SOUTHERN CALIFORNIA EDISON COMPANY'S …docs.cpuc.ca.gov/PublishedDocs/SupDoc/A1503003/312/170297594.pdf · Testimony for the Mesa 500 kV Substation Project ... The One and Two Transformer

11/18/16 4:39 PM

Application No.: A.15-03-003 Exhibit No.: SCE-[ ] Witnesses: Garry Chinn Scott Lacy Jason Pendleton Lori Iles-Rangel Charles Adamson

(U 338-E)

Southern California Edison Company’s Opening Testimony for the Mesa 500 kV Substation Project

Before the

Public Utilities Commission of the State of California

Rosemead, California

November 18, 2016

Southern California Edison Company's Opening Testimony For The Mesa 500 Kv Substation Project

Table Of Contents Section Page Witness

-i-

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

II. THE FEIR ALTERNATIVES ARE INFEASIBLE ..........................................2

A. The One and Two Transformer Alternatives Result in Reliability Issues and Do Not Meet Project Objectives ........................2 G. Chinn

B. All FEIR Alternatives Other Than the Proposed Project Would Unreasonably Delay Compliance with the December 31, 2010 OTC Retirement Policy Compliance Date And Would Not Meet Project Objective........................................................8

1. Updated schedule information results in a potential for the Proposed Project to be operational in June 2021............................................................................................8 S. Lacy

2. All FEIR Alternatives other than the Proposed Project result in unreasonable schedule delays. .......................14 J. Pendleton

i. One Transformer Alternative – 10 month delay .............................................................................14

ii. Two transformer Alternative-6 month delay ...............17

iii. GIS Alternative- 14 month delay .................................18

iv. Delays due to Alternatives-dictated operating theater construction ......................................................20

C. Environmental Considerations Contribute to Infeasibility of Alternatives ..........................................................................................22

1. The Two Transformer and GIS Alternatives result in additional grading disturbance not captured in the FEIR. ........................................................................................22

2. The Potential for fugitive dust increases with the Alternatives; not decreases. .....................................................24

3. Impacts to biological resources under the Proposed Project are already less than significant. ..................................25 L. Iles-Rangel

Southern California Edison Company's Opening Testimony For The Mesa 500 Kv Substation Project Table Of Contents (Continued)

Section Page Witness

-ii-

D. The GIS Alternative Would Cost Between $64-$74 Million More Than the Proposed Project..........................................................26 S. Lacy

E. The 1600 MVA Transformer Bank is Not an SCE-Approved Design Standard. ..................................................................................28 C. Adamson

III. OVERRIDING CONSIDERATIONS .............................................................29

APPENDIX A

APPENDIX B

APPENDIX C

1

I. 1

INTRODUCTION 2

On March 13, 2015, Southern California Edison Company (SCE) filed with the 3

California Public Utilities Commission (CPUC or Commission) an application (A.15-03-003) 4

seeking a Permit to Construct (PTC) for the Mesa 500 kV Substation Project (Proposed Project). 5

The Commission issued the Draft Environmental Impact Report (DEIR) on April 29, 2016 and 6

the Final EIR (FEIR) on October 7, 2016.1 In accordance with the Scoping Memo and Ruling of 7

Assigned Commissioner (Ruling), dated November 14, 2016, SCE hereby serves the following 8

direct testimony regarding: 9

Infeasibility of the FEIR Alternatives,2 sponsored by Garry Chinn, Scott Lacy, 10

Jason Pendleton, Lori Iles-Rangel, and Charles Adamson 11

Overriding considerations, sponsored by Charles Adamson 12

1 SCE submitted comments on the DEIR. SCE’s position, in part, was that the three Alternatives

proposed in the DEIR, the One-Transformer, Two-Transformer, and GIS Alternative, were not environmentally superior to the Proposed Project and should be dismissed from further consideration. The FEIR retained these alternatives. SCE’s position remains that the three alternatives put forth in the FEIR are not environmentally superior, but as they were retained, SCE submits this testimony on the infeasibility of those alternatives and the benefits of the Proposed Project which override the significant impacts associated with it. http://www.cpuc.ca.gov/environment/info/ene/mesa/Docs/46.1%20Comment%20Set%20D_Applicant.pdf

2 As referenced herein, “project alternatives” or “FEIR Alternatives” refers to the One Transformer Alternative, the Two Transformer Alternative and the GIS Alternative. The Proposed Project will generally be referenced as Project or Proposed Project.

2

II. 1

THE FEIR ALTERNATIVES ARE INFEASIBLE 2

A. The One and Two Transformer Alternatives Result in Reliability Issues and 3

Do Not Meet Project Objectives 4

The CPUC included three Project Objectives in the FEIR.3 Project Objective 1 addresses 5

violations of reliability standards upon the retirement of Once Through Cooling (OTC) 6

generation by December 31, 2020. Specifically, Project Objective 1 states that violations are 7

based on power flow data from 2014 and the contingencies listed in Appendix B of the FEIR.4 8

Project Objective 2 requires avoiding the introduction of new reliability standard violations. Both 9

the One and Two Transformer Alternatives fail to meet both of these important FEIR Project 10

Objectives. 11

According to the FEIR, the One and Two Transformer Alternatives are designed to meet 12

planning assumptions developed in 2014 by SCE which include assumptions that have since 13

changed as reflected in the CAISO’s 2015-16 Transmission Plan (2016 Plan). As compared to 14

the Proposed Project, these Alternatives reduce the import capability into the Western LA Basin 15

by reducing the number of 500/220kV transformer banks from three (Proposed Project) to either 16

one or two transformers. The reduced import capability, however, will limit the ability to 17

accommodate changes in the type and location of renewable resources located outside the 18

Western LA Basin. These resources will be imported through Mesa Substation to service a large 19

3 FEIR, Section 1.2.2.1, page 1-3, lines 17-25. The objectives identified by the CPUC are as follows:

1. Address anticipated violations of the NERC Standard TPL-001-04 (NERC 2015), WECC Regional Business Practice TPL-001-WECC-RBP-2 (WECC 2011), and CAISO Planning Standards that would occur upon retirement by December 31, 2020, of generators that use OTC.

2. Avoid introduction of new violations of NERC, WECC, and CAISO standards. 3. Maintain electrical service by minimizing service interruptions during project implementation.

4 FEIR, Section 1.2.4.1, page 1-7, lines 4-8.

3

portion of the Western LA Basin and replace the capacity provided from OTC resources. Due to 1

state policy, generation resources are shifting from in-basin fossil fueled power plants to 2

renewable resources located outside of the Western LA Basin. In general terms, resource 3

portfolios are moving to a 33% Renewable Portfolio Standard (RPS) by 2020 and, with the 4

passage of Senate Bill 350, the RPS goal will be increased to 50% by 2030.5 5

The types of resources and their locations have been recently updated by the CAISO in 6

its 2016 Plan. Specifically, the CPUC and CEC provided updated 33% renewable portfolios to 7

the CAISO for analysis.6 This portfolio is the basis for modeling renewable resources for 8

CAISO’s Local Capacity Requirement (LCR) cases as reflected in the 2016 Plan. In contrast, the 9

2014 power flow data used to develop the Alternatives is SCE’s 2014 reliability assessment case. 10

This case is several years older and does not reflect the 33% renewable portfolio assumptions in 11

the CPUC and CEC letter but instead focused on high imports from any resource type outside 12

SCE’s service territory that would stress SCE’s transmission system during peak load periods. 13

Though this case does show the need for the Mesa 500 kV Substation, it is not the only reference 14

to ensure a reliable transmission system. A comparison of the SCE 2014 case versus the 2016 15

Plan, based on the CPUC and CEC renewable portfolios, shows a significant difference in 16

renewable resources. The renewable resource output in the Tehachapi area north of Mesa 17

Substation increased by over 1,900 MW, resulting in an increase of over 1,100 MW on the lines 18

feeding into Mesa Substation. 19

5 SCE recognized the need for flexibility to accommodate the siting of future generation as

encapsulated in its Project Objective 3, which was deleted from the Objectives in the DEIR. (SCE PEA Section 2.2 Project Objective 3, Page 2-2., dated March 2015):

Allow greater flexibility in the siting of future generation projects to meet local reliability needs in the Western Los Angeles Basin while reducing the total amount of new generation required by providing additional transmission import capability.

