april 7, 2017 ms. kimberly d. bose, secretary federal energy … · ms. kimberly d. bose, secretary...

Rebecca Furman Senior Attorney

Transmission and Wholesale Market Issues

[email protected]

P.O. Box 800 2244 Walnut Grove Ave. Rosemead, California 91770 Tel. (626) 302-3475 Fax (626) 302-1935

April 7, 2017

Ms. Kimberly D. Bose, Secretary Federal Energy Regulatory Commission 888 First Street, N.E. Washington, DC 20426

Re: Petition for Declaratory Order

Dear Ms. Bose:

Pursuant to Rule 207(a)(2) of the Rules of Practice and Procedure of the Federal Energy Regulatory Commission, Southern California Edison Company (“SCE”) hereby respectfully submits this Petition for Declaratory Order and the accompanying Direct Testimony of Charles Adamson, Fernando Benavides, Garry Chinn and Paul Hunt in support of the Petition. In accordance with the Commission’s Annual Update of Filing Fees, issued on January 11, 2017 in Docket No. RM17-6-000, SCE is submitting a check for the required $25,640.00 filing fee by overnight mail concurrently with this electronic submission of the Petition for Declaratory Order. Please do not hesitate to contact the undersigned regarding this submittal. Respectfully submitted, /s/ Rebecca A. Furman Rebecca A. Furman

RAF:raf

Enclosures

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UNITED STATES OF AMERICA BEFORE THE

FEDERAL ENERGY REGULATORY COMMISSION

Southern California Edison Company ) Docket No. EL17-63-000

PETITION OF

SOUTHERN CALIFORNIA EDISON COMPANY FOR DECLARATORY ORDER

Pursuant to Section 2191 of the Federal Power Act (“FPA”), Rule 207 of the Rules of

Practice and Procedure of the Federal Energy Regulatory Commission (“Commission”),2 Order

No. 679,3 and the Commission’s November 15, 2012 policy statement on transmission incentives

(“Policy Statement”),4 Southern California Edison Company (“SCE”) respectfully requests that

the Commission issue a declaratory order granting the rate incentives described below in

connection with SCE’s proposed Alberhill System Project (“Alberhill”), Mesa 500 kV

Substation Project (“Mesa”) and the Eldorado-Lugo and Lugo-Mohave 500 kV Series Capacitor

Project (“ELM”) (collectively, “Transmission Projects”). SCE forecasts that approximately $933

million (out of a total of over $1.3 billion) of costs for the Transmission Projects will be

recoverable in SCE’s transmission rates.

Based on meeting the Section 219 requirements, as described in this petition for

declaratory order (“Petition”), SCE requests that the Commission find: (1) that SCE be granted

1 16 U.S.C. § 824s. 2 18 C.F.R. § 385.207. 3 Promoting Transmission Investment through Pricing Reform, Order No. 679, 71 Fed. Reg. 43,294 (July 31, 2006); FERC Stats. & Regs. ¶ 31,222 (2006), order on reh'g, Order No. 679-A, 72 Fed. Reg. 1152 (Jan. 10, 2007); FERC Stats. & Regs. ¶ 31,236 (2006); order denying reh’g, 119 FERC ¶ 61,062 (2007). 4 Promoting Transmission Investment through Pricing Reform, (“Policy Statement”) 141 FERC ¶ 61,129 (2012).

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authority to recover 100% of its prudently incurred costs if the Transmission Projects are

cancelled or abandoned for reasons beyond SCE’s control (the “Abandonment Incentive”), and

(2) that SCE be granted authority to recover 100 % of the Transmission Projects’ network

transmission Construction Work in Progress (“CWIP”) in transmission rate base during the

construction period. SCE is not requesting a Return on Equity (“ROE”) project adder or any

other rate incentives for the Transmission Projects.5 Instead, SCE has narrowly tailored its

request to the incentives that are most appropriate given the special risks and challenges that

each of the Transmission Projects present for SCE: the Abandonment Incentive and CWIP.

SCE is not filing for rate changes pursuant to Section 205 of the FPA at this time.

Consistent with Order No. 679, SCE will make a separate rate filing subsequent to a Commission

order in this proceeding for the purpose of implementing a rate mechanism to recover any rate

incentives associated with these Projects.

As described in Section IV, below, SCE requests that the Commission approve this

Petition within 60 days as SCE has significant capital spending planned in 2017 associated with

the Transmission Projects. If the Commission is unable to act within 60 days as a result of the

impact of the Commission’s current lack of quorum, SCE requests that the Commission award

an effective date of June 7, 2017, which is 61 days after the date of the filing.

5 Other available incentives for Public Utilities include: ROE Sufficient to Attract Capital; Hypothetical Capital Structure; Accelerated Depreciation; Deferred Cost Recovery and Single-Issue Ratemaking. Order 679 at PP 84-179.

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I. INTRODUCTION

As the Commission is aware, SCE has been engaged in a continuous effort over the last

ten years to expand its transmission infrastructure to enlarge, improve and reinforce the

California Independent System Operator (“CAISO”) transmission grid, which is being

undertaken in order to maintain reliable service to customers at the lowest reasonable cost and

provide increased access to renewable generation resources.6 The Commission has previously

granted incentive-based transmission rate treatments for certain projects that are part of this

program.7 In this Petition, SCE seeks narrowly tailored incentive-based transmission rate

treatments for three Transmission Projects that have been identified and approved as needed

transmission assets through the CAISO's transmission planning process ("TPP").8

Specifically, SCE requests that the Commission authorize the following incentive rate

treatments for the Transmission Projects:

A. 100% Abandoned Plant Recovery

SCE requests recovery of 100 percent of the prudently incurred costs for each of the

Transmission Projects to the extent that any must be cancelled or abandoned for reasons outside

SCE’s control.

6 See Southern California Edison Co., Docket No. EL07-62-000, Petition for Declaratory Order at pp. 1-2 (filed May 18, 2007) (describing SCE’s then-current plan to spend $4.3 billion in transmission investment over five years), Southern California Edison Co., Docket No. EL10-1, Petition for Declaratory Order at p. 6 (filed October 1, 2009) (describing SCE’s then-current plan to spend $6.2 billion in transmission investment over five years), Southern California Edison Co., Docket No. EL10-81, Petition for Declaratory Order at p.5 (filed August 4, 2010) (describing SCE's then-current plan to spend $5.5 billion in transmission investment over five years), Southern California Edison Co., Docket No. EL11-10, Petition for Declaratory Order at p.5 (filed December 9, 2010) (describing SCE's then-current plan to spend $5.5 billion in transmission investment over five years), and Docket No. ZZ16-3-000, SCE's April 18, 2016 FERC Form 730 (showing forecast transmission investment of over $3.5 billion from 2016 to 2020). 7 See FERC Docket No. EL07-62, 2007 SCE Incentives Order dated November 16, 2007, FERC Docket No. EL10-1, 2009 Incentive Order, dated December 17, 2009, FERC Docket No. EL10-81, 2010 SCE Incentive Order dated October 29, 2010, and FERC Docket EL11-10, 2011 Incentive Order dated March 11, 2011. 8 See SCE-5, Affidavit of Garry Chinn at P 18 and SCE-8, Affidavit of Fernando Benavides at P 18.

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B. Construction Work in Progress

SCE requests inclusion in transmission rate base of 100 percent of CWIP expenditures

incurred during construction of each of the Transmission Projects. The CWIP will include

expenditures for facilities and land acquired for the Transmission Projects during the

construction period. SCE proposes to include each Transmission Projects’ CWIP in SCE’s

formula rate or successor rate that will be filed in late 2017 as required under SCE’s current

formula rate settlement or a successor rate, as applicable.9 If CWIP is granted, SCE will not

accrue Allowance for Funds Used During Construction (“AFUDC”) for the network

transmission component of the Transmission Projects and has, or will establish, accounting

procedures to ensure that costs are properly tracked and assure that there will be no double

recovery of the costs incurred by SCE to construct the Transmission Projects.10 Consistent with

Commission policy, SCE will include in CWIP the costs of only network transmission project

facilities and associated land costs that are recoverable through SCE’s Base Transmission

Revenue Requirement (“TRR”) and in the CAISO’s Transmission Access Charge (“TAC”).11

9 SCE’s formula rate settlement states: There shall be no limitation on SCE’s ability to request the inclusion of 100% of construction work in progress (“CWIP”) in rate base for additional transmission projects, provided that, as to any such project for which the Commission grants a CWIP incentive, SCE agrees to reflect an allowance for funds used during construction (“AFUDC”), rather than 100% of CWIP, on project costs incurred prior to the date SCE obtains (i) any required licensing approval from the CPUC for the project; and (ii) California Independent System Operator (“CAISO”) approval for the project through the applicable CAISO planning or interconnection process. Docket No. ER11-3697, Offer of Settlement filed on August 26, 2013 and approved on November 5, 2013 (See Southern California Edison Co., 145 FERC ¶ 61,103 (2013) (“SCE’s Formula Rate Settlement”)). SCE will abide by this provision of the formula rate settlement provision until the effective date of a successor rate. 10 Note that the communications-related costs, which amount to approximately one percent of the Transmission Projects’ costs, are classified as General Plant and will be allocated between the FERC and CPUC jurisdictions in rate proceedings. 11 This includes the cost of land and construction of facilities that will operate as part of the CAISO network pursuant to the Mansfield test under the CAISO’s Operational Control. See Mansfield Municipal Electric Dept., 97 FERC ¶ 61,134 (2001) (“Mansfield”), reh’g denied, 98 FERC ¶ 61,115 (2002); see also California Independent Sys. Oper. Corp., 119 FERC ¶ 61,061 (2007).

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Nothing in SCE’s current formula rate settlement prohibits the Commission from acting

on any request that SCE has made in this Petition.12 Further, SCE is not at this time filing a

request for rate changes pursuant to FPA Section 205. Consistent with Order No. 679,13 SCE

will make the appropriate section 205 filings to implement the applicable incentive rate

treatments granted by the Commission in its order on this Petition.

II. BACKGROUND

A. Description of SCE

SCE, a wholly-owned subsidiary of Edison International, is an investor-owned utility,

engaged in generating, transmitting and distributing electric energy over portions of central and

southern California. In addition to its properties in California, SCE owns, in some cases jointly

with others, facilities located in Nevada, Arizona and New Mexico, which produce and/or deliver

electric energy for the use of customers in California. SCE is subject to the Commission’s

jurisdiction for the provision of wholesale and retail transmission service, as well as various

other matters, while its remaining retail electric services are regulated by the California Public

Utilities Commission ("CPUC”). SCE transferred operational control over its transmission

facilities to the CAISO on April 1, 1998, and is a Participating Transmission Owner in the

CAISO control area.

12 See FN 9, supra and SCE’s Formula Rate Settlement at 3.6.3 states: As to new requests at FERC for pre-approval to recover 100% of prudently-incurred abandoned plant costs on a transmission project, SCE may seek such treatment only on transmission projects that are included in the CAISO transmission plan, or that are constructed pursuant to a FERC-approved interconnection process. 13 See Order No. 679 at P 191 (“We believe that single-issue ratemaking can provide a significant incentive for achieving the infrastructure investment goals of section 219 because it can provide assurance that the decision to construct new infrastructure is evaluated on the basis of the risks and returns of that decision, rather than the additional uncertainty associated with re-opening the applicant’s entire base rates to review and litigation”).

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B. Description of the Projects

1. Description of the Alberhill Project

Alberhill has been reviewed and approved through the CAISO’s TPP as a reliability

project to serve current and projected demand for electricity and maintain electric system

reliability in portions to the southeast of Alberhill Substation and south of Valley Substation,

including the cities of Lake Elsinore, Canyon Lake, Perris, Menifee, Murrieta, Murrieta Hot

Springs, Temecula, and Wildomar, as well as the surrounding unincorporated portions of

Riverside County.14 Alberhill would relieve the Valley South 115 kilovolt (kV) system by

transferring five existing 115/12 kV substations (Ivyglen, Fogarty, Elsinore, Skylark and

Newcomb 115 kV substations) to the new Alberhill system.15 Alberhill will include construction

of the following facilities: (1) a new 500/115 kV substation with 500 kV switchrack and two

three-phase 500/115 kV transformers; and (2) two new 500 kV transmission line segments (3.3

miles in length) to connect the new substation to SCE’s existing Serrano-Valley 500 kV line.16

It is contemplated that the 500 kV switchrack and 500 kV transmission line segments would be

under the Operational Control of the CAISO and subject to the requested incentives. Alberhill

is estimated to cost $427 million, with $202 million of that cost being recoverable through

transmission rates.17

2. Description of Mesa Project

Mesa has been reviewed and approved by the CAISO through its TPP as a reliability

project needed to address reliability concerns resulting from the retirement of the San Onofre

14 See SCE-5, Affidavit of Garry Chinn at P 6. 15 Id at P 8. 16 Id at P 9. 17 SCE-1, Affidavit of Charles B. Adamson Affidavit at P 27. SCE is in the process of revising its cost estimates for Alberhill and expects this number to increase.

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Nuclear Generating Station (“SONGS”) in 2013 and from Once-Through Cooling (“OTC”)

generation shutdowns expected by December 31, 2020.18 Mesa will help address these concerns

by allowing for greater flexibility in the siting of future generation to meet local reliability needs

in the western Los Angeles Basin, while reducing the total amount of new generation required by

providing additional transmission import capability.19 Mesa involves the construction of a new

500/220/66/16 kV Mesa Substation and includes both network transmission facilities as well as

distribution, i.e., non-network, facilities.20 It is contemplated that certain 500 kV and 220 kV

transmission facilities would be under the Operational Control of the CAISO and subject to the

requested incentives.21 Mesa is estimated to cost $654 million, with $449 million of that

recoverable through transmission rates.22

3. Description of ELM Project

ELM has been reviewed and approved by the CAISO through the TPP as a policy driven

project to relieve deliverability constraints in order to support achievement of California’s

renewables goals. The network transmission facilities that SCE proposes to construct as part of

ELM include: 1) construction of two new 500 kV mid-line series capacitors-the proposed

Newberry Springs Series Capacitor and Ludlow Series Capacitor near Pisgah Substation; 2)

installation of up to two dead-end towers adjacent to each of the proposed Newberry Spring and

Ludlow Series Capacitors; 3) correction of 16 overhead clearance discrepancy locations 18 OTC facilities are generating plants that take in ocean or estuarine water to cool their turbines and return the water back to the source. California State Water Resource Control Board’s (SWRCB) OTC Policy outlines a state-wide compliance schedule to reduce the environmental impact of these facilities, which involves the planned retirement of specific OTC plants within the Los Angeles Basin by the end of 2020. For more information see http://www.swrcb.ca.gov/water_issues/programs/ocean/cwa316/policy.shtml 2013-2014 ISO Transmission Plan (July 16, 2014), available at http://www.caiso.com/Documents/Board- Approved2013-2014TransmissionPlan_July162014.pdf; at p. 6. 19 Id. at p. 11. 20 Id. at p. 12. 21 SCE-5, Affidavit of Garry Chinn at P15. 22 SCE-1, Affidavit of Charles B. Adamson at P 26.

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involving relocation, replacement, or modification of existing transmission, subtransmission, and

distribution facilities including minor grading along the Eldorado-Lugo, Lugo-Mohave, and

Eldorado-Mohave 500 kV Transmission Lines; 4) installation of new line termination equipment

(circuit breakers, disconnects, conductor, system protection, etc.) at the Lugo, Mohave, and

Eldorado Substations; 5) upgrade of the existing series capacitor banks at Eldorado and Lugo

Substations; and 6) replacement of the existing series capacitor bank at Mohave Substation.23

It is contemplated that these transmission facilities would be under the Operational Control of the

CAISO and subject to the requested incentives.24 ELM is estimated to cost $289 million, with

$280 of that recoverable in transmission rates.25

III. SCE’S INVESTMENT IN THE PROJECTS QUALIFIES FOR INCENTIVE RATE TREATMENTS

Recognizing a need to encourage investment in transmission infrastructure, Congress

directed the Commission to establish incentive-based rate treatments to promote investment in

new transmission facilities. Section 219 of the FPA requires the Commission to promote capital

investment in the development of the transmission grid by providing incentives,26 including

recovery of prudently incurred costs related to infrastructure development.27 In response to this

directive, the Commission issued Order No. 679 setting forth procedures by which utilities may

seek incentives for the development of new transmission projects. Under Order No. 679, the

23 SCE-8, Affidavit of Fernando Benavides at P 7. 24 Id. at P 14. 25 SCE-1, Affidavit of Charles B. Adamson at P 28. 26 16 U.S.C. § 824s(c). 27 Id; §824s(b)(4)(B).

