRC basis (electric and gas distribution and electric generation).

As shown, for the recommended test year 2011 revenue requirement level, the difference between PG&E and DRA alone amounted to $883 million. While the three-year (2011 test year and 2012 and 2013 attrition years) accumulated increase requested by PG&E amounted to slightly more than $4 billion, DRA recommended only $0.9 billion. Incorporating the positions of other parties would reduce the recommended increase further below that of DRA.

When looked at in total, the settlement produces a reasonable outcome. As shown above the cumulative settled revenue requirement increase of $1.7 billion for the years 2011, 2012, and 2013 is significantly less than the $4.0 billion amount requested by PG&E. The record in this proceeding supports reductions to PG&E's request but not to the full extent advocated by the various other parties. While recognizing that settlements are compromises of parties' positions, the fact that such a large number of parties, with such diverse interests and recommendations, were able to reach a compromise that was acceptable from their various viewpoints provides assurance that the overall result is reasonable. Additionally where specific issues were identified and resolved in the Settlement Agreement the results are reasonable and consistent with the record.

Aside from resolution of the lone outstanding issue in this GRC and how the Settlement Agreement may reflect aspects of that issue, we conclude that the revenue requirement levels reflected in the Settlement Agreement are reasonable.

Besides resolving the revenue requirement issues, the Settlement Agreement includes a number of guidelines and directions that are consistent with the record and reasonable. They address:

· Retention of the Vegetation Management Balancing Account.

· Allocation of work credits for Rule 20A projects.

· Allocation of electric RD&D project costs between generation and distribution, and, with certain limitations, placement of project results in the public domain.

· Establishment of DIMP and an associated one-way balancing account.

· Treatment of the postretirement benefits other than pensions and long term disability balancing account and associated costs.

· Treatment of certain Diablo Canyon Power Plant labor costs as operating expense rather than capital expenditures.

· Cost recovery treatment and guidelines related to the Diablo Canyon Steam Generator Replacement Project, Gateway Settlement Balancing Account, Colusa Generating Station, Humboldt Bay generating station, Hunters Point Power Plant site, and nuclear fuel payments.

· Below-the-line treatment of customer retention costs incurred by the Customer Care organization.

· Requiring an independent audit of PG&E's SmartMeter-related costs.

· Continuation of the SmartMeter Benefits Realization Mechanism.

· Treatment of the Commission's consultant costs for the SmartMeter evaluation as an eligible cost in the SmartMeter balancing accounts.

· Commitment of PG&E to file an application by January 1, 2012 to comprehensively reassess all of its DA and CCA fees.

· Rejection of reconnection fee adjustments.

· Approval of 8:30 a.m. to 5:00 p.m. as local office hours.

· Reduction of Non-sufficient Funds Fee to $9 from the current level of $11.50.

· Modification of PG&E's Below-the-Line Guidelines.

· Treatment of employee transfers from affiliates.

· Guidelines for meal expense records.

· Recovery of nuclear fuel and fuel oil carrying costs at short-term commercial paper rates.

· Removal of all Market Redesign and Technology Upgrade related revenue requirements from this proceeding.

· Denial of PG&E's requests for new balancing accounts for health care costs, New Business/Work at the Request of Others (WRO)/Rule 20; renewable energy projects, uncollectibles, emergencies and catastrophic events, and RD&D expenses.

· Use of the adopted 2011 rate base amounts in developing revenue requirements from future cost of capital proceedings.

· Use of adopted 2011 A&G expenses for use in determining administrative and general expenses in related proceedings, if needed.

· Approval of the Memorandum of Understanding between DisabRA and PG&E.

· Elimination of the requirement for PG&E to prepare total factor productivity studies.

· Elimination of the requirement for PG&E to include information about long-term incentives that are not funded by ratepayers, in future total compensation studies.

· Review of the Results of Operations model for use in PG&E's next GRC.

· Justification of new types of costs in the next GRC.

· Suspension of AFUDC accruals for the ten Transform Operations projects identified by TURN.

· Employee training and hiring testimony requirements for PG&E in its next GRC.

4.7.3. Non-tariffed Products and Services

The Settlement Agreement adopts PG&E's proposal to be allowed to expand its offerings of non-tariffed products and services (NTP&S).¹⁰ As discussed below, we agree that PG&E should be allowed to expand its list of approved NTP&S offerings, but we will require an annual report from PG&E on their new offerings as they suggested in the comments on the proposed decision. The Settlement Agreement also specifies the costs and revenues associated with the expansion of services shall be treated on a cost of service basis and that PG&E's proposals concerning the 50/50 net revenue sharing mechanism and a sharing mechanism for shareholder capital shall not be adopted. This aspect of the settlement is reasonable.

