2018 General Rate Case Rebuttal Testimony … General Rate Case Rebuttal Testimony Transmission & Distribution (T&D) ... 5 transmission and distribution ... Advanced Outage Detection

Application No.: A.16-09-001 Exhibit No.: SCE-18, Vol. 11 Witnesses: P. Haralson

(U 338-E)

2018 General Rate Case Rebuttal Testimony

Transmission & Distribution (T&D) Volume 11 – Grid Technology

Before the

Public Utilities Commission of the State of California

Rosemead, CaliforniaJune 16, 2017

SCE-18: Transmission & Distribution (T&D)Volume 11 – Grid Technology

Table Of Contents Section Page Witness

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I. INTRODUCTION .............................................................................................1 P. Haralson

A. Capital Expenditures ..............................................................................5

1. Advanced Technology Labs ......................................................5

a) ORA’s Position ..............................................................6

b) SCE’s Rebuttal to ORA’s Position ................................6

c) TURN’s Position ............................................................6

d) SCE’s Rebuttal to TURN’s Position ..............................6

(1) EDEF Addresses Issues Unique to SCE ....................................................................7

(2) EDEF is the Most Cost-Effective Option ................................................................8

(3) Recovery of EDEF Costs Including Recorded 2016 ...................................................9

2. Energy Storage Pilots .................................................................9

a) ORA’s Position ............................................................10

b) SCE’s Rebuttal to ORA’s Position ..............................11

(1) SCE Has Not Used EPIC Funds to Purchase Energy Storage Systems for Its Projects ..................................................12

(2) The Term “Pilot” and TD&D Project” Are Not Interchangeable ....................12

(3) SCE’s Energy Storage Pilots Are Not Unnecessarily Duplicative of Other Efforts ....................................................14

c) TURN’s Position ..........................................................15

d) SCE’s Rebuttal to TURN’s position ............................15


Table Of Contents (continued) Section Page Witness

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(1) SCE Is Not Allowed to Use EPIC Funds to Purchase Energy Storage Systems for Its Projects ....................................16

(2) The Proposed Energy Storage Pilots Provide Ratepayer Benefits and are Not Duplicative of Existing Pilots ...................16

(3) The Proposed Energy Storage pilots meets the Commission’s Mandate, third-party ownership was considered, and cost effectiveness was assessed .....................................................19

(4) The Proposed Energy Storage Pilots Inform the DRP and IDER Programs ..............21

3. Distribution Volt VAR Control and Capacitor Automation ..............................................................................22

a) ORA’s Position ............................................................23

b) SCE’s Rebuttal to ORA’s Position ..............................23

(1) ORA’s Argument that DVVC Is Part of Grid Modernization Contradicts the Commission’s Definition and Misclassifies the Project ..................................23

(2) The Commission Should Approve This Project Based on the Benefits and Merits of the DVVC Program ...................25

(3) Smart Invertors .................................................25

(4) Addressing ORA’s Position on No Recorded Costs for the DVVC ........................26

(5) ORA’s Recommendation on Capacitor Automation Fails to Account for the Customer Benefits of DVVC ..........................................................26

4. Advanced Outage Detection and Analytics Program ..............27


Table Of Contents (continued) Section Page Witness

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B. O&M ....................................................................................................27

Appendix A Data Request Responses

Appendix B Energy Storage Pilots

Appendix C

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I.1

INTRODUCTION2

SCE’s Advanced Technology Division provides technology solutions that serve our customers’ 3

changing needs and help us reach many ambitious state and federal energy policy targets, while 4

continuing to provide safe, affordable, reliable, and clean electricity to our customers. 5

New technologies must be identified, assessed for their maturity and performance, and tested for 6

their intended purposes. After SCE applies its rigorous process, the new technologies can be safely and 7

predictably integrated into SCE’s grid. On behalf of our customers, we identify promising and prudent 8

technological solutions. We then help make sure those solutions can actually be used across our grid 9

without compromising safety and reliability. 10

Since 2009, SCE has taken these types of measured and prudent steps to pinpoint and assess 11

promising technologies, test their performance in simulated conditions, and demonstrate and pilot them 12

in a real, integrated grid environment prior to deploying them or connecting them to our grid. As public 13

policy goals and technological capabilities continue to evolve, these efforts continue to increase in 14

importance. 15

For the specific projects proposed in this volume, ORA disagrees with SCE including Energy 16

Storage Pilots in this rate case, and contests our forecast for Distribution Volt VAR Control. ORA does 17

not object to SCE’s Advanced Technology Labs.18

TURN contests our requested cost recovery for the Equipment Demonstration & Evaluation 19

Facility (EDEF). However, TURN’s objection to EDEF is based on mistakenly asserting that these 20

projects do not provide benefits. SCE has provided evidence justifying EDEF, and ORA accepts SCE’s 21

2017-2020 expenditures. Apart from EDEF, TURN does not object to SCE’s Advanced Technology 22

Labs. Additionally, TURN disagrees with SCE’s proposed Energy Storage Pilots being included in this 23

rate case. 24

Both ORA and TURN’s objections to SCE’s Energy Storage Pilots are based on the incorrect 25

opinion that these Energy Storage Pilots must be part of the Electric Program Investment Charge (EPIC) 26

program, or that the Energy Storage Pilots are duplicative of existing pilots and demonstrations. 27

These parties are mistaken. The Energy Storage Pilots are for the installation of commercially28

available storage products. Because the products and technologies are commercially available, they do 29

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not qualify for EPIC funding. A Commission decision restricts purchasing commercially available 1

products and technologies with EPIC funds.12

The Energy Storage Pilots are no different than any other new equipment or techniques that SCE 3

pilots before full deployment. Moreover, the Energy Storage Pilots will participate in SCE’s existing 4

transmission and distribution technology pilot process, which the Company uses for a variety of new or 5

changing technologies. The Pilots encompass the development of safety protocols, deployment, 6

operation and maintenance standards, as well as developing and disseminating necessary training 7

materials for SCE’s engineering, operations and field personnel. 8

Finally, TURN objects the Advanced Outage Notification and Analysis project. To address 9

certain cost and scope information we received since the time that we filed our GRC Application, SCE 10

has revised the expected completion date of the project. As a result, this project no longer impacts the 11

revenue requirement for the 2018 GRC. The merits of this project remain strong, and we will be 12

continuing our efforts on the project.13

Summaries for Grid Technology Capital Expenditures and O&M Expenses are provided in Table 14

I-1and Table I-3 shown below.15

1 See D.12-05-037, Ordering Paragraph 3.

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Table I-1 Summary of Grid Technology Capital Expenditures

100% CPUC Jurisdictional – Nominal $000

Activity 2011 2012 2013 2014 2015 2016Distribution Volt VAR Control -$ -$ -$ -$ -$ -$ Capacitor Automation Program 614$ 935$ 1,360$ 1,940$ 1,891$ 1,071$ Advanced Technology 5,196$ 2,570$ 2,112$ 12,500$ 10,380$ 3,852$ Advanced Outage Detection & Analysis -$ -$ -$ -$ -$ -$ Energy Storage Pilots -$ -$ -$ -$ 11$ 678$ Total Capital - Grid Technology 5,810$ 3,505$ 3,473$ 14,439$ 12,283$ 5,601$

Recorded

Activity 2017 2018Total

2017-2018 2017 2018Total

2017-2018 VarianceDistribution Volt VAR Control 2,651$ 4,414$ 7,065$ -$ -$ -$ (7,065)$ Capacitor Automation Program 2,854$ -$ 2,854$ 1,634$ 1,673$ 3,307$ 453$ Advanced Technology 8,676$ 5,928$ 14,604$ 8,676$ 5,928$ 14,604$ 0$ Advanced Outage Detection & Analysis -$ 20,144$ 20,144$ -$ 14,416$ 14,416$ (5,728)$ Energy Storage Pilots 14,518$ 22,499$ 37,017$ -$ -$ -$ (37,017)$Total Capital - Grid Technology 28,699$ 52,985$ 81,684$ 10,310$ 22,017$ 32,327$ (49,357)$

SCE Forecast ORA Forecast


2017-2018 2017 2018Total

2017-2018 VarianceDistribution Volt VAR Control 2,651$ 4,414$ 7,065$ n/a n/a n/a n/aCapacitor Automation Program 2,854$ -$ 2,854$ n/a n/a n/a n/aAdvanced Technology1 8,676$ 5,928$ 14,604$ 6,393$ 5,400$ 11,793$ (2,811)$Advanced Outage Detection & Analysis -$ 20,144$ 20,144$ -$ -$ -$ (20,144)$Energy Storage Pilots 14,518$ 22,499$ 37,017$ 3,511$ -$ 3,511$ (33,506)$Total Capital - Grid Technology 28,699$ 52,985$ 81,684$ (56,461)$

SCE Forecast TURN Forecast

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As discussed below, SCE has revised the completion date for the Advanced Outage Detection 1

and Analysis project. The project no longer impacts the revenue requirement for SCE’s 2018 GRC. 2

Please refer to Table I-2. 3

Table I-2 Revised Advanced Outage Detection and Analysis Capital Forecast


Table I-3 Summary of Grid Technology O&M Expenses

Constant 2015 $000

As discussed below, SCE is withdrawing our O&M associated with the Advanced Outage 4

Detection and Analysis from this GRC, as shown in Table I-4. 5

Activity 2017 2018 2019 2020Total

2017-2020 2017 2018 2019 2020Total

2017-2020 VarianceAdvanced Outage Detection & Analysis -$ 20,144$ 14,711$ 8,392$ 43,247$ -$ -$ -$ -$ -$ (43,247)$

SCE Forecast (Application) SCE Forecast (Revised)

GRCAccount Description 2011 2012 2013 2014 2015560.260 Grid Technology Expenses - Transmission 5,036$ 3,033$ 2,782$ 2,714$ 2,598$

580.260 Grid Technology Expenses - Distribution 13,775$ 12,275$ 11,990$ 12,603$ 13,317$Advanced Outage Detection and Analytics Project -$ -$ -$ -$ -$ Total 580.260 13,775$ 12,275$ 11,990$ 12,603$ 13,317$

Total SCE-02, Volume 11 18,811$ 15,308$ 14,772$ 15,317$ 15,915$

Recorded

GRCAccount Description SCE ORA

ORAVariance TURN

TURNVariance

560.260 Grid Technology Expenses - Transmission 2,598$ 2,598$ -$

580.260 Grid Technology Expenses - Distribution 13,317$ 13,317$ -$ Advanced Outage Detection and Analytics Project 590$ 422$ (168)$ Total 580.260 13,907$ 13,739$ (168)$

Total SCE-02, Volume 11 16,505$ 16,337$ (168)$ n/a n/a

2018 Forecast

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Table I-4 Revised Advanced Outage Detection and Analysis O&M Forecast

Constant 2015 $000

A. Capital Expenditures 1

1. Advanced Technology Labs 2

Advanced Technology (AT) labs allow SCE to safely evaluate, test, and pilot new and 3

emerging technologies that support our compliance with public policies such as modernizing the grid, 4

providing clean energy, enabling customer choice, and integrating distributed resources. The labs also 5

let us test newer versions of existing technologies to support increased operating capabilities when 6

evaluating replacement options for equipment that has reached the end of its lifecycle. SCE maintains 7

and operates AT laboratories at three locations: the Fenwick Laboratories in Westminster, CA; Pomona 8

Laboratory, in Pomona, CA; and the Equipment Demonstration and Evaluation Facility, located in 9

Westminster, CA. 10

Table I-5 Advanced Technology Capital Expenditures 100% CPUC Jurisdictional – Nominal $000

GRCAccount Description

SCE(Application)

SCE(Revised) Variance

580.260 Grid Technology Expenses - Distribution 13,317$ 13,317$ -$Advanced Outage Detection and Analytics Project 590$ -$ (590)$Total 580.260 13,907$ 13,317$ (590)$

2018 Forecast

Activity 2011 2012 2013 2014 2015 2016Advanced Technology 5,196$ 2,570$ 2,112$ 12,500$ 10,380$ 3,852$

Recorded


2017-2018 2017 2018Total

2017-2018 VarianceAdvanced Technology 8,676$ 5,928$ 14,604$ 8,676$ 5,928$ 14,604$ 0$


Activity 2016 2017 2018Total

2016-2018 2016 2017 2018Total

2016-2018 VarianceAdvanced Technology 9,575$ 8,676$ 5,928$ 24,179$ 1,056$ 6,393$ 5,400$ 12,849$ (11,330)$


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a) ORA’s Position 1

For the Advanced Technology Labs, ORA recommends recovery of 2016 actual 2

expenditures and accepts SCE’s forecast for 2017 and 2018. 3

b) SCE’s Rebuttal to ORA’s Position 4

SCE agrees with ORA’s recommendation and appreciates its acceptance of the 5

2017 and 2018 forecast for the Advanced Technology Labs. 6

c) TURN’s Position 7

Apart from the EDEF, TURN does not object to SCE’s Advanced Technology 8

Labs. Regarding EDEF, TURN opposes all of SCE’s forecast expenditures, and recommends a 9

disallowance of 2016 recorded expenditures.2 As SCE noted in its opening testimony, the Commission 10

rejected SCE’s 2015 GRC request to fund the project, finding that SCE had not demonstrated that the 11

“problems it would address are unique to SCE and that other more cost-effective options do not exist.”312

TURN argues that the Commission has already addressed this project in D.15-11-021 and that it would 13

be more cost-effective to use the capabilities of other facilities. Specifically, TURN disagrees with 14

SCE’s interpretation of the AT Technical Testing Facility Survey results.415

d) SCE’s Rebuttal to TURN’s Position 16

SCE appreciates TURN’s acknowledgment that we were forthright in specifically 17

stating that the Commission previously rejected our request for funding EDEF.5 We intended to be fully 18

transparent about that fact, address the Commission’s reasons for denying SCE’s 2015 request (i.e., the 19

Commission’s view that the problems that SCE plans to address with EDEF are not unique to SCE and 20

other, more cost-effective options may exist), and explain why SCE chose to move forward with the 21

project. To help address the reasons the Commission identified for denying SCE’s 2015 GRC request, 22

SCE conducted a survey of entities in the business of providing testing services similar to those SCE 23

proposes to conduct at EDEF. 24

2 See TURN-11, p. 4. 3 Id.4 Id. at p. 5. 5 Id. at p. 4.

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(1) EDEF Addresses Issues Unique to SCE 1

SCE designed and constructed EDEF to provide an energized, high-2

voltage environment to test a variety of new technologies to support renewables integration, grid 3

modernization, infrastructure replacement and safety enhancements.6 EDEF is a highly flexible circuit 4

with overhead conductors, underground cable, switching equipment, protection devices, control systems, 5

communications network, above-ground test pads, utility poles, and underground vaults to simulate a 6

variety of SCE circuit configurations. The project also includes three grid load banks (each simulates 7

roughly 200 customers), a grid simulator, and a two megawatt battery (repurposed from SCE’s Large 8

Energy Storage Test Apparatus).9

The flexible nature of this project allows SCE personnel to safely conduct 10

a variety of high-voltage tests without impacting our customers. Moreover, the integrated nature of the 11

test environment (e.g., actual control systems, communication systems, and field devices) replicates the 12

actual characteristics and configurations of SCE’s distribution grid; this allows us to realistically and 13

comprehensively test technologies and assess how they perform in the actual operating conditions on our 14

grid. The entire laboratory is dedicated to SCE system design, equipment standards, construction 15

methods and operations and maintenance practices. This makes the lab, and the work we do in it, unique 16

to SCE. 17

In 2016, SCE used EDEF to support testing components of Next 18

Generation Distribution Automation, which includes: 19

• Remote Integrated Switch (RIS) – This testing supported the advancement of an 20

automation scheme for distribution circuit fault detection, automatic load restoration, and 21

circuit reconfiguration. The first five RIS in 2.5 configuration (or 2 sectionalizing 22

“midpoint” switches and 3 tie switches) were successfully tested at EDEF and then 23

demonstrated on two circuits at Johanna Substation as part of the Integrated Grid Project. 24

• High Impedance Fault (wire down detection) – SCE conducted multiple wire down 25

tests with multiple technologies, including a reflectometry-based technology solution to 26

detect high impedance faults on distribution circuits. SCE also tested advanced metering 27

infrastructure (AMI) to detect a wire down. Our testing indicated that a load-side wire 28

6 See SCE-02, Vol. 11, p. 30.

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down can be detected by AMI; this needs to be investigated further before considering 1

wide implementation. Additionally, SCE tested partial discharge technology to detect 2

wires down. Additional tests will be conducted to refine the partial discharge technology 3

algorithm. Until SCE determines a proven and practical solution for high impedance fault 4

detection to improve public safety, we will continue to evaluate a range of technology 5

and solution options. It may also be possible that more than one solution will eventually 6

be implemented to improve the accuracy of detection. EDEF allows us to conduct these 7

tests in a safe environment without affecting our customers. 8

(2) EDEF is the Most Cost-Effective Option 9

To address the Commission’s question regarding whether there are other, 10

more cost-effective solutions, SCE conducted an exhaustive survey of research laboratories, research 11

universities, and research consortiums to determine whether any entity meets SCE’s specific testing and 12

evaluation needs.713

TURN’s assertion that “every single capability or feature asked could be 14

accomplished by one or more of the respondents’ facilities”8 is accurate. TURN, however, did not 15

consider that EDEF is the only facility that can perform all these capabilities in an integrated test 16

environment at one physical location with conditions that replicate SCE’s distribution grid conditions. 17

This allows testing to be more accurate and robust, and helps ensure the testing outcome will be 18

applicable to SCE’s distribution system conditions. 19

For example, for high impedance fault testing (wire down detection) no 20

other facility has the capability that EDEF provides to drop a 12 kV line to ground to test various wire 21

down conditions that have occurred in SCE’s service territory. Because of the complexity and technical 22

capabilities required to perform the types of work we must conduct at EDEF, we usually use a team of 23

engineers, system operators, troublemen and internal business partners. If SCE were to select multiple 24

vendors in different locations (as seemingly proposed by TURN), then the entire team would have to 25

7 See WP SCE-02 Vol. 11, pp. 42-73 (Advanced Technology Laboratories Workpapers – AT Technical Testing Facility Survey w Blinded Results) on Appendix C, pp. C-1–C-32.

