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BEFORE THE PUBLIC UTILITIES COMMISSION OF THE

STATE OF CALIFORNIA

In the Matter of the Application of SOUTHERN CALIFORNIA EDISON COMPANY (U 338-E) for a Permit to Construct Electrical Facilities with Voltages between 50 kV and 200 kV; Valley-Ivyglen 115 kV Subtransmission Line Project.

A.07-01-031, et al.

(Filed January 16, 2007)

And Related Matter.

A.07-04-028

In the Matter of the Application of SOUTHERN CALIFORNIA EDISON COMPANY (U 338-E) for a Certificate of Public Convenience and Necessity for the Alberhill System Project.

A.09-09-022

(Filed September 30, 2009)

SOUTHERN CALIFORNIA EDISON COMPANY’S (U 338-E) REPLY BRIEF

BETH A. GAYLORD TAMMY JONES IAN FORREST

Attorneys for SOUTHERN CALIFORNIA EDISON COMPANY

2244 Walnut Grove Avenue Post Office Box 800 Rosemead, California 91770 Telephone: (626) 302-6634 Facsimile: (626) 302-1910 E-mail: [email protected]

Dated: January 4, 2018

ASP Reply Brief

Table Of Contents

Section Page

i

I. INTRODUCTION ...........................................................................................................................1

II. THE INTERVENORS’ ASSERTIONS THAT CAISO’S FORECAST, RATHER

THAN SCE’S FORECAST, SHOULD BE USED ARE BASED ON

FUNDAMENTALLY FLAWED ASSUMPTIONS AND SHOULD BE

REJECTED ......................................................................................................................................3

III. SUBSTANTIAL EVIDENCE DEMONSTRATES THAT THE PROJECT

WOULD REMEDY MULTIPLE ELECTRICAL SYSTEM NEEDS TO

PROVIDE OVERRIDING CONSIDERATIONS SUPPORTING APPROVAL

OF THE PROJECT ..........................................................................................................................6

A. SCE Forecasts of Electrical Demand are in Accordance with Prudent Planning Principles,

Including the Adjustments SCE Makes to Raw Data in Order to Accurately Represent the

Capabilities and Needs of the System ............................................................................................. 6

B. SCEs Forecast Allocates Proper Weight to Local Energy Resources Such as Distributed

Generation, Energy Efficiency and Demand Response ................................................................ 12

C. Contrary to the Intervenors’ Assertions, the ASP is Needed to Develop System Tie-Lines ........ 15

D. Power Flow Analyses Incorporating the Valley South Subtransmission Project Have

Demonstrated that the VIG Project is Needed Irrespective of Whether VSSP is Constructed .... 16

IV. THE INTERVENORS CONTINUE TO RAISE ALTERNATIVES THAT WERE

ADDRESSED AND DISMISSED IN THE FEIR .........................................................................18

A. Shifting Demand From One Substation to Another Substation does not Meet the Project

Objectives and was Accordingly Eliminated in the FEIR ............................................................ 19

B. The Installation of a Third Transformer was Considered and Eliminated in the FEIR Because it

does not Meet the Project Objectives............................................................................................ 20

ASP Reply Brief

Table Of Contents (Continued)

Section Page

ii

V. THE FEIR SHOULD BE CERTIFIED BECAUSE IT ANALYZES THE

ENTIRETY OF THE WORK NEEDED TO COMPLETE THE PROJECT, IT

ADEQUATELY ANALYZES POTENTIAL ENVIRONMENTAL IMPACTS

AND SUBSTANTIAL EVIDENCE SUPPORTS ITS REJECTION OF

ALTERNATIVES..........................................................................................................................21

A. The FEIR’s Environmental Analyses are Appropriate and are Supported by Substantial Evidence

in the Administrative Record ........................................................................................................ 21

1. Aesthetics ................................................................................................................................... 22

2. Socioeconomic and Environmental Justice ................................................................................ 26

3. Air Quality .................................................................................................................................. 28

4. Noise........................................................................................................................................... 33

B. The Fact that the FEIR does not Include Measures Which Ensure Compliance with its

Assumptions does not Render it Invalid ....................................................................................... 35

C. A Statement of Overriding Considerations for VIG is Warranted and Supported by Substantial

Evidence in the Administrative Record ........................................................................................ 35

D. The FEIR’s Analysis of Alternatives is in Accordance with and Satisfaction of CEQA ............. 38

1. There is no Feasible Alternative to Construct VIG without Helicopters ................................... 38

2. No ASP Alternative was Rejected for Failure to Require the Construction of a Substation ..... 41

3. The FEIR Considered a Reasonable Range of Alternatives and the Fact that it did not Consider

an Undergrounding Alternative Exclusive to the City does not Render the FEIR’s Alternatives

Analysis Deficient ...................................................................................................................... 42

VI. SCE’S ESTIMATE OF MAXIMUM PRUDENT AND REASONABLE COST IS

CONSISTENT WITH PUBLIC UTILITIES CODE SECTION 1005.5 ...................................... 43

A. Cost Increases will not “Unquestionably” be needed but Even if They Are, PUC Section

1005.5(b) Specifically Allows for Such Increases ........................................................................ 44

ASP Reply Brief

Table Of Contents (Continued)

Section Page

iii

B. SCE has Provided a Detailed (488 page) Document with Information in Support of the MPRC

and the Project’s 15% Contingency is Reasonable and Consistent with Commission Precedent 45

VII. CONCLUSION ..............................................................................................................................47

ASP Reply Brief

Table Of Authorities

Page

iv

Statutes Cal. Pub. Resources Code § 21082.2. ............................................................................................21 Cal. Pub. Resources Code § 21082.2 (c) .......................................................................................27 Cal. Pub. Resources Code § 21168.5. ............................................................................................21 Cal. Pub. Util. Code § 1005.5(b) .................................................................................................. 44

Case Law Anderson First Coalition v. City of Anderson,

130 Cal.App.4th 1173, 1182 (2005) .........................................................................................26 City Brief, at 7-8 (citing Berkeley Keep Jets Over the Bay Comm. v. Board of Port Comms.,

91 Cal.App.4th 1344 (2001 ........................................................................................................23 Dry Creek Citizens Coalition v. County of Tulare,

70 Cal.App.4th 20, 26 (1999). ...................................................................................................31 Fullerton Joint Union High School Dist. v. State Bd. of Education,

32 Cal.3d 779, 797 (1982) .........................................................................................................25 Joshua Tree Downtown Bus. Alliance v. County of San Bernardino,

1 Cal.App.5th 677, 690 (2016) ...................................................................................................22 Mission Bay Alliance v. Office of Community Investment.,

6 Cal.App.5th 160, 186, FN 33 (2016) ......................................................................................32 North Coast Rivers Alliance v. Kawamura,

243 Cal.App.4th 647, 674-75 (2015) .........................................................................................27 North Coast Rivers Alliance v. Marin Municipal Water District Board of Directors,

216 Cal.App.4th 614, 626-27 (2013). .......................................................................................22 Perley v. Board of Supervisors,

137 Cal.App.3rd 424, 435-36 (1982) .........................................................................................27 South Orange County Wastewater Authority v. City of Dana Point,

196 Cal.App.4th 1604, 1614 (2011) ..........................................................................................26 Vineyard Area Citizens for Responsible Growth, Inc. v. City of Rancho Cordova,

40 Cal.4th 412, 435 (2007) ..................................................................................................22, 25

CPUC Decisions D.10-08-009 ...................................................................................................................................36 D.16-12.001 ...................................................................................................................................16 D.16-12-064 .................................................................................................................................4, 5

CPUC Rules of Practice and Procedure Rule 13.11 ....................................................................................................................................... 1

Other Authorities CEQA Guidelines § 15088 ............................................................................................................26 CEQA Guidelines § 15126(d)(2). ..................................................................................................42 CEQA Guidelines § 15126.4(a)(1)(B) ...........................................................................................31 CEQA Guidelines § 15126.6(a) .....................................................................................................42 CEQA Guidelines § 15384(a). .......................................................................................................21 CEQA Guidelines § 15151 ............................................................................................................31

v

LIST OF COMMONLY USED ACRONYMS AND ABBREVIATIONS

Amp Ampere

APM Applicant Proposed Measure

ASP Alberhill System Project

CAISO

CEQA

California Independent System Operator

California Environmental Quality Act (Pub. Resources Code § 21000 et. seq.

CEQA Guidelines Guidelines for the Implementation of the California Environmental Quality Act (Tit. 14, Cal. Code Regs. § 15000 et. seq.).

Commission California Public Utilities Commission

CPCN Certificate of Public Convenience and Necessity

CPUC California Public Utilities Commission

DEIR Draft Environmental Impact Report

DER Distributed Energy Resources

EIR Environmental Impact Report

EMF Electric and Magnetic Fields

ENA Electrical Needs Area

FEIR Final Environmental Impact Report

FMP Field Management Plan

kV Kilovolt

MM Mitigation Measure

MVA Megavolt-Ampere

MW

NERC

Megawatt

North American Electric Reliability Corporation

PFM Petition for Modification

vi

Project Alberhill System Project and Valley Ivyglen Project Combined

PTC Permit to Construct

PV Photovoltaic

SCE Southern California Edison Company

Scoping Memo

VSSP

Assigned Commissioner’s Scoping Memo (issued June 19, 2017)

Valley South Subtransmission Project

VIG

WECC

Valley-Ivyglen Project

Western Electricity Coordinating Council

vii

RECORD CITATION FORM

Record exhibits are cited according to the following formats:

• Citations to prepared written testimony are cited as: “[party] Exhibit [number]

[(witness)], at [page(s):line(s)]” as applicable.1

• Citations to the Final Environmental Impact Report for the Alberhill System

Project and the Valley Ivyglen Project are cited as “[DEIR], at [page(s)]” or

“[FEIR], at [page(s)]” as applicable.

• Citations to the Transcript of the October 17-19, 2017 evidentiary hearing

proceeding are cited as: “Transcript (Witness), at [page(s): line(s)].

• Citations to The Utilities Reform Network Opening Brief filed by The Utilities

Reform Network are cited as: “TURN Brief, at [page(s)]” as applicable.

• Citations to the Forest Residents Opposing New Transmission Lines Opening

Brief filed by the Forest Residents Opposing New Transmission Lines are cited

as: “FRONTLINES Brief, at [page(s)]” as applicable.

• Citations to the City of Lake Elsinore Opening Brief filed by the City of Lake

Elsinore are cited as: “City Brief, at [page(s)]” as applicable.

• Citations to the Office of Ratepayer Advocates Opening Brief filed by the Office

of Ratepayer Advocates are cited as: “ORA Brief, at [page(s)]” as applicable.

• Citations to the Castle & Cooke Opening Brief filed by Castle & Cooke are cited

as: “Castle & Cooke Brief, at [page(s)]” as applicable.

1 Exhibit numbers correspond to the numbers assigned by Administrative Law Judge Hallie Yacknin at

the evidentiary hearing held on October 17-19, 2017.

viii

• Citations to the Nevada Hydro Company Opening Brief filed by the Nevada

Hydro Company are cited as: “Nevada Hydro Brief, at [page(s)]” as applicable.

• Citations to Southern California Edison Company’s (U 338-E) Opening Brief

filed by SCE are cited as: “SCE Opening Brief, at [page(s)]” as applicable.

ix

SUMMARY OF RECOMMENDATIONS

Southern California Edison Company (“SCE”) hereby responds to the Forest Residents

Opposing New Transmission Lines Opening Brief (“FRONTLINES Brief”) filed by the Forest

Residents Opposing New Transmission Lines (“FRONTLINES”); The Utility Reform Network

Opening Brief (“TURN Brief) filed by The Utility Reform Network (“TURN”); The City of Lake

Elsinore Opening Brief (“City Brief”) filed by the City of Lake Elsinore (the “City”); the Office

of Ratepayer Advocates Opening Brief (“ORA Brief”) filed by the Office of Ratepayer

Advocates (“ORA”); the Castle & Cooke Opening Brief (“Castle & Cooke Brief”) filed by

Castle & Cooke; and The Nevada Hydro Company Opening Brief (“Nevada Hydro Brief”) filed

by the Nevada Hydro Company (“Nevada Hydro”). For brevity, FRONTLINES, TURN, the

City, ORA, Castle & Cooke and the Nevada Hydro are collectively referred to as “Intervenors”

and their briefs are collectively referred to as “Intervenors’ Briefs” throughout this Summary of

Recommendations and Reply Brief.

The Intervenors2 oppose SCE’s applications for California Public Utilities Commission

(“CPUC” or “Commission”) approval of a Permit to Construct (“PTC”) the Valley-Ivyglen 115

kV Subtransmission Line Project (“VIG” or VIG Project”) and a Certificate of Public

Convenience and Necessity (“CPCN”) for the Alberhill System Project (“ASP”) (collectively,

the VIG Project and the ASP are referred to as the “Project”). The Intervenors’ arguments;

however, are belied by the law and the facts. Instead of recognizing that multiple electrical

needs support the need for the Project, the opposing Intervenors put forth arguments based on

invalid readings of SCE’s planning methodology and rely on inapplicable and false assumptions

to argue that the Project is not needed. The Intervenors also fail to recognize that the Final

Environmental Impact Report (“FEIR”) for the Project contained a comprehensive analysis of

the need for the Project and the environmental impacts associated with the Project, and ignore

2 While this Reply Brief generally replies to most of the Intervenors’ arguments, it should be noted that

Nevada Hydro does not oppose the Project, and the City of Lake Elsinore’s Opening Brief is primarily concerned with CEQA arguments, rather than Project need arguments.

x

evidence that the CPUC appropriately studied all potential Project impacts and feasible

alternatives. Despite the fact that for several years now the CPUC and its consultants have

continually collected data regarding the Project to completely study electrical needs and Project

impacts and SCE has consistently attempted to provide relevant information responsive to the

CPUC requests at every turn, the Intervenors simply argue that the well-established planning

methodology used by SCE and the CPUC’s consultant is wrong and that other agency planning

methodologies should be used instead. None of the Intervenors’ contentions has merit.