The Commission's NTP&S program was designed, not to allow utility management to enter markets unrelated to their core function of providing good utility service, but instead to encourage that management to find and exploit economies of scope available in any underutilized capital or capacity already acquired by ratepayers and used for the provision of the utility service.¹¹ While it is our preference that this process of exploitation of economies be performed by the utility's unregulated affiliates, under the purview of our Affiliate Transactions Rules, company management may find this approach impractical and decide, instead, to utilize our NTP&S program. If so, we need to be ensured that this program will not divert utility expertise and other resources enough to affect utility service, will not distort existing non-utility markets, and reasonably reimburse ratepayers for the use of their assets for the project.

Therefore, our NTP&S Rule VII of the Affiliate Transactions Rules requires a utility to describe their proposed NTP&S project in an advice letter which also includes the following showings: 1) identification of the underutilized or excess capacity acquired for the utility service; 2) the steps that will be taken to ensure that the project will not affect the quality or cost of the utility service; 3) proof that the provision of the NTP&S will not distort non-utility markets or be in some way anticompetitive; and 4) a reasonable mechanism to divide the proceeds of the project between ratepayers and shareholders.¹²

PG&E's proposal is that it be allowed to provide NTP&S that have been already approved by the Commission for other utilities without the advice letter requirement.¹³ PG&E has found the advice letter approval process to be cumbersome, indicating experiences of eight months to one year for approval. PG&E states that its proposal would create a catalogue that is more consistent statewide and reduce the administrative burden of advice letter filings for NTP&S that are already being offered in the state and should need no additional approval.

PG&E provides Table 12-2, in Exhibit PG&E-4, as an illustrative list of NTP&S categories currently offered by other California energy utilities. We note that all categories of NTP&S identified in Table 12-2 were listed by these utilities as products or services already offered in 1997 at the time this program and our rules were promulgated. We allowed the utilities to continue offering these categories without review by Commission staff for compliance with the new rules. At that time, PG&E listed 27 categories that they were already offering. We required new categories for each utility to be approved through advice letter filing for review, correction and finally disposition by the Commission.

We are not convinced that elimination of all reporting requirements, even for NTP&S categories and associated products or services offered by other utilities, is appropriate. It is not clear that, in light of the Affiliate Transaction Rules, every existing category should also now be applicable to PG&E without any review or verification. For instance, PG&E may have different levels of underutilization or excess capacity than utilities already offering a particular product or service. Also, the Commission needs assurance that appropriate steps are taken by PG&E such that the provision of NTP&S in a particular category will not affect the quality or cost of the utility service. However, in general, we agree that PG&E should be allowed to offer NTP&S that are already being offered by the other major energy utilities in a more expeditious manner than is currently available. Therefore, PG&E shall be required to provide an annual
information-only report to the Energy Division that describes, on a prospective basis, PG&E's specific plans for expansion into any of the areas currently authorized for the other utilities. The report should also be made available to the parties to this proceeding as well as the parties to Rulemaking 05-10-030. The purpose of the report is to permit the Commission and interested parties to confirm that PG&E's expanded NTP&S offerings in this category mirror the NTP&S already offered by one of the other energy utilities in their approved categories for NTP&S. As part of the report, PG&E should identify 1) the underutilized or excess capacity used to provide the NTP&S; 2) the steps that will be taken by PG&E to ensure that the project will not affect the quality or cost of the utility service; and 3) proof that the expanded NTP&S will not distort
non-utility markets or be anticompetitive.¹⁴ We determine this reporting requirement, in lieu of a formal advice letter filing, is sufficient due to the limited nature of the proposal, that is it will only apply to those NTP&S categories and associated products or services specifically described in other utilities' filings, and the costs and revenues will be treated on a cost of service basis.¹⁵ However, in order to allow time for the Commission and interested parties to confirm that PG&E's expanded NTP&S offerings are appropriate and justified, PG&E should not offer any such expanded service until at least 30 days after the issuance of the annual information-only report.

4.7.4. Reprioritization and Cost Deferrals

While the record supports the revenue requirement levels that are reflected in the Settlement Agreement, the Commission's expectations with respect to how authorized funds should be spent and PG&E's accountability with respect to how those funds are spent should be clarified.