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incentives a public utility may request include the Abandonment Incentive and CWIP in rate

base, among others.28

The Commission adopted its Section 219 implementing regulations in Order No. 679. In

that Order, the Commission interpreted the statute as requiring, as a threshold matter, a

demonstration that the project for which an applicant seeks incentives either promotes reliability

or reduces the cost of delivered power by reducing transmission congestion.29 There is a

rebuttable presumption that this threshold Section 219 requirement is met if: “(i) the transmission

project results from a fair and open regional planning process that considers and evaluates

projects for reliability and/or congestion and is found to be acceptable to the Commission; or (ii)

a project has received construction approval from an appropriate state commission or state siting

authority.”30

The Commission also stated that an applicant seeking rate incentives must demonstrate a

nexus between the incentives requested and the proposed investment, including showing that the

requested incentives address project-specific risks and challenges.31 The “nexus test is met when

an applicant demonstrates that incentives requested are ‘tailored to address the demonstrable

risks or challenges faced by the applicant.’”32

28 Other available incentive to Public Utilities include Return on Equity adder, hypothetical capital structure, accelerated depreciation, deferred cost recovery, and single issue ratemaking, Order 679 at PP84-193. 29 Order No. 679 at P 37; Order No. 679-A at P 5. 30 Order No. 679 at P 58. See also Potomac-Appalachian Transmission Highline, 122 FERC ¶ 61,188 at P 29 (2008). In Order No. 679-A at P 49, the Commission clarified the operation of this rebuttable presumption by noting that a regional planning process must, in fact, consider whether the project ensures reliability or reduces the cost of delivered power by reducing congestion. 31 Order No. 679-A at P 27. See also 18 CFR § 35.35(d) (“The applicant must demonstrate that the facilities for which it seeks incentives either ensure reliability or reduce the cost of delivered power by reducing transmission congestion consistent with the requirements of section 219, that the total package of incentives is tailored to address the demonstrable risks or challenges faced by the applicant in undertaking the project, and that resulting rates are just and reasonable.”). 32 Ameren Services Co., 135 FERC ¶ 61,142 at P 35 (2011) (quoting Order No. 679-A at P 40).

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In its Policy Statement, the Commission provided additional guidance concerning

requests for incentives under Section 219 and Order No. 679. Specifically, the Policy Statement

reaffirmed the Commission’s policy of awarding risk-reducing incentives, including: CWIP;

treatment of pre-commercial costs not included in CWIP as a regulatory asset, including deferred

cost recovery; and recovery of prudently incurred costs if the project is abandoned or cancelled

for reasons beyond the developer’s control.33

Each Transmission Project satisfies the rebuttable presumption that it will improve

reliability or reduce congestion because each was approved by CAISO as a reliability or policy

project in the CAISO’s TPP. Further, each project also satisfies the Commission’s nexus test

because, as described in Section IIIB below, SCE faces considerable risks and challenges in

developing each Project. Thus, in accordance with FPA Section 219 and Order No. 679, the

Commission should find that the Transmission Projects qualify for the requested Abandonment

and CWIP Incentives.

A. Each Project Qualifies for the Rebuttable Presumption Under Order No. 679

Applicants seeking rate incentives are required to demonstrate that the project at issue

either promotes reliability or reduces the cost of delivered power by reducing transmission

congestion under Order No. 67934 or show that the projects at issue meet the policy guidelines

under Section 205. A rebuttable presumption that the FPA section 219 requirement is met

applies in either of two circumstances: “(i) the transmission project results from a fair and open

regional planning process that considers and evaluates projects for reliability and/or congestion

and is found to be acceptable to the Commission; or (ii) a project has received construction

33 See Policy Statement, 141 FERC ¶ 61,129 (2012). 34 Order No. 679 at P 37; Order No. 679-A at P 5.

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approval from an appropriate state commission or state siting authority.”35 As discussed more

fully below, the CAISO selected the Transmission Projects as necessary to address the identified

reliability concerns and public policy goals. The Commission has found that the CAISO’s TPP

is a fair and open regional planning process that CAISO uses to determine which projects are

needed for reliability or to reduce congestion. In Citizens Energy Corporation, the Commission

relied in part upon the fact that the project had been approved through the CAISO’s TPP as a

basis for the rebuttable presumption.36 Further, in NextEra Energy West, LLC, the Commission

found that a transmission project approved through the CAISO’s transmission plan as a “policy-

driven” project qualified for the rebuttable presumption under Order 679.37

The three Transmission Projects were identified as needed for reliability and policy

reasons at various times from 2009 to 2014 by the CAISO.38 CAISO undertakes a

comprehensive TPP annually.39 The duration of the development of each transmission plan is

approximately two years.40 Each TPP is developed in three phases: Phase I establishes the study

plan, Phase 2 is completion of technical studies and development of a comprehensive plan, and

Phase 3 is the competitive solicitation process, as applicable.41 The CAISO’s TPP includes

35 Order No. 679 at P 58. See also Potomac-Appalachian Transmission Highline, 122 FERC ¶ 61,188 at P 29 (2008). 36 Citizens Energy Corp., 129 FERC ¶ 61,242 at P 16 (2009) (holding that approval through the CAISO’s transmission planning process was a factor establishing rebuttable presumption). 37 NextEra Energy Transmission West, LLC, 154 FERC ¶ 61,009 at P20 (2016) (“We find that NEET West is entitled to the rebuttable presumption that the Commission established in Order No. 679 with respect to the threshold requirement of section 219 for the Projects, as the CAISO transmission planning process through which the Projects were approved evaluates whether identified transmission projects will enhance reliability and/or reduce congestion.”). 38 SCE-6, Alberhill Board Memo (Alberhill was approved by the CAISO in 2009), See Affidavit of Garry Chinn at PP 19 & 26, Mesa was approved by the CAISO in 2014, Id. at P 31, ELM was approved by the CAISO in 2013 and 2014, See SCE-8, Affidavit of Fernando Benavides at P 18. 39 SCE-5, Affidavit of Garry Chinn at P 18. 40 Id. 41 Id.

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significant stakeholder participation in each phase.42 For instance, the 2010-2011 CAISO

Transmission Plan explains the transmission planning process as one that “provides a

comprehensive evaluation of the [CAISO] transmission grid to identify upgrades needed to

successfully meet California’s policy goals, in addition to examining conventional grid reliability

requirements and projects that can bring economic benefits to consumers.”43 Key analytics

include, among other things, “[i]dentification of transmission upgrades and additions needed to

reliably operate the network and comply with applicable [NERC and CAISO] planning standards

and reliability requirements.” According to the Plan, compliance with those standards and

reliability requirements “are a foundational element of the transmission plan.”44 While the

CAISO’s TPP has changed significantly over the past few years, the Transmission Projects have

been included in each TPP to date.

Below is a summary of the reliability and policy benefits of each Transmission Project

found by the CAISO through its TPP. The benefits of the Transmission Projects are described

more fully in the affidavits of Garry Chinn and Fernando Benavides, attached hereto as Exhs.

SCE-5 and SCE-8, respectively.

Further, all three Transmission Projects have or will need approval from state siting

authorities. Alberhill is pending construction approval from the CPUC. Mesa has already

received construction approval from the CPUC and ELM will have to receive approvals from

both the CPUC and the Nevada Public Utilities Commission (the “PUCN”). The development

42 Id. 43 CAISO Board Approved 2016-2017 Transmission Plan, p. 1. Available at http://www.caiso.com/Documents/Board-Approved_2016-2017TransmissionPlan.pdf 44 Id. at p. 12.

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risks associated with each project are described in the affidavit of Charles Adamson attached

hereto as Exh SCE-1.

1. Alberhill

The 2009 CAISO Transmission Plan identified Alberhill as one of the various

alternatives requiring further CAISO evaluation prior to submitting for CAISO Board approval,

and requested that SCE provide engineering feasibility and planning level cost estimates for

Alberhill and five other alternatives. CAISO conducted a reliability assessment and determined

that there was a need for Alberhill based on the load projections for the Valley South 115 kV

system. The Valley South 115 kV system “will exceed its transformer capability by summer

2014.”45 CAISO Management found that Alberhill was the “most robust transmission alternative

with expected minimum environmental impact in meeting reliability needs and providing long-

term transformer capacity for serving load growth in the southwestern Riverside County”46

CAISO Management recommended that the Board approve Alberhill as a new addition to the

ISO controlled grid. Alberhill was approved by the CAISO Board of Governors on December 9,

2009.47

2. Mesa

In the 2013-2014 TPP, CAISO performed analyses to determine the transmission

solutions necessary to maintain reliability in Southern California in light of the retirement of

SONGS, announced in 2013, and scheduled OTC generation retirements expected by December

31, 2020. These generating facilities account for approximately 7,332 MW of generation in the

45 SCE-5, Affidavit of Garry Chinn at P 20. 46 SCE-6, Alberhill Board Memo (Memorandum from Dr. Keith Casey at the CAISO to the ISO Board of Governors approving Alberhill Substation Project dated December 9, 2009). 47 Id.

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region.48 CAISO studied over 12 potential transmission proposals to address reliability issues

caused by the SONGS retirement and OTC generation retirements.49 CAISO recommended an

overarching strategy, one that included specific transmission development with respect to certain

proposals, including Mesa.50 CAISO stated, “[W]ith this project, a new 500/230/66 kV

substation will be rebuilt on the property of the existing Mesa 230/66 kV substation. With the

addition of 500kV voltage, a new source from bulk transmission will be established in the LA

Basin to bring power from Tehachapi renewables or power transfer from PG&E via WECC Path

26.”51 In March 2014, as part of the 2013/2014 Transmission Plan, the CAISO Board of

Governors approved Mesa.52 The CAISO has reaffirmed the need for Mesa in subsequent TPPs,

including its most recent 2016/2017 Draft Transmission Plan.53

3. ELM

In 2010, the CAISO filed to modify its transmission planning process to include planning

for, review and approval of projects that the CAISO considered necessary to achieve “state and

federal policy requirements and directives,” such as greenhouse gas reduction requirements and

renewable energy targets. The Commission approved the CAISO’s category of “policy-driven”

projects, finding that “the R[evised] T[ransmission] P[lanning] P[rocess] is a positive step

toward facilitating the development of transmission infrastructure needed to enable California

48 SCE-7, 2013-2014 ISO Transmission Plan (July 16, 2014), available at http://www.caiso.com/Documents/Board- Approved2013-2014TransmissionPlan_July162014.pdf; at p. 91. 49 Id. at p. 96. 50 SCE-5, Affidavit of Garry Chinn at P 29. 51 SCE-7, CAISO Board Approved 2013-2014 Transmission Plan Section 2.6.3.2 at p.107, attached to Affidavit of Garry Chinn at P 30. 52 SCE-5, Affidavit of Garry Chinn at P 31. 53 Id. at P 32.

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utilities to meet California’s ambitious renewable portfolio standards and other environmental

goals.”54

ELM was first identified by SCE and the CAISO as a result of the generator

interconnection studies55 that were performed as part of a Queue Cluster (QC) 3 and 4 Phase II

Interconnection Study in November of 2012. To manage multiple generator interconnection

requests that are made for generation resources proposed to be located in the same geographic

area, CAISO and SCE have developed procedures for evaluating “clusters” of generation

facilities in a single study based on the interconnection queue (i.e., the queue of generators that

have requested interconnection within the CAISO controlled system).56 SCE, in conjunction

with CAISO, identified the need to increase the compensation on both the Eldorado-Lugo and

Lugo-Mohave 500 kV Transmission Lines as part of a Delivery Network Upgrade in order to

maintain the reliability of the SCE transmission system, prevent adverse effects on the

transmission system of a neighboring utility, and to provide deliverability for the projects

requesting to interconnect as part of these clusters. The upgrades were identified as needing to

be completed in order for the renewable generation projects to achieve Full Capacity Delivery

Status.57

Under the CAISO’s RTPP, if a transmission upgrade identified in the generator

interconnection process is needed for the base portfolio, plus at least one other portfolio, the

CAISO may include that upgrade as a “Category 1” policy-driven transmission project as part of

54 California Independent System Operator, 133 FERC ¶ 61,224 at P2 (2010), also finding CAISO’s innovative RTPP proposal enhances CAISO’s transmission planning by improving transparency and openness and expanding stakeholder, sub-regional, and regional collaboration. 55 SCE-8, Affidavit of Fernando Benavides at P 17. 56 Id. at P 14. 57 Id. at P 15.

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its annual transmission plan instead of a generator interconnection driven upgrade.58 The

2012-2013 and 2013-2014 CAISO Transmission Plans identified and recommended for approval

the Eldorado-Lugo and Lugo-Mohave Series Capacitor Upgrades, respectively, as Category 1

Policy-Driven Upgrade Solutions since they were identified as being needed by a large quantity

of generation projects spread across a large geographic area.59 The Eldorado-Lugo and Lugo-

Mohave portions of ELM were proposed and approved through the CAISO TPP on March 20,

2013 and July 16, 2014, respectively, as Policy-Driven Upgrades.60 Through this process, each

of the upgrades were identified as providing renewable integration, reliability, and deliverability

benefits.61

B. The Requested Incentives Satisfy the Nexus Test

Applicants for rate incentives are required to demonstrate a nexus between the incentives

sought and the investment in question.62 The nexus test requires that an applicant demonstrate

that the requested incentives are rationally related and “tailored to address the demonstrable risks

58 CAISO Tariff, Section 24.4.6.6. Category 1 policy-driven solutions are recommended to be built in the current planning cycle. 59 The CAISO identified additional reliability issues that would be mitigated by the Eldorado-Lugo portion of the project, stating “Overloads on 500 kV facilities from McCullough to Victorville outside of the ISO balancing authority area were observed under normal condition and Category C outage along the Colorado River to Devers transmission corridor. To reduce flow through the neighboring systems and mitigate the overloads, the series compensation level on the Lugo – Eldorado 500 kV line needs to be increased from 35 percent to 70 percent by switching in the series capacitor at Eldorado. However, overload on the Lugo – Eldorado 500 kV line was identified under Category B and Category C outage conditions. Switching in the series cap would further aggravate the overload on the Lugo – Eldorado 500 kV line. The rating of the line is limited by the series capacitors and terminal equipment. The series capacitors and terminal equipment needs to be upgraded to higher rating of 3,800 Amps. These upgrades were identified in the cluster 3 and 4 Phase II in the generator interconnection process study. However, they are needed by a large quantity of generation projects spread across a large geographic area. This upgrade should be considered for approval as a policy-driven upgrade through transmission planning process.” SCE-9, 2012-2013 CAISO Transmission Plan at pp. 275-276. 60 Refer to Section 24.4.6.6-Policy-Driven Transmission Solutions at http://www.caiso.com/Documents/Section24_-- ComprehensiveTransmissionPlanningProcess_asof_Mar28_2016.pdf. See also, SCE-9, 2012-2013 Transmission Plan (Pg. 278), SCE-10, 2013-2014 Transmission Plan (Pg. 198). 61 SCE-8, Affidavit of Fernando Benavides at P 18. 62 Order No. 679 at PP 1-2, & 26. See also 18 CFR § 35.35(d).

17

or challenges faced by the applicant.”63 It is no longer necessary for an applicant to make a “but

for” showing – i.e., that a project will not be built without the requested incentives – to satisfy

the nexus requirement.64 Nor is it necessary for the applicant to demonstrate that the project for

which it seeks incentives is a “non-routine” project. Rather, applicants “must provide sufficient

explanation and support” regarding how the incentives requested are tailored to address the risks

and challenges of the project.

As discussed below, the requested incentives (the Abandonment Incentive and CWIP) are

narrowly tailored to address the risks and challenges of the Transmission Projects, i.e., primarily,

permitting-related regulatory risk associated with the Certificate of Public Convenience and

Necessity (“CPCN”) or Permit to Construct (“PTC”) permitting process through the CPCN and

the level of capital expenditures SCE intends to make over the next four years. Accordingly, the

requisite nexus test is satisfied.

1. Recovery of 100% of Prudently Incurred Abandonment Costs

SCE requests the Abandonment Incentive for each of the Transmission Projects if any of

the Transmission Projects must be cancelled or abandoned for reasons outside SCE’s control.

SCE’s request for the Abandonment Incentive in the event it is forced to cancel or

abandon any of the Transmission Projects is specifically tailored to the risks faced by SCE with

respect to these Transmission Projects because each face significant licensing and permitting

challenges. As the Commission has explained, recovery of abandoned plant is important when

utilities “encounter investment opportunities with significant risk associated with factors beyond

their control, such as generation developers’ decisions to develop or terminate the development

63 Order No. 679-A at P 115; Order No. 679 at P 48. 64 See Policy Statement at P 10 (The Commission “re-frame[d] its application of the nexus test” such that it “no longer rel[ies] on the routine/non-routine analysis.” Id.).