Pursuant to Rule 13.11 of the CPUC’s Rules of Practice and Procedure, SCE provides the

following summary of its responses to these points, as the responses are further developed

throughout the balance of this Reply Brief:

1. The completed Project would provide a number of benefits related to enhancing

SCE’s ability to provide reliable power to portions of the City of Lake Elsinore, Canyon Lake,

Wildomar, Murrieta and unincorporated areas of southwestern Riverside County, and each

benefit would, collectively and individually, outweigh any potentially significant environmental

impacts.

2. The FEIR prepared by CPUC staff and its consultants should be certified as it

includes detailed analyses for each environmental impact area identified in California

Environmental Quality Act (“CEQA”) Guidelines Appendix G, and substantial evidence

supports the FEIR’s conclusions regarding whether or not each impact would be significant. In

addition, the FEIR analyzes a reasonable range of alternatives and a number of alternatives that

are rejected for a wide variety of reasons, and identifies the Project as the environmentally

superior alternative.

3. Overriding considerations, in the form of addressing multiple electrical system

needs, support approval of a PTC for the VIG Project and a CPCN for the ASP. SCE planning

criteria demonstrate the crucial need for a new subtransmission line to avoid disruptions to

customers in the Electrical Needs Area for multiple reasons. SCE planning criteria also

demonstrate the urgency for a new substation and additional transformer capacity.

xi

4. The Commission should find that SCE’s proposed estimated costs to construct the

ASP are reasonable. The Intervenors have presented insufficient evidence as to why SCE’s costs

are not reasonable and SCE has provided a wealth of information to support its cost estimates.

For the foregoing reasons, SCE respectfully requests the CPUC to reject the requests and

arguments set forth in the Intervenors’ Briefs, and instead issue a decision granting the relief

requested in SCE’s PTC Application, CPCN Application, and the SCE Opening Brief.

1


STATE OF CALIFORNIA


A.07-01-031, et al.


And Related Matter.

A.07-04-028


A.09-09-022


SOUTHERN CALIFORNIA EDISON COMPANY’S (U 338-E) REPLY BRIEF

I.

INTRODUCTION

Pursuant to Rule 13.11 of the Rules of Practice and Procedure of the California Public

Utilities Commission (“CPUC” or “Commission”), and the Administrative Law Judge’s ruling at

the October 17-19, 2017 evidentiary hearings, Southern California Edison Company (“SCE”)

respectfully provides this Reply Brief in support of its Application for a Permit to Construct

(“PTC”)3 the Valley-Ivyglen 115 kV Subtransmission Line Project (“VIG” or “VIG Project”)

3 SCE filed a PTC Application for the VIG Project on January 16, 2007, which was granted on August

12, 2010. Subsequent to that approval, SCE determined certain route modifications are necessary, requiring SCE to file a Petition for Modification on April 2, 2013. Throughout this brief, references to the VIG PTC are intended to apply to SCE’s PTC Application, as subsequently modified by SCE’s request for a PFM for the VIG Project.

2

and its Application for a Certificate of Public Convenience and Necessity (“CPCN”) for the

Alberhill System Project (“ASP”) (collectively referred to as the “Project”). SCE submits this

Reply Brief in response to the six Opening Briefs filed by the Intervenors in this proceeding: 1)

The Utility Reform Network Opening Brief (“TURN Brief”); 2) the Forest Residents Opposing

New Transmission Lines Opening Brief (“FRONTLINES Brief”); 3) the Office of Ratepayer

Advocates Opening Brief (“ORA Brief”); 4) the City of Lake Elsinore Opening Brief (“City

Brief”); 5) the Castle & Cooke Opening Brief (“Castle & Cooke Brief”); and 6) the Nevada

Hydro Company Opening Brief (“Nevada Hydro Brief”).4

Rather than focus on whether substantial evidence supports approval of the Project, the

opposing Intervenors Briefs’ rely on misstatements of law, distortions of fact, half-truths and

unsubstantiated assumptions that are belied by real data. For example, their challenge to SCE’s

electrical needs analysis and planning methodologies should be rejected because the opposing

Intervenors misapply SCE planning criteria and make uninformed and factually incorrect

statements regarding the operation of SCE’s electrical system. In contrast, SCE’s forecasting

methodologies and assessment of potential problems in the Electrical Needs Area (“ENA”) are

supported by substantial evidence and have been independently verified by California Public

Utilities Commission (“CPUC” or “Commission”) consultants.

The Intervenors similarly fail in challenging the Final Environmental Impact Report

(“FEIR”) prepared for the Project. While the allegations against the FEIR make clear that the

Intervenors disagree with the FEIR’s conclusions, their arguments are either largely unsupported

by any citation to substantial evidence in the record, or they simply re-state objections the

Commission has substantively addressed in its responses to comments on the DEIR. In contrast,

the Commission’s conclusions are clearly based on substantial evidence in the administrative

4 While for purposes of simplicity, TURN, FRONTLINES, ORA, the City of Lake Elsinore, Castle &

Cooke, and the Nevada Hydro Company are collectively referred to as “Intervenors” and their opening briefs are collectively referred to as “Intervenors’ Briefs” throughout the balance of this Reply Brief, it should be noted that Nevada Hydro does not oppose the Project, and the City of Lake Elsinore’s arguments are primarily focused on CEQA, rather than “need” concerns.

3

record. Finally, the Intervenors’ arguments do not meaningfully undercut or render inadequate

the FEIR’s good-faith efforts at full disclosure, which broadly satisfies CEQA’s statutory goal of

informed decision-making.

For all these reasons, SCE respectfully requests that the CPUC grant the PTC, the CPCN

and certify the FEIR.

II.

THE INTERVENORS’ ASSERTIONS THAT CAISO’S FORECAST, RATHER THAN

SCE’S FORECAST, SHOULD BE USED ARE BASED ON FUNDAMENTALLY

FLAWED ASSUMPTIONS AND SHOULD BE REJECTED

The Intervenors (particularly with respect to FRONTLINES and TURN) contend that the

California Independent System Operator’s (“CAISO”) planning methodologies and forecast

assumptions should be used instead of relying on the expertise of SCE’s own planners and their

decades of experience planning SCE’s radial distribution systems5. They are wrong. As

explained in expert testimony and during the evidentiary hearings, portions of SCE’s electrical

system are unique and independent from those electrical systems under the jurisdiction of the

CAISO.

Within the CAISO Balancing Authority Area (“BAA”), the majority of subtransmission

facilities of Pacific Gas & Electric (“PG&E”) and San Diego Gas & Electric (“SDG&E”) are

placed under CAISO control, while the majority of SCE’s subtransmission facilities are under

SCE control. (TURN Exhibit 1 (Jenkins), at 10:20-24.) This is because the CAISO-controlled

grid includes those lower-voltage networked distribution facilities which operate electrically in

parallel with its transmission facilities. (Transcript (McCabe), at 170:19-28.) By contrast, SCE’s

5 SCE’s Valley 115kV Systems are radial distribution systems and were determined by FERC to be

used in local distribution of electric energy. Thus, they are not classified as part of the Bulk electric System and not subject to CAISO’s jurisdiction. (See 153 FERC ¶ 61,384, Order On Local Distribution Determination (December 31, 2015) (available at https://www.ferc.gov/CalendarFiles/20151231135800-RC15-1-000.pdf).)

4

radial distribution systems are radial from the transmission system at a single point, and

consequentially, all the electrical demand that those radial systems serve passes through a single

point in the transmission grid. (Id.) This distinction means there are inherent differences in the

planning for network systems, such as those controlled by CAISO, and radial systems, such as

those controlled by SCE. (Id., at 170:28-171:3.) Accordingly, the 500 kV components that

connect SCE’s Valley Substation to the region’s bulk electrical grid are managed by CAISO,

while the 115 kV components of Valley Substation and the Valley South 115 kV System are not

managed by CAISO or deemed part of the region’s bulk electric grid, but are rather subject only

to SCE’s Transmission Planning Criteria and Guidelines. (FEIR, at 1-6.) As with Valley

Substation, the ASP will similarly be subject to SCE’s Transmission Planning Criteria and

Guidelines.

Despite this clear evidence to the contrary, FRONTLINES, TURN and ORA continue to

insist that CAISO’s forecast methodology, rather than SCE’s forecast methodology, should be

used to assess the need for the Project, irrespective of the fact that the CAISO forecast is not

intended for use in planning local-area radial distribution systems. In support of its arguments,

FRONTLINES cites Proceeding A.12-05-020, which was a decision addressing whether

SDG&E’s South Orange County Reliability Enhancement Project (“SOCRE Project”) should be

approved. FRONTLINES argues that in the SOCRE proceeding, the CPUC established a

reliance on CAISO’s load projections (as opposed to SDG&E’s projections) to determine

whether the SOCRE project was needed to serve a radially configured subtransmission system

(e.g., radial distribution system). (FRONTLINES Brief, at 3.)

In making its determination, the Commission agreed with SDG&E and CAISO that the

South Orange County loop is not a “radially configured system” as defined by CAISO, but rather

part of a networked bulk electric system which is under CAISO control and thus subject to

NERC planning standards. (D.16.12-064 at 34.) Accordingly, the Commission approved the

project because while peak demand projections may not have materialized, the project was still

5

needed to satisfy NERC, WECC, and CAISO standards.6

Unlike SOCRE, however, SCE’s Valley South System is a “radially configured system”

and is recognized by the CAISO as such. Indeed, CAISO explicitly notes in its Board of

Governors Memorandum recommending approval of ASP that:

SCE plans for infrastructure upgrades under its own operational jurisdiction (i.e., Valley 115kV 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.

(FRONTLINES Exhibit 1 (Ayer), at Exhibit 18, emphasis added.)

Because the Valley South System is a radial system, SCE planning standards, and not

CAISO planning standards, are applied. When planning for electrical systems which are radial

from the CAISO-controlled bulk electric system, planning standards that rely on local-area

knowledge of load growth and non-coincident peak demand loading values (both historical and

projected) are the appropriate planning standards to use. (Transcript (McCabe), at 18:16-20.)

Accordingly, the SOCRE decision is inapplicable here, as the SOCRE Project and the ASP are

not equivalent projects and different planning standards and approvals apply.7

6 While it is true that in the SOCRE proceeding the CPUC determined no project was necessary to

accommodate the projected load growth over the ten year forecast period, and that the CPUC made that determination based on CAISO’s load projections, the CPUC ultimately approved the SOCRE project because there was a need for the project in order for SDG&E to meet NERC, WECC, and CAISO standards. (D.16-12-064 at 35.)

7 The Intervenors also misinterpret the approval process SCE needs from CAISO. Although the ASP would be a radial, non-networked system and not controlled by the CAISO, it would be served from the CAISO-controlled 500 kV transmission system. Accordingly, SCE obtained CAISO approval for ASP in 2010. (FRONTLINES Exhibit 1 (Ayer) at Exhibit 18) To this date, no further review has been requested, or required by the CAISO.

6

III.

SUBSTANTIAL EVIDENCE DEMONSTRATES THAT THE PROJECT WOULD

REMEDY MULTIPLE ELECTRICAL SYSTEM NEEDS TO PROVIDE OVERRIDING

CONSIDERATIONS SUPPORTING APPROVAL OF THE PROJECT

Overriding considerations support approval of a PTC for the VIG Project and a CPCN for

the ASP because, as explained in expert testimony and in the FEIR, the Project would provide a

number of electrical capacity and voltage benefits to portions of the City of Lake Elsinore and

the surrounding areas, including portions of southwestern Riverside County, which would enable

SCE to avoid unacceptable system conditions. In addition, SCE’s forecast data has been

confirmed by the CPUC’s independent electrical consultant and the Intervenors’ critiques of that

data are unfounded.

A. SCE Forecasts of Electrical Demand are in Accordance with Prudent Planning

Principles, Including the Adjustments SCE Makes to Raw Data in Order to

Accurately Represent the Capabilities and Needs of the System

An ongoing theme in TURN’s and FRONTLINES’ arguments is that SCE over-predicts

peak demand and improperly relies on adjusted, rather than raw data in its forecasting. However,

these Intervenors’ arguments are flawed, as some simply misrepresent actual facts, some are

based on inapposite and/or incorrect information, some misinterpret data trends and some are

based on speculative assumptions without any supporting technical data.

For example, FRONTLINES argues that SCE should use “raw” data in Megawatts

(“MWs”) to determine the need for the Project. As support for its argument, FRONTLINES

compares raw backward-looking data in MW to projected 1-in-5 year heat storm values in

megavolt-amperes (“MVA”). In doing so, it should be expected that there would be large

variations between the two unrelated values for most years, and to expect a close correlation

between the two demonstrates a flawed understanding by FRONTLINES of utility system

7

planning. As has been stated extensively in expert testimony, a comparison of raw data to

projected data does not result in an “apples to apples” comparison (and notably when the

projected values represent demand values under 1-in-5 year extreme weather conditions).

