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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
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
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
27
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).)
34
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.
35
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.).
38
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.
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)
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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