8 See TURN-11, p. 5.

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travel along with their equipment and materials to multiple locations to perform the same tests that could 1

be performed at EDEF within a shorter period of time and with greater flexibility. 2

Importantly, if SCE were to use an all-inclusive, external testing facility, 3

we would not have the same opportunity to provide our employees with the hands-on experience (e.g., 4

operations and maintenance training) necessary for effectively deploying newer technologies. In any 5

event, such a “one stop” external testing facility does not exist, to our knowledge. 6

In sum, EDEF gives SCE a cost-effective means to perform a variety of 7

high-voltage tests on live circuits under real-world conditions. And it lets us accomplish this testing 8

work in a safe environment that will not impact electric service to customers when we do the testing. 9

What TURN could not have known, because SCE could not share survey 10

participant names due to a commitment of confidentiality for their participation, is that several of the 11

participants surveyed responded that they maintained some of the capabilities of EDEF, but these 12

capabilities are sited at their facilities located outside of California or even outside the U.S. For SCE, 13

testing at an out-of-state or out-of-country facility with limited capabilities is not a feasible or cost-14

effective alternative to testing at EDEF. 15

(3) Recovery of EDEF Costs Including Recorded 2016 16

In the 2015 GRC proceeding, no party opposed SCE’s request to fund the 17

Advanced Labs (including EDEF). The Proposed Decision, which denied the EDEF funding, was not 18

issued until September 2015. The Commission’s final decision, which ultimately adopted the reductions 19

found in the Proposed Decision, was not issued until November 5, 2015. SCE had not anticipated any 20

disallowance of funding, since the request was unopposed. So SCE had proceeded with constructing 21

EDEF, and incurred expenditures on the labs consistent with the proposals in our 2015 GRC application. 22

As of December 2015, SCE had already spent $5.2 million on EDEF. SCE has continued with the EDEF 23

project, as we believe (for the reasons discussed above) we have met the Commission requirements 24

stemming from the 2015 GRC Decision. SCE respectfully requests that the Commission adopt full 25

funding for EDEF. 26

Importantly, SCE has already conducted several tests at EDEF and our 27

customers are already receiving the benefits of the facility. 28

2. Energy Storage Pilots 29

SCE’s proposed Energy Storage Pilots (ES Pilots) are capital programs that will be 30

pursued in conjunction with the Energy Storage Mandate, which allows utility ownership of up to 290 31

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MW. These ES Pilots will be deployed on the distribution system and used to provide electric service to 1

our customers. This effort builds upon the lessons learned from the Company’s history of conducting 2

activities in this important technological field and previous, Commission-approved investments, known 3

as the Distributed Energy Storage Integration (DESI) program. Application of these technologies 4

remains in the early stages of the maturity cycle with many questions needing to be addressed. 5

Accordingly, SCE’s proposal for a ten-project set of in-field pilots is a necessary and prudent step on 6

behalf of our customers before we undertake any full-scale implementation of the technology. 7

Importantly, the ES Pilots are of value even if the majority of storage in the long term will be owned by 8

third parties; we are learning how to integrate and optimize the utilization of such technologies on the 9

SCE grid.10

The ES Pilots will participate in SCE’s existing transmission and distribution technology 11

pilot process, which the Company uses for a variety of new or changing technologies. The Pilots 12

encompass the development of safety protocols, deployment, operation and maintenance standards. As 13

part of the Pilots, we will also develop and disseminate necessary training materials for SCE’s 14

engineering, operations and field personnel. 15

Table I-6 Energy Storage Pilots Capital Expenditures 100% CPUC Jurisdictional – Nominal $000


Except for recovery of recorded 2016 expenditures, ORA opposes SCE’s 17

proposed ES Pilots. ORA believes these Pilots violate a Commission order prohibiting investor-owned 18

utilities from making research, development and demonstration (RD&D) proposals in general rate case 19

Activity 2011 2012 2013 2014 2015 2016Energy Storage Pilots -$ -$ -$ -$ 11$ 678$

Recorded


2017-2018 2017 2018Total

2017-2018 VarianceEnergy Storage Pilots 14,518$ 22,499$ 37,017$ -$ -$ -$ (37,017)$



2017-2018 2017 2018Total

2017-2018 VarianceEnergy Storage Pilots 14,518$ 22,499$ 37,017$ 3,511$ -$ 3,511$ (33,506)$


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proceedings. ORA asserts that the ES Pilots should instead be proposed as EPIC technology 1

demonstration and deployment (TD&D) projects. ORA asserts: 2

(a) SCE and other investor-owned utilities (IOUs) are conducting energy storage 3

projects and funding them as part of their EPIC portfolios; 4

(b) The term “pilot” and “TD&D projects” are used interchangeably; and 5

(c) SCE’s ES Pilots seem to unnecessarily duplicate efforts underway in SCE’s 6

own EPIC program and other proceedings.97


ORA’s proposal rests on the assertion that SCE’s ES Pilot proposals qualify as 9

TD&D projects and therefore should be requested and funded through EPIC. This assertion is mistaken. 10

In fact, the use of EPIC funding for these projects would violate the criteria established by the 11

Commission. 12

Decision 12-05-037 defines a TD&D project as "the installation and operation of 13

pre-commercial technologies or strategies at a scale sufficiently large and in conditions sufficiently 14

reflective of anticipated actual operating environments to enable appraisal of the operational and 15

performance characteristics and the financial risks.”1016

The energy storage technologies that SCE proposes to implement in its ES Pilots 17

are in the early stages of the technology maturity cycle. But the technologies are already commercially 18

available and will be “used and useful” through their service lives. Thus, SCE is not proposing these 19

pilots to research or help develop pre-commercial technologies or solutions. 20

Proof of the commercial availability of the items for which SCE seeks funding 21

can be found in connection with Commission Resolution E-4791, issued on May 26, 2016. That 22

Resolution required that SCE expedite procuring energy storage assets to help alleviate potential outage 23

risks, due to limited operations of the Aliso Canyon Gas Storage Facility. In response to this 24

Commission directive, SCE was able to contract for 40 megawatts of cost-competitive, “build and 25

9 See ORA-09, pp. 124-135. 10 D.12-05-037, Ordering Paragraph 3 (emphasis added).

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transfer” energy storage resources; these resources were able to perform their core function of charge 1

and discharge in support of grid operation by December 30, 2016.112

The system and commercial requirements for these and future battery storage 3

technologies include: a design life of at least 15 years, certification of all electrical equipment by a 4

third-party (InterNational Electrical Testing Association or equivalent), compliance with IEEE standards 5

(e.g., 1547, 519), certification of fire suppression systems (NFPA or equivalent), milestone payments 6

associated with performance test results and performance guarantees, liquidated damages clause, and 7

standard vendor warranties for the equipment and work performed. 8

Thus, because the energy storage technologies we seek funding for are 9

commercially available and fully supported as commercial products by vendors, the purchase of such 10

technologies with EPIC funds would violate the “pre-commercial” requirement established in Decision 11

12-05-037.12

(1) SCE Has Not Used EPIC Funds to Purchase Energy Storage Systems for 13

Its Projects 14

SCE has not used EPIC funds to purchase battery storage technologies for 15

its Commission-approved TD&D activities. ORA correctly notes that SCE’s EPIC portfolio includes 16

projects that make use of battery energy storage systems (i.e., Distributed Optimized Storage, Optimized 17

Control of Multiple Storage Systems, and Integrated Grid Project), but incorrectly concludes that SCE 18

used EPIC funds to purchase them. As previously noted, the battery energy storage systems that SCE 19

plans to use in its energy storage pilots are commercially available devices. We are not allowed to 20

purchase them with EPIC funds. 21

(2) The Term “Pilot” and TD&D Project” Are Not Interchangeable 22

ORA uses the Distributed Optimized Storage (DOS) project as an example 23

of the terms “pilot” and “TD&D” being interchangeable,12 and specifically references SCE’s EPIC 24

Annual Report. While ORA is correct that SCE used the term “pilot” in its EPIC Annual Report, SCE 25

did not purchase the DOS battery energy storage system using EPIC funding. In fact, the battery energy 26

11 While the Aliso Canyon Energy Storage (ACES) projects were able to perform their core function, Center Peaker and Grapeland Peaker operations were limited as of December 30, because commissioning and control system integration was not yet complete.

12 See ORA-09, p. 127.

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storage system we will use for DOS will be purchased as part of the Commission-approved DESI 1

pilots.13 As noted previously, the ES Pilots are based on commercially-available energy storage 2

technologies, which is inconsistent with the definition of an EPIC TD&D project. 3

ORA further attempts to justify its assertion that SCE’s ES Pilots are 4

TD&D Projects by citing PG&E as an example of using “pilot” interchangeably with a TD&D project, 5

in EPIC and in PG&E's Smart Grid Pilot Deployment Project (A.11-11-017).14 This is erroneous. ORA 6

supports its argument by referencing PG&E’s EPIC Annual Report. However, the only mention of a 7

pilot (Smart Grid Deployment Project) is a title, header and footnote of a table intended to show linkages 8

between EPIC projects and other technology activities undertaken by PG&E.15 More importantly, the 9

referenced table did not discuss the energy storage system used. Much has happened since PG&E filed 10

its EPIC Investment Plan in November 2012, including the fact that certain energy storage technologies 11

have continually advanced, with devices now being commercially available. 12

Moreover, SCE’s ES Pilots go beyond an EPIC TD&D and will provide 13

energy services to customers for the useful life of the asset, rather than for a particular project or 14

demonstration. The ES Pilots will be deployed in service of SCE’s customers and undergo SCE’s 15

established technology pilot process, which includes developing safety protocols, establishing 16

deployment, operation and maintenance standards, and developing and disseminating the training 17

materials for field and operations personnel. This is the standard process by which SCE prepares for the 18

full-scale implementation of new solutions on its transmission and distribution grid. 19

Consistent with the Storage Framework in D. 13-10-040,16 SCE designed 20

each of the ES Pilots to further one or more of the Commission’s guiding principles, which are: 1) The 21

optimization of the grid, including peak reduction, contribution to reliability needs, or deferment of 22

transmission and distribution upgrade investments; 2) The integration of renewable energy; and 3) The 23

13 See SCE-02, Vol. 11, p. 36. The Commission approved the DESI pilots in SCE’s 2015 GRC. 14 See ORA-09, pp. 127-128. 15 A.12-11-003, Application of Pacific Gas and Electric Company for Approval of its 2012-2014 Electric

Program Investment Charge Investment Plan, Attachment 1, Appendix B, p. B-1 (filed November 1, 2012). http://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M031/K735/31735305.PDF.

16 Order Instituting Rulemaking Pursuant to Assembly Bill 2514 to Consider the Adoption of Procurement Targets for Viable and Cost-Effective Energy Storage Systems (R. 10-12-007).

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reduction of greenhouse gas emissions to 80 percent below 1990 levels by 2050, per California goals. 1

This design approach adheres to Commission directives for such investments, and helps ensure that 2

SCE’s ES Pilots not only support internal efforts to safely and reliably deploy new technologies, but also 3

support broader Commission objectives by providing much-needed information on such deployments. 4

Contrary to ORA’s belief, the CPUC drew a distinction between pilots and 5

other activities, stating that the pilot deployments “are intended to help SCE develop deployment plans 6

for energy storage.”17 Interestingly, ORA itself seems to acknowledge the difference between research 7

and development projects on the one hand, and pilot projects on the other. In discussing SCE’s Grid 8

Modernization proposals, ORA says: “[d]emonstration and pilot projects are an important step beyond 9

research and development (R&D) projects and full-scale deployment of new technologies.”1810

(3) SCE’s Energy Storage Pilots Are Not Unnecessarily Duplicative of Other 11

Efforts12

ORA incorrectly asserts that the ES Pilots seem to unnecessarily duplicate 13

efforts underway in SCE’s own EPIC program and other proceedings.19 Even though SCE’s GRC 14

testimony describes how its ES Pilots will provide the battery energy storage system for its Preferred 15

Resource Pilot (PRP),20 ORA states that the Energy Storage Pilots appear duplicative of SCE’s PRP 16

efforts.21 ORA makes the same assertions regarding SCE’s Distributed Resources Plan (DRP) and the 17

Commission’s Integrated Distributed Energy Resources (IDER) proceeding.22 SCE’s testimony 18

describes how DESI 2 will be used for battery energy storage system in SCE’s Integrated Grid Project 19

(DRP Demonstration D). DESI 3 will be utilized in the PRP deployment area, and the lessons learned 20

from DESI 3 will inform the IDER proceeding.2321

17 D. 15-11-021, pp. 47-48. 18 ORA-09, p. 24. 19 Id. at p. 134. 20 See SCE-02, Vol. 11, pp. 36-37. 21 See ORA-09, p. 132. 22 Id. at pp. 130-132. 23 See SCE-02, Vol. 11, pp. 36-37.

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Importantly, SCE chose to leverage existing EPIC funding and the DESI 2 1

energy storage system to satisfy the Commission’s requirements for the DRP, Demonstration D; the 2

Commission requires assessment of a system that can operate high penetration of DERs. This was a 3

conscious effort to reduce compliance costs for the DRP to our customers. This approach was not 4

contemplated for the IDER projects, discussed in ORA’s testimony and approved by the Commission in 5

D.16-12-036, because these projects were approved three months after SCE filed its testimony. 6

However, the ES Pilots could potentially satisfy one or more of these projects as well. So in other words, 7

ORA is seeing duplication when there is none. The DRP and IDER demonstrations necessarily require 8

resources. We are making two ES Pilot resources available for DRP demonstrations. If we did not do so, 9

then the DRP demonstrations would consume other resources. SCE is leveraging rather than duplicating. 10

ORA did not oppose the reasonableness of the cost forecast or the 11

methodology used to develop the forecast for SCE’s ES Pilots. The evidence provided above 12

demonstrates why ORA incorrectly objected to inclusion of the ES Pilots in the GRC. SCE’s forecast 13

should be approved. 14

c) TURN’s Position 15

TURN believes the proposed energy storage pilot projects are duplicative with 16

ongoing pilot projects or EPIC demonstrations and are unlikely to result in incremental knowledge.2417

TURN’s argument rests on the following: 18

(a) The majority of proposed costs should be directed through the EPIC program; 19

(b) The proposed energy storage projects do not provide ratepayer benefits that 20

could not be obtained with existing pilots or SCE-owned storage facilities; 21

(c) The energy storage pilots do not meet fundamental requirements of the 22

Commission’s Energy Storage Mandate Program and are not needed for other 23

pilot proceedings; and 24

(d) The energy storage pilots are not needed for the DRP or IDER Programs. 25

d) SCE’s Rebuttal to TURN’s position 26

TURN’s argument misunderstands the distinction between demonstrations and 27

pilots. Furthermore, TURN incorrectly asserts that the proposed energy storage projects do not provide 28

24 See TURN-11, pp. 7-8.

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customer benefits. These proposed energy storage pilots do in fact provide customer benefits, and 1

learnings that cannot be achieved from SCE’s existing pilots. 2

TURN’s opening statement in this section, “One of the primary benefits of any 3

new pilot program is to gain additional knowledge or test new technologies such that future or current 4

generations of ratepayers benefit”25 illustrates TURN’s misunderstanding of a crucial distinction 5

between a Demonstration and a Pilot. As TURN points out in the very next paragraph, “SCE has owned 6

and tested storage for years,” albeit not these specific technologies. 7

SCE’s proposed pilots do not represent demonstration of “new technologies.” 8

Instead the energy storage systems that SCE proposes to implement in its ES Pilots are commercially 9

available. They are not “new,” because they have already been developed and offered for commercial 10

application.11

(1) SCE Is Not Allowed to Use EPIC Funds to Purchase Energy Storage 12

Systems for Its Projects 13

Given that energy storage systems are available and fully supported as 14

commercial products by vendors, these energy storage systems will be “used and useful” through their 15

service lives. The purchase of such systems with EPIC funds would violate the “pre-commercial” 16

requirement established by the Commission in Decision 12-05-037. 17

The Energy Storage Pilots will be deployed in service of SCE’s customers 18

and go through its established technology pilot process, which includes the development of safety 19

protocols, deployment, operation and maintenance standards, and, the formation and dissemination of 20

necessary training materials. Additionally, as noted above in SCE’s rebuttal to ORA, there are specific 21

system and commercial requirements for these battery storage systems. This is the standard process by 22

which SCE prepares for the full-scale implementation of new apparatuses and processes on its 23

transmission and distribution grid. 24

(2) The Proposed Energy Storage Pilots Provide Ratepayer Benefits and are 25

Not Duplicative of Existing Pilots 26

TURN indicates three categories of potentially redundant projects:27

(A) Existing SCE-owned storage, (B) SCE Ongoing and Upcoming pilot projects and (C) non-SCE 28