6 http://www.caiso.com/Documents/Revised2015-2016RenewablePortfoliosTransmittalLetter.pdf

4

The One Transformer Alternative results in reliability issues when examined under both 1

the SCE 2014 case as well as the 2016 Plan. The One Transformer Alternative modeling in the 2

FEIR utilized an impedance value of 0.121 per unit. This results in power flows equal to 98% of 3

the emergency rating of the existing transmission lines in the Serrano Corridor7 with the one 4

1600 MVA transformer bank at Mesa Substation loaded to 96% of its rating when examined 5

using the 2014 case, just below an overload scenario. One of the reasons the Proposed Project is 6

needed is to relieve the Serrano Corridor when OTC units retire since the Serrano Corridor is 7

also a transmission import path into the Western LA Basin. Any impedance value larger than the 8

selected 0.121 per unit value would divert power away from the one transformer bank at Mesa 9

Substation to the Serrano Corridor, causing power flows to reach or exceed the emergency rating 10

of those Serrano Corridor transmission lines. If the impedance is lowered to 0.110 per unit, more 11

flows would be directed to the one transformer bank which would be at 100% of its rating under 12

base case condition (N-0, no transmission elements are lost). Any lower impedance will overload 13

the one transformer bank alternative. The 0.121 per unit impedance was selected to narrowly 14

balance the loading of the one transformer bank at Mesa Substation and the loading of the 15

transmission lines in the Serrano Corridor. 16

But, further, when examined under the CAISO’s updated 2016 Plan, using the 33% 17

renewable generation allocations directed by the CPUC and CEC, the 0.121 per unit impedance 18

would cause the single transformer bank to overload to 101% and the Serrano Corridor would be 19

at 100%. If the impedance is adjusted down to relieve the transformer bank at Mesa Substation, 20

the Serrano Corridor would increase above 100%. Therefore, utilizing the most recent 33% 21

7 FEIR, Appendix B, Contingencies 4 & 5, column titled “One 1600-MVA Transformer Alternative.”

5

renewable portfolio, there is virtually no impedance value that can be chosen for the transformer 1

for which the One Transformer Alternative is a reliable solution. 2

It appears the 0.121 per unit impedance value was specifically selected in order to satisfy 3

just those narrow requirements of the 2014 case. This is not the way transformer impedances are 4

typically selected. SCE uses standard impedance values for large transformers and selects the 5

number of transformers in parallel to satisfy capacity requirements rather than trying to match a 6

given transformer bank’s impedance to system conditions for one power flow case. As seen by 7

the changes from the 2014 case to the 2016 Plan, planning assumptions can change significantly 8

over even a short period of time and the components of the overall transmission system need to 9

be designed with enough flexibility to accommodate these changes. 10

The 0.121 per unit value of the single 1600 MVA appears to be atypical. Banks of 11

similar size located at Los Angeles Department of Water & Power’s Rinaldi Substation and 12

Bonneville Power Administration’s Maple Valley Substation have impedance values less than 13

0.08 per unit. A 1600 MVA bank with a 0.121 per unit impedance will likely be a custom 14

designed transformer. This would necessitate a unique transformer installation and the 15

procurement of perfectly matched spares in order to maintain system resiliency. 16

Both the One Transformer and Two Transformer Alternatives, as described in the FEIR 17

require a Remedial Action Scheme (RAS). Upon the loss of two transmission lines, the RAS will 18

open two other transmission lines in the Serrano Corridor. This results in the loss of four 19

transmission lines that serve the Western L.A. Basin. This degrades system reliability by creating 20

a system which will be vulnerable and unlikely to withstand the next contingency. The Proposed 21

Project with three 1120 MVA transformer banks does not require a RAS and is therefore more 22

reliable. 23

6

The Two Transformer Alternative includes two 1120 MVA transformer banks and a 1

RAS. As described in the FEIR, the transformers would have an operating requirement wherein 2

they would be connected in parallel and switched as one. In the event that one transformer bank 3

failed, the other transformer would automatically go out of service.8 This arrangement is 4

necessary to prevent the overload of the remaining bank when one bank is lost. The FEIR 5

categorizes this event as the loss of two elements (N-1-1 or N-2).9 6

This configuration, from a planning and operational perspective, is functionally 7

equivalent to a single 2240 MVA (2 x 1120 MVA) transformer bank. The loss of the two banks 8

in this configuration should actually be considered as the loss of one element (N-1). This would 9

require the system to remain secure for the next contingency. When this alternative is modeled 10

as specified in the FEIR utilizing the 2016 Plan, the loss of the transformers followed by the loss 11

of the Mesa – Lighthipe line will overload the Mesa – Laguna Bell line to 106%. This is a 12

violation of NERC reliability standards and is less reliable than the Proposed Project comprised 13

of three independent 1120 MVA transformers in which the loss of one transformer will not 14

overload the remaining two. 15

The FEIR narrowed the focus to system planning assumptions available in 2014, and the 16

One and Two Transformer Alternatives reflect solutions that satisfy only that narrow focus, 17

facilitated by the choice of a precisely selected impedance value for the one transformer 18

alternative. The updated information available in the 2016 Plan results in the FEIR One & Two 19

Transformer Alternative failing to meet the FEIR Project Objectives 1 and 2 in addressing 20

reliability standard violations due to OTC retirements, and potentially introducing new reliability 21

standard violations. The Proposed Project with three transformer banks has the requisite 22

8 FEIR, Section 3.0 Alternatives, page 3-10, lines 14-17. 9 FEIR, Responses to Comments at 341.

7

flexibility to accommodate the 33% renewable resource assumptions. Not recognizing the 33% 1

renewable portfolio reflected in the 2016 Plan in the design of the One and Two Transformer 2

Alternatives would likely result in an immediate initiation of an additional transmission project 3

in the CAISO’s Transmission Planning Process to install additional 500/220kV transformer 4

capacity at Mesa Substation. 5

Also, it should be noted that although the OTC compliance date for the generating plants 6

in SCE’s service territory is December 31, 2020, the electrical system reliability concern does 7

not become critical until the next summer peak loading period, which is typically presumed to 8

begin on June 1, 2021. As noted below, the Proposed Project is the only Alternative evaluated 9

that has an opportunity to meet this need date. 10

Further, the FEIR suggests that the OTC compliance date of December 31, 2020, as 11

stated in Project Objective 1, is not an objective but a “target date” and that the SWRCB may 12

extend the compliance date.10 Though the Statewide Advisory Committee on Cooling Water 13

Intake Structures (SACCWIS) exists to advise the SWRCB to not disrupt California’s electrical 14

power supply,11 there is no evidence that SWRCB will definitively extend the compliance date to 15

allow the OTC plants in SCE’s service territory to continue operation beyond December 31, 16

2020. 17

Even if the SWRCB were to extend the OTC compliance date, there is evidence that OTC 18

units may not be available as the deadline is approached. Per its Power Purchase Agreement,12 19

AES is in the process of repowering the Alamitos Generating Station from 1,936 MW to 640 20

10 FEIR, Responses to Comments at 322. 11 http://www.waterboards.ca.gov/water_issues/programs/ocean/cwa316/saccwis/ 12 See CPUC Decision D.15-11-04.

