PUBLIC UTILITIES COMMISSION - Southern California Edison · project will be referred to as Devers-Colorado River Transmission Line Project (DCR or Project). In D.07-01-040 and D.09-11-007,

STATE OF CALIFORNIA Edmund G. Brown Jr. Governor

PUBLIC UTILITIES COMMISSION

SAN FRANCISCO, CA 94102-3298

March 19, 2014 Advice Letter 2804-E

Megan Scott-Kakures

Vice President, Regulatory Operations

Southern California Edison Company

8631 Rush Street

Rosemead, CA 91770

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-4602.

Sincerely,

Edward F. Randolph, Director

Energy Division

* Note: reference – Decision D.02-02-049, dated February 21, 2002, and Rule 7.5 in appendix A of D.O7-01-024

ADVICE LETTER (AL) SUSPENSION NOTICE ENERGY DIVISION

Utility Name: Southern California Edison Company. Date Utility Notified: November 26, 2012 via: email Utility No./Type: U 338-E [X] E-Mail to: [email protected] 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,

[email protected] Utility Phone No.: (626) 302-2086 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 [email protected] cc: EDTariffUnit

P.O. Box 800 8631 Rush Street Rosemead, California 91770 (626) 302-3630 Fax (626) 302-4829

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.) 07-01-040, as modified by D.09-11-007, and D.11-07-011.1 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.07-01-040 and D.09-11-007, 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.11-07-011 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.04-08-046, SCE recognizes that the Commission believes that the Commission is obligated by Public Utilities (PUC) Code § 1005.5(a) to specify “a maximum amount determined to be reasonable and prudent for the facility.” The Commission has also recognized that

ADVICE 2804-E (U 338-E) - 2 - 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 § 1005.5(a) in D.07-01-040. 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 $545.3 million4 (2005$) adopted in D.07-01-040 to $701.3 million5 (2005$). Escalating the cost estimate to current year dollars brings the updated cost estimate to $944.8 million6 (2012$). 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 § 1005.5(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. 07-01-040, 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 § 1005.5(b), and shall address whether the cost increases affect the cost-effectiveness and need for the DPV2 project.” In D. 09-11-007, at page 25, the Commission granted SCE’s request to retain the advice letter process, stating that, “The Decision [D.07-01-040] 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.


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-of-way (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.07-01-040, 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.


1,200 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.07-01-040, 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.07-01-040, 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.


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, 2009. SCE did not change or provide new cost estimates, but did escalate to 2009 dollars the costs adopted in D.07-01-040 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.07-01-040 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.11

9 On May 18, 2009, SCE withdrew its pre-filing request in PT08-1-000. 10 See SCE’s June 26, 2009 Supplemental Information on PFM of D.07-01-040, p. 19. 11 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


On November 20, 2009, in D.09-11-004, 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 Application13 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.09-11-007. As part of the Commission’s review of the Colorado River Substation Expansion Project in Application (A.)10-11-005, 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.11-07-011 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 Application15 for the Red Bluff 500/220 kV Substation which was granted by the CPUC in D.11-07-020 on November 17, 2010.

(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, 2010.

13 A.10-11-005.

14 As used in the advice letter, a substation is a switchyard with transformers, or transformation. 15 A.10-11-012.


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.10-11-005, as reflected in D.09-11-007,

16 The need for the California portion of the DPV2 project has evolved and is no longer based on cost-

effectiveness. 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.09-11-007, 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. 1-4.

17 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.07-01-040. 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.07-01-040 was not modified at the time D.09-011-007 was issued. Instead, SCE was directed to file a cost update after final engineering was completed.


D.11-07-011, 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.11-07-011.19

• 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.07-01-040 and D.09-11-007, SCE is seeking an increase in the cost estimate for the California portion of DPV2 to $ 944.8 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 http://www.cpuc.ca.gov/environment/info/aspen/dpv2/mmcrp/mitigation_consistency_determination.pdf.

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


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.07-01-040 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.05-04-015. 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.


Table 1.

Comparison of Cost Estimates (Constant 2005 Dollars, unless otherwise noted)

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.07-01-040 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.

(A) (B) (C) (D) = (C) - (B)

CategorySCE’s 2005 CPCN

for DPV2Advice Filing

Update

Difference between CPCN Adopted and

Advice Filing Update

Preliminary Engineering & Licensing $11.7 $25.9 $14.2Bulk Transmission $255.5 $333.3 $77.9Environmental Mitigation & Monitoring $0.0 $81.2 $81.2Substation $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 $0.6Contingency $63.0 $85.3 $22.4

Total Direct Forecast (excludes Corp OH): $503.2 $654.3 $151.1Corporate 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

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.


Table 2.

Comparison of Cost Estimates (Constant 2012 Dollars)

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.

(A) (B) (C) (D) = (C) - (B)

CategorySCE’s 2005 CPCN

for DPV2Advice Filing

Update

Difference between CPCN Adopted and

Advice Filing Update

Preliminary Engineering & Licensing $15.7 $34.8 $19.2Bulk Transmission $344.2 $449.1 $104.9Environmental Mitigation & Monitoring $0.0 $109.4 $109.4Substation $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 $0.8Contingency $84.8 $115.0 $30.2

Total Direct Forecast (excludes Corp OH): $677.9 $881.5 $203.6Corporate Overheads: $56.8 $63.3 $6.6

Total: $734.6 $944.8 $210.2


Preliminary Engineering and Licensing

DPV2 CPCN (2012$, millions)

Advice Filing Update (2012$, millions)

Difference between DPV2 CPCN and


$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


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.07-01-040 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 2006. While the CPCN decision was received in early 2007, the additional California licensing activities resulting from the ACC denial of the Certificate of Environmental Compatibility25 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 DPV226

• The modification of DPV2 to be a California-only project27

24 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, 2012. The settlement was approved by FERC on August 30, 2012.

26 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.


• The location change for the Colorado River substation to accommodate concerns

related to the Mojave Fringe-Toed lizard

Bulk Transmission





$344.2 $ 449.1 $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.11-07-011. 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.11-07-020.

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-2011-31 (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.


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.


Environmental Mitigation and Monitoring





$0 $ 109.4 $ 109.4

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 consultants32 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 2014. 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.


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.05-04-015). As it had done in A.85-12-012, 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.07-01-040.36

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.88-12-030, 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 1005.5 (b).”).

36 See, D.07-10-040, Ordering Paragraph 12.


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





$210.6 $ 162.1 ($ 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 1 500 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.


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





$9.5 $4.3 ($ 5.2)

38 See SEIR adopted by the Commission in D.11-07-011.


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





$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.


Distribution





$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





$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.


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


$56.8 $63.3 $6.6

39 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.


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.


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 7.6.1 and 7.6.2 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.


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 94102 E-mail: [email protected]

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 91770 Facsimile: (626) 302-4829 E-mail: [email protected] Leslie E. Starck Senior Vice President c/o Karyn Gansecki Southern California Edison Company 601 Van Ness Avenue, Suite 2030 San Francisco, California 94102 Facsimile: (415) 929-5540 E-mail: [email protected]

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.05-04-015 service lists. Address change requests to the GO 96-B service list should be directed by electronic mail to [email protected] or at (626) 302-4039. For changes to all other service lists, please contact the Commission’s Process Office at (415) 703-2021 or by electronic mail at [email protected].

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.


To view other SCE advice letters filed with the Commission, log on to SCE’s web site at http://www.sce.com/AboutSCE/Regulatory/adviceletters.

For questions, please contact Ryan Stevenson at (626) 302-3613 or by electronic mail at [email protected].

Southern California Edison Company

Akbar Jazayeri

AJ:rs:jm Enclosures

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) 302-2086

PLC HEAT WATER E-mail: [email protected]

E-mail Disposition Notice to: [email protected]

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 07-01-040 and 09-11-007

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 AL1:

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

No. of tariff sheets: -0-

Estimated system annual revenue effect: (%):

Estimated system average rate effect (%):

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 proposed1:

Pending advice letters that revise the same tariff sheets:

1 Discuss in AL if more space is needed.

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 94102 [email protected]

Akbar Jazayeri Vice President of Regulatory Operations Southern California Edison Company 8631 Rush Street Rosemead, California 91770 Facsimile: (626) 302-4829 E-mail: [email protected] Leslie E. Starck Senior Vice President c/o Karyn Gansecki Southern California Edison Company 601 Van Ness Avenue, Suite 2030 San Francisco, California 94102 Facsimile: (415) 929-5540 E-mail: [email protected]

Appendix A

Cost Escalation Method and Financing Costs

A-1

ESCALATION METHOD AND FINANCING COSTS

Purpose

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.09-11-007,1 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.07-01-040 and D.09-11-007, 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. 07-01-040, the Commission did not include financing costs to establish the level of total maximum reasonable and prudent

costs.3 D.09-11-007 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.09-11-007, pp. 25-26. 2 See, for example, Decision 09-09-033 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.07-11-040, Ordering Paragraph No. 10, mimeo at 115 (2007). 4 D.09-11-007 at p. 26.

