Data Request Scip-Watson-Tcap-Psep-04

OIR ON THE COMMISSION’S OWN MOTION TO ADOPT NEW SAFETY AND RELIABILITY REGULATIONS FOR NATURAL GAS TRANSMISSION AND DISTRIBUTION PIPELINES AND RELATED RATEMAKING MECHANISMS (R.11-02-019/A.11-11-002)

(DATA REQUEST SCIP-WATSON-TCAP-PSEP-04) ______

QUESTION SCIP-WATSON-TCAP-PSEP-04-01:

This question follows-up the SCG-SDG&E response to Q4 of SCIP-Watson’s First Data Request to SCG-SDG&E in R. 11-02-019. This question asked SoCalGas and SDG&E to describe the capital projects included in their currently-authorized capital spending for gas transmission pipeline safety. The response received did not include a specific description or details on each transmission pipeline testing, replacement, or modification project that is included in the existing SoCalGas – SDG&E Transmission Integrity Management Programs (TIMP) whose costs are now included in rates. SCG- SDG&E’s response appears to have aggregated such projects into just two or three “Budget Codes,” without explanation of what such codes mean. Please provide this data in more disaggregated form, so that SCIP-Watson can see, for each individual TIMP capital project, the numbered line involved in each project, the number of miles for each project, the project cost by year, the scope of the project, reason that the project is included in the TIMP, and the expected date of completion for the project. The purpose of this request is to allow SCIP-Watson to ensure that capital projects included in the authorized TIMP for SCG and SDG&E, and now included in rates, do not duplicate capital projects included in the PSEP. We attach lists of capital projects that NCIP obtained in discovery from PG&E in R. 11-02-019 and A. 09-09-013 (the PG&E Gas Accord V rate case), which NCIP used to determine that there was no significant overlap between the capital projects for PG&E’s PSEP and those for the PG&E pipeline integrity management program funded under existing PG&E Gas Accord V rates. SCIP- Watson seek data in a similar format for the SCG-SDG&E TIMP, so that we are able to undertake the same analysis for SCG and SDG&E. Without the data to make this determination, SCIP-Watson may propose that the capital budget for the PSEP should be reduced by the amount of TIMP capital expenses.

1 OIR ON THE COMMISSION’S OWN MOTION TO ADOPT NEW SAFETY AND RELIABILITY REGULATIONS FOR NATURAL GAS TRANSMISSION AND DISTRIBUTION PIPELINES AND RELATED RATEMAKING MECHANISMS (R.11-02-019/A.11-11-002)

RESPONSE SCIP-WATSON-TCAP-PSEP-04-01:

The original data request –Watson 1, Q4 - asked for a description of the existing gas transmission safety projects that are included in SCG and SDG&E rates today. The table provided in the response included reference to Budget Codes 276, 312, and 412 in effort to describe the work efforts.

As more background, for budget planning and cost reporting SCG and SDG&E use “Budget Codes” to represent a collection or grouping of similar work activities. As described in testimonies, SCG Budget Codes 276 and 312 (Exhibit SCG-05 A.06-12- 010, beginning at page JMR-43) and SDG&E Budget Code 412 (Exhibit SDGE-06, A.06-12-009, beginning at page JMR-26) include the following TIMP elements (abridged from Testimony).

SCG Budget Code 276

As shown in this Data Response, Budget Code 276 captures the investments made to the distribution plant to comply with the transmission pipeline integrity rule.

Per SoCalGas policy, when facilities meet capitalization requirements and are to be installed on distribution plant assets to allow the in-line inspection, these additions are recorded to Budget Code 276. The forecast of these downstream impact additions are based upon the recorded history of 2003 through 2005 (this activity did not exist prior to 2003). Since each pipeline may have vastly different impacts to customers and service levels, an average cost per HCA mile internally inspected during the period of 2003 through 2005 was calculated and applied to each year’s forecast of HCA mileage per the baseline assessment plan.

The mileages involved in making these calculations, and the calculations themselves, are discussed in detail in the work papers made a part of this filing.

Expenditures associated with retrofitting and inspecting pipelines in HCAs as defined by the new Pipeline Integrity rules are included in Budget Code 276 when they are defined as Distribution plant. The schedule of these retrofit and inspections is determined by the baseline assessment plan. Refer to 49 CFR, Part 192, Subpart O and the individual work papers prepared as part of this filing for project cost determination.

SCG Budget Code 312 for Transmission Integrity

Expenditure associated with retrofitting and inspecting transmission pipelines in HCAs as defined by the new Pipeline Integrity Rules are included in Budget Code 312. Approximately 100 such projects, through 2008, are discussed individually in detail in work papers made as part of this filing. Capital costs in Budget Code 312 are lower in 2008 in – part due to federally-mandated changes in the method of accounting for integrity inspections, specifically, that initial inspections must be expensed beginning January 1, 2008.

Also, as explained in FERC Accounts 863.7 and 887.7, the Baseline Assessment Plan (BAP) was used to forecast the expenditures for completing assessments. The assessment method used to perform the assessment is selected based upon many factors including the unique characteristics of the pipeline, schedule, and cost. The use of in-line inspection is often not practical on lower pressure smaller diameter pipelines. These pipelines become increasingly prevalent as the program progresses and are typically scheduled using ECDA. As a result, the capital requirement to retrofit pipelines in order to accommodate in-line inspection tapers off while the expense associated with ECDA increases. Refer to 49 CFR, Part 192, Subpart O. and the individual work papers prepared as part of this filing for project cost determination.