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of potential resources or difficulty obtaining state or local siting approvals.”65 The

Commission’s reasoning behind this policy is that permitting cost recovery serves as “an

effective means to encourage transmission development by reducing the risk of non-recovery of

costs.”66 This incentive thus alleviates developers’ disincentive to invest if their lenders and

shareholders otherwise would be required to bear the costs of projects that must be abandoned

for reasons that the developer cannot control. The Commission has determined that abandoned

plant recovery is appropriate in circumstances such as where a project developer has been unable

to obtain necessary regulatory approvals or rights of way.67 This is akin to the situation with the

Transmission Projects, because while they are all in different phases of permitting and licensing,

all face risks of regulatory disapproval or delay that could lead to changing needs for the

projects, outside of SCE’s control. The Transmission Projects require multiple approvals from

the CPUC as well as federal and local governmental and regulatory authority approval, and each

approval process carries considerable risk. Below is a description of the unique risks faces by

each of the Transmission Projects.

a. Alberhill

With respect to Alberhill, SCE faces several significant hurdles in its licensing and

project development. First and foremost, SCE must obtain a CPCN from the CPUC.68 The

CPCN has now been pending at the CPUC for over seven years. On September 30, 2009, SCE

filed an application with the CPUC and, based upon past experience, SCE is anticipating a final

determination as to the CPCN in the third quarter of 2017. The review associated with a CPCN 65 Order No. 679 at P 155. 66 Order No. 679 at P 163. See also Policy Statement at P 14 (citing Order No. 679 at P 163) (“[T]he incentive that allows for 100 percent recovery of prudently incurred costs of transmission facilities that are abandoned for reasons beyond the control of the transmission owner…reduces the regulatory risk of non-recovery of prudently incurred costs.”). 67 See Order No. 679 at P 163. See also S. Cal. Edison Co., 129 FERC ¶ 61,246 at PP 67-68 (2009). 68 SCE-1, Affidavit of Charles B. Adamson at P 8.

19

application involves a lengthy process that requires detailed explanation of the project costs and

the project need (e.g., why the project is required to be constructed and operated). In addition,

details of other project elements are required, including property acquisition, construction

schedule, environmental impacts and a design for project features. The first step in the CPCN

review process is an environmental review consisting of the lead agency producing the required

documents analyzing environmental impacts under both state (CEQA) and, if required, federal

(NEPA) requirements. The environmental review includes consideration of input and comments

from the public. In this lengthy process the lead agency may add and potentially select

alternatives as “Environmentally Superior” that are not practical and that jeopardize the project

moving forward. The second step in the CPCN application process is a structured Case-in-Chief,

whereby parties to the proceeding have an opportunity to challenge the environmental review as

well as the need for the project. Ultimately, the CPCN application process is discretionary and

may result in approval, denial, or modification and delay of the proposed project. This poses a

substantial risk of project abandonment. In the case of Alberhill, the CPUC identified an

environmentally superior alternative substation site. SCE commented to the CPUC that the

alternative was infeasible because it did not meet project objectives, did not reduce significant

impacts when compared to the proposed Alberhill project and was not cost effective. Lastly,

SCE commented that the alternative would cause delays to the project schedule; more

specifically, SCE did not have sufficient time to complete a full technical feasibility evaluation

of the alternative or the necessary design or engineering work, and such work would need to be

completed. The additional design and engineering work could subsequently find the alternative

to be technically infeasible. SCE does not yet know whether the CPUC will keep the alternative

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or revert to SCE’s proposed Alberhill project.69

A further risk of project abandonment is presented when the CPCN application process

results in modifications to the proposed project design, such as the undergrounding of

transmission lines that were otherwise proposed to be overhead,70 or approval of an alternative

that could change the project in its entirety, e.g., a system alternative. These changes can be and

often are unacceptable to SCE or CAISO, causing undue delay to show the need for an

environmental override by decision makers, or ultimately a rehearing of the case if the decision

is deemed unacceptable.

In addition to the CPCN for Alberhill, SCE expects that it will need to obtain permits

and/or approvals from multiple agencies, including state, county, regional and municipal

agencies. A permit will also be required from a federal agency, the Army Corps of Engineers.

State permitting agencies include the Department of Fish & Wildlife, the State Water Resources

Board and the California Department of Transportation (“Caltrans”). Regional permitting

agencies include the South Coast Air Quality Management District, the Santa Ana Regional

Water Quality Control Board (Region 8), the Riverside County Habitat Conservation Agency,

and the Western Riverside County Regional Conservation Authority. Multiple permits will be

required from Riverside County and from several cities in the County, including Lake Elsinore,

Canyon Lake, Perris, Menifee, Murrieta, Temecula and Wildomar. In addition, encroachment

permits will be required from other utilities and municipalities.71

69 SCE-1, Affidavit of Charles B. Adamson at P 10. 70 In 2013, the CPUC determined that a portion of SCE’s Tehachapi Renewable Transmission Project should be undergrounded through the city of Chino Hills, leading SCE to have to abandon the overhead portion. See Southern California Edison Company, 148 FERC ¶ 61,126 (2014). 71 SCE-1, Affidavit of Charles B. Adamson at P 13.

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b. Mesa

SCE submitted an application for a PTC to the CPUC on March 13, 2015. The CPUC

granted the PTC on February 9, 2017.72 While SCE already has its license from the CPUC to

construct this project, that does not entirely mitigate that the risk of abandonment based upon the

regulatory approval process. Further, an Application for Party Status and an Application for

Rehearing are currently pending at the CPUC with respect to Mesa. If the Application for

Rehearing is granted, SCE could face significant delay or cancellation of Mesa.73 SCE will need

to obtain permits from, or consult with, multiple agencies, including state, federal, county,

regional, and municipal agencies. A “take authorization” is required from a federal agency, the

U.S. Fish & Wildlife Service. State permitting agencies include the State Water Resources

Control Board, the Department of Fish & Wildlife, and the Department of Transportation74

Further, Mesa is a complete replacement and upgrade of an existing load serving station

on the same site. The existing station will have to continue to serve load while the new station is

built. This requires complex construction and outage sequencing to build the new facilities,

transfer the sources and loads to those new facilities, then demolish the existing facilities and

build new facilities in their place. Delays in material delivery and/or construction that might

cause a day-for-day slip in the completion date of a typical project could have a much larger

effect on the completion date of Mesa depending upon where in the complex sequence such

delays occur. The potential for delay of over a year could trigger the need for reliability

mitigations which could ultimately trigger abandonment.75

72 Decision Granting Permit To Construct The Mesa 500-kV Substation Facility Project, D.17-02-015 (February 9, 2017). 73 SCE-1Affidavit of Charles B. Adamson at P 14. 74 Id. at P 13. 75 Id. at P 17.

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c. ELM

ELM will be located in both California and Nevada, which presents significant additional

siting and licensing risk to SCE. ELM involves a complex cross jurisdictional permitting and

licensing plan. SCE will need to obtain permits from multiple agencies in California and

Nevada. SCE expects to file PTC applications with the CPUC and the PUCN in late 2017.

Additionally, SCE will need to obtain a modification of its Rights of Way grants from the

Bureau of Land Management to cover the additional facilities that will be place in the rights of

way for ELM. The PTC application processes in both states combine with the federal ROW

grant applications ensure compliance with their respective environmental laws.

The first step in the state PTC and federal ROW grant review processes is an

environmental review consisting of the lead agency producing the required document that

analyze environmental impacts under both state (CEQA) and federal (NEPA) requirements. The

environmental review includes consideration of input and comments from the public. In this

lengthy process, the lead agency may add and potentially select alternatives as “Environmentally

Superior” but that are not practical and jeopardize the project moving forward. The second step

in the PTC process is a structured Case-in-Chief whereby parties to the proceeding have an

opportunity to challenge the environmental review as well as the need for the project. Since

ELM is largely on federally controlled land, the Federal lead agency will need to complete a

NEPA review and approve the project through a Record of Decision (“ROD”). Ultimately, the

Federal ROD and State PTC processes are discretionary and may result in approval, denial, or

modification and delay of the proposed project. This poses the risk that a project could be

abandoned.76 The ROD and PTC processes can result in modifications to the proposed project

76 SCE-1, Affidavit of Charles B. Adamson at PP 11 and 19.

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design, such as undergrounding of transmission lines that were otherwise proposed overhead, or

approval of an alternative that could change the project in its entirety, e.g., a system alternative.

These changes may be unacceptable to the applicant or the CAISO causing undue delay to show

the need for an environmental override by decision makers, or ultimately rehear the case if the

decision is unacceptable.

2. Inclusion of CWIP in Transmission Rate Base

In Order No. 679, the Commission authorized utilities to include, where appropriate,

100% of prudently incurred transmission-related land and facilities’ construction costs in

transmission rate base. The Commission found that:

Given the long lead time required to construct new transmission, and the associated cash flow difficulties faced by many entities wishing to invest in new transmission, the Final Rule provides that, where appropriate, the Commission will allow for the recovery of 100 percent of CWIP in rate base. Here again, we seek to remove an impediment–inadequate cash flow–that our current regulations can present to those investing in new transmission.77

This rate treatment, according to the Commission, will further the goals of FPA Section 219 by

providing upfront regulatory certainty, rate stability and improved cash flow for applicants,

thereby reducing the pressures on their finances caused by transmission development

programs.78

There is a clear nexus between SCE’s request to include 100 percent of CWIP in rate

base and the investments that it intends to make in each of the Transmission Projects. Recovery

in transmission rate base of CWIP expenditures during construction of the facilities will

improve cash flow during a time when SCE is financing a significant expansion and upgrade of

77 Order No. 679 at P 29. 78 Order No. 679 at P 115.

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its transmission system. SCE’s $3.6 billion investment in transmission over the next four years

compares to the $6.3 billion in CAISO-controlled net transmission plant that SCE had in service

at the end of 2015. Over that same period, SCE is planning distribution investments of $12.6

billion. Investment in generation and grid modernization increases the total investment over the

period to $19.3 billion.79

The combined nearly $1.3 billion cost (of which approximately $933 million are FERC

jurisdictional costs) for the Transmission Projects represents a significant cash outlay at a time

when SCE has embarked upon an significant level of capital spending and will add to the

significant financial burdens and risks associated with SCE’s transmission investment program.80

Generally, SCE’s routine transmission and distribution investments do not face the

hurdles of multiple jurisdictional approvals that the Transmission Projects face, can be

completed in less time, are less likely to be abandoned or canceled, and so do not merit the kind

of incentives that SCE is requesting for the Transmission Projects.81

a. The Transmission Projects Involve a Long Lead Time

SCE anticipates that the construction of the Transmission Projects will begin this year

and construction will be completed in 2021. Unless SCE is permitted to recover CWIP in rate

base, SCE investors would have to wait for several years (or more, should unforeseen delays

occur) before receiving any cash return on their investment in the largest of the Transmission

Projects. This long delay diminishes the attractiveness of this investment in comparison with

other SCE investments that have shorter lead times and thus provide greater cash returns in a

79 SCE-2, Affidavit of Paul T. Hunt Affidavit, at P 17. 80 Id., at P 11. 81 Id. at P 17.

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shorter time frame.82 The Commission has approved recovery of CWIP in rate base for projects

with similar lead times.83

b. CWIP Recovery Will Support SCE’s Ability to Finance the

Transmission Projects

As noted above, SCE is undertaking a substantial commitment in transmission expansion,

and this transmission investment coincides with significant need for growth in SCE’s

distribution and generation capital requirements.84 Thus, increased cash flow prior to the in-

service date of the Transmission Projects will be important to SCE as it expends large amounts

of capital over the next several years. Traditional rate recovery mechanisms would not allow

SCE to recover the costs of the Transmission Projects until they are placed into service in the

future. Because of the magnitude of SCE’s transmission expansion program, these traditional

rate recovery mechanisms act as a barrier to transmission investment.85

As SCE undertakes large and lengthy construction projects, CWIP and AFUDC balances

will increase based on the cash requirements of these projects. When CWIP balances are high

and the AFUDC comprises a major portion of earnings, investors become concerned about the

quality of earnings, subsequent rate shock (once the projects are added to the rate base) and the

ability of the utility to generate a prompt return of and on invested capital. Including CWIP in

rate base will assist SCE with its financing requirements and rating agency coverage ratios by

replacing non-cash AFUDC earnings with cash earnings. In addition, CWIP in rate base

enhances debt ratings due to higher coverage ratios and the improved quality of earnings.

82 Id. at P 18. 83 See Eldorado-Ivanpah Transmission Project (“ EITP”) was “over two years.” 129 FERC ¶ 61,246 at P 45. 84 SCE-2, Affidavit of Paul T. Hunt at PP 19 and 22. 85 Id. at P 18.

26

Investors view reduced variability in the year over year earnings positively which, in the long

run, lowers borrowing costs.86

In the long term, customers benefit from smoothing out large rate increases and stronger

credit ratings for the utility because the company may be able to obtain better financing terms

that ultimately will be passed on to customers.87 Weakening of credit quality leads to higher

rates and commitment fees, increasing long-term borrowing costs, which may also be passed on

to customers.88

c. Including CWIP in Rate Base Will Promote Rate Stability

Under present Commission policy, an electric utility building a new facility is permitted

to capitalize its construction financing costs through accrual of AFUDC. Costs related to facility

construction and related land acquisition costs are captured in the CWIP account. When the

plant goes into service, CWIP balance, including accrued AFUDC, is then added to the existing

rate base. At that point, the utility starts earning a regulated rate of return on the project and

recovers all of its expenditures related to the construction of a facility over its useful life.

Given the size and scope of SCE’s multi-billion dollar transmission investment plan,

relative to SCE’s current rate base, there would be significant transmission rate increases as the

Transmission Projects are completed and added to rate base upon their in-service dates.

Inclusion of CWIP in rate base will phase in these increases in transmission rates during the

construction period, and will result in a lower future rate base than would occur by accruing

86 Id. at P 24. 87 Id. at P 25. 88 Id. at PP 15 & 22.

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AFUDC until the in-service date, thereby reducing rates in the future through a lower revenue

requirement over the remaining lives of the Transmission Projects.89

IV. REQUEST FOR EXPEDITED APPROVAL

SCE understands that it is currently the Commission’s policy that the Abandonment

Incentive apply only proactively from the date upon which the Commission grants the incentive.

90 Time is of the essence in granting this Petition because SCE is projected to spend more than

$70 million on licensing and construction of the Transmission Projects in 2017.91 Further, SCE

estimates that it is on track to spend over $172 million on the licensing and construction of the

Transmission Projects in 2018.92 As shown above, the Transmission Projects meet the

Commission standard for the Abandonment Incentive. Commission approval of the

Abandonment Incentive is needed on an expedited basis to protect SCE’s shareholders from

having to bear the burden if the Transmission Projects are abandoned for reasons beyond SCE’s

control. As such, SCE hereby requests that the Commission approve this Petition within 60

days. However, given the tight time frame requested in this Petition and the Commission’s

current lack of a quorum, SCE understands that the Commission may not be able to issue its

order on the Petition within that timeframe. Therefore, if the Commission is unable to approve

this Petition within 60 days, SCE requests that the Commission assign an effective date of June

7, 2017, 61 days after the date of this Petition. Good cause exists for the Commission to assign

this effective date because SCE has shown that the Transmission Projects qualify for the

89 SCE2-, Affidavit of Paul T. Hunt at PP 23-24. 90 See Docket No. EL15-103-001, San Diego Gas & Electric Company, 157 FERC ¶ 61,056, currently pending appeal in the D.C. Circuit in Case No. 16-1433. 91 SCE-1, Affidavit of Charles B. Adamson at P 24. 92 Id., at P 26.

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Abandonment Incentive and should not be penalized for reasons beyond its control such as

delayed action as a result of the lack of quorum.