8

MW by December 31, 2020, which includes plans to demolish all six existing OTC units.13 In 1

addition, AES, as the owner of the Redondo Beach generating plant, and the City of Redondo 2

Beach sent a joint petition to the CEC to suspend an application to repower that facility. AES is 3

currently searching for a third-party or partner to develop the 50-acre Redondo Beach generating 4

plant site for non-industrial use.14 5

B. All FEIR Alternatives Other Than the Proposed Project Would Unreasonably 6

Delay Compliance with the December 31, 2010 OTC Retirement Policy 7

Compliance Date And Would Not Meet Project Objective 8

1. Updated schedule information results in a potential for the Proposed 9

Project to be operational in June 2021. 10

Since filing the PEA, SCE has continued to refine the engineering scope and has 11

responded to numerous data and information requests from the CPUC that have resulted in scope 12

refinements to and/or additional engineering information related to the Proposed Project scope. 13

This effort culminated in the submittal of scope refinements via geographical information system 14

(GIS) data to the CPUC in June 2016. That GIS data set is representative of the scope 15

refinements SCE made to the project components since filing of the PTC application. However, 16

some additional final engineering details have occurred since June 2016, and are expected to 17

continue through the execution of project construction. 18

13 Report of the Statewide Advisory Committee on Cooling Water Intake Structures, April 2016, pp. 3,

11-12. Available at: http://www.google.com/url?sa=t&rct=j&q=&esrc=s&source=web&cd=1&ved=0ahUKEwjj64y0i7PQAhXHgFQKHcN9DY0QFggdMAA&url=http%3A%2F%2Fwww.cpuc.ca.gov%2FWorkArea%2FDownloadAsset.aspx%3Fid%3D11675&usg=AFQjCNFuLP3awofdPbsRtQlE35qBL7dsuQ

14 See, http://www.aescalifornia.com/new-projects/redondo-beach.

9

Additional studies that have been completed as part of SCE’s refined engineering include 1

additional geotechnical borings at various locations throughout the project area, hydrological 2

studies, underground utility potholing along the existing roads surrounding the project area, 3

various environmental surveys, and a property rights assessment. As a result of the refined 4

engineering and studies, as it relates to the proposed installation of transmission, 5

subtransmission, distribution and telecommunications circuits, the engineering team has refined 6

the locations, and sizes of structures. 7

Regarding the civil design, the site grading plans have been updated based on both 8

constructability comments received from SCE substation construction personnel as well as plan 9

check review comments received from the city of Monterey Park. The DEIR shows that the 10

Proposed Project would require 100,000 cubic yards of soil to be imported in Phase 1 and 50,000 11

cubic yards of soil exported in Phase 3. The overall sequencing of the grading activities has been 12

optimized to take advantage of all potential sources of fill soil on the site in order to minimize 13

the amount of import required to accomplish the Project. The refinement efforts for the 14

Proposed Project resulted in Phase 1 now requiring only 5,000 cubic yards to be imported and 15

only 7,000 cubic yards to be imported in Phase 3. The ability to move the available soil on site 16

rather than import it saves approximately four months on the overall schedule. See attached 17

Appendix A for a summary of truck trips and import/export quantities by phase for the Proposed 18

Project. 19

SCE has determined that construction of the Proposed Project could be accomplished in 20

approximately 48 months rather than the potential 55 month range originally represented in the 21

PEA. This reduction in construction duration was based upon review of the scope as identified in 22

the refined engineering, and further evaluation of the line outages and other constraints and 23

10

opportunities that affect how SCE could construct the Proposed Project. Planning from 1

construction personnel has allowed for the new 220 kV switchrack to be constructed in one effort 2

rather than in two different phases (i.e., one-half of the switchrack at a time). In addition, the 3

refinement of the grading sequencing for the Proposed Project allows for most of the required 4

soil to be moved on site rather than having it imported from and/or exported to remote quarry 5

locations. The efficiency of these changes has resulted in the overall seven month reduction in 6

anticipated construction duration. 7

It must be noted, however, that this construction duration estimate is contingent upon 8

several potential constraints, such as electrical line outage availability, adverse weather, and 9

nesting bird or other similar environmental issues, as described in more detail below. 10

With regard to line outage availability constraints, since filing the PTC application, SCE 11

has been able to better understand and assess the necessary line outages that SCE would need to 12

request from the CAISO. A majority of the Proposed Project construction would require SCE to 13

request circuit outages from the CAISO. Based on past operating experience throughout the SCE 14

system, SCE believes that it is reasonable to assume that extended duration line outages (i.e., 15

several months in length) and other temporary line reconfigurations would be required to 16

facilitate safe and efficient construction of the Proposed Project in order to minimize potential 17

overloading of the remaining in-service lines. While SCE cannot predict what outages CAISO 18

will approve and exactly when those outages would occur, preliminary planning reviews by SCE 19

assume that the necessary outages would be available at the required time(s). 20

The high risk of environmental delays (e.g., nesting birds) is another constraint SCE 21

considered when developing the updated construction schedule. The 48-month construction 22

duration of the Proposed Project requires that SCE construct during four annual nesting seasons. 23

11

It is worth noting that the longer construction durations of the FEIR Alternatives, as described 1

below, could require that SCE construct during five or even six nesting seasons, increasing the 2

potential for those risks to be realized. Based on the complexity explained previously related to 3

line outages for the Proposed Project, environmental factors could ultimately require critical 4

construction activities to come to a complete stop if, for example, SCE would be unable to place 5

a previously granted line outage back into service and then also be unable to request another line 6

outage in order to continue with construction of the Proposed Project in another location. 7

According to the schedule identified in the Ruling,15 a Final Decision could be issued as 8

early as February 9, 2017.16 If this date holds, SCE would be able to initiate certain post-decision 9

pre-construction activities that would allow major construction efforts to start during the second 10

quarter of 2017. If so, then the refined 48-month construction duration would result in a 11

projected June 2021 operating date for the Proposed Project, which would meet the system 12

electrical need date associated with the December 2020 OTC policy requirement.17 As noted in 13

the PEA, the relocation of the MWD water line, which is estimated to take approximately 5 14

months of construction, must be completed as early as possible in order to build the balance of 15

the new substation facilities within the project construction schedule. However, MWD is not able 16

to take that water line out of service between April 1 and October 1 of any given year. For the 17

water line to be relocated and to be on the same grade as the future substation, the alignment of 18

the future water line must be cleared of vegetation and graded, which requires approximately 14 19

feet of fill in some areas of the property. Since bird nesting season typically runs from 20

approximately February through August and vegetation on the project site provides areas for 21

15 Ruling at 4-5. 16 Ruling at 5. 17 See, Supra, Section II.(A) at 7.

12

many common species to nest, it is imperative, in order to make the soonest online date, that 1

SCE receives a Notice To Proceed (NTP) to clear vegetation from the necessary construction 2

areas in order to accommodate the grading requirements of the Project. If all the requirements 3

listed below are met, SCE believes that the Proposed Project can achieve a June 2021 operating 4

date, which, as discussed in other sections, meets the reliability need resulting from the 5

December 2020 OTC policy retirement date and is substantially earlier than other alternatives’ 6

operating dates. If, however SCE cannot obtain a timely NTP to initiate these certain 7

construction elements, or if any of the other assumptions listed below are not met, the online date 8

would be impacted accordingly. However, assuming that those items listed below would apply 9

equally to all of the FEIR Alternatives, the operating date of the Proposed Project would still be 10

sooner than any of the three FEIR Alternatives. 11

The list of critical schedule assumptions, include, but are not limited to, the following: 12

The Commission will issue a Final Decision (FD) on or before the February 9, 2017 13

regular meeting; 14

The Commission’s FD approves SCE’s Proposed Project as defined in the FEIR; 15

The Energy Division staff will accept and review SCE’s request for a limited notice to 16

proceed (NTPR) for vegetation clearing and bird nesting deterrents prior to a Final 17