While the Commission sets the adopted GRC revenue requirement based, in large part, on programs and projects proposed by PG&E, which are reviewed in the GRC proceeding and adopted in the GRC decision, PG&E may not actually expend funds in that exact manner. For instance, regarding certain distribution costs in this proceeding, PG&E states:

In an effort to remain within the capital and expense expenditure levels imputed from the 2007 GRC Settlement Agreement, PG&E adjusted work where possible by focusing on work in higher priority categories.¹⁶

Certain parties were concerned that the process of reprioritization and deferral of certain costs has resulted in projects identified and adopted in a prior GRC being deferred by PG&E and included again in its request for this proceeding. To address this concern, DRA, in its testimony, excluded a number of such electric distribution activities including replacement/reinforcement of poles, replacement of underground cables, preventative maintenance and equipment repair, electric line patrol and inspection, network work and projects, streetlight group replacements, pole restoration, and substation maintenance, as well as the gas meter protection program.¹⁷

It is generally recognized that when a utility files a GRC, expenditure estimates are based on plans and preliminary budgets developed at least
two years in advance of when they will actually be incurred. When the utility finalizes its budget just prior to the year when costs will be incurred or adjusts the budget during the year, new programs or projects may come up, others may be cancelled, and there may be reprioritization. This process is expected and is necessary for the utility to manage its operations in a safe and reliable manner. The Commission has recognized the concept of reprioritization, in part, as follows:

We conclude that this is not deferred maintenance in the sense we discussed previously. The work was not deferred to improve the utility's financial position. We do not intend to push utilities to spend the earmarked maintenance dollars simply to avoid risk of disallowance in a future proceeding. Because we hold the utility accountable to provide safe, reliable and efficient service, the utility should be able to move maintenance dollars from one account to another for the reasons provided in this case . . . ¹⁸

In summary, we should note that the issue in this instance is not deferred maintenance; rather, it is whether the utility should have the flexibility to shift earmarked funds if it is in the ratepayers' interest to do so. We conclude that if the utility has a valid reason based on economic or other considerations, then it should have the flexibility. This is simply prudent management.¹⁹

However, the fact that this flexibility is available to the utility does not mean that everything the utility ends up doing is necessary or reasonable. The Commission has disallowed costs of activities that were requested and included in prior GRC authorizations, deferred, and re-requested in another GRC. For instance, in PG&E's last GRC, the Commission stated:

The Commission has repeatedly held that it is unjust and unreasonable to make ratepayers pay a second time for activities explicitly authorized by the Commission in the past. Here, there is no dispute that PG&E received funding for lead paint and PCB abatement in its prior GRC proceeding, and that PG&E seeks funding for these activities a second time in the current proceeding.²⁰

And:

In order to find that the Settlement Agreement is consistent with the law, which includes adherence to long-established Commission precedent, we must be satisfied that all of PG&E's lead paint and PCB abatement costs are excluded from the O&M expenses adopted by the Settlement . . . ²¹

As indicated, reprioritization and cost deferrals may be necessary and reasonable, and, if not, cost disallowance of previously requested activities which were deferred and re-requested may be appropriate. With respect to reprioritization and deferred cost issues in this GRC, the Settlement Agreement does not indicate specific outcomes; however it is assumed that the settled position reasonably reflects Commission precedents as noted above, taking into consideration the strengths and weaknesses of parties' positions. The Settlement Agreement does state that:

The fact that Settling Parties set forth specific amounts for certain categories of costs is not intended to limit PG&E's management discretion to spend funds as it sees fit in a manner consistent with its obligation to provide reliable service and consistent with its obligation to maintain the safe operation of its utility systems. Nor does it limit the discretion of other parties to argue in future proceedings that it is unjust or unreasonable to make ratepayers pay a second time for activities explicitly authorized by the Commission in this proceeding or that PG&E has not provided safe and reliable service.²²

While we reaffirm that it is the utility management's prerogative and responsibility to provide safe and reliable service by reprioritizing and deferring activities as necessary, the Commission must be assured that the process is reasonable. We have concerns in that respect. For instance, despite any financial implications of exceeding authorized cost levels, the utility does have the responsibility to spend what is necessary to ensure safe and reliable service. To the extent a utility uses authorized cost levels as a reason for deferring activities, the Commission must be assured that such deferrals are otherwise reasonable especially with respect to safe and reliable service. Also, justified or not, reprioritization and deferrals undermine the basis for the Commission's determination of the reasonableness of the utility's GRC request and the extent of the authorized revenue requirement. Much of what is authorized is based on the utility's depiction of its needs and associated costs. Those needs and costs are tested by the GRC process. Reprioritized needs and associated costs may not be so tested and may not result in the most efficient use of funds. In light of these concerns, we will impose certain requirements on PG&E, as a step in ensuring that any reprioritization processes are reasonable and result in the best use of ratepayer funds.