A-2

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.07-01-040, 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 Planner7 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 2014. These labor escalation rates are consistent with SCE’s labor escalation rates used in its

general rate case proceedings.8 Historical Labor Escalation 2005-2011: 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.10-11-015, SCE-10, Volume 1, p. 63.

A-3

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 2012-2014: 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 2014.

Table A-1

Correspondence Between Employee Categories And Global Insight Variables

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 (2005 – 2011) and IHS Global Insight’s Construction Cost Indexes for Transmission Plant – Pacific region for the years 2012 through 2014. The Commission has used these indexes in previous proceedings to

calculate escalation of construction costs and capital additions.10

9 IHS Global Insight Power Planner Operation and Maintenance Costs, Quarter 2 2012, 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.

Employee CategoryGlobal Insight

VariableVariable Description

Wage Bill Share

Physical Workers CEU4422110008Utility Price and Wage Indicators, AHE,

Transmission and Distribution Workers24.1%

Clerical Workers CEU4422110008Utility Price and Wage Indicators, AHE,

Transmission and Distribution Workers8.6%

Managers and

SupervisorsECIPWMBFNS

Employment Cost Index, Managers and

Administrators25.7%

Professional and

TechnicalECIWSPWP & TNS

Employment Cost Index, Wages and Salaries,

Professional and Technical Workers41.6%

100.0%Total

A-4

Historical Nonlabor Escalation - Handy-Whitman 2005-2011: 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 #175.11

Forecast Nonlabor Escalation - IHS Global Insight Forecast of Construction Costs – Transmission Plant – Pacific region, 2012-2014: 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

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 2 2012. 12 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.

Description 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014

Labor/Nonlabor Blend 5.96% 7.26% 6.05% 6.15% 2.21% 3.37% 3.36% 2.17% 2.48% 2.49%

A-5

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 forecasts15 for 2012 through 2014 .

CPI-U is based on costs unrelated to building transmission capital in California.

According to the BLS website16 “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:

In comparison, Global Insight’s Transmission Production Plant – Pacific region includes

costs and indexes based on the following components17:

• 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 2 2012 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” http://www.bls.gov/news.release/cpi.nr0.htm 17 IHS Global Insight –- Transmission Production Plant – description of variables.

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%

A-6

• 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-7

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 10719 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, 2008.

19 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-8

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 4th 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 11.43 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, 2008. The mechanism

terminated on December 31, 2011, and was replaced by SCE’s transmission formula rate, which became effective on January 1, 2012. 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 § 399.2.5, and the actual AFUDC amount would be higher.

24 18 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.07-01-040, Ordering Paragraph No. 10, mimeo at 115 (2007).

Appendix B

Description of Environmental-Related

Costs

B-1

Appendix B Description of Environmental-Related Costs1

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 agencies2 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. 2SCE 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)

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B-3

In addition to the MMCRP, the USFWS issued a Biological Opinion on January 11, 2011.4 The

USFWS Biological Opinion included approximately 59 additional conservation measures, for

example:

• USFWS Biological Opinion Conservation Measure 2, page 11: Requires a Field Contact

Representative (Specialist Biologist) present during all ground disturbing activities and

requires that should there be an imminent threat of injury to kangaroo rats, milk-vetch,

fringe-toed and horned lizards, or tortoises, the non-compliant construction activities

shall cease. USFWS Biological Opinion Compliance Measure 5 requires that if one of

these species is injured or killed all activities in the immediate area will be halted and

the incident reported within 24 hours;

• USFWS Biological Opinion Conservation Measure 30, page 16: Requires habitat

compensation for Coachella Valley fringe-toed lizard (a threatened species, not

endangered) to offset the impact of temporary and long-term losses of Coachella Valley

fringe-toed lizard habitat; and,

• USFWS Biological Opinion Conservation Measure 43, page 22: Requires habitat

compensation for desert tortoise habitat.

By contrast, the August 1987 EIR adopted by the CPUC in A.85-12-012 is approximately 53

pages, and incorporated by reference the Draft EIR, which was approximately 110 pages. In

September, 1988, the CPUC issued an Addendum to the EIR that was approximately 18

pages. Thus, the CPUC FEIR, DEIR and addendum for associated with the 1985 application

for DPV2 totaled less than 200 pages. In addition, BLM issued a Final Supplemental EIS in

October 1988. The Final Supplemental EIS associated with the 1985 application for DPV2

was also less than 200 pages long.

These environmental requirements have a significant impact on the cost and time to construct

the Project. The significance of these factors can be seen by comparing the time to construct

two similarly situated towers – Tower 15-1, part of the DPV1 line built in 1985, and Tower

1063, a new tower that will be constructed as part of DCR. Tower 1063 is adjacent to DPV1

Tower 15-1. In 1980, a single tower could be constructed in 4 days, including foundations.

4 In order to impact species covered under the Endangered Species Act, the USFWS must issue a Section 7

Biological Opinion on the project. The USFWS Biological Opinion authorizes the amount of take the project can

have on listed species and sets additional compliance requirements beyond that of the FEIR including the

purchase of mitigation lands to compensate for permanent impacts.

B-4

Today construction is generally estimated to take a range of 10-25 days.5 Construction of

DPV1 from Valley Substation to Palo Verde Substation in Arizona lasted 24 months at a cost

of $35 million dollars (Constant 1980$).6 Construction of DCR is forecast to take 21 months,

even though the length of DCR is 152 miles compared to approximately 230 miles for DPV1.

A. Tower 15-1

After receiving the CPCN for DPV1 in 1979, SCE mobilized its own construction force and

began construction. SCE was not required to obtain a CPUC Notice to Proceed authorization

prior to construction. The requirements and environmental restrictions placed on construction

crews, were of a more general and flexible nature, such as “The applicant will be required to

instruct its employees of its contractors from needlessly harming wildlife” and “Applicant will be

requested to notify the applicant’s biologist if they think they observe threatened or

endangered species. The applicant will periodically report such incidents to the Authorized

Officer.”7

B. Tower 1063

It is important to note that Tower 1063 impacts habitat for special status plants, is located

within suitable habitat for listed species, and also impacts a Jurisdictional Water feature.

Impacting a Jurisdictional Water feature requires a Clean Water Act (CWA) Section 401 Water

Quality Certification from the SWRCB, a CWA Section 404 Dredge and Fill Permit from the

Army Corp. of Engineers, and a California Department of Fish and Game 1602 Streambed

Alteration Agreement. The information and materials necessary for the applications for these

permits require several months to prepare. Once submitted, the agencies can take six months

to a year to approve the permit. In the case of the 401 Permit, the agencies required 10

months for approval.

In addition to the major permits described above, a Notice to Proceed Request (NTPR) must

be submitted to the CPUC before a Notice to Proceed (NTP) can be issued.8. NTPRs are

lengthy documents which reiterate the environmental setting for the area, the biological

resources, the project components, construction activities, and all of the mitigation measures

that will have to be implemented. Detailed cultural, biological, and Geographical Information

System (GIS) Support reports and maps are also included in the NTPR package to define the

5 Not all of the increase in construction duration is due to environmental mitigation requirements; the increase is

also due to increased safety requirements, larger foundations and slightly larger towers being utilized for DPV2. 6 SCE subcontracted out the construction of the AZ portion of the DPV1 as well as a small section between Blythe

and the AZ/CA border. Those costs are not reflected in the $35 million. 7 DPV2 Final EIS, Chapter 4.0, Mitigating Measures, p. 4-7 (1979).

8 Although there are no requirements stipulating how many NTPs a project should have, SCE typically divides the

project into manageable sections and develops an NTP for each section.

B-5

area of disturbance in detail. If more disturbance or work area is needed a Temporary Extra

Workspace (TEWS) application must be filed with the Commission. Once the NTPR is

submitted, the CPUC develops and issues an NTP which often contains additional conditions.

Once a NTP is issued, pre-construction surveys must be performed on the access roads, stub

roads, and work areas 14 days prior to construction to verify that the environmental conditions

for a given site have not changed. The surveys are conducted out to a 500 feet range from the

roads and work site with biologists walking at 100 foot intervals. The site is then surveyed to

stake the pre-determined disturbance areas and install the Best Management Practices

(BMPs) as required by the SWRCB in the Storm Water Pollution Prevention Plan (SWPPP).

The disturbance area is ground staked. The CPUC (Aspen) monitors validate the

preconstruction survey results and sites before the site is officially released.