Decision and issue the limited NTP either concurrent with or within 10 business days 18

after the FD; 19

There are no delays resulting from any supplemental environmental review/permits by 20

federal and state agencies; 21

The Commission promptly issues any required variances and no Petitions for 22

Modification (PFMs) will be required; 23

13

The management of common and abundant nesting birds and other species so that no 1

buffers or work stoppages will be required; 2

Any necessary permits are issued by relevant resource agencies; 3

SCE will be able to enter into contracts for materials and construction services according 4

to schedule, that all contractors, consultants, and suppliers will deliver on-time 5

performance under an expedited construction schedule which may involve extended and 6

weekend hours, and that all underlying construction and scheduling assumptions will be 7

realized; 8

The U.S. Fish and Wildlife Service would timely provide SCE with incidental take 9

authorization for listed species present in any designated environmentally sensitive areas 10

where construction will occur; and 11

There will be no unforeseen or unexpected contingencies, such as weather delays, natural 12

disasters, or other force majeure events that delay construction, design, or permitting 13

efforts. 14

In other words, SCE’s time estimates contained in this testimony are based on optimistic, 15

though not unrealistic, assumptions, providing a best case scenario aimed only to help the parties 16

understand what a schedule may look like for the Proposed Project. These estimates also do not 17

account for the substantial risk of potential environmental delays during the construction of the 18

new substation. 19

14

2. All FEIR Alternatives other than the Proposed Project result in 1

unreasonable schedule delays. 2

i. One Transformer Alternative – 10 month delay 3

The One Transformer alternative will result in an approximate 10 month delay beyond 4

the anticipated June 2021 online date for the Proposed Project, resulting in, at best, a March 31, 5

2022 completion date. The calculation of 10 months is based on, and in comparison to, the 6

estimated construction duration of the Proposed Project. The projection of the completion date 7

for the One Transformer Alternative assumes the same optimistic assumptions as the Proposed 8

Project listed above. The information provided below discusses some of the specific factors that 9

were accounted for in calculating the total delay. It was also assumed that some of the items 10

discussed below could be completed in parallel with each other, which minimizes the aggregate 11

delay as much as possible. 12

SCE expects that it will take approximately 2 months after the issuance of the FD to 13

confer with the Energy Division staff and their FEIR consultants to verify the details of the 14

proposed switchrack and transformer arrangement that was used to develop the substation 15

boundary line show in Figure 3.4-1 in the FEIR. During the DEIR comment period, SCE asked 16

the CPUC for that detailed information, but was informed that no such information was 17

available, only the outline of the alternative was developed. It is critical to understand how the 18

alternative was designed in order to accomplish its intended goal of reducing the disturbed area 19

by nearly 20 acres when compared to the Proposed Project. SCE believes that the high-level 20

design did not fully consider the overall site terrain and the amount of grading that would still 21

15

need to take place.18 Also, the alternative eliminated the area on the northeast corner of the 1

property where SCE has proposed to install the replacement operations theater. The new 2

operations theater is needed because the existing operations theater will need to be demolished to 3

clear the area where the 500/220 kV transformer banks will be located, regardless of which 4

alternative is selected. Additional impacts related to the operations theater are discussed below. 5

Once the conceptual design is confirmed, SCE will need approximately 2 months to 6

compare the overall impacts of this revised layout with the current overall grading plan to ensure 7

that the changes to the substation perimeter plan on the east end of the substation, including any 8

potential location of the new operations theater, will not result in significant elevation changes to 9

the far west end of the substation pad. This area is of particular concern because not only must 10

the pad be designed to accomplish correct site drainage, but SCE must still maintain a certain 11

amount of cover over the top of the future relocated MWD waterline, which is aligned just 12

outside of the western portion of the new substation layout. In addition, to maintain compliance 13

with applicable Low Impact Development (LID) requirements, the on-site storm drain retention 14

basin must be designed to contain the calculated volume of storm water (2.8 acre feet in final 15

design) based on the overall site design in a 100 year storm. With a fixed pipe size (constrained 16

outflow) and elevation of the existing storm drain inlet at Markland Drive, which the retention 17

basin eventually drains into, the elevation of the future substation pad at the top of the retention 18

basin is therefore also constrained. This results in a certain fixed elevation that must be 19

maintained in that area of the property. Once these grading plan revisions are evaluated and/or 20

completed, SCE must resubmit these plans to the city of Monterey Park to obtain a grading 21

permit. This process, including any revisions that must be made to the plans due to review 22

18 See attached Appendix B, Grading Impacts of the Two Transformer and GIS Alternatives.

16

comments, could take as little as one month, but is more likely to take between two and three 1

additional months. 2

During this same time period, SCE would initiate the required changes to the substation 3

electrical design plans. These modifications would incorporate the alternative’s changes to the 4

“line and bus configuration” of the 220 kV switchrack, primarily reducing the number of 5

positions assigned to the transformer bank terminations. It is SCE’s understanding that this 6

alternative has no impact on the electrical design for the 66 kV or 16 kV switchracks and 7

associated transformer banks, so no re-design effort would be required for those elements. The 8

re-design of the 220kV switchrack and consequential delay in starting civil construction would 9

result in an approximate six month delay to the schedule. 10

Only after the revised site grading and 220 kV electrical designs are substantially 11

completed would SCE be able to move forward with the construction contracting process to 12

initiate the start of construction. 13

There would be a significant schedule impact on the site grading work planned to occur 14

during Phases 1 and 2.19 Because this alternative would not allow SCE to take full advantage of 15

the existing soil quantities available directly on the property, SCE would have to import the 16

difference from remote quarry location(s). At this time, SCE calculates that approximately 17

105,000 cubic yards would need to be imported for these two phases and an additional 60,000 18

cubic yards would then be required to be imported in Phase 3. This would result in 19

approximately 16,700 additional truck trips compared to the Proposed Project. See attached 20

Appendix A for a summary of truck trips and import/export quantities by phase. A reasonable 21

construction estimate is that each haul truck can hold up to 10 cubic yards of soil and that the site 22

19 FEIR, Section 2.0 Project Description at 2.54-2.62.

17

can effectively receive and process approximately 70 trucks per day, resulting in approximately 1

700 cubic yards of soil being brought to the site each day. While an average day of import under 2

optimum conditions on this site moves 700 cubic yards of soil, an average day of grading on this 3

site under optimum conditions would move 7,000 cubic yards of soil. Therefore, having to 4

import the required soil quantities under this alternative would result in an approximately four 5

month schedule impact for grading in Phase 1 and an additional four month schedule impact for 6

Phase 3 grading. 7

ii. Two transformer Alternative-6 month delay 8

The impacts resulting from selection of the Two Transformer Alternative as they relate to 9

the overall schedule are essentially the same as for the One Transformer Alternative, though they 10

are estimated to result in a six month delay when compared to the Proposed Project, or a 11

projected November 30, 2021 completion date. The calculation of six months is based on, and in 12

comparison to, the estimated duration of the Proposed Project. The projected completion date for 13

the Two Transformer Alternative assumes the same optimistic assumptions as for the Proposed 14

Project listed above. The information provided below discusses some of the specific factors that 15

were accounted for in calculating the total delay. It was also assumed that some of the items 16

discussed below could be completed in parallel with each other, which would minimize the 17

aggregate delay as much as possible. 18

The impacts to the conceptual design phase and detailed grading and electrical 19

engineering plans, as described above in the delays for the One Transformer Alternative will be 20

similar. The re-design of the 220kV switchrack and consequential delay in starting civil 21

construction would result in a six month delay to the schedule. The grading schedule impacts, 22

however, are different. At this time, SCE calculates that approximately 112,000 cubic yards of 23

18

soil would need to be imported for Phases 1 and 2 and an additional 20,000 cubic yards would 1

then be required to be imported in Phase 3. This would result in approximately 10,700 additional 2

truck trips compared to the Proposed Project. See attached Appendix A for a summary of truck 3

trips and import/export quantities by phase. Having to import the required soil quantities under 4

this alternative would result in an approximately four month schedule impact for Phase 1. 5

iii. GIS Alternative- 14 month delay 6

The GIS alternative will result in an approximate 14 month delay in the overall project 7

schedule when compared to the Proposed Project, resulting in a July 31, 2022 projected 8

completion date. The GIS alternative therefore has the potential to miss two separate summer 9

loading seasons. The calculation of 14 months is based on, and in comparison to, the estimated 10

duration of the Proposed Project. The projection of the completion date for the GIS Transformer 11