First, in order for the Commission to better understand the ongoing effects of reprioritizations and deferrals, PG&E should provide the following expense and capital expenditure information for electric distribution, electric generation, and gas distribution.²³

Within 90 days of the issuance of this decision:

· PG&E's authorized budgeted amounts²⁴ for 2011, as of
January 31, 2011, by major work category (MWC), with an explanation of any differences with what is assumed in the Settlement Agreement for 2011.

By March 31, 2012:

· PG&E's authorized budgeted amounts, by MWC, for 2012, as of
January 31, 2012.

· The recorded amounts for 2011, by MWC, with explanations for significant deviations from PG&E's January 31, 2011 authorized budget for 2011.

By March 31, 2013:

· PG&E's authorized budgeted amounts, by MWC, for 2013, as of
January 31, 2013.

· The recorded amounts for 2012, by MWC, with explanations for significant deviations from PG&E's January 31, 2012 authorized budget for 2012.

Also, in its next GRC, as part of its showing, PG&E should fully describe any reprioritizations and deferrals of costs explicitly identified in the Settlement Agreement or costs that can reasonably be imputed from the Settlement Agreement. PG&E should fully explain its reprioritization process, justify deferrals of specific activities and projects, and justify the implemented higher reprioritized activities and projects that were not identified in this GRC. For activities and projects that were deferred and are now being re-requested, PG&E should fully explain why they are needed now when they were able to be deferred before. The Commission will be critical in its evaluation of previously requested activities or projects that were deferred and re-requested keeping in mind that the utility has the obligation to maintain its operations and its plant in the condition to provide efficient, safe and reliable service, even if that condition requires more expenditures than the Commission has authorized.²⁵

4.7.5. Gas Distribution Pipeline Safety Reporting

Due to the Commission's responsibilities and concerns regarding gas pipeline safety, we will impose additional reporting requirements related to gas distribution pipelines.²⁶ We will require PG&E to submit semi-annual gas distribution pipeline safety reports to the Directors of the Commission's Consumer Protection and Safety Division and Energy Division. The requirements of the reports are detailed in Attachment 5 to this decision. Reports should cover activity over the first six-month period and second
six-month period of the calendar year and continue until further notice of the Commission.

4.7.6. Financial Health

Aglet included testimony on the financial condition of PG&E, which Aglet characterizes as now being very good. With respect to PG&E's rise in credit ratings and stock prices since its bankruptcy in 2001, Aglet asserts the central feature of these financial improvements has been strong cash flows and access to capital. PG&E does not dispute Aglet's assertions and acknowledges that it has very strong access to capital because of its strong balance sheet and its ability to raise capital both from equity and debt financing.

The evidence demonstrates that PG&E is financially healthy. For the period covered by this GRC, the Settlement Agreement will provide PG&E with sufficient revenues to maintain its financial health, provide adequate service, and make necessary capital investments.

4.7.7. The Public Interest

We agree with the Settling Parties' position that the Settlement Agreement is in the public interest. There are no allegations, and we do not detect, that any element of the Settlement Agreement is inconsistent in any way with the public interest. Settlement avoids costs of further litigation and conserves resources of the parties and the Commission. In this case, it provides reasonable outcomes that are acceptable to a large number of parties representing a broad spectrum of interests.

Settling Parties assert and we agree that the principal public interest affected by this GRC is delivery of safe, reliable electric and gas service at reasonable rates, and the Settlement Agreement advances this interest because it sets forth a compromise that significantly reduces the revenue sought by PG&E while providing PG&E a test year revenue requirement increase and predictable attrition allowance.

Besides providing reasonable revenue requirement levels for electric distribution, electric generation and gas distribution, the Settlement Agreement furthers the public interest (such as safe and reliable service, ratepayer safeguards, and levelized competitive playing fields) by:

· Retaining the current one-way Vegetation Management Balancing Account, whereby any unspent amount will be returned to ratepayers.

· With respect to Rule 20 undergrounding projects, allowing communities with projects already in progress to continue with their projects even if they exceed the 5-year allowable borrowing period.

· Establishing of a one-way balancing account mechanism for the gas related DIMP that covers developments and improvements in such areas as preventative maintenance, leak surveys, operator qualifications and training. Any net unspent funds from this program will be returned to customers in the next GRC.

· Allowing PG&E to file a subsequent application to recover additional site-specific environmental remediation costs to the extent necessary to accommodate the development plan ultimately adopted for the Hunters Point site.