25 Id. at p. 7.

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EPIC projects. TURN’s assertions of redundancy are incorrect, as detailed for each category below. 1

Before addressing TURN’s claims, it is important to understand the objectives of the individual 2

proposed projects (e.g., Horoscope, Mercury, Gemini, etc.) and the value of the program overall. The 3

objectives of these proposed projects are summarized in Table 1 of this Rebuttal Volume’s Appendix B - 4

Energy Storage Pilots.265

TURN suggests that two projects sharing certain common features are 6

duplicative. TURN’s assertion is incorrect. Two pilot projects are not identical just because both include 7

an energy storage component. To develop an understanding of interactions in complex systems, the 8

scientific method requires comparing multiple examples with controlled variability. As SCE described 9

in its GRC request, the number of applications energy storage may serve is broad and diverse. The need 10

for all relevant applications does not exist on one circuit, much less two or three circuits. Furthermore, 11

SCE serves 5 million customers in 7 climate zones27 on approximately 4,600 unique circuits. Climate 12

and load conditions introduce additional variability that SCE, and the industry, must better understand. 13

This complex operating environment requires multiple tests and evaluations over time. 14

The proposed energy storage pilots are intended to advance Commission 15

objectives and address SCE’s complex and varied operating environment. Therefore, while some 16

projects may have overlapping features, each project has a unique set of features that will provide 17

different benefits. We clearly describe the structure of the various pilots in Table 1 of this Rebuttal 18

Volume’s Appendix B - Energy Storage Pilots.28 For example, while Mercury 3, Mercury 4 and Gemini 19

1 storage pilots will support the same four functions,29 implementing and operating the three projects 20

under three sets of unique conditions30 will enhance knowledge and capabilities far more than one 21

26 See Appendix B – Energy Storage Pilots of this Rebuttal Testimony, p. B-1. 27 http://www.energy.ca.gov/maps/renewable/building_climate_zones.html. 28 See Appendix B – Energy Storage Pilots of this Rebuttal Testimony, p. B-1. 29 The four functions of energy storage deployed on circuits with high PV penetration levels, include: reverse

power flow mitigation, voltage support, PV dependability and integration capacity. 30 Conditions that differentiate project conditions include, but are not limited to ambient conditions, customer

mix and operational issues / DER interdependencies. The three circuits currently identified for these systems exhibit the following: high desert / majority industrial customers / high daytime reverse power flow attributed to large Rule 21 interconnections, low desert / majority commercial customers / multiple issues (see previous footnote) attributed to Net Energy Metering (NEM) and Rule 21 interconnections, and high desert / majority residential customers / high nighttime peak with over 300 NEM customers.

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project standing alone could achieve. Furthermore, each of these systems will be addressing real 1

operational issues on each of three separate distribution circuits through the pilot energy storage 2

system’s service lives, which is ten to fifteen years, consistent with typical practice for capital pilot 3

projects.4

TURN argues “it is clear many of the functionalities SCE claims need 5

’testing’ could be achieved with storage it already owns.”31 TURN is incorrect, because achieving the 6

objectives described above requires: 7

• Deploying storage systems in locations to address specific needs; and 8

• Utilizing energy storage systems available for dispatch for T&D reliability 9

purposes, rather than Generation market purposes. Table 2 in the 10

Appendix to this Volume32 includes all SCE-owned and planned storage 11

facilities cited by TURN and describes how each project does not support 12

the functions described in Table 9 of TURN’s testimony. 13

TURN states “SCE has also ignored or under-emphasized other upcoming 14

and ongoing pilots where storage will play a role.”33 TURN provides no evidence of duplication, as 15

illustrated by the caption of TURN’s Table 4, “SCE Ongoing and Upcoming Pilot Projects that 16

Potentially Duplicate Learnings from Proposed Energy Storage Pilot Projects.”34 TURN’s assertion 17

appears to be speculative. SCE’s Table 3 in the attached Appendix B – Energy Storage Pilots35 includes 18

the ongoing and upcoming pilot projects cited by TURN. Our Table 3 describes how SCE’s proposed 19

storage pilots are either unrelated to, or complementary of, the projects that TURN points to. There is no 20

duplication here. 21

TURN compiled a list of EPIC projects it believes are “likely duplicative,” 22

but offers no analysis supporting this assertion.36 SCE’s funding request and the projects cited by TURN 23

31 TURN-11, p. 8. 32 See Appendix B – Energy Storage Pilots of this Rebuttal Testimony, p. B-2. 33 TURN-11, p. 8. 34 Id. at Table 4, pp. 9-10. 35 See Appendix B – Energy Storage Pilots of this Rebuttal Testimony, p. B-3. 36 See TURN-11, Table 5, pp. 11-12.

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do not overlap, for the reasons discussed above. SCE has created Table 4 in the attached Appendix,371

which further clarifies how each project identified by TURN is not duplicative of existing projects or 2

capabilities. 3

(3) The Proposed Energy Storage pilots meets the Commission’s Mandate, 4

third-party ownership was considered, and cost effectiveness was assessed 5

TURN argues that SCE’s energy storage pilots “do not meet the 6

Commission’s Energy Storage Mandate”38 and further claims that “SCE did not consider whether these 7

projects should be owned and operated by third parties, nor assess cost-effectiveness.”39 TURN’s 8

assertions are incorrect. The vast majority of installed and planned storage within SCE’s service territory 9

will be owned and operated by third parties.40 Moreover, SCE’s approach (consistent with the 10

Mandate)41 is to identify projects for which SCE ownership is appropriate as an exception to the general 11

rule, and to do so on a case-by-case basis rather than on a blanket basis. 12

As a result, installed and planned SCE-owned storage falls well under 13

what the Mandate allows. Furthermore, SCE-owned storage represents less than 1% of SCE’s Eligible 14

Storage Projects in its 2016 Energy Storage Procurement Plan,42 and the estimated capacity for the 12 15

projects SCE has proposed is 38.5MW. This represents only about 13% of the 290MW ceiling for SCE-16

owned storage under the Commission’s Mandate. 17

According to D.13-10-040, when proposing a utility-owned project “the 18

IOU must make a showing that holding a competitive RFO is infeasible. These circumstances may 19

include market power mitigation, reliability, preferred resources, and expansion of existing facilities.” 20

Holding an RFO is infeasible for the proposed projects. RFOs require a high level of specificity 21

regarding how a resource must be operated under any and all conditions through its intended service life. 22

As a result, resources brought online through an RFO are inherently inflexible. D.13-10-040 (section 23

37 See Appendix B – Energy Storage Pilots of this Rebuttal Testimony, p. B-4. 38 TURN-11, p. 13. 39 Id. at p. 14. 40 A.16-03-002, Table III-9, p. 28 shows SCE has procured 357.7 MW in total of energy storage; however, only

2.4 MW is utility owned energy storage. 41 See response to TURN-SCE-011-Q10a, on Appendix A, pp. A-1–A-2. 42 See A.16-03-002, Appendix A, 2.4MW of 339.4MW total is SCE-owned.

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4.9.3) states “This definition [of energy storage] is intended to embrace a mix of ownership models and 1

contribute to a diverse portfolio that can encourage competition, innovation, partnerships, and 2

affordability.” SCE is implementing utility-owned energy storage systems with partners that are selected 3

through competitive RFP processes. This maximizes affordability. Innovation requires operational 4

flexibility enabled by ownership. 5

Cost-effectiveness for complying with the Energy Storage Mandate is 6

measured in terms of “least cost.” Procuring storage to support the Energy Storage Mandate is analogous 7

to the Renewable Portfolio Standard. SCE does not perform cost-benefit analysis and then determine 8

whether to meet the Standard depending on the result. Rather, SCE must meet the Standard as policy 9

requires, and must do so as cost-effectively as possible. 10

Accordingly, we do not perform cost-benefit analysis for energy storage 11

projects. This approach supports the “market transformation” goal of the Energy Storage Mandate and is 12

consistent with D.13-10-040, where the Commission stated that “the long-term goal would be to 13

eliminate targets when the storage market is more mature, sustainable, and able to compete to provide 14

services alongside other types of resources.”43 This cited language is an acknowledgment that the 15

Commission does not yet expect energy storage projects to be driven purely by easily quantifiable 16

economics. 17

SCE’s proposed DESI projects, and energy storage projects in general, are 18

rather unique; direct comparisons are difficult as purely equivalent projects do not exist. (Please refer to 19

our response to TURN on this point above). However, the relevant standard, as explained above, is cost-20

effectiveness relative to third party projects. We help ensure such cost-effectiveness as follows: 21

• SCE is leveraging under-utilized space in SCE-owned rights of way to site 22

energy storage pilots, achieving zero incremental cost to customers for 23

land use. It’s reasonable to assume that third party projects would usually 24

incur some incremental costs for land use. 25

• Approximately two-thirds of the cost of a typical project44 comprises 26

energy storage equipment and interconnection facilities. As previously 27

43 See D.13-10-40, p. 7. 44 See DESI 2 budget in WPSCE02V11-D. Kim of this Rebuttal Testimony, in Appendix C, p. C-33.

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described, the former is installed by vendors selected through a 1

competitive RFP process. For the latter, costs are no different for SCE-2

owned projects than third-party projects. In fact, SCE follows the very 3

same interconnection processes (Wholesale Distribution Access Tariff, 4

Rule 21, etc.) as customers and third parties do. 5

• There is one precedent in directly comparable projects. In response to 6

limited operations of the Aliso Canyon Gas Storage Facility and 7

subsequent reliability concerns in the Los Angeles Basin, SCE contracted 8

utility-owned and 3rd party storage resources. We determined cost 9

reasonableness by comparing results of the RFO conducted in response to 10

Commission Resolution E-4791. SCE’s selection process for the utility-11

owned project included making sure its cost to customers was equivalent 12

to, or less than, that of the third party systems. 13

(4) The Proposed Energy Storage Pilots Inform the DRP and IDER Programs 14

TURN, in an interestingly hyperbolic fashion (“It is ludicrous on its face 15

to suggest additional pilots are needed to support other pilots”),45 objects to SCE’s efforts to find 16

synergies between programs and leverage assets to maximize value for its customers. TURN asserts 17

SCE’s proposed energy storage pilots are not needed for the DRP and DER programs. 18

As noted above in SCE’s rebuttal to ORA, we are leveraging DESI 2 and 19

DESI 3 to enable the DRP Demonstrations in order to reduce costs to customers. If DESI 2 and DESI 3 20

were not available to support the DRP, resources with equivalent capabilities would still be required and 21

comparable cost would still be incurred. By leveraging DESI 2 and DESI 3, we have a clearer path for 22

extracting value from energy storage deployed in support of the DRP for 10-plus years beyond the DRP 23

Demonstration test period. As discussed in our rebuttal to ORA’s testimony, the IDER pilot projects, 24

approved by the Commission in D.16-12-036, occurred three months after SCE filed its testimony. 25

However, the Energy Storage Pilots could potentially support one or more of these projects. TURN’s 26

arguments (that the proposed ES Pilots are duplicative and that SCE has not adequately shown why pilot 27

funding is necessary) are not valid. SCE’s forecast should be approved. 28

45 TURN-11, p. 14.

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3. Distribution Volt VAR Control and Capacitor Automation 1

The Distribution Volt VAR Control (DVVC) Program centralizes control of the field and 2

substation capacitors, to coordinate and optimize voltage and VARs across all circuits fed by a 3

substation. Capacitors on distribution circuits and in substations are essential to maintaining voltage 4

within prescribed tolerances. Without capacitor banks, voltages may fluctuate, causing damage to 5

customer equipment and presenting safety hazards. DVVC will leverage distribution substation 6

capacitors and existing standard automated distribution field capacitors on distribution circuits. This will 7

reduce energy consumption, as well as safeguard reliability by limiting voltage fluctuations. We do this 8

while maintaining overall customer service voltage requirements. DVVC will reduce excess voltage 9

(and foster avoided energy procurement and capacity costs) without compromising the safety and 10

reliability of our service. SCE estimates these avoided energy procurement and capacity costs should 11

provide a 1% actual savings in energy costs for customers for every 1% reduction in voltage.4612

Table I-7 DVVC Capital Expenditures


46 See SCE-02, Volume 11, p. 46.

Activity 2011 2012 2013 2014 2015 2016Distribution Volt VAR Control -$ -$ -$ -$ -$ -$

Recorded


2017-2018 2017 2018Total

2017-2018 VarianceDistribution Volt VAR Control 2,651$ 4,414$ 7,065$ -$ -$ -$ (7,065)$


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Table I-8 Capacitor Automation Program Capital Expenditures

Total Company – Nominal $000


Without arguing the merits of the DVVC Program, ORA opposes the entirety of 2

SCE’s proposed expenditures because ORA classifies the deployment as a Grid Modernization effort, 3

and says that SCE did not provide a discussion of smart inverters in its testimony. ORA also points to 4

the zero recorded expenditures for DVVC.475

ORA notes that SCE’s existing Capacitor Automation program could also be Grid 6

Modernization, but since it is an existing program, recommends that it continue through the rate case 7

period at historical expenditure levels.488


(1) ORA’s Argument that DVVC Is Part of Grid Modernization Contradicts 10

the Commission’s Definition and Misclassifies the Project 11

Whether DVVC should be categorized as “Grid Modernization” is a 12

matter of definition. ORA argues that DVVC should be defined as a Grid Modernization project based 13

on the equipment in the project. ORA disagrees with SCE’s classification of DVVC as a traditional, 14

reliability-based program “because DVVC automates capacitors, transfers data via a field data network, 15

and is controlled by DMS and EMS control software, and each of these are elements of Grid 16

47 See ORA-09, p. 122. 48 Id. at p. 123.

Activity 2011 2012 2013 2014 2015 2016Capacitor Automation Program 614$ 935$ 1,360$ 1,940$ 1,891$ 1,071$

Recorded


2017-2018 2017 2018Total

2017-2018 VarianceCapacitor Automation Program 2,854$ -$ 2,854$ 1,634$ 1,673$ 3,307$ 453$


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Modernization programs.”49 The list of equipment SCE identified included remotely controlled voltage 1

regulators and dynamic voltage controllers, remote controlled switches, remote fault indicators, and 2

many other assets as distribution automation assets.503

ORA’s inclusion of DVVC as a Grid Modernization program is at odds 4

with the definition published in a recent Energy Division white paper.51 The Commission has stated that 5

“the DRP proceeding is specifically focused on investments that are primarily driven by the need to 6

accommodate high penetration of DERs. This includes investments that both enable DER penetration 7

and safety and reliability, but does not include investments made solely for the purpose of safety and 8

reliability.”52 ORA has classified DVVC as Grid Modernization, solely on the basis of the types of 9

equipment deployed and the connection with automation. ORA has not disputed the reliability basis for 10

DVVC.11

DVVC long predates the DRP proceeding. SCE had proposed DVVC-type 12

projects, and been laying the foundations for this project with its new DMS application in the both the 13

2012 and 2015 GRC, long before DERs were an issue of focus for the Commission. As discussed below, 14

SCE plainly states that DVVC is being proposed for its reliability benefits and the benefits of reduced 15

energy costs that it will bring to our customers. As such, it fits squarely within the Energy Division’s 16

definition of projects that “can be proposed and authorized through IOUs’ GRCs separate from Grid 17

Modernization Guidance.”53 ORA’s argument to eliminate funding for DVVC on grounds that it is a 18

Grid Modernization project should be rejected. 19

49 ORA-09, p. 122 (footnotes omitted). ORA’s conclusion rest on a table in SCE-02, Volume 3R, and an SCE response to Question 2 of ORA-SCE-029-TCR, which confirmed that “components of Volt/VAR optimization systems are distribution automation devices.”

50 See response to ORA-SCE-029-TCR-Q.2 on Appendix A, pp. A-3–A4. 51 Assigned Commissioners Ruling Requesting Answers to Stakeholder Questions Set Forth in the Energy

Division Staff White Paper on Grid Modernization, A.15-05-005; see the attached “Staff White Paper on Grid Modernization,” p. 10, included as Appendix D.