Alternative assumes the same optimistic assumptions as for the Proposed Project listed above. 12

The information provided below discusses some of the specific factors that were accounted for in 13

calculating the total delay. It was also assumed that some of the items discussed below could be 14

completed in parallel with each other, which would minimize the aggregate delay as much as 15

possible. 16

Similar to the One Transformer Alternative, SCE expects that it will take approximately 17

two to three months after the issuance of the FD to confer with the Energy Division staff and 18

their FEIR consultants to verify the details of the proposed GIS switchrack and transformer 19

arrangement that was used to develop the substation boundary line show in Figure 3.4-3 in the 20

FEIR. 21

Once the conceptual design is confirmed, SCE will need approximately 12-14 months to 22

execute the overall procurement process for the GIS switchracks, which includes specifying the 23

19

requirements for each of the four voltage levels (500, 220, 66, and 16 kV), initiating requests for 1

proposals from potential GIS switchrack manufacturers, receiving and evaluating the various bid 2

responses, and negotiating terms and conditions with the selected vendor(s). Once the awards 3

have been made, it is reasonable to assume that it will take those vendor(s) anywhere between 4

six months (for the fairly simple16 kV switchrack) to at least 12 months (for the more 5

complicated 220 kV switchrack) to substantially complete their overall design and be ready to 6

initiate major material procurement and site construction activities. The redesign will take at 7

least 13 additional months before construction could begin on the 220, 66, and 16kV switchracks 8

in Phase 1. 9

About six months after the selected GIS vendor(s) have started their engineering process, 10

there should be enough physical design information available to allow for a review of the overall 11

impacts of this revised layout with the current overall grading plan. This would initiate the same 12

two month period to revise the site grading plans as described in the One Transformer 13

Alternative, as well as the two to three month additional time period needed to resubmit these 14

plans to the city of Monterey Park to obtain a grading permit. Overall, this process to update the 15

site grading plans is likely to overlap with the completion of the GIS switchrack physical and 16

electrical design activities described above. 17

After the site grading and GIS switchrack designs are completed, the substation 18

construction personnel could move forward with the construction contracting process to initiate 19

the start of construction. Because the construction of GIS switchracks are generally more 20

complicated than air insulated switchracks, there would be a slight increase to the construction 21

schedule for the electrical facilities, especially the 220 kV switchrack because of its large 22

number of positions required to connect the transmission lines and transformer bank leads. There 23

20

would be a slight schedule impact on the site grading work. Because this alternative would not 1

allow SCE to take full advantage of the existing soil quantities available directly on the property, 2

SCE would have to import additional soil onto the site. At this time, SCE calculates that 3

approximately 44,000 cubic yards would need to be imported for Phases 1 and 2 and another 4

20,000 cubic yards would need to be imported in Phase 3. This would result in approximately 5

5,200 additional truck trips compared to the Proposed Project. See attached Appendix A for a 6

summary of truck trips and import/export quantities by phase. The import of soil in Phases 1 and 7

2 would extend the grading period by an additional three months but would not extend the final 8

completion date of the project because this work can be done in parallel with the redesign of the 9

electrical engineering package. On the other hand, the additional soil import requirements in 10

Phase 3 would result in an approximately one to two month schedule impact. 11

iv. Delays due to Alternatives-dictated operating theater construction 12

Construction of the operating theater as proposed for the FEIR Alternatives would 13

increase the project cost significantly and could impact the construction duration. One of the 14

unique features of Mesa Substation is that it is one of SCE’s limited number of manned 15

switching centers with an operating theater. Operating theaters are manned 24 hours a day, every 16

day of the year, and are responsible for the on-going operation of not just the host substation but 17

also approximately 100 other nearby substations, along with the transmission, subtransmission, 18

and distribution lines that connect them with the rest of the grid. One of the challenges with this 19

project is being able to keep the existing substation and operating theater completely functional 20

while the new facilities are being constructed. The existing operating theater is located in an area 21

that will eventually be replaced by the new 500/220 kV transformer banks, regardless of which 22

of the four project alternatives (e.g., the Proposed Project versus the three FEIR alternatives) is 23

21

selected. The Proposed Project utilizes an area at the northeast corner of the property, near the 1

intersection of Potrero Grande and Greenwood, for the location of the replacement operating 2

theater, as shown in Figure 2.4 of the FEIR. SCE selected this location for the new operating 3

theater because it is one of the few, if not only, places on the site that is outside of the location 4

for the future switch racks and is not obstructed by any existing facilities. As currently planned 5

for the Proposed Project, the new operating theater would be constructed in Phase 1 and would 6

take approximately 16 months to build, including the installation of all necessary computer and 7

telecommunications systems that would allow operating personnel the ability to manage the 8

electrical system. This plan would relocate personnel from the existing operating theater to the 9

new building prior to the beginning of Phase 3. If the personnel are not relocated by the 10

beginning of Phase 3, then the project would be delayed significantly until the existing building 11

was vacated. Each of the three project alternatives shown in the FEIR show the eastern boundary 12

of these alternatives overlaying the current fenceline of the existing substation, which would 13

constrain SCE’s ability to construct the operating theater in the area outside the fenceline as 14

planned for the Proposed Project. As far as SCE can determine by reviewing the project 15

descriptions associated with the three FEIR alternatives, particularly FEIR Figures 3.4-1, 3.4-2, 16

and 3.4-3, there is no provision considered in any of them for the relocation of this building 17

anywhere on the existing Mesa Substation property, nor does it appear there is room within the 18

alternatives’ footprints for placement of the buildings. If SCE were not allowed to construct in 19

the area as shown in the Proposed Project, but could somehow find a place to construct a new 20

theater within the alternatives’ footprints, SCE would have to relocate all of the operating 21

personnel and, more importantly, the telecommunication feeds, into a temporary facility, make it 22

compliant with all applicable physical and cyber security requirements, and install the required 23

22

video boards and equipment to make it fully functional. The cost impacts to the project, and 1

impacts to the people that work in that operating theater, if SCE were to create a temporary 2

facility off site, would be quite significant. Additionally, without a new operating theater to 3

move telecommunication lines over to in advance of demolishing the old theater, it is likely there 4

would be an impact to the schedule and final completion of all three FEIR Alternatives in 5

addition to the delays discussed above. Rather than create a temporary facility, the other unlikely 6

option is to wait for part of the existing substation to be removed, construct the new operating 7

theater, and then relocate the telecommunication lines and personnel. This would postpone the 8

grading and civil construction of the new 500kv switchrack (for the Proposed Project, and all 9

three Alternatives alike) by as much as 16 months which ultimately delays the final completion 10

date of the project(s) by 16 months. 11

C. Environmental Considerations Contribute to Infeasibility of Alternatives 12

1. The Two Transformer and GIS Alternatives result in additional grading 13

disturbance not captured in the FEIR. 14

Figure 5-1 in the FEIR depicts the comparison of the project alternatives’ footprints. 15

Given that certain portions of the project alternatives’ footprints in that figure line up with the 16

existing substation’s perimeter fence, it appears that Figure 5-1 also intends to reflect the 17

respective future perimeter fence alignment(s) for each alternative. The FEIR then calculates the 18

supposed reduction in impacted acreages based on those fence lines. However, the project 19

alternatives’ footprints depicted in Figure 5-1 do not appear to consider the actual site 20

topography and associated slope requirements and therefore do not accurately capture the total 21

area impacted by each alternative. Specifically, both the Two Transformer Alternative and the 22

GIS Alternative will require significant cut/fill slopes in order to make up the difference between 23

23

the future substation pad finished elevation and the elevation of the terrain immediately adjacent 1

the project alternatives’ footprints. The elevation difference is in excess of 30 feet in some areas. 2

