Subject: SCE Update Regarding the Cost-Estimate for the California Portion of the Devers-Palo Verde No. 2 Transmission Line Project

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1 STATE OF CALIFORNIA PUBLIC UTILITIES COMMISSION SAN FRANCISCO, CA Edmund G. Brown Jr. Governor March 19, 2014 Advice Letter 2804-E Megan Scott-Kakures Vice President, Regulatory Operations Southern California Edison Company 8631 Rush Street Rosemead, CA Subject: SCE Update Regarding the Cost-Estimate for the California Portion of the Devers-Palo Verde No. 2 Transmission Line Project Dear Ms. Scott-Kakures: Advice Letter 2804-E is effective February 5, 2014, per Resolution E Sincerely, Edward F. Randolph, Director Energy Division

2 ADVICE LETTER (AL) SUSPENSION NOTICE ENERGY DIVISION Utility Name: Southern California Edison Company. Date Utility Notified: November 26, 2012 via: Utility No./Type: U 338-E [X] to: Darrah.Morgan@sce.com Advice Letter Nos.: 2804-E Date AL filed: November 2, 2012 Fax No.: N/A Utility Contact Person: Darrah Morgan ED Staff Contact: Manisha Lakhanpal, ml2@cpuc.ca.gov Utility Phone No.: (626) For Internal Purposes Only:) Date Calendar Clerk Notified / / Date Commissioners/Advisors Notified / / [X] INITIAL SUSPENSION (up to 120 DAYS from the expiration of the initial review period) This is to notify that the above-indicated AL is suspended for up to 120 days beginning December 3, 2012 for the following reason(s) below. If the AL requires a Commission resolution and the Commission s deliberation on the resolution prepared by Energy Division extends beyond the expiration of the initial suspension period, the advice letter will be automatically suspended for up to 180 days beyond the initial suspension period. [ ] A Commission Resolution is Required to Dispose of the Advice Letter [ ] Advice Letter Requests a Commission Order [ ] Advice Letter Requires Staff Review The expected duration of initial suspension period is 120 days [ ] FURTHER SUSPENSION (up to 180 DAYS beyond initial suspension period) The AL requires a Commission resolution and the Commission s deliberation on the resolution prepared by Energy Division has extended beyond the expiration of the initial suspension period. The advice letter is suspended for up to 180 days beyond the initial suspension period. If you have any questions regarding this matter, please contact Analyst at Manisha.lakhanpal@cpuc.ca.gov cc: EDTariffUnit * Note: reference Decision D , dated February 21, 2002, and Rule 7.5 in appendix A of D.O

3 Akbar Jazayeri Vice President of Regulatory Operations November 2, 2012 ADVICE 2804-E (U 338-E) PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA ENERGY DIVISION SUBJECT: Southern California Edison Company Update Regarding the Cost-Estimate for the California Portion of the Devers-Palo Verde No. 2 Transmission Line Project INTRODUCTION Southern California Edison Company (SCE) submits this filing to the California Public Utilities Commission (CPUC or Commission) to update the cost estimate for the California portion of the Devers-Palo Verde No. 2 Transmission Line Project (DPV2) authorized by the Commission in Decision (D.) , as modified by D , and D For purposes of this Advice Filing, the California portion of the DPV2 project will be referred to as Devers-Colorado River Transmission Line Project (DCR or Project). In D and D , the Commission approved SCE s request to provide updated cost estimates to the Commission in an advice letter and seek an increased approved maximum and reasonable cost. 2 The Commission recognized that SCE s 1 D authorized the construction of the Colorado River Substation Expansion, and approved the Supplemental Environmental Impact Report which required relocating the Colorado River Substation to a new location approximately 4,000 feet to the southeast of the prior location. This relocation was done in order to avoid a sand transport corridor to reduce impacts to the Mojave fringe-toed lizard to less than significant impacts with mitigation measures. SCE believes that the cost updates for the 500 kv switchyard elements are adequate for the Commission to adopt an updated maximum reasonable and prudent cost for the Project. 2 Although FERC has jurisdiction to determine how much of the costs the utility may reflect in transmission rates, see D , SCE recognizes that the Commission believes that the Commission is obligated by Public Utilities (PUC) Code (a) to specify a maximum amount determined to be reasonable and prudent for the facility. The Commission has also recognized that P.O. Box Rush Street Rosemead, California (626) Fax (626)

4 ADVICE 2804-E (U 338-E) November 2, 2012 cost estimates would be more accurate once SCE developed a final engineering design-based construction estimate, particularly given that certain routing options remained under consideration. 3 SCE is submitting this cost update now for several reasons. First, SCE has recently begun constructing the Project. The Project cost is now more well-defined than it was at the time the decisions approving the Project were issued. Second, as discussed below, the Project has evolved over time, and SCE believes that there is value in restating the current purpose and configuration of the Project, along with related cost impacts. Finally, although final engineering is not yet complete for the entire Project, final engineering has been completed for significant parts of the Project, and SCE has made significant progress in completing the design for the Project as a whole. The cost of the Project will significantly exceed the amounts the Commission specified under PU Code (a) in D SCE desires to ensure that the Commission is aware of the current cost estimates and modifies the cost cap. The cost estimate for the Project has increased from the $545.3 million 4 (2005$) adopted in D to $701.3 million 5 (2005$). Escalating the cost estimate to current year dollars brings the updated cost estimate to $944.8 million 6 (2012$). SCE s methodology for the escalation is provided in Appendix A. This Advice Filing contains an explanation of the current cost estimates and an explanation of the factors contributing to the changed estimates. As discussed later in this Advice Filing, there are several reasons for the increased cost estimate, but environmental factors are the single largest driver of the cost increases. Environmental related costs include both direct and indirect costs. Direct environmental related costs the amount specified pursuant to PU Code (a) in a CPCN decision is not a final or hard cap on the reasonable costs, but instead is subject to revision. In the case of DCR in particular, as more fully discussed below, SCE s cost estimates were based on preliminary design that did not include the costs for mitigation measures and monitoring programs imposed by the CPUC and other regulatory agencies after the CPCN was granted. 3 In D , Ordering Paragraph 12, the Commission stated that, If SCE s final detailed engineering design-based construction estimate for the authorized project exceeds the authorized maximum cost, SCE shall, within 30 days, file an advice letter to seek an increase in the approved maximum cost pursuant to (b), and shall address whether the cost increases affect the costeffectiveness and need for the DPV2 project. In D , at page 25, the Commission granted SCE s request to retain the advice letter process, stating that, The Decision [D ] recognized that SCE s cost estimate for the Project would be more accurate once SCE developed a final detailed engineering design-based construction estimate, particularly given the fact that certain routing options remained under consideration. 4 Inclusive of corporate overheads but exclusive of financing costs. Corporate overheads include administrative and general, pensions and benefits, payroll taxes, injuries and damages, and property taxes. Financing costs include allowance for funds used during construction (AFUDC) and construction work in progress (CWIP) in rate base. 5 Inclusive of corporate overheads but exclusive of financing costs. 6 Inclusive of corporate overheads but exclusive of financing costs.

5 ADVICE 2804-E (U 338-E) November 2, 2012 include mitigation lands and field monitors, the costs of preparing permits, the mitigation plans and the Commission s Mitigation Monitoring and Compliance Reporting Program (MMCRP), notice to proceed requests, requests for variances and determinations of National Environmental Policy Act (NEPA) adequacy, addendums, project refinement reports, requests for temporary extra workspace, and the SCE and agency (e.g., CPUC, California Department of Fish and Game (CDFG), Bureau of Land Management (BLM), and United States Fish & Wildlife Service (USFWS)) resources needed to prepare, review and process the documents. In addition to the direct environmental costs, the indirect costs to implement the environmental mitigation measures and considerations are also key drivers in the cost increase for the transmission lines and substation facilities associated with the Project. An example is the loss of construction productivity related to a partially released right-ofway (ROW). Historically, transmission projects were constructed in a predominately linear fashion, allowing the contractor flexibility to cost-effectively manage and sequence work. However, more recent projects are likely to be subject to extensive environmental mitigation requirements. For DCR, the mitigation and permit conditions contained in the MMCRP specify that specific construction sites are to be released for construction not the entire ROW. In addition, before a specific construction site can be released, pre-construction surveys by both SCE and the CPUC are performed. These processes eliminate the contractor s ability to construct in a sequential or linear manner. Instead construction personnel are moved around to work the sites that have been released and that have received agency validation. Even after sites are released, they may be shut down for nesting birds and other environmentally-sensitive biological and cultural resources, which again results in the need to move crews and equipment. These work practices, necessitated by environmental considerations, have significantly increased the cost of the Project by reducing productivity. Appendix B contains a more comprehensive discussion of the impact of the environmental factors on the Project. SCE estimates that environmental related costs (both direct and indirect) amount to $234.4 million (2012$). PROCEDURAL BACKGROUND In D , the Commission granted SCE s application for a Certificate of Public Convenience and Necessity (CPCN) for DPV2. DPV2 was originally comprised of two major transmission lines, one of which was intrastate, and one of which was interstate. 7 Together, the elements of the project were intended to increase the transfer capability between load centers in Southern California and electrical resources in Arizona by 7 The intrastate portion was a 42-mile transmission line known as the Devers-Valley No. 2 transmission line. This would be a second 500 kilovolt (kv) transmission line between SCE s Devers substation in North Palm Springs, Riverside County, and SCE s Valley substation in the unincorporated portion of Riverside County. The interstate line was an approximate 230-mile 500 kv line known as the Devers-Harquahala transmission line, which would connect Devers substation in California to a location in Arizona near the Palo Verde Nuclear Generating Plant.