Accordingly, it is common industry practice to adjust actual “raw” data for weather and other

variables and then compare that to projected data. (Transcript (McCabe), at 128:25-129:9).

Indeed, SCE adjusts and weather normalizes peak load data as part of its forecasting

methodology, not to manipulate information as the Intervenors imply, but rather to present a

representative peak load value based on temperature trends to ensure a consistent baseline from

which to produce a forecast. This approach tempers the effects of an anomalous year where the

peak temperature might have been wildly inconsistent with normal years. (SCE Exhibit 2

(McCabe), at 12:15-13:10.)

As evidence in support of its argument, FRONTLINES provides a chart in its opening

brief which purportedly compares “raw” peak demand versus SCE forecast peak demand.

(FRONTLINES Brief, at 18.) This table, however, conflates “raw” data in MW and projected 1-

in-5 year heat storm data in MVA and ignores such variables as power factor; data-capture

errors; abnormal system configurations; load imbalance between phases; as well as the fact that

the values FRONTLINES has provided may not have even occurred on the same day as the peak

demand day SCE selected for that particular year.8 (Transcript (McCabe), at 57:14-19.)

Moreover, this chart misrepresents SCE’s use of “unity power factor” for planning purposes.9

Peak demand values recorded in amperes by definition already incorporate power factor because

8 Indeed, through data requests, FRONTLINES requested that SCE provide it the highest annual value,

but not the value on the peak day selected by SCE (which had to meet certain criteria to be considered).

9 Power factor is the ratio of MW to MVA. Unity power factor is when the ratio is 1.0 or when MW (power to serve “real” or resistive loads like lightening) equals MVA (total power requirements needed to serve both “real” power loads and “reactive” power loads (such as motors). When unity power from the transmission system is achieved, it means that all of the power delivered from the transmission system is delivered to serve “real” power loads and any requirements to serve “reactive” power loads is provided locally through reactive compensation devices such as capacitors. (SCE Exhibit 2 (McCabe), at 7, footnote 3.)

8

they represent the total energy required to serve customer demand, both in real power (MW) for

typical resistive loads and reactive power (MVAR) for inductive motor loads, and through the

use of peak demand measured in amperes, there is no need to further account for power factor.

These ampere values when calculated with nominal system voltage (e.g., 115 kV) result in the

total power in MVA.10 As such, SCE’s use of assumed unity power factor is for simplicity in

planning purposes and is specifically for the purpose of taking the data provided by CAISO to

SCE for system-wide and specific sub-region coincident forecasts and then disaggregating it

amongst all of SCE’s radial distribution systems.11 (Transcript (McCabe), at 151:23-26.) In

turn, these values are then provided back to the CAISO for its use in performing bulk electric

system transmission planning assessments (Transcript (McCabe), at 184:3-23.), but not for local-

area radial distribution system capacity requirements. SCE strives to provide unity power factor

at each radial distribution system that interfaces with the CAISO-controlled transmission system

typically through the installation and use of capacitors (which are reactive compensation

devices). (SCE Exhibit 2 (McCabe), at 7:19-21.) SCE has presented testimony and evidence

that local areas served by radial distribution systems within its electrical service territory are

unique, experience their own peak demand periods, have various compositions of electrical load,

and experience a wide range of local weather conditions. (SCE Exhibit 2 (McCabe), at 15:21-

27.) SCE plans for unity power factor at peak demand of each of its radial distribution systems

based on specific parameters described above that are associated with that local area. (SCE

Exhibit 2 (McCabe), at 7:19-21) SCE reasonably assumes that, when these non-coincident local-

area peak demand values are adjusted to be coincident with the CAISO forecast, that unity power

factor is maintained or as reasonably close as possible.

10 MVA = √3 X amperes X kilovolts.

11 The validation of actual power factor for broad planning purposes is complex as there is no single point in which to measure a broad-based system-wide power factor, rather it is based on the best efforts to maintain unity power factor at each discrete local-area system. (SCE Exhibit 2 (McCabe), at 7:17-22.)

9

Many, if not all, radial distribution systems peak at a time that is non-coincident with the

CAISO provided peak value. (SCE Exhibit 2 (McCabe), at 5:23-24; Id., at 6:1-3) The sum of

the disaggregated values coincident to the CAISO provided peak that SCE provides back to the

CAISO, must be equal to the original CAISO provided peak value, therefore for simplicity and

consistency, SCE reasonably assumes unity power factor when providing these values. (Id. at

191:5-13.) While this approach is reasonable for broad transmission system planning activities

performed by the CAISO, the unity power factor assumption is not appropriate when planning

for the local-area capacity requirements for radial systems, especially when the actual power

factor can be obtained for a discrete local-area system unlike that of a larger broad-based system.

(SCE Exhibit 2 (McCabe), at 7:17-8:2.) Whereas the CAISO is planning for transmission

systems (up at the highest voltage levels of the system and those lower voltage systems operating

in parallel with it), SCE is planning for local-area radial distribution systems (down at the lower

voltage levels of the system) and use of actual power factor (incorporated through the use of

peak load readings in amperes as described above) is appropriate and necessary. These planning

approaches are necessarily different to account for such things as changes in the weather,

geographical environment, or economic differences that may be present from one planning area

to the next. While these areas in SCE’s service territory are ultimately served by the CAISO-

controlled transmission system, they are locally served by different SCE radial distribution

systems. The focus on an area’s local electrical needs, based on its diversity from an adjacent

system, would be lost using a coincident forecast derived from a higher-level CAISO forecast.

(SCE Exhibit 2 (McCabe), at 5:1-6:24.)

The table provided by FRONTLINES is further flawed in that it compares raw,

unadjusted data to projected 1-in-5 year heat storm values, doing so without reference to

adjustments necessary to reflect temperature and without a reference to temperature there is no

meaningful comparison to be made. Even assuming any of the peak demand days were on a day

within an average peak temperature day, these demand values would be wrong by approximately

10

8%12 as compared to those expected on a 1-in-5 heat storm day. To illustrate how greatly

exaggerated FRONTLINES table is, the following table shows the comparison of an

appropriately adjusted 1-in-5 year heat storm value against the projected 1-in-5 year heat storm

value and gives the actual “% difference” values that FRONTLINES fails to account for:

A B C D E F

Year Actual (“raw”) Peak Demand [Ex. FRONT-4]

(MW)

Adjusted Peak Demand: Normal Weather

(MVA)*13

Adjusted Peak Demand: 1-in-5 Heat Storm

Weather (MVA)

SCE Forecast Peak Demand

[Ex. FRONT-3]: 1-in-5 Heat

Storm Weather (MVA)

% Difference Between

Adjusted 1-in-5 and Projected 1-in-5 (Column E

divided by Column D)

2007 888 944 1004 1038 3.4%

2008 768 817 869 1062 22.2%

2009 812 867 922 1057 14.5%

2010 880 921 980 968 -1.3%

2011 875 934 994 1014 2.0%

2012 873 923 982 1027 4.6%

2013 873 960 1033 1020 -1.3%

2014 915 951 1023 1055 3.1%

2015 865 940 1011 1045 3.4%

2016 899 995 1071 1022 -4.5%

*Calculated from high-phase Amps recorded value which properly accounts for power factor and any imbalance which may exist between the three phases.

12 SCE’s 1-in-5 year heat storm is 4 degrees Fahrenheit hotter than an average peak temperature day and

the expected change in peak demand loading is 1.9% per degree change in temperature (4°F times 1.9% per °F = 7.6%).

13 Columns C and D are produced directly from TURN Exhibit 1 (Jenkins), at Attachment A.)

11

As can be calculated from this table, the appropriate average “% difference” over the 10-

year period (2007-2016) is 4.6%, demonstrating that SCE’s recorded (and appropriately

adjusted) 1-in-5 year heat storm peak demand values have fallen both above and below its

projected 1-in-5 year heat storm peak demand values, as would be expected for any forecast.

Even with the two outlier years of 2008 and 2009 when there was a major economic downturn

and SCE’s forecasts were much higher than what occurred, the average over the ten years has

remained within +/-5%. Thus, FRONTLINES assertion that “SCE’s forecast has not been

‘reasonably close’” and that it has always been “off” by at least 10% is incorrect.

Similar errors are contained in TURN’s Opening Brief. TURN points to SCE’s provided

coincident factor of 0.96 for Valley South, and notes that while this should result in only a 4%

difference from the CAISO coincident peak forecast, SCE’s forecasted load profile for Valley

South is much higher than 4%. (TURN Brief, at 26.) While TURN makes this statement

without providing any evidence of the values they are comparing, it should be noted that SCE

forecast values for peak loading are 1-in-5 year heat storm values, while CAISO’s are 1-in 10

year heat storm values. (SCE Exhibit 2 (McCabe), at 7:9-16.) The two forecasts are based on

different extreme weather conditions, and the CAISO forecast has the assumption of unity power

factor, whereas SCE’s forecast does not. (Id.) Accordingly, TURN’s assumption that because of

the 4% coincidence difference there should be only a 4% difference in forecast values is

fundamentally flawed because the data cannot be compared for the reasons stated above.

In assessing the evidence, the Commission must make a determination of whether SCE

has sufficiently demonstrated that its planning methodology is sound and is based on prudent

planning principles. SCE has presented expert testimony on the issues by professional electrical

engineers with training and experience in their fields. SCE’s system planning witness performed

appropriate substation capacity planning and power flow analyses on the existing system, the

Project as proposed, and alternatives that were identified in advance of testimony being served.

By contrast, Intervenors rely upon speculation, proffering various proposals without any

analytical support. TURN’s witness, Mr. Jenkins, who could have performed system analysis

12

including power flow studies, did not do so. (Transcript (Jenkins), at 275:19-27.) As SCE has

testified, radial distribution systems commonly peak at times that are different or non-coincident

with that of the larger overall system peak. Even Mr. Jenkins acknowledged this (Id., at 276:5-

10.) Mr. Jenkins also confirmed SCE’s witness’ testimony (Id., at 177:1-4) that individual

electrical facilities should be planned for based on the highest loading values those facilities

would be expected to experience, even if the time of that peak loading was different (i.e., non-

coincident) than that of the other facilities in the area. (Id., at 280:7-15) The other Intervenors

have also not provided any evidence to show they have performed any system planning or power

flow studies to substantiate their claims. Accordingly, because the Intervenors have provided no

evidence to support their proposals and claims, the Intervenors’ meritless challenges to SCE’s

forecasting techniques should be rejected.

B. SCEs Forecast Allocates Proper Weight to Local Energy Resources Such as

Distributed Generation, Energy Efficiency and Demand Response

The opposing Intervenors also argue that SCE’s forecast adjustments inflate the historic

peak demand data by adding back in load that may have been met through energy resources such

as demand response and “non-dependable” generation. SCE’s considers “dependable”

generation for planning purposes as the reasonably expected output amount of a generation

source that is on-line at least 90% of the on-peak demand hours over the period of years

prescribed by the designation of the generator as being “dispatchable or non-dispatchable”14

during the months of July, August, and September. Any generation that does not meet this

criteria is considered “non-dependable” and is not considered reliable by SCE for use in its

planning activities. (SCE Exhibit 2 (McCabe), at FN 5.)

14 Dispatchable generation is under contractual and/or operational control of SCE, while non-

dispatchable generation is not. For non-dispatchable generation, SCE planning activities include acquiring five years of output before the power production of a non-dispatchable generator may be considered reliable for planning purposes.

13

In order to determine what is “dependable” versus “non-dependable” generation, SCE

installs communication equipment and telemetry devices on all generation sources that are 1

MW or greater. (Transcript (McCabe), at 195:3-4) This allows SCE to monitor the generation

facility and provides a “track record” of power output. (Transcript (McCabe), at 196:18-19).

Facilities of this size or greater are those that must meet SCE’s definition of “dependability” to

be considered for inclusion in planning activities. Generation sources smaller than 1 MW, which

are mostly comprised of solar photovoltaic (“PV”) installations (the bulk of which are residential

rooftop solar), do not have the telemetry equipment (as most are “behind the meter” resources)

and thus SCE does not have the visibility to real-time data regarding the operations and output of

the facilities. (Transcript (McCabe), 197:13-20.)

This fact, and because the bulk of the installations are residential rooftop solar PV, SCE

uses “solar output curves” (developed using SCE smart meter data consistent with common

industry practice) to determine a percentage of maximum output of the installation based on any

particular hour of the day. (Transcript (McCabe), at 71:5-10.) For instance, at 12:00 p.m.