Consequently, these adjacent areas will be significantly altered with cut/fill slopes that will 3

extend up to an additional 75-plus feet into the hillside south of the existing substation thereby 4

reducing the total acreage of potentially undisturbed area, which is specifically the “foraging 5

habitat” that the alternatives intend to preserve. The total acreage of additional impacted area is 6

approximately 2 acres for both the Two Transformer Alternative and the GIS Alternative, though 7

the specific areas impacted are slightly different for each alternative. See attached Appendix B 8

for the approximate location of the slopes for the Two Transformer Alternative and for the GIS 9

Alternative. Therefore, the acreage disturbance calculations associated with these two 10

alternatives are underestimated in the FEIR, i.e., there will be more ground disturbance 11

associated with these two alternatives than assumed in the FEIR and an equivalent reduction in 12

the benefit that these alternatives supposedly provide in preserving that ‘habitat’ area. Finally, 13

regardless of which alternative is chosen between either the Proposed Project or any of the three 14

FEIR alternatives, it is worth noting that the project would also require a significant amount of 15

temporary disturbance in the area south of the substation perimeter in order to replace the 16

existing 220 kV and 66 kV overhead lines traversing that area with new overhead and/or 17

underground lines, as well as the installation of a new storm drain in that area to handle 18

stormwater run-on from the adjacent Monterey Park Market Place commercial development. 19

24

2. The Potential for fugitive dust increases with the Alternatives; not 1

decreases. 2

The Energy Division’s response to comment D1-18 in SCE’s Comments on the Draft 3

Environmental Impact Report (SCH #2015061014) for the Mesa 500 kV Substation Project 4

(A.15-03-003) dated June 27, 2016 states the following: 5

The One-Transformer-Bank Substation Alternative would slightly 6 increase total exhaust emissions but would still substantially 7 decrease fugitive dust created when compared to the proposed 8 project. On balance, there would be a moderate reduction in air 9 quality impacts. 10

11 This conclusion is in error given several factors because the potential for fugitive dust 12

actually increases if soil must be imported for grading, as is the case with all three FEIR 13

Alternatives. 14

First, per AQMD regulations and licensing requirements, SCE is responsible for 15

complying with mitigation measures to decrease if not eliminate fugitive dust. It is not accurate 16

to suggest that one alternative would substantially increase or decrease its total production of 17

fugitive dust; because SCE must mitigate for fugitive dust, it should only be analyzed based on 18

potential risk of creating fugitive dust. Even so, the Energy Division’s response appears to 19

suggest there is less risk with importing soil rather than moving it on site. This just isn’t the case. 20

Moving soil on site requires less handling than importing soil. A single 637 Scraper (earthmover) 21

can move approximately 25 cubic yards in one load. On the other hand, a single haul truck (dual 22

trailer bottom-dump) used for importing soil has to be loaded with 5 to 6 buckets from an 23

excavator or loader and only holds 10 cubic yards per truck. The risk for fugitive dust is 24

significantly more when handling the same quantity of soil multiple times. 25

25

Second, a significant source of risk for fugitive dust is having open areas of cut or fill 1

during windy days. In the same response to SCE’s comments on the DEIR, the Energy Division 2

acknowledged that construction methods for moving soil on site are 10 times faster than having 3

to import the same quantity of soil from offsite. The grading durations for the project alternatives 4

extend the overall grading activities by an additional four to eight months depending on the 5

alternative. Consequently, fill areas will remain open and unfinished for these extended 6

durations, which significantly increases the associated risk for fugitive dust. 7

Further, given the current drought situation in southern California, the water required for 8

managing the risk of fugitive dust over this extended duration could be another significant 9

impact to local water resources. 10

3. Impacts to biological resources under the Proposed Project are already less 11

than significant. 12

The FEIR found that impacts to biological resources due to the Proposed Project were 13

less than significant. The area sought to be preserved via the One Transformer, Two Transformer 14

and GIS Alternatives is ruderal, and mapped as “non-native” vegetation, as noted in the FEIR, 15

Chapter 4, Section 4.3. In four years of biological survey data, there has been no documentation 16

of successful nesting by listed species in this area. Additionally, as noted in the FEIR, Section 17

4.3 (4.3.3.3), with the implementation of applicant proposed and mitigation measures, impacts to 18

coastal California gnatcatcher and its habitat would be less than significant. Further, SCE will 19

obtain all necessary permits to mitigate the less-than-significant impacts of the Proposed Project 20

in this area. 21

26

D. The GIS Alternative Would Cost Between $64-$74 Million More Than the 1

Proposed Project. 2

Subsequent to the issuance of the FEIR, SCE attempted to quantify the potential cost 3

increases associated with the GIS Switchrack Alternative.20 SCE conducted this cost comparison 4

for all four voltage levels (16, 66, 220, and 500 kV) of the entire substation, as was described in 5

the FEIR in both Chapter 3 “Description of Alternatives” (page 3-14, lines 5-6): 6

This alternative would involve construction of the project as 7 proposed, except the substation would be built with gas-insulated 8 equipment on switchracks (emphasis added) rather than air-9 insulated equipment 10 11

and in Chapter 5 “Comparison of Alternatives” (page 5-20, lines 31-32): 12

The 500-kV, 220-kV, 66-kV, and 16-kV switchracks (emphasis added) would be 13

about one-tenth the size of the switchracks for the proposed project. 14

SCE used two separate and independent efforts focusing primarily on the differences in 15

material and equipment costs between a GIS option and a more traditional air-insulated 16

switchrack (AIS) option. This effort should be considered as only a “rough order of magnitude” 17

type estimate, as SCE did not perform a formal cost estimating effort nor were additional cost 18

components included in the analysis, including those related to any engineering redesign efforts, 19

20 SCE did not pursue a similar cost analysis for the One and Two Transformer alternatives. Upon

cursory review, it was anticipated that any potential savings in costs due to the reduction in transformers compared to the Proposed Project would likely be negligible to the overall budget, as those savings would be substantially offset by the combination of engineering redesign efforts, the additional costs of imported soil for site grading, and miscellaneous construction overhead costs due to the longer schedule duration, among other factors. In addition, because the system planning analyses showed that these two alternatives were both likely to almost immediately trigger a CAISO project to increase transformer capacity at Mesa, as well as all the other issues with those alternatives, such as reliability, missing OTC compliance date, etc., the costs for those alternatives may actually be greater than the Proposed Project, but not likely enough to warrant a cost analysis similar to the GIS alternative.

27

the additional soil imports that would be required, or any additional construction management 1

overhead costs resulting from the extended construction schedule resulting from this alternative. 2

The first estimate was performed in-house by SCE apparatus engineering department 3

members. Their approach was to gather pricing information from either recently completed SCE 4

projects that utilized GIS technology or pending projects that plan to utilize GIS technology. 5

This information was then used to extrapolate an equivalent price for the scope related to Mesa 6

Substation, considering changes in voltage levels and number of switchrack positions required at 7

each location. Similarly, the cost for the AIS approach was calculated based on recent material 8

procurement efforts that SCE has completed for equipment similar to what would be required for 9

installation as part of the Proposed Project. Overall, the results of the SCE engineering effort 10

showed that the GIS option would cost at least $74 million more than the AIS option, just in 11

material expenses alone ($97M total for GIS versus $23M total for AIS). The majority of this 12

differential was associated with the 220 kV switchrack. 13

The second estimate was performed by Black & Veatch (B&V), one of SCE’s substation 14

engineering design contractors. For the GIS cost estimate, similar to the SCE effort, it developed 15

an appropriate GIS material list that would satisfy the needs of the Project, gathered from a 16

variety of other projects that it has been involved with across the country, and determined the 17

typical pricing for each type of material that would be combined for the total pricing estimate. 18

The approach for the AIS cost estimate was to develop a project equivalent scope utilizing the 19

“Per Unit Cost Guide” that each Participating Transmission Owner (PTO), including SCE, 20

provides to the CAISO to “allow interconnection customers to learn the anticipated costs of 21

procuring and installing facilities required to interconnect to the applicable PTO.” Overall, the 22

results of the independent B&V effort showed that the material expenses related to the GIS 23