6 ADVICE 2804-E (U 338-E) November 2, ,200 megawatts (MW). This would have allowed Southern California ratepayers to access competitively priced electrical resources in Arizona, as well as reduced congestion on existing transmission lines, thus providing significant ratepayer benefits in the form of lower energy prices and reduced congestion charges. These ratepayer benefits were estimated to be well in excess of the annual ratepayer costs of the project at that time. As a result of these findings, the Commission authorized DPV2 in D , and conditioned construction of the project upon approval from the Arizona Corporation Commission (ACC). However, in June 2007, the ACC denied SCE s application to construct the Arizona portion of DPV2. On May 14, 2008, SCE filed a Petition for Modification (PFM) of D , requesting that the CPUC authorize SCE to construct the California portion of DPV2, up to and including the Midpoint Switchyard near Blythe, California. SCE s PFM indicated that building the California portion of the project would allow access to potential new renewable and conventional gas-fired generation in the Blythe area, and would help enable California to meet its renewable energy goals. At the time the PFM was submitted, SCE still anticipated building the Arizona portion of the DPV2 project. SCE was concurrently working with Arizona stakeholders and the ACC to see if there would be a basis for seeking a change in the ACC decision denying a Certificate of Environmental Compatibility for the project, and was also pursuing the ability to seek construction authority from the Federal Energy Regulatory Commission (FERC). 8 A Joint Ruling dated July 17, 2008, from the CPUC Assigned Commissioner and Administrative Law Judge directed SCE to amend its PFM to provide additional information demonstrating that construction of the California portion of DPV2 would serve the public interest. In response, SCE submitted an Amendment to the PFM on September 2, 2008, and a further Supplement on September 12, 2008, providing additional information regarding the renewable resources in the Blythe area, as well as updated information regarding the costs and benefits of the Project. During this time, SCE continued to work with stakeholders in Arizona and to evaluate the cost-effectiveness of continuing to pursue licensing of the Arizona portion of the project. In May 2009, SCE concluded that it would not continue to pursue construction of the Arizona portion of the DPV2 project. SCE informed both the Commission and the 8 On May 16, 2008, SCE filed a pre-filing request with the FERC requesting FERC to issue a permit to allow SCE to construct the Arizona portion of DPV2 and attached 11 resource reports as required by 18 CFR 50.5 including: 1) General Project Description; 2) Water Use and Quality; 3) Fish, Wildlife and Vegetation; 4) Cultural; 5) Socioeconomics; 6) Geological Resources; 7) Soils; 8) Land Use, Recreation and Aesthetics; 9) Alternatives; 10) Reliability and Safety; and 11) Design and Engineering. At the time that SCE submitted its request to FERC, it was SCE s belief that the Arizona portion of the project would provide benefits to both Arizona and California.

7 ADVICE 2804-E (U 338-E) November 2, 2012 ACC of its decision and reasoning, and also withdrew its pre-filing request for construction authority from the FERC. 9 In response, on June 3, 2009, the Commission directed that SCE further supplement the PFM regarding (1) the current status of the California-only Project, including any changes to cost estimates, applications before other agencies and the California Independent System Operator (CAISO), power purchase agreements between SCE and generation developers served by the Project, projections of renewable energy resources identified by the Renewable Energy Transmission Initiative (RETI), and any other relevant information; (2) information regarding the status of the CAISO s approval of the California-only Project; and (3) information regarding the status of the Blythe Energy Project Phases I and II generation facilities. SCE filed supplemental information on June 26, SCE did not change or provide new cost estimates, but did escalate to 2009 dollars the costs adopted in D and the costs for the Midpoint Switchyard presented in the PFM. Specifically, SCE did not provide a new estimate for environmental mitigation requirements or revise previous estimates. 10 SCE instead requested that the maximum cost adopted in D not be modified until the final route was known and final engineering-based cost estimate had been completed. In addition to responding to the Commission s requests, SCE included the June 19, 2009 letter from the CAISO setting forth the conditions for CAISO approval of a California-only project (CAISO Letter). The CAISO Letter suggested that the California portion of the project would continue to provide operational and reliability benefits, and confirmed that the CAISO had identified the anticipated need for the project to interconnect new generation. The CAISO concluded that it would agree to construction of the California portion of the project, should certain specified requirements be met On May 18, 2009, SCE withdrew its pre-filing request in PT See SCE s June 26, 2009 Supplemental Information on PFM of D , p The CAISO Letter indicated that the CAISO would agree to construction of the California portion of the project that includes a second line from Midpoint substation to Valley substation once the following have occurred: (1) any combination of the following have occurred for requests for interconnection to the Devers- Palo Verde No. 1 line in the amount of at least 1,030 MW of full capacity generating facilities: (a) LGIAs have been executed by generating facility developers, SCE, and the CAISO pursuant to Section 11 of Appendix U or Y of the ISO tariff; or (b) the ISO has received the initial posting of interconnection financial security by generating facility developers pursuant to Section 9.2 of Appendix Y (subject to Section 6 of Appendix 2 of Appendix Y) of the CAISO tariff; and (2) the CAISO has completed the interconnection studies for the plan of service for at least one of those proposed generating facilities in which the California portion of the proposed Devers-Palo Verde No. 2 project, including the new Midpoint to Valley line, has been identified as needed network upgrade facilities to accommodate that generating facility, pursuant to Section 8 of Appendix U or Section 7 of Appendix Y of the CAISO tariff, and

8 ADVICE 2804-E (U 338-E) November 2, 2012 On November 20, 2009, in D , the Commission granted SCE s request to build the California-only Project, but conditioned start of construction upon CAISO approval. On August 5, 2010, the CAISO sent a letter to the Commission indicating that SCE could proceed with the construction, and on August 9, 2010, the Commission formally authorized SCE to commence construction. 12 As additional renewable generators sought interconnection to the SCE system, planning studies by SCE and the CAISO concluded that the Midpoint Switchyard, which had been renamed to Colorado River Switchyard, should be expanded to facilitate interconnection of the 1,000 MW Blythe Solar Power Project and the 250 MW Genesis and the 250 MW McCoy Solar Energy Projects to the CAISO-controlled grid. In order to accommodate this additional generation, SCE filed a Permit to Construct Application 13 on November 3, 2010 to expand the Colorado River Switchyard to a 500/220 kv substation. 14 The application explained the relationship between the Colorado River Substation Expansion and the Project approved by the Commission in D As part of the Commission s review of the Colorado River Substation Expansion Project in Application (A.) , the Commission undertook a supplemental environmental analysis culminating in a Supplemental Environmental Impact Report (SEIR) to the original DPV2 FEIR. As part of the SEIR, the location of the substation was modified to avoid a sand transport corridor to minimize impacts to the Mojave Fringe-Toed Lizard, which has been designated as a BLM Sensitive species and a CDFG Species of Special Concern. D approved SCE s application and adopted the SEIR, including the recommendation to move the Colorado River Substation 4,000 feet to the southeast of the previously-approved location. In addition, planning studies concluded that another new substation the Red Bluff Substation should be constructed, and that the DCR line should be looped into the Red Bluff Substation. SCE filed a Permit to Construct Application 15 for the Red Bluff 500/220 kv Substation which was granted by the CPUC in D on November 17, (3) an LGIA has been executed by a generating facility developer, SCE, and the CAISO pursuant to Section 11 of Appendix U or Y of the CAISO tariff in which the California portion of the proposed project, including the new Midpoint to Valley line, has been identified as needed network upgrade facilities to accommodate the generating facility for which the LGIA has been executed. 12 Letter from CPUC Executive Director Paul Clanon to SCE Senior Vice President James Kelly dated August 9, A As used in the advice letter, a substation is a switchyard with transformers, or transformation. 15 A

9 ADVICE 2804-E (U 338-E) November 2, 2012 PROJECT PURPOSE DPV2 has evolved from a transmission line intended to bring economic power from Arizona generation to California load to a project that will be used to bring energy from new conventional and renewable generation projects near the California/Arizona border to California load. 16 The changed purpose caused significant modification to the original DPV2 elements. All of the Arizona elements have been eliminated from the Project scope, and additional facilities to support a California-only project to deliver energy from new conventional and renewable generation projects were added. The major modifications included: (1) the elimination of approximately 72 miles of 500 kv transmission line located in Arizona; (2) the elimination of approximately 15 miles of 500 kv transmission line proposed in California; (3) the elimination of facilities associated with the then proposed Harquahala Switchyard; (4) the elimination of shunt capacitors and static variable compensators at the Devers Substation; (5) the addition of the Colorado River Switchyard; 17 (6) the elimination of the planned Arizona series capacitor, and (7) the upgrade to the planned California series capacitor needed to increase the current carrying capacity of the transmission line. These project modifications and the associated environmental impacts were reviewed, analyzed and approved by the Commission through the PFM and the SEIR prepared in connection with A , as reflected in D , 16 The need for the California portion of the DPV2 project has evolved and is no longer based on costeffectiveness. Instead, the Commission concluded that the Project was needed based on unique circumstances, and would support a large and desirable Renewable Energy Transmission Initiative identified as the California Renewable Energy Zone (CREZ). See, D , P. 19 ( Given the potential for resources in the Riverside East CREZ, the substantial work already completed on the Project including certification of the Final EIR the constrained environmental impacts of building in an existing corridor, the lack of environmental opposition, and the uncertainty in terms of delay and cost considering an alternative project to access this CREZ, we find it is necessary, reasonable, and prudent to construct the California-only project. ). The RETI Final Phase 1A Report estimated that the solar energy potential in the Riverside County area (including the Blythe area) had the potential to produce up to 8,750 MW of solar power. RETI Phase 1B Report dated January 2, 2009, Table 1-1 on p The Colorado River Switchyard, or Midpoint as it was called during the DPV2 proceeding, was identified as needed to integrate the Desert Southwest project. While the environmental impacts of the switchyard were analyzed as part of the DPV2 FEIR/FEIS, the Commission did not authorize construction of the switchyard, but instead directed SCE to file for approval to construct when the facility would be required. Accordingly, the costs for Midpoint/Colorado River Switchyard were not included in the maximum and reasonable cost adopted by the Commission in D As discussed above, SCE filed the PFM in 2008 requesting authorization to construction Midpoint, which was approved by the Commission. However, as discussed above, the cost cap adopted in D was not modified at the time D was issued. Instead, SCE was directed to file a cost update after final engineering was completed.

