Exhibit No.: / SCE
Witnesses: / Thomas A. Burhenn
Bryan W. Frazee
Terry Ohanian
Daniel C. Pearson
Jack Sahl
Fred W. Salzmann
Les Starck
Robert K. Stiens
Gilbert Tam
(U 338E)
Southern California Edison Company’s Phase II Supplemental Direct TestimonyBefore the
Public Utilities Commission of the State of California
Rosemead, CaliforniaJuly 7, 2006
I. INTRODUCTION 1
II. COST SUPPPORT FOR DPV2 PROJECT AND ALTERNATES 2 Ohanian/Salzmann
III. Route Selection The Devers Valley NO. 2 Alternate Route 7 Starck
IV. ArIZONA PUBLIC SERVICE TS5 Project UPDATE 9 Tam
V. The Commission Should Not Condition Approval of DPV2 Upon the City of Los ANGELES Department of Water and Power Participation 11 Frazee
VI. Additional EMF Studies 12 Sahl
VII. CompLIANCE with Public Utilities Code Section625 15 Burhenn
VIII. Updated Information on Environmental Reviews 16 Pearson
IX. Updated Information on PUBLIC INVOLVEMENT 18 Stiens
Appendix A - WITNESS QUALIFICATIONS A-1
APPENDIX B - COST DATA b-1
APPENDIX C - COST DATA - RELATED MAPS c-1
DPV2 Update July 7.DOC ii 7/7/2006 3:15 PM
SOUTHERN CALIFORNIA EDISON COMPANY’S (U 338E)
PHASE II SUPPLEMENTAL DIRECT TESTIMONY
List Of Tables
Table / PageTable II1 Summary Of Proposed And Alternate Routes 3
Table VI2 Proposed Magnetic Field Reduction Measures, Costs, And Percentage Magnetic Field Reductions 14
Table VIII3 Major Environmental And RightOfWay Approvals, Permits Or Other Actions Required Prior To Construction Of DPV2 In Arizona And California 16
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I. INTRODUCTION
Pursuant to Administrative Law Judge’s (“ALJ”) October28, 2005 Ruling, the Southern California Edison Company (“SCE”) submits this Phase II supplemental direct testimony on Application No.(“A.”)0504015 on the DeversPalo Verde No.2 Transmission Line Project (“DPV2”).
On April 11, 2005, SCE filed an application for a Certificate of Public Convenience and Necessity (“CPCN application”) authorizing the construction of DPV2. In the January 2006 hearings on PhaseI, the Commission addressed “issues related to the need for the DPV2 transmission project.”[1] SCE demonstrated that the DPV2 project was cost effective for customers. All parties in PhaseI of this proceeding either agreed with, or did not controvert, SCE’s evidence on the need for DPV2. The California Independent System Operator (“CAISO”) and Division of Ratepayer Advocates (“DRA”) presented an independent analysis that agreed with SCE’s conclusion that the project was cost effective.
SCE filed its Proponent’s Environmental Assessment (“PEA”) and prepared testimony regarding DPV2 with its April11, 2005 CPCN application. The August26, 2005 Scoping Memo of Assigned Commissioner, directed SCE to submit additional information on the following topics:
· Cost support for the DPV2 project and project alternatives;
· SCE’s Electric Magnetic Field (“EMF”) management plan; and
· Compliance with Pub. Util. Code §625.
SCE provides additional direct testimony on these items and updates information related to the project and alternates, below.
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II. COST SUPPPORT FOR DPV2 PROJECT AND ALTERNATES
In its April 11, 2005 application, SCE stated that the estimated costs for DPV2 construction are $591million in 2005 dollars.[2] This estimate included pension, benefits, and administrative and general overhead, but did not include Allowance for Funds Used During Construction (“AFUDC”). The DRA reviewed the preliminary estimates that SCE provided in Phase 1 and found them to be reasonable for the purposes of determining need:
“Based on my experience, these cost estimates for the DPV2 project appear reasonable for purposes of performing a costeffectiveness analysis and apparently reflect the benefit of using existing right of way and SCE’s knowledge of the costs of DPV2 and the prior DPV2 application.”[3]
The August 26, 2005 Scoping Memo requested that SCE provide cost information on the expected project costs in sufficient detail so as to allow the Commission to assess the costeffectiveness and thus the need for the proposed project. The Commission requested estimates of AFUDC and cost information regarding alternate routes and configurations.[4]
In AppendixB, SCE presents updated and more refined estimates to give the Commission an understanding of the basis for our ‘preliminary’ estimates. These estimates itemize the major costs of 500kV and 220kV transmission lines, substation modifications, series compensation, land and easement acquisitions, facilities acquisitions and telecommunications. They will be further refined after final engineering and design of the complete project.