52 Id. (emphasis added). 53 Id.

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(2) The Commission Should Approve This Project Based on the Benefits and 1

Merits of the DVVC Program 2

Approval of the DVVC program is warranted because it offers significant 3

benefits to the customer. These benefits have been tested, and realization of the benefits for customers 4

pivots on deploying DVVC. 5

As discussed in our opening testimony, our current capacitor control 6

system relies on “obsolete, first generation automation equipment.”54 DVVC is the upgrade and 7

replacement for this existing Automation System that is needed to maintain automated capacitor controls 8

on our distribution circuits and substations.55 In addition, the existing equipment cannot be used by 9

our grid control software to centrally control Voltage and VARs. 56 Without the DVVC project, the 10

energy saving benefits will not be achieved. 11

As also noted in our opening showing, SCE estimates the avoided energy 12

procurement and capacity costs associated with DVVC would provide a 1% actual savings in energy 13

costs for customers per 1% reduction in voltage.57 While integrating DERs will be supported and safer 14

with DVVC, the program stands on its own merits for reliability and energy savings reasons, and the 15

Commission approved it in D.15-11-021, SCE’s 2015 GRC.58 ORA’s assertion that this is part of Grid 16

Modernization is at odds with the Commission’s definition. 17

(3) Smart Invertors 18

SCE has done a great deal of work on smart inverter technologies at its 19

Advanced Technology Labs in Westminster, CA, and has published the results. SCE believes such 20

technologies can be leveraged as part of a broader strategy to support distribution voltage and VAR 21

regulation, and we are working in a variety of areas, including IEEE standards committees, to facilitate 22

adoption of the technologies. Unfortunately, full adoption of smart inverters and deployment in numbers 23

54 SCE-02, Vol. 11, p. 47. 55 See response to TURN-SCE-011-Q.29a on Appendix A, pp. A-5–A-6. 56 See response TURN-SCE-011-Q.23 and Q.31 on Appendix A, pp. A-7–A10. 57 See SCE-02, Vol. 11, p. 46. 58 The program was named Wide Area Voltage/VAR Control System in SCE’s 2015 GRC.

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that would positively impact the grid,59 are many years away. DVVC can be modified when needed for 1

incorporating the implementation of smart inverters into its decision making. And it is deployable now 2

with immediate and lasting benefits. 3

(4) Addressing ORA’s Position on No Recorded Costs for the DVVC 4

SCE experienced delays in developing detailed scope for project 5

construction. SCE intends to proceed with the DVVC scope in 2017 and 2018, as described in our 6

opening showing, to fully achieve the benefits described above.60 Also, SCE’s traditional Capacitor 7

Automation program is planned to be phased out after 2017, with DVVC being the next step in SCE’s 8

capacitor automation efforts. DVVC will allow for the centralized voltage and VAR control and 9

conservation voltage reduction benefit that the Capacitor Automation alone cannot provide. 10

(5) ORA’s Recommendation on Capacitor Automation Fails to Account for 11

the Customer Benefits of DVVC 12

ORA’s recommendation on Capacitor Automation is based on the 13

incorrect premise that DVVC is a Grid Modernization project. SCE’s proposal for spending on 14

Capacitor Automation is simply to maintain existing controls until DVVC, its replacement, can be 15

implemented. The technology being used for the current Capacitor Automation is obsolete,61 and it 16

simply does not make sense to continue to install new systems or even replace existing equipment any 17

longer than is absolutely necessary. ORA has it backwards: Capacitor Automation is a not a substitute 18

for DVVC; DVVC is the replacement for Capacitor Automation. 19

ORA’s recommendation to continue the Capacitor Automation program at 20

an average of 2014-2016 historical expenditure levels also fails to achieve the 1% annual energy savings 21

for our customers.62 ORA makes no alternative recommendation of how we can achieve those benefits 22

59 Because of the diversity of SCE’s grid, there may be pockets with voltage problems where we might deploy smart inverters earlier.

60 See SCE-02, Vol. 11, Section I.A.3.b.2 entitled “The Commission Should Approve This Project Based on the Benefits and Merits of the DVVC Program.”

61 See response to TURN-SCE-011-Q.19 on Appendix A, pp. A-11–A12. 62 See responses to TURN-SCE-011-Q27.a and SEIA-Vote Solar-SCE-001 Q1.47a and 1.47.b in Appendix A,

pp. A-13–A17.

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without this funding, and in fact completely ignores the energy savings for customers in their testimony. 1

SCE’s request, as described in testimony for both DVVC and Capacitor Bank Automation, is prudent. 2

4. Advanced Outage Detection and Analytics Program 3

The Advanced Outage Detection and Analytics program aims to enhance the capabilities 4

of SCE’s infrastructure, and utilize the collective data to improve public safety, outage detection, outage 5

notification, response, and work practices.63 In SCE’s Application, SCE forecast the capital expenditures 6

on the project would occur in 2018 – 2020, with an in-service date of December 2020. 7

In the time period after SCE submitted its Application, we have received certain 8

additional information that could materially affect the project costs, scope, and schedule. As a result, 9

SCE now does not expect the project to be in-service until 2021. The revised in-service date of January 10

2021 has been included as an errata. The result of changing the in-service date is that the capital costs of 11

the project do not affect the revenue requirement during the three years of the 2018 GRC cycle. We 12

stand by the underlying merits of this project and will be continuing to evaluate technologies and 13

methodologies to use SmartMeter data to more quickly identify and respond to outages. SCE plans to re-14

submit the capital request for this project in our next GRC, when the cost, scope, and schedule items 15

have been more fully vetted and resolved. 16

B. O&M 17

The expenses for the Advanced Technology organization record to two GRC accounts, 560.260 18

and 580.260. Our forecast utilized last year recorded for the ongoing engineering and project 19

management activities. We also included a normalized amount of incremental expenses for GRC 20

account 580.260 to capture expenses we expect to incur in developing and deploying the Advanced 21

Outage Notification project. 22

There were no objections to our ongoing engineering and project management expenses. ORA 23

did have an alternative proposal for the expenses associated with the Advanced Outage Detection and 24

Analytics project. However, as discussed above, with the change in completion date for this project, it 25

has moved outside of the current rate case revenue requirement. Therefore, we are withdrawing our 26

request for the associated O&M. Our revised request for test year 2018 is shown in Table I-4. 27

63 See SCE-02, Volume 11, pp. 49-60.

Appendix A

Data Request Responses

Southern California Edison2018 GRC A.16-09-001

DATA REQUEST SET TURN-SCE-011

To: TURNPrepared by: Loic Gaillac

Title: Engineering ManagerDated: 11/08/2016

Received Date: 11/08/2016

Question 10.a:

The following questions refer to SCE09-V11, Grid Technology.

Storage

10. Please provide a list of SCE-owned storage projects (including those planned but not yet installed) including the following information:

a. Name/location on the system including whether it is connected to the transmission or distribution system.

Response to Question 10.a:

The installed projects listed count toward SCE’s energy storage procurement target. The planned projects include:

4 projects in response to CPUC Resolution E-4791 authorizing expedited procurement of �

storage resources to ensure electric reliability in the Los Angeles Basin due to limited operations of Aliso Canyon Gas Storage Facility;2 pilots approved in SCE's 2015 GRC; and �

10 pilots requested in SCE's 2018 GRC.�

The table below provides details regarding SCE-owned storage projects with location, connection type, MW/MWh, and primary benefits.

��

��


DATA REQUEST SET ORA-SCE-029-TCR

To: ORAPrepared by: Eric Nunnally

Title: Project ManagerDated: 10/14/2016


Question 02:

Originated by: Tom Roberts

Exhibit Reference: SCE-2, volume 10SCE Witness: R. RagsdaleSubject: Electric T&D, Grid Modernization, Distribution Automation (DA), general

2. Please indicated which of the following types of devices are considered by either SCE or the electric utility industry as DA devices:

a. Sectionalizers,

b. Reclosers,

c. Components of Fault Location, Isolation, and Service Restoration (FLISR) systems,

d. Components of Volt/VAR Optimization (VVO) systems,

e. Substation transformer tap changers,

f. Remote controllable devices, including voltage regulators, switched capacitor banks, dynamic voltage controllers, power regulating transformers,Other types of devices not listed above

Response to Question 02:

Of the components listed, SCE considers the following to be distribution automation devices:

Sectionalizers which have the ability to be remotely operated, such as Remote Controlled �

Switches (RCS) and Remote Intelligent Switches (RIS).Reclosers which have the ability to be remotely operated.�

��

Components which contribute to the function of a FLISR system such as RCSs, RISs, and �

Remote Fault Indicators (RFI). Components which contribute to the function of a VVO system such as automated switched �

capacitor banks.Remotely controlled voltage regulators and dynamic voltage controllers. �

Telemetry such as line monitors to sense and communicate current, voltage, and power.�

Network protectors such as those operating in our Long Beach network.�

SCE does not consider substation transformer tap changers as DA devices.

��



To: TURNPrepared by: Hamilton Pham

Title: EngineerDated: 11/08/2016


Question 29.a:


Distribution Volt-Var Control/Capacitor Automation

29. On page 48 SCE describes that implementation of DVVC will occur at approximately 313 distribution substations as well as the number of PCC’s per year from 2018-2020.

a. Please provide the basis and an explanation for the number of capacitor controls installed per year.


Annually, SCE will still require ongoing PCC replacements as part of the Capacitor Automation Program. The replacement of capacitor controls is mainly the result of failed controls or obsolescence. Lifecycle age is not the major factor that will dictate the need to replace a capacitor control, but it is a guide to estimate the end of its service life. With the age of the capacitor controls reaching and/or exceeding the service life of 15 years, capacitor controls are expected to fail at increasing rate as they age, which adversely affects the reliable operation of capacitor banks as well as voltage support on the system.

Along with the need to maintain the system-wide program for capacitor automation, there is a separate need to focus on and prioritize replacing failed controls and obsolete capacitor controls on feeders that are served out of substations where DVVC is being implemented. Along with a few locations in the San Joaquin Valley, North Coast, and Desert regions, implementation of DVVC is concentrated in the LA basin area, which is where SCE's load is mostly concentrated. In order for DVVC to successfully optimize voltage and VARs, and thereby provide energy savings for customers, it is critical that the DVVC algorithm have reliable data from functioning PCCs as well as possess the ability to remotely control the capacitor banks through utilizing the PCCs.

Therefore, along with the annual Capacitor Automation program which looks at the entire

��

service territory for PCC replacement scope, we have placed additional focus toward replacing all of the necessary PCCs within DVVC areas. SCE has, on average, historically replaced approximately 440 controls system wide on an annual basis. With the deployment of DVVC to substations mostly in the LA basin and in the surrounding areas, DVVC is highly dependent upon utilizing functioning capacitor controls in executing its optimization algorithm. Within the DVVC area alone there are approximately 1400 capacitor controls that need replacement. So we are prioritizing a ramp-up of control replacements within the DVVC areas. With so many controls requiring replacement, in addition to the ongoing maintenance of controls that fail as part of normal service, we estimate that an additional 200 controls per year would need to be replaced from 2018 to 2020 in order to successfully implement the DVVC program.

��






Question 23:



23. Why is SCE continuing to spend on capacitor automation in 2016 and 2017 if the program is scheduled to end in 2018? Please explain why the costs spent in 2016 and 2017 on this program are necessary and beneficial to ratepayers.


SCE’s Capacitor Automation program automates existing manual capacitor controls and upgrades obsolete, first-generation automation equipment. Capacitor controls are used to remotely operate switched capacitor banks installed on the distribution system to provide voltage and VAR support. Without capacitor banks, the voltage supplied to SCE customers would drop to levels that can damage the customers’ equipment or appliances, and present safety hazards. Automating the control of these capacitor banks allows SCE to remotely monitor and control the operation of these devices, rather than sending a person to operate the device manually in the field.

Capacitor Automation with programmable capacitor controls provides a number of distribution system benefits, all of which enable SCE to better manage its distribution system and provide benefits to SCE customers. SCE uses capacitors to manage the voltage on its distribution system to acceptable levels. Low or high voltages at a customer’s meter can result as requirements on the system change. These low or high voltage levels can damage customer equipment and appliances. The remote operation of capacitor banks allows SCE to provide voltage and VAR support where and when it is needed. It also enables engineers and operators to remotely monitor distribution system conditions. Better-managed voltage and VAR support is critical in operating SCE’s system and maintaining proper voltages for electricity delivered to customers.

For additional information, please see the response to TURN-SCE-011-Q29 and SCE's 2018 GRC testimony at SCE-02, Volume 11, pages 43-49. Maintaining and upgrading capacitor

��

automation is necessary, both now and in the future. The capacitor automation program that replaces failed capacitor controls is expected to continue in 2016 and 2017 as the DVVC program ramps up. From 2018 onwards, all capacitor automation and controls replacements/upgrades will be combined under the DVVC program.

��






Question 31:



31. Please describe how SCE’s distribution volt-var control program will interact with its traditional conservation voltage reduction program. Doesn’t SCE’s CVR program limit the potential benefit of the DVVC program? Please explain.


SCE's traditional distribution system CVR program consists of utilizing distribution field capacitors that are automated with capacitor controls, which have two-way communication, monitoring capability, and localized autonomous control through programmable local settings such as for local voltage, time, date schedule, and local temperature. SCE’s existing 12 kV and 16 kV distribution systems, that are supplied by a 66 kV sub-transmission system, use automated capacitors. The automated capacitors are located along the circuits and within each substation connected at the distribution bus. Nearly all of these capacitor controls operate based on the locally sensed primary circuit voltage at its connection point. Each capacitor controller has a control bandwidth that switches a capacitor off when the primary voltage exceeds the upper band limit and switches the capacitor back on when primary voltage drops below the lower band limit. To compensate for additional voltage drop during peak conditions in the secondary system (e.g., 120/240 volt), many of SCE’s capacitor controllers use time bias and/or temperature bias. The bias will raise (or lower) the entire bandwidth during specific times of the day or temperature conditions to provide additional voltage support during peak conditions. The problem is that this bias attempts to estimate (and compensate for) secondary voltage drop based solely on time of day and/or temperature. It does not sense load or customer voltage directly. While this system has provided adequate customer voltage control, it does not allow for the better control that might be obtained by sensing voltages and actively coordinating capacitor switching as part of a centralized system like DVVC.

SCE demonstrated CVR and a superior method of coordinated central capacitor control in a

��

project called DCAP. From 1992 through 1994, SCE demonstrated DCAP at two distribution substations with a total of eighteen 12 kV distribution circuits and 72 switched capacitor banks. The scheme centralized the switching of field and substation capacitors to achieve the lowest average customer voltages possible without violating minimum voltage requirements at any measured point and without violating substation power factor limits. The system relied on special purpose secondary voltage monitors, which provided a direct measurement of customer voltage via radio. The team turned the DCAP system on and off for alternate time-periods and observed a CVR factor of approximately 1.0. At least a 1% voltage reduction resulting in an approximate 1% reduction in customer energy consumption was demonstrated in the demonstration at MacArthur substation.

The DVVC application seeks to optimize customer voltage profiles in pursuit of “conservation voltage reduction” (CVR) by using existing capacitor controls under a centralized command scheme rather than having each capacitor control operate locally and independently. The primary objective of DVVC is to achieve a “flat and low” voltage profile in pursuit of CVR. Operating the DVVC algorithm through the pilot at MacArthur Substation showed that the algorithm satisfied DVVC’s main objectives, which include meeting volt/VAR requirements (when possible), minimizing average customer voltage, and minimizing capacitor controller switching.

The DVVC application provides for a centralized control in that it not only considers the information at the local capacitor control, but at every capacitor controller in the specific DVVC system. It has been demonstrated that centralized control of substation and distribution capacitors under DVVC could substantially reduce overall system voltage and customer energy use without requiring any change in customer behavior.

��






Question 19:



19. Please identify the quantitative realized benefits, annually, of SCE’s capacitor automation program and accompanying analyses and workpapers.


SCE does not track and has not quantified realized benefits for replacing failed or obsolete capacitor controls.

SCE's Capacitor Automation Program is designed to automate existing manual capacitor controls and replace obsolete capacitor controls, in addition to providing two-way communication for existing switched capacitor banks. Automating the control of existing capacitor banks allows SCE to remotely monitor and control the operation of these devices, rather than sending a person to the device in the field.

The plan for the Capacitor Automation Program is to replace failed Programmable Capacitor Controls (PCC) and PCCs nearing the end of their lifecycle (which is 15 years of service life) with a more modern control with radio communication capability. First-generation Fisher Pierce 4100 series automated controls are considered obsolete and have exceeded the end of their designed life, as these controls were first introduced to SCE in 1994. Capacitor control replacement parts for vintages of Fisher Pierce 4100 controls are no longer available, and the vendors no longer provide technical support for them. Regardless of age, some controllers are rendered technologically obsolete, as parts, software, and technical support by the manufacturer are no longer available. The alternative to capacitor control replacement would be to not replace the capacitors controls as they fail. This would result in degradation of reliability for our customers. Or we could replace the failed capacitor controls with a like-for-like replacement. But this would require installing obsolete equipment on the current grid even as that grid is otherwise being significantly updated and upgraded to meet the objectives of the Commission

��

and other policymakers.

The latest capacitor control that SCE is using as the replacement of older controls is the IntelliCap Plus capacitor controller. SCE has not quantified the benefits. However, based on SCE Field Apparatus crew feedback, the new Intellicap Plus controller provides several benefits, including but not limited to: • Software that is faster and easier to use; • Faster inspections and maintenance; • No laptop is required to enter or change settings (this allows for faster response during an emergency situation); • Ability to program multiple settings for operation under varying system needs; and• Better reliability.