10 ADVICE 2804-E (U 338-E) November 2, 2012 D , or through the project refinements procedures, documentation and reviews conducted by the Commission s Energy Division. 18 DESCRIPTION OF THE PROJECT The major components of DCR include: A new 110-mile 500 kv transmission line between SCE s Devers Substation near Palm Springs and the new Colorado River Switchyard, paralleling the existing Devers-Palo Verde No. 1 (DPV1) transmission line. A new 42-mile 500 kv transmission line between Devers Substation and SCE s Valley Substation in Menifee. The line would be parallel to the existing Devers- Valley transmission line. A new 500 kv Colorado River Switchyard near Blythe at the location described in D A 500 kv series capacitor adjacent to the existing DPV1 series capacitor, and substation upgrades at the Devers and Valley Substations. DESCRIPTION OF ESCALATED AND UPDATED COSTS As authorized by D and D , SCE is seeking an increase in the cost estimate for the California portion of DPV2 to $ million in 2012 dollars including corporate overheads, but excluding financing costs. This updated cost estimate is based on current design specifications, 20 bids received for materials and labor, known 18 In August 2010 and October 2010, SCE submitted Project Refinements Reports for DCR to the CPUC. In May 2011, the CPUC issued a Project Memorandum that stated the refinements simply describe minor changes to project elements previously addressed in the Final EIR/EIS, including but not limited to construction yards, helicopter landing zones, increased tower heights, and the Devers to Valley No. 1 transmission line relocation. The Project Memorandum concluded that the refined Project is consistent with the approved Project and that the modifications were incorporated into the approved Project for mitigation monitoring during construction. See df. 19 SCE considers only the 500 kv portion of the substation, but not the 500/220 kv transformation and 220 kv equipment to be part of the Project, even though SCE is constructing the entire substation facility now. Only the costs associated with the 500 kv portion of the substation are included in this Advice Filing. 20 The cost estimate does not include increased construction costs caused by new requirements. For example, by letter dated August 17, 2012, the CPUC informed SCE that a PFM would be required to address SCE s implementation of modifications to DPV2 in response to the Federal Aviation Administration s recommendations to install marker balls and aviation lighting on approximately 17 towers and 50 transmission spans. On September 5, 2012, SCE submitted a PFM. The cost estimate includes approximately two to three million dollars for the cost of the ball markers and tower lighting; however, it does not include the cost of potential construction delay. If SCE s PFM is not

11 ADVICE 2804-E (U 338-E) November 2, 2012 field conditions, and current environmental requirements and practices. 21 SCE requests that the Commission adopt the updated cost estimate as the approved maximum reasonable and prudent cost for DCR. In Table 1 below, SCE presents a comparison of the costs adopted by the Commission in D to the cost estimates presented in this Advice Filing. All costs in the table are presented in constant 2005 dollars. The first column identifies the major cost categories of the Project. The second column shows the cost estimates for the $545.3 million (2005$) approved by the Commission in January 2007 as the maximum reasonable and prudent cost for the original DPV2 project. 22 The third column of Table 1 shows the costs presented in this Advice Filing for DCR. The fourth column shows the difference in the cost estimates. The penultimate row shows the escalation from 2005 constant dollars to the current year 2012 constant dollars. 23 The updated DCR cost estimate is $944.8 million in constant 2012 dollars including corporate overheads but excluding financing costs. approved by December 20, 2012, wire pulls and tower construction will need to be deferred until after the 2013 nesting bird season. Remaining project construction activities will be shut down for six months (March-August 2013). The cost estimate does not include the increased costs due to construction delay. Additionally, the cost estimate does not include potential post-construction monitoring costs that occur after the line has been energized where the specific requirements are unknown, or have not been agreed to with the responsible agencies. For example, SCE has included the costs for initial re-vegetation activities, including site-restoration and monitoring. SCE has not, however, included other project-driven post-construction costs, such as the costs for post-construction raven control monitoring, in this updated cost estimate where, at time of this filing, the specific requirements are unknown, or have not yet been agreed to with the responsible agencies. SCE reserves to right to capitalize these costs if it is appropriate to do so and as consistent with good accounting practices. 21 The impact of the MMCRP and resource agency interpretations of the environmental requirements associated with the CPCN and other permit conditions may change as both SCE and the agencies address issues related to Project construction. SCE has attempted to estimate these costs, based upon current practices and experiences. However, SCE understands that these practices may change over time. An example of a current issue that could significantly impact the forecast of Project costs is the continuing discussion around appropriate practices related to nesting birds. SCE believes that laws and agency regulations support reasonable flexibility in managing nesting bird buffer zones. However, to the extent that agencies ultimately conclude that the zones contained in nesting bird management plans are restrictive, additional costs may be imposed as a result of either delay or construction restrictions. 22 The costs were first presented in supplemental direct testimony filed in July 2006, and admitted into evidence as Exhibit 31 in A The maximum and reasonable cost adopted by the Commission included corporate overheads, but did not include financing costs. 23 SCE s escalation methodology is presented in Appendix A.

12 ADVICE 2804-E (U 338-E) November 2, 2012 Table 1. Comparison of Cost Estimates (Constant 2005 Dollars, unless otherwise noted) (A) (B) (C) (D) = (C) - (B) Category SCE s 2005 CPCN for DPV2 Advice Filing Update Difference between CPCN Adopted and Advice Filing Update Preliminary Engineering & Licensing $11.7 $25.9 $14.2 Bulk Transmission $255.5 $333.3 $77.9 Environmental Mitigation & Monitoring $0.0 $81.2 $81.2 Substation $156.3 $120.4 ($35.9) Land $7.0 $3.2 ($3.9) Telecommunications $9.8 $4.4 ($5.4) Distribution $0.0 $0.6 $0.6 Contingency $63.0 $85.3 $22.4 Total Direct Forecast (excludes Corp OH): $503.2 $654.3 $151.1 Corporate Overheads: $42.1 $47.0 $4.9 Total: $545.3 $701.3 $156.0 Escalation from 2005$ to 2012$: $243.5 Total Project Cost (2012$): $944.8 Figure 1 below, graphically depicts the changes in the cost estimates for the major categories from the adopted maximum and reasonable costs for DPV2 approved in D and this Advice Filing. Figure 1 also shows the portion of the overall cost increase attributable to escalating the cost estimates from constant 2005 dollars to constant 2012 dollars.

13 ADVICE 2804-E (U 338-E) November 2, 2012 Figure 1 Cost Comparison of DPV2 CPCN Decision and Advice Filing Update For ease of comparison, Table 2 displays the same information as provided in Table 1 with all amounts escalated to constant 2012 dollars.

14 ADVICE 2804-E (U 338-E) November 2, 2012 Table 2. Comparison of Cost Estimates (Constant 2012 Dollars) (A) (B) (C) (D) = (C) - (B) Category SCE s 2005 CPCN for DPV2 Advice Filing Update Difference between CPCN Adopted and Advice Filing Update Preliminary Engineering & Licensing $15.7 $34.8 $19.2 Bulk Transmission $344.2 $449.1 $104.9 Environmental Mitigation & Monitoring $0.0 $109.4 $109.4 Substation $210.6 $162.1 ($48.4) Land $9.5 $4.3 ($5.2) Telecommunications $13.1 $5.9 ($7.3) Distribution $0.0 $0.8 $0.8 Contingency $84.8 $115.0 $30.2 Total Direct Forecast (excludes Corp OH): $677.9 $881.5 $203.6 Corporate Overheads: $56.8 $63.3 $6.6 Total: $734.6 $944.8 $210.2 The updated cost estimates discussed in the following sections are all presented in constant 2012 dollars. For each major cost category, SCE explains what is included in the category, and discusses the major sources of the cost differences for each category. Environmental considerations (direct and indirect) are a significant factor in the cost increases for several of the categories. Appendix B provides a more integrated discussion of the manner in which environmental considerations and compliance have affected overall project costs.