If construction does not commence within 14 days of the pre-construction surveys and

validation, or the site is not maintained as “active”, the site will have to be re-surveyed and “re-

released” for construction.

After all of the aforementioned activities are performed, ground disturbing activities can

commence. Ingress and egress to the site can only occur on approved access roads while

adhering to the 15 mile per hour speed limit.

Each morning, before crews can begin work, a biological sweep of the site must be performed

and a tailboard is held to discuss any Environmentally Sensitive Areas (ESAs). The netting

around equipment, which was put in place to prevent birds from building nests, is removed

each morning before work commences. Under the Migratory Bird Treaty Act and California

Fish and Game Code, the take of birds, egg, or their nests is forbidden. If a nest does become

active, a 300 foot buffer is established and no work can continue within that buffer until the

hatchlings fledge. Following approval of the Nesting Bird Management Strategy by the CDFG

and CPUC, the buffer may be reduced under certain circumstances following consultation with

the agencies.

Site preparation, including access road grading and tower pad grubbing, precede actual tower

construction. Once the site is cleared and appropriately graded, surveys are conducted to

verify the tower center hub and the position of each leg before the foundations can be drilled.

Foundation drilling may require additional cultural and Native American monitors to be present,

in addition to any environmental, biological, specialist, or CPUC Monitors, to inspect the bore

spoils for sensitive artifacts. If any culturally significant artifacts are unearthed, construction

could be shut down to assess the artifact. Construction can also be shut down for impacts to

other resources, i.e., desert tortoise take, safety incidents, etc. As many as six monitors have

been present at a single tower site to meet all of the various conditions and mitigation

measures.

B-6

To construct Tower 1063, as a result of delays in receiving the water permits, construction

occurred on Saturdays to make a critical outage window. A variance was drafted to receive

approval to deviate from the pre-determined work schedule evaluated in the FEIR/FEIS.

Variances, depending on their complexity, can take several weeks to prepare and an additional

number of weeks to approve.

Throughout the remaining tower construction activities (foundations, tower assembly, tower

erection, wire-stringing and pulling), the sites are continually monitored to ensure that all of the

approximately 345 mitigation and conservation measures are correctly implemented and

complied with.

Construction of Tower 1063, foundations through tower erection, took 17 days. By contrast,

DPV1 Tower 15-1, which is adjacent to Tower 1063, took four days for foundations through

tower erection.

II. Costs Associated with Environmental Mitigation Measures and 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 from 2004 through 2009. 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 include 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 2014. 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 contributions to the National Fish and Wildlife Foundation and the California Department of Parks and Recreation.

B-7

• 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.

A. Field Activities & Reporting - $73.0 million

SCE estimated costs associated with biological, environmental, and archaeological field

activities and reporting for the project. This includes biological, environmental and

archaeological surveys, as well as the preparation, development and review of survey reports

and associated maps. Monitoring (biological, environmental, archaeological/paleontological

and site restoration) is also required to ensure effective implementation and reporting of

mitigation measures and to respond in the event human remains or sacred sites are

encountered.

Biological Field Activities and Reporting: $42.1 million

Many different types of biological surveys are required for the project, including

numerous bird surveys, pre-construction 14-day clearance surveys, construction

validation surveys, seasonal protocol level surveys and special-status species

observation surveys in addition to the continuous construction monitoring. Pre-

construction surveys are conducted to identify special status plant and wildlife species

such as active bird nests protected by the Migratory Bird Treaty Act and the California

Fish and Game Code. Other examples of surveying activities include assisting

engineering in the surveying of tower locations for fatal flaw analysis and conducting the

Golden Eagle survey, which had strict timing and protocol requirements. Reports must

be prepared upon completion of surveys, and they consist of a pre-field review of

previous reports, state databases, and Geographic Information System data. During

construction, the biologists must conduct daily morning sweeps and also monitor nearly

all construction related activities to ensure compliance with all of the mitigation

measures. Monitoring reports must also be prepared and reviewed on a daily basis.

Biological activities include relocation of wildlife species and special status plants.

Examples include relocation of special status plants in accordance with biological

mitigation measure mm b-6a for cactus and special status plant relocation and

relocation of a Coachella Valley Fringe Toed Lizard in accordance with USFWS BO -

B-8

January 11, 2011, Compliance Measure No. 29, at 16. Other biological field activities

include engaging in tasks to ensure compliance with all biological mitigation measures,

such as implementing weed control measures in accordance with biological mitigation

measure mm b-2a for noxious weeds.

Archaeological Field Activities and Reporting: $7.9 million

This includes conducting archaeological surveys, as well as cultural resource treatment

elements of the Historic Properties Management Plan. Archaeologists conduct

monitoring of construction ground disturbance, and identify and report new resource

discoveries. Paleontologists are deployed to observe ground disturbing construction

activity in areas of sensitivity in order to document any discovery and to initiate

treatment of any significant paleontological finds. Archaeological field activities also

include tasks such as establishing and maintaining cultural resource “environmental

sensitive area” barrier fencing, as well as managing data and artifact recoveries and

responding to unanticipated discoveries.

Environmental Field Activities and Reporting: $4.2 million

Environmental field activities include monitoring for dust control and inspecting the

adequacy of the storm water pollution and prevention plan. Activities also include

observing project construction, assessing construction procedures for compliance,

interpreting mitigation measures, and conducting daily and weekly observation

reporting.

Site Restoration Field Activities and Reporting: $16.8 million

The site restoration costs are a preliminary estimate prepared by SCE based upon the

requirements outlined in the Biological Opinion and the Habitat Restoration

Compensation Plan. The environmental budget includes two round of seeding

(purchasing and planting of seeds in 2013 and 2014), two years of weed abatement (2013

and 2014), and 2 years of site restoration monitoring and reporting (planting of seeds in

2013 and 2014 and annual assessment and reports in 2014). The budget excludes

additional rounds of seeding which may need to be conducted after 2014 should the

success criteria not be met. The budget also excludes long term operations and

maintenance (O&M) requirements for weed abatement activities and site restoration

monitoring and reporting costs after 2014. The first round of seeding is projected to

occur in 2013. Seeds are to be purchased and the planting of the seeds is estimated to

take place in the fall of 2013. No irrigation costs are included because the seeds will rely

upon rainfall for watering needs. Section 3.4.1.3 in the Habitat Restoration

Compensation Plan outlines the plan to seed with no supplemental irrigation. The

success criteria with seeding is dependent upon the timing of rainfall, wind, and other

atmospheric conditions. Mitigation Measure MM B-1a states that “the creation or

B-9

restoration of habitat shall be monitored for five years after mitigation site construction,

or until established success criteria are met.” There may be a need to conduct

additional rounds of seeding after 2013 if the success criteria is not achieved. Biologists

(including specialized botanists) will conduct site restoration monitoring of the project in

the fall of 2013 to monitor the planting of the seeds. Site restoration monitoring will also

be conducted in the spring of 2014. The biologists will walk the entire line of the project

to perform the assessment and ensure that the plants are established and growing

properly. SCE assumes that a second round of seeding would need to be conducted in

2014. A second round of seeds would need to be purchased and the planting of the

second round of seeds is estimated to take place in the fall of 2014. The biologists will

also need to monitor the second round of seeding activities in 2014. Weed abatement

activities will occur prior to seeding activities in 2013 and 2014, and also simultaneously

with the site restoration monitoring in the spring of 2014. The environmental budget

does not take into account any costs for additional rounds of seeding which may need

to be conducted after 2014. The budget also does not take into account additional site

restoration monitoring, reporting and weed abatement costs that may be incurred after

2014.

Agency Field Activities and Reporting: $2.0 million

The costs for CPUC/Aspen are estimated to be approximately $1.9 million for 2012 and

2013. The costs for the San Bernardino National Forest are estimated to be about

$0.1 million.

For the cost of biological and environmental field activities and reporting, SCE based its

estimate on the construction schedule estimate from its Owners Engineer (Kenny Construction

Company). SCE then consulted with CH2M Hill to determine the level of support required

based on the requirements in the MMCRP and USFWS BO. Archaeological, Native American

and Paleontological resources field activities and reporting costs were estimated using the

findings from the FEIR/FEIS, Historic Properties Management Plan, and the Paleontological

Monitoring and Treatment Plan.