Overall, these qualitative benefits on the IntelliCap capacitor controller improve capacitor bank reliability, proper operation, and minimize down-time due to controller failures or malfunctions. SCE Field Apparatus crews also indicated a wide variety of failures associated with the Fisher Pierce 4100 series capacitor controls. For example:

• Communication failure with the control resulting in inability to operate or monitor capacitor bank remotely; • Erroneous voltage readings by the control such as turning the capacitor bank on or off indiscriminately; • Manual Open/Close switch or relay failure which results in inability to operate the capacitor bank locally through the control; • Unexplained loss of settings; and • Software glitches, which can render the crews unable to change, set, or read data on the controller without the programming software.

��



To: TURNPrepared by: Bryan Pham

Title: Engineering ManagerDated: 11/08/2016


Question 27.a:



27. On page 46, lines 11 to 13, SCE states it “estimates these avoided energy procurement and capacity costs to provide a 1% actual savings in energy costs for customers per 1% reduction in voltage.”

a. Please provide the basis for this statement. Is this based on SCE’s Irving Smart Grid demonstration? Please explain and provide all relevant reports, workpapers, and data.


In 1992, SCE implemented the Distribution Capacitor Automation Project and validated the 1%:1% energy savings to voltage reduction ratio or a Conservation Voltage Reduction (CVR) factor of one. This was documented in an IEEE paper titled “Distribution Capacitor Automation Provides Integrated Control of Customer Voltage Levels and Distribution Reactive Power Flow.” See attachment entitled “DCAP IEEE paper.”

Independent studies have also shown energy saving potential of CVR as follows:

• US DOE Evaluation of CVR on a National Level (2010) Annual energy reduction approximately 0.5-4.0% per feeder 3.04% energy reduction with complete (nationwide) deployment

• Navigant, prepared for BPA (2013) “Advanced” voltage control reduces energy consumption 2.5%

In 2014, as part of the Irvine Smart Grid Demonstration project, SCE implemented a field test for Distribution Volt VAR Control and demonstrated that the system produces lower overall

��

voltages of approximately 1.5 to 2 volts (on a 120 volt base) while operating in CVR mode. An average reduction of 1.75 volts (or 1.45%) and a CVR factor of 1.0 translates into energy savings of approximately 1.45%. Since DVVC was conducted on only 7 distribution circuits (fed from a 56 MVA transformer bank), SCE believes when fully deployed on a system-wide basis, some circuits may experience a higher CVR factor and some may experience less. Therefore, we conservatively estimates 1% actual savings in energy costs for customers per 1% reduction in voltage.

DCAP IEEE paper.pdfDCAP IEEE paper.pdf

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DATA REQUEST SET SEIA-Vote Solar-SCE-001

To: SEIA, VOTE SOLARPrepared by: Hamilton Pham

Title: Engineer 3Dated: 02/10/2017


Question 01.47.a:

SCE-02 Volume 11 – Grid Technology

1.47 At p. 48 of SCE-02 Volume 11, SCE indicates that it will deploy Distribution Volt VAR Control (DVVC) at 313 substations. Page 47 indicates that DVVC could result in a 2% voltage reduction and a potential energy savings of 3.4%. Please provide:

a) A spreadsheet showing for each of the 313 proposed DVVC substations:

� Substation name � Subtransmission and distribution voltages� Number of circuits� Total residential, commercial and industrial customers served� Estimated annual customer energy savings from DVVC (in kWh)� Other estimated annual energy savings from DVVC (e.g., reduced line

losses)

Response to Question 01.47.a:

The attached spreadsheet provides the requested information. The forecast annual energy savings was applied to the number of stations identified in 2014. The annual savings forecast is dependent on the approximated number of substations in the DVVC deployment plan.

GRC REQUEST-DVVC CUSTOMER AND FORECAST ENERGY SAVINGS DATA.xlsxGRC REQUEST-DVVC CUSTOMER AND FORECAST ENERGY SAVINGS DATA.xlsx

��


DATA REQUEST SET SEIA-Vote Solar-SCE-001

To: SEIA, VOTE SOLARPrepared by: Hamilton Pham

Title: Engineer 3Dated: 02/10/2017


Question 01.47.b:

SCE-02 Volume 11 – Grid Technology

1.47 At p. 48 of SCE-02 Volume 11, SCE indicates that it will deploy Distribution Volt VAR Control (DVVC) at 313 substations. Page 47 indicates that DVVC could result in a 2% voltage reduction and a potential energy savings of 3.4%. Please provide:

b) An explanation of how SCE intends to measure and verify the energy savings from DVVC

Response to Question 01.47.b:

SCE intends to model its Measurement and Verification (M&V) framework after those developed for projects such as the Distribution Capacitor Automation (DCAP) and ISGD Demonstration Programs. The current approach uses an algorithm, which is cycled on for one week and off for another week, for a period of one year. SCE will use this approach at representative DVVC installations to determine if the initial deployment is meeting the targeted 1:1 conservation voltage reduction (CVR) factor. This effort will require the use of available SCADA data and smart meter data. The SCADA data will be used to determine any voltage reduction at the system level and the smart meter data will be used to validate energy reduction and voltage reduction at the customer panel. This process will allow SCE to validate the 1:1 CVR target ratio.

Further detail on the method can be found in the following reports: “Final TP&D Report - Distribution Automation & DSEEP Support” and the “Final Technical Report - Irvine Smart Grid Demonstration.”

Final TP&D Report - Distribution Automation & DSEEP Support.pdfFinal TP&D Report - Distribution Automation & DSEEP Support.pdf

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Final Technical Report - Irvine Smart Grid Demonstration.pdfFinal Technical Report - Irvine Smart Grid Demonstration.pdf

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Appendix B

Energy Storage Pilots

TABLE 1 Energy Storage Pilots Overview

Projectcategory

Category focus Project name

Project objective

DESI Phase 1 (approved2015 GRC)

How best to integrate energy storage onto the grid

DESI 1 (installed)

Support circuit feeding C&I customers during sporadic periods of high demand

DESI 2

Implement capability in urban environment to support dual functions of (1) local distribution reliability and optimization (2) service in wholesale market

DESI 3 Dispatch of multiple storage systems for optimized phase and voltage balancing

Distributionreliability

Mitigate system planning criteria violations

Horoscope Dispatch storage to preclude exceedance of duct bank temperature limit

Mercury 1 Dispatch storage to preclude exceedance of planned loading limit

Mercury 2 Dispatch storage to maintain N-1 contingency in Subtransmission system

Facilitatepreferredresources

Integraterenewables;enable greater DER penetration levels

Mercury 3 4 common functions (reverse power flow, voltage fluctuation, PV dependability, integration capacity) implemented on 3 circuits differentiated by load profile / customer mix

Mercury 4

Gemini 1

Otherapplications

Grid resiliency Gemini 2 Dispatch storage to support N-2 contingency in Transmission system

Microgrid IFOM Gemini 3

Utilize storage as voltage source on microgrid supporting multiple customers providing critical infrastructure and public safety through emergency events

Microgrid BTM Apollo 1

Implement capability in rural environment to support dual functions of (1) local distribution reliability and optimization (2) microgrid support for critical Department of Defense loads

Electrification Apollo 2 Optimize grid investment and operations in area of high load growth attributed to transportation electrification

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TABLE 2 Existing Projects Incompatibility with DESI

Project Status as of May 2017

DESI incompatibility

Tehachapi Storage Project

Soon to be restarted

System dedicated to CAISO market dispatch per CPUC Resolution E-4809

Irvine Smart Grid Demonstration – Community Energy Storage

Decommissioned Unavailable and too small

Irvine Smart Grid Demonstration – Containerized Energy Storage

Provided to UC Irvine

Unavailable

Catalina Island Operational Antiquated technology serving atypical load on an island

Distributed Energy Storage Integration 1

Operational First deployment of DESI program; dedicated function does not overlap with 12 projects in 2018 GRC (see Table 1)

Mira Loma A & B Operational System dedicated to CAISO market dispatch per CPUC Resolution E-4791

Center & Grapeland Enhanced Gas Turbines

Operational System dedicated to CAISO market dispatch per CPUC Resolution E-4791

Distributed Energy Storage Integration 2 & 3

Planned Compatible – TURN and SCE in agreement projects should proceed with cost recovery

��

TABLE 3 Existing Projects Relationship to DESI

Project DESI relationshipDESI 1 See Table 1, Table 2 DESI 2, DESI 3 Learnings not duplicated, see Table 1 PRP PRP defers or eliminates need to procure new gas-fired generation in South

Coast basin; dispatch of capacity procured in support of PRP does not support DESI objectives

DRP Funding available through the DRP is limited, with explicit Commission guidance to leverage other programs. SCE identified synergies between the DRP and 2018 GRC objectives. The DRP Demonstration D is enabled by DESI 2 & DESI 3, not duplicated by DESI 2 & DESI 3. Upon completion of the DRP Demonstration D these two storage systems will continue to support local distribution reliability through their service lives.

IDER The upcoming IDER Utility Regulatory Incentive Mechanism Pilot requires complementing the DRP Demonstration C. This pilot, similar to DRP Demonstration C will use customer resources for demand response, which does not support DESI objectives.

Tehachapi Storage Project

See Table 6

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TABLE 4 CEC’s EPIC Projects Relationship to DESI

Entity Project Project objectives – none of which overlap with SCE DESI objectives as described above

SunSpec Alliance EPC-14-036 Advancement of inverter technology; DESI pilots will use commercially available, UL-listed inverters.

The Regents of the University of California, on behalf of the Riverside Campus

EPC-15-003 Testing pre-commercial flow-batteries; DESI pilots will use commercially available, UL-listed storage components.

The Regents of the University of California, San Diego

EPC-14-005 Advancement of Localized Constructed Analogs (LOCA) with inclusion of climate data; the learnings from this TD&D project (improved solar forecasting) could support the more efficient operation of the DESI pilots deployed to facilitate preferred resources.

Eos Energy Storage, LLC

EPC-14-023 Battery technology testing in laboratory environment; DESI pilots will use commercially available, UL-listed storage components.

Prospect Silicon Valley dba Bay Area Climate Collaborative (BACC)

EPC-14-083 Advancement of hardware integration of solar PV, storage and power electronics; DESI pilots will use commercially available hardware that is certified by proper agency (e.g., UL or other, as applicable).

The Regents of the University of California, Davis

EPC-14-085 Demonstration of community scale energy management, retire EV batteries; DESI pilots will deploy new storage components for their full useful life.

Gridscape Solutions EPC-14-050 Advancement of microgrid energy management systems; 1 or 2 DESI systems may support customer-driven microgrids, but DESI funds are not supporting microgrid energy management development.

Robert Bosch LLC EPC-14-053 Renewable Based Direct Current Building Scale Microgrid. Some DESI systems may support microgrids, but all microgrids will be Alternative Current (AC) based.

The Regents of the University of California, on behalf of the Los Angeles campus

EPC-14-056 Demonstration of EV “smart” charging; DESI pilots are not explicitly coordinated with EV charging.

��

Appendix C

Workpaper – Southern California Edison / 2018 GRC

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r�efficiency�te

sting,�how

ever,�they�are�no

t�currently�con

nected�to

�the�grid�te

st�facility.

�Ductle

ss�re

side

ntial�A

/C�unit�w

ith�variable�freq

uency�drives�(V

FD)?

We�can�replicate�vario

us�grid

�con

ditio

ns�su

ch�as�v

oltage�flicker�a

nd�in�rush�current.

Non

e.

�Second

ary�vo

ltage�re

gulatio

n�de

vices?

We�have�th

e�ability�to

�simulate�diffe

rent�pow

er�factor�con

ditio

ns�and

�vary�system

�voltages.

Non

e.

12Doe

s�you

r�facility�currently�have�the�ab

ility�to

�ene

rgize�utility�and

�customer�devices�in

�order�to

�ope

rate�th

em�

in�a�con

trolled�en

vironm

ent,�isolated

�from

�the�electric�grid

?Yes

Utilizing�a�grid

�simulator,�PV�sim

ulators,�and

�load�banks�we�can�replicate�real�world�grid

�cond

ition

s�usin

g�iso

lated�test�panels.�

X

13If�yes�to�Q.�12,�doe

s�you

r�facility�have�the�capa

bility�to�su

bject�the

se�devices�to

�abn

ormal�voltage�and

/or�

freq

uency�tran

sien

ts�th

at�are�re

presen

tativ

e�of�actua

l�events�tha

t�can

�occur�on�the�electric�grid

�to�und

erstan

d�the�de

vice�re

spon

se�during�such�events?

Yes

Utilizing�a�grid

�simulator,�PV�sim

ulators,�and

�load�banks�we�can�r eplicate�real�world�grid

�cond

ition

s�usin

g�iso

lated�test�panels.�

X

Doe

s�you

r�facility�have�the�ab

ility�to

�gen

erate�arbitrary�an

d�tran

sien

t�waveforms�w

ith�th

e�prog

rammab

le�

power�su

pplie

s�which�wou

ld�allo

w�th

e�assessmen

t�of:

X

�The�OPA

L�RT

�real�time�sim

ulator�is�tightly�interfaced�to

�voltage�and

�current�amplifiers�that�

can�drive�sig

nals�up

to�150

V�and�2A

�RMS�for�frequ

encies�between�30

�Hz�to�1kHz.��Ad

ditio

nally,�

an�Omicron�25

6�programmable�m

ulti�ph

ase�sig

nal�sou

rce�is�used�fo

r�relay�te

sting�and�is�

capable�of�m

uch�of�what's�listed�here.

�PV

�inverter�voltage/frequ

ency�protection?

Yes

Usin

g�grid�and

�PV�sim

ulators�v

oltage�dips�a

nd�sw

ells�are�created�for�e

valuation�of�devices.�

X

�Ride

�throu

gh�cha

racteristic

s,�stab

ility�during�oscillatio

ns?

Yes

Usin

g�grid�and

�PV�sim

ulators�v

oltage�dips�a

nd�sw

ells�are�created�for�e

valuation�of�devices.�

X

�An

ti�island

ing�capa

bilities?

Yes

Utilize

�load�banks�to

�match�load�with

�inverter�based�generation.

X

�Harmon

ics�g

eneration?

Yes

A�grid�simulator�is�used�to�generate�volta

ge�harmon

ics�a

nd�high�resolutio

n�mon

itorin

g�equipm

ent�to�assess�device�performance.

X

�Fault�current�con

tribution?

Yes

We�can�create�faults�or�sho

rt�circuits�via�phase�to

�phase�and

�phase�to

�groun

d�sim

ulations�in�

an�isolated�enviro

nment.

X

Doe

s�you

r�facility�currently�have�the�follo

wing�eq

uipm

ent�a

nd�cap

abilitie

s?�If�yes,�w

hat�is�the

�level�o

f�integration�be

twee

n�these�de

vices?

Custom

ized�test�se

tups�can�be�created�to�intergrade�all�of�th

ese�device�capabilitie

s�depending�

on�th

e�testing�needs.��For�example,�inverter�te

sting�wou

ld�utilize

�all�of�th

ese�devices�a

nd�air�

cond

ition

ing�testing�wou

ld�not�use�a�PV�sim

ulator.��

�PV

�Sim

ulators�(Prog

rammab

le�DC�Po

wer�Sup

plies)?

Yes

X

�Prog

rammab

le�irradian

ce�&�te

mpe

rature�profiles?

Yes

X

�Grid

�Sim

ulators�(Prog

rammab

le�AC�Po

wer�Sup

plies)?

Yes

XYes.�OPA

L�RT

�real�time�sim

ulator�(EMTP,�Transient�stability�simulations)�w

ith�voltage�and

�current�a

mplifiers.��Also�Omicron�25

6�source.

�Vo

ltage�&�freq

uency�tran

sien

t�gen

eration?

Yes

X�Harmon

ics�w

aveform�gen

eration?

Yes

X�Arbitrary�waveform�gen

eration?

Yes

X�Load

�Ban

ks?

Yes

XStand�alon

e�5kW�load�bank

�Prog

rammab

le�pow

er�fa

ctor?

Yes

XOmicron�25

6�multi�ph

ase�sig

nal�sou

rce,�program

mable�PF.��

�Cu

stom

�wave�shap

es?

Yes

XYes.�This�c

an�be�do

ne�with

�the�same�setups�as�d

escribed�abo

ve�fo

r�the�voltage,�current�and

�frequency�ranges�m

entio

ned.

�Sh

ort�C

ircuit�T

est�B

ox?

Yes

X�Multip

le�fa

ult�com

bina

tions�(3

ph�gnd

,�ph�ph

,�1ph

�gnd

,�etc.)?

Yes

XOmicron�25

6�describ

ed�abo

ve�can�be�used�fo

r�fault�testing�relays.

15Yes.�This�c

an�be�do

ne�with

�the�same�setup�as�described�abo

ve�fo

r�the�voltage�and

�current�

ranges�fo

r�frequ

encies�between�30

�Hz�to�1kHz.��

Omicron�25

6�can�do

�the�same�with

�voltages�u

p�to�150

�Vrm

s�and

�current�up�to�75�Arms.