(approximately the time of peak solar output), a solar PV facility may be producing at its

maximum output or close to 100% of what it is rated for. However, at 5:00 p.m. (or the

approximate time of the electrical system peak in the area in this example) when the sun is

setting, the output of the same solar PV installation will only be a small fraction of its maximum

output. (Id., at 71:18-22.) To determine how much of the output of installed solar PV in an area

is dependable for peak demand planning purposes, SCE uses the solar output curve that is

applicable for that planning region and then takes the total installed capacity of solar PV in the

area (of installations smaller than 1 MW) and multiplies it by the percentage output that occurs at

the time of the electrical system peak. (Transcript (McCabe), at 71:10-15) For the Valley South

System, the procedure described above results in approximately 10% of the installed maximum

solar PV output to be considered dependable for peak demand planning purposes. (Transcript

(McCabe), at 71:18-22)

14

Contrary to the Intervenors’ assertions, for facilities smaller than 1 MW (the vast

majority of installed or planned for distributed energy resources), SCE does not require five

years of output data prior to reviewing and considering a generation resource as dependable for

planning purposes. SCE clearly states that the five years of output for determining

“dependability” is applicable to larger generators (greater than 1 MW) and not to smaller

distributed energy resources. (Transcript (McCabe), at 197:7-9)

In addition, there are also very valid reasons why other peak demand and load growth

offsets such as energy storage and demand response have not historically been included by SCE

in its local-area forecast development. For example, energy storage is a relatively emerging

technology that historically has not been prevalent in SCE’s system, and there have been few

examples of installations to demonstrate its impact on a consistent and reliable basis. Similarly,

demand response has historically not been considered a reliable resource for local-area planning

activities, as many of these programs employ trigger mechanisms for their use that are mostly

based on broader system-level events or market-based pricing signals. (FEIR Appendix L,

Responses to Comments, at 33-34.) Additionally, as the demand response programs are

incentive based, many of them can be opted out of based on customer behavior and choice. Most

often these demand reduction programs are not implemented for smaller, local-area electrical

system needs and generally have restrictions, such as limits on frequency and/or duration of use,

such as how many times or for how many hours the program can be implemented on an annual

or monthly basis. (Id.)

Once a starting point for a 10-year forecast is developed, SCE projects future annual peak

demand values, by taking the starting point year and adding to it expected changes in peak

demand for the next year. (SCE Exhibit 2 (McCabe), at 13:19-21.) These changes may be

increases or decreases, and account for factors such as: load growth, transfers of load between

systems, distributed energy resources (“DERs”), plug-in electric vehicles, and energy efficiency

(“EE”) measures. (FRONTLINES Hearing Exhibit 15, at 30:14-19.) The sum of these values is

the net growth from the one year to the next. This process is part of SCE’s development of its

15

planning forecast. (SCE Exhibit 2 (McCabe), at 13:25-14:3.) When it is identified that

appropriately derived projected loading values would exceed available capacity, a project is

proposed.

The evidence in the record demonstrates that SCE’s forecasting methodology

incorporates a variety of real-world and real-time assumptions that constitute substantial

evidence. Moreover, despite annual adjustments to SCE’s forecasts and the associated Project

need date, these adjustments are merely examples of prudent planning activities and evidence of

SCE recognizing the appropriate changes in electrical demand that occur, and are expected to

occur, based on historical data in addition to forward-looking data. In more than a decade of

Project development and licensing activity, there has never been a time when the forecast has

demonstrated that the Project was not needed within the applicable 10-year planning horizon to

that forecast. (SCE Exhibit 1 (McCabe), at 11:15-18.) Any forecast must use the best

information available at the time and project development must adhere to the principles which

are necessary to achieve the appropriate outcome. SCE has done this year after year. It is long

established under CEQA that forecast development is not a perfect science15 and that the

expected outcome is not to be exact, but rather to reflect as accurately as possible the expected

values and to plan accordingly to address any system needs that result.

C. Contrary to the Intervenors’ Assertions, the ASP is Needed to Develop System Tie-

Lines

Based on the above methodology, SCE proposed the ASP because it satisfies the near and

long-term electrical needs of the area by providing additional transformer capacity and

redistributing the existing electrical demand between the Valley South System and the new

Alberhill System. (SCE Exhibit 1 (McCabe), at 10:12-14) In doing so, there would be a

sufficient capacity margin available in both systems to serve existing electrical demand,

15 See CEQA Guidelines, §15144.

16

accommodate future growth, and to allow for better system response to unplanned outages and

planned maintenance or construction activities. (SCE Exhibit 1 (McCabe), at 10:15-17.)

Additionally, reliability and operational flexibility would be improved through the creation of

115 kV system tie-lines between the two systems allowing the ability to transfer substations from

one to another to address unplanned and planned outages. (Id.) The construction of a second

500/115 kV system and tie-lines makes the Valley South System no longer isolated and islanded

from the rest of SCE’s electrical system, which would improve long-term electrical service for

this area. (Id., at 14:4-7.)

Despite the clear evidence in the record to the contrary, the Intervenors’ argue that SCE

should have developed these system tie-lines back in 2004 when the Valley System was split.

(FRONTLINES Brief, at 28.) However, when SCE split the Valley System in 2004, it

recognized that a long-term solution was needed for the electrical needs of the area which would

need to include both the addition of transformer capacity and also the need for creating system

tie-lines. The development and proposal of the ASP was this long-term solution. While the

licensing process has taken longer than anticipated, the ASP addresses the needs for system tie-

lines, but in the prudent and responsible manner of incorporating that system need with that of

other system needs to ensure a comprehensive system-wide solution was developed.

D. Power Flow Analyses Incorporating the Valley South Subtransmission Project Have

Demonstrated that the VIG Project is Needed Irrespective of Whether VSSP is

Constructed

The Intervenors argue that SCE and the FEIR fail to divulge that the power flow studies

used to support the VIG Project do not incorporate the Valley South Subtransmission Project

(“VSSP”), another SCE project approved by the CPUC in 2016 (See D.16-12.001). The VIG

Project need date precedes the need date of the VSSP by many years. Accordingly, power flow

studies, specifically in support of the VIG Project, would not include a project with an expected

operational date many years in the future. However, SCE does study the electrical system

17

annually under N-1 conditions for each year of the 10-year planning horizon. (SCE Exhibit 2

(McCabe), at 14:10-12.) In the year of the anticipated completion of the VSSP, it was assumed

that the VIG Project would have also been completed a few years earlier. The Intervenors

mischaracterize that SCE did not perform power studies with the completion of the VSSP to see

if the VIG Project would still be needed. (Transcript (McCabe), at 133:21-23.) At the

evidentiary hearings, what SCE witness Mr. McCabe stated was that there were no specific

studies done to evaluate the system had the VIG Project not been approved or constructed.

(Transcript (McCabe), at 135:3-5) However, Mr. McCabe clearly stated that SCE did evaluate a

virtually identical scenario where VSSP is in-service and there is an outage of the Valley-Ivyglen

115 kV line, which would be equivalent to if it had not been constructed. (Transcript (McCabe),

at 135:17-28.) In addition, as part of SCE’s N-1 studies, each and every line segment is taken

out of service, one at a time, and a power flow study done to assess system performance.

(Transcript (McCabe), at 135:22-28.) These N-1 scenarios are comprehensive and cover all 115

kV line outages, including the Valley-Ivyglen 115 kV Line.

The Intervenors appear to believe that the construction of the VSSP would have some

material impact to the need for the VIG Project. One of the three reasons the VIG Project is

needed is to provide a second source line to Ivyglen Substation (FEIR, at 1-3.) However, the

area to be served by the VSSP is located more than 30 miles away from Ivyglen Substation, and

would have absolutely no impact on addressing this identified need. (Transcript (McCabe), at

134:20-23) Regarding the other two VIG Project objectives (serve projected electrical demand

requirements in the ENA and to improve operational and maintenance flexibility) (FEIR, at 1-

10), power flow analyses were performed by SCE and those power flows supported the need for

the VIG Project, irrespective of whether VSSP was completed. (Transcript (McCabe), at 134:23-

26)

Despite the Intervenors assertions to the contrary, anytime a new source line is added into

an electrical area, there will be impacts on the loading of the other lines as the added route of

power flow will cause power to be split in a different manner than it was prior to the new line.

18

This is due to the change in the overall characteristics of the subtransmission system (e.g.,

impedances of the lines) that serve the area and how those changes affect the power flow.

(Transcript (McCabe), at 132:17-26.) However, it is impossible to precisely predict the change

in power flows merely by inspection or by simple addition and subtraction. Rather, power flow

studies are required, and how the power gets delivered through the lines is based on the

characteristics of those lines and of the loads being served. (Id.) FRONTLINES, in particular,

seems to assert that upon an outage of a single line removing 217 MVA of capacity, there would

still be 1,234 MVA of capacity, which, they argue, is plenty to serve the peak demand of the

system. (Transcript (McCabe), at 132:10-16.) FRONTLINES makes this determination merely

by comparing the total loads served by the Valley South System against the capacity of the

remaining in-service 115 kV lines and then states there is no capacity need. (FRONTLINES

Brief, at 47) However, it has been well established in expert testimony that power flow studies

are required to assess system performance and loading on the lines. SCE regularly performs

these studies, and each one supports the need of the VIG Project, the ASP, and the VSSP

independently. (Transcript (McCabe), at 229:26-230:2.)

IV.

THE INTERVENORS CONTINUE TO RAISE ALTERNATIVES THAT WERE

ADDRESSED AND DISMISSED IN THE FEIR

A continuing theme of the Intervenors is that other alternatives, in particular, shifting

load from one system to another, or the installation of an additional transformer, would be

sufficient to eliminate the need for the Project. These arguments, however, have been repeatedly

rejected in both the DEIR and the FEIR. Because there is sufficient evidence in the record to

refute these alternatives, the Intervenors’ meritless challenges should be rejected.

19

A. Shifting Demand from One Substation to Another Substation does not Meet the

Project Objectives and was Accordingly Eliminated in the FEIR

The Intervenors continue to assert that the Valley North, Valley South, and Vista Systems

are geographically enmeshed such that each system can simply accommodate load from other

systems. (FRONTLINES Brief, at 33.) FRONTLINES, in particular, contends that SCE can

transfer the Sun City and Newcomb Substations to the Valley North System, and that doing so

will simply require the construction of less than 10 miles of new 115-kV subtransmission line.

(Id.) This alternative, however, was already considered and dismissed in the EIR. Specifically,

the DEIR’s Alternatives Screening Report addressed “Alternative F”, which would transfer

electrical demand from two 115/12-kV substations (Newcomb and Sun City) served by the

Valley South System to the Valley North System. (DEIR, Appendix D, Alternatives Screening

Report at 37.) The Report concluded that this Alternative should be eliminated because it

“would not meet the project objectives or reduce a significant effect of the proposed Alberhill

Project. (Id. at 39.)

Further, the DEIR concluded that under this alternative, while construction of the

proposed Alberhill Substation and several miles of new 500 kV transmission lines would be

delayed, it is still expected that a project similar to the ASP would still need to be constructed

prior to the end of the planning period in 2023. (Id. at 38.) In addition, the FEIR concluded that

while construction and operation under this alternative would result in similar environmental

effects as the Project, additional effects on air quality would occur because of fugitive dust and

vehicle and equipment emissions from construction of the additional miles of 115 kV

subtransmission lines. (Id. at 39.)

Despite this evidence to the contrary, the Intervenors continue to argue this alternative

should be considered in lieu of constructing the Project. Moreover, FRONTLINES’ arguments

in support of this alternative are based solely on speculation and hypothetical assumptions.

Transferring a substation from one electrical system to another is not performed by simply

20

transferring the subtransmission lines of the substation from one source to another. Rather,

subtransmission lines form a network of source lines (networked amongst themselves but radial

from the transmission network that is CAISO controlled) that deliver power from the

transmission substation to the distribution substations downstream. (SCE Exhibit 2 (McCabe), at

19:5-9) Accordingly, each of the distribution substations is not served in a radial manner by the

subtransmission source lines, but rather they are integrated in a network of subtransmission lines

that emanate from the transmission substation, delivering power at a distribution substation, and

continuing onward to other distribution substations. (Id., at 19:9-12). One cannot simply

propose such a transfer by looking at a schematic diagram of the electrical system and expect it

to be adequate to just transfer one or more lines. Rather, it is understood that power flow

analyses are necessary to determine the impacts of changing certain elements of a transmission

system and FRONTLINES has not performed such analysis. (Id., at 19:12-18)

While FRONTLINES cites to exhibits in the record, those exhibits were prepared solely

by FRONTLINES, and not an expert consultant, to support its arguments. Because its claims are

based on incomplete and confused questioning of expert witnesses and are no substitute for a

comprehensive plan of service prepared by licensed, trained and experienced power system

electrical engineers, they should be rejected.

B. The Installation of a Third Transformer was Considered and Eliminated in the

FEIR Because it does not Meet the Project Objectives

The Intervenors’ claims that the addition of a third transformer so serve the Valley South

System eliminates all transformer overload concerns is similarly unfounded. The Intervenors

argue that SCE can easily deploy a third transformer to address transformer capacity concerns

without difficulty or adverse consequences. This is untrue. Continuing to add capacity to Valley

Substation does not represent sound engineering practice as it represents further centralizing of

capacity rather than decentralizing it, and would subject hundreds of thousands of customers to

outage and reliability issues that would otherwise be less likely to occur through diversifying the

21

electrical capacity in the area. (Id., at 21:18-22) Conversely, the ASP would increase the

capacity to meet demand in a diversified manner and adds the necessary 115 kV system tie-lines.

Simply installing a third load-serving transformer to the Valley South System does not meet

most of the project objectives and this alternative was also already considered and eliminated in

the FEIR. (DEIR, Appendix D, Alternatives Screening Report at 37)

V.

THE FEIR SHOULD BE CERTIFIED BECAUSE IT ANALYZES THE ENTIRETY OF

THE WORK NEEDED TO COMPLETE THE PROJECT, IT ADEQUATELY

ANALYZES POTENTIAL ENVIRONMENTAL IMPACTS AND SUBSTANTIAL

EVIDENCE SUPPORTS ITS REJECTION OF ALTERNATIVES

Various Intervenors offer arguments alleging the FEIR in support of the ASP and the

VIG Project failed to comply with the California Environmental Quality Act (“CEQA”). As set

forth below, however, those arguments are without merit and therefore should be rejected.

