2. The Settlement Agreement

The Joint Parties represent that the settlement negotiations were "lengthy and complex" and involved many different provisions and "numerous trade-offs involving cost of capital, revenue requirement, marginal cost, revenue reconciliation, and rate design issues."5 Pursuant to Rule 12.1 of the Commission's Rules of Practice and Procedure (Rules), on July 16, 2009, Sierra, DRA and A-3CC filed a Joint Motion to Accept Settlement Agreement of Sierra, DRA, and the A-3 Customer Coalition (Joint Motion). Attached to the Joint Motion, as Attachments A, B, and C, respectively, are the Settlement Agreement, a comparison table summarizing the parties' positions and the settlement position on results of operations, and a comparison table summarizing the class impacts under present rate revenues, under Sierra's proposed rate revenues, and under the rate revenues produced by the Settlement Agreement.

The proposed Settlement Agreement is an all-party settlement and resolves all issues raised in the protests and all elements of Sierra's 2008 GRC. No protest or comment was filed in response to the Joint Motion.

2.1. Testimony

Sierra served its prepared direct testimony on revenue requirement,6 marginal costs, revenue allocation, and rate design on August 1, 2008. Pursuant to ALJ Darling's Ruling, issued January 13, 2009, which extended time and revised the procedural schedule, DRA served its prepared testimony on results of operations7 relating to revenue requirement, PTAM, and Energy Efficiency programs on April 3, 2009 and its prepared testimony regarding cost allocation and rate design on April 17, 2009. Also on April 17, 2009, A-3CC served its prepared testimony on marginal costs and rate design.8 On May 29, 2009, Sierra served its rebuttal testimony on DRA's results of operations testimony and on A-3CC's marginal cost and rate design testimony.

The Settlement Agreement resolves all issues related to Sierra's 2008 GRC. Its primary provisions are summarized below.

Sierra proposed a capital structure of 43.71% Equity, 56.29% Debt, a Cost of Debt of 6.8%, a Return on Equity (ROE) of 11.4%, and a weighted average rate of return of 8.81%. No party opposed Sierra's proposed Capital Structure or Cost of Debt. DRA proposed an ROE of 10.5% and as a result of the settlement negotiations, the Joint Parties agreed to an ROE of 10.7%. All parties agreed to the revised weighted average rate of return of 8.51%, calculated using the settlement ROE of 10.7%.

In its Amended Application, Sierra proposed an overall revenue requirement increase of $8.91 million for Test Year 2009 based primarily on (1) inclusion of the new Tracy Combined Cycle Power Plant that became operational July 1, 2008, (2) an increase in the proposed rate of return from 8.73% to 8.81%, (3) investments in new transmission and distribution facilities, and (4) proposed increases in Sierra's Energy Efficiency programs. DRA recommended a $4.259 million increase in base rate revenues. One of the major differences is that DRA used non-labor escalation factors updated in February 2009, rather than the May 2008 escalation factors used by Sierra in its calculations.9 In its rebuttal testimony,10 Sierra accepted the updated escalation factors, in addition to correcting a calculation error in depreciation expense which reduced the California jurisdictional depreciation expense by $1.4 million.

The Settlement Agreement proposes a $5.5 million increase to Sierra's revenue requirement, approximately 62% of Sierra's original request. The items listed below are changes to Sierra's forecasted revenues and expenses as a result of the Settlement Agreement. Changes to revenue requirement are shown in parentheses.

· Reduction of Return on Equity from 11.5% to 10.7% ($690,000);

· Correction of California jurisdiction depreciation expense incorporating allocation updates ($1,514,000);

· An overall reduction in Operations and Maintenance expenses ($733,000);

· A reduction in forecasted California jurisdictional plant, incorporating allocation updates and tax effects ($331,000);

· Various adjustments to Other Rate Base, including tax impacts ($227,000);

· An increase in Other Operating Revenues ($140,000);

The net effect of the Settlement Agreement provisions is to reduce Sierra's base rate revenue requirement increase to $5.5 million.

In its application, and amended application, Sierra proposed establishing a PTAM to recover cost increases other than those recovered through Sierra's ECAC during the two years between rate cases. Sierra's proposal included an Attrition Component (reflecting the forecasted Consumer Price Index), less a productivity factor, and a Major Plant Additions Component for additions greater than $20 million on a companywide basis. Rate changes under the PTAM would be filed by advice letter starting in October 2009 with an effective date of January 1, 2010.

Sierra also proposed an increase in its annual budget for Energy Efficiency programs from $450,000 to $600,000 and requested authorization to offer to its California customers a renewable energy incentive program it operates for its Nevada residential customers called the "SolarGenerations Program." Under the SolarGenerations program, Sierra offers rebates to customers for installation of photo-voltaic systems and requires transfer of Renewable Energy Credits (REC) from the customers to Sierra. On June 26, 2008, the Commission's Energy Division advised Sierra to stop offering the program in California until it obtained specific Commission approval because the REC transfer violated prior Commission decisions.11 Nothing in the Settlement Agreement or this Decision provides authority to Sierra to operate the Solar Generations program in California or otherwise alters the Commission's position as articulated in the June 26, 2008 letter from the Energy Division.