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uted

�Ene

rgy�Re

sources

11 14These�scenarios�c

an�be�mod

eled�in�OPA

L�RT

�and

�the�correspo

nding�sig

nals�can�be�generated�

through�the�analog�outpu

t�interfacing�with

�the�volta

ge�and

�current�amplifiers�m

entio

ned�

above.�Add

ition

ally,�the�Omicron�25

6�source�can�generate�harm

onics�a

nd�be�used�fo

r�fault�

current�testin

g�of�re

lays�and

�similar�d

evices�(w

ith�se

parate�voltage�and

�current�inpu

ts)

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stions�

Controls

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ution�Au

tomation

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dent�01

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e�follo

wing�qu

estio

ns�in

�reference�to�you

r�current�fa

cilities'�technical�test�a

bilities.�NOTE:�The

se�que

stions�are�prefaced�with

�the�follo

wing�stipulations�in

�order�fo

r�a�"Ye

s"�to

�be�a�valid

�respon

se:

1.�The�te

st�facility�do

es�not�need�to�und

ergo�significant�re

mod

eling�to�accom

mod

ate�testing�of�su

ch�te

chno

logy�or�if�test�facility�can�m

eet�test�capability,�but�re

quire

s�minor�re

tool�of�facility�or�test�a

pparatus�to

��

��accom

mod


ch�te

chno

logy,�the�re

tool�time�will�ta

ke�less�th

an�one�week�to�com

plete.

2.�Test�facility�currently�has�all�necessary�equipm

ent�to�cond

uct�testin

g�with

out�h

aving�to�procure�te

st�equ

ipment�b

y�either�purchasing�or�re

nt/le

ase�agreem

ents�to

�meet�testin

g�capabilities.

3.�Test�facility�has�qualified�person

nel�on�staff�to�cond

uct�said�tests.

4.�Data�that�re

sults�from

�all�tests�m

ust�b

e�collected�from

�calibrated�NIST�traceable�equipm

ent�(where�app

licable)�and

�must�b

e�assessed�usin

g�standard�and

�accepted�practices�of�u

ncertainty�analysis.

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spon

se

SC

E C

onfid

entia

lP

age

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42

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SC

E T

and

D B

ench

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king

Adv

ance

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ory

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ties

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vey

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6

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tsYe

sNo

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tsSurvey�Que

stions�

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dent�01

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spon

se

16Doe

s�you


ility�to

�supp

ort�smart�g

rid�in

itiatives�th

at�re

quire

�radio�commun

ications�

testing/evalua

tion�an

d/or�utilize�sm

art�m

eter�data�an

d�infrastructure?

Yes

�HAN

�and

�FAN

.X

17Is�you


able�of�u

sing

�smart�m

eter�data�to�im

prov

e�accuracy�of�the

�meter/transform

er�

correlation�mod

el?

Yes

Smart�m

eter�outage�data�is�used�to�correlate�m

eter�to

�transformer.�V

oltage�signature�

analysis�is�also�used.

X

18Wha

t�are�you

r�facility�cap

abilitie

s�to�test�ra

dio�commun

ication�for�H

ome�Area�Network�(HAN

)�and

�Field�Area�

Network�(FAN

)�and

�other�te

lecom�fo

r�distribution�fie

ld�equ

ipmen

t?Yes

HAN:�Sniffe

rs,�Zigbee�do

ngles:�RainForest,�Da

intree,�M

MB,�Telegesis.�RF:�antenna,�spectrum�

analyzer,�test�h

arness�fo

r�interference,�re

mote�sensors�for�coverage�/�R

SSI�testin

g.��

FAN:Network,�M

esh,�Pt�to�Pt.�Throu

ghpu

t�and

�interference�te

sting.�Network�security�testing.�

NTP�time�and�reciever�se

nsitivity�(stepp

ed�attenuators)

Is�you

r�facility�currently�equ

ippe

d�with

�the�follo

wing?

�Sign

al�gen

erators�a

nd�ana

lyzers?

Yes

Vector�generators,�sp

ectrum

�analyzer,�po

wer�m

eters,�and

�GPS�time�standard.

X�ZigB

ee�sign

al�se

nsors�a

nd�decod

ers?

Yes

See�18

�(abo

ve)

X�Test�harne

sses?

Yes

Quality�Logic�SEP�2.0�harness.

X

�Po

werlin

e�carrier�signa

l�gen

erator?

Yes

PLC�test�sy

stem

�from

�NESTA

�/�AE

P.�Permanent�lab�installatio

n�for�interference�testing.

X

�Ra

dio�sign

al�isolation�bo

xes�a

nd�Farad

ay�Cage?

Yes

Full�size�Faraday�cage.�FAN

�testing�with

�RF�enclosures.

X

�Sm

art�m

eters�a

nd�cell�relays?

Yes

Live�lab�reference�samples�at�p

rodu

ction�revisio

n.X

Doe

s�you

r�facility�currently�ope

rate�with

�the�follo

wing�eq

uipm

ent�a

nd/or�cap

abilitie

s?

�Ph

otov

oltaic�(P

V)�simulators�a

llowing�simulation�of�PV�or�Storage�(D

C)�in

teractions?

Yes

PV�simulator�allowing�sim

ulation�of�PV�and�Storage.�

X

�En

ergy�Storage,�Electric

al�Veh

icles�(EV

s),�D

C�Fast�Cha

rger,�R

oof�T

op�PV�to�allo

w�dem

onstratio

n�an

d�evalua

tion�of�com

mun

ications�and

�con

trols�integratio

n?Yes

EVSE�ra

ck�allowing�testing�of�level�2�EVS

E's,�3.3KW

�roof�to

p�PV

�con

nected�to

�a�storage�device.�

All�devices�are�networked�allowing�for�d

emon

stratio

n�of�com

mun

ication�and�controls.

X

�External�and

�Internal�Network�Interfaces��For�in

terfacing�with

�con

trols�systems,�in

ternet�based

�entities,�

and�internal�equ

ipmen

t?Yes

Open�internet�access�a

nd�facility�netw

ork�access.

X

21Doe

s�you

r�facility�currently�have�the�capa

bility�to�con

duct�both�op

en�and

�closed�loop

�testing�in�a�sa

nd�box�

type

�env

ironm

ent?

Yes

With

�the�PV

�simulator�and

�gird

�simulator�we�have�th

e�ability�to

�create�sand

�box�type�te

st�

environm

ents.��

XGrid

�simulators�a

llow�us�to�cond

uct�"sand

�box"�tests.��HIL�(Opal�R

T)�allows�for�te

sting�of�

specific�applications�and

�a�con

nection�to�Grid

LAB�D�allows�for�sc

alability.�

22If�yes�to�Q.�21,�is�you

r�facility�able�to�simulate�an

d�evalua

te�a�virtua

lly�unlim

ited�set�o

f�use�cases�in

�safe�and

�controlle

d�cond

ition

s?Yes

All�use�cases�th

at�pertain�to

�customer�owned�DE

R's.�

XUse�cases�are�virtually�unlim

ited.

23Doe

s�you


ility�to

�evaluate�an

d�utilize�se

veral�m

odeling�tools�to�de

velop�

distrib

ution�circuit�m

odels?

Yes

X

24If�yes�to�Q.�23,�can

�these�mod

els�sho

w�accurate�dy

namic�and

�steady

�state�simulations�re

presen

ting�be

yond

�the�

meter�lo

ads�leveraging�sm

art�m

eter�data?

Yes

We�can�create�detailed�beyond

�the�meter�load�m

odels�for�re

sidentia

l�customers�a

nd�load�

profiles�for�com

mercial�customers.�These�m

odels�a

re�used�to�stud

y�the�dynamic�and

�steady�

state�cond

ition

s.�W

e�also�perform

�dynam

ic�simulations.�

XGrid

LAB�D�incorporates�behind�the�meter�load�m

odeling�that�can�be�calibrated�to�AMI�data.

25Doe

s�you


ility�to

�ana

lyze�and

�visua

lize�test�data�an

d�results�to

�develop

�integration�strategies�and

�inform

�field�de

ploy

men

t�of�con

trol�equ

ipmen

t,�en

ergy�storage�an

d�othe

r�devices?

Yes

We�analyze�and�visualize

�data�from

�tests�a

nd�bulk�data�from

�the�grid.�

XWe�have�integrated�to

ols�to�analyze�and�visualize

�test�data.

26Can�yo

ur�fa

cility�curren

tly�evaluate�differen

t�softw

are�tools�a

nd�so

lutio

ns�th

at�provide

�visua

lization�of�pow

er�

distrib

ution�system

s?�

Yes

We�can�evaluate�m

any�softw

are�tools�in�a�secured�test�enviro

nment�w

ithou

t�affe

cting�the�

grid.��

XAlthou

gh�so

me�mod

ificatio

ns�are�needed�to�align�data�se

ts�to

�data�form

at�re

quire

ments�of�

diffe

rent�to

ols.

27Doe

s�you


ility�to

�develop

/evaluate�ne

w�datab

ase�structures�and

�mathe

matical�

metho

dologies�su

ch�as�d

imen

sion

�redu

ction�to�han

dle�distrib

uted

�data?

Yes

We�have�th

e�ability�to

�test�and

�develop

�new

�database�structures.�

XAn

d�we�have�a�strong�te

am�in�data�analytics�research.

28Can�yo

ur�fa

cility�curren

tly�con

duct�time�serie

s�ana

lysis�to�dy

namically�calculate�th

e�distrib

uted

�ene

rgy�

resource�(D

ER)�h

ostin

g�capa

city�fo

r�any

�given

�nod

e�with

in�th

e�distrib

ution�an

d�tran

smission

�system

�for�a

ny�

hour�of�the

�day?

Yes

We�have�th

e�ability�to

�perform

�time�serie

s�analysis.�

XDistrib

ution�on

ly.

29Doe

s�you


ility�to

�con

duct�hardw

are�in�th

e�loop

�con

trol�sy

stem

�testing,�protective�

relay�testing,�wide�area�protection�an

d�control�testin

g?Yes

The�sim

ulators�c

an�driv

e�a�low�level�relay�inpu

t,�or�can�driv

e�a�Do

ble�test�se

t�for�a�se

cond

ary�

volta

ge�and

�current�inpu

t.�Several�tests�have�been�con

ducted�usin

g�relays�to

�evaluate�and�test�

wide�area�protection�techniqu

es.�

XYes�to�all.�

30Doe

s�you


ility�to

�evaluate�sm

art�g

rid�develop

men

t�for�in

clusion�in�an�electrical�

grid?

Yes

Smart�g

rid�equ

ipment�can�be�tested,�evaluated,�and

�coo

rdinated�usin

g�hardware�in�th

e�loop

�sim

ulations.��

XSm

art�g

rid�app

lications�can�be�tested�in�sm

all�scale�HIL�or�large�scale�simulation.

31Doe

s�you


ility�to

�run�large�scale�real�tim

e�simulations�utilizing�control�system�and

�relay�commun

ications�equ

ipmen

t?Yes

The�full�bu

lk�sy

stem

�mod

el�can�be�sim

ulated�usin

g�real�time�sim

ulations�enviro

nment�that�

combine�both�controls�and�protectio

n�hardware�as�well�as�the�transie

nt�m

odels�o

f�the�sy

stem

�compo

nents.��

XLarge�scale�real�time�sim

ulations�can�be�performed�via�Grid

LAB�D;�incorporating�a�co�

simulation�engine,�this�c

an�re

ach�the�scale�of�~1,00

0�circuits.

32Doe

s�you

r�facility�currently�have�a�platform

�to�te

st�in

tegration�of�in

�service�legacy�proprietary�su

bstatio

n�au

tomation�system

s�based

�on�Mod

bus�P

lus�a

nd�M

odbu

s�protocols�with

�new

�IEC�61

850�op

en�stan

dards�

system

s?Yes

This�facility�has�a

ll�necessary�equipm

ent�a

nd�personn

el�to

�perform

�integration�test�usin

g,�

Mod

bus�P

lus,�M

odbu

s�TCP

,�Mod

bus�R

TU,�and

�all�protocols�u

sed�in�IEC�61

850.

XWe�have�th

e�capability�to�te

st�M

odbu

s�and

�IEC�61

850�with

�supp

ortin

g�devices,�so

ftware,�and

�expertise

.�We�lack�su

pport�for�M

odbu

s�Plus.

33Doe

s�you

r�facility�currently�have�direct�con

nectivity

�to�a�te

st�ene

rgy�man

agem

ent�system�fo

r�testin

g�an

d�integrating�ne

w�su

pervisory�control�and

�data�acqu

isition

�(SCA

DA)�sy

stem

s?�

Yes

This�facility�has�c

ommun

ications�to

�a�te

st�EMS�system

.��System

�test�can�be�performed�on�bo

th�

Seria

n,�and

�Ethernet�C

hann

els.

XWe�currently�have�access�to

�an�Alstom

�EMS�&�DMS�for�integratio

n�into�te

st�cases.

34Doe

s�you

r�facility�currently�have�an

�in�hou

se�re

al�tim

e�digital�sim

ulator�sy

stem

�for�testin

g�of�su

bstatio

n�protectio

n�an

d�au

tomation�functio

ns�to

�fully�vet�and

�test�next�g

eneration�substatio

n�au

tomation�system

s?Yes

We�currently�use�re

al�time�digital�sim

ulators�a

nd�a�variety�of�I/O

�mod

ules�dedicated�fo

r�substatio

n�automation�system

�testing.

XWe�have�an�OPA

L�RT

�real�time�po

wer�sy

stem

�simulator�cou

pled�with

�voltage�and

�pow

er�

amplifier�cards�fo

r�HIL�te

sting.

35Doe

s�you


ility�to

�mim

ic�a�large�substatio

n�(up�to�70�racks)�fo

r�testin

g�of�grid

�mod

ernizatio

n�eq

uipm

ent?

No

XWe�can�mod

el�a�large�substatio

n�with

in�th

e�OPA

L�RT

�with

�subsets�o

f�real�equ

ipment�w

here�

necessary.

Substatio

n�Au

tomation

Garage�of�th

e�Future�

20 Distrib

ution�Grid

�Ana

lytics

Power�Systems

Grid

�Edge�Solutio

ns

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SC

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and

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ench

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stions�

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dent�01

SCE�Re

spon

se

Do�yo

u�curren

tly�have�a�high

�voltage�distribution�circuit�(12

kV�35kV)�fa

cility�de

dicated�to�te

sting�ne

w�

equipm

ent?�If�yes,�p

lease�an

swer�th

e�follo

wing:

Yes

•�Doe

s�this�facility�fe

ed�any

�customers?

No

This�circuit�d

oes�n

ot�feed�any�customers.�

•�Is�th

is�fa

cility�integrated

�with

�other�distribution�circuits�fe

d�from

�the�source�su

bstatio

n?�

Yes

The�circuit�is�fed�from

�a�dedicated�circuit�b

raker�from�a�su

bstatio

n�which�feeds�o

ther�12kV�

circuits.

•�Is�th

is�fa

cility�capa

ble�of�perform

ing�integration�testing�that�wou

ld�in

clud

e�radio�an

d�commun

ication�

system

s�used�for�circ

uit�a

utom

ation�an

d�mon

itorin

g?Yes

•�Can�this�fa

cility�pe

rform�simultane

ous�testin

g�of�up�to�10�au

tomated

�fault�interrupting�de

vice�in

clud

ing�

overhe

ad,�p

admou

nt�and

�und

ergrou

nd�(inside�a�vault)?�

Yes

Circuit�h

as�both�overhead�and

�und

ergrou

nd�se

ctions�to

�enable�diffe

rent�te

st�con

figurations�

and�scenarios,�m

ultip

le�te

st�pads�a

nd�an�un

dergroun

d�vault.


cility�pe

rform�simulation�of�various�fa

ult�m

agnitude

�and

�con

ditio

ns�on�12

kV�distribution�circuits?

Yes

Facility�is�equipp

ed�with

�fault�p

ads�a

nd�a�con

figurable�re

sistor�cabinet�dedicated�to

�fault�

testing.

•�Doe

s�this�facility�have�a�po

wer�sy

stem

�simulator�with

�hardw

are�in�th

e�loop

�testing�capa

bility?

Yes

•�Doe

s�this�facility�have�the�capa

bility�to�te

st�a�m

icrogrid�with

�devices�th

at�allo

w�fo

r�recon

figuration�such�as�

load

�ban

ks,�grid

�simulator,�smart�inv

erters,�b

attery�storage�an

d�vo

ltage�re

gulatio

n�de

vices�(capa

citor,�

volta

ge�re

gulator,�etc.)�a

t�12kV?

Yes

•�Doe


bility�to�con

figure�test�fo

r�overhead�an

d�un

dergroun

d�cond

uctors�or�a

�combina

tion�of�both?

Yes

The�circuit�con

sists�of�b

oth�overhead�and

�und

ergrou

nd�portio

ns.�


cility�pe

rform�high�im

peda

nce�fault�testin

g�on

�an�en

ergized�12

kV�circ

uit�w

ith�a�com

bina

tion�of�

overhe

ad�con

ductor�and

�und

ergrou

nd�cab

les�w

ithin�th

e�ne

xt�2�m

onths?