Additionally, in Appendix B, SCE provides cost estimates for several alternate routes that are considered in the Draft EIR/EIS.[5] SCE developed a cost matrix that allows cost estimates to be generated for full project routes by adding up the costs of various combined route segments in the costmatrix.[6] A summary of SCE’s total cost estimates for some of the alternates follow.
Table II1Summary Of Proposed And Alternate Routes
(Includes P&B, A&G, and AFUDC)
Proposed: Devers Harquahala and West of Devers / $ 624.412 million
Alternate 1 Harquahala West Alternative / $ 609.823 million
Alternate 2 Palo Verde Alternative / $ 600.777 million
Alternate 3 Harquahala Junction Alternative and DeversValley No. 2 / $ 565.013 million
Alternate 4 DeversValley No. 2 Alternative / $ 589. 299 million
The designation of the alternate routes are consistent with the descriptions in the Executive Summary of the Draft EIR/EIS, dated May 2006.
Draft EIR/EIS describes a “Palo Verde Alternative” (Alternate 2 in TableII1, above) as an alternative where the DPV2 line would terminate at the Palo Verde Nuclear Generating Station Switchyard) instead of Harquahala Generating Switchyard). Although SCE has included the Palo Verde Alternate in TableII1, the Commission should be aware that there are issues regarding termination of the DPV2 line at the PaloVerde Hub that may make it nonviable. The Arizona Corporation Commission (“ACC”) discourages new transmission line interconnections at the Palo Verde Switchyard. In an August17, 2005 decision granting a Certificate of Environmental Compatibility (“CEC”) to Arizona Public Service (“APS”), APS was required to pursue goodfaith efforts to reach agreements for interconnection at a new Arlington Valley 500kV Switchyard, and/or a new Harquahala Junction 500kV Switchyard instead of the PaloVerde Switchyard. APS was prohibited from signing an interconnection agreement to interconnect at PaloVerde until it had pursued such goodfaith efforts and reported on those efforts to the ACC's Utilities Division. (ACC Decision No.68063, Condition No.24.) It is clear from Condition No.24 that the ACC considers further interconnections or line terminations at the PaloVerde Switchyard a last resort.
Additionally, the ACC staff recommends that sponsors of new transmission lines should consider, “for overall diversity, performance, and risk mitigation,” interconnecting at one of the power plant switchyards around the PaloVerde Hub rather than connecting directly to the PaloVerde Nuclear switchyard.[7] Because the ACC and ACC staff appear to disfavor the PaloVerde Alternative, the Commission should approve Alternate3 (if SCE, APS, and HGC reach agreement on a joint project arrangement and Harquahala Junction switchyard is built) and Alternate4. As explained by Mr.Tam’s testimony, the proposed joint project negotiations, which include the Harquahala Junction switchyard component of Alternate 3, among SCE, APS, and HGC, are ongoing. Because the Harquahala Junction switchyard design and the associated cost-sharing arrangements under the proposed joint project described by Mr.Tam have not been finalized, SCE based its cost estimates for Alternative 3 on preliminary design work. If Alternate3 is ultimately agreed to by the parties and the ISO approves, SCE will submit an updated cost estimate to the Commission.
SCE based its cost estimates on preliminary design work, as detailed costestimates have only been completed for some components. The full detailed engineering and cost estimates have not yet been completed. Additionally, some of the environmental and EMF measures may not be fully developed at this time. In developing the estimates, SCE has included reasonable allowances and contingency factors. Upon completion of the final, detailed engineering, design-based construction estimates for the approved project, SCE will submit the final estimate to the Commission consistent with the practices for other CPCNs.
In D.0408046, the Commission recognized that the Federal Energy Regulatory Commission (“FERC”) will ultimately decide how much of the costs the utility may reflect in transmission rates.[8] However, SCE recognizes that the Commission believes that the Commission is obligated by Pub. Util. Code §1005.5(a)[9] to specify “a maximum amount determined to be reasonable and prudent for the facility”. This ‘reasonable amount’ has been called a ‘cost cap’ even though the Commission has in fact recognized that the costs submitted in a CPCN Application are based on preliminary design estimates, and that after the CPCN is granted, the cost estimates will be adjusted based on the route selected by the Commission, the final engineering design, environmental mitigation requirements, and other factors.
Pub. Util. Code § 1005.5(b) specifically allows the utility applicant to seek additional cost recovery beyond that originally set forth in the CPCN Application after the decision granting the CPCN has been issued.[10] For example, if the Bureau of Land Management (“BLM”) or Commission imposes mitigation measures, the Commission should address an appropriate request for an increase in the cost cap pursuant to Pub. Util. Code § 1005.5(b). In addition, SCE proposes the use of deflation factors to convert actual expenditures in future years to their equivalent value in 2005 dollars. SCE believes the deflation factors should be calculated using an index such as the HandyWhitman Index of Public Utility Construction Costs and considering other factors that have significant influences on the cost of the project.