B. Land Mitigation - $12.9 million

Approximately $12.9 million is the estimated cost of the mitigation land including the funding of

an endowment to care for the property in perpetuity. The USFWS Biological Opinion requires

that SCE purchase mitigation land to compensate for habitat disturbances. SCE is required to

purchase a total of 1,622 acres for desert tortoise habitat at a cost of $3,810/acre, 52 acres for

Coachella Valley Fringe Toe Lizard habitat at $56,200/acre, and 74 acres of Coachella Valley

Milk-Vetch habitat at $34,560/acre. Based on the Supplemental Environmental Impact Report

(SEIR) and geographic information system analysis, SCE is required to purchase 143.35 acres

B-10

of Mojave Fringe Toed Lizard habitat at $6,680/acre. The total acreage impact to be purchased

is approximately 1,891 acres at a cost of $12.7 million.9

The balance of the estimate for land mitigation encompasses SCE’s other mitigation costs,

such as the Stephens’ Kangaroo Rat (SKR) mitigation credit purchase from the Metropolitan

Water District, the Stephens’ Kangaroo Rat (SKR) habitat enhancement fee to the California

Department of Parks and Recreation, and the region wide Raven Management contribution to

the National Fish and Wildlife Foundation.

To date, SCE has spent approximately $12.9 million on land mitigation. This cost could

increase if SCE was required to purchase additional compensation land (i.e., if the project has

additional temporary or permanent land disturbance).

C. Environmental Compliance Documents - $7.1 million

Significant time and effort goes into the preparation and processing of environmental

compliance documents required before, during and after construction. Environmental

documents include mitigation plans, notices to proceed requests, authorizations to proceed,

permits, variances, temporary extra workspace, addendums, and other reports. These

documents are often subject to several rounds of review and approval by multiple agencies

and SCE is required to fund its own cost to produce these plans as well as fund the review

cost of the agencies. SCE prepared estimates for each type of document, along with

assumptions of the number of submittals that could be required. The actual number and cost

will vary.

Mitigation Plans: Mitigation plans are required prior to the initiation of construction. The mitigation plans

are prepared to provide guidance to contractors. The mitigation plans describe the

intent and application of the mitigation measures, and identify how a specific resource

should be protected or avoided. Once the initial plan is prepared, the environmental

team will schedule an internal “live review” of the plan. The appropriate subject matter

experts will attend this “live review” and all comments are incorporated immediately into

the document. The document is revised, and is then submitted to the agency for review

and comments. Frequently, several agencies will review and comment on the plan.

There are often multiple revisions of a plan prior to the agencies’ final approval. To date,

approximately 23 mitigation plans have been prepared and submitted to the agencies,

SCE estimates costs for mitigation plans for the project at a cost of approximately

$4.2 million.

Notice to Proceed Requests (NTPRs)

9 All acreage estimates are nominal.

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NTPRs are submitted to the CPUC for authorization to begin construction of a defined

component of the Project. A description of the construction activities is reviewed by the

project team for accuracy and completeness. The NTPR package is submitted to the

applicable agency, and any comments received from the agency are incorporated and

the NTP is resubmitted for final review and approval. The agency then issues a Notice

to Proceed which may contain additional conditions. NTPRs require preparation of GIS

support maps, analysis of applicable mitigation measures, biological and cultural

analysis, and preparation of biological and cultural reports. To date, SCE has submitted

approximately 15 NTPRs to the agencies. The total cost estimated for NTPRs for the

project is approximately $0.8 million.

Authorizations to Proceed (ATP) Checklist

The Authorization to Proceed (ATP) Checklist is an internal process within SCE. The

ATP checklist is a tool used to track the status of pre-construction, construction, and

post-construction environmental requirements and documentation. The completion of

the ATP Checklist supports the Major Projects Organization’s (MPO’s) issuance of an

ATP letter, which allows the Construction Management Team (CMT) to issue an

Authorization to Construct (ATC) to the construction contractor to start construction.

The ATP Checklist is used to verify compliance with the mitigation measures, APMs,

permits, NTPR conditions, and other pre-construction requirements in environmental

licenses and permits. The cost for completing ATPs for the project is estimated at

approximately $0.2 million.

Permits

The development of a list of permits required for the project involved a review of the

project licensing documents and mitigation measures. Meetings were scheduled with

the appropriate local and state agencies to provide a project overview and schedule.

Some local agencies that were contacted included Riverside County, Cities of Menifee,

Beaumont, Banning, Desert Hot Springs, Palm Springs, Cathedral City, Indio and

Coachella. The permit applications were then submitted with the necessary fee

payments. Examples of permits for the project include temporary use permits, grading

permits, building permits driveway approach permits, overhead encroachment permits

(wire stringing), fugitive dust control plan (Rule 403.1 specific plans),temporary

helicopter landing zone permits, and 7460-1 Notification to Airmen FAA filings for

construction within airport boundaries. The total cost of permits for the project is

estimated at approximately $0.7 million.

Variances/Determination of NEPA Adequacy (DNA)

Variances/DNAs are required when a temporary or less-than-substantial change to

project components or construction activities are required to accommodate project

execution. Variances are necessary during construction as a result of final engineering

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final surveys, agency direction, or other reasons. The variance is prepared for the

proposed change from what was approved in the Notice to Proceed (NTP). A typical

variance includes the complete scope of work describing the change, the GIS data

(geo-referenced), GIS maps, if applicable, start and end of when change is planned to

occur, justification for the proposed change, and date the variance is needed. Issuance

of a variance approval by the appropriate agency or agencies is necessary prior to

implementation of the project change. To date, SCE has prepared approximately 57

variances. The total cost of variances for the project is estimated at approximately

$0.9 million.

Temporary Extra Workspaces (TEWs) A TEWs is a request for additional construction workspace not identified in the Notice to

Proceed (NTP) that is needed for a short term period (60 days or less) and is not in or

adjacent to sensitive environmental resources. A complete and full description of the

proposed TEWs location with dimensions and a map are required. This information is

evaluated to ensure that the location requested does not result in any new significant

impacts. The TEWs is then drafted and circulated to the project team. Once all project

team comments are incorporated, a request for TEWs is submitted to the applicable

agency for review approval. The total cost for the preparation of TEWs for the project is

estimated at approximately $0.2 million.

Addendums An addendum to the Environmental Impact Report (EIR) is required for a permanent or

substantial change to a Project that was evaluated in the EIR. An addendum includes

an overview, project, description, and a CEQA analysis of the proposed change. The

addendum request must include an analysis of the potential for the change to result in

an impact to environmental resources. The addendum should contain adequate

information to facilitate an informed evaluation. The total cost of addendums for the

project is estimated at approximately $0.1 million.

D. Environmental Coordination, GIS, and Material - $16.4 million

This category includes environmental coordination and management, geographic information

system support, contract and construction specifications and procedures, document tracking

tools, material, and direct allocation.

Environmental Coordination and Management:

Approximately $6.1 million is estimated for environmental coordination and

management. A significant amount of effort is needed to effectively coordinate and

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manage the large force of environmental personnel needed to ensure that all of the

approximately 345 mitigation measures and compliance requirements are adhered to.

These critical activities include interpreting and implementing the mitigation measures

identified in the MMCRP, prioritizing and scheduling work activities of field personnel,

interfacing with multiple agencies for compliance concurrence, and continually

managing emergent environmental field issues.

Material and Direct Allocation:

Approximately $5.1 million is estimated for material and direct allocation.

Material costs pertain to costs of mobile equipment, office supplies, cell/blackberry

accessories, etc. They also include costs such as installation of docking stations for the

project, ordering laptops, computer cases and other costs. Direct allocation costs

include a percentage of the labor, material and contract costs incurred by departments

such as Supply Management, Real Properties, and Information Technology to support

the project. Other costs include letter of credit fees, general activities/support,

HyperOffice, equipment maintenance, avian protection and records searches.

Geographic Information System:

Approximately $4.0 million is estimated for geographic information system mapping

requirements needed for the project. This type of activity includes the preparation and

development of map books as well as the review, analysis, and updates of engineering -

and other- types of data. Additional activities include creating project mapping

components for the environmental database, conducting spatial analysis of the

disturbance areas to ensure that the project is aligned with the Biological Opinion, and

providing data coordinates & buffers for nesting birds observations for air operations to

enable avoidance of nesting birds.

Document Tracking Tools:

Approximately $0.7 million is estimated for document tracking tools. This includes costs

for the field reporting environmental database, which is an agency accessible database

used to gather information from site monitors to facilitate compliance reporting.

Contract/Construction Specifications & Procedures:

Approximately $0.5 million is estimated for contract/construction specifications and

procedures. This includes development of construction procedures used to comply with

all the mitigation plans. Contract specifications were prepared from the construction

procedures that were used as part of the bid specifications for the construction

contractor.

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III. Impact of Environmental Considerations on Project Construction While the mitigation measures detailed above have significant direct costs, such as monitoring

requirements, there are also significant indirect costs that are attributed to the construction

contractors. These costs are related to protecting nesting birds, sensitive species, vehicle

washing, and other compliance activities.