V. LIST OF AFFIDAVITS AND EXHIBITS

The filing consists of this application and the following supporting exhibits:

1. Exhibit No. SCE-1: Affidavit of Charles B. Adamson; 2. Exhibit No. SCE-2 through SCE-4: Affidavit of Dr. Paul T. Hunt and exhibits

thereto;

3. Exhibit SCE-5 through SCE-7:Affidavit of Garry Chinn and exhibits thereto;

4. Exhibit SCE-8 through SCE-10: Affidavit of Fernando Benavides and exhibits thereto.

VI. COMMUNICATIONS

Correspondence or communications regarding this matter should be sent to the following individuals:

Rebecca A. Furman Attorney Southern California Edison Company 2244 Walnut Grove Avenue Rosemead, CA 91770 Tel: (626) 302-3475 Email: [email protected] Jeffrey L. Nelson Director, FERC Rates and Market Integration Southern California Edison Company P.O. Box 800 2244 Walnut Grove Avenue Rosemead, CA 91770 Email: [email protected]

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VII. CONCLUSION

For the reasons set forth in this Petition, SCE requests that the Commission issue an order

declaring that: (1) the Transmission Projects qualify for the incentives contemplated by Section

219 of the FPA; (2) SCE shall have the right to recover 100 percent of prudently incurred costs,

if any, of the Transmission Projects that are cancelled or abandoned for reasons beyond SCE’s

control; (3) SCE shall have the right during construction of the Transmission Projects to recover,

as CWIP in transmission rate base, the costs of facilities and land associated with the

Transmission Projects, through SCE’s Formula Rate or a successor mechanism; and (4) the

effective date shall be June 7, 2017, 61 days from the date of this filing.

Respectfully submitted, /s/ Rebecca A. Furman

Rebecca A. Furman Southern California Edison Company

2244 Walnut Grove Avenue Rosemead, CA 91770

Dated: April 7, 2017

Exhibit SCE-1

Affidavit of Charles B. Adamson

Exhibit No. SCE-1 Page 1 of 13

UNITED STATES OF AMERICA

BEFORE THE


Southern California Edison Company Docket No. EL-17-___-000

AFFIDAVIT OF CHARLES B. ADAMSON

FOR SOUTHERN CALIFORNIA EDISON COMPANY

I, Charles B. Adamson, being duly sworn, depose and state as follows:

1. My name is Charles B. Adamson. My business address is 2 Innovation Way, Pomona,

California 91768-2557.

2. I am making this affidavit on behalf of Southern California Edison Company (“SCE”).

The statements made herein are true and correct to the best of my knowledge and belief,

and I adopt them as my sworn testimony in this proceeding.

3. I am a Principal Manager in SCE’s Transmission & Distribution business unit. I

currently manage large transmission projects in the Transmission and Distribution

Organizational Unit. My responsibilities include managing several teams responsible for

licensing and building bulk power transmission, distribution, and substation projects. I

have previously sponsored testimony to the Commission in the following Docket Nos.,

EL10-1-000, EL11-10-000, and ER16-1025-000, relating to the licensing challenges of

SCE’s transmission projects.


4. I received a Certificate in Project Management from the University of California, Irvine

in 2000. My experience includes project management, engineering, technical training and

technical support. From 1990 to 1997, my responsibilities included technical training and

support, as well as engineering, design and process improvement. From 1997-2001, I

managed substation automation and generation divestiture projects. From 2001-2006, I

managed both licensing and construction of transmission and substation projects. From

2006 to 2010, I managed the licensing of large transmission projects. From 2010 to

present I manage multiple teams for both the licensing and construction of large

transmission and substation projects.

5. The purpose of this affidavit is to describe the permits and licenses SCE must obtain in

order to construct the Alberhill System (“Alberhill”), Mesa Substation (“Mesa”), and

Eldorado-Lugo-Mohave Series Capacitor projects (“ELM”, collectively, the

“Transmission Projects”).

6. My overall analysis is that the Transmission Projects present complex permitting

challenges that significantly exceed routine requirements. Below, I explain the unique

challenges of each Transmission Project. I expect that the Transmission Projects will

each require separate determinations by local, state and federal agencies, as well as

multiple ministerial permits from county and municipal authorities in California.

Additionally, ELM will require approvals by permitting agencies in Nevada, which adds

additional complexity to that project. Separate determinations by different agencies can

result in conflicting environmental mitigation and preferred project alternatives, which

can require additional time to reconcile. In addition, all of the Transmission Projects

will cross near the habitats of several protected species (including the desert tortoise and


several species of desert plants) which will require complex environmental reviews under

state and federal laws.

7. In sum, and as explained more fully below, the Transmission Projects have been, and

continue to be, far from routine projects due to the multiple layers of federal, state, and

local approvals and extensive environmental protection requirements. Extensive

permitting time frames can drive the need for reliability mitigations that may cost more

than the proposed project and/or ultimately bring the project need into question

increasing the risk of cancelation and triggering the need for abandonment.

I. ALBERHILL SYSTEM

8. With respect to Alberhill, SCE faces several significant hurdles in its licensing and

project development. First and foremost, SCE must obtain a Certificate of Public

Convenience and Necessity (“CPCN”) from the California Public Utilities Commission

(“CPUC”). On September 30, 2009, SCE filed a CPCN application with the CPUC1 and,

based on past experience SCE is anticipating a final determination in the third quarter of

2017. The review for a CPCN is a lengthy process that requires detailed explanation of

the project costs and the project need (e.g., why the project is required to be constructed

and operated). In addition, details of other project elements are required, including

property acquisition, construction schedule, environmental impacts and a design for

project features.

9. The Alberhill CPCN application has been pending at the CPUC for almost 8 years, which

is a significant delay in the expected licensing timeline. In response to a Deficiency

Letter, SCE filed an amended application on March 15, 2010. The CPUC deemed the 1 Application of SOUTHERN CALIFORNIA EDISON COMPANY (U338E) for a Certificate of Public Convenience and Necessity for the Alberhill System Project: Alberhill System Project, A.09-09-022 dated September 30, 2009.


application complete on March 26, 2010. During the CPUC’s environmental review

process pursuant to the California Environmental Quality Act (CEQA), the proposed

Alberhill Project was found to be infeasible as proposed and the CPUC withdrew the

completeness determination on January 24, 2011. SCE submitted an amended application

on April 11, 20112, and the CPUC deemed the amended application complete on May 26,

20113. The CPUC later determined that it would be in the public interest to consolidate

the CEQA analyses for the Alberhill Project and a previously filed SCE project, the

Valley – Ivyglen Project, into a single Environmental Impact Report (EIR). All of this

additional analysis and reconfiguration of the environmental review caused the

preparation of the Draft EIR to take over six years instead of the more typical 1.5-2 years.

The CPUC issued a Draft EIR4 on April 14, 2016 and it is anticipated the CPUC will

issue its Final EIR in April 2017. After issuing the Final EIR, the project will undergo

the case and chief process, then the CPUC staff will issue a Proposed Decision for CPUC

Commissioner approval as described below.

10. The first step in the CPCN review process is an environmental review consisting of the

lead agency producing the required documents analyzing environmental impacts under

state (CEQA) and, if required, federal (NEPA) requirements. The environmental review

includes considering input and comments from the public. In this lengthy process the lead

agency may add and potentially select alternatives as “Environmentally Superior.” In the

2 Amendment to the Application of Southern California Edison Company (U 338-E) for a Certificate of Public

Convenience and Necessity: Alberhill System Proejct. Availabe at .http://www.cpuc.ca.gov/environment/info/ene/alberhill/Amended%20PEA%202011%20with%20figures.pdf

3CPUC letter to SCE (dated May 26, 2011) regarding Determination of Completeness, Southern California Edison’s Revised PEA relating to the Alberhill System Project. http://www.cpuc.ca.gov/environment/info/ene/alberhill/AlberhillDeterminationCompletenessAmendedPEA_20110525.pdf.

4 Available at http://www.cpuc.ca.gov/environment/info/ene/alberhill/AlberhilllDraftEIR.html.


case of Alberhill, the CPUC identified an environmentally superior alternative substation

site. SCE commented to the CPUC that the alternative was infeasible because it did not

meet project objectives, did not reduce significant impacts when compared to the

proposed Alberhill project and was not cost effective. Lastly, SCE commented that the

alternative would cause delays to the project schedule; more specifically, SCE did not

have sufficient time to complete a full technical feasibility evaluation of the alternative or

the necessary design or engineering work, and such work would need to be completed.

The additional design and engineering work could subsequently find the alternative to be

technically infeasible. SCE does not yet know whether the CPUC will keep the

alternative or revert to SCE’s proposed Alberhill project.

11. The second step in the CPCN process is a structured case-in-chief where parties to the

proceeding have an opportunity to challenge the environmental review as well as the

need for the project. In the end, the CPCN process is discretionary and may result in

approval, denial, or modification and delay of the proposed project. If the CPUC does

not approve the CPCN for Alberhill, SCE would likely have to abandon the project.

12. The CPCN process can also result in modifications to the proposed project design, or

approval of an alternative that could change the project in its entirety, e.g., a system

alternative. These changes may not be practical or adequate to meet the technical

requirements of the applicant or the CAISO causing undue delay to show the need for an

environmental override by decision makers, or ultimately rehear the case if the decision is

unacceptable.

13. In addition to the CPCN, SCE expects it will need to obtain permits and/or approvals,

from multiple agencies, including state, county, regional, and municipal agencies. In


addition, a permit will be required from a federal agency, the Army Corps of Engineers.

State permitting agencies include the Department of Fish & Wildlife, the State Water

Resources Board and the Department of Transportation (“Caltrans”). Regional

permitting agencies include the South Coast Air Quality Management District, the Santa

Ana Regional Water Quality Control Board (Region 8), Riverside County Habitat

Conservation Agency, and the Western Riverside County Regional Conservation

Authority. SCE will need to obtain these agency approvals or discretionary permits in

advance of starting construction. Additional delays obtaining these permits would further

delay the start of the project and failure to obtain them could stop the project. Multiple

ministerial permits will be required from Riverside County and from several cities in the

County, including Lake Elsinore, Canyon Lake, Perris, Menifee, Murrieta, Temecula and

Wildomar. In addition encroachment permits will be required from other utilities,

Caltrans, and municipalities. While delays in obtaining these non-discretionary permits

would not prevent the project from starting, they could cause undue delay in the

construction schedule and cause the completion date to be later than anticipated.

II. MESA SUBSTATION

14. SCE submitted an application for a permit to construct (“PTC”) to the CPUC on March

13, 2015.5 The CPUC granted the PTC on February 9, 2017.6 However, the City of

Montebello has filed an Application for Party Status and an Application for Rehearing

5 Application of Southern California Edison Company (U 338-E) for a Permit to Construct Electrical Substation

Facilities with Voltage over 50 kV: Mesa 500 kV Substation Project, A. 15-03-003 dated March 13, 2015. 6 Decision Granting Permit To Construct The Mesa 500-kV Substation Facility Project, D.17-02-015 dated February

9, 2017.


alleging CEQA violations.7 If a rehearing were to be granted, the Mesa project would be

delayed and could open the possibility for revisions to the February 2017 decision.

15. In addition to the CPUC PTC, SCE will need to obtain approvals and discretionary

permits from, or consult with, multiple state and federal agencies. Pending the outcome

of consultation with and a Biological Opinion from the respective resource agencies, take

authorizations for listed species such as California Gnatcatcher and Least Bells Vireo

may be required from state and federal agencies possibly including the California

Department of Fish & Wildlife and the U.S. Fish & Wildlife Service. Streambed

alteration and storm water control permits are required from the Army Corp of Engineers

and the State Water Resources Control Board. SCE will need to obtain these agency

approvals or discretionary permits in advance of starting any construction. Additional

delays obtaining these permits would further delay the start of the project and failure to

obtain them could stop the project.

16. Multiple ministerial permits are required, including from the South Coast Air Quality

Management District, an air pollution agency for the urban portion of Los Angeles

County, which includes Mesa substation. State Highway encroachment permits will be

required from the CA Department of Transportation (“Caltrans”) and multiple permits

will be required from Los Angeles County agencies, including the Department of Public

Works and the Department of Regional Planning. Municipal permits must be obtained

from the cities of Monterey Park, Montebello, Commerce, Pasadena, and Bell Gardens.

While delays in obtaining these non-discretionary permits would not prevent the project

7 On March 17, 2017, the city of Montebello submitted an application for rehearing of D.17-02-015 with the CPUC

(i.e., “CITY OF MONTEBELLO APPLICATION FOR REHEARING (JOINED BY THE MONTEBELLO UNIFIED SCHOOL DISTRICT”).


from starting, they could cause undue delay in the construction schedule and cause the

completion date to be later than needed.

17. The Mesa project is a complete replacement and upgrade of an existing load serving

station on the same site. The existing station will have to continue to serve the load while

the new station is built. This requires complex construction and outage sequencing to

build the new facilities, transfer the sources and loads to those new facilities, then

demolish the existing facilities and build more new facilities in their place. Delays in

material delivery and/or construction that might cause a day-for-day slip in the

completion date of a typical project could have a much larger effect on the completion

date of Mesa depending on where in the complex sequence they occur. The potential for

delay of over a year could trigger reliability mitigations that while potentially costing

more than the proposed project, might reduce the need and lead to cancellation and

triggering of abandonment.

III. ELDORADO-LUGO-MOHAVE SERIES CAPACITORS

18. The Eldorado-Lugo-Mohave Series Capacitors Project (“ELM”) will be located in both

California and Nevada. This involves a complex cross jurisdictional permitting and

licensing plan which carries significant risk. SCE will need to obtain permits from

multiple state agencies in California and Nevada. A right-of-way (ROW) grant

application has already been filed with the Bureau of Land Management to initiate the

federal NEPA review process. SCE expects to file Permit to Construct (“PTC”)

applications with the CPUC and the Public Utilities Commission of Nevada (PUCN) later

in 2017. The review process in PTC applications of both states and in federal ROW grant


applications ensure compliance with each jurisdiction’s respective environmental laws,

CEQA and the [Nevada] Utility Environmental Protection Act (“UEPA”), and the federal

National Environmental Policy Act (NEPA). Moreover, details of other project elements

are required, including property acquisition, construction schedule, environmental

impacts and a design for project features. The first step in the state PTC or federal ROW

grant review processes is an environmental review consisting of the lead agency8

producing the required documents analyzing the environmental impacts under the

appropriate state (CEQA/UEPA) or federal (NEPA) requirements. The environmental

review includes extensive input and comments from the public. During this lengthy

process, the lead agency may add and potentially select alternatives as “Environmentally

Superior” that are not practical and jeopardize the project moving forward.

19. The second step in the PTC process is a structured Case-in-Chief where parties to the

proceeding have an opportunity to challenge the environmental review as well as the

need for the project. Since the project is largely on federally controlled land, the federal

lead agency will need to complete a NEPA review and approve the project through a

Record of Decision (ROD). In the end, the federal ROD and State PTC processes are

discretionary and may result in approval, denial, or modification and delay of the

proposed project. This poses the risk that a project could be abandoned.

20. The ROD and PTC processes can result in modifications to the proposed project design,

or approval of an alternative that could change the project in its entirety, e.g., a system

alternative. These changes may be unacceptable to the applicant or the CAISO causing

8 BLM will be the NEPA lead agency and typically the CPUC is the CEQA lead agency. The environmental review

process for Nevada will be handled in accordance with UEPA.


undue delay to show the need for an environmental override by decision makers, or

ultimately rehear the case if the decision is unacceptable.

21. Much of Eldorado-Lugo-Mohave crosses federal land, thus SCE expects it will need to

obtain several permits from federal agencies, including the Bureau of Land Management

(BLM), the National Park Service, the Bureau of Reclamation, and the Department of

Defense.

22. In addition to the CPUC PTC, PUCN PTC, and federal ROD, SCE will need to obtain

approvals and discretionary permits from, or consult with, multiple state and federal

agencies. Pending the outcome of consultation with and a Biological Opinion from the

respective resource agencies, take authorizations for listed species such as desert tortoise

may be required from state and federal agencies such as: the California Department of

Fish & Wildlife, Nevada Department of Wildlife and U.S. Fish & Wildlife Service.9

Streambed alteration and storm water control permits are required from the Army Corp of

Engineers and State Water Resources Control Board. SCE will need to obtain these

agency approvals or discretionary permits in advance of starting any construction.

Additional delays obtaining these permits would further delay the start of the project and

failure to obtain them could stop the project.

23. Multiple ministerial permits are also required. These may include highway encroachment

permits from the California Department of Transportation (“Caltrans”) and Nevada

Department of Transportation (NDOT). Railroad and pipeline encroachment permits may

also be required. Municipal permits must be obtained from Clark County, NV, and San

9 An incidental take permit is a permit issued under Section 10 of the United States Endangered Species Act (ESA)

to private, non-federal entities undertaking otherwise lawful projects that might result in the take, i.e., harm of an endangered or threatened species.


Bernardino County, CA. While delays in obtaining these non-discretionary permits would

not prevent the project from starting, they could cause undue delay in the construction

schedule and cause the completion date to be later than anticipated.