SDG&E Budget Code 412 – Transmission Integrity

This account contains the labor and non-labor capital required to comply with SDG&E’s Pipeline Integrity mandate from the Department of Transportation. This account includes the costs of repairing deficiencies discovered through the inspection process that would require replacement of pipeline segments and/or lowering of pressure with the associated installation of alternate feeder lines and regulator stations. This forecast includes the replacement of approximately 1,276 feet of 16 inch diameter pipe in city streets. The actual number of feet will not be known until pipeline integrity inspections are performed, and could be higher than the estimate.

The estimated feet of pipeline replacement required in SDG&E is based on Pipeline Integrity pipeline replacements experienced by SoCalGas, specifically, recent recorded costs of transmission line replacement in city streets recorded at $2.6 million (direct) dollars per mile for 12 inch pipe. Sixteen (16) inch diameter transmission main in the urban streets of San Diego area could exceed $3 million per mile, or $568 per foot. Based on recent results in the SoCalGas transmission system, ¼ mile per year is the least amount appropriately forecast.

The second part of the original question asked for the amounts SCG and SDG&E are authorized to spend on each project. In their TY2008 General Rate Case proceedings SCG and SDGE sought funding consistent with efforts of their Transmission Pipeline Integrity Program. In its revised response, SDG&E and SCG provided 2008 authorized costs from their respective 2008 GRC decisions because discreet costs for any attrition year (years between GRC decision, including 2011) were not contemplated and addressed by the Commission.

Absent detailed 2011 authorized capital expenditures from the Utilities Test Year 2008 GRC, SDG&E and SCG provide estimated capital expenditures for the years 2006, 2007 and 2008 as shown in the Applications. For SCG, Capital Work Papers, Exhibit SCG-05-JMR-CWP filed in A. 06-12-010 discuss the type of project that could be anticipated to be completed. Similarly, for SDGE a projection of work elements is shown in Capital Work papers Exhibit SDGE-06-JMR-CWP in A. 06-12-009. Included for your convenience are copies of these work papers and project summary listing, which form the basis of the authorized level of expenditure.

TIMP Projects TIMP Projects TY2008 CWP TY2008 Application SCG CapitalTY2008 Rivera.pdf Application SDGE Capitalsummary.xlsx Rivera.pdf

In addition, SDG&E and SCG are providing copies of capital work papers from their respective TY2012 General Rate Case proceedings for rates effective January 1, 2012 (A. 10-12-005 and A.10-12-006, respectively). Also included for your convenience is a project summary listing. As with the TY2008 showing, these filings include the Utilities estimated capital expenditures for the years 2010, 2011, and 2012.

TIMP Projects TIMP Projects from TY2012 CWP SCG-05-CWP-R Stanford_ZZ SDG&E-04-CWP-R REVISED July 2011.pdf Stanford_ZZ summary.xlsx REVISED July 2011.pdf

QUESTION SCIP-WATSON-TCAP-PSEP-04-02:

The January 17, 2012, Technical Report of the CPUC’s Consumer Protection and Safety Division (CPSD Report) recommends at pages 3 and 24 that, for 20 miles of transmission pipe installed between 1961 and 1970, if SoCalGas – SDG&E lack documentation for the pressure testing of these pipes in accordance with CPUC G.O. 112, utility shareholders should bear the costs for the pressure testing or replacement of this pipe.

 Have SCG-SDG&E verified that they lack pressure-test data in accordance with CPUC G.O. 112 for these 20 miles of pipes?

 Please provide data on the location of these 20 miles of pipeline segments, as well as the costs (expenses and capital for each year from 2011-2015) that the SCG-SDG&E PSEP proposes to expend for the strength testing or replacement of these 20 miles of transmission pipes, or of any other pipe installed between 1961 and 1970 for which SoCalGas – SDG&E lack documentation for pressure testing in accordance with CPUC G.O. 112.

RESPONSE SCIP-WATSON-TCAP-PSEP-04-02:

a) SCG/SDG&E have currently identified approximately 12 miles of transmission pipe located in Class 3 or 4 or High Consequence Areas that are labeled as Category 4 and also do not have documentation in accordance with GO 112. Associated with these segments are roughly an additional 12 miles of transmission pipeline, also Category 4, that are located in Class 1 or 2 non-High Consequence Areas.

b) The mileage that corresponds to the transmission pipe described above is, for the most part, interspersed among other mileage of earlier vintage that will be addressed in the PSEP.

The station start and stop for the segments identified in part (a) are as follows:

Station Start_Stop

A high level estimate of the portion of the total project cost contributed by these segments, as calculated through a simple proration methodology, is as follows:

Estimated Cost (proration) In the PSEP filing, specific pipeline projects were not allocated to particular years. Instead, the total pipe replacement and pressure testing estimated costs were spread over Phase 1A (years 2012-2015) per the factors and assumptions noted in the workpapers supporting Chapter IX of the testimony under the heading “Schedule”.