15 ADVICE 2804-E (U 338-E) November 2, 2012 Preliminary Engineering and Licensing DPV2 CPCN (2012$, millions) Advice Filing Update (2012$, millions) Difference between DPV2 CPCN and Advice Filing Update (2012$, millions) $15.7 $34.8 $ 19.2 The costs included within the Preliminary Engineering and Licensing category relate to the costs of developing the Project and preparing numerous documents required for the project licensing filings such as the Proponent s Environmental Assessment (PEA) for the CPCN Application. The costs of consultants hired by the CPUC, BLM and the USFWS for work on the licensing filings are also included in this cost category. All of the activities in this category have been completed, and there are no additional costs forecast in this area. The Preliminary Engineering and Licensing activities and costs fall into the following subcategories: Preliminary Engineering and Design: $ 12.8 million (2012$) for the development of project design criteria, the scope of work, technical specifications and studies, and other engineering activities. This subcategory primarily includes SCE and contract resource costs related to performing studies on the proposed line routes and substation sites, developing one-line diagrams and plot plans to describe the required work, performing geotechnical surveys to assess subsurface conditions, performing load flow analysis to assess equipment sizing requirements, field surveys and performing other technical work. Environmental: $ 7.0 million (2012$) for research, surveys, studies, and reports to document existing environmental conditions and regulations required to support the Proponent s Environmental Assessment (PEA) document used to obtain agency licenses. This primarily includes SCE labor and contract costs related to complying with the California Environmental Quality Act (CEQA) and NEPA, including all analyses required to address all environmental criteria such as biological, cultural, air quality, water quality and hazardous materials. Activities include reviewing plans and records, performing surveys, developing environmental documents and reports, consulting with agencies, and performing other environmental-related work. Project Management and Support: $ 10.0 million (2012$) for the SCE and contract resources to manage and control the project, and provide the information needed for the licensing and CPCN permitting activities. During the Preliminary Engineering and Licensing phase, the project management team coordinates the siting process, preliminary engineering scope development, environmental document development, regulatory filings, team meetings, management reporting and other licensing activities. The project manager has overall responsibility from project initiation to successful completion. Other

16 ADVICE 2804-E (U 338-E) November 2, 2012 support resources include project analysts, schedulers, cost engineers, consultants and other personnel. This category also includes the work performed by several other SCE departments including Corporate Real Estate, Law, 24 Transmission Planning, Resource Planning, Grid Contracts, Regulatory Affairs, Public Affairs, Corporate Communications, Electric and Magnetic Field (EMF), and Supply Chain related to performing property assessments and right checks for new land and easement requirements, performing surveys and mapping, application and testimony development, economic studies, negotiating and obtaining agreements, public involvement activities, EMF studies and development of the Field Management Plan, and many other support functions. Agency Costs: $ 5.0 million (2012$) for the costs incurred by the CPUC, BLM and USFWS to approve the licensing and permit applications. These costs include both agency staff costs as well as any consultants. The $19.2 million (2012$) difference between the estimate approved in D and the estimate for Preliminary Engineering and Licensing presented in this Advice Filing results primarily from the changes in the Project purpose and design discussed earlier and the fact that the approval of agency licenses and refinements to the related environmental documents was more lengthy than originally anticipated. SCE initiated the Preliminary Engineering and Licensing work for DPV2 in March 2002, and originally assumed the CPCN and related environmental approvals would be obtained in While the CPCN decision was received in early 2007, the additional California licensing activities resulting from the ACC denial of the Certificate of Environmental Compatibility 25 and PFM, which took place in 2008, 2009 and 2010, are included in this cost category. A portion of the costs associated with the SEIR are also included here. The major Project changes affecting the increased costs for Preliminary Engineering and Licensing are: The substitution of Devers-Valley for the west of Devers segment as the recommended alternative for DPV2 26 The modification of DPV2 to be a California-only project Costs of outside counsel only. 25 All of the costs associated with the Arizona portion of DPV2, including the preliminary engineering and licensing costs, are excluded from the updated Project cost estimate updates in this Advice Filing. On October 28, 2011, in Docket No. ER12-239, SCE filed with FERC a request for abandoned plant recovery of the Arizona costs. A settlement was reached with all parties and SCE filed the settlement with FERC on July 2, The settlement was approved by FERC on August 30, SCE s CPCN application originally proposed upgrades to four transmission lines west of Devers Substation that crossed over the existing lands of the Morongo Band of Mission Indians. Because continued use over Morongo tribal lands was deemed not feasible, SCE performed additional engineering, technical studies and environmental work related to the Devers-Valley No. 2 Alternative.

17 ADVICE 2804-E (U 338-E) November 2, 2012 The location change for the Colorado River substation to accommodate concerns related to the Mojave Fringe-Toed lizard Bulk Transmission DPV2 CPCN (2012$, millions) Advice Filing Update (2012$, millions) Difference between DPV2 CPCN and Advice Filing Update (2012$, millions) $344.2 $ $104.9 The costs included in the Bulk Transmission category involve the construction of the 500 kv line from Valley to Devers and the 500 kv line from Devers to the Colorado River Substation. The costs of looping the existing DPV1 500 kv line into the Colorado River Substation are also included in the bulk transmission line costs. In addition, a segment of DPV1 must be moved to accommodate the change in location for the Colorado River Substation ordered in D The cost of this DPV1 relocation is also included in the DCR cost category. While both the DCR 500 kv line and the existing DPV1 500kV line will be looped into the Red Bluff Substation, the costs of these loop-ins are not part of the costs of DCR, but rather are included in the cost of the Red Bluff Substation project, approved by the Commission in D SCE has awarded a contract for the construction of the 500 kv bulk transmission lines to PAR Electrical Contractors, Inc. (PAR). SCE s cost estimate for the transmission line components provided in this Advice Filing is based on the contract with PAR, entered into as a result of a competitive procurement process. 28 PAR and the other bidders were provided detailed information regarding likely compliance requirements, and the contract is designed to assign to the contractor much of the cost of construction-related risk due to compliance. 29 The contract costs are significantly higher than SCE had originally estimated. 27 SCE prepared and filed two Projects Refinement documents with the CPUC in 2010 that included a description of the changes, equipment and facility modifications, geographic changes and the related environmental effects of these refinements. Preparation of these documents required additional work and costs for each of the Preliminary Engineering & Licensing subcategories. 28 To begin the competitive solicitation, SCE prepared detailed bid specifications for the transmission line components, which specified the tower locations, tower design, foundation design, and conductor requirements. Specifically, SCE prepared a 2011 Specification, E (2011 Spec). The 2011 Spec consisted of over 500 pages, including 58 appendices related to environmental compliance requirements. The bid specification included detailed description of the transmission line design, and the biological and cultural requirements. The bid contractors were informed that they would be required to implement and comply with all requirements and conditions. 29 However, any significant change in scope, Act of God or delay may be grounds for a change order. Additional compliance requirements beyond the scope outlined in the 2011 Spec may also result in a change order increasing transmission line construction costs.

18 ADVICE 2804-E (U 338-E) November 2, 2012 SCE believes that a major driver for the higher estimated construction costs is the requirement that the contractor absorb the construction-related risks associated with environmental and permit compliance. SCE asked PAR if the construction-related risks associated with environmental and permit compliance contributed significantly to the increased estimates for transmission line construction. The information obtained from PAR is summarized in Appendix B. Also included in this category are the costs of material yards and handling of transmission line equipment, conductor pull sites, construction support, and of Owner s Engineer services. The Owner s Engineer provides construction planning, construction safety program oversight, material yard management and claims support, and general construction management services. Other major differences from the CPCN estimate to this update include: elimination of the 500 kv transmission line segment from the Colorado River to Harquahala Switchyard, increases in the material costs, and increases in the number of material yards needed. SCE has spent approximately $155.1 million (2012$) through June 2012 on Bulk Transmission or approximately 35 percent of the estimated costs for this category. The recorded costs represent costs spent for final engineering, materials, Owner s Engineer and construction. SCE has completed final engineering for the Bulk Transmission lines and has begun constructing both the 110-mile 500 kv transmission line between Devers and the new Colorado River Substation and the 42-mile 500 kv transmission line between Devers and Valley substations. The estimate for the remaining costs in this category is based on the construction schedule, and the terms and conditions for the transmission line construction contract and related support. 30 More detailed information about the transmission line cost estimate is presented in Appendix C. The estimated costs for bulk transmission has increased approximately by $104.9 million (2012$) from the $344.2 million (2012$) reflected in the CPCN. As mentioned above, the primary driver of higher construction costs is due to environmental compliance and mitigation requirements. Additional discussion regarding the increased construction costs can be found in Appendix B. 30 The construction contract includes pre-established costs for units of work, such as foundation installation and tower assembly.

19 ADVICE 2804-E (U 338-E) November 2, 2012 Environmental Mitigation and Monitoring DPV2 CPCN (2012$, millions) Advice Filing Update (2012$, millions) Difference between DPV2 CPCN and Advice Filing Update (2012$, millions) $0 $ $ The cost components included in the Environmental Mitigation and Monitoring category include the costs of land mitigation, 31 the cost of monitors required by the FEIR and other federal and state permits, preparation of post-cpcn environmental documents and reports such as mitigation plans, variances, notices to proceed requests and temporary extra workspace requests, the cost of NOx emission credits, the cost of geographic information system (GIS) support and the staff needed to support environmental compliance. SCE uses a combination of employees, direct contractors and consultants 32 to staff environmental compliance. SCE estimates that the direct cost for environmental compliance is approximately $109.4 million, 2012 constant dollars, not including corporate overheads. This amount excludes the preliminary licensing costs discussed above. 33 The costs include the following items: Field Activities & Reporting: $73.0 million. This amount includes approximately $42.1 million for biological field activities and reporting, $7.9 million for archaeological field activities and reporting, $4.2 million for environmental field activities and reporting, and $16.8 million is for site restoration field activities and reporting. The amount for site restoration field activities and reporting includes weed abatement, seeding activities, site restoration monitoring and associated reports. It excludes long term operations and maintenance (O&M) requirements for site restoration costs (weed abatement, seeding activities, site restoration monitoring and reporting) after CPUC/Aspen monitoring costs are approximately $1.9 million, and San Bernardino National Forest monitoring costs are approximately $0.1 million. Land Mitigation: $12.9 million. This amount includes an estimated $12.9 million for land mitigation costs to purchase approximately 1,891 acres for desert tortoise, fringe-toed lizard, and milk-vetch habitat, as well as other costs such as 31 SCE is required to purchase mitigation land to comply with the requirements of the USFWS Biological Opinion, which was an appendix to the CPUC FEIR for the project. In addition, the SEIR required mitigation for disturbance to the Mojave Fringe-Toed lizard habitat. 32 CH2M Hill is SCE s lead consultant on environmental compliance and related activities. 33 The preliminary engineering and licensing cost category generally covers the period from 2004 through 2009.