IV. THE COSTS OF THE TRANSMISSION PROJECTS, PROJECTED SPEND

DATES AND NEED FOR TIMELY EVALUATION BY THE COMMISSION OF

THIS PETITION

24. Given the significance of these three projects, SCE requests a timely response by the

Commission to this Petition. Timely approval will assist SCE in moving aggressively

regarding the licensing and construction of all three projects, including estimated

expenditures that are expected to exceed $307 million in FERC jurisdictional costs by the

end of 2018 and $933 million in FERC jurisdictional costs through the CAISO’s

Transmission Access Charge (TAC) by the end of 2022.10

25. Mesa construction is scheduled to begin in May 2017 and the scheduled operating date is

June 2021. Mesa was approved by the CAISO in 2014 to meet reliability needs due the

closure of the San Onofre Nuclear Generating Station (“SONGS”) and the expected

shutdown of “Once Through Cooling” generating units11 by 2020. As the CAISO stated

in its 2013-2014 Transmission Plan about the new substation:

10 These costs are in nominal dollars, including capitalized corporate overheads (pensions & benefits and

administrative & general expenses) 11 OTC facilities are generating plants that take in ocean or estuarine water to cool their turbines and return the water

back to the source. California State Water Resource Control Board’s (SWRCB) OTC Policy outlines a state-wide compliance schedule to reduce the environmental impact of these facilities, which involves the planned retirement of specific OTC plants within the Los Angeles Basin by the end of 2020. For more information see http://www.swrcb.ca.gov/water_issues/programs/ocean/cwa316/policy.shtml


This allows SCE to bring a new 500kV electric service into its metropolitan load center delivering power from Tehachapi wind resources area or resources located in PG&E service territory or the Northwest via the 500kV bulk transmission network system. Bringing another 500kV source into the heart of the LA Basin by utilizing the existing Vincent – Mira Loma 500KV line also helps reinforce the bulk transmission system and improve its voltage performance against the critical overlapping N-1-1 contingency of the Southwest Powerlink and the Sunrise Powerlink in southern San Diego area.12

26. SCE expects to spend more than $257 million (over $164 million recoverable in FERC

transmission rates through the CAISO’s TAC) by the end of 2018, and more than $654

million total on Mesa by 2022 (over $449 million recoverable in CAISO TAC).13

27. Alberhill construction is scheduled to begin in early 2019 and the scheduled operating

date for the new substation is June 2021. In approving Alberhill in 2009, the CAISO

Board found that the project is a necessary and cost-effective long-term transmission

addition to the CAISO Controlled Grid.14 SCE expects to spend more than $117 million

(over $55 million recoverable in FERC transmission rates through the CAISO’s TAC) by

the end of 2018, and more than $427 million total on Alberhill by 2022 (over $205

million recoverable in CAISO TAC).15

28. ELM will increase power flow through existing transmission lines from Nevada to

Southern California and relieves multiple area deliverability constraints. ELM is in the

licensing stage but construction is expected to begin in 2018 and SCE expects to spend

more than $90 million (over $87 million recoverable in CAISO TAC) by the end of 2018.

12 SCE-7, CAISO 2013-2014 Transmission Plan dated July 16, 2014 at p. 98 13 See footnote 8. 14 SCE-6, CAISO Board Memorandum, Decision on Alberhill Substation Project dated December 9, 2009 at p. 2 15 See footnote 8.


The total cost of ELM is expected to exceed $289 million, (over $280 million recoverable

in FERC transmission rates through the CAISO’s TAC).16

16 Id.

Exhibit SCE-2

Affidavit of Dr. Paul T. Hunt



BEFORE THE FEDERAL ENERGY REGULATORY COMMISSION

Southern California Edison Company ) Docket No. EL17-___-000

AFFIDAVIT OF PAUL T. HUNT FOR SOUTHERN CALIFORNIA EDISON COMPANY

I, Paul T. Hunt, being duly sworn, depose and state as follows: I. INTRODUCTION

1. My name is Dr. Paul T. Hunt. I am the Director of Regulatory Finance and

Economics for Southern California Edison Company (“SCE”). My business address is 2244

Walnut Grove Avenue, Rosemead, California 91770.

2. I am submitting this affidavit on behalf of SCE. The statements made herein are

true and correct to the best of my knowledge and belief, and I adopt them as my sworn testimony

in this proceeding.

3. I have worked for SCE for over thirty-six years. My present responsibility is to

apply economic, financial and statistical analysis to regulatory issues and for internal corporate

purposes. I am SCE’s chief expert on cost of capital, rate of return, and wage and price

escalation.

4. I received a Bachelor of Arts degree in Economics from Pomona College in 1975,

a Master of Arts degree in Economics from Stanford University in 1976, and a Doctor of

Philosophy degree in Economics from Stanford University in 1981. I joined SCE as an

Associate Economist in the Treasurer’s Department in 1980. I was promoted to Economist in

1982 and Senior Economist in 1984. In 1989, I transferred to the Regulatory Policy and Affairs

Hunt Affidavit

Page 2 of 15

Department as a Regulatory Economics Consultant. I returned to the Treasurer’s Department in

1996 as a Senior Economist. In 1997, I was promoted to Project Manager. In 2000, I was

promoted to Manager of Regulatory Finance and Economics. I was promoted to my present

position in 2010.

5. In late 2009, I was invited to write, with a co-author, a book chapter on cost of

capital in regulated industries. The book chapter is titled “Cost of Capital in Regulated

Industries,” and it appears in Cost of Capital in Litigation: Applications and Examples, published

by John Wiley & Sons, Inc. in November 2010. (ISBN: 978-0-470-88094-4.)

6. A revised version of the book chapter appears in The Lawyer’s Guide to Cost of

Capital: Understanding Risk and Return for Valuing Businesses and Other Investments,

published by ABA (American Bar Association) Publishing in July 2014. (ISBN: 978-1-62722-

723-0.)

7. In 2016, I was elected to the Board of Directors of the Society of Utility and

Regulatory Financial Analysts. The Society’s purpose is to promote improvement and

understanding of rate of return analysis.

8. I have submitted testimony to this Commission in Docket Nos. ER82-427-000,

ER84-75-000, ER97-2355-000, ER02-925-000/ER02-925-001, ER03-549-002, EL00-105-

007/ER00-2019-007, ER06-186-000, ER08-375-000, ER08-437-000, ER08-1343-000, ER09-

187-000, ER09-1534-000/ER09-1534-001, ER10-160-000, ER11-1952-000, and ER11-3697-

000. I also submitted affidavits in Docket Nos. ER04-316-000, ER08-375-004, ER09-187-

002/ER10-160-000, EL10-1-000, EL10-81-000, and EL11-10-000. My previous testimony has

generally concerned issues related to cost of capital, rate of return and cost escalation. I have

Hunt Affidavit

Page 3 of 15

also submitted testimony to the California Public Utilities Commission (“CPUC”) on behalf of

SCE.

9. The purpose of my affidavit is to describe: a) the financial risks and challenges

SCE will face in constructing the Alberhill System Project (“Alberhill”), the Mesa Substation

Project (“Mesa”), and the Eldorado-Lugo-Mohave Series Capacitor Project (“ELM,” collectively

“Transmission Projects"); and b) the proposed ratemaking incentives tailored to address these

particular risks and challenges. The Transmission Projects are network transmission facilities

that will be under the operational control of the California Independent System Operator

(“CAISO”), although there are distribution system components included in the Alberhill System

and Mesa Substation projects that will not be under CAISO’s operational control.

10. My affidavit is organized as follows:

• Section II discusses the Transmission Projects and SCE’s planned capital

investment program;

• Section III discusses financial risks and challenges arising from the Transmission

Projects;

• Section IV describes how SCE’s proposed incentives are tailored to the

Transmission Projects; and

• Section V presents conclusions.

Hunt Affidavit

Page 4 of 15

II. SCE’S PLANNED TRANSMISSION INVESTMENT AND THE PROJECTS

11. The estimated total cost of the Transmission Projects (including pension and

benefit costs, and administrative and general costs) is approximately $1.3 billion; of that total,

approximately $933 million will be network transmission costs recovered through SCE’s

transmission rates.1 Over the next four years, SCE plans to spend $3.6 billion for new and

replacement transmission infrastructure.2 This investment program will strengthen SCE’s

system reliability and increase access to renewable energy for SCE and other California utilities.

The Transmission Projects will help accomplish both objectives and will comprise a substantial

addition to SCE’s transmission plant.

12. An example of a planned SCE project for upgrading its system to integrate

renewable resources is the West of Devers Upgrade Project in Riverside and San Bernardino

Counties. West of Devers will primarily serve a solar rich environment in the eastern portion of

SCE’s service territory.

13. As noted above, SCE forecasts that it will invest $3.6 billion on CAISO-

controlled transmission facilities over the four-year period from 2017 to 2020. This is a

substantial increase in net CAISO transmission plant in service.3 Of course, actual spending will

1 See Edison International SEC Form 8-K, filed February 22, 2017, Exhibit 99.1, p. 15. The most current estimates regarding network transmission costs are as follows: Alberhill, $205 million; Mesa, $449 million; and, Eldorado-Lugo-Mohave, $280 million. (These costs are in nominal dollars, including corporate overheads.)

2 Edison International Form 8-K, filed February 22, 2017, Exhibit 99.1, p. 27. 3 At the end of 2015, net CAISO transmission plant in service was $6.4 billion.

Hunt Affidavit

Page 5 of 15

depend on the timing of licensing, permitting and regulatory approvals.

III. FINANCIAL RISKS AND CHALLENGES OF THE PROJECTS

14. The Transmission Projects are being constructed to support SCE’s electric system

reliability and to allow renewable generation resources to serve California electric customers.

The Alberhill and Mesa projects are being built to meet current and projected demand for

electricity and to maintain electric system reliability, including addressing reliability concerns

arising from the retirement of San Onofre Nuclear Generating Station (“SONGS”).4 The ELM

project provides policy driven upgrades required to serve new renewable generation resources

that wish to interconnect with SCE’s system. Integrating this renewable generation into the

CAISO grid will help SCE meet the renewable energy requirements set by California’s

Renewable Portfolio Standard for SCE to serve at least 33 percent of its retail load with

renewable energy by 2020.5 This renewable generation will also provide renewable energy to

San Diego Gas & Electric Company (“SDG&E”). At this time, it is projected that ELM will

serve 888 MW of generation capacity.6

15. The Transmission Projects constitute a significant cash outlay for SCE, during a

time of continued high capital spending for SCE. SCE’s overall level of capital spending

presents SCE with significant financial burdens and risks and SCE will have difficulty executing

its aggressive capital spending plans during the next few years without eroding its credit quality.

If FERC does not grant SCE’s requested Construction Work In Progress (CWIP”) incentive for

4 Affidavit of Garry Chinn at PP 6 & 11. 5 Affidavit of Fernando Benevides at P. 19. 6 Id. at PP 15 & 21.

Hunt Affidavit

Page 6 of 15

the Transmission Projects, SCE will have to rely more heavily on external financing, which will

place greater stress on SCE’s balance sheet.

16. Financing the Transmission Projects will have negative effects on SCE’s cash

flow and financial metrics. When the financing requirements of the Transmission Projects are

added to the financing requirements of SCE’s other proposed projects, they pose considerable

adverse effects on SCE’s cash flow and financial metrics. This is because the total combined

investment in the Transmission Projects and SCE’s other transmission infrastructure projects,

such as West of Devers, totals approximately $3.6 billion over the period from 2017-2020, a

figure that represents approximately 19 percent of SCE’s total system investment during this

period.7 When compared to more typical transmission and distribution investments that SCE

plans to complete during this period, these Transmission Projects face the most difficult

obstacles and are the most likely to be postponed or canceled if they run into difficulties.

7 SCE’s total capital investment over this period is projected to be as much as $19.3 billion. Edison International Form 8-K, filed February 22, 2017, Exhibit 99.1, p. 8.

unt Affidavit Page 7 of 15

17. Investors will view the Transmission Projects in light of SCE’s total transmission

spending and capital spending. While investment in the Transmission Projects is significant, it is

not this investment alone that concerns investors, but the size of SCE’s total capital investment.

As discussed previously, SCE plans to undertake as much as $3.6 billion in total transmission

investment during the next four years. Over that same period, SCE is planning distribution

investments of $12.6 billion.8 Investment in generation and grid modernization increases the

total investment over the period to $19.3 billion.9 Generally, SCE’s routine transmission and

distribution investments do not face the hurdles of multiple jurisdictional approvals and

significant environmental reviews and permitting that the Transmission Projects face, can be

completed in less time, are less likely to be abandoned or canceled, and so do not merit the kind

of incentives that SCE is requesting for the Transmission Projects.

18. SCE anticipates that the Transmission Projects will begin construction in 2017

and that the final parts of the Transmission Projects will be completed in 2021. In the absence of

the CWIP incentive requested in this Petition, SCE’s investors would have to wait for several

years before receiving any cash return of or on much of their investment. All other things equal,

this long delay diminishes the attractiveness of these investments in comparison with other SCE

investments which have shorter lead-times and thus provide a cash return more quickly.

19. The Transmission Projects and SCE’s total transmission investment program are

part of the largest investment program in SCE’s history. As noted, SCE’s total capital

investment during the 2017-2020 period is projected to be as much as $19.3 billion10 and will

8 Edison International Form 8-K, filed February 22, 2017, Exhibit 99.1, p. 27. 9 Edison International Form 8-K, filed February 22, 2017, Exhibit 99.1, p. 8. 10 Id.

EHunt Affidavit

Page 8 of 15

result in substantial financing requirements for SCE. In addition to investing in transmission

facilities, SCE’s capital investment during this period includes, among other things,

infrastructure replacement and expansion of SCE’s distribution system and grid modernization.

IV. INCENTIVES REQUESTED ARE TAILORED TO THE SPECIFIC RISKS AND CHALLENGES OF THE PROJECTS

A. ABANDONED PLANT

20. Mr. Adamson addresses the unique risks and challenges that merit granting the

100% abandoned plant incentive for the Transmission Projects.11 The abandonment incentive

for the Transmission Projects reassures investors that their capital is not at risk if, among other

things, the Transmission Projects fail to receive all of their multiple regulatory approvals or if the

Transmission Projects are cancelled for other reasons outside of SCE’s control.

11 Affidavit of Charles B. Adamson at PP 7-22.

Hunt Affidavit

Page 9 of 15

B. CWIP

21. There is a clear nexus between SCE’s request to include 100% of CWIP in rate

base and SCE’s investment in the Transmission Projects. Including CWIP in rate base will

improve cash flow at a time when SCE is required to finance a significant expansion and upgrade

of its transmission system. From 2017 to 2020, SCE’s total rate base is projected to grow at an

average compound growth rate of as much as 8.6 percent, from $24.9 billion at the end of 2016

to $34.6 billion at the end of 2020.12 If SCE’s petition is approved, SCE’s rate base will be

lower than otherwise and the rate impact of the Transmission Projects will follow a smoother

trajectory.

22. SCE’s planned transmission investment for the next several years is substantial,

and this aggressive transmission investment increase coincides with a significant need for growth

in SCE’s distribution capital investments, as well. Thus, increased cash flow prior to the in-

service date of the Transmission Projects will be important to SCE’s credit quality as SCE

expends large amounts of capital during this period.

23. As SCE undertakes large and lengthy construction projects, CWIP and Allowance

for Funds Used During Construction (“AFUDC”) balances will increase based on the cash

requirements of these projects. When CWIP balances are high and AFUDC comprises a major

portion of earnings, investors become concerned about the quality of earnings, subsequent rate

shock (as and when the projects are added to rate base), and the ability of the utility to generate a

prompt return of and on invested capital.

12 Edison International Form 8-K, filed February 22, 2017, Exhibit 99.1, p. 27.

Hunt Affidavit Page 10 of 15

24. Including CWIP in rate base will assist SCE with its financing requirements and

rating agency coverage ratios by replacing non-cash AFUDC earnings with cash earnings. In

addition, debt ratings are supported due to better financial metrics and the improved quality of

earnings. This results in holding down borrowing costs.

25. In the long term, customers benefit from smoothing out large rate increases. In

addition, the utility’s stronger credit ratings will allow for lower financing costs which will

ultimately be passed along to customers. The effect on the Transmission Projects’ projected

revenue requirements from including CWIP in rate base is shown in the following three charts

(the numbers underlying these charts are included in Exhibit SCE-3):

ALBERHILL SYSTEM PROJECT

EHunt Affidavit Page 11 of 15

MESA SUBSTATION PROJECT


ELDORADO-LUGO-MOHAVE SERIES CAPACITOR PROJECT

26. Exhibit No. SCE-4 provides an illustration of the potential cash flow and interest

cost streams for the Transmission Projects during the period of construction and the first few

years of operation under both traditional ratemaking (accrual of AFUDC until the in-service date

of the Transmission Projects) and CWIP-in-rate-base ratemaking. As can be seen from

Attachment 2, CWIP treatment will enhance SCE’s cash flow and reduce interest expense during

construction of the Transmission Projects.