As discussed in the bulk transmission section of the updated and escalated cost section of the

Advice Filing, SCE’s procurement strategy for the transmission line component of DCR was to

solicit fixed price bids from qualified transmission contractors, and select the least cost bid.

SCE was able to ascertain that one of the reasons for the cost increase for the transmission

line component is based on the amount and complexity of the mitigation measures for DCR.

The impact on the construction schedule and productivity is further discussed below.

Background On January 25, 2007, the California Public Utilities Commission (CPUC) adopted the Final

Environmental Impact Report/Environmental Impact Statement (EIR/EIS) for the Devers-Palo

Verde No. 2 (DPV2) Project. In response to the Final EIR/EIS, SCE prepared a

comprehensive specification in early 2007 to solicit bids from prospective transmission line

contractors. A bid from the contractor that was ultimately awarded the contract in 2011 was

received on June 1, 2007- six days before the Arizona Corporation Commission (ACC) would

deny SCE’s Application to build the Arizona portion of the Project.

The ACC’s Decision made the review of the construction bids unnecessary. However, the

contractor that was ultimately awarded the contract in November of 2011 also bid on the

project in 2007. Comparing the two bids serves as a useful gauge to assess the cost increases

related to transmission construction between 2007 and 2011.

Table B-1 is a comparison of the contractors 2007 bid to the 2011 bid:

Table B-1

DPV2 Transmission Line Construction Bid 2007 and 2011 Comparison

Bid Year Cost (2012 $) Scope 2007 $132 million Construct approximately

152 miles 500 kV

2011 $269 million Construct 152 Miles 500 kV

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Compliance Impact on Transmission Line Construction Costs – June 2007

In the 2007 bid, bidding contractors were required to include the full cost to “design, engineer,

procure,10 construct and commission the project in accordance with all environmental and

health and safety conditions required by applicable laws and applicable permits of city, state,

and federal government.” In addition, the contractors were required to obtain, at their own

expense, multiple permits including the 401 Certification and Section 404 Permit and

developing and implementing a Storm Water Pollution Prevention Plan (SWPPP) under the

National Pollution Discharge Elimination System (NPDES).

In addition to securing and implementing the permits described above, the contractor’s bid

were to include the cost to comply with all of the mitigation measures and compliance

requirements described in the final EIR/EIS and the Mitigation Monitoring and Compliance

Reporting Program (MMCRP).

In its June 2007 bid, PAR Electric (PAR), the contractor that was ultimately awarded the

contract in 2011, proposed to use a qualified subcontractor to implement many of the required

mitigation measures. The qualified environmental team, as furnished by the subcontractor,

consisted of one permit coordinator, one lead environmental inspector, and one environmental

inspector.

Importantly, the total environmental cost identified in the contractor’s 2007 bid, including the

aforementioned permitting activities, was approximately $6.4 million. In addition to the primary

contractor’s subcontracted resources assigned to manage and implement all environmental

compliance related activities for the DPV2 Project, the SCE DPV2 project team had identified

one dedicated resource for environmental compliance in 2007.

Compliance Impact on Transmission Line Current Construction Costs

In May of 2008, SCE’s Petition for Modification (PFM) was adopted by the CPUC eliminating

the Arizona portion of the project and changing the justification from economic to supporting

renewable generation. Subsequent approval by the California Independent System Operator

(CAISO) was received in August of 2010 which allowed SCE to move forward with planning

the construction of the project. In April of 2011, SCE, and its Owner’s Engineer, Kenny

Construction Company, began the development of a specification to solicit bids on the updated

project.

The 2011 Specification, E-2011-31, (“2011 Spec”) differed from the 2007 Specification, E-700-

05-02, (“2007 Spec”), in several significant ways. First, the 2011 Spec would no longer be an

10

Procure” in this instance referred to minor materials, SCE was going to procure the major materials (Tower Steel, Conductor, insulators, etc.)

B-16

Engineer-Procure-Construct (EPC) model, but would be for construction of the transmission

line only. Second, the contractor permitting requirements included in the 2007 Spec were

largely removed and would be handled by SCE. For example, the contractor would no longer

be required to obtain the Clean Water Act (CWA) Section 401 Water Quality Certification, the

CWA Section 404 Dredge and Fill Permit, the California Department of Fish and Game 1602

Streambed Alteration Agreement, develop the Fugitive Dust Emission Control Plan (FDECP),

or have to develop the SWPPP. The development and obtaining of these plans and permits

would be the responsibility of SCE with the contractor required to implement the plans and

abide by the conditions of the permits. In addition, the 2011 Spec no longer required the

contractor to perform environmental, biological, or cultural construction monitoring. This would

be another responsibility assumed by SCE.

From 2007 to 2011, the contractor’s bid to construct the DPV2 Project increased by $137

million (2012 $). By the time the 2011 Specification was issued, the MMCRP was completed

detailing the interpretation by the Agencies of the specific requirements for the mitigation

measures and additional compliance measures had been imposed in the Biological Opinion.11

Compliance with these specific requirements contributed significantly to the cost increases.12

Although the relevant Laws and Acts under which the mitigation measures in the FEIR/FEIS

were written did not change appreciably between 2007 and 2011, recent interpretations of the

Lead Agencies, and their consultants, of those Laws and Acts, and what was considered to be

reasonable mitigation of identified impacts, were the main drivers in cost increases.

Based on discussions with the contractor, SCE has identified the primary drivers for the cost

increases between the 2007 and 2011 bids:

Partial Right of Way (ROW) Release

Previous contracts allowed for the complete release of the ROW for construction allowing the

contractor flexibility to move and control crews for maximum efficiency. As a result of the

CPUC’s NTP process, which requires that pre-construction mitigation measures and submittals

be completed before construction can commence, sites are released to the contractor

individually which eliminates the contractor’s flexibility in managing its crews. Specifically, this

process eliminates the ability to construct in a linear manner, which is most efficient, and

instead construction must move around to work the sites that have been “released”.

Specie Restrictions

Time limitations and decreases in available work areas from flora and fauna restrictions have

become more stringent over time despite no major changes in the relevant laws. For example,

11 The 2007 Spec dedicated approximately two pages detailing the environmental compliance requirements. The 2011 Spec provided well over 500 pages including 58 appendices relating to environmental compliance requirements. 12 Approximately $125 M of the $ 137 M increase in the 2011 bid was related to environmental considerations.

B-17

the Migratory Bird Treaty Act (MBTA) and the Endangered Species Act (ESA) did not change

between 2007 and 2011, however, the interpretations of the laws and acts by the lead

Agencies enforcing these laws and acts have changed significantly. For example, the MBTA

has no requirement relating to the need to establish “buffers” around nesting birds. However,

mitigation measures were created to establish buffers ranging from 300 to 500 feet to protect

nesting birds. Restrictions from these buffers have caused significant delays or shut down

construction sites entirely. As a result, contractors now must remove or secure netting around

all equipment and material at the beginning and end of each work day which negatively

impacts productivity.

Yard Restrictions

Previously, the only restrictions to Contractors in selecting their yards were primarily local

zoning requirements. This allowed the contractor to select the best yard locations to serve their

needs. Presently, the contractor yards are now considered to be part of the project and must

meet certain environmental requirements and be selected based upon environmental factors.

This causes yards to be selected in locations that are farther away from the actual construction

work, are not of sufficient size, or are otherwise not ideally suited to support construction. In

addition, the NTPs that approve the yards require additional requirements and conditions that

further inhibit the contractor’s efficiency.

Water Use, Dust Control, Stormwater Pollution Prevention Plan (SWPPP)

The requirements of the Fugitive Dust Emissions Control Plan and the SWPPP, as well as the

increased regulation of water sources, have increased significantly since 2007. The contractor

expects to spend approximately $20 million on watering the right-of-way (ROW) alone in 2012

and 2013.

Conclusion

This Appendix describes the cost increases associated with environmental activities and the

constraints the environmental requirements have on the cost to construct the Project. SCE’s

current estimate for completing the required environmental activities is $109.4 million. This

estimate includes the direct costs for environmental compliance related to land mitigation, the

cost of monitors, preparation of post-CPCN environmental documents, and supporting

resources. Additionally, the environmental mitigation requirements and other permit conditions

have measurably affected the cost to construct the Project by approximately $125 million. As

discussed above, these environmental activities, constraints and related costs are required to

enable SCE to meet the compliance requirements imposed by the agencies.

Appendix C

Transmission Line and Substation Cost

Detail

C-1

INTRODUCTION

As discussed in the advice letter, the majority of the costs for DCR are for the

transmission work, substation work and environmental requirements. Appendix B

discusses the costs related to environmental requirements. This Appendix provides a

more detailed discussion of the costs related to the transmission and substation

components of the DCR project. SCE is also providing in this Appendix a table

comparing the components of the project approved in D.07-01-040, and the

components of the current DCR project approved by the Commission in D.09-11-007,

D.11-07-011 and the CPUC’s May 2011, Project Memorandum.