Yes

We�have�perform

ed�se

veral�12kV�high�im

pedance�fault�tests�at�this�facility.


cility�lim

it�the�fault�current�to

�any

�specific�rang

e?Yes

A�resistor�cabinet�can�be�used�to

�limit�current�d

uring�fault�testin

g.•�Doe


bility�of�in

tegrating�2M

W�battery�storage�that�can

�act�both�as�a�so

urce�and

�load

?Yes

•�If�yes�to�the�previous�que

stion,�is�th

e�facility�configured

�to�allo

w�th

e�2M

W�battery�to

�con

nect�to

�various�

locatio

ns�on�the�12

kV�circ

uit�b

y�pe

rforming�circuit�switc

hing

�using

�12�kV

�distribution�sw

itche

s�(for�v

arious�

test�sc

enarios)?

Yes

•�Doe

s�this�facility�currently�have�an

�integrated

�grid

�simulator�devices?�

No

Once�control�roo

m�con

struction�is�complete,�simulator�devices�will�be�incorporated�and

�conn

ected�to�circuit.

•�If�yes�to�the�previous�que

stion,�doe

s�this�facility�currently�ope

rate�a�1MVA

�@�12kV�grid�simulator�whe

re�

volta

ge,�frequ

ency,�real�and

�reactiv

e�po

wer�(u

tility

�and

�customer�lo

ad)�can

�be�simulated

�and

�adjusted�to�

replicate�fie

ld�events?


cility�test�sh

ort�circuit�impa

ct�at�1

2kV�for�D

istributed

�Ene

rgy�Re

sources�(DER

)?Yes


cility�test�voltage�im

pacts�o

n�DER

�switc

hing

�devices?

Yes

•�Doe

s�this�facility�currently�have�integrated

�second

ary�(up�to�2�M

VA,�w

ith�step

�up�tran

sformers�to�12

kV)�

load

�ban

ks?

Yes

Facility�has�load�banks�(up

�to�2�M

VA)

•�Doe

s�this�facility�have�a�da

ta�acquisitio

n�system

�with

�the�ab

ility�to

�process�and

�display�data?

Yes

•�Doe

s�this�facility�have�a�de

dicated�control�roo

m�whe

re�in

form

ation�techno

logy�back�office�system

s�and

�control�systems�c

an�be�man

aged

?Yes

Control�building�is�in�th

e�fin

al�stages�of�p

lann

ing�and�perm

itting�with

�an�expected�opening�of�

Q1�20

17.

•�Doe


bility�to�te

st�su

bstatio

n�process�b

us�(d

igita

l�sub

station)?

Yes

37Do�yo

u�ha

ve�a�fa

cility�capa

ble�of�m

onito

ring�test�circ

uits�and

�the�tests�p

erform

ed�using

�an�existin

g�distrib

ution�

man

agem

ent�system�(D

MS)?

Yes

38Do�yo

u�ha

ve�a�fa

cility�capa

bility�of�simulating�vario

us�circ

uit�len

gths?

Yes

This�is�po

ssible�by�utilizin

g�diffe

rent�sw

itching�procedu

res�a

nd�circuit�con

figurations.

39Do�yo

u�ha

ve�a�fa

cility�capa

bility�of�simulating�differen

t�circ

uit�con

figurations�(loo

p,�ra

dial,�n

etwork)?

Yes

This�is�po

ssible�by�utilizin

g�diffe

rent�sw

itching�procedu

res�a

nd�circuit�con

figurations.

40Doe

s�you


bility�to�te

st�large�ba

tteries�systems�w

ith�m

axim

um�ra

tings�of�9

00�V�DC,�100

0�A�

DC,�and

�250

�kW�in

�large�tempe

rature�con

trolled�en

vironm

ents�(u

p�to�870

�cub

ic�ft,�b

etwee

n��45°C�an

d�70

°C)?

Yes

xOrganiza

tion'�does�n

ot�currently�have�the�capability�to�te

st�energy�storage�system

s�with

�these�

requ

irements

41Wha

t�is�the

�total�n

umbe

r�of�ind

ividua

l�tests�on�large�ba

tteries�systems�tha

t�can

�be�tested

�at�a

ny�given

�time?�

Note:�th

is�que

stion�refers�to

�the�nu

mbe

r�of�ind

ividua

l�tests�th

at�can

�be�run�in�parallel.

Four�te

sts�a

t�900

�V�DC�/�5

00�A�DC�or�tw

o�at�900

�V�DC�/�1

000�A�DC

42Doe

s�you


bility�to�te

st�batterie

s�packs�with

�maxim

um�ra

tings�of�4

45�V�DC,�265

�A�DC,�and

�12

5�kW

�in�large�tempe

rature�con

trolled�en

vironm

ents�(u

p�to�64�cubic�ft,�b

etwee

n��45°C�an

d�70

°C)?

Yes

XOrganiza

tion'�does�n

ot�currently�have�the�capability�to�te

st�battery�packs�with

�these�

requ

irements

43Wha

t�is�the

�total�n

umbe

r�of�ind

ividua

l�tests�on�ba

tteries�p

acks�th

at�can

�be�tested

�at�a

ny�given

�time?

14�te

sts�a

t�445

�V/�2

65�A/�1

25�kW�or�u

p�to�fo

ur�at�4

45�V�/�53

0�A�/�1

25�kW�and

�up�to�th

ree�at�

445�V�/�6

40�A�/�12

5�kW

44Doe

s�you


bility�to�te

st�battery�cells�with

�maxim

um�voltage�of�5

�V�DC�an

d�40

0�A�DC�in�

tempe

rature�con

trolled�en

vironm

ents�(b

etwee

n��34°�and

�70°C)?

Yes

xOrganiza

tion'�ro

utinely�tests�ind

ividual�cells�in�te

mperature�con

trolled�environm

ents.

45Wha

t�is�the

�total�n

umbe

r�of�b

attery�cells�th

at�can

�be�tested

�at�a

ny�given

�time?�Note:�th

is�que

stion�refers�to

�the�

numbe

r�of�ind

ividua

l�tests�th

at�can

�be�run�in�parallel.

Two�cells�at�5

�V�DC/40

0�A�or�eight�cells�at�5�V/�1

00�A.��An

�add

ition

al�16�cells�can�be�tested�at�

5�V/10

A,�or�fou

r�at�5

0�V/40

�A.�

Currently��in�excess�of�3

00�chann

els�that�can�te

st�5V��4

0A�sy

stem

s,�~�3�te

st�sy

stem

s�that�can�

hand

le�5V�40

0A.�

46Doe

s�you


bility�to�te

st�a�com

plete�en

ergy�storage�system

�(ESS)�w

ith�m

axim

um�ra

tings�of�

480�V�AC

,�and

�250

�kW�and

�up�to�140

�sq.ft.�foo

tprin

t�per�sy

stem

?Yes

XCo

mplete�energy�storage�system

s�have�been�te

sted�at�'Organiza

tion'�an�intercon

nected�to

�bu

ilding�and�PV

�resources�for�use�case�analysis

Doe

s�you


bility�to�te

st�in

dividu

al�critical�com

pone

nts�o

f�an�ESS?

Yes

•�Po

wer�Con

version�System

s�(PC

S)?

Yes

x

•�Ba

ttery�Man

agem

ent�S

ystems�(BM

S)?

Yes

x

•�Co

ntrol�and

�com

mun

ication�interface?

Yes

x

Doe

s�you


bility�to�con

duct�grid

�impa

ct�te

sting�of�ESS�(e

.g.,�po

wer�qua

lity�an

alysis)?

•�Can�yo

ur�f a

cility��con

duct�te

sting�by

�con

necting�ESS's�to�the�grid?

Yes

Facility�has�the�necessary�te

st�beds�to�perform�grid

�con

nected�te

sting.�

XESS�system

s�have�been�te

sted�con

nected�to

�PV�and�bu

ildings�but�where�isolated�from

�the�

grid.��With

�app

roval,�grid�con

nection�is�po

ssible.

•�Can�yo

ur�fa

cility�cond

uct�testin

g�by

�utilizing�a�simulated

�gr id

�that�can

�run�profile

s�for�grid

�disturban

ces�a

t�vario

us�voltage�and

�pha

se�con

figurations?

Yes

X

49Wha

t�is�the

�total�n

umbe

r�of�E

SS�th

at�can

�be�tested

�at�a

ny�given

�time?

Maxim

um�of�1

8�system

s�and

�24�cells

50Doe

s�you


bility�to�con

duct�evaluation�of�Pho

tovo

ltaic�(P

V)�equ

ipmen

t�such�as�PV�arrays,�

and�PV

�inverters?

Yes

Yes,�'O

rganiza

tion'�has�a�128

kW�PV�array�which�has�beenp

reviou

sly�integrated�wth�larger�

scale�(125

kW/500

kWhr)�ESS�

Energy�Storage�(B

attery�Profiling,�Testin

g,�and

�Evaluation�Ca

pabilities)

47Organiza

tion'�has�th

e�capabilities�to�test�PCS�at�various�locatio

ns�across�c

ampu

s.��BMS�and�

ESS�control�and

�com

mun

ication�interfaces�have�tested�in�con

juction�with

�field�deployed�ESS�

system

s

48Equipm

ent�D

emon

stratio

n�&�Evaluation�Facility

36

SC

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onfid

entia

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age

3

44

��



SC

E T

and

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ench

mar

king

Adv

ance

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stions�

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dent�01

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spon

se

Doe

s�you


bility�to�con

duct�fu

el�econo

my�an

d�em

ission

s�testin

g�of�ligh

t�duty�vehicles�

according�to�fe

deral�stand

ards?

Yes

The�facility�cond

ucts�fu

el�econo

my�and�em

issions�light�d

uty�vehicles�as�d

efined�by�DO

T�with

�2�

onbo

ard�em

issions�te

sting�system

s.

•�Co

nven

tiona

l�ICE�Veh

icles?

Yes

Facility�has�e

xperience�with

�testing�prototype�and�prod

uctio

n�mod

el�vehicles�w

ith�

conventio

nal�internal�com

bustion�engines�p

ower�units.

X

•�Electric�Veh

icles?

Yes

Facility�has�e

xperience�with


uctio

n�mod

el�vehicles�w

ith�fu

ll�battery�

electric�pow

er�units.

X

•�Hyb

rid�Electric

�Veh

icles?

Yes

Facility�has�e

xperience�with


uctio

n�mod

el�vehicles�w

ith�hybrid

�battery�ICE�and�hydrogen�battery�pow

er�unit�ve hicles.

X

•�Gaseo

us�Fue

led�Ve

hicles?

Yes

On�road�only.�Experience�with

�testing�vehicles�with

�hydrogen�and�compressed�natural�gas�

power�units�but�lacks�g

arage�and�dynamom

eter�gaseous�fu

el�facilities.

X

Doe

s�you


bility�to�con

duct�heavy�duty�en

gine

�testing�according�to�fe

deral�stand

ards?

No

The�facility�is�no

t�equ

ipped�with

�an�engine�te

st�dynam

ometer.

•�Fuel�econo

my�testing?

No

X•�Em

ission

s?No

X•�Hyb

rid�Electric

�Driv

es?

No

X•�Gaseo

us�Fue

l�Eng

ines?

No

XDoe

s�you


bility�to�con

duct�fu

el�econo

my�an

d�em

ission

s�testin

g�of�heavy�duty�vehicles�

according�to�fe

deral�stand

ards?

Yes

The�facility�cond

ucts�fu

el�econo

my�and�em

issions�heavy�duty�vehicles�as�d

efined�by�DO

T�with

�2�on

board�em

issions�te

sting�system

s.

•�On�dy

namom

eter?

No

Light�to

�medium�duty�on

ly.�Facility�has�on�site�dynamom

eter�with

�2�and

�4�wheel�driv

e�capability�with

�a�m

axim

um�GVW

R�of�14,00

0�lbs.

X

•�On�road

?Yes

Facility�has�P

EMS�po

rtable�emissions�m

easurement�systems�a

nd�experience�with

�on�road�and

�track�testing�of�heavy�duty�vehicles.

X

•�Hyb

rid�Electric

�Veh

icles?

Yes

Facility�has�instrum

entatio

n�to�capture�electric�energy�flo

ws�a

nd�experience�with

�testing�

prototype�and�prod

uctio

n�mod

el�vehicles�w

ith�hybrid

�battery�IC

E�and�hydrogen�battery�

power�unit�vehicles.

X

•�Gaseo

us�Fue

l�Veh

icles?

Yes

On�road�only.��Facility�has�experience�with

�tes ting�prototype�and�prod

uctio

n�mod

el�vehicles�

with

�hydrogen�and�compressed�natural�gas�pow

er�units.

X

•�PE

MS�em

ission

s�testin

g?Yes

Facility�has�2

�system

s�for�PEM

S�testing.

X•�Ba

g�em

ission

s�testin

g?No

X•�Stationa

ry�utility

�or�o

ther�vocationa

l�cycles?

Yes

Facility�has�e

xperience�testing�utility�to

ols�in�typical�utility�lineman�duty�cycles.

XDoe

s�you


bility�to�te

st�Electric

�Veh

icle�Sup

ply�Eq

uipm

ent�(EV

SE)?

Yes

Facility�has�D

ranetz�Pow

er�Profilers.

•�SA

E�J177

2�Levels�1�and

�2?

Yes

Facility�has�E

V�em

ulators,�Evs,�and

�grid

�simulators;�m

ultip

le�sites�for�lab�and�field�evaluation.

X

•�SA

E�J177

2�Level�3�AC?

Yes

Facility�has� h

igh�volta

ge�and

�high�po

wer�instrumentatio

n,�gr id

�simulators.

X•�SA

E�J177

2�DC�Fast�Cha

rge�Co

mbo

�CCS?

Yes

Facility�has�h

igh�volta

ge�and

�high�po

wer�instrumentatio

n,�grid

�simulators.

X

•�Bidirectiona

l�pow

er�EVS

E?Yes

Facility�has�g

rid�simulators,�instrumentatio

n,�and

�experience�with

�bidire

ctional�pow

er�EVS

E�testing.

X

•�AC

�3�pha

se�EVS

E?Yes

Facility�has�D

ranetz�Pow

er�Profilers.

X

•�Overhead�cond

uctiv

e�po

wer�tran

sfer�EVS

E?No

Field�test�only.

X

•�Wire

less�pow

er�tran

sfer�EVS

E?Yes

PQ�and

�EMF�(field�on

ly).

X

•�Fast�Cha

rge�Ch

AdeM

O?

Yes

Facility�has�1

�site�fo

r�ChA

deMO�fast�charging.

X•�Grid

�simulation�an

d�grid�im

pacts?

Yes

Facility�has�g

rid�simulators�a

nd�SAE

�J289

4�expertise

.X

Doe

s�you

r� facility�have�the�capa

bility�to�te

st�fu

ll�plug

�in�electric

�veh

icle�(P

EV)�cha

rging�system

s�for�effect,�

efficiency,�and

�pow

er�qua

lity?

Yes

•�SA

E�J289

4/2?

Yes

X

•�California�Title

�20?

Yes

X

•�Ve

hicle�to�grid

�system

s,�IEEE�154

7,�UL�17

41?

Yes

XDoe

s�you


bility�to�te

st�auxiliary�po

wer�sy

stem

s?Yes

•�En

gine

�gen

erators?

Yes

X

•�Ba

ttery�po

wer�sy

stem

s�including

�BMS�an

d�controls?

Yes

X

•�AC

�pow

er�in

verter�sy

stem

s,�pow

er�qua

lity,�in

put�ou

tput?

Yes

X

•�DC�DC�po

wer�sy

stem

s?Yes

X

•�Hyd

raulic�pow

er�sy

stem

s?Yes

X•�Po

wer�th

ermal�m

anagem

ent�systems?

Yes

X

•�Electrical�isolation�an

d�pe

rson

nel�p

rotection?

Yes

X

•�HVA

C�system

s?Yes

X

•�Co

mpressed�air�storage�sy

stem

s?Yes

XDoe

s�you

r�facility�have�in�hou

se�CFR/EPA

�s pecificatio

n�chassis�d

ynam

ometer?�

Yes

•�Ligh

t�Duty?

Yes

Up�to�140

00�lbs.�GVW

RX

•�Heavy�Duty?

No

Up�to�140

00�lbs.�GVW

RX

•�Em

ission

s�measuremen

t?Yes

PEMS�po

rtable�sy

stem

sX

•�PE

V�charging

�infrastructure?

Yes

Charging�site�in�Dynam

ometer,�all�levels.

X•�Gaseo

us�fu

els?

No

X

55 56 57Electric�Transpo

rtation

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buy

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eede

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rnal

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t�of�the�box�so

lutio

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buy

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odelled�by�existing�programmable�

inverters

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elled�on

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dn�a�su

per�com

puter�for�use�in�a�so

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lab�environm

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lace�at�these�facilities.�

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are�(PSS®E,�PSS®Sincal,�PSS®ODM

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commun

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art�g

rid�

commun

ications�simulator,�called�'nam

e',�w

hich�has�th

e�ability�to

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commun

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chno

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nd�data�from

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distrib

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its�can�be�locally�deployed�to�customer�

facility�for�faster�sim

ulation,�te

sting�and�diagno

stics.

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�RPI�Center�for�Future�Energy�Systems�(CFES)�to�sim

ulate�the�

integration�of�DER

�and

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em�in�an�RT

DS�lab�near�'location'.

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are,�i.e.�usin

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at�will�be�stud

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uties.�Up�to�63kA�fault�testin

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n'�Polygeneration�Lab

xX

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xX

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mak

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usly

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quipment�a

s�needed,�and

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er�internally�or�a

t�other�facilitie

s.

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s con

tinuo

usly

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quipment�a

s�needed,�and

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er�internally�or�a

t�other�facilitie

s.

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focu

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eeded.

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pports�a�ra

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No

XX

We�have� doing�th

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sting�and�pion

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many�years.�W

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ing�multiyear�lab�and

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small�scale�and

�utility�size�energy�storage.�Prio

r�lab�te

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ited�to�te

mperature�

control�between�10

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wever�we�have� indu

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ition

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requ

ired.

No

XX

Prior�testin

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ited�to�te

mperatures�b

etween�10

C�and�50

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nmentally�con

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ental�con

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ired.

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�We�have�th

e�capability�to�do�cell�level�testin

g�althou

gh�initial�te

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arily�

focused�on

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ired.

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eeded.

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mon

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ication�interfaces�includ

e�CA

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ducted�various�pow

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nd�high�speed�transie

nt�perform

ance�

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extensive�testing�bo

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eeded.

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e�capability�to�do�this�testing�at�various�pow

er�levels

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XX

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XX

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e�capability�to�do�this�testing�at�various�pow

er�levels

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XX

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e�capability�to�do�this�per�o

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there�are�facilities�w

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Please�answer�th

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estio

ns�th

at�are�in�re

ference�to�you

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st�abilities.�The

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stions�are�prefaced�

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�the�follo

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�respon

se:

Survey�Que

stions�

Yes

No

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t

Energy�Storage�(B

attery�Profiling,�Testin

g,�and

�Evaluation�Ca

pabilities)

40D

oes

your

faci

lity

have

the

capa

bilit

y to

test

larg

e ba

tterie

s sy

stem

s w

ith m

axim

um ra

tings

of 9

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, 100

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rge

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ts (u

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, bet

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n -4

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and

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C)?

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hat i

s th

e to

tal n

umbe

r of i

ndiv

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l tes

ts o

n la

rge

batte

ries

syst

ems

that

can

be

test

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t any

giv

en ti

me?

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e: th

is q

uest

ion

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rs to

the

num

ber

of in

divi

dual

test

s th

at c

an b

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n in

par

alle

l.We�can�test�6�battery�sy

stem

s�at�a

ny�given

�time.

42D

oes

your

faci

lity

have

the

capa

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y to

test

bat

terie

s pa

cks

with

max

imum

ratin

gs o

f 445

V D

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kW

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tem

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ture

cont

rolle

d en

viro

nmen

ts (u

p to

64

cubi

c ft,

bet

wee

n -4

5°C

and

70°

C)?

NOur�facility�has�tested�battery�packs�o

nly�up

�to�300�V�DC�at�m

axim

um�of�1

50�A�in�ro

om�te

mpe

rature�enviro

nmen

ts.

43W

hat i

s th

e to

tal n

umbe

r of i

ndiv

idua

l tes

ts o

n b

atte

ries

pack

s th

at c

an b

e te

sted

at a

ny g

iven

tim

e?

We�can�test�8�battery�packs,�or�1

4�battery�packs�if�n

ot�te

sting�battery�system

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ny�given

�time.

44D

oes

your

faci

lity

have

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cap

abili

ty to

test

bat

tery

cel

ls w

ith m

axim

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ge o

f 5 V

DC

and

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A D

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tem

pera

ture

con

trolle

d en

viro

nmen

ts

(bet

wee

n -3

4° a

nd 7

0°C

)?N

The�sm

allest�cells�that�we�can�test�is�12�V�DC

.

45W

hat i

s th

e to

tal n

umbe

r of b

atte

ry c

ells

that

can

be

test

ed a

t any

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en ti

me?

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e: th

is q

uest

ion

refe

rs to

the

num

ber o

f ind

ivid

ual t

ests

that

can

be

run

in p

aral

lel.

2�battery�cells�at�1

2�VD

C�can�be

�tested

�at�a

ny�given

�time.

46D

oes

your

faci

lity

have

the

capa

bilit

y to

test

a c

ompl

ete

ener

gy s

tora

ge s

yste

m (E

SS

) with

max

imum

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gs o

f 480

V A

C,

and

250

kW a

nd u

p to

14

sq.ft

. foo

tprin

t per

sys

tem

?Y

Our�facility�can�test�sy

stem

s�at�4

80�V�AC�up

�to�500�kW�with

�footprints�of�2

00�sq

.�ft.

1.��The

�test�fa

cility�do

es�not�need�to�und

ergo�significant�re

mod

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ch�te

chno

logy�or�if�test�facility�can

�meet�test�cap

ability,�but�re

quire

s�minor�re

tool�of�facility�or�test�a

pparatus�to

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chno

logy,�the

�retool�time�will�ta

ke�less�th

an�1�week�to�

complete.

2.��Test�facility�currently�has�all�ne

cessary�eq

uipm

ent�to�cond

uct�testin

g�with

out�h

aving�to�procure�te

st�equ

ipmen

t�by�either�purchasing�or�re

nt/lease�agreemen

ts�to

�meet�testin

g�capa

bilities.

3.��Test�facility�has�qua

lified�pe

rson

nel�on�staff�to�cond

uct�said�tests.

4.��D

ata�that�re

sults�from

�all�tests�m

ust�b

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�from

�calibrated�NIST�traceable�eq

uipm

ent�(whe

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licab

le)�a

nd�m

ust�b

e�assessed

�using�stan

dard�and

�accep

ted�practices�of�u

ncertainty�ana

lysis.

62

��



Fenwick�Labs:�Survey�Summary��Background:�To�determine�which�entities�possess�SCE’s�needed�capabilities�a�survey�was�conducted�targeting�universities,�national�labs�and�energy�consortia.�SCE,�along�with�12�entities�responded�to�the�survey,�which�was�divided�into�seven�categories:�Controls,�Distribution�Automation,�Distributed�Energy�Resources,�Grid�Edge�Solutions,�Distribution�Grid�Analytics,�Power�Systems,�and�Substation�Automation.��Controls:�This�category�is�comprised�of�the�following�five�questions,�one�of�which�contains�a�sub�question:��Question�1:�Does�your�facility�currently�have�the�capability�to�run�real�time�simulation�of�distribution�feeders?�

� SCE�along�with�twelve�respondents�(1,�2,�3,�4,�6,�7,�8,�9,�10,�11,�12,�and�13)�have�the�capability�to�run�real�time�simulation�of�distribution�feeders.�

�Question�2:�Can�your�facility�perform�hardware�and�software�in�the�loop�(closed�and�open)�testing?��

� SCE�and�all�thirteen�respondents�have�the�ability�to�perform�hardware�and�software�in�the�loop�testing.�

�Question�3:�Is�your�facility�currently�capable�of�testing�controls�systems�using�attenuated�radio�communication�hardware?�

� SCE�along�with�nine�respondents�(3,�5,�7,�8,�9,�10,�11,�12,�and�13)�have�the�capability�of�testing�controls�systems�using�attenuated�radio�communication�hardware.�

�Question�4:�Does�your�facility�currently�own�and�operate�amplifier�test�sets�for�driving�hardware�with�secondary�voltage�and�current�signals?�If�so,�can�test�sets�be�driven�by�the�simulators�in�the�facility?�

� SCE�along�with�twelve�respondents�(1,�2,�3,�4,�5,�7,�8,�9,�10,�11,�12,�and�13)�currently�own�and�operate�amplifier�test�sets�for�driving�hardware�with�secondary�voltage�and�current�signals.�

o SCE�along�with�respondents�1,�2,�3,�4,�7,�8,�9,�10,�11,�12,�and�13�possess�the�capability�to�have�test�sets�driven�by�the�simulators�in�the�facility.�Respondent�5�does�not�possess�this�capability.�

�Question�5:�Is�your�facility�integrated�with�systems�in�other�facilities/labs�such�as�cybersecurity,�substation�automation,�field�automation,�field�message�bus,�and�enterprise�bus�architecture?�SCE,�along�with�eleven�respondents�(1,�2,�3,�4,�7,�8,�9,�10,�11,�12,�and�13)�possess�a�facility�integrated�with�systems�in�other�facilities/labs�such�as�cybersecurity,�substation�automation,�field�automation,�field�message�bus,�and�enterprise�architecture.��Distribution�Automation:�This�category�is�comprised�of�the�following�four�questions:��Question�1:�What�are�your�facility’s�IEC�61850�testing�capabilities�with�regard�to�Distribution�Automation�systems?�

� SCE,�along�with�eight�respondents�(1,�2,�5,�7,�9,�10,�12,�and�13)�have�the�ability�to�fully�test�IEC�61850�with�regard�to�Distribution�Automation�systems.�Respondents�8�and�11�have�some�ability�to�test�this�aforementioned�capability�as�well.��

�

63

��



Question�2:�Is�your�facility�currently�capable�of�testing�integration�of�next�generation�substation�and�distribution�automation�systems?�

� SCE�along�with�eleven�respondents�(1,�2,�3,�4,�6,�7,�8,�9,�10,�11,�and�13)�have�the�capability�of�testing�integration�of�next�generation�substation�distribution�automation�systems.�

Question�3:�Is�your�facility�currently�equipped�with�Real�Time�Digital�Simulators�(RTDS)?�� SCE�along�with�eleven�respondents�(1,�2,�3,�4,�6,�7,�9,�10,�11,�12,�and�13)�have�a�facility�equipped�

with�RTDS.��Question�4:�What�are�your�facility’s�current�capabilities�for�broadband�wireless�network�integration�of�distribution�automations�systems?�

� SCE,�along�with�seven�respondents�(5,�7,�8,�9,�10,�12,�and�13)�have�full�capabilities�to�test�next�generation�broadband�wireless�network�integration�of�distribution�automations�systems.�Respondent�1�has�some�characteristics�of�testing�next�generation�broadband�wireless�networks.�

�Distributed�Energy�Resources:�This�category�is�comprised�of�the�following�four�questions,�three�of�which�are�multi�part�and�one�contains�a�sub�question:��Question�1:�What�are�your�facility’s�capabilities�for�testing�and�evaluating�the�following:�Smart�(Solar�PV)�inverters,�commercial�rooftop�A/C�units,�ductless�residential�A/C�unit�with�variable�frequency�drives,�and,�secondary�voltage�regulation�devices?�

� SCE�has�full�capabilities�for�testing�and�evaluating�smart�inverters,�commercial�rooftop�A/C�units,�ductless�residential�A/C�unit�with�variable�frequency�drives,�and�secondary�voltage�regulation�devices.�Respondent�13�has�75%�of�these�capabilities,�respondents�6�and�9�have�50%,�and�respondents�1,�2,�5,�and�8�have�25%�of�these�testing�and�evaluating�capabilities.��

�Question�2:�Does�your�facility�currently�have�the�ability�to�energize�utility�and�customer�devices�in�order�to�operate�them�in�a�controlled�environment,�isolated�from�the�electric�grid?�If�so,�does�your�facility�have�the�capability�to�subject�these�devices�to�abnormal�voltage�and/or�frequency�transients�that�are�representative�of�actual�events�that�can�occur�on�the�electric�grid�to�understand�the�device�response�during�such�events?��

� SCE,�along�with�ten�respondents�(2,�4,�5,�7,�8,�9,�10,�11,�12,�and�13)�have�the�ability�to�energy�utility�and�customer�devices�in�order�to�operate�them�in�a�controlled�environment,�isolated�from�the�grid�and�have�the�capability�to�subject�these�devices�to�abnormal�voltage�and/or�frequency�transients�that�are�representative�of�actual�events�that�can�occur�on�the�electric�grid.��

�Question�3:�Does�your�facility�have�the�ability�to�generate�arbitrary�and�transient�waveforms�with�the�programmable�power�supplies�which�allow�the�assessment�of:�PV�inverter�voltage/frequency�protection,�ride�through�characteristics,�anti�islanding�capabilities,�harmonics�generation,�and�fault�current�contribution?�

� SCE,�along�with�nine�respondents�(1,�2,�4,�5,�8,�9,�10,�11,�and�13)�have�full�ability�to�generate�arbitrary�and�transient�waveforms�with�the�programmable�power�supplies.�Respondents�3�and�7�have�80%�of�these�abilities.��

�Question�4:�Does�your�facility�currently�have�the�following�equipment�and�capabilities?�If�yes,�can�the�facility�test�the�following:�PV�Simulators�(Programmable�DC�Power�Supplies,�Programmable�irradiance�and�temperature�profiles,�Grid�Simulators�(Programmable�AC�Power�Supplies),�Voltage�and�frequency�transient�generation,�and�arbitrary�waveform�generation?�

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� SCE,�along�with�three�respondents�(4,�9,�and�11)�have�full�capabilities�to�test�equipment.�Respondent�10�has�90%,�respondents�1,�2,�and�13�have�81%,�respondent�8�has�64%,�respondent�6�has�55%,�and�respondent�3�has�27%�of�testing�capabilities.��

�Grid�Edge�Solutions:�This�category�is�comprised�of�the�following�4�questions,�one�of�which�is�a�multi�part�question:��Question�1:�Does�your�facility�currently�have�the�ability�to�support�smart�grid�initiatives�that�require�radio�communications�testing/evaluation�and/or�smart�meter�data�and�infrastructure?��

� SCE,�along�with�nine�respondents�(3,�4,�5,�7,�8,�9,�10,�12�and�13)�have�the�ability�to�support�smart�grid�initiatives�that�require�radio�communications�testing/evaluation�and/or�smart�meter�data�and�infrastructure.�Respondent�2�has�partial�capabilities�to�test�smart�meters,�but�not�radio�communications.�

�Question�2:�Is�your�facility�currently�capable�of�using�smart�meter�data�to�improve�accuracy�of�the�meter/transformer�correlation�model?�

� SCE,�along�with�five�respondents�(3,�5,�9,�12,�and�13)�have�the�capability�of�using�smart�meter�data�to�improve�accuracy�of�the�meter/transformer�correlation�model.�

�Question�3:�What�are�your�facility�capabilities�to�test�radio�communication�for�Home�Area�Network�(HAN)�and�Field�Area�Network�(FAN)�and�other�telecom�for�distributed�field�equipment?�

� SCE,�along�with�five�respondents�(5,�9,�10,�12,�and�13)�have�the�capability�to�test�radio�communication�for�HAN�and�FAN�and�other�telecom�distributed�field�equipment.�

�Question�4:�Is�your�facility�equipped�with�the�following:�signal�generators�and�analyzers,�ZigBee�signal�sensors�and�decoders,�test�harnesses,�powerline�carrier�signal�generator,�radio�isolation�boxes�and�Faraday�Cage,�and�smart�meters�and�cell�relays?�

� SCE,�along�with�four�respondents�(6,�9,�12,�and�13)�are�fully�equipped�with�signal�generators�and�analyzers,�ZigBee�signal�sensors�and�decoders,�test�harnesses,�powerline�carrier�signal�generator,�radio�isolation�boxes�and�Faraday�Cage,�and�smart�meters�and�cell�relays.�Respondents�3,�5,�and�6�have�83%,�respondent�10�has�67%,�respondent�4�has�50%,�and�respondent�2�has�17%�of�the�equipment�testing�capabilities.��

�Distribution�Grid�Analytics:�This�category�is�comprised�of�the�following�five�questions,�one�of�which�has�a�sub�question:��Question�1:�Does�your�facility�currently�have�the�ability�to�evaluate�and�utilize�several�modeling�tools�to�develop�circuit�models?�If�yes,�can�these�models�show�accurate�dynamic�and�steady�state�simulations�representing�beyond�the�meter�loads�leveraging�smart�meter�data?�

� SCE�along�with�ten�respondents�(1,�2,�3,�7,�8,�9,�10,�11,�12,�and�13)�have�the�ability�to�evaluate�and�utilize�several�modeling�tools�to�develop�circuits�and�show�accurate�dynamic�and�steady�state�simulations�representing�beyond�the�meter�loads�leveraging�smart�meter�data.�Respondents�4�and�6�have�the�ability�to�evaluate�and�utilize�several�modeling�tools,�but�do�not�have�the�ability�to�show�accurate�dynamic�and�steady�state�simulations.��

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Question�2:�Does�your�facility�have�the�ability�to�analyze�and�visualize�test�data�and�results�to�develop�integration�strategies�and�inform�field�deployment�of�control�equipment,�energy�storage�and�other�devices?�

� SCE,�along�with�eleven�respondents�(1,�2,�3,�4,�5,�6,�7,�9,�10,�11,�12,�and�13)�have�the�ability�to�analyze�and�visualize�test�data�and�results�to�develop�integration�strategies�and�inform�field�deployment.��

�Question�3:�Can�your�facility�currently�evaluate�different�software�and�solutions�that�provide�visualization�of�power�distribution�systems?�

� SCE,�along�with�eight�respondents�(1,�2,�8,�9,�10,�11,�12,�and�13)�have�the�ability�to�evaluate�different�software�solutions�that�provide�visualization�of�power�distribution�systems.�

�Question�4:�Does�your�facility�currently�have�the�ability�to�develop/evaluate�new