27. The estimates utilized and shown in Exhibit No. SCE-4 are based on assumed

construction timelines for the Transmission Projects. To the extent there are delays in securing

required project permits or approvals from government agencies, the cash flow and interest

expense benefits from CWIP treatment will increase relative to traditional ratemaking. This is

because AFUDC under traditional ratemaking will continue to be applied and compound during


any period of delay, whereas under CWIP treatment, SCE will earn a cash return during

construction.

V. CONCLUSION

28. My affidavit demonstrates that SCE’s requested incentives are carefully tailored

to the risks and challenges of the Transmission Projects. Therefore, the Commission should

grant SCE’s requested incentives.

Exhibit SCE-3

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with

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0

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.6

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1.

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)

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.4)

(4.3

)

(4

.2)

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(4

.0)

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Exhibit SCE-4

Summary of Cash Flow and Interest Expense Differences

Atta

chm

ent 2

Sout

hern

Cal

iforn

ia E

diso

n C

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ary

of C

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rest

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ense

Diff

eren

ces

Alb

erhi

ll20

1720

1820

1920

2020

2120

2220

2320

2420

2520

2620

2720

2820

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Milli

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Trad

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akin

g (N

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in R

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from

Ope

ratio

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(0.4

)

(0

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(4.7

)

13

.8

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.7)

Bal

ance

for C

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on S

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0.4

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(0

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(0.6

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(0

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(0.8

)

(0

.9)

(0.9

)

(0

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(0.8

)

(0

.8)

(0.7

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(0

.6)

Bal

ance

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(0.3

)

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(1

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(0

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(0.9

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(0

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rest

on

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(0.2

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(0

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(0.3

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(0

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(0.3

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(0

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ance

for C

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on S

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(0.6

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(1

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(0

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(0.8

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(0

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(0

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)

Atta

chm

ent 2

Sout

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iforn

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of C

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and

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ense

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ces

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a20

1720

1820

1920

2020

2120

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2720

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ons)

Trad

ition

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31.3

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1.6

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(1

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(1.7

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(1

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(1.6

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(1

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(1.4

)

(1

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Bal

ance

for C

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(0.6

)

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7

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14

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rest

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t(0

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(0.6

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(0

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(0.8

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ed D

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ends

0.0

0.0

0.1

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0.2

0.2

0.2

0.2

0.2

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0.2

0.1

Bal

ance

for C

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on S

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ers

(2.2

)

(2

.6)

(2.2

)

(3

.2)

(1.9

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(1

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(1

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tal

(2.2

)

(2

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(2.5

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(2.4

)

(2

.3)

(2.3

)

(2

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(2.1

)

(2

.1)

(2.0

)

Atta

chm

ent 2

Sout

hern

Cal

iforn

ia E

diso

n C

ompa

nySu

mm

ary

of C

ash

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and

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rest

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rado

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ave-

Lugo

Upg

rade

s20

1720

1820

1920

2020

2120

2220

2320

2420

2520

2620

2720

2820

29(In

Milli

ons)

Trad

ition

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atem

akin

g (N

o C

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in R

ate

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e)N

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from

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ratio

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.2)

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)

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8)

27.5

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4

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(1.2

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(1

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(1.4

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(1

.4)

(1.3

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(1

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(1.2

)

(1

.1)

(1.0

)

(1

.0)

Bal

ance

for C

omm

on S

hare

hold

ers

0.3

2.3

6.5

11.5

15

.1

14.7

13

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13.2

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11.9

11

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10.7

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(1.1

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(1.3

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(1

.2)

(1.2

)

(1

.1)

(1.0

)

(1

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(0.9

)

(0

.9)

Bal

ance

for C

omm

on S

hare

hold

ers

(0.1

)

(0

.0)

3.3

8.1

13.7

13

.4

12.6

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10

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6

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0.

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5.

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11

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12.0

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(Dec

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ratio

ns(0

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0.3

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(2

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(2.1

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(2

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(2.1

)

(2

.0)

(2.0

)

(2

.0)

(1.9

)

(1

.9)

Inte

rest

on

Deb

t(0

.0)

(0.0

)

(0

.2)

(0.4

)

(0

.6)

(0.6

)

(0

.6)

(0.5

)

(0

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(0.5

)

(0

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(0.5

)

(0

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Pre

ferr

ed D

ivid

ends

0.0

0.0

0.0

0.1

0.1

0.1

0.1

0.1

0.1

0.1

0.1

0.1

0.1

Bal

ance

for C

omm

on S

hare

hold

ers

(0.4

)

(2

.4)

(3.2

)

(3

.4)

(1.3

)

(1

.3)

(1.3

)

(1

.3)

(1.2

)

(1

.2)

(1.2

)

(1

.1)

(1.1

)To

tal

(0.4

)

(2

.4)

(3.3

)

(3

.7)

(1.8

)

(1

.8)

(1.7

)

(1

.7)

(1.6

)

(1

.6)

(1.5

)

(1

.5)

(1.4

)

Exhibit SCE-5

Affidavit of Garry Chinn



BEFORE THE



AFFIDAVIT OF GARRY CHINN


I, Garry Chinn, being duly sworn, depose and state as follows:

1. My name is Garry Chinn. My business address is 3 Innovation Way, Pomona, California

91768-2557.

2. I am making this affidavit on behalf of Southern California Edison Company (“SCE”).

The statements made herein are true and correct to the best of my knowledge and belief,

and I adopt them as my sworn testimony in this proceeding.

3. I received a Bachelor of Science degree in Electrical and Electronic Engineering, from

California State University, Sacramento, in 1991. I received a Master of Science in

Electrical Engineering, from the University of Southern California in 1995. I received my

Professional Engineer license as an Electrical Engineer in 1995. Since 1991, I have held

positions related to transmission system planning with the Los Angeles Department of

Water and Power, Metropolitan Water District of Southern California, and SCE. I have

more than 15 years of experience with SCE, all within Electric System Planning. I am

currently a Senior Engineering Manager of Electric System Planning. In this role, I am


responsible for leading a group of power system engineers in assessing the electric

system and developing transmission facilities to ensure the performance of SCE’s bulk

power system is in compliance with North American Reliability Corporation (“NERC”)

Reliability Standards. This is the first time I have submitted an affidavit to the

Commission.

4. The purpose of this affidavit is to describe: (I) the Alberhill and Mesa Projects, including

the transmission facilities to be constructed; (II) the findings of statewide transmission

plans.

I. PROJECT DESCRIPTIONS

5. SCE proposes to construct three major transmission projects that will improve reliability,

address load growth in SCE’s service area and address renewable policy goals. My

affidavit will discuss two of the three projects for which SCE is requesting incentive rate

treatment, the Alberhill Project and the Mesa Project. Both of these projects include

network facilities that will be under the operational control of the California Independent

System Operator (“CAISO”) and non-network facilities that will not be under the

operational control of the CAISO.

A. Alberhill

6. The Alberhill Project (“Alberhill”) has been proposed to serve current and projected

demand for electricity needs and maintain electric system reliability in areas surrounding

the proposed Alberhill Substation site and southwest of SCE’s existing Valley Substation

(see Figure 1 below).

7. Figure 1


8. In addition to serving the forecasted demand in the area surrounding the substation,

Alberhill would relieve the Valley South 115 kilovolt (kV) system by transferring five

existing 115/12 kV distribution substations: Ivyglen, Fogarty, Elsinore, Skylark, and

Newcomb substations, from the Valley South 115 kV system to the new Alberhill 115 kV

system. Alberhill would improve electrical reliability and operational flexibility in

southwestern Riverside County.

9. Alberhill would include construction of the following facilities: a) a new 500/115 kV

substation with a 500 kV switchrack and two 500/115 kV transformers; b) two new 500

kV transmission line segments (3.3 miles in total length) to connect the new substation to

SCE’s existing Serrano-Valley 500 kV transmission line, forming the Alberhill-Serrano

and Alberhill-Valley 500 kV transmission lines.


10. The 500 kV switchrack and two 500 kV transmission segments will be under CAISO

control and subject to the incentives requested.

11. Project costs for Alberhill are described by Mr. Adamson in Exhibit No. SCE-1.

12. The planned in-service date for Alberhill is June 2021.

B. Mesa

13. The Mesa Project (“Mesa”) is needed to address reliability concerns resulting from the

retirement of the San Onofre Nuclear Generating Station (“SONGS”) in 2013 and from

Once-Through Cooling (OTC) generation shutdowns expected by December 31, 2020.

Mesa will help address these concerns by allowing for greater flexibility in the siting of

future generation to meet local reliability needs in the Western Los Angeles Basin, while

reducing the total amount of new generation required by providing additional

transmission import capability.

14. Mesa involves the construction of a new 500/220/66/16 kV Mesa Substation and includes

both network transmission facilities as well as distribution, i.e., non-network, facilities.

Mesa would be constructed on the existing 220/66/16 kV Mesa Substation site.

15. The network transmission facilities for Mesa include the following: 1) construction of a

new 500 kV and 220 kV switchrack; 2) installation of three 500/220 kV transformer

banks; looping in the existing Mira Loma-Vincent 500 kV line, which currently passes

through the existing Mesa Substation site, to the new 500 kV switchrack forming the

Mesa-Vincent and Mesa-Mira Loma 500 kV lines; 3) looping in the existing Goodrich-


Laguna Bell 220 kV line, which currently passes through the existing Mesa Substation

site, to the new 220 kV switchrack forming the Goodrich-Mesa and Laguna Bell-Mesa

No. 1 220 kV lines; 4) looping-in the existing Laguna Bell-Rio Hondo 220 kV line,

which currently passes through the existing Mesa Substation site, to the new 220 kV

switchrack forming the Mesa-Rio Hondo and Laguna Bell-Mesa No. 2 220 kV lines; 5)

re-routing and termination of existing 220 kV lines into the new 220 kV switchrack with

new overhead getaways (i.e. replacement of existing overhead structures and removal of

portions of existing overhead lines in the transmission right-of-way adjacent to the Mesa

Substation site); 6) replacement of an existing 220 kV double-circuit transmission

structure in City of Commerce that supports the existing Goodrich–Laguna Bell (future

Laguna Bell–Mesa No. 1) and Mesa–Redondo 220 kV lines in order to increase the

capacity rating of the future Laguna Bell–Mesa No. 1 220 kV line. All of the above

facilities will be under CAISO control and subject to the incentives requested.

16. Figure 2 below, shows the transmission network configuration pre and post completion of

Mesa.


Figure 2: Transmission System Pre and Post Mesa Project

17. The planned in-service date for Mesa is June 2021.

II. TRANSMISSION PLANNING STUDIES

18. CAISO undertakes a comprehensive Transmission Planning Process (“TPP”) annually.

The CAISO TPP was approved by the Commission as a fair and open regional planning

process that considers and evaluates projects for reliability and congestion relief. The

duration of the development of each transmission plan is approximately 2 years. Each

TPP is developed in three phases; Phase I establishes the study plan, Phase 2 is

completion of technical studies and development of a comprehensive plan, and Phase 3 is

GOULD

EAGLE ROCK

GOODRICH

RIO HONDO

WALNUTMESA

LAGUNA BELL

GOULD

EAGLE ROCK

GOODRICH

RIO HONDO

WALNUT

MESA

CENTER

LAGUNA BELL

To Mira Loma

To Mira Loma

To Redondo

Beach CENTERTo Lighthipe

To Redondo

Beach To Lighthipe

VINCENTVINCENT

Planned 500 kV Substation/500 kV Loop-inPlanned 220 kV Loop-ins

Existing 500 kV Substation/Transmission LinesExisting 220 kV Substation/ Transmission Lines

Existing 500 kV Substation/Transmission LinesExisting 220 kV Substation/ Transmission Lines


the competitive solicitation process, as applicable. The CAISO’s TPP includes significant

stakeholder participation in each phase.

A. Alberhill

19. On December 9, 2009, the CAISO Board of Governors approved Alberhill.1 CAISO

found that the project was the “most robust transmission alternative with expected

minimum environmental impact in meeting reliability needs and providing long-term

transformer capacity for serving load growth in the southwestern Riverside County.”2

20. The 2009 CAISO Transmission Plan identified Alberhill as one of the various

alternatives requiring further CAISO evaluation prior to submission for CAISO Board

approval and requested that SCE provide engineering feasibility and planning level cost

estimates for five other alternatives. CAISO then conducted a reliability assessment and

determined that there was a need for Alberhill based on the load projections for the

Valley South 115 kV system. Valley South 115 kV system “will exceed its transformer

capability by summer 2014.”3

21. SCE’s Valley Substation, located in Romoland, California, is the sole source serving

customer electrical demand in the San Jacinto Region of southwestern Riverside County,

an area encompassing roughly 1,260 square miles and serving approximately 350,000

metered customers. Valley Substation transforms voltage from 500 kV to 115 kV with

four 560 MVA transformers. In 2004, the Valley 115 kV System was split into two

1 SCE-6, CAISO Memorandum to ISO Board of Governors regarding the decision on Alberhill Substation Project (December 9, 2009) attached hereto as Exhibit No. SCE-6. 2 Id. at p. 9. 3 Id. at p. 3.


separate and distinct 115 kV systems, the Valley North 115 kV system and the Valley

South 115 kV system. Each of these systems is served by two 560 MVA transformers.

22. These two 115 kV systems are served from the same 500 kV source and are not

connected at the 115 kV level. The Valley North 115 kV system consists of 11

distribution substations and the Valley South 115 kV system is served by 13 distribution

substations. The amount of electrical load that can be served by the Valley South 115 kV

system is limited to 1,119 megavolt amperes (MVA), the maximum amount of electrical

power that the two Valley South 115 kV system transformers can serve before exceeding

operating limits.

23. As shown in Figure 3, the 1-in-5 year heat storm projected peak electrical demand will

exceed the available transformer capacity of the Valley South 115 kV system. It indicates

that there is a need to build Alberhill to reduce loading on the transformers and provide

reliable service to the Valley South 115 kV System.

24.


Figure 3

25. The Valley South 115 kV System is currently islanded from any other 115 kV system. It

is bounded by San Diego Gas & Electric service territory to the south and mountains to

both the west and east. To the north is the Valley North 115 kV system; however, there

are no direct ties between the two systems at the 115 kV level. This means that no load

can be transferred to another system including the Valley North 115 kV System to

address the projected capacity overload. While the peak loading is less on the Valley

North 115 kV system than the Valley South 115 kV system, the transfer of load from the

Valley South 115 kV system to the Valley North 115 kV system could only occur

through the transfer of entire 115/12 kV distribution substations. Many of these

substations serve over 100 MVA of load and the transfer of these distribution substations


to the Valley North 115 kV system would only shift the capacity problem to the Valley

North 115 kV System. The two closest distribution substations to transfer has a total load

of over 225 MVA in 2021 and the available capacity of the Valley North 115 kV System

is only 265 MVA. Within just a few years, this transfer would result in the need for a

project, similar to Alberhill, to increase capacity and relieve the Valley North 115 kV

System. SCE determined this alternative as infeasible.

B. Mesa

26. In the 2013-2014 TPP, CAISO performed analyses to determine the transmission

solutions necessary to maintain reliability in Southern California in light of the retirement

of the San Onofre Nuclear Generating Station (“SONGS”) in 2013, and scheduled Once

Through Cooling4 (“OTC”) generation retirements expected by December 31, 2020.

These generating facilities account for approximately 7,332 MW of generation in the

region5. CAISO studied over 12 potential transmission proposals to address reliability

issues and divided the proposals into three groups6:

a. Group I – Transmission upgrades optimizing use of existing transmission lines

and not requiring new transmission rights of way;

b. Group II – Transmission lines strengthening Los Angeles/San Diego connection –

optimizing use of corridors into the combined area; and

4 OTC facilities are generating plants that take in ocean or estuarine water to cool their turbines and return the water back to the source. California State Water Resource Control Board’s (SWRCB) OTC Policy outlines a state-wide compliance schedule to reduce the environmental impact of these facilities, which involves the planned retirement of specific OTC plants within the Los Angeles Basin by the end of 2020. For more information see http://www.swrcb.ca.gov/water_issues/programs/ocean/cwa316/policy.shtml 5 SCE-7, CAISO Board approved 2013-2014 Transmission Plan p. 91, available at http://www.caiso.com/Documents/Board-Approved2013-2014TransmissionPlan_July162014.pdf. 6 Id. p. 96.


c. Group III – New transmission into the greater Los Angeles Basin/San Diego area.