A. The FEIR’s Environmental Analyses are Appropriate and are Supported by

Substantial Evidence in the Administrative Record

When a lead agency prepares an EIR, that agency’s factual environmental determinations

will be upheld if they are supported by substantial evidence in the administrative record. (See

Pub. Resources Code § 21168.5.) Substantial evidence means “enough relevant information and

reasonable inferences from this information that a fair argument can be made to support a

conclusion, even though other conclusions might also be reached.” (See CEQA Guidelines §

15384(a).) Substantial evidence includes “facts, reasonable assumptions predicated upon facts,

and expert opinion supported by facts.” (See Pub. Resources Code § 21082.2.) It does not

include “[a]rgument, speculation, unsubstantiated opinion or narrative, evidence which is clearly

inaccurate or erroneous, or evidence of social or economic impacts which do not contribute to, or

22

are not caused by, physical impacts on the environment….” (See id.) “Complaints, fears, and

suspicions about a project’s potential environmental impact likewise do not constitute substantial

evidence.” (Joshua Tree Downtown Bus. Alliance v. County of San Bernardino, 1 Cal.App.5th

677, 690 (2016) (citations omitted).)

Substantial deference is accorded to the lead agency’s substantive factual conclusions,

which may not be set aside on the ground that an opposite conclusion would have been equally,

or even more, reasonable. (See Vineyard Area Citizens for Responsible Growth, Inc. v. City of

Rancho Cordova, 40 Cal.4th 412, 435 (2007) (Reviewing courts “accord greater deference to the

agency's substantive factual conclusions. In reviewing for substantial evidence, the reviewing

court ‘may not set aside an agency's approval of an EIR on the ground that an opposite

conclusion would have been equally or more reasonable’ (citations omitted)).) “Where, as here,

the agency prepares an EIR, the issue is whether substantial evidence supports the agency's

conclusions, not whether others might disagree with those conclusions.” (North Coast Rivers

Alliance v. Marin Municipal Water District Board of Directors, 216 Cal.App.4th 614, 626-27

(2013).)

1. Aesthetics

The City of Lake Elsinore (the “City”) alleges the FEIR’s analysis of aesthetic

impacts is flawed because it fails to account for degraded views to residents and patrons of

commercial developments by: (1) overly emphasizing freeway views; (2) using outdated

standards to judge visual impacts; (3) using simulated views depicting single-circuit

configurations when certain poles in Lake Elsinore’s boundaries will be double-circuited; and (4)

failing to adequately respond to the City’s substantially similar comments on the DEIR. (See

City Brief, at 6-19.) While it is clear that the City disagrees with the FEIR’s conclusions, its

23

objections to the aesthetic methodologies employed by the FEIR do not undercut the

Commission’s conclusions based on the substantial evidence in the administrative record.

Regarding the alleged over-emphasis on freeway views, the City argues that the

FEIR fails to perform a “qualitative” analysis, using only criteria based on the Federal Highway

Administration’s 1988 Visual Impact Assessment for Highway Projects (“FHA Visual Impact

Assessment”). (See City Brief, at 7-8 (citing Berkeley Keep Jets Over the Bay Comm. v. Board of

Port Comms., 91 Cal.App.4th 1344 (2001) (“Berkeley Jets”) for the proposition that the use of a

quantitative methodology that excluded any qualitative analysis of noise impacts was

inappropriate and grounds to set aside the Final EIR).) This argument is inaccurate and is based

on a misunderstanding of the FHA Visual Impact Assessment and a misreading of the aesthetics

analyses performed by the Commission.

First, the FHA Visual Impact methodology is inherently qualitative, as is CEQA’s

approach to aesthetics generally. (See FEIR, at 4.1-16 to 4.1-18 (FHA Visual Impact Assessment

includes qualitative evaluations such as “assess the visual resources of the proposed project area

by describing the visual character of the area and assessing the visual quality… in terms of the

four visual pattern elements: firm, line, color, and texture,” describe “potentially affected

viewers…in terms of viewer sensitivity and viewer exposure,” and assess the visual quality

through the criteria of “vividness,” “intactness,” and “unity”), 4.1-43 (describing CEQA’s

Appendix G “significance criteria” checklist for aesthetics to include general qualitative

evaluations of “damage [to] scenic resources” and degradation of “the existing visual character

or quality of the site…”)) Because this aesthetic analysis is already qualitative, the City’s

citation to Berkeley Jets and the noise analysis at issue therein is inapposite to the consideration

of aesthetics in the FEIR here. (See City Brief, at 7-8 (citing Berkeley Jets).)16 Second, the City’s

16 While not clear from its brief, to the extent the City is simply suggesting that a different methodology

be used to assess aesthetic impacts, SCE notes that: (1) there is no evidence in the record or proffered by the City that undercuts the validity of the method selected by the Commission; and (2) given that the qualitative nature of the aesthetic analysis is already captured, it is unclear exactly how the City believes the aesthetic methodology should be modified. The City’s argument and citation to Berkeley Jets is potentially relevant in the context of environmental resources that are subject to both

24

complaint that the FEIR failed to consider the vantage of retail patrons and certain viewpoints

outside of the highway corridors (see City Brief, at 8-11) ignores the fact that the FEIR used the

six vantage points designated in the City’s own General Plan. (See id., at 8 (citing FEIR); FEIR,

at 4.1-12 (Section 4.1.1.4 (Scenic Vistas), describing FEIR’s consideration of identified scenic

vistas in Lake Elsinore).) The City cannot credibly fault the FEIR for not accounting for

unidentified and innumerable scenic resources within its City boundaries that even it has not

recognized.

Regarding the use of the allegedly “outdated” methodologies for the assessment

of visual resources, the Commission clearly notes that it is aware that the 1988 FHA Visual

Impact Assessment has been subsequently revised, but goes on to explain why the use of the

1988 version is more appropriate for the Commission’s purposes:

The FHWA has recently revised its guidelines for visual impact assessment to allow different levels of documentation and be more readily understood and practical in its application (FHWA 2015). However, the new FHWA guidelines now focus more on transportation projects and no longer emphasize several key concepts from the earlier guidelines that are applicable to various types of projects, such as transmission lines, substations, and similar industrial-type development projects, in rural, suburban, and urban landscapes. Although the new FHWA guidelines incorporate many elements from those issued in 1988, the earlier guidelines remain most applicable for assessing aesthetic impacts of proposed projects situated within diverse landscape types and on private lands.

(FEIR, at 4.1-16 – 4.1-17 (Section 4.1.3.1, emphasis added).) It is completely appropriate and in

line with CEQA’s tenets that the Commission employ environmental methodologies it judges to

be better suited to the types of projects that come before it. (See Vineyard Area Citizens for

quantitative and qualitative analyses, such as the noise analysis at issue there. Here however, aesthetics analyses are already qualitative. The Commission is well within its discretion under CEQA to select the appropriate aesthetic methodology to use and should be afforded substantial deference in determining what methodologies and factors to use in evaluating aesthetic impacts. (See Vineyard Area Citizens for Responsible Growth, Inc., 40 Cal.4th at 435 (great deference afforded agency’s substantive factual conclusions).)

25

Responsible Growth, Inc., 40 Cal.4th at 435 (great deference afforded agency’s substantive

factual conclusions).)17

Regarding the allegedly erroneous depiction of the number of cross arms in the

FEIR’s visual simulations, the simulations of “Key Viewpoints” (“KV”) 6 and 7 (Figures 4.1-4f

and 4.1-4h) show two single circuit pole lines as proposed by VIG, as clearly described in the

title of the simulation’s title (“Proposed Valley-Ivyglen Visual Simulation).” While it is accurate

that ASP will place another circuit on one of those pole lines, the cumulative impacts section of

the FEIR asserts as much: “[s]everal Valley-Ivyglen Project components would be in the same

viewshed as cumulative projects,” including ASP. (See FEIR, at 6-7; see also FEIR, at 6-9 (same

for ASP).) Tables 6-2 and 6-3 describe the “Cumulative Projects within the Aesthetics

Geographic Scope” for VIG and ASP, each respectively noting overlapping ASP and VIG

segments. Specifically, VIG Segment 5 (shown in KVs 6 and 7) overlaps with, among other

things, 115-kV Segment ASP1, ASP1.5, and ASP2. (See FEIR, at Table 6-2; see also FEIR, at

Table 6-3 (same).)

Further, the City points to no evidence in the record suggesting that this alleged

error, even if accurate with respect to certain visual simulations, is material or sufficient to call

into question the FEIR’s aesthetic analyses. “The fundamental purpose of CEQA is to ensure

‘that environmental considerations play a significant role in governmental decision-making,’”

and the FEIR’s aesthetic analysis certainly satisfies that role. (See Fullerton Joint Union High

School Dist. v. State Bd. of Education, 32 Cal.3d 779, 797 (1982) (fundamental purpose of

17 Again, the City’s citation to Berkeley Jets is unavailing given the vastly different nature of the

environmental analyses at issue, as well as the lead agency’s disclosure of its rationales. (See City Brief, at 12.) Here, the issue is aesthetics and the Commission has plainly justified its rationales. In contrast, in Berkeley Jets the issue was the air quality analysis (toxic air contaminant (TAC) emissions, an analysis uniquely in the purview of the California Air Resources Board (CARB) and the local Air Quality Management Districts (AQMDs)), and the EIR’s response was misleading (misquoting a CARB official) in its justification as to why the older standard was used. (See Berkeley Jets, 91 Cal.App.4th at 1365-66.)

26

CEQA, citations omitted); CEQA Guidelines § 15151 (EIRs reviewed “not for perfection but for

adequacy, completeness, and a good faith effort at full disclosure”).)

Lastly, there is no question that the FEIR acknowledges and responds to the

concerns the City enumerates in its DEIR comment letter. As summarized above, the City’s

criticisms of the analyses and methodological approach to aesthetics are, as described in the

response to comments, addressed in FEIR’s analysis of aesthetics. (See City Brief, at 17-18

(citing FEIR response to the City’s aesthetic comments).) In compliance with CEQA Guidelines

Section 15088, FEIR Response 248-2 clearly identifies the issue raised (identifying the City’s

specific comment related to “visual impacts” in FEIR, Appx. M3), and responds that “[i]n cases

where a visual impact was identified, mitigation was included to reduce the impact…,” going on

to refer to Sections in the FEIR containing the FEIR’s analysis of aesthetics (Section 4.1) and

undergrounding alternatives (Chapter 5.0). (See CEQA Guidelines § 15088(c) (in good faith and

supported by reasoned analysis, EIR responses to comments shall identify the issue and, if

applicable, give specific reasons why comment was not accepted).)

2. Socioeconomic and Environmental Justice

The City alleges the FEIR fails to address socioeconomic impacts of the ASP and

VIG Projects. (See City Brief, at 19-20.) “Economic and social impacts of proposed projects

are…outside of CEQA’s purview…[unless] there is evidence … that economic and social effects

caused by a project … could result in a reasonably foreseeable indirect environmental impact,

such as urban decay or deterioration, then the CEQA lead agency is obligated to assess this

indirect environmental impact.” (Anderson First Coalition v. City of Anderson, 130 Cal.App.4th

1173, 1182 (2005); see also South Orange County Wastewater Authority v. City of Dana Point,

196 Cal.App.4th 1604, 1614 (2011) (“[C]ourts have recognized that CEQA is not a weapon to be

deployed against all possible development ills. … Only if the loss of businesses affects the

physical environment — for example, by causing or increasing urban decay — will CEQA be

engaged” (citations omitted)).) However, “[a]n impact ‘which is speculative or unlikely to occur

is not reasonably foreseeable,’” (see Anderson First Coalition, 130 Cal.App.4th at 1182 (citing

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CEQA Guidelines, § 15064(d)(3))) and “[a]rgument, speculation, unsubstantiated opinion or

narrative, … or evidence of social or economic impacts which do not contribute to, or are not

caused by, physical impacts on the environment…” are not “substantial evidence” under CEQA.

(See Pub. Res. Code § 21082.2(c); North Coast Rivers Alliance v. Kawamura, 243 Cal.App.4th

647, 674-75 (2015) (arguments unsupported by evidence in record insufficient to challenge EIR);

Perley v. Board of Supervisors, 137 Cal.App.3rd 424, 435-36 (1982) (unsubstantiated fears and

concerns about project’s impacts lacked objective basis for challenge and did not constitute

substantial evidence).)

Here, there is absolutely no evidence cited by the City which supports its claims

that the Projects will manifestly result in “reduced visitors and profitability to the commercial

uses,” reduced property values, the faltering of planned development, and ultimately “blight or

urban decay.” (See City Brief, at 19-20 (citing no evidence in support of alleged socioeconomic

impacts from Projects).) The causal chain that the City alleges to begin with overhead

transmission lines and end in blight, urban decay, and economic distress is speculative,

unsubstantiated, and certainly not proven out across SCE’s service territory where overhead lines

are routinely located in the vicinity of thriving commercial interests. (See id.)

Further, the potential for socioeconomic impacts was not overlooked; rather,

consistent with the arguments above, the Commission considered it unlikely to occur. In

response to the City’s DEIR comment regarding alleged socioeconomic impacts, the

Commission responded “[c]onsidering that the project would result in less than significant

aesthetic impacts or impacts that would be mitigated to less than significant, the construction of

the project would not result in blight or urban decay.” (See FEIR, Appx. L at 20 (Response to

comment # 248-16).)