DRA recommended two changes to the proposed PTAM and opposed the Energy Efficiency increase, noting $123,029.00 in unspent energy efficiency program funds from the last rate case cycle. The Settlement Agreement provides:

· The proposed PTAM is adopted and modified such that (1) the Attrition Component will be based on the September Global Insight U.S. Economic Outlook forecast for CPI, minus 0.5% productivity factor (but not less than zero), and (2) for the Major Plant Additions component, Sierra will provide advance notice to DRA and A-3CC of any plan to make a major plant addition;

· A $200,000 reduction to Sierra's California Energy Efficiency programs proposed annual budget for the 2009-2011 three year budget cycle, subject to the following:

    · Sierra's 2008 year-end balance of $123,029 in carryover funds from the last rate base cycle will be tracked and reported in Sierra's next GRC, and if Sierra is unable to use the funds by the end of the 2009-2011 budget cycle, the funds should be refunded to California ratepayers; and

    · Any Energy Efficiency program funds accumulated during the 2009-2011 budget cycle will be tracked, reported, and unspent funds will be refunded to California ratepayers.

In Sierra's 2005 GRC, the Commission adopted a Settlement Agreement that provided Sierra would re-evaluate its method of determining class marginal transmission and distribution demand costs in the 2008 GRC.12 In this proceeding, Sierra modified its MCS, presumably to improve its calculations of these specified costs. Sierra asserts the MCS used in this application follows the same general marginal cost approach it has used in proceedings before this Commission and the Public Utilities Commission of Nevada for more than 20 years, but with several improvements. The changes made to Sierra's MCS include the following:

· Allocating all annual marginal transmission demand costs to hours of the year using Sierra's system (California and Nevada) Probability of Peak (POP) allocator;

· Allocating marginal transmission demand costs between customer classes exclusively on the basis of customer class coincident peak allocator, a change from the previous 80% coincident/20% non-coincident peak allocation used since its 1993 GRC (D.93-04-056.);

· Allocating marginal distribution demand costs to hours of the year using Sierra's California-System POP allocator (CA POP), causing California costs to be concentrated in the Winter period when Sierra's California system experiences peak load;

· Allocating 100% of substation marginal costs and 50% of the non-revenue feeder marginal costs to hours of the year and to customer classes using the CA POP, with the balance of non-revenue feeder costs allocated using the non-coincident demand allocator;

· Use of Sierra's facilities (or line extension project) database (actual costs) to determine customer and facilities costs by class, and removal of the line extension facilities costs from demand-driven distribution costs; and

· Increasing the average reserve margin from 5% to 15%, consistent with Sierra's Resource Plan.

DRA agreed with or did not oppose many aspects of the MCS, including the six identified above, but also sought several modifications related to revenue allocation and rate design. A-3CC opposed several aspects of the MCS, including those noted above and emphasized the disproportionate impact of the MCS methodology on cost allocation to the A-3 customer class. In particular, A-3CC recommended that the median non-coincident peak (NCP) demand, rather than the mean NCP demand, be used to develop the NCP distribution demand allocator for the A-3 class because the presence of four large customers in the class skews the distribution for the whole class and overstates the total non-coincident distribution demand costs for the class.

In settlement discussions, the Parties agreed to accept Sierra's MCS for purposes of this GRC, with some changes including:

· Reallocation of class revenue requirements is based on Equal Percentage of Marginal Cost (EPMC) with a 2% cap on increases to any class above the overall percentage increase, except that (1) the residential class increase is limited to the 7.75% overall percentage increase, and (2) the PA (agricultural irrigation) class will receive a subsidy that increases from $9,000 to $17,000;13

· The revenue reconciliation results in the following percentage increases by customer class (exclusive of surcharges):

    · Residential - 7.75%

    · A-1 - 6.20%

    · A-2 - 7.46%

    · A-3 - 9.75%

    · PA - (14.91%) (rate reduction)

    · Street Lighting - 9.43%

    · OLS - 7.49%

· Increases to customer charges by class, as follows:

    · Residential - from $6.00 to $6.50

    · A-1 - from $11.00 to $12.00

    · A-2 - from $100.00 to $107.00

    · A-3 - from $550.00 to $565.00

    · PA - from $11.00 to $12.00

· Addition of optional Time-Of-Use (TOU) rate schedules for residential, A-1, A-2, and CARE customers, provided Sierra (1) provides information on its website that compares TOU to flat rates and answers customer questions, and (2) offers Residential and CARE customers the Guaranteed Lowest rate feature currently in effect for Sierra's Nevada residential customers who try the optional TOU schedule.

The parties accepted all other elements of Sierra's proposed rate design, including updated residential baseline and excess rates based on a composite tier differential of 17.5%, and the updated master billing credit, which will be updated consistent with the settlement.

5 Joint Motion to Accept Settlement Agreement of Sierra, the DRA, and the A-3 at 4.

6 Sierra is a multi-jurisdictional utility that provides electric service under three jurisdictions: California, Nevada, and the Federal Energy Regulatory Commission. Its revenue requirement is based on its cost of service studies and is then allocated among the three jurisdictions.

7 DRA's results of operations are based on Sierra's California jurisdictional electric revenues, expenses, and plant.

8 A-3CC's testimony addresses the new methodology used by Sierra in its MCS and its impact on the A-3 customer class.

9 DRA Testimony 1-4 and 1-5.

10 Sierra's Rebuttal testimony at 4.

11 Sierra's Testimony, Volume 2, Chapter 4 at Exhibit JWH-1.

12 Decision (D.) 06-08-024 at 6.

13 The subsidy to PA class (agricultural irrigation), designed to reduce rate disparity between adjacent irrigation customers in California and Nevada, was authorized by Commission Resolution E-3050 (September 10, 1987.) Sierra originally proposed a $27,000 subsidy and DRA originally opposed a subsidy in any amount.

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