20 ADVICE 2804-E (U 338-E) November 2, 2012 contributions to the National Fish and Wildlife Foundation and the California Department of Parks and Recreation. Environmental Compliance Documents: $7.1 million. This amount includes approximately $7.1 million for the development of environmental compliance documents such as mitigation plans, notice to proceed requests, authorizations to proceed, permits, variances, temporary extra workspaces, addendums and other regulatory compliance reports. Environmental Coordination and Management : $16.4 million. This includes environmental coordination and management, geographic information system support, contract and construction specifications and procedures, document tracking tools, material, and direct allocation costs. SCE did not include a forecast of direct environmental mitigation and monitoring costs in the cost estimates provided in the DPV2 CPCN application (A ). As it had done in A , SCE had requested the ability to update the costs for environmental mitigation and monitoring via an advice letter. 34 SCE s CPCN stated that it did not include additional costs due to mitigation measures, 35 and requested that it be allowed to update the Commission on the costs via an advice letter. The Commission agreed to this process in D Appendix B provides further discussion of the costs of environmental mitigation and compliance. Appendix B also describes the difference in the emphasis on environmental mitigation and monitoring today compared to SCE s experience with both the Devers-Palo Verde No. 1 transmission line and SCE s efforts to license a second Devers-Palo Verde line in the late 1980 s. To help illustrate the significance of the difference in emphasis, Appendix B provides a comparison between a tower constructed as part of the Devers-Palo Verde Number 1 Line in 1985 and an adjacent tower to be constructed as part of DCR. SCE has spent approximately $48 million (2012$) through June 2012 on Environmental Mitigation and Monitoring or approximately 44 percent of the estimated costs for this category. The recorded costs represent costs for preparing environmental documents, compliance support, land mitigation and costs for monitors. Prior to commencing construction, SCE was required to prepare its mitigation plans and submit notice to proceed requests to the CPUC for approval. SCE has also submitted payments for land 34 In 1988, the Commission issued a CPCN for DPV2 that stated that SCE could seek any adjustments in adopted project costs due to: (1) anticipated delays in starting the project or inflation, (2) final design criteria, and (3) the adopted mitigation measures and mitigation monitoring program. (D , Ordering Paragraph 12.) 35 Id. at 19 ( For example, if the Bureau of Land Management ( BLM ) or the Commission imposes mitigation measures, the Commission should address an increase in the cost cap pursuant to Pub. Util. Code Section (b). ). 36 See, D , Ordering Paragraph 12.

21 ADVICE 2804-E (U 338-E) November 2, 2012 mitigation requirements and has begun construction, requiring compliance monitoring. The remaining costs were estimated based upon a forecast of the construction schedule and number of crews requiring monitors, monitor labor rates and estimated hours for each type of monitoring activity. Substation DPV2 CPCN (2012$, millions) Advice Filing Update (2012$, millions) Difference between DPV2 CPCN and Advice Filing Update (2012$, millions) $210.6 $ ($ 48.4) The costs in the Substation category include the modification and additions to the Devers and Valley Substations, the cost of the new Colorado River Switchyard, and the costs of the new series capacitor. A significant reason for the reduction in the cost estimates for the Substation category is the elimination of all construction at the Harquahala Switchyard (the terminus point for the Arizona portion of DPV2), a portion of the construction at Devers Substation, including the static var compensators (SVCs), shunt capacitors and Arizona series capacitor that were needed for the Arizona portion of the project, but are not needed for the California-only Project. 37 The major subcategories of costs include: $31.2 million (2012$) for modifications/additions to the Devers and Valley Substations, including new line positions at both substations, a bus extension at Devers, circuit breaker upgrades at Devers, the addition of breakers to the existing shunt reactors, and line protection equipment such as relays. The estimate also includes minor changes at the Palo Verde switchyard facility. $97.4 million (2012$) for the Colorado River Switchyard portion of the Colorado River Substation. $33.4 million (2012$) for the new series capacitor east of Devers Substation and adjacent to the existing DPV1 series capacitor. 37 The line to Harquahala, together with the existing DPV kv line, provided a low impedance path through which power surges emanating from critical contingencies could flow and overly stress the electric system in Devers area. Originally, the SVC provided mitigation for possible voltage collapse at Devers Substation under these adverse operating conditions. The absence of the Arizona portion of the 500 kv line restricted the flow from these power surges sufficiently to operate the system reliably under contingency conditions without a new SVC or shunt capacitors. As a result of these studies, the SVC and shunt capacitors were removed from the DCR scope of work.

22 ADVICE 2804-E (U 338-E) November 2, 2012 Approximately 60 percent of the substation category cost is attributable to the cost of constructing the Colorado River Switchyard. The estimated costs for the Colorado River Switchyard have increased from the estimates presented in the 2008 PFM. Major contributors to the cost increases include the need to redo the engineering and design for the substation associated with the decision to move the location of the substation 4,000 feet to the southeast to avoid the sand transport area affecting the Mojave Fringe- Toed lizard. 38 Additionally, the estimates were revised to reflect the contracted cost for civil construction and contracted material costs. Costs associated with interconnecting the generators are not included in the DCR cost estimate for this Advice Filing. As originally proposed, the DPV2 series capacitor was to be designed with the same amperage as the existing DPV1 series capacitor (2,700 amps). However, the power delivery requirement from queued renewable energy now exceeds the amount of generation that would have been imported over DPV2. During the engineering project development phase it was determined that this increase in power delivery required reassessing the amperage of California series capacitors near Devers, specifically, the new series capacitor to be installed on the DCR line. The assessment indicated the need to increase the series capacitor amperage to 3,800 amps. SCE has spent approximately $48.4 million (2012$) through June 2012 or approximately 30 percent of the estimated costs for this category. The recorded costs represent costs for engineering and purchased materials. SCE has not yet completed final engineering for the Substation category. The remaining costs are based on estimates of work derived from the current scope of the Project and SCE s experience with the cost to build other 500 kv substations. More detailed information related to the substation cost estimate is presented in Appendix C. The estimated costs for substations have decreased by approximately by $48.4 million (2012$) from the $210.6 million (2012$) reflected in the CPCN. A significant reason for the reduction in the cost estimates for the Substation category is the elimination of all construction at the Harquahala Switchyard (the terminus point for the Arizona portion of DPV2), a portion of the construction at Devers Substation, including the SVCs, shunt capacitors and Arizona series capacitor that were needed for the Arizona portion of the project, but are not needed for the California-only Project. Land DPV2 CPCN (2012$, millions) Advice Filing Update (2012$, millions) Difference between DPV2 CPCN and Advice Filing Update (2012$, millions) $9.5 $4.3 ($ 5.2) 38 See SEIR adopted by the Commission in D

23 ADVICE 2804-E (U 338-E) November 2, 2012 The costs in this section include the real estate acquisition for transmission, telecommunications and switchyard facilities. The costs would also include related activities such as real estate surveys, title search, escrow services, condemnation and SCE labor to support these activities. The cost reduction is due to the elimination of the Arizona scope in the current estimate. This includes removing the property near Blythe and Harquahala Mountain for telecommunication facilities, removing the property for 25 miles of the Harquahala-Hassayampa 500 kv transmission line, and removing property from the California and Arizona border to the Harquahala facility. SCE has spent approximately $3.7 million ($2012) through June 2012, or approximately 86 percent of the estimated costs for this category. The recorded costs represent costs for purchasing land including related surveys, title searches and escrow services. The remaining costs were estimated based upon additional land rights for telecommunication facilities. Telecommunications DPV2 CPCN (2012$, millions) Advice Filing Update (2012$, millions) Difference between DPV2 CPCN and Advice Filing Update (2012$, millions) $13.1 $5.9 ($7.3) The costs in this category are for telecommunications facilities required to operate the transmission grid. For example, the new Colorado River switchyard/substation requires communication equipment which will enable SCE s grid operations center to operate the switchyard in order to maintain reliability for the transmission network. The scope of telecommunications work is directly influenced by the scope of transmission and substation work. Similar to the Land category, the scope of telecommunication work has been reduced due to the elimination of Arizona scope. SCE has spent approximately $1.9 million through June 2012, or approximately 32 percent of the estimated costs for this category. The costs includes engineering, materials and construction of the planned telecommunications equipment at various locations such as Valley, Devers, Mirage, Vista, Mira Loma and Colorado River substations, and the California series capacitor site.