Similarly, the City alleges that the FEIR should have analyzed alleged

environmental justice impacts from the Project, and specifically whether the City’s “residents are

disproportionately exposed to the Proposed Projects’ impacts as compared to the residents of

…other benefitted communities.” (See City Brief, at 20-21.) In response to the City’s DEIR

28

comment regarding alleged environmental justice concerns, the Commission evaluated the 2015

census data and determined that “Lake Elsinore as a whole is not a population at risk due to its

minority or low income population.”(See FEIR, Appx. L at 20 (Response to comment # 248-

17).) The City fails to cite evidence that would support otherwise.

There is simply no basis to support the City’s claim that socioeconomic and/or

environmental justice impacts are reasonably foreseeable and therefore should have been more

thoroughly considered in the FEIR.

3. Air Quality

FRONTLINES asserts the FEIR’s air quality analysis was flawed because it

allegedly: (1) fails to account for the concurrent emissions of both the ASP and VIG Projects

(see FRONTLINES Brief, at 67-68 (Section 14.4)); (2) does not properly account for fugitive

dust emissions associated with helicopter take offs and landings (see id., at 68-69 (Section

14.5)); and, by extension, (3) fails to address Valley Fever concerns. (See id., at 67-68 (Section

14.8).) FRONTLINES arguments are either incorrect, or do not so undercut the FEIR’s good

faith efforts at full disclosure such as to render it insufficient as an informational document

supporting the Commission’s decision-making.

First, FRONTLINES’ inaccurately alleges the FEIR understates air quality

impacts that will occur if both the ASP and VIG Projects are approved by failing to account for

“overlapping construction schedules.” (See id., at 67-68.) While true that the two Projects’

construction may overlap, the Projects remain separate endeavors. The potential air quality

impacts resulting from the overlapping construction of these two Projects are disclosed in the

cumulative air quality analyses for the respective Projects, as well as the FEIR’s cumulative

impacts analysis. (See FEIR, at 4.3-17 (Impact AQ-3, VIG would have cumulatively

considerable air quality construction impacts), 4.3-25 (Impact AQ-3, ASP would have

cumulatively considerable air quality construction impacts), 6-12 to 6-13 (disclosing that even

after Project Commitment J and mitigation measures are implemented, the construction of ASP

and VIG would each have cumulatively considerable impacts on PM10 and PM2.5).)

29

Second, with respect to FRONTLINES’ allegation that the FEIR does not

“properly quantify air quality impacts resulting from helicopter deployment,” while

FRONTLINES is correct that not all helicopter take-offs and landings would occur on “paved

areas” and that there would likely be some fugitive dust emissions specific to helicopter

landings/take-offs, its estimates that PM10 emissions would be increased by 106 lbs./day and

132 lbs./day for the ASP and VIG Projects respectively are grossly overstated. (See

FRONTLINES Brief, at 68-69 (“...FEIR asserts (wrongly) that SCE’s takeoff and landing events

on the Valley-Ivyglen Project will occur on paved surfaces…” and estimating daily PM10

emission increases); FEIR, Appx. L at Response # 99-62 (incorrectly noting that “helicopter

landing and takeoff activities would … occur on paved areas…”).) FRONTLINES’ estimates of

an additional 6.6 lbs. of PM10 per helicopter “trip” is premised on the erroneous assumption that

each trip will involve two take-off and landing cycles from unpaved areas. In fact, most

helicopter construction trips will not include landing along the construction ROW, but will rather

involve taking off, hovering along a stringing site, and landing back at that same staging area,

i.e., only one take-off/landing cycle per trip. Even assuming the remainder of FRONTLINES’

calculations are correct,18 this would halve FRONTLINES’ estimated PM10 emissions per

helicopter trip to 3.3 lbs. PM10 per helicopter trip, resulting in only 53 additional lbs./day for

ASP and 66 additional lbs./day for VIG.

Applying these assumptions to the PM10 estimates for the two Projects, adding

66 lbs./day of PM10 to VIG’s estimated PM10 emissions during the “Install Conductor”

18 SCE has not specifically challenged all of FRONTLINES’s assumptions for the purposes of this

example. SCE notes however, that the remainder of assumptions in FRONTLINES’s calculations likely also overstate PM10 emissions, including: (1) that all take-offs/landings were from unpaved sites; (2) the emissions factors from FRONTLINES’s cited Particulate Matter Emissions for Dust from Unique Military Actions (http://www.cpuc.ca.gov/environment/info/panoramaenv/TL695_TL6971/DraftMND/Pendleton_DMND_AppxB_AirQuality.pdf ) are already conservative in that measurements were conducted in dry, unpaved, desert in Arizona and are based on UH-1H Huey helicopter (not a light duty Hughes 500 as is proposed to be used here); (3) FRONTLINES accounted for no dust control measures, which could reduce emissions by as much as 55%; and (4) FRONTLINES’ calculations aggressively assume 40 take-off and landing cycles per day.

30

construction phase (124.55 lbs./day) would total 190.55 lbs./day - still below the FEIR’s

conservatively estimated 233.07 lbs./day of PM10. (See FEIR, Appx. B, VIG_AQ

Emissions_With PC-J.xls, Table 2 (“Peak Daily Criteria Pollutant Construction Emissions

Compared to Regional Thresholds” estimating maximum 233.07 lbs./day of PM10). However,

because ASP’s maximum daily peak emissions calculation conservatively assumes the maximum

daily emissions from each of the four principle phases of ASP work (i.e., Substation, 500kV,

115kV, and Telecom) would occur simultaneously, adding 53 lbs./day of PM10 to ASP’s

estimated PM10 emissions would result in a greater estimated maximum peak daily emissions

figure than was asserted in the FEIR. Specifically, adding 53 lbs./day of PM10 to ASP’s

estimated PM10 emissions (476.31 lbs./day) would suggest a new peak of 529.31 lbs./day. (See

FEIR, Appx. B, ASP_AQ_Helicopter Scenario_Soil Option 1_w_PC-J.xls, Table 2 (“Total Daily

Criteria Pollutant Emissions for Overlapping Construction Phases” estimating maximum of

476.31 lbs./day of PM10).

However, as indicated above, these estimates are based on extremely conservative

assumptions, unlikely to occur during actual construction. Further, even if FRONTLINES’

estimates credibly suggested that PM10 emissions would be greater than the FEIR’s estimated

maximum daily PM10 emissions, the Projects’ respective impacts from PM10 were already

deemed to be significant and unavoidable, as well as cumulatively considerable as explained

above. (See FEIR, at 4.3-17 & 25 (Impact AQ-3, VIG/ASP each have cumulatively considerable

air quality construction impacts), 6-12 to 6-13 (VIG/ASP each have cumulatively considerable

PM10 and PM2.5 impacts despite mitigation).)

FRONTLINES also challenges the FEIR’s assertion that “fugitive dust emissions

from SCE’s proposed helicopter activities will be reduced to less than significant by the

‘implementation of dust control measures,’” going on to attack MMAQ-3 (requiring the

preparation of a Dust Control Plan per AQMD Rule 403) as “deferred mitigation.” (See

FRONTLINES Brief, at 69 (challenging that Project Commitment J would reduce fugitive dust

impacts to less than significant levels), fn. 38 (alleging MMAQ-3 is deferred mitigation).)

31

Frontlines is correct that the FEIR’s assertion that fugitive dust emissions would be rendered less

than significant is in error, but this is corrected by other portions of the air quality analyses which

clearly maintain that fugitive dust (PM10 emissions) during construction would remain

significant despite mitigation. (See FEIR, at 4.3-17 & 26 (VIG and ASP construction PM10

emissions each significant despite mitigation).)

FRONTLINES characterization of MMAQ-3 as improperly deferred mitigation

however, is inaccurate. MMAQ-3 requires the preparation of a Dust Control Plan pursuant to

AQMD Rule 403, setting out “performance standards which would mitigate the significant effect

of the project and which may be accomplished in more than one specified way;” a practice

specifically allowed under CEQA. (See CEQA Guidelines § 15126.4(a)(1)(B) (while mitigation

should not be “deferred,” specifying performance standards is acceptable); FEIR at 4.3-9

(describing AQMD Rule 403).)

On balance, the errors identified by FRONTLINES do not “explicitly violate

CEQA” or “prevent the Commission from properly weighing the full extent of the

project’s…adverse impacts.” (See FRONTLINES Brief, at 70.) “CEQA requires an EIR to

reflect a good faith effort at full disclosure; it does not mandate perfection, nor does it require an

analysis to be exhaustive.” (CEQA Guidelines § 15151; see also Dry Creek Citizens Coalition v.

County of Tulare, 70 Cal.App.4th 20, 26 (1999) (citing CEQA Guidelines section 15151 and

noting “[a]n EIR should be prepared with a sufficient degree of analysis to provide decision

makers with information which enables them to make a decision which intelligently takes

account of environmental consequences. An evaluation of the environmental effects of a

proposed project need not be exhaustive, but the sufficiency of an EIR is to be reviewed in the

light of what is reasonably feasible. …The courts have looked not for perfection but for

adequacy, completeness, and a good faith effort at full disclosure”).) “A prejudicial abuse of

discretion occurs if the failure to include relevant information precludes informed decision-

making and informed public participation, thereby thwarting the statutory goals of the EIR

process.” (Dry Creek Citizens Coalition, 70 Cal.App.4th at 26; see also Mission Bay Alliance v.

32

Office of Community Investment, 6 Cal.App.5th 160, 186, FN 33 (2016) (use of allegedly

improper TAC analysis was not contrary to the good-faith full disclosure requirement in part

because results of analysis still below significance threshold and did not alter conclusions of

FEIR).) Here, nothing in the errors identified by FRONTLINES materially changes the

environmental conclusions of the FEIR, which identifies a significant and unavoidable

environmental impact from fugitive dust emissions and already requires that mitigation be

assigned to offset that significant impact to the maximum extent feasible. As such, CEQA’s

statutory goal of informed decision-making and the FEIR’s good-faith efforts at full disclosure

are not meaningfully undercut or rendered inadequate by the errors FRONTLINES identifies.

Lastly with respect to the FEIR’s air quality analyses, FRONTLINES’ allegation

that the FEIR “fails to properly address Valley Fever concerns” is essentially a dispute regarding

how to interpret a 2015 Riverside County Health System publication: FRONTLINES alleges the

publication supports the assertion that Valley Fever is a concern in the areas of ASP and VIG

construction (see FRONTLINES Brief, at 74-75); 19 in contrast and citing the same publication,

the FEIR asserts “[t]here is a low probability of the Valley Fever spores in the VOG and ASP

project areas… ” (See FEIR, at 4.3-6.) Further, the fugitive dust emissions from helicopters will

be mitigated to the extent feasible through the implementation of Project Commitment J,

requiring certain watering and limitations of vehicle speed, and MMAQ-3, requiring the

development of a Dust Control Plan pursuant to AQMD Rule 403. (See FEIR, at 4.3-14, 4.3-23,

Appx L, Response 99-62 (noting Project Commitment J and MMAQ-3 as measures which would

reduce potential dust dispersion).) Here, the FEIR’s interpretation of the 2015 Riverside County

Health System publication should be given deference, “even though other conclusions might also

19 FRONTLINES goes on to cite other sources of information which are not part of the administrative

record for the ASP and VIG PFM proceedings, asking that judicial notice be taken of these extra-record sources. (See FRONTLINES Brief, at 75, fns. 40 – 42 (citing an alleged “Valley Fever ‘hot spot’ map and another Valley Fever study)). SCE objects to FRONTLINES’ improper and unsubstantiated request for judicial notice and citation to these extra-record sources in its briefs. SCE moves that any such references be stricken and given no weight in this proceeding.

33

be reached.” (See CEQA Guidelines § 15384(a) (substantial evidence is “enough relevant

information and reasonable inferences from this information that a fair argument can be made to

support a conclusion, even though other conclusions might also be reached.”))

4. Noise

FRONTLINES also alleges that FEIR’s noise analysis was flawed because it

understates actual noise impacts by allegedly: (1) failing to disclose significant noise impacts; (2)

ignoring impacts to sensitive noise receptors; and (3) misrepresenting the decibels of helicopter

noise that will be experienced when the helicopter is taking-off, hovering, and/or in flight. (See

FRONTLINES Brief, at 73-74.) Again, FRONTLINES arguments are incorrect.

First, the FEIR does not “indicate that Ivyglen noise impacts will be ‘less than

significant’” by excluding helicopter noise as FRONTLINES alleges. (See id., at 73). Indeed,

Table 4.11-16 explicitly notes that that the noise decibel data it presents excludes noise-intensive

“blasting and helicopter use,” and is immediately followed by a paragraph overtly and explicitly

concluding “[c]onstruction of the proposed Valley–Ivyglen Project would have significant and

unavoidable impacts from short-term increases to ambient noise levels.” (See FEIR, at 4.11-30.)

Second, this same overt conclusion that VIG would have significant and

unavoidable noise impacts substantially undercuts FRONTLINES’ assertion that noise impacts

to sensitive receptors were “ignored.” The Commission responded to FRONTLINES’ specific

allegations regarding Ortega High School, noting in relevant part that the school is “located on

Chaney Street/Education Way near the VIG4 Segment and the new part of the [ASP]. Education

buildings on education Way are noted in Table 4.11-4/Table 4.11-15 and are noted for being

within 71 feet of a project component.” (See FEIR, Appx. L, Response 99-69.) Extensive

listings of other sensitive receptors is presented in tables 4.11-15 (VIG) and 4.11-19 (ASP)

which include proximity, predicted noise level, and whether the noise threshold is expected to be

exceeded. (See FEIR at 4.11-27 – 4.11-29 (Table 4.11-15, VIG), 4.11-39 to 4.11-41 (Table 4.11-

19, ASP).)