· Requiring PG&E to record customer retention costs incurred by its Customer Care organization below-the-line.

· Committing PG&E to file an application by January 1, 2012 to comprehensively reassess all of its DA and CCA service fees.

· Modifying PG&E's below-the-line guidelines to provide for an annual compliance review, as well as identification of additional below-the line activities and more thorough accounting and employee training.

· Advocating Commission approval of the MOU between PG&E and DisabRA regarding accessibility and safety issues for the disabled.

· Providing for an independent audit to ensure proper booking and allocation of costs and benefits related to PG&E's SmartMeter program and evaluate whether PG&E's internal cost management guidelines are adequate to ensure that all labor and non-labor costs are properly booked to the SmartMeter balancing account.

We conclude that the Settlement Agreement is in the public interest.

4.7.8. Clarifications

The Settlement Agreement designates the Energy Division to be responsible for overseeing the audit process. We clarify that this responsibility does not fall on the Energy Division in particular, but on Commission staff in general, with specific responsibility being designated by Commission management based on staff availability.

It should be noted that, by the terms of the Settlement Agreement, if PG&E prevails on the issue of the rate of return for electromechanical meters replaced by SmartMeters, a $44 million revenue requirement increase will be added to the adopted electric distribution revenue requirement. If TURN prevails, the adopted electric revenue requirement would remain as indicated in the Settlement Agreement. To the extent that this decision adopts a different ratemaking treatment than proposed by either PG&E or TURN, the Settlement Agreement is modified in that respect.

4.7.9. Conclusion

The Settlement Agreement is consistent with law. With the additional requirements related to NTP&S, reprioritization and cost deferrals, and gas distribution pipeline safety reporting, and with minor clarification, as discussed, the Settlement Agreement is reasonable and in the public interest. It should and will be adopted.

The lone issue that was not resolved by the Settlement Agreement relates to the ratemaking treatment for meter devices replaced by SmartMeters.

⁴ DisabRA joins only in the following portions of the Settlement Agreement: Article 1, Article 2, Article 3.12(j), and Article 4.

⁵ Merced ID joins only in the following portions of the Settlement Agreement: Article 1, Article 2, Article 3.5.1(b), and Article 4.

⁶ Modesto ID joins only in the following portions of the Settlement Agreement:
Article 1, Article 2, Article 3.5.1(b), and Article 4.

⁷ The Joint Comparison Exhibit is identified as Exhibit PG&E-69 and is received in evidence.

⁸ See, for example, Decision (D.) 88-12-083, 30 CPUC2d 189.

⁹ Rule 12.1(d) of the Commission's Rules of Practice and Procedure (Rules).

¹⁰ See Exhibit PG&E-4, Chapter 12.

¹¹ The classic example given was leasing available land for Christmas tree lots under transmission lines. See D.97-12-088, as revised by D.06-12-029. The most recent introduction of this program by this Commission was for the water utilities in
D.10-10-019.

¹² See D.06-12-029, Appendix A-1, Rule VII C.

¹³ For new NTP&S categories, PG&E is currently required to make Tier 3 advice letter filings, which require Commission approval by resolution.

¹⁴ This reporting requirement was proposed by DRA, TURN, and PG&E in their opening comments on the proposed decision of ALJ Fukutome and the alternate proposed decision of Commissioner Peevey.

¹⁵ PG&E will include a new forecast of the costs and revenues in its information-only filing. In the test year and the attrition years, if the revenues or costs are different than forecasted the differences fall on shareholders rather than ratepayers. Such "cost of service" ratemaking has been used for NTP&S under PG&E's existing NTP&S catalog since the late 1990s and will be maintained.

¹⁶ See, for instance, Exhibit PG&E-3 at 1-35.

¹⁷ TURN and CFBF made similar types of adjustments for cost deferrals.

¹⁸ D.83-12-068, 14 CPUC2d 15, 146.

¹⁹ D.94-12-068, 16 CPUC2d 721, 782.

²⁰ D.07-03-044 at 93 (footnote omitted).

²¹ D.07-03-044 at 95.

²² Settlement Agreement, Article 4.11.

²³ This information should be provided through compliance filings in this docket. Energy Division should report to the Commission if it observes any spending patterns that are of concern with respect to the provision of safe and reliable service.

²⁴ Budgeted amounts are those authorized by PG&E management.

²⁵ For example, see D.83-12-068, 14 CPUC2d 15, 66.

²⁶ Gas transmission pipelines issues are not within the scope of this proceeding, but are instead addressed in PG&E's Gas Transmission and Storage proceeding, A.09-09-013.