The transmission and substation elements account for approximately $611.2 million of

the total $944.8 million updated cost estimate. Each element comprises costs

categorized as project engineering, management and support, materials, construction

and direct allocated costs. The following sections describe these categories for the

transmission and substation elements. All cost information in this appendix is

expressed in constant 2012 dollars, unless otherwise noted.

COST ESTIMATING PROCESS

SCE estimates bulk transmission work and substation elements with a common

approach. Each estimate starts with the engineering team developing a scope. The

scoping documents prescribe the required materials, which are used to compile a

material take off, listing the quantity of each required material. Quantities are multiplied

by two sets of unit costs: (1) costs associated with acquiring the material from qualified

manufacturers, and (2) costs associated with the installation or construction by qualified

resources. Both types of unit costs are based on purchase orders awarded for the

project and/or estimating assumptions developed by SCE based on experience and

known market conditions.

In addition, to the materials and construction costs, the project team develops

assumptions required to estimate the project management, engineering and support

costs. These costs are primarily labor related and are further detailed below. The

specific trades and amount of time are based on the complexity of the scope and SCE’s

experience. The wage rates are based on current employee wages, market reference

points, and purchase orders.

Finally, direct allocated and corporate overhead costs are applied. Direct allocated

costs include a range of activities and are further detailed below. Corporate overheads

are applied to the aforementioned costs and are further described below. The sum of

all these costs is included in the updated cost estimates provided in the Advice Filing.

C-2

TRANSMISSION LINE COST DETAIL

Bulk Transmission is generally defined as those transmission lines operating at 200kV

or above. These lines are part of the CAISO and under FERC jurisdiction. The bulk

transmission scope includes:

A. 110 miles of single circuit 500kV transmission line between Devers Substation to Colorado River Switchyard.

B. 42 miles of single circuit 500kV transmission line between Devers Substation to Valley Substation.

C. 2 miles of single circuit 500kV transmission line to loop the existing DPV1 line into the Colorado River Switchyard and associated modifications to DPV1.

The total cost of these elements is estimated to be $449.1 million. The following Table

C-1 summarizes the bulk transmission costs by these elements.

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Table C-1

Material

Material for transmission lines is primarily comprised of structural steel and conductor.

SCE procures these materials through competitive bidding processes that include

assessing vendors’ abilities to perform and pricing. Other materials common to SCE’s

entire transmission and distribution infrastructure are acquired in bulk, warehoused and

deployed to a variety of projects including DCR. Examples may include optical ground

wire, insulators, nuts, bolts, etc. These materials are also acquired from qualified

manufacturers.

Recorded Through 2011

Forecast2012 to 2014 Total Cost

(A) (B) (A+B)

1. Construct 110 mi 500kV T/L from Devers to Co. River Switchyard

Material $28,739 $15,889 $44,629Construction 10,487 169,912 180,399Proj Eng, Mgmt & Support 15,496 9,055 24,552Direct Allocated Cost 4,053 11,282 15,335

Total Direct Cost $58,776 $206,138 $264,915

2. Contruct 42 mi 500kV T/L from Devers to ValleyMaterial 16,277 7,626 23,903Construction 7,426 111,734 119,160Proj Eng, Mgmt & Support 9,073 5,757 14,829Direct Allocated Cost 3,183 6,735 9,919


3. Construct DPV1 Loop-In at Co. River SwitchyardMaterial 1,024 2,562 3,586Construction 14 10,973 10,988Proj Eng, Mgmt & Support 69 586 655Direct Allocated Cost 51 1,080 1,131


Total Trans (>200kV) Direct Cost $95,893 $353,193 $449,086

Summary of Transmission (>200kV)(2012$ Direct cost without Contingency, in Thousands)

C-4

Construction

The increase in construction costs is the major contributor to the overall increase in the

bulk transmission costs. Construction costs for the transmission line element are

primarily comprised of labor, equipment, foundations and the cost to develop or improve

access roads to structures.

SCE’s cost estimate for the transmission line components in this Advice filing is based

on the contract with PAR Electrical Contractors, Inc. (PAR), entered into following a

competitive procurement process.1 PAR is required to utilize union labor, provide the

equipment, obtain all local, ministerial permits, and adhere to all compliance measures.

PAR and the other bidders were provided information regarding known compliance

requirements.

As discussed in Appendix B, the bids were significantly higher than SCE had originally

estimated.2 SCE asked PAR what were the factors resulting in the significant cost

increase from the previously submitted informational bid to construct DPV2 in 2007.

PAR indicated that the major contributor to the increase is related to the environmental

and permit compliance. Further discussion on this topic is provided in Appendix B.

The costs of material yards and handling of transmission line equipment, conductor pull

sites, construction management, and Owner’s Engineer services are also included

under construction. The Owner’s Engineer provides construction planning, construction

safety program oversight, material yard management and claims support, and other

construction management services.

Project Engineering, Management and Support

The costs associated with Project engineering, management and support for

transmission lines are primarily comprised of labor. The project requires a variety of

engineering disciplines, such as electrical, structural, civil and geotechnical. The

1 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-2011-31 (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.

2 After receiving the CPCN, but prior to ACC action, SCE had begun the process of soliciting bids to construct DPV2, and had solicited nonbinding informational bids. After the ACC denied the CEC, those bids were not used, but the information received helped form SCE’s expectations for the transmission line construction costs.

C-5

engineering work includes individually designing each tower, which involves the type of

structure, height, loading conditions, and foundation requirements. The conductor is

specified based on design capacity of the transmission.

Project management and support is required to help ensure effective planning,

governance and execution of the project. Effective execution requires integrating not

only different engineering disciplines, but also the joint effort of many other disciplines

such as those in construction, real estate, procurement, environmental, financial, and

regulatory compliance. Besides managing the internal disciplines, Project management

and support must also oversee the activities between the Construction contractor and

the Owners Engineer to ensure that cost, scope, and schedule are in accordance with

the contracts. This requires management of the overall project budget and the

development of a master integrated schedule, which comprises thousands of

interrelated activities used to manage all aspects of the project. Project management

oversees the correct allocation of costs by project element in order to attribute costs

eligible for incentive treatment, produce effective cost forecasts, and to impose

corrective action when necessary.

Direct Allocated Costs

Direct allocated costs are operational resources and items centrally managed to be cost

effective and/or ensure consistency. All SCE’s projects are subject to these allocations.

Managerial and administrative resources for the operational organizations are examples

of costs allocated to capital projects and maintenance activities. Other costs not unique

to DCR are managed in aggregate at the operational level, such as: vehicles, tools and

supplies for field work; and, computers and servers for information and data sharing,

analyzing and reporting. Direct allocated costs are for essential activities that SCE’s

operational organizations incur for all of SCE’s capital projects, operations and

maintenance activities.

SUBSTATION COST DETAIL

The costs in the Substation category primarily include the modification and additions to

the Devers and Valley Substations, the cost of the new Colorado River Switchyard,3

and the costs of the new series capacitor. As stated in the advice letter, the cost of

3 This refers to the 500 kV portion of the substation, but not the 500/220 kV transformation and 220 kV

equipment. SCE is constructing the entire substation facility; however, the costs in this Advice Filing only include the 500 kV switchyard elements, and not the elements for the full substation expansion. Appendix D explains the method SCE uses to allocate costs between DCR and the Colorado River Substation Expansion Project.

C-6

substation work has decreased from $210.6 million to $162.1 million. The scope of

substation work for DCR is made up of five elements.

• Largest element is the new Colorado River Switchyard, which is a portion of the Colorado River Substation.

• Modifications/additions to the existing Devers Substation, including new line positions, a bus extension, circuit breaker upgrades, adding breakers to the existing shunt reactors, and line protection equipment such as relays.

• Modifications/additions to the existing Valley Substation, including new line positions, adding breakers to the existing shunt reactors, and line protection equipment such as relays.

• Installation of new series capacitor east of Devers Substation along the new transmission line and adjacent to the existing DPV1 series capacitor.

• Removal of wave traps and line tuners at the Palo Verde Substation in Arizona.

The majority 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.4 The total cost of the

substation category is estimated to be $162.1 million. Table C-2 summarizes the

substation costs by element.

4 SCE has not yet completed final engineering for the Colorado River Substation. The cost estimates

contained in this Advice filing are based on preliminary engineering.