27. Group I consisted of the following four proposals, including Mesa (formerly called Mesa

500 kV Loop-In Project):

• Additional 450-700 MVAR dynamic reactive support at or near the new

SONGS Mesa Substation7

• Imperial Valley flow controller

• Mesa 500 kV Loop-In Project

• Huntington Beach generation or electrically equivalent reactive support

28. CAISO describes Mesa as follows: “SCE proposed the Mesa 500 kV Loop-in

Project along with 500 MW of additional local resource capacity in the Western

LA area to: a) address the loading concerns identified in the ISO’s reliability

assessment results; b) alleviate the increased overall loading on transmission

facilities in the LA Metro area resulting from the retirement of SONGS and OTC

generation as well as long term load growth in the LA Metro and San Diego

areas; and, c) reduce the amount of local capacity needed to replace retired

generation8.”

29. In analyzing the proposals in Groups I, II, and III, CAISO recommended an overarching

strategy, which includes specific transmission development of the Group I proposals,

including Mesa. The following summarizes CAISO’s recommendation:

7 SONGS Mesa refers to an area next to SONGS and not in the vicinity of the Mesa Substation site. The proposed Dynamic Reactive Support is separate from the Mesa Project. 8 SCE-7, CAISO Board Approved 2013-2014 Transmission Plan p. 99. Available at http://www.caiso.com/Documents/Board-Approved2013-2014TransmissionPlan_July162014.pdf.


“[CAISO recommends] approval of ‘optimizing existing transmission’ projects to address a portion of the residual needs and as a more certain hedge against other resources failing to develop on schedule. (Group I) These mitigations provide material reductions in local capacity requirements, without the addition of new transmission rights of way. This provides the best use of existing transmission lines and transmission rights of way, as well as minimizing risk about permitting and the timing of permitting.”9

“The [CAISO] strategy is based on the principles of least regrets transmission development, focusing on maintaining reliability, supporting preferred resources and minimizing or delaying new transmission lines by focusing first on the Group I solutions that do not require new transmission lines. It provides the maximum opportunity for preferred resources to develop in lieu of new transmission lines (Group II or Group III transmission proposals) which represent higher cost, new transmission right of way, possibly lengthier development timelines, and higher regulatory uncertainty than the Group I projects. The recommended strategy also provides the least risk of the need for delay in compliance with OTC generation requirements. Further, the ISO’s analysis demonstrates that the recommended resources perform complementary to many of the Group II and Group III proposals should those be developed to address needs beyond this transmission plan’s scope.”10

30. CAISO recommended proceeding with Mesa in the LA Basin. CAISO stated: “With this

project, a new 500/230/66 kV substation will be rebuilt on the property of the existing

Mesa 230/66 kV substation. With the addition of 500kV voltage, a new source from bulk

transmission will be established in the LA Basin to bring power from Tehachapi

renewables or power transfer from PG&E via WECC Path 26.”11

31. In March 2014 as part of the 2013/2014 Transmission Plan, the CAISO Board of

Governors approved the four projects in Group I, including Mesa.

9 Id. at p. 104. 10 Id. at pp. 104-105. 11 Id. p. 107.


32. The CAISO has reaffirmed the need for Mesa in subsequent TPPs. In the latest 2016-

2017 Transmission Plan, the CAISO performed a mid-term (2021) and a long term

(2026) local capacity requirement assessments and concluded the following: “The CPUC-

approved long-term local capacity procurement, together with the ISO Board-approved

transmission upgrades are needed to provide adequate resources to meet reliability

requirements for the LA Basin and San Diego LCR areas and to enable compliance with

the State Water Resources Control Board’s Policy on once-through-cooled generation.”12

The ISO Board-approved transmission upgrades includes the Mesa Project.

33. In addition to the retirement of OTC units, Mesa is driven by a set of planning

assumptions. The location and size of new generation, forecasted load, and retirement of

existing non-OTC generation are integral to the planning process that has shown the need

for this project.

34. Two pieces of California legislation, however, add uncertainty to these planning

assumptions. The first is Senate Bill 350, signed into law in October 2015, which

increases California’s renewable electricity procurement goal from 33% by 2020 to 50%

by 2030, doubles statewide energy efficiency savings in electricity end uses by 2030 and

authorizes utilities to undertake transportation electrification activities.13 More recently,

Senate Bill 32, enacted into law in September 2016, requires the California State Air

Resources Board to ensure that statewide greenhouse gas emission are reduced to 40%

12 SCE-7, CAISO Board Approved 2016-2017 Transmission Plan p. 114, available at http://www.caiso.com/Documents/Board-Approved_2016-2017TransmissionPlan.pdf 13 See http://www.energy.ca.gov/sb350/.


below 1990 levels by 2030.14 In additional to the transportation sector, greenhouse gas

reductions includes electric generation.

35. SB350 and SB32 introduce potentially significant changes in the forecasts of load and

generation. For example, vehicle electrification may increase load in some areas while

increasing energy efficiency savings can significantly decrease load. New renewables

may remain central plant design and sited in areas remote from load centers or outside of

California. New renewables may be distributed resources located in load centers.

Greenhouse gas emitting generation may retire. Once these potential changes are fully

incorporated into the planning process, the need for a particular project can change.

36. In general, new planning assumptions can defer the need for a project beyond the

planning horizon and in some cases significant assumption changes can result in project

cancellation. Of note, in CAISO’s 2016-17 Transmission Plan published March 17,

2017, thirteen Pacific Gas & Electric projects were recommended to be canceled.15 New

planning assumptions can also accelerate the need for a project. Even if a designated

project remains on schedule, an earlier need date may drive a search for alternatives that

can address the need in an earlier timeframe. As the planning process is performed

annually, projects are exposed to several cycles of review and any delays increase the risk

for a re-examination of the project.

14 Senate Bill (SB) 32, California Global Warming Solutions Act of 2006, Section 38556 of the Health and Safety code. Available at https://leginfo.legislature.ca.gov/faces/billNavClient.xhtml?bill_id=201520160SB32. 15 SCE-7, CAISO Board Approved 2016-2017 Transmission Plan p. 102, available at http://www.caiso.com/Documents/Board-Approved_2016-2017TransmissionPlan.pdf.

Exhibit SCE-6

Memo to CAISO Board Recommending Approval of Alberhill

M&ID/RT South/A. Chowdhury/D. Le Page 1 of 9

California Independent System Operator Corporation

MemorandumTo: ISO Board of Governors

From: Dr. Keith Casey, Vice President of Market & Infrastructure Development

Date: December 9, 2009

Re: Decision on Alberhill Substation Project

This memorandum requires Board action.

EXECUTIVE SUMMARY

This memorandum requests ISO Board of Governors approval of the Alberhill Substation Project (Project), proposed by Southern California Edison Company (SCE). Based on the ISO Business Practice Manual for the Transmission Planning Process, transmission projects with capital cost greater than $50 million require Board approval. The Project has an estimated total cost of $315 million, which includes both the distribution retail cost as well as the transmission access charge (TAC) cost under the ISO. The TAC-related cost is $171 million. Management’s principal determinations and findings are:

The Project is needed by summer 2014, based on SCE’s 1-in-5 year1 heat wave load forecast for the local area2, to provide additional transformer capacity to mitigate the Valley South 500/115 kV transformer overloading concerns. The Valley South transformers are located within the Valley Substation in Romoland, California.

In the absence of a certain generation alternative, the proposed Project, with its ultimate build-out of three, 560 MVA, load-carrying transformers (and one spare transformer), will provide robust substation capacity to serve load growth in the southern Riverside County area, at least for the next fifteen years, based on the current load projection;

1 SCE plans for infrastructure upgrades under its own operational jurisdiction (i.e., Valley 115 kV system) based on 1-in-5 year heat wave load forecast. The Valley 115 kV system is not under ISO’s operational control and is not subject to ISO planning standards that require 1-in-10 year heat wave load forecast. 2 The California Energy Commission (CEC) provides the ISO with individual participating transmission owners system load forecast for planning studies. However, the owners provide the ISO with the sub-area load projections. These owners are responsible for ensuring that the aggregated coincidental sub-area forecasts match with the CEC load forecast for its aggregated larger area.

M&ID/RT South/A.Chowdhury/D.Le Page 2 of 9

The Project will enable SCE to improve its reliability in serving load in Riverside County by minimizing the loss of load exposure3 in the event of a substation outage; and

The Project is expected to cause minimum environmental impact in the area.

Management recommends that the Board approve the Project and directs SCE to proceed with its necessary permitting and engineering:4

Moved, that the ISO Board of Governors finds that the Alberhill 500/115 kV Substation Project, as described in the memorandum dated December 9, 2009, is a necessary and cost-effective long-term transmission addition to the CAISO Controlled Grid.

Moved, that the ISO Board of Governors directs Southern California Edison to continue with the design, licensing, and construction of this project.

BACKGROUND

SCE’s Valley Substation, located in Romoland, California, is the sole source serving customers’ loads in the San Jacinto Region of southwestern Riverside County. This area encompasses about 1,260 square miles and serves approximately 325,000 customers. Valley Substation transforms voltage from 500 kV to 115 kV, with four load-carrying 560 MVA transformers. In 2004, the Valley 115 kV system was split into two separate 115 kV systems: Valley North and Valley South. Each of these systems is served by two 560 MVA transformers from the same 500 kV source. A stand-by spare transformer5 is scheduled to be installed at Valley Substation in 2010. This spare transformer will provide back-up transformer capacity in the event of a transformer failure at Valley Substation. Since SCE has operational control on radial transmission facilities, the cost of the spare Valley transformer will be incurred by its Distribution Department and recovered through its retail rate.

The ISO transmission planning process requires participating transmission owner’s sponsored projects to be submitted through the request window for evaluation and recommendation in the transmission plan for that study cycle. Accordingly, SCE submitted the Project during the 2008 request window, along with the supporting information required by the tariff and the Business Practice Manual (BPM) for Transmission Planning. The 2009 Transmission Plan identified the Project as one of the various alternatives requiring further information for ISO evaluation prior to submitting for Board approval.6

3 SCE 1-in-5 load forecast for the Valley Substation is 1,642 MW for 2010. 4 Estimated cost for final engineering and design works is approximately 10% of the total project cost. 5 The stand-by transformer is the fifth transformer to be installed at Valley Substation; the other four existing transformers are load-carrying transformers. 6 See Table 1-4, page 20 of the ISO 2009 Transmission Plan (http://www.caiso.com/2354/2354f34634870.pdf).


ISO STAFF ASSESSMENT

Evaluation of need for Project

ISO staff conducted a reliability assessment and determined that there was a need for the Project, based on the projections for the Valley South 115 kV system load. Specifically, the assessment found the Valley South system load will exceed its transformer capability by summer 2014 (i.e., 1122 vs. 1120 MVA). The Valley North and South systems are two separate electrical systems: Valley North is served from the 115 kV gas insulated switchgear and the Valley South is served from the 115 kV open air substation facilities. Due to high load growth (approximately 14% per year) between the 2000 and 2004 time frame, the Valley North and Valley South systems were split into two separate electrical systems in 2004. This allowed the Valley South system to be served from the expanded 115 kV open air switchgear, rather than being connected to the limited gas insulated switchgear. Based on the existing system design limitation, the Valley North switchgear cannot be expanded further.

Evaluated alternatives to the Project

Management requested that SCE provide engineering feasibility and planning level cost estimates of five other alternatives in its evaluation of the Project. These alternatives are summarized in the following Table 1.


Table 1. Summary of Rejected Alternatives

Alternative Scope of Project Evaluations Amount7

Alternative 1

Transfer Load from Valley South to Valley North

Transfers two 115kV Substations from the Valley South bus to the Valley North bus within the existing valley substation Constructs new 115 kV transmission line

Pros:

Low costs

Cons:

• Requires rebuilding a substantial portion of the existing lines

• Only shifts the problem without solving it

• Is considered short-term mitigation that requires additional upgrades (i.e., new substation) within two years of its completion

Less than $30 million

Alternative 2

Expansion of 500/115 kV Valley Substation

• Installs a new 560 MVA 500/115 kV Transformer Bank at the existing Valley Substation

• Replaces 16 existing 115 kV breakers on Valley South System with 63 kA rated units

Pros:

• Low costs

Cons:

• Does not create any new 115 kV system ties for substation load transfers

• Exceeds SCE’s substation design practice of limiting to 3 load-carrying banks and 1 spare within 500 kV substation

• Increases further loss of load exposure

Less than $50 million

7 Listed costs for alternatives are approximate costs due to proprietary information from SCE. However, ISO Staff has actual planning costs provided by SCE for evaluation of alternatives.


Alternative 3

Build New 230/115 kV Substation

• Constructs new 230/115 kV Substation

• Constructs three new 30 mile 230 kV T/L

Pros:

• Provides loading relief to Valley transformers for 10-year planning horizon

Cons:

• Is considered difficult to permit because this option requires CPCN permitting for at least 30 miles of rights-of-way through populated areas

• Proposed location is far from major load areas

$300 - $350 million

Alternative 4

Construction of new Auld Substation

• Constructs a new 500/115 kV substation south of the existing valley substation

• Constructs two 14 mile 500 kV T/L

Pros:

• Provides loading relief to Valley transformers for at least 10-year planning horizon

Cons:

• Is considered difficult to permit because it requires CPCN permitting and acquisition of a minimum of 28 miles of rights-of-way through heavily populated areas

• Requires much longer construction time

$300 - $350 million

Alternative 5

Generation Option (EME-proposed Sun Valley Energy Project)

Edison Mission Energy proposed to construct 5x101.5 MW peakers (507.5 MW total capacity)

Currently is at the permitting stage at the California Energy

Pros:

If this project receives appropriate environmental permits from the CEC and the South Coast Air Quality Management District, receives power purchase agreement, and is able to complete by June

Less than $40 million8 for

connection of this generation to

Valley Substation

8 Non-TAC costs due to proposed connection of generation project to SCE-Controlled 115 kV sub-transmission radial system


Commission

Connects to Valley South 115 kV bus at Valley Substation

2014, it will negate the need for the transmission option.

Cons:

Project is located in South Coast Air Quality Management District (SCAQMD), which currently has priority reserve issues

Uncertain in obtaining air credits from SCAQMD for construction

Project is still under environmental review by the CEC and has not yet been granted permit to construct

Has no signed power purchase agreement with Utility Distribution Company

Is considered uncertain generation project due to above environmental issues that need to be resolved

Description of proposed Project

SCE proposes to construct the Project to serve current and projected demand for electricity in the southwestern Riverside County, including the cities of Lake Elsinore, Canyon Lake, Perris, Menifee, Murrieta, Murrieta Hot Springs, Temecula, Wildomar, and the surrounding unincorporated portions of Riverside County. The following is the scope of the project:

1. Construction of a new 500/115 kV substation to provide additional substation capacity to the area currently served by Valley Substation; the project will have two 560 MVA 500/115 kV AA-transformer banks initially. The ultimate substation arrangement will have a total of four 560 MVA transformer banks, with three banks carrying load and


one serving as a stand-by spare unit in the event of a bank failure. The 500/115 kV substation will be constructed using a hybrid (500 kV gas insulated switchgear/115 kV open air) configuration.

2. Construction of two, 1.5-mile lengths of new, 500 kV single-circuit transmission lines to connect the new substation by loop-in of the existing Serrano – Valley 500 kV transmission line;

3. Construction of a new 115 kV sub-transmission line (approximately three miles in length) and modifications to four existing 115 kV sub-transmission lines to transfer loads from Valley South system to the new Alberhill substation. The cost for performing these works is recovered through retail rate and is not under the ISO TAC cost, since SCE’s 115 kV radial facilities are not under ISO operational control.

4. Installation of telecommunication improvements to connect the new facilities to SCE’s telecommunication network. The cost for most of this work is not included in the ISO TAC costs.


Figure 1. Alberhill Substation Project (Drawing Courtesy of SCE)

Costs of Alberhill Substation Project

The total cost of this project is $315 million, which includes both the TAC and non-TAC portions. The TAC-related cost is $171 million and covers the cost of the transmission facilities under ISO’s operational control. The retail rate cost is $144 million and covers the cost of the 115 kV sub-transmission facilities that are under SCE’s operational control. The estimated annual levelized revenue requirement for the TAC cost portion is estimated to be $22 million, if the annual carrying charge is 13 percent. This estimate is for illustration only because SCE has yet to bring this project to the Federal Energy Regulatory Commission for cost recovery approval. An updated transmission revenue requirement will be available upon their review and approval.