For all the above reasons, SCE suggests that the Commission adopt provisions similar to those included in D.8812030, the Commission’s first decision granting a CPCN for DPV2.[11] Specifically, the Commission should authorize SCE to seek adjustments based on changes in cost estimates, once SCE completes final, detailed designbased construction estimates due to:
1. adjustments in project costs because of any unanticipated delays in starting the project or inflation;
2. adjustments in project costs as a result of final design criteria; and
3. additional project costs resulting from the adopted mitigation measures (and mitigation monitoring program).
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III. Route Selection The Devers Valley NO. 2 Alternate Route
SCE’s CPCN application describes the need for construction of upgrades to four of SCE’s existing 230kV transmission lines that are located west of the Devers substation (“West of Devers Upgrades”). The existing 230kV transmission lines currently cross over lands of the Morongo Band of Mission Indians (“Tribe”), pursuant to several existing rightofway agreements between SCE and the Tribe. These rightofway agreements begin to expire in 2010.
SCE and the Tribe are engaged in discussions regarding this Application. While the CPCN application has proposed West of Devers Upgrades that crosses over the existing lands of the Tribe, the Tribe has informed SCE that continued use of these lands is not acceptable. However, the Tribe has expressed the willingness to negotiate an agreement for an entirely new rightofway corridor that would be located some distance away from the existing West of Devers substation corridor. A new rightofway corridor as suggested by the Tribe would cross less of the reservation and more privately owned land. SCE and the Tribe have recently begun good-faith efforts to identify such a new rightofway corridor. Following development of a new rightofway corridor and rightofway agreement, such agreement would be subject to approvals by the Morongo Tribal Council, Tribal membership, and the Bureau of Indian Affairs.
SCE remains committed to continuing negotiations with the Tribe for a new rightofway that would address SCE’s continuing needs for transmission. SCE anticipates that the negotiations with the Tribe will need to continue independently of the DPV2 project licensing schedule. This will allow the parties sufficient time to reach a mutually acceptable agreement.
On May 4, 2006, and as part of this proceeding, the Commission and the Bureau of Land Management (“BLM”) issued a Joint Draft EIR/EIS that evaluates an alternate route to SCE’s proposed West of Devers Upgrades. This alternate would require construction of a new 500kV transmission line from the Devers substation to the Valley substation (“DeversValley No. 2 Alternative”). The Draft EIR/EIS states that the DeversValley No. 2 Alternative would “avoid impacts associated with traversing highdensity residential areas and tribal lands”. The Draft EIR/EIS also notes the “potential legal feasibility challenges of the West of Devers segment over Morongo Tribal lands” and that the DeversValley No. 2 Alternative would eliminate “the impacts of all West of Devers Upgrades”.[12] The Draft EIR/EIS also concludes that the DeversValley No.2 Alternative would meet the objective of the DPV2 project and is feasible.
SCE has evaluated the DeversValley No. 2 Alternative and agrees with the conclusion of the Commission and BLM that it is an acceptable and viable alternative to the West of Devers Upgrades. Because the Tribe has informed SCE that its proposed West of Devers Upgrades are not acceptable, SCE has concluded that such upgrades are not feasible. Accordingly, SCE recommends that the CPUC adopt the DeversValley No.2 Alternative in lieu of the West of Devers Upgrades. Adoption of the DeversValley No.2 Alternative will not only allow for completion of the DPV2 project within the current licensing schedule, it will allow SCE and the Tribe to continue to negotiate a new rightofway agreement independent of the DPV2 licensing schedule.
For all the above reasons, the Commission should issue a decision adopting the DeversValley No.2 Alternative.
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IV. ArIZONA PUBLIC SERVICE TS5 Project UPDATE
In its April 11, 2005 CPCN Application[13] SCE indicated that APS and SCE were discussing a potential joint project arrangement in which the parties (subject to the parties ability to reach a mutually acceptable agreement) would share the existing HarquahalaHassayampa 500kV transmission line (which SCE plans to acquire from Harquahala Generating Company (“HGC”) pursuant to the Option Agreement to complete the connection of the DPV2 project to the Hassayampa Switchyard as described in PEA VolumeI, PartI, Section2.3.2 and thereby defer the need for APS to construct an additional 500kV line into the PaloVerde Hub.
SCE’s preferred option at this time is to terminate at the existing Harquahala Generating Station Switchyard as described in PEA VolumeI, PartI, Section2.3.2. Discussions among SCE, APS, and HGC are ongoing. If ultimately agreed upon by the parties and the CAISO, the proposed joint project arrangement could provide for interconnection of the proposed DeversHarquahala 500kV line, the existing HarquahalaHassayampa 500kV line, and the certificated APS Palo Verde HubTS5 500kV line at a new Harquahala Junction Switchyard.