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Table C-2

Rec'd through 2011 To Go Total Cost(A) (B) (A+B)

1. Construct Colorado River SwitchyardMaterial $1,494 $28,177 $29,672Construction 1,117 40,618 41,735Proj Eng, Mgmt & Support 1,818 13,526 15,344Direct Allocated Cost 449 10,246 10,695


2. Upgrade Devers SubstationMaterial 10 8,061 8,071Construction 45 6,871 6,916Proj Eng, Mgmt & Support 1,002 2,839 3,840Direct Allocated Cost 56 2,843 2,899


3. Upgrade Valley SubstationMaterial 7 3,512 3,519Construction 30 3,144 3,174Proj Eng, Mgmt & Support 273 1,268 1,541Direct Allocated Cost 31 1,187 1,217

Total Direct Cost $341 $9,111 $9,452

4. Construct California Series CapacitorMaterial 11 1,946 1,957Construction 73 23,078 23,151Proj Eng, Mgmt & Support 783 4,756 5,539Direct Allocated Cost 73 2,708 2,781

Total Direct Cost $940 $32,487 $33,426

5. Remove Wave-Traps and Line-Tuners at Palo Verde Swyd

Material 0 65 65Construction 0 13 13Proj Eng, Mgmt & Support 0 2 2Direct Allocated Cost 0 20 20

Total Direct Cost $0 $100 $100

Total Substation Direct Cost $7,271 $154,879 $162,150

Summary of Substation(2012$ Direct cost without Contingency, in Thousands)

C-8

Material

SCE procures some of the materials for substation through multiple competitive bidding

processes that include assessing vendors’ abilities to perform besides pricing. Some

materials are procured using master service agreements, which are competitively bid.

Costly materials include series capacitors, circuit breakers, control building, ground grid,

shunt reactors and structural steel. Some of these materials are common to SCE’s

entire transmission and distribution infrastructure, and are acquired in bulk, warehoused

and deployed to a variety of projects including DCR.

Construction

Construction for substations is often organized by trade, also known as work packages

– civil (grading), structural, and electrical. Depending on the scope complexity, some

elements utilize multiple contracts whereas others utilize a bundled contract. Contracts

are awarded based on competitive bidding processes.

For the new Colorado Switchyard, SCE has awarded the civil work, which includes

grading, dirt access road, fencing, and ground wire, to one vendor and the estimate is

based on the contract. SCE has awarded another major contract covering the

remaining civil work, structural work and electrical work, and the estimate is based on

this contract. The remaining substation elements will be awarded through competitive

bidding processes after additional engineering.

Project Engineering, Management and Support

Similar to transmission lines, project engineering, management and support for

substations is primarily comprised of labor. The substations require a variety of

engineering disciplines, such as electrical, structural, civil and geotechnical. The

engineering work includes designing the configuration of the positions and structures

required to connect different transmissions lines in and out of the switchyard.

Developing complicated communication and switching schemes is another crucial

aspect for substation design. Upgrades are required at other existing substations to

help integrate the safe and reliable operation of the new transmission lines and

switchyard with the overall network. Project management and support is discussed

above under the bulk transmission.

Direct Allocated Costs

Direct allocated costs for substations contain cost for resources and items centrally

managed to be cost effective and/or ensure consistency. Please refer to the bulk

transmission discussion for details regarding direct allocated costs.

C-9

Detailed Comparison of Changes in Project Scope and Costs

To help compare the changes in project scope and costs to the CPCN, SCE is providing

Table C-3. The Table builds upon the cost table from SCE’s DPV2 CPCN cost

testimony. The left columns depict the changes in scope by element between the

CPCN and the current project scope. The right columns depict the changes in costs by

element between the CPCN and the current estimates. SCE proposes that the project

cost cap be updated to $944.8 million to reflect the changes to the project since the

2005 CPCN.

C-10

Table C-3

Item # CPCN Advice Filing Change CPCN CPCN Adjusted* Advice Filing

1Devers-Palo Verde No. 2 Planning,

Preliminary Engineering and Licensing

Devers-Colorado River Project

Planning, Preliminary Engineering and

Licensing

PFM required to remove the Arizona

portion of DPV2$11.7 $11.7 $25.9

2

Build 125.4 miles (mi) of single-circuit

500 kilovolt (kV) transmission line (T/L)

with 2 bundled conductors between

Devers Substation and California

/Arizona border. Install a single fiber

optic ground wire on the new towers.

Build a 110 mile single circuit 500kV

T/L paralleling the existing Devers-Palo

Verde #1 T/L, from the Devers

Substation to the new Colorado River

Switchyard. Install a single fiber optic

ground wire on the new towers.

Transmission line length reduced by 15

miles to terminate at the Colorado River

Switchyard site instead of the CA/AZ

border

$106.0 $106.0 $196.6

3

Build 71.8 mi of single circuit 500 kV

T/L with 2 bundled conductors between

the California / Arizona border and

Harquahala 500kV Switchyard. Install a

single fiber optic ground wire on the

new towers.

Removed from Current Project Arizona scope removed for CA only project $53.2 $53.2 -

4

Devers Substation: Extend the 500kV

bus and add a new line position. Equip

the position by installing two 500kV

circuit breakers, line reactor, and all

associated equipment to terminate the

Devers-Harquahala 500 kV line.

Devers Substation: Extend the 500kV

bus and add two line positions. Equip

two positions by installing two 500kV

circuit breakers, line reactor, and all

associated equipment to terminate the

Devers-Valley and Devers-Colorado

River 500 kV lines.

Combined items with items 7 and 28 $10.7 $15.7 $13.1

5Devers Substation: Install two 500kV

shunt capacitors.Removed from Current Project Revised engineering studies with CAISO $17.7 $17.7 -

6

Devers Substation: Install a static

variable compensator (SVC) and all

associated equipment on the 500 kV

bus.

Removed from Current Project Revised engineering studies with CAISO $45.0 $45.0 -

7

Devers Substation: Install conduit

between new Devers-Harquahala

transmission line tower to the

communication room for the single fiber

optic ground wire.

Consolidated to item 4 Consolidated to item 4 $0.1Consolidated to

Item 4-

8

McCullough Substation (LADWP): The

cost represents SCE's share of

replacing circuit breakers to mitigate

short circuit duty.

Removed from Current Project Not a capital expenditure $0.1 $0.1 $0.0

9

Design and install a special protection

scheme (SPS) to trip 12 generating

units at generating stations in the Palo

Verde Hub area in Arizona area.


10

Design and install an SPS to shed load

at various SCE substation facilities for

the loss of DPV1 and DPV2 T/L's.

Removed from Current Project Revised engineering and/or estimate $1.0 $1.0 -

11

Arizona Site: Install a series capacitor

bank west of Harquahala Substation on

the new 500kV T/L and adjacent to the

existing DPV1 series capacitor.


12

California Site: Install a series

capacitor bank east of Devers

Substation on the new 500kV T/L and

adjacent to the existing DPV1 series

capacitor.

California Site: Install a series

capacitor bank east of Devers

Substation on the new 500kV T/L and

adjacent to the existing DPV1 series

capacitor.

Increase capacity from 2,700 amps to

3,800 amps $17.4 $17.4 $24.8

13

Acquire property near Blythe and

Harquahala Mountain for

telecommunication facilities.


14

Acquire property from Devers

substation to the Colorado River for the

new 500kV T/L.


item 36-

15Telecommunication equipment for

protection requirements.Consolidated to item 37 Consolidated to item 37 $5.1

Consolidated to

item 37-

16Telecommunication equipment for SPS

in Arizona.Removed from Current Project Arizona scope removed for CA only project $3.9 $3.9 -

17Telecommunication equipment for SPS

in California.Removed from Current Project Revised engineering $0.4 $0.4 -

18

Devers Substation: Replace ten 230kV

circuit breakers and upgrade two

230kV circuit breakers.

Devers Substation: Replace and

upgrade circuit breakers.

Construction labor increases higher than

general escalation rates$2.0 $2.0 $3.0

2005 Constant Dollars

C-11

Table C-3 (con’t)

19

Harquahala Switchyard: Install a

500kV bus and add a new line position.

Equip the position by installing two

500kV circuit breakers, line reactor,

and all associated equipment to

terminate the Devers-Harquahala 500

kV line. Install new MEER.


20

Harquahala Switchyard: Install all

equipment to provide full supervisory

control and data acquisition.


21Harquahala Switchyard: Purchase the

500kV switchyard.Removed from Current Project Arizona scope removed for CA only project $10.5 $10.5 -

22

Hassayampa Switchyard: Purchase

facilities for telecommunication and

protection as part of the Harquahala-

Hassayampa 500 kV T/L acquisition.


23Acquire existing 25 mi Harquahala-

Hassayampa 500 kV T/L.Removed from Current Project Arizona scope removed for CA only project $12.7 $12.7 -

24

Build 35.5 mi of single circuit 500 kV

T/L with 2 bundled conductors from

Turn-off point to Harquahala via

Harquahala jct.