24 ADVICE 2804-E (U 338-E) November 2, 2012 Distribution DPV2 CPCN (2012$, millions) Advice Filing Update (2012$, millions) Difference between DPV2 CPCN and Advice Filing Update (2012$, millions) $0.0 $0.8 $0.8 The costs in the Distribution category are for a new 33 kv line extension and the relocation of existing distribution lines. The new distribution line extension from the existing 33 kv Chanslor circuit to the Colorado River Switchyard facility is approximately 2 miles in length and will provide station light and power. The relocation of existing distribution lines is required for the installation of the new series capacitors at the DCR California Series Capacitor site 14 miles west of Red Bluff Substation. SCE has spent approximately $520 thousand through June 2012, or approximately 65 percent of the estimated costs for this category. The recorded costs represent a portion of the distribution line extension construction and related engineering, material and support activities. The remaining costs were estimated based upon the distribution line relocation near the series capacitor site, completion of the remaining line extension construction, and completion of distribution facilities which can only be completed after installation of the Mechanical Electrical Equipment Room at the Colorado River Switchyard. Contingency DPV2 CPCN (2012$, millions) Advice Filing Update (2012$, millions) Difference between DPV2 CPCN and Advice Filing Update (2012$, millions) $84.8 $115.0 $30.2 Contingency is included in the Project to address uncertainties associated with the level of scope definition, changes due to field conditions, inclement weather, additional environmental restrictions that emerge during the construction process, and other unknowns that may occur subsequent to the completion of the estimate. Contingency is not intended to cover every unforeseen circumstance as this would require unreasonably high levels of contingency to cover catastrophic events, workforce strikes, major scope changes driven by external factors, and force majeure. Contingency also is not intended to cover changes in Project scope. For this Advice Filing, SCE included a 15 percent contingency amount. This amount is reasonable given the remaining uncertain elements of cost that remain a risk factor for execution.

25 ADVICE 2804-E (U 338-E) November 2, 2012 Examples of these risk factors include: The level of scope for the substation elements. Final engineering is not complete. Upon completion, the majority of construction will go through the procurement process to bid and award similar to the transmission construction process described earlier. Risk elements remain associated with potential changes that can emerge as detailed engineering and design become available as well as actual construction bids. Change associated with field conditions during the construction process that were not identified in the design process. Although a geotechnical evaluation was made of soil conditions along the project route, the actual conditions at each tower site are not known until drilling is completed. Unfavorable soil conditions may extend the construction time or require foundation redesign. In addition, there could be unforeseeable events that affect construction. For example, in March of 2012, human remains were discovered during excavation to construct the road to the Colorado River Switchyard. Upon further identification, the remains were identified as Native American. Construction on the road was suspended until the issue could be resolved with the local tribe. The direct and indirect costs associated with environmental requirements can change daily as environmental pre-construction surveys are completed and issues are identified. For example, active bird nests have been discovered during construction. Consistent with CDFG requirements and the MMCRP, SCE s contractor may be precluded from proceeding with construction in the affected areas. The cumulative effect of such delays may affect the overall costs for the Project SCE believes that given the project is in the early stages of construction, and the risk elements that remain, a 15 percent contingency amount is reasonable to cover the uncertain elements of costs within the defined Project scope. 39 Corporate Overheads DPV2 CPCN (2012$, millions) Advice Filing Update (2012$, millions) Difference between DPV2 CPCN and Advice Filing Update (2012$, millions) $56.8 $63.3 $ A significant change in regulatory requirements, such as a change in the way nesting bird buffer reduction requests are managed, would not be within the scope of normal contingency. If such a change were ultimately imposed by the CPUC or other permitting agency, the costs associated with Project construction could be increased significantly. See also, discussion in footnote 20 and 21, above.

26 ADVICE 2804-E (U 338-E) November 2, 2012 Corporate overheads include administrative and general (A&G), pensions and benefits (P&B), payroll taxes, injuries and damages, and property taxes that are allocated to the capital orders. These costs are not directly recorded to the capital orders and are allocated to reflect the corporate functions supporting the construction work. A&G, for example, includes (1) corporate departmental expenses associated with day-to-day operations such as salaries, office supplies, and related expenses; and (2) expenses not directly incurred by any single department such as insurance premiums. A&G is charged to the capital orders by applying the company-wide composite weighted average A&G capitalization rate by the A&G expense and allocating these costs monthly to capital orders based on the total capital costs of the Project. The cost increase is attributable to the increased costs of the Project as Corporate overheads are factored based on the Project cost components. SCE has spent approximately $15.3 million (2012$) through June 2012 or approximately 24 percent of the estimated costs for this category. The recorded costs represent the amount of corporate overheads allocated to the capital orders. The remaining costs were estimated based upon applying a gross-up factor to the Project cost components. The factor assumed for forecasted corporate overheads is 7.66 percent.

27 ADVICE 2804-E (U 338-E) November 2, 2012 Escalation Methodology and Financing Costs A large part of the cost increase for the project is merely due to the escalation to account for inflation by deferring the project. In Appendix A, SCE explains its capital escalation methodology and describes the total amount of financing costs projected for DCR. SCE did not include financing costs in the cost calculations for this advice letter. OTHER This advice filing will not increase any rate or charge, cause the withdrawal of service, or conflict with any other schedule or rule. REQUEST FOR TIER 2 TREATMENT The General Order (G.O.) 96-B contains the requirements for Advice Filings, including the specific Energy Industry Rules. Energy Industry Rule 5 outlines the Tier Classifications for Advice Filings. Although it could be asserted that this cost update should be considered a compliance-type filing falling with Industry Rule 5.1(1), SCE believes that the more appropriate classification would be Tier 2 a request that would otherwise be appropriate for Tier 1, but for which the utility submitting the advice letter requests review and disposition under Tier 2 as provided in Rule 5.2(7). In addition, while Tier 2 Advice Filings are typically Effective after Staff Approval, SCE requests that this Advice Filing be Effective after Commission Approval in accordance with General Rules and of G.O. 96-B. The actions requested herein require more than ministerial action, and thus disposition on the merits should be by Commission resolution. APPENDICES Appendices A. Escalation Methodology and Financing Costs B. Description of Environmental Related Costs C. Description of Bulk Transmission and Substation Costs D. Cost Accounting Overview EFFECTIVE DATE This advice filing will become effective on upon Commission resolution.

28 ADVICE 2804-E (U 338-E) November 2, 2012 NOTICE Anyone wishing to protest this advice filing may do so by letter via U.S. Mail, facsimile, or electronically, any of which must be received no later than 20 days after the date of this advice filing. Protests should be mailed to: CPUC, Energy Division Attention: Tariff Unit 505 Van Ness Avenue San Francisco, California EDTariffUnit@cpuc.ca.gov Copies should also be mailed to the attention of the Director, Energy Division, and Room 4004 (same address above). In addition, protests and all other correspondence regarding this advice letter should also be sent by letter and transmitted via facsimile or electronically to the attention of: Akbar Jazayeri Vice President of Regulatory Operations Southern California Edison Company 8631 Rush Street Rosemead, California Facsimile: (626) AdviceTariffManager@sce.com Leslie E. Starck Senior Vice President c/o Karyn Gansecki Southern California Edison Company 601 Van Ness Avenue, Suite 2030 San Francisco, California Facsimile: (415) Karyn.Gansecki@sce.com There are no restrictions on who may file a protest, but the protest shall set forth specifically the grounds upon which it is based and shall be submitted expeditiously. In accordance with Section 4 of GO 96-B, SCE is serving copies of this advice filing to the interested parties shown on the attached GO 96-B and A service lists. Address change requests to the GO 96-B service list should be directed by electronic mail to AdviceTariffManager@sce.com or at (626) For changes to all other service lists, please contact the Commission s Process Office at (415) or by electronic mail at Process_Office@cpuc.ca.gov. Further, in accordance with Public Utilities Code Section 491, notice to the public is hereby given by filing and keeping the advice filing at SCE s corporate headquarters.

29 ADVICE 2804-E (U 338-E) November 2, 2012 To view other SCE advice letters filed with the Commission, log on to SCE s web site at For questions, please contact Ryan Stevenson at (626) or by electronic mail at ryan.stevenson@sce.com. Southern California Edison Company AJ:rs:jm Enclosures Akbar Jazayeri

30 CALIFORNIA PUBLIC UTILITIES COMMISSION ADVICE LETTER FILING SUMMARY ENERGY UTILITY MUST BE COMPLETED BY UTILITY (Attach additional pages as needed) Company name/cpuc Utility No.: Southern California Edison Company (U 338-E) Utility type: Contact Person: Darrah Morgan ELC GAS Phone #: (626) PLC HEAT WATER Disposition Notice to: EXPLANATION OF UTILITY TYPE ELC = Electric GAS = Gas PLC = Pipeline HEAT = Heat WATER = Water (Date Filed/ Received Stamp by CPUC) Advice Letter (AL) #: 2804-E Tier Designation: 2 Subject of AL: Southern California Edison Company Update Regarding the Cost-Estimate for the California Portion of the Devers-Palo Verde No. 2 Transmission Line Project Keywords (choose from CPUC listing): Compliance, Transmission Lines AL filing type: Monthly Quarterly Annual One-Time Other If AL filed in compliance with a Commission order, indicate relevant Decision/Resolution #: Decisions and Does AL replace a withdrawn or rejected AL? If so, identify the prior AL: Summarize differences between the AL and the prior withdrawn or rejected AL 1 : Confidential treatment requested? Yes No If yes, specification of confidential information: Confidential information will be made available to appropriate parties who execute a nondisclosure agreement. Name and contact information to request nondisclosure agreement/access to confidential information: Resolution Required? Yes No Requested effective date: Upon Commission Resolution Estimated system annual revenue effect: (%): Estimated system average rate effect (%): No. of tariff sheets: -0- When rates are affected by AL, include attachment in AL showing average rate effects on customer classes (residential, small commercial, large C/I, agricultural, lighting). Tariff schedules affected: Service affected and changes proposed 1 : Pending advice letters that revise the same tariff sheets: 1 Discuss in AL if more space is needed.