POSITIONS OF THE PARTIES

Management presented this proposed project to stakeholders as part of the 2009 transmission planning process. In Table 1-4, page 20 of the Final ISO 2009 Transmission Plan Report9, posted on the ISO website, the Management indicated that this proposed Project would be evaluated further with other alternatives before recommending to the Board for approval. On September 30, 2009, SCE submitted to the CPUC its CPCN permit filing. The CPUC has initiated a proceeding to conduct the environmental permit review of this project. Currently, SCE anticipates receiving the final decision from the CPUC regarding this project in the Fall of 2011. The planned completion date for this project is June 2014.

MANAGEMENT RECOMMENDATION

Based on Management’s findings that the project is the most robust transmission alternative with expected minimum environmental impact in meeting reliability needs and providing long-term transformer capacity for serving load growth in the southwestern Riverside County, Management recommends the Board approve this project as a new addition to the ISO controlled grid. In addition, SCE should be directed to proceed with necessary permitting, engineering and construction of the project, with a planned operational date of June 2014.

9 The ISO Transmission Plan is posted at http://www.caiso.com/2354/2354f34634870.pdf.

Exhibit SCE-7

CAISO’s 2013-2014 Transmission Plan Containing Sections Approving Mesa

CAISO’s 2016-2017 Transmission Plan Confirming the Need for Mesa

Exhibit SCE-8

Affidavit of Fernando Benavides

Exhibit No. SCE-Page 1 of 11


BEFORE THE



AFFIDAVIT OF FERNANDO BENAVIDES


I, Fernando Benavides, being duly sworn, depose and state as follows:

1. My name is Fernando Benavides. My business address is 3 Innovation Way, Pomona,

California 91768-2557.

2. I am making this affidavit on behalf of Southern California Edison Company

(“SCE”). The statements made herein are true and correct to the best of my

knowledge and belief, and I adopt them as my sworn testimony in this proceeding.

3. I received a Bachelor of Science degree in Electronics and Computer Engineering

Technology, from California State Polytechnic University, Pomona, in 2003. I

received a Master of Science in Electrical Engineering, from California State

University, Los Angeles, in 2014. I received my certification as an Engineer-In-

Training in 2016 (State of California, Certificate No. 157882 ) Over the past three

years, I have been performing transmission planning studies with respect to

transmission capability in the SCE electric system in order to accommodate new

Exhibit No. S E-Page 2 of 11

generation interconnections. This is the first affidavit or testimony I have submitted

to the Federal Energy Regulatory Commission.

4. The purpose of this affidavit is to describe: (I) the Eldorado-Lugo and Lugo-Mohave

500 kV Series Capacitor Project (“ELM”); (II) the transmission facilities to be

constructed and/or modified on the Eldorado-Lugo, Eldorado-Mohave, and Lugo-

Mohave 500 kV Transmission Lines and at the Eldorado, Lugo, and Mohave

Substations to increase the series compensation on the Eldorado-Lugo and Lugo-

Mohave 500 kV Transmission Lines; (III) the necessity, under the California

Independent System Operation Corporation (“CAISO”) tariff, for SCE, co-owner of

Eldorado and Mohave Substations, owner of the Lugo Substation, and owner of the

Eldorado-Lugo and Lugo-Mohave 500 kV Transmission Lines, to construct and

modify facilities required for ELM; (IV) the risks and challenges associated with

SCE’s construction of ELM.

I. PROJECT DESCRIPTION

5. ELM is located in California and Nevada, within the Mojave Basin and Range. ELM

would extend northeast from Lugo Substation (located in San Bernardino County,

California) to Mohave Substation (located in Clark County, Nevada) and Eldorado

Substation (located in the City of Boulder City, Nevada), as well as northwest from

Mohave Substation to Eldorado Substation, as depicted in Figure 1: Project Overview

Map. Portions of ELM would also cross the City of Hesperia and the unincorporated

community of Lucerne Valley in California, as well as the unincorporated

communities of Searchlight and Laughlin in Nevada.


6. Figure 1: Project Overview Map

7. The network transmission facilities that SCE proposes to construct as part of ELM

include: 1) construction of two new 500 kV mid-line series capacitors-the proposed

Newberry Springs Series Capacitor and Ludlow Series Capacitor near Pisgah

Substation; 2) installation of up to two dead-end towers adjacent to each of the

proposed Newberry Spring and Ludlow Series Capacitors; 3) correction of 16

overhead clearance discrepancy locations involving relocation, replacement, or

modification of existing transmission, subtransmission, and distribution facilities


including minor grading along the Eldorado-Lugo, Lugo-Mohave, and Eldorado-

Mohave 500 kV Transmission Lines; 4) installation of new line termination

equipment (circuit breakers, disconnects, conductor, system protection, etc.) at the

Lugo, Mohave, and Eldorado Substations; 5) upgrade of the existing series capacitor

banks at Eldorado and Lugo Substations; and 6) replacement of the existing series

capacitor bank at Mohave Substation. All of the above network transmission

facilities will be under CAISO control and subject to the incentives requested.

8. ELM would include modifications within the existing Lugo, Mohave, and Eldorado

Substations including installation of new terminal equipment at each substation,

upgrading the existing series capacitor banks at Eldorado and Lugo, and replacement

of the series capacitors at Mohave. ELM will increase the series compensation the

Eldorado-Lugo and Lugo-Mohave 500 kV Transmission Lines from 35% to 65%

and 70% respectively. The planned in-service date for ELM is June of 2020.

9. Figure 2 below, shows the Project configuration in addition to the proposed

compensation level and location of each series capacitor. A description of the

facilities required to complete ELM is provided in Section I of this Affidavit.

Exhibit No. SCE- Page 5 of 11

10.

Figure 2

11. Segments of ELM will terminate at the Eldorado 500 kV Switchyard and the Mohave

Switchyard, which are both located within the Eldorado System. The Eldorado

System is jointly-owned by SCE, the Los Angeles Department of Water and Power,

and NV Energy (the “Eldorado Co-Owners”). SCE is the operating agent for the

Eldorado System on behalf of the Eldorado Co-Owners. The Eldorado System is

within the CAISO balancing authority area. SCE is the only Eldorado Co-Owner

who is also a CAISO Participating Transmission Owner.

12. The majority of ELM would be constructed within existing SCE ROWs, or public

ROWs where SCE has existing franchise agreements. However, upon final

engineering and ELM approval, acquisition of new land rights would be required for

the proposed mid-line series capacitors and/or fiber optic repeater sites, where

necessary.


13. Project costs for ELM are described by Mr. Adamson in Exhibit No. SCE-1.

II. TRANSMISSION PLANNING STUDIES

14. To manage multiple generator interconnection requests that are made for generation

resources proposed to be located in the same geographic area, the CAISO and SCE

have developed procedures for evaluating “clusters” of generation facilities in a

single study based on the Interconnection Queue (i.e., the queue of generators that

have requested interconnection within the CAISO controlled system). The CAISO

and SCE can, therefore, evaluate a cluster of queued facilities in a single study instead

of assessing each facility in a separate study. The CAISO’s and SCE’s cluster studies

are referred to herein as Queue Cluster (QC) Interconnection Studies1.

15. As part of the SCE East of Pisgah2 (EOP) QC 3 and QC 4 Interconnection Studies

(completed together and referred to as the QC3/QC4 Phase II Interconnection Study

Report), SCE in conjunction with the CAISO identified the need to increase the

compensation on both the Eldorado-Lugo and Lugo-Mohave 500 kV Transmission

1 As directed by the Federal Energy Regulatory Commission, the CAISO has developed standardized interconnection procedures that govern the process by which generation interconnections are studied and ultimately connected to that portion of SCE’s transmission system that is under the operational control of the CAISO. The currently effective, FERC–approved CAISO generator interconnection procedures can be found at: https://www.caiso.com/Documents/AppendixY_GeneratorInterconnectionProceduresForInterconnectionRequests_asof_Mar8_2016.pdf. 2 East of Pisgah refers to the area consisting of the transmission system between the Eldorado and Pisgah Substations and resides within the East of Lugo Area as defined by the CAISO. The annual Board Approved CAISO Transmission Plan provides an Area Description of this location. https://www.caiso.com/Documents/BoardApproved2012-2013TransmissionPlan.pdf


Lines as part of a Delivery Network Upgrade3 (DNU) in order to maintain the

reliability of the SCE Transmission System, prevent adverse effects on the

Transmission System of a neighboring utility, and to provide Deliverability for the

projects requesting to interconnect as part of these queue clusters. The upgrades were

identified as needing to be completed in order for projects to achieve Full Capacity

Delivery Status (FCDS4).

16. In response to the California Renewable Portfolio Standard (RPS)5, the ISO amended

its tariff to address needed changes, and the Federal Energy Regulatory Commission

(FERC) approved the ISO tariff amendments on December 16, 2010.6 The amended

tariff provided changes to the ISO’s transmission planning process, including the

introduction of Policy-Driven Transmission Solutions7 for new transmission projects.

Policy Driven Transmission Solutions are those that could be needed to achieve state,

municipal, county or federal policy requirements or directives. The tariff changes

were initially applied to the CAISO 2012-2013 Transmission Plan followed by the

2013-2014 Transmission Plan. The CPUC and CEC subsequently sent a letter on

March 12, 2012 formally recommending the renewable portfolios for use in the ISO

2012-2013 Transmission Planning Process and on February 7, 2013 for use in the ISO

3 As defined in CAISO Appendix A (i.e. Master Definition Supplement), of the Fifth Replacement Tariff: https://www.caiso.com/Documents/AppendixA_Definitions_asof_Jan1_2017.pdf. 4 As defined in CAISO Appendix A (i.e. Master Definition Supplement) of the Fifth Replacement Tariff: http://www.caiso.com/Documents/AppendixA_Definitions_asof_Feb1_2017.pdf 5See the CPUC California Renewables Portfolio Standard site available at http://www.cpuc.ca.gov/RPS_Homepage/ 6 Order Conditionally Accepting Tariff Revisions And Addressing Petition For Declaratory Order, 133 FERC ¶ 61,224 (December 16, 2010) 7 CAISO Fifth Replacement FERC Electric Tariff, Section 24.4.6.6, Policy-Driven Transmission Solutions. See www.caiso.com/Documents/Section24_--ComprehensiveTransmissionPlanningProcess_asof_Mar28_2016.pdf


2013-2014 Transmission Planning Process8. As a result, the ISO’s transmission

planning process considered a range of possible generation scenarios and identified

transmission elements needed to meet the State’s RPS goals.

17. As part of the changes to the ISO’s planning process, in the interest of meeting the

States RPS goals, upgrades required to serve renewable resources that either had or

were expected to have signed generator interconnection agreements (GIAs), including

the upgrades identified as a result of the QC 3 and QC 4 Phase II Interconnection

Study for increased compensation on the Eldorado-Lugo and Lugo-Mohave 500 kV

Transmission Lines, were considered as part of the ISO analysis methodology in the

CAISO’s annual transmission plan. Subsequently, the 2012-2013 and 2013-2014 ISO

Transmission Plans identified and recommended for approval the Eldorado-Lugo and

Lugo-Mohave Series Capacitor Upgrades, respectively, as Policy-Driven Upgrade

Solutions9 since they were identified as being needed by a large quantity of

generation projects spread across a large geographic area. Both Projects also relieve

previously identified deliverability constraints10.

8 www.caiso.com/Documents/2013-2014RenewablePortfoliosTransmittalLetter.pdf 9 Refer to Section 24.4.6.6-Policy-Driven Transmission Solutions at http://www.caiso.com/Documents/Section24_--ComprehensiveTransmissionPlanningProcess_asof_Mar28_2016.pdf 10 This constraint, referred to as the “Desert Area Constraint”, limits deliverability in a wide electrical area that covers several renewable zones. Generators interconnecting within these renewable zones contribute to the constraint. The need for transmission upgrades to relieve the Desert Area Constraint is analyzed for other renewable portfolios by comparing the generation behind the deliverability constraint. The CAISO analyzes this constraint as part of their annual transmission planning process.


18. The Eldorado-Lugo and Lugo-Mohave portions of the Project were proposed and

approved through the CAISO transmission planning process on March 20, 201311 and

July 16, 201412 respectively as Policy-Driven Upgrades. Through this process, each

of the upgrades were identified as providing renewable integration, reliability, and

deliverability benefits.13

19. ELM was approved as part of an effort to integrate renewable generation to meet the

requirements as outlined and required by the California Renewable Portfolio Standard

(RPS) for SCE to serve at least 33 percent of its retail load with renewable energy by

2020. As a result of the requirements of the California RPS, the CAISO identified and

approved the Projects as Policy-Driven Transmission Solutions. As a Policy-Driven

Transmission Solution, ELM was evaluated by the CAISO as being needed to meet

federal, state, county, or municipal policy requirements.

20. ELM, as part of its reliability benefit, would decrease power flow into the

neighboring system’s transmission system, and its adverse effects, due to the increase

of generation in the SCE Eldorado System in addition to increased imports into the

LA Basin.. The reduction in loop flow into the neighboring system is accomplished

by decreasing the amount of MW power flow into the Los Angeles Department of

Water and Power (LADWP) Transmission System by increasing the compensation on

both the Eldorado-Lugo and Lugo-Mohave 500 kV Transmission Lines. The results 11 2012-2013 ISO Transmission Plan (March 20, 2013), available at http://www.caiso.com/Documents/BoardApproved2012-2013TransmissionPlan.pdf 12 2013-2014 ISO Transmission Plan (July 16, 2014), available at http://www.caiso.com/Documents/Board-Approved2013-2014TransmissionPlan_July162014.pdf 13 See pages 275-76, 2012-2013 ISO Transmission Plan and page 196, 2013-2014 ISO Transmission Plan


identifying the adverse effects on the LADWP Transmission System as well as the

CAISOs recommendation and approval of ELM as a mitigation can also be found in

the CAISO 2012-2013 and 2013-2014 Transmission Plans.14

21. ELM is required to increase the amount of deliverability of interconnection requests

that contribute to the Desert Area Constraint. As a result, ELM is required for existing

generators that are currently operational, generators that have signed and executed

Interconnection Agreements that are not yet in-service, and proposed generation

interconnecting projects that do not yet have a signed Interconnection Agreement to

achieve FCDS. The ability of generation interconnection projects to achieve FCDS

effects projects in the EOP Area as well as generation interconnection projects in

surrounding areas within and outside of the SCE service territory including San Diego

Gas & Electric (SDG&E). As a result ELM would allow SCE and other utilities to

meet the requirements of executed Interconnection Agreements (IA) that require the

Project to achieve FCDS. As shown in the following table (Figure 3), there are

currently two (2) and six (6) generation interconnection projects within the SCE and

SDG&E service territories, respectively, that require completion of ELM to achieve

FCDS.

14 See Page 275, 2012-2013 ISO Transmission and Page 196, 2013-2014 ISO Transmission Plan


22.

Figure 3

Utility

CAISO Queue

Position

CAISO Study Technology

Project Size

(MW)

GIA?

Current/Actual

Online Date

FERC Docket No.

SCE 643AE QC3 PV 150 MW Y

9/1/2021 ER15-78-LGIA ER15-1670-First Amendment

SDG&E

667 QC4 PV 150 MW Y

12/31/2021

SDG&E

789 QC4 PV 80 MW Y 9/30/2016

SCE 855 QC4 PV 80 MW Y 12/2/2016

ER15-202

SDG&E

952 QC6 PV 100.81 MW

Y 11/30/2016

SDG&E

961 QC6 PV 200.62 MW

Y 7/21/2018

SDG&E

1040 QC7 PV 127 MW Y 1/3/2014

Exhibit SCE-9

CAISO’s 2012-2013 Transmission Plan Containing Sections Approving

Lugo-Eldorado Series Capacitors Portion of ELM

Exhibit SCE-10

CAISO’s 2013-2014 Transmission Plan Containing Sections Approving

Lugo-Mohave Series Capacitors Portion of ELM

CERTIFICATE OF SERVICE

I hereby certify that I have this day served the foregoing PETITION OF SOUTHERN

CALIFORNIA EDISON COMPANY FOR DECLARATORY ORDER upon each person

designated on the official service list compiled by the Secretary in this proceeding.

Dated at Rosemead, California, this 7th day of April, 2017.

/s/ Norman Goss____________________________ Norman Goss, Legal Administrative Assistant SOUTHERN CALIFORNIA EDISON COMPANY

2244 Walnut Grove Avenue Post Office Box 800 Rosemead, California 91770