28

option would cost at least $64 million more than the AIS option. Similarly, the majority of the 1

cost increase is associated with the 220 kV switchrack. In addition, B&V also generated a rough 2

order of magnitude cost estimate for the additional soil import that would be required for this 3

alternative, resulting in a number of approximately $14.5 million. 4

E. The 1600 MVA Transformer Bank is Not an SCE-Approved Design Standard. 5

SCE included a project objective (number 7) in its PEA to design and construct the 6

Proposed Project in accordance with SCE’s approved engineering, design and construction 7

standards. The 1600 MVA transformer bank associated with the One Transformer Alternative is 8

not currently an SCE standard design. The FEIR omitted this objective “…because it does not 9

speak to the underlying purpose of the project.”21 To the contrary, utilizing SCE standards will 10

enable the project to facilitate compliance with OTC requirements and meet project objectives in 11

the most timely manner and with the least environmental impact. SCE standards are developed 12

based on experience to ensure SCE constructs safe, reliable, and operable facilities on a 13

consistent basis. The use of standard-sized equipment also allows for long-term efficiencies to be 14

gained in foundation design, maintenance procedures, and the ability for spare equipment to be 15

utilized at many different locations, including sharing of equipment between utilities in 16

emergency situations, as evidenced by the large participation rates in the Spare Transformer 17

Equipment Program (STEP) that is managed by the Edison Electric Institute (EEI). 18

Upon reading the response to SCE’s comments in the FEIR, SCE reached out to 19

Bonneville Power Administration (BPA) to discuss the large 500/230kV 533 MVA transformers 20

utilized at Maple Valley Substation. It is SCE’s understanding that this size transformer was 21

selected several decades ago when utility 500 kV systems were initially being designed and 22

21 DEIR at 1-4.

29

standardization had not yet been undertaken. SCE also understands that BPA has since settled on 1

a smaller standard 500/230kV transformer bank size of 1200 MVA (3x400 MVA units) for 2

similar reasons as SCE. The smaller size is more practical to transport and assemble and, more 3

importantly, using a standard size 500/230kV transformer allows BPA, just as it allows SCE, to 4

keep interchangeable spare transformers in many diverse locations. Lastly, SCE understands that 5

while BPA expects to continue to maintain the large transformers at Maple Valley Substation, it 6

no longer designs substations using this larger, or any other uniquely-sized transformers. 7

III. 8

OVERRIDING CONSIDERATIONS 9

The FEIR indicates that the Proposed Project has significant and unavoidable impacts to 10

Aesthetics, Air Quality, and Noise.22 Nevertheless, there are multiple important benefits of the 11

SCE-proposed Mesa 500 kV Project, each of which individually outweighs the significant and 12

unavoidable impacts including, but not limited to: OTC retirement policy compliance in a timely 13

manner; maintaining NERC, WECC, and CAISO reliability standards; facilitating California’s 14

progress towards meeting its RPS goals; prudent system planning (i.e., not triggering the need 15

for an immediate capacity upgrade as the One-and Two Transformer Alternatives do); decreasing 16

environmental impacts associated with OTC by facilitating OTC retirement sooner than other 17

alternatives23; and building a project that makes the most economic sense and has the least 18

overall environmental impacts as compared to FEIR alternatives. 19

22 FEIR, Section 6.3, at 6-37 – 6-38. 23 See, http://www.swrcb.ca.gov/water_issues/programs/ocean/cwa316/ and see also

http://www.swrcb.ca.gov/water_issues/programs/ocean/cwa316/policy.shtml.

Appendix A

GRADING ESTIMATES FOR PROPOSED PROJECT AND FEIR

ALTERNATIVES

TABLE IN THE DEIRConst.Phase

Fill/ImportQuantity (CY)

Cut/ExportQuantity (CY)

Net Quantity (CY)Haul Trips(10 CY/Trip)

Import /ExportSource /

Destination

1 250,000 150,000 100,000 10,000 ImportQuarry within 45mile radius

2 5,000 70,000 (65,000) n/a 1 NoneStockpile forPhase 3

3 1 325,000 375,000 (50,000) 5,000 ExportLandfill within 45mile radius

Total 580,000 595,000 (15,000) 15,000 Import & Export

1: Cut/Export values in Phase 3 include surplus generated in Phase 2. Phase 3 raw cut volume is 310,000 CY

CURRENT PLAN BASED ON SCE PROPOSED PROJECTConst.Phase





Destination

1 1 268,000 215,000 53,000 500 ImportQuarry within 45mile radius

2 2 88,000 136,000 48,000 0 None Use in Phase 1

3 246,000 239,000 7,000 700 Import None

12,000 1,200 ImportQuarry within 45mile radius

1: Truck Trips shown for Phase 1 are reduced by the on site surplus generated in Phase 2

2: Net Export in Phase 2 is used to offset Phase 1 import requirements, resulting in zero truck trip

PLAN BASED ON ONE 1600 MVA TRANSFORMER ALTERNATIVE PROJECTConst.Phase





Destination





PLAN BASED ON TWO TRANSFORMER ALTERNATIVE PROJECTConst.Phase





Destination



3 220,000 213,000 7,000 700 ImportQuarry within 45mile radius


PLAN BASED ON GIS ALTERNATIVE PROJECTConst.Phase





Destination

1 1 307,000 215,000 92,000 4,400 ImportQuarry within 45mile radius

2 2 88,000 136,000 48,000 0 None Use in Phase 1



1: Truck Trips shown for Phase 1 are reduced by the on site surplus generated in Phase 2

2: Net Export in Phase 2 is used to offset Phase 1 import requirements, resulting in zero truck trip

Tables are preliminary using approximate estimates and are based on several assumptions alongwith information from the DEIR, FEIR, and preliminary engineering.

Totals

Totals

Totals

Totals

GRADING ESTIMATES FOR PROPOSED PROJECT AND FEIRALTERNATIVES

Appendix B

GRADING IMPACTS OF THE TWO TRANSFORMER AND GIS ALTERNATIVES

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Appendix C

WITNESS QUALIFICATIONS

SOUTHERN CALIFORNIA EDISON COMPANY 1

QUALIFICATIONS AND PREPARED TESTIMONY 2

OF CHARLES B. ADAMSON 3

Q. Please state your name and business address for the record. 4

A. My name is Charles B. Adamson, and my business address is 2 Innovation 5

Way, Pomona, CA, 91768. 6

Q. By whom are you employed? 7

A. I am employed by Southern California Edison Company (SCE). 8

Q. Briefly describe your present responsibilities at the Southern California 9

Edison Company. 10

A. I am Manager of Large Transmission Projects in the Transmission and 11

Distribution Business Unit at Southern California Edison Company (SCE). 12

My responsibilities include managing several teams who are currently 13

licensing and building bulk power and distribution transmission and 14

substation projects. 15

Q. Briefly describe your educational and professional background. 16

A. I received a Certificate in Project Management from the University of 17

California Irvine in 2000. My experience includes project management, 18

engineering, technical training, and technical support. From 1990 to 1997 19

my responsibilities included technical training and support, as well as 20

engineering, design, and process improvement. From 1997 to 2001, I 21

managed substation automation and generation divestiture projects. From 22

2001 to 2006, I managed both licensing and construction of transmission and 23

substation projects. From 2006 to 2010 I managed the licensing of large 24

transmission projects. From 2010 to present I manage multiple teams for 25

both the licensing and construction of large transmission and substation 26

projects. 27

Q. What is the purpose of your testimony in this proceeding? 28

A. The purpose of my testimony in this proceeding is to sponsor Section II.E. at 1

pages 25-26 and Section III, at page 26, in SCE’s Opening Testimony for the 2

Mesa 500 kV Substation Project, as identified in the Table of Contents. 3

Q. Was this material prepared by you or under your supervision? 4

A. Yes, it was. 5

Q. Insofar as this material is factual in nature, do you believe it to be correct? 6

A. Yes, I do. 7

Q. Insofar as this material is in the nature of opinion or judgment, does it 8

represent your best judgment? 9

A. Yes, it does. 10

Q. Does this conclude your qualifications and prepared testimony? 11

A. Yes, it does. 12



OF GARRY CHINN 3


A. My name is Garry Chinn, and my business address is 3 Innovation Way, 5

Pomona, CA, 91768. 6


Edison Company. 8

A. I am an Engineering Manager of the Transmission & Interconnection 9

Planning Group within Transmission and Distribution (T&D). In this 10

position, I am responsible for leading a group of power system engineers in 11

assessing the electric system and developing transmission facilities to ensure 12