31 Protests and all other correspondence regarding this AL are due no later than 20 days after the date of this filing, unless otherwise authorized by the Commission, and shall be sent to: CPUC, Energy Division Attention: Tariff Unit 505 Van Ness Ave., San Francisco, CA Akbar Jazayeri Vice President of Regulatory Operations Southern California Edison Company 8631 Rush Street Rosemead, California Facsimile: (626) Leslie E. Starck Senior Vice President c/o Karyn Gansecki Southern California Edison Company 601 Van Ness Avenue, Suite 2030 San Francisco, California Facsimile: (415)

32 Appendix A Cost Escalation Method and Financing Costs

33 Purpose ESCALATION METHOD AND FINANCING COSTS The purpose of this appendix is to 1) explain and justify the escalation rates used to inflate and deflate historical Project expenditures for the years 2005 through 2011 and forecast Project expenditures for the years 2012 through 2014 and 2) provide an estimate of the costs associated with financing the development and construction of the Project. The escalation section summarizes the rates developed for this advice filing to convert nominal recorded and forecast costs to constant dollars. Consistent with the Commission s direction in D , 1 this section also describes the escalation methodology, sources used to develop the escalation rates and explains why this method is more appropriate than using a Bureau of Labor Statistics Consumer Price Index (CPI). The financing cost section explains the estimate of the Project s financing costs and the methods used to calculate these costs. Consistent with Commission practice, 2 D and D , SCE is providing an estimate of its financing costs to provide full disclosure to the Commission, and is not including these costs to estimate the total maximum reasonable and prudent costs. In D , the Commission did not include financing costs to establish the level of total maximum reasonable and prudent costs. 3 D explained that SCE s advice letter filing should update the AFUDC projected for the California-only project, explain how it was calculated, including the rate used to calculate AFUDC. 4 1 See D , pp See, for example, Decision at p. 14, Finding of Fact No. 19 and Conclusions of Law No. 10. The Commission stated that Based upon SCE s explanations in the Petitions and the Amendment, we do not include this AFUDC estimate in the maximum cost. However, because the cost of financing is a significant portion of the costs of a transmission project which is ultimately recovered from ratepayers, we find that such financing costs, either in the form of CWIP or AFUDC, should be fully disclosed in Commission proceedings prior to project approval. 3 See D , Ordering Paragraph No. 10, mimeo at 115 (2007). 4 D at p. 26. A-1

34 Project Escalation Methodology SCE s estimated Project costs are presented in current-year constant 2012 dollars. Restating the Project costs in constant dollars provides greater comparability to evaluate costs recorded over time. In D , the Commission adopted a maximum cost for DPV2 of $545 million in constant 2005 dollars. In assessing compliance with this cost cap, SCE has presented a comparison of the DPV2 adopted maximum cost to the current Project cost estimate in constant 2005 dollars. 5 Setting the maximum cost in constant dollars has been endorsed by the Commission and has been an acceptable practice in assessing compliance against an authorized maximum cost. SCE s Project escalation methodology consists of separately escalating and deescalating the Project s labor and nonlabor related expenditures by separate labor and nonlabor escalation rates. The nonlabor escalation rate is based on historical transmission capital escalation rates from the Handy-Whitman Index of Public Utility Construction Costs, 6 and IHS Global Insight Power Planner 7 for forecasts of transmission capital escalation rates. The labor escalation rate is based on SCE s historical and forecast labor costs. These labor and nonlabor escalation rates are then blended by calculating a weighted average escalation rate based on the Project s historical and forecast annual labor and nonlabor related expenditures. Labor Escalation SCE escalates and deescalates the Project labor costs using SCE s historical average hourly earnings escalation rates for transmission workers for the years 2005 to 2011 and forecast transmission labor escalation rates for the years 2012 to These labor escalation rates are consistent with SCE s labor escalation rates used in its general rate case proceedings. 8 Historical Labor Escalation : SCE has recorded payroll data for labor expenses that include wages paid for straight time labor, overtime labor, and double time labor and corresponding hours by these categories. To estimate the average hourly earnings, effective hours are calculated as the sum of: (i) straight time hours; (ii) overtime hours multiplied by one and one-half; and, (iii) double time hours multiplied by two. Wages are summarized across three categories and are then divided by effective hours worked to calculate average hourly earnings. This method removes the effect of 5 See Advice Letter, Table 1. 6 The Handy-Whitman Indexes, published continuously since 1924, provide historical cost trends and are prepared specifically for electric, gas and water utilities. 7 SCE purchases economic projection data from IHS Global Insight, an industry standard source for providing forecasts of Handy-Whitman indexes. 8 See, for example, A , SCE-10, Volume 1, p. 63. A-2

35 year to year variations in overtime and double time hours worked and provides an accurate basis for determining SCE s historical labor related price changes. Forecast Labor Escalation : For 2012 through 2014, SCE applied the same forecast labor escalation approach as it has used in its previous general rate cases. For employee categories where SCE knows its future labor costs, as in the case of represented employees as part of a collective bargaining agreement, SCE utilized the collective bargaining agreements as a basis for labor escalation for the represented workers employee category. For non-represented employees, SCE used labor escalation rates provided by IHS Global Insight s Power Planner. 9 Table A-1 below shows the categories of workers, the shares of total wages and salaries they earn, and the IHS Global Insight variable used to forecast the employee category. These weights are used to construct the weighted average labor escalation rates for 2012 through Table A-1 Correspondence Between Employee Categories And Global Insight Variables Employee Category Physical Workers Clerical Workers Managers and Supervisors Professional and Technical Global Insight Variable Variable Description CEU Utility Price and Wage Indicators, AHE, Transmission and Distribution Workers CEU Utility Price and Wage Indicators, AHE, Transmission and Distribution Workers ECIPWMBFNS Employment Cost Index, Managers and Administrators ECIWSPWP & TNS Employment Cost Index, Wages and Salaries, Professional and Technical Workers Total Wage Bill Share 24.1% 8.6% 25.7% 41.6% 100.0% Nonlabor Escalation SCE escalates and deescalates the Project nonlabor costs by using the Handy- Whitman Index of Public Utility Construction Costs, Transmission Production Plant Pacific region for the historical years ( ) and IHS Global Insight s Construction Cost Indexes for Transmission Plant Pacific region for the years 2012 through The Commission has used these indexes in previous proceedings to calculate escalation of construction costs and capital additions IHS Global Insight Power Planner Operation and Maintenance Costs, Quarter , Managers and Administrators and Professional and Technical Workers. 10 SCE has used Handy-Whitman indexes in various general rate cases. Pacific Gas and Electric, San Diego Gas & Electric and Southern California Gas use various Handy-Whitman indexes in the construction of their respective escalation indexes in their general rate cases. A-3

36 Historical Nonlabor Escalation - Handy-Whitman : SCE uses the Handy- Whitman Index of Public Utility Construction Costs Transmission Production Plant to estimate the historical Project nonlabor construction costs. For this Advice Filing, SCE used Transmission Production Plant - Pacific region - bulletin # Forecast Nonlabor Escalation - IHS Global Insight Forecast of Construction Costs Transmission Plant Pacific region, : SCE purchases economic projection data from IHS Global Insight, 12 an industry accepted source for economic forecasts. For 2012 through 2014, SCE used the IHS Global Insight Construction Cost Indexes for Transmission Production Plant Pacific region, 13 which directly forecast the Handy- Whitman Transmission Production Plant Pacific region index referenced above. Average Project Escalation Factors Project Escalation Rate Blending: SCE s Project expenditures include labor and nonlabor costs. As described above, SCE escalated and deescalated labor and nonlabor costs separately. The blended escalation rates in Table A-2, below, represent the annual weighted average escalation rate based on the annual labor and nonlabor expenditures for the Project. The blended rates accurately represent the annual mix of labor and nonlabor costs incurred during each year of the Project. Table A-2 Blended Project Escalation Factors Description Labor/Nonlabor Blend 5.96% 7.26% 6.05% 6.15% 2.21% 3.37% 3.36% 2.17% 2.48% 2.49% Handy-Whitman Public Utility Construction Cost and SCE Labor Indexes are More Appropriate Indexes to Estimate Transmission Capital Escalation than CPI-U The Handy-Whitman Index of Public Utility Construction Costs, Pacific region, Transmission Production Plant is the appropriate index to use when estimating escalation of Transmission capital cost escalation in California. Handy-Whitman Construction cost indexes have been relied upon by the Commission in numerous regulatory proceedings regarding capital escalation, and are a reliable source for 11 Handy-Whitman Index of Public Utility Construction Costs, bulletin #175, released in Quarter SCE has used IHS Global Insight indexes in various general rate cases. Pacific Gas and Electric, San Diego Gas & Electric and Southern California Gas use various IHS Global Insight indexes in the construction of their respective escalation indexes in their general rate cases. 13 IHS Global Insight Power Planner, Quarter 2, 2012, Transmission Production Plant variable JUEPT@PCF. A-4