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Lastly with respect to noise, FRONTLINES argues that the FEIR fails to fully

disclose the noise impacts from helicopters and “materially understates actual noise impacts

created by helicopter operations.” (See FRONTLINES Brief, at 73-74 (FEIR misrepresents

helicopter “noise envelopes”).) In contrast to FRONTLINES characterization, the FEIR

explicitly notes, among other things,

Noise in any one work location along the 115-kV Segments would be short term; however, as shown in Table 4.11-15, there would be a substantial temporary increase in noise (i.e. 10 dBA above ambient noise levels) at nearest sensitive receptors identified along all 115-kV Segments, at three blasting sites, and at Staging Areas VIG3, VIG9, VIG12 and VIG13. … While flying above residential areas, helicopter operations have the potential to create a temporary but noticeable increase above ambient noise levels; however, it is anticipated that most of the noise effects associated with helicopter used would occur at those receptors located in the vicinity of staging areas, since these areas would be use for landing and take-off at a frequent basis. Impacts would be temporary and significant and unavoidable for those sensitive receptors located along the flight paths in the proximity to staging areas.

(FEIR at 4.11-29 (emphasis added).) Further, it should be noted that the Projects’ construction

noise impacts were found to be significant and unavoidable even without the use of helicopters.

Table 4.11-16 discloses “Valley-Ivyglen Project Construction Noise Scenarios (excluding

blasting and helicopter use)” and indicates that even with mitigation, construction noise levels

within 200 ft. of VIG would exceed thresholds of significance. (See FEIR, at 4.11-30 (emphasis

added).)

SCE disputes that any of FRONTLINES’ arguments with respect to noise

evidence actual error.

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B. The Fact that the FEIR does not Include Measures Which Ensure Compliance with

its Assumptions does not Render it Invalid

FRONTLINES argues the fact that there is no “mechanism” to ensure compliance with

the assumptions of the FEIR is a “fatal deficiency…because it negates the entire CEQA review

process and renders the FEIR non-compliant with CEQA.” (See FRONTLINES Brief, at 64-66

(Section 14.2).) FRONTLINES is mistaken and cites no legal precedent for this argument.

There are numerous enforcement mechanisms that may be utilized by the Commission and/or

members of the public to ensure that SCE’s construction practices are consistent with the

assumptions made in the FEIR, including the FEIR’s Mitigation Monitoring, Compliance and

Reporting Plan (“MMCRP,” see FEIR Chapter 9), fines pursuant to Resolution E-4550 (CEQA

Citation Program), and complaints filed pursuant to Article 4 of the CPUC Rules of Practice and

Procedure (“CPUC Rule”). FRONTLINES’ suggested conditions are neither required nor

warranted and should be rejected.

C. A Statement of Overriding Considerations for VIG is Warranted and Supported by

Substantial Evidence in the Administrative Record

FRONTLINES argues the fact that the administrative “record does not provide any

evidence that SCE's proposed helicopter construction alternative will result in an economic,

legal, social, or technological benefit” and therefore, “CEQA Guidelines Section 15093

precludes the Commission from developing of a Statement of Overriding Considerations that

approve [sic] SCE's helicopter construction method request.” (See FRONTLINES Brief, at 57-58

(Section 12).) FRONTLINES misunderstands CEQA Guidelines Sections 15091, 15093, and the

nature of the Statement of Overriding Considerations.

36

As a threshold matter and as referenced previously, the assertion that the helicopter

construction “will create significant and unavoidable adverse environmental impacts” is

misleading. (See id., at 57.) VIG as originally proposed, prior to the VIG’s 2014 Petition for

Modification (“PFM”) requesting permission to employ helicopter construction, found various

environmental impacts, including air quality, to be significant and unavoidable. (See Decision

10-08-009, Decision Granting Southern California Edison Company a Permit to Construct the

Fogarty Substation and the Valley-Ivyglen Subtransmission Line Project (August 12, 2010)

(available at

http://docs.cpuc.ca.gov/PublishedDocs/WORD_PDF/FINAL_DECISION/122152.PDF), at 17

(“The proposed project would have significant and unavoidable impacts on land use, visual

resources, mineral resources, and air quality”).) Similarly, VIG’s construction noise impacts

were found to be significant and unavoidable even without the use of helicopters. (See FEIR, at

4.11-30 (Table 4.11-16 finds exceedance of noise thresholds despite mitigation and without

helicopters).) This is important to note because it undercuts the primary argument running

through all of FRONTLINES’ environmental challenges to the FEIR; namely that without

helicopter construction, environmental impacts would not be significant. This is simply not true.

More importantly to FRONTLINES’ argument here, CEQA Guidelines Section 15093

requires the Commission to “balance, as applicable, the economic, legal, social, technological, or

other benefits, including region-wide or statewide environmental benefits, of a proposed project

against its unavoidable environmental risks when determining whether to approve the project

[emphasis added].” Thus, Section 15093 does not mandate that the benefits of helicopter use be

quantified as suggested by FRONTLINES, but rather that the Commission take into account the

benefits of the Project itself, i.e., servicing the electrical demands in the VIG ENA, increasing

37

electrical reliability, and improving operational and maintenance flexibility on subtransmission

lines. (Compare FRONTLINES Brief, at 58 (noting the record “does not provide any evidence

that SCE's proposed helicopter construction alternative will result in an economic, legal, social,

or technological benefit) with FEIR, at 1-10 (Section 1.2.1, VIG Objectives).) Consistent with

the Commission’s original approval of the VIG PTC, it is those benefits that the Commission

must again find outweigh VIG’s significant and unavoidable environmental impacts. (See CEQA

Guidelines § 15093(a) (if specific benefits of proposed project outweigh the unavoidable

environmental consequences, “the adverse environmental effects may be considered

‘acceptable’”).)

Helicopter construction is simply a means to derive those enumerated VIG Project

benefits. (See FEIR, at 1-10 (Section 1.2.1, VIG Objectives).) SCE submitted the VIG PFM

specifically requesting permission to employ helicopter construction. Without the helicopter

construction, SCE may be forced to employ construction means and methods potentially having

greater environmental impacts, or it may be questionable whether SCE can construct the VIG

Project as proposed. Such a result would remove the benefits of which have already been found

by the Commission to be in the public interest in the original VIG PTC proceeding.

FRONTLINES also alleges that no overriding considerations merit approval of the VIG

PFM because the significant adverse impacts of VIG may be avoided through the

implementation of a feasible alternative. (See FRONTLINES Brief, at 58 (Section 13).).

Specifically, FRONTLINES alleges that its so-called “Alternative 1” or “ALT1” would “achieve

the same benefits” as VIG with presumably less environmental impacts. (See id., at 48-50

(Section 10, describing an alternative means to provide a second source of power to the Ivyglen

Substation), 55 (Section 11.2, describing two FRONTLINES proposed alternatives to VIG), 58.).

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SCE objects to the introduction of new Alternatives which are not part of the

administrative record for the VIG PFM proceedings. No proper request for judicial notice has

been filed and SCE moves to strike any reference to this extra-record information in its briefs

and requests that it be given no weight in this proceeding. SCE further objects to FRONTLINES

new alternatives to the extent they raise issues that are beyond the scope of the PFM, ignoring

the procedural posture of VIG as a PFM proceeding. It is wholly inappropriate to bring new,

previously undisclosed Project alternatives into this proceeding at this phase. Lastly, and as

discussed in Sections III and IV above, FRONTLINES “Alternative 1” would not meet the basic

Project Objectives for VIG and thus, regardless of the procedural deficiencies SCE notes above,

Alternative 1 is properly rejected from further consideration.

D. The FEIR’s Analysis of Alternatives is in Accordance with and Satisfaction of

CEQA

Intervenors advance various arguments challenging the reasonable range of alternatives

considered by in the FEIR.

1. There is no Feasible Alternative to Construct VIG without Helicopters

FRONTLINES alleges that “[t]he evidentiary record clearly establishes that

constructing the Valley Ivyglen project without helicopters is a feasible alternative,” offering a

variety of unfounded claims in support of same. (See FRONTLINES Brief, at 51-54 (Section

11.1).) First, FRONTLINES argument here is fatally flawed, as it assumes eliminating

helicopter deployment would either eliminate or decrease significant environmental impacts

from VIG’s construction. In fact, as indicated in Section V.C. above, environmental impacts

such as air quality and noise are significant and unavoidable with or without helicopter

construction. Further, even if technically feasible, any alternative envisioning the construction of

VIG without helicopters may require means and methods of construction that are more

39

environmentally impactful. For example, while the MMCRP does not explicitly assert the use of

helicopters as a means to mitigate project impacts, MMBR-4 does require SCE to limit removal

of native vegetation. The use of a helicopter to string wire over the San Jacinto wash and river

could materially aid the satisfaction of MMBR-4. Certain residents may also experience greater

noise impacts over a longer duration in the form of additional truck trips if helicopters are not

employed.

Second, it is not a given that “[VIG] construction does not require the use of

helicopters, and SCE’s construction program for Valley Ivyglen can feasibly proceed without the

use of helicopters.” (See id., at 52.) In support of the VIG PFM, SCE has consistently

maintained that construction may require the use of helicopters and should that eventuality come

to pass, in order to support such use, it is entirely appropriate and even encouraged under CEQA

that the FEIR disclose and estimate the potential environmental impacts of that possibility,

prescribing mitigation measures as may be warranted or appropriate. (See CEQA Guidelines §

15378 (defining “Project” under CEQA to mean “the whole of an action, which has a potential

for resulting in either a direct physical change…or reasonably foreseeable indirect physical

change in the environment…”).) FRONTLINES’ argument turns CEQA on its head, apparently

encouraging that the FEIR be modified to prohibit the use of helicopters, instead of disclosing

their potential use and mitigating for that possibility. It is inappropriate and inconsistent with the

FEIR’s function as an informational document to omit the potential use of helicopters in the

unlikely event that SCE’s construction of VIG ultimately did not require them.

Most importantly, FRONTLINES apparently misunderstands and/or forgets the

procedural posture of SCE’s VIG PFM proceeding and the fact that there is a substantial risk that

construction of VIG will require the use of helicopters:

Note that conditions vary along the routes and that there is no guarantee that it would be feasible to access certain portions of the route merely because the applicant has determined that helicopters are not required in other areas. In fact, some portions of the route span slopes or other areas where it would be infeasible to conduct certain activities. Note also that the placement of equipment

40

required for conductor pulling differs from the placement of equipment required for component construction, such as pole or tower erection. Therefore, there is no guarantee that areas surrounding the existing road network could be used for conductor pulling merely because a pole or tower could be constructed in a particular location using areas adjacent to an existing road.

(See FEIR, Appx. L, Response 99-58.) In fact, this risk is substantially significant such as to

prompt SCE to file the VIG PFM in order to ensure the potential use of helicopters is disclosed

in order to make the use of helicopters available during construction:

Note that although the CPUC previously approved a project design for the Valley-Ivyglen project that did not include helicopter usage, during final engineering of the previous iteration of the project design, SCE determined that helicopters were necessary in order to construct the project. The CPUC expects that SCE would not use helicopters in areas that are easily accessible along existing roadways due to cost considerations unless necessary.

(See FEIR, Appx. L, Response 99-49.) Any alternative envisioning the construction of VIG

without helicopters is infeasible, as it will either require means and methods of construction that

are more environmentally impactful (environmental infeasibility), and/or will render construction

of VIG as currently proposed technically infeasible. (See id.) It is primarily for this reason that

ASP includes a conventional (i.e., non-helicopter) construction option and VIG does not; for

ASP, conventional construction appears technically feasible whereas for VIG, it does not. (See

FRONTLINES Brief, at 54 (questioning why ASP included a conventional construction

alternative and VIG did not).)

Third, FRONTLINES’ assertions that “constructing Valley Ivyglen without

helicopters will not cause any substantive schedule delays, since Appendix B of the FEIR

assumes helicopters are deployed for only 20 days” and that “constructing Valley Ivyglen

without helicopters will reduce project costs” are both inaccurate. With respect to delays, SCE

plans to use the helicopters for a maximum of 20 days. That does not mean that without

41

helicopters, SCE’s construction would only be delayed 20 days. Construction delays may be

appreciably longer as different, more time-consuming, and more environmentally impactful

construction practices are implemented in lieu of reliance on helicopters. Regarding costs, again,

road-based construction is typically less costly than helicopter use; but that calculation may shift

with extreme terrain or if environmental hazards and/or resources must be avoided. In those

circumstances, reliance on helicopter construction may actually decrease costs.

In sum, the record here and certainly the procedural posture of SCE’s VIG PFM

proceeding provide substantial evidence supporting a finding that constructing VIG without

helicopters is environmentally and technically infeasible.

2. No ASP Alternative was Rejected for Failure to Require the Construction of

a Substation

Certain Intervenors also allege that ASP’s narrow Project Objectives effectively

preclude evaluation of a reasonable range of Project Alternatives for ASP. (See FRONTLINES

Brief, at 60 – 64; TURN Brief, at 42-44.) While these Intervenors’ summary of the applicable

law under CEQA is broadly accurate, their application of those standards to the facts here is not.