the performance of SCE’s bulk power system is in compliance with NERC 13

Reliability Standards. 14


A. In 1991, I received a Bachelor of Science degree in electrical & electronic 16

engineering from California State University, Sacramento. I also earned a 17

Master of Science degree in electrical engineering from the University of 18

Southern California in 1994. I became a registered professional electrical 19

engineer with the State of California in 1995. Since 1991, I have held 20

positions related to the planning of the transmission system with the Los 21

Angeles Department of Water & Power, Metropolitan Water District of 22

Southern California and SCE. I have over ten years of service with SCE, all 23

with the Transmission & Interconnection Planning Group. 24


A. The purpose of my testimony in this proceeding is to sponsor Section II.A at 26

pages 1-7 in SCE’s Opening Testimony for the Mesa 500 kV Substation 27

Project, as identified in the Table of Contents. 28

1


A. Yes, it was. 3


A. Yes, I do. 5



A. Yes, it does. 8


A. Yes, it does. 10



OF LORI ILES-RANGEL 3


A. My name is Lori Iles-Rangel, and my business address is 6040 N. Irwindale 5

Avenue, Irwindale, CA 91702. 6


Edison Company. 8

A. I am an Environmental Project Manager in the Major Environmental 9

Projects group within the Environmental Services Department. In this 10

position, I am responsible for managing environmental compliance for major 11

projects during execution, including management of multi-disciplinary 12

technical teams and external consultants during all phases of pre-13

construction planning through completion of construction. 14


A. I have been with the Environmental Services Department at SCE since 2008 16

in my current capacity. Prior to this postion, I worked in the Major Project 17

Organization as a Project Analyst for major projects. Recently completed 18

work on the Tehachapi Renewable Transmission Projects and the Chino Hills 19

500kV Underground Project, where I managed environmental oversight and 20

compliance over the course of 8+ years of construction. 21


A. The purpose of my testimony in this proceeding is to sponsor Section II.(C)(3) 23

at page 23 in SCE’s Opening Testimony for the Mesa 500 kV Substation 24

Project, as identified in the Table of Contents. 25


A. Yes, it was. 27


A. Yes, I do. 1



A. Yes, it does. 4


A. Yes, it does. 6

Scott Lacy Quals.docx -1-



OF SCOTT R. LACY 3


A. My name is Scott R. Lacy, and my business address is 2 Innovation Way, 5



Edison Company. 8

A. Presently, I am a Project Engineer for transmission and substation projects 9

within SCE’s Major Projects Organization. As Project Engineer, I have the overall 10

responsibility and accountability for the execution of engineering and design 11

activities for the Project, ensuring that all activities comply with corporate policies 12

and procedures, as well as with any permitting and licensing requirements. 13


A. I received a Bachelor of Science degree in General Engineering from the 15

University of Redlands in 1990. I received a Certificate in Project Management from 16

the University of California, Irvine, in 2007. I hold a Professional Engineering 17

(Electrical) License in the State of California. 18

I joined SCE in 1990 as a regional engineer in the Distribution Engineering 19

Department. From that time until 2006, I held various jobs within that 20

department, including supervising regional and staff engineers, providing 21

engineering support to various organizations involved with the design and 22

construction of the distribution system and identifying distribution system 23

upgrades necessary to maintain capacity and reliability. Prior to my current 24

position, I was the Senior Distribution Field Engineer for SCE’s Eastern Zone. I 25

also briefly served as the Supervisor of the Radio/Television Interference (RTVI) 26

and Power Quality (PQ) groups within the Distribution Engineering organization. 27

In that capacity, I oversaw the response to customer complaints with electric service 28

Scott Lacy Quals.docx -2-

and proposed changes to SCE’s distribution system facilities and construction 1

standards in order to mitigate future power quality issues. I also represented SCE 2

at various committees and working groups sponsored by the California Energy 3

Commission related to Distributed Generation interconnection issues. 4

I began my current position as a Project Engineer in June 2006, and have 5

served in that role for various recently completed capital improvement projects 6

including the El Casco System Project, Rancho Vista Substation Project, and the 7

Devers-Colorado River (DCR, formerly known as Devers-Palo Verde No. 2 (DPV2)) 8

Project, as well as currently working on the West of Devers (WOD) Upgrade Project. 9


A. The purpose of my testimony in this proceeding is to sponsor Section II.(B)(1) 11

at pages 8-13 and II(D), at pages 23-25, in SCE’s Opening Testimony for the 12

Mesa 500 kV Substation Project, as identified in the Table of Contents. 13


A. Yes, it was. 15


A. Yes, I do. 17



A. Yes, it does. 20


A. Yes, it does. 22



OF JASON PENDLETON 3


A. My name is Jason Pendleton , and my business address is 3 Innovation Way, 5



Edison Company. 8

A. Currently, I am a Construction Project Manager within SCE’s Substation 9

Construction and Maintenance Organization. As Construction Project Manager, I 10

have the overall responsibility for the execution of construction activiites within the 11

substation. My responsibilities include managing the schedule(s) and budget(s) for 12

the construction phase of various projects, ensuring work is completed according to 13

plans and specifications, and in compliance with licensing requirements. Given the 14

complex nature of the Mesa 500 kV Substation Project, I have been responsible for 15

developing the construction sequencing for the project and providing 16

constructability review(s) and feedback for the preliminary engineering completed 17

thus far. 18


A. I attendeded school at Cal State San Bernardino from 1998 to 1999 and the 20

University of Phoenix from 2008 to 2009. I have received a certificate (not current) 21

from ICC (previously ICBO) for Deputy Inspection of Reinforced Concrete and 22

Structural Masonry. I received a certificate of testing concrete (not current) from 23

the American Concrete Institute (ACI). I received over 30 certifications for material 24

testing from the California Department of Transportation (Cal-Trans). 25

I worked for Converse Consultants and Hilltop Geotechnical from 1998 to 26

2004 as a lab and field technician where I was responsible for testing, monitoring 27

and quality assurance of construction projects ranging from residential 28

communities and high-rise buildings in the private sector to public works projects 1

like hospitals and schools. 2

I was employed by Pulte Homes in 2004 as a Project Superintendent and 3

Area Manager to oversee the Land Development of several master-planned 4

communities including Sun City Shadow Hills; a 3,400 home community with two 5

18-hole golf courses, Recreation Center, and Clubhouse. 6

In 2007 I was hired as the Vice President for The Masonry Group to oversee 7

project management, Estimating, and Sales of its corporate location in Riverside, 8

Ca. Annual revenue was in excess of $250 million. 9

In 2011 I worked as a contingent employee for SCE to construct Red Bluff 10

Substation; a new 500-220kV substation as part of the DCR capital improvement 11

project. I joined SCE in 2013 in my current role where I have been involved in 12

several hundred projects including several licensing projects; Triton Substation 13

Project, Fogarty Substation Project, and Lakeview Substation Project. 14


A. The purpose of my testimony in this proceeding is to sponsor the following 16

sections in SCE’s Opening Testimony for the Mesa 500 kV Substation Project, as 17

identified in the Table of Contents: II(B)(2) at pages 13-20; II (C)(1) and (2) at pages 18

21-22. 19


A. Yes, it was. 21


A. Yes, I do. 23



A. Yes, it does. 26


A. Yes, it does. 28