37 historical utility construction cost information. 14 The Handy-Whitman index utilized in this study is based on actual construction cost data for transmission capital projects in the Pacific region. SCE also relies on what it knows about its labor costs. The escalation labor index is based on the actual labor escalation rates SCE incurred during the Project period for the historical period and is based on SCE s represented employees contractual wage increase and Global Insight Power Planner forecasts 15 for 2012 through CPI-U is based on costs unrelated to building transmission capital in California. According to the BLS website 16 The Consumer Price Index (CPI) is a measure of the average change in prices over time of goods and services purchased by households. Obviously, the basket of goods for households is not representative of the basket of goods purchased by utilities to install transmission capital in California. This is evidenced by the BLS Relative importance of components in the Consumer Price Indexes: U.S. city average, December 2010 where the BLS lists the components of CPI-U. According to the BLS, the CPI-U s components are: Component Share/Weight Food and beverages 14.8% Housing 41.5% Apparel 3.6% Transportation 17.3% Medical care 6.6% Recreation 6.3% Education and communication 6.4% Other goods and services 3.5% Total 100% In comparison, Global Insight s Transmission Production Plant Pacific region includes costs and indexes based on the following components 17 : Materials, Transformers & Station Equipment - Pacific Overhead Conductor - Transmission - All Regions Tower Steel 14 For instance, SCE has used IHS Global Insight indexes in all of its general rate cases since at least the early 1980s. Pacific Gas & Electric, San Diego Gas & Electric, and Southern California Gas Company also use various IHS Global Insight indexes in their general rate cases. 15 IHS Global Insight Power Planner, Quarter as a basis for forecasting labor rates. 16 Bureau of Labor Statistics, Consumer Price Index Summary November 2011, released December 16, 2011 Brief Explanation of the CPI 17 IHS Global Insight - Transmission Production Plant description of variables. A-5

38 Insulators Treated Pine Poles - All Regions Materials, Underground Conductors & Devices - Pacific Construction Equipment - All Regions Building Material - Ready-Mix Concrete - Pacific Standard Cross Arms - All Regions Standard Galvanized Steel Guy Wire - All Regions Building Material - Steel Bars For Reinforced Concrete Pacific Therefore, by reviewing the components within CPI-U and comparing them to the SCE labor index and components in Global Insight s Transmission Production Plant Pacific region, it is evident that the CPI-U components (housing, food, apparel, etc.) do not reflect the costs associated with installing transmission capital (transformers, conductors, structures, steel, wire) and that the SCE labor index and the Handy- Whitman Transmission Production Plant Pacific region index, which are calculated to reflect Transmission capital costs in the Pacific region, represent more accurate indexes to estimate the inflationary effects on building transmission facilities in California. A-6

39 Financing Costs Financing costs represent the costs associated with financing the development and construction of the Project, prior to the Project s in-service date. There are two methods by which SCE can recover financing costs Allowance for Funds Used During Construction (AFUDC) and Construction Work in Progress (CWIP) in Rate Base. 18 AFUDC represents the estimated cost of debt and equity funds that finance utility plant construction. AFUDC is accrued as a carrying charge to the open capital orders contained in Account and is capitalized as part of the overall cost of plant. When the new plant is closed to Electric Plant-In-Service, 20 the total capital-related order costs including capitalized finance charges are in rate base. Electric Plant-In-Service, including AFUDC, is recovered in rates through depreciation expense over the useful lives of the related assets. SCE earns an annual return on the un-depreciated rate base balance. Construction financing cost recovery through CWIP in Rate Base changes the recovery timing of SCE s finance charges. Under CWIP in Rate Base treatment, SCE collects from ratepayers its cost of debt and equity financing charges associated with the Project in current rates while the facilities are under construction rather than accruing AFUDC. CWIP in Rate Base only applies to eligible Project expenditures for FERC-jurisdictional facilities, and SCE will continue to accrue AFUDC for CPUC-jurisdictional facilities and for non-eligible Project expenditures for FERC-jurisdictional facilities. 21 Based on the Project scope and schedule, the majority of the financing costs are eligible to be recovered through CWIP in Rate Base treatment under SCE s CWIP Ratemaking Mechanism, or for expenditures made after December 31, 2011, the transmission 18 On November 26, 2007, the FERC issued an order granting incentives on three of SCE s largest proposed transmission projects, DPV2, Tehachapi Transmission Project, and Rancho Vista Substation Project. The order permits SCE to include in rate base 100% of prudently incurred capital expenditures during construction of all three projects. On February 29, 2008, the FERC approved SCE s revision to its Transmission Owner Tariff to collect 100% of CWIP for these projects in rate base and earn a return on equity, rather than capitalizing AFUDC. SCE implemented the CWIP rate, subject to refund, on March 1, Capital expenditures associated with the construction of new plant are accumulated in FERC Account 107 Construction Work In Progress Electric (CWIP). 20 Electric Plant-In-Service includes FERC Account 101 (Electric Plant-In-Service) and FERC Account 106 (Completed Construction Not Classified). 21 AFUDC will still accrue for CPUC-jurisdictional facilities, such as telecommunications equipment, distribution circuits, and for non-eligible Project expenditures for FERC-jurisdictional facilities, such as capital costs incurred prior to September 1, 2005, the date upon which Project expenditures became eligible for CWIP treatment. A-7

40 formula rate. 22 The actual AFUDC anticipated to be collected in CPUC and FERC rates for DCR is approximately 8.5 percent of the total financing estimate. 23 The AFUDC estimate is based on the recorded AFUDC through December 31, 2011, the Project expenditures incurred prior to receiving the CWIP in Rate Base incentive, the recorded and forecast CPUC-jurisdictional Project expenditures, the facility in service dates and the AFUDC rate calculation. The AFUDC rate calculation is based upon the prescribed methodology in the FERC USOA. 24 SCE used its 4 th Quarter 2011 AFUDC rate of 7.70 percent to calculate its forecast AFUDC amount. The total AFUDC projected for the Project is approximately $8.1 million (Nominal dollars). The CWIP in Rate Base estimate is based on the recorded CWIP in Rate Base through December 31, 2011, the eligible forecast Project expenditures for FERC-jurisdictional facilities and the Project CWIP return on equity rate of percent. The total CWIP in Rate Base projected for the Project is approximately $87.3 million (Nominal dollars). The cost of financing is driven by interest rates and specified by the applicable CPUC and FERC proceedings. SCE did not include financing costs to estimate the total maximum reasonable and prudent costs, which follows Commission practice. 25 For information purposes, an estimate of financing costs for DCR of approximately $95.4 million is provided in nominal dollars. 22 The CWIP Ratemaking Mechanism was first made effective on March 1, The mechanism terminated on December 31, 2011, and was replaced by SCE s transmission formula rate, which became effective on January 1, Like the CWIP Ratemaking Mechanism, the transmission formula rate provides for CWIP recovery in current rates for eligible transmission projects, like this Project. 23 If the FERC does not approve the eligible Project costs, then SCE may request recovery through CPUC rates under California Public Utilities Code , and the actual AFUDC amount would be higher CFR Part 101, Electric Plant Instruction, 3.A(17). 25 For example, the maximum reasonable and prudent cost ordered by the Commission for DPV2 excludes financing costs. See D , Ordering Paragraph No. 10, mimeo at 115 (2007). A-8

41 Appendix B Description of Environmental-Related Costs

42 Appendix B Description of Environmental-Related Costs 1 I. Introduction and Background This Appendix is intended to provide more detail regarding the impact of environmental activities and constraints on the overall cost of the Project. The Appendix describes the direct environmental costs incurred by SCE and the responsible agencies 2 related to licensing the Project as well as the costs incurred to ensure compliance with the mitigation measures in the FEIR/EIS, MMCRP and the USFWS Biological Opinion. The Appendix also discusses the impact that the environmental mitigation requirements and other permit conditions are having on the overall cost of the Project by limiting flexibility and lowering productivity of the construction contractors. Figure B-1 presents the Project costs that are attributable to all these environmental considerations. 1 All dollars are constant unless otherwise noted. 2 SCE reimburses the costs incurred by the following agencies associated with the Project: U.S. Fish and Wildlife Services, Metropolitan Water District of Southern California, California Department of Parks and Recreation, California Department of Fish and Game, State Water Resources Control Board, California Public Utilities Commission (CPUC), San Bernardino National Forest (SBNF), Bureau of Land Management (BLM), State Lands Commission (SLC) B-1

43 Figure B-1. Environme ental-related Costs ($2012 millions) SCE is presenting this information not to criticize or question the environmental requirements associated with the Project, but simply to document thee impact on overall Project costs. The impact of these environmental considerations exceeded SCE s prior experience with Project licensing and construction, and SCE could not have anticipated the consequences to costs. As noted in the Advice Filing, SCE first began the preliminary engineering and licensing work for the Project in March At that time, one of the last major transmission line projects constructed by SCE was the DPV1 transmission line completed in While SCE had sought a CPCN for DPV2 in the 1980 s, the environmental mitigation measures and permit conditions associated with that application were relatively modestt compared to the requirements currently imposed on the Project. The 2007 FEIR/FEIS for DPV2 contains approximatelyy 1,960 pages, including approximately 256 mitigation requirements, 99 mitigation measures and 157 Applicant Proposed Measures (APMs). The FEIR/FEIS required the development of the MMCRP. Approval of the MMCRP involved the CPUC, BLM, their consultant Aspen, and SCE in determining the applicability, approach, and interpretation of the mitigation measuress which had been developed years before. The 2011 MMCRP is currently 211 pages longg and contains approximately 286 mitigation equirements, including 196 Mitigation Measures and 90 APMs. 3 Although SCE did license and construct several other large projects in this timeframe, SCE s experience related to environmental considerations was similar in nature to its experience with DPV1. B-2