Here, there is simply no evidence that any alternative was eliminated because it would not

involve the construction of a substation. To the contrary, Appendix K of the FEIR explicitly

asserts

Note that although it was evident to the CPUC team that a 500-kV substation would be necessary to relieve projected electrical demand, the CPUC nonetheless evaluated a number of non-substation alternatives, as documented in the Alternatives Screening Report (Appendix D of the EIR). These alternatives met none of the project objectives. During public review of the DEIR, several commenters stated that the project objectives for the Alberhill Project were too narrow, which they claim limited the alternatives analysis in the EIR to only 500-kV substation alternatives. The CPUC analyzed and documented a number of non-substation alternatives in the Alternatives Screening Report, but these non-substation alternatives met none of the project objectives and therefore were eliminated from further analysis. While it may appear that the alternatives screening process favored substation alternatives, the explanation

42

for the lack of non-substation alternatives in the DEIR is that none of the substation alternatives identified met any of the project objectives.

(See FEIR, Appx. K. at 3 (emphasis added).) The Commission is well within their discretion

under CEQA to reject Project alternatives which do not satisfy any of the Project objectives. (See

CEQA Guidelines § 15126.6(c) (“Among the factors that may be used to eliminate alternatives

from detailed consideration in an EIR are: (i) failure to meet most of the basic project

objectives…”); FEIR, Appx. D (eliminating various alternatives for failure to meet Project

Objectives), Appx K. at 3 (consideration of alternatives vis-à-vis Project Objectives).) Further,

because the range of alternatives considered was not improperly narrowed by the Project

Objectives, TURN’s subsequent argument that “ASP failed to evaluate alternatives that would

reduce ASP’s significant environmental impacts” also fails. (See TURN Brief, at 44 (Section

XI.B).) Appendices D and K of the FEIR constitute substantial evidence of the Commission’s

evaluation of a reasonable range of alternatives that Intervenors do not credibly challenge here.

(See CEQA Guidelines § 15126.6(a) (“An EIR need not consider every conceivable alternative

to a project. Rather it must consider a reasonable range of potentially feasible alternatives that

will foster informed decision making and public participation.”).)

3. The FEIR Considered a Reasonable Range of Alternatives and the Fact that

it did not Consider an Undergrounding Alternative Exclusive to the City

does not Render the FEIR’s Alternatives Analysis Deficient

The City alleges “[t]hough [the FEIR] analyzes undergrounding alternatives in

certain areas, the Final EIR never presents any undergrounding through Lake Elsinore, other than

Alternative M to the VIG Project which calls for undergrounding the entire VIG project.” (City

Brief, at 22). Under CEQA, the range of alternatives “shall include those that could feasibly

accomplish most of the basic purposes of the project and could avoid or substantially lessen one

or more of the significant impacts.” (CEQA Guidelines § 15126(d)(2).) The discussion of

alternatives need not be exhaustive, but rather are governed by a “rule of reason.” (See CEQA

43

Guidelines § 15126.6(a) (“An EIR need not consider every conceivable alternative to a project.

Rather it must consider a reasonable range of potentially feasible alternatives that will foster

informed decision making and public participation. … There is no ironclad rule governing the

nature or scope of the alternatives to be discussed other than the rule of reason”).)

Here, the FEIR found

[p]er Section 4.1, Aesthetics, visual impacts would be reduced to less than significant with mitigation [and while] a number of alternatives included undergrounding … in some cases, undergrounding alternatives may result in reduced aesthetic impacts at the expense of greater impacts on other resource areas….[and] the CPUC… determined that none of the alternatives carried forward for analysis would be considered environmentally superior to the proposed project….

(See FEIR, Appx. K, Response 248-16). Because the FEIR found no significant aesthetic

impacts in the City and in light of the potential increase in environmental impacts resulting from

undergrounding, an additional undergrounding alternative specific to the City is not warranted or

required under CEQA based on the substantial evidence before the Commission.

VI.

SCE’S ESTIMATE OF MAXIMUM PRUDENT AND REASONABLE COST IS

CONSISTENT WITH PUBLIC UTILITIES CODE SECTION 1005.5

With respect to SCE’s estimated Maximum Prudent and Reasonable Cost (“MPRC”),

TURN alleges generally that SCE has not submitted a sufficiently reliable cost estimate to

determine the MPRC. (See TURN at 49 (“The Commission should accordingly find that SCE has

not provided a sufficiently reliable cost estimate to support a determination of the “reasonable

and prudent” maximum cost for the project.”).)20 Specifically, TURN suggests that: (1) the

20 No other challenge is made directly to SCE’s MPRC estimate. For its part, ORA suggests that the

MPRC be adjusted to the final project approved by the CPUC (see ORA Brief, at 6 (“To the extent that the Commission finds that the Alberhill project is needed, the cost estimate should be refined to

44

actual cost of ASP will be higher; and (2) that the designated “maturity level” of the Project is

too low to support the MPRC. (See TURN at 47 (“…SCE anticipates that the actual cost of ASP

will be much higher than its proffered ‘estimated budget’ of $574.6 million.”), 49 (“Given the

low maturity level of this project, SCE has not actually committed to a ‘maximum and prudent

reasonable cost’ for ASP.”).) Neither of TURN’s arguments meaningfully undercut SCE’s

methodology for estimating the MPRC, or materially dispute SCE’s compliance with PUC

Section 1005.5.

A. Cost Increases will not “Unquestionably” be needed but Even if They Are, PUC

Section 1005.5(b) Specifically Allows for Such Increases

TURN’s opinion that “future [cost] increases will unquestionably be needed” misstates

SCE Witness Tomaske’s testimony and is unfounded and speculative. (See TURN Brief, at 47

(“SCE Witness Tomaske testified that future increases will unquestionably be needed”).) Mr.

Tomaske testified that there is potential for cost increases, not that such increases are presumed.

(See Transcript (Tomaske), at 346:25 – 348:4 (describing factors that “[i]f going up in an

unanticipated way…could cause the project to [sic] the cost increase significantly”)) As with all

projects seeking licenses before the Commission, while cost increases are a possibility, they are

not a given, and there is no support for TURN’s assertion otherwise.

Moreover, as explained in SCE’s Opening Brief, even if the Project costs are eventually

determined to be higher than currently estimated, PUC Section 1005.5(b) specifically allows for

adjustments to the MPRC if the Commission finds that the costs have in fact increased and that

include only those project elements that are needed.”)), while FRONTLINES asserts flatly that no expenditure (“$0”) is warranted because the Project’s Objectives may arguably be satisfied through other means. (See FRONTLINES Brief, at 44 (“…the Alberhill Project does not warrant a CPCN, therefore, the expenditure of any further funds on the Alberhill Project is neither reasonable nor prudent…the ‘maximum prudent and reasonable’ cost for the Alberhill Project is $0”).)

45

the Project is still needed at the increased cost. (See SCE Opening Brief, at 27 (citing PUC §

1005.5(b) and noting that the California “legislature provided for such upward pressure on the

costs of labor and materials by allowing utilities to ‘apply to the [C]ommission for an increase in

the maximum cost specified in the certificate.’”)) TURN’s suggestion that SCE has failed to

comply with PUC Section 1005.5 because the Project costs may increase in the future ignores

Commission practice and the plain, legislative intent of PUC Section 1005.5(b).

B. SCE has Provided a Detailed (488 page) Document with Information in Support of

the MPRC and the Project’s 15% Contingency is Reasonable and Consistent with

Commission Precedent

TURN then suggests that the Association for the Advancement of Cost Engineering

(“AACE”) International Recommended Practice No. 17R-97 (“IRP 17R-97”) “maturity level”

designated by SCE (Class 3 out of 5) is too low to support the estimated MPRC. (See TURN

Brief, at 49 (“Given the low maturity level of this project, SCE has not actually committed to a

‘maximum and prudent reasonable cost’ for ASP.”); see also SCE Rebuttal Testimony, Exhibit

D (containing IRP 17R-97).)

Table 1 of IPR 17R-97 presents five, generic “Estimate Classes” which generically depict

the “Maturity Level of Project Definition Deliverables” (expressed as a percentage of complete

definition), “End Usage” (the typical purpose of the estimate), and “Expected Accuracy Range.”

(See IPR 17R-97 at 2.) Mr. Tomaske testified that the cost estimate for ASP is currently a “Class

3” estimate. (See Testimony (Tomaske), at 350:2 – 351:1 (Class 3).) A Class 3 designation

suggests that the expected accuracy range of the cost estimate is “2 to 6,” relative to an index of

1. (See id.) Thus, if cost estimates are well supported (as is the case with ASP and its 488 pages

of supporting documentation), the expected accuracy range of a Class 3 estimate will be closer to

46

“2,” suggesting the actual costs will range between -10% and +20% of the Class 3 estimate. (See

id. (“If the range index value of "1" represents +10/‐5%, then an index value of 10 represents

+100/‐50%”).)21 On the other hand, in the case of a Class 3 estimate deemed to be a “6,” the

expected accuracy would range between -30% and +60% of the Class 3 estimate. (See id.)22

TURN’s arguments that a “Class 3” cost estimate is not sufficiently “mature” is premised

on two fundamental mischaracterizations of the IPR 17R-97 and Mr. Tomaske’s testimony.

First, TURN’s seems to focus on the “maturity level” of the Project, when the more relevant

variable with respect to the accuracy of the MPRC is the “expected accuracy range.” (See id.;

TURN Brief, at 49).) Second, even when referencing the accuracy range, TURN presumes the

Project’s accuracy estimate is a “6,” when SCE’s use of a fifteen percent contingency and Mr.

Tomaske’s testimony make clear that the Project’s accuracy estimate is a “2.” (Compare TURN

Brief, at 49 (“A maturity level 3 project has an expected accuracy range between 2 and 6. By

definition, this translates to a confidence interval of between 60% high and 30% low [sic],

meaning that the actual cost of the project will likely lie between these 2 extremes”) with

Testimony (Tomaske) at 350:20 – 351:1 (“Our interpretation of this was something in the range

of 15%”).23 TURN’s attempted characterization of SCE’s cost estimates as “barely above the

concept study level” is further contradicted by its acknowledgement (in the same sentence) that

SCE “provided a 488-page document with a lot of detailed costs….” (See TURN at 48).

21 Applying this formula to an expected accuracy of “2”: 2 x +10 = +20%; 2 x -5 = -10%.

22 Applying the formula to an expected accuracy of “6”: 6 x +10 = +60%; 6 x -5 = -30%.

23 A 15% contingency is consistent with an expected “Class 3” accuracy range between -10% and +20%.

47

In summary, SCE’s cost estimates are well supported and are sufficiently accurate and

reliable to support the current MPRC estimate.24

VII.

CONCLUSION

For the foregoing reasons, SCE respectfully requests the CPUC reject the requests and

arguments set forth in the Intervenors’ Briefs, and instead issue a decision to: 1) grant the PFM

authorizing SCE to complete the VIG Project; 2) grant a CPCN authorizing SCE to complete the

ASP; 3) certify the FEIR; 4) determine that the ASP’s and VIG Project’s designs are consistent

with the CPUC’s policies regarding EMF; and 5) make a finding that overriding considerations

support the approval of licenses for the completion of the ASP and VIG, as requested in SCE’s

Opening Brief.

Respectfully submitted, TAMMY JONES

/s/ Tammy Jones By: Tammy Jones

Attorney for SOUTHERN CALIFORNIA EDISON COMPANY

2244 Walnut Grove Avenue Post Office Box 800 Rosemead, California 91770 Telephone: (626) 302-6634

24 SCE notes that TURN also appears to challenge the “reasonableness and prudency of the cost of

ASP… in light of the [allegedly] marginal benefit it will provide to SCE customers.” (See TURN Brief, at 49-50.) This argument purports to challenge “whether the ASP best serves a present or future public convenience and necessity” and the CPUC’s overall determination regarding ASP, but not any specific, additional arguments with respect to SCE’s estimated MPRC. (See id., at 50.) Consistent with its arguments herein, SCE asserts that ASP as proposed is in the public convenience and necessity and should be approved by the Commission.

48

Facsimile: (626) 302-1910 E-mail: [email protected]

January 4, 2018


STATE OF CALIFORNIA


A.07-01-031, et al.


And Related Matter.

A.07-04-028


A.09-09-022


CERTIFICATE OF SERVICE

I hereby certify that, pursuant to the Commission’s Rules of Practice and Procedure, I have this day served a true copy of the SOUTHERN CALIFORNIA EDISON COMPANY’S (U 338-E) REPLY BRIEF on all parties identified on the attached service list A.07-01-031 and A.09-09-022. Service was effected by one or more means indicated below:

☒ Transmitting the copies via e-mail to all parties who have provided an e-mail

☒ Placing the copies in sealed envelopes and causing such envelopes to be delivered

by U.S. Mail to the offices of the Commissioner(s) or other addressee(s).

ALJ Hallie Yacknin California Public Utilities Commission 505 Van Ness Avenue, Room 5108 San Francisco, CA 94102-3214

Executed on January 4, 2018, at Rosemead, California.

/s/ AnnMarie Lett AnnMarie Lett, Legal Administrative Assistant SOUTHERN CALIFORNIA EDISON COMPANY

2244 Walnut Grove Avenue Post Office Box 800 Rosemead, California 91770

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BEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE … › sscc › law › dis › dbattach5e.nsf...

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