25Acquire Real Estate from the California

/Arizona border to Harquahala.Removed from Current Project Arizona scope removed for CA only project $1.4 $1.4 -

26

Design an SPS No.2 to shed load at

various SCE substation facilities for the

loss of Devers-Valley No.1 and Devers-

Valley No. 2.

Removed from Current Project Revised engineering $1.0 $1.0 -

27

Build 41.6 mi of single-circuit 500 kV

T/L paralleling the existing Devers-

Valley 500 kV line and relocate the

Devers-Valley 500 kV line south of

Cabazon.

Build 42 mi of single-circuit 500 kV T/L

paralleling the existing Devers-Valley

500 kV line and relocate the Devers-

Valley 500 kV line south of Cabazon.

Scope changed, in terms of specific tower

types, number of types, weight of types$55.5 $55.5 $124.6

28

Devers Substation: Add all appropriate

facilities to connect the Devers-Valley

No.2 500kV T/L line.


Item 4-

29

Valley Substation: Add all appropriate


No.2 500 kV line.

Valley Substation: Add all appropriate


No.2 500 kV line.

Addition of transformer and construction

labor increases$4.9 $4.9 $7.0

30

Acquire Property in California to

accommodate the Devers - Valley

Alternative.


item 36-

31Telecommunication equipment for the

Devers- Valley No.2 500kV T/L.Consolidated to item 37 Consolidated to item 37 $0.4

Consolidated to

item 37-

32 Item was not in CPCN Cost CapDPV #1 T/L Loop into Colorado River

Swithyard

CPCN did not include Colorado River

Switchyard$0.0 - $12.1

33 Item was not in CPCN Cost CapDistribution (Colorado River Switchyard

Light and Power)

CPCN did not include Colorado River


34 Item was not in CPCN Cost Cap Colorado River SwitchyardCPCN did not include Colorado River


35 Item was not in CPCN Cost Cap Environmental Mitigation & MonitoringCPCN did not include monitoring and

mitigation (see Appendix B)$0.0 - $81.2

36 Previously Items 14 and 30 Consolidated Real Estate

Real estate requirements changed

consistent with scope refinements since

CPCN

$0.0 $5.0 $3.2

37 Previously Items 15 and 31

Install various microwave and fiber optic

telecommunications systems, for

protection of the 500kV T/L Network.

Communication requirements changed

consistent with scope refinements since

CPCN

$0.0 $5.5 $4.4

38 Item was not in CPCNRemove wave traps and line tuners

from Palo Verde Generation Station$0.0 - $0.1

Direct without contingency Direct Total without Contingency $440.2 $440.2 $569.0

Contingency Contingency $63.0 $63.0 $85.3

Subtotal: Direct + Contingency Sub Total = Direct + Contingency $503.2 $503.2 $654.3P&B and A&G P&B and A&G $42.1 $42.1 $47.0

Total ProjectTotal = Direct + Contingency + P&B

and A&G $545.3 $545.3 $701.3

$243.5

$944.8

*CPCN Adjusted value reflects combined items to

facilitate comparison to the Advice Filing numbers

Escalation from 2005 $ to 2012 $

Total Project Cost (2012 $)

Appendix D

CRS Cost Assignment and Allocation

D-1

This appendix explains the methodology for assigning or allocating the costs of the Colorado River Substation (CRS) between the (1) DCR Project (the subject of this Advice Letter); (2) the expansion facilities that were the subject of A.10-11-005 and approved by the Commission in D.11-07-011 (Colorado River Substation Expansion (CRSE) costs), and (3) interconnecting generators. SCE is constructing CRS as one facility. Doing so allows SCE to maximize efficiencies by using one contractor and doing the work concurrently, resulting in overall cost savings to customers. CRS, for example, is staffed with one project management team, one engineering team, and one construction management team. The costs associated with these teams are allocated to DCR, CRSE and interconnecting generators. Similarly, the transmission elements of the Project are managed with the same resources as CRS. The Red Bluff Substation project is the subject of CPUC Proceeding A.10-11-012 and approved by the Commission in D.11-07-020. Directly Assigned Costs The majority of costs are directly assigned to DCR, CRSE, Red Bluff or the interconnecting generators. Costs are directly assigned when it is clear that the costs are necessary for one of the three projects (DCR, CRSE or the interconnecting generators). The elements assigned directly to DCR include the costs associated with the 500 kV switchyard. These facilities include, but are not limited to, the 500 kV circuit breakers, line positions, disconnect switches and structures, relay panels, capacitive coupled voltage transformers (CCVTs) and surge arrestors, line shunt reactors, emergency generator, mechanical electrical engineering room (MEER), battery and related equipment, telecommunications, water well, and other 500 kV-related equipment. A few of these facilities, like the emergency generator, MEER, and water well, will serve CRSE and the interconnecting generators as well as DCR. However, the costs have been assigned directly to DCR because these costs would have been incurred if there was no CRSE or interconnecting generators. These costs are all required to construct the Colorado River Switchyard. Other common work and cost components assigned directly to DCR that benefit the other project and interconnecting generators include the access road, material laydown yards, mobilization costs, and construction trailers. These items are needed for the switchyard without regard to the CRSE and interconnecting generators, and therefore are properly assigned to DCR. The elements assigned directly to CRSE include all equipment and work associated with constructing just the 220 kV switchyard and 500/220 kV transformation. The 220 kV switchyard facilities include the 220 kV circuit breakers, line positions, disconnect switches and structures, relay panels, CCVTs, surge arrestors, bus supports, and

D-2

related equipment. The 500/220 kV transformation facilities directly assignable to CRSE include the 500/220 KV transformers and bus work, current limiting reactors, 500 kV circuit breakers, disconnect switches and structures, surge arrestors, and related structures, and 220 kV equipment including circuit breakers, disconnect switches, CCVTs, surge arrestors, and structures. These items are only required because of the substation expansion. The elements assigned directly to the interconnection generators include all equipment and work associated with just connecting the generators to the substation. These facilities include, but are not limited to, 220 kV CCVTs, current differential relays, remote terminal units (RTUs), dead end structures, insulators and hardware assemblies, along with conductor spans and necessary telecommunication and protection equipment. These items are only required because of the interconnecting generators and SCE accounts for these items and costs by customer. Allocation Method(s) – Substation For substation costs that cannot be directly assigned as noted above, SCE allocated the costs among DCR, CRSE, and interconnecting generators in accordance with appropriate cost allocation methodologies. SCE is using two allocation methodologies: one based on acreage and one based on estimated costs of the work. Certain elements were allocated based on the acreage of CRS. As noted in the Supplemental Environmental Impact Report, CRS measures approximately 77 acres within the perimeter wall. The original scope of CRS only included the switchyard, as part of DCR, and was thus 44 acres. Expanding upon the switchyard to drop the voltage from 500kV to 220kV resulted in 77 acres for the entire substation, thus an additional 33 acres is attributable to the CRSE. This results in a 57 percent allocation to DCR and a 43 percent allocation to CRSE for those elements affected by the size and area of the substation. Examples of elements and work affected by acreage include site preparation, perimeter wall, the inside driveway and gravel/rocking, security, and environmental survey work. The costs of these elements are then allocated to DCR and CRSE based on percentages described above. SCE also allocated the project management, engineering and support costs to each project and interconnecting generator. This allows the project management, engineering teams, and other support resources to charge one order that can then be allocated to DCR, CRSE, and the interconnecting generators. Because the work these resources perform is integrated across the substation, it would be overly complex for each of these groups and resources to charge their hours to separate project orders. The allocation factors are based on separate cost estimates for the project development and management of each project and similar work required for the interconnection customers. SCE estimated the cost of project management, engineering and support for each project and used these estimates to develop percentage allocation factors by dividing each estimate into these amounts. The current allocation is 31 percent for DCR, 66 percent for CRSE, and 1.5 percent for each of the two interconnecting

D-3

generators.1 To simplify the process and ensure there is consistency, an order was created with a settlement rule which allocates these costs to the appropriate project based on the percentages described above. This rule can be adjusted as changes are introduced (e.g. customer is added or removed or an estimate revised). Allocation Method(s) – Transmission The allocation of costs for 500kV transmission work is limited to the project management and support costs. These allocations are derived using the same weighing approach discussed above for CRS. SCE estimates the cost of project management and support for each project’s transmission elements. This allocation method weighs this portion of each project’s estimate relative to the sum total of all the projects. The allocation is 4% and 96% for Red Bluff Substation project and DCR project, respectively.

1 The allocations are subject to change. For example, the BSPP is currently being re-estimated, if the engineering and project management cost change for this project, then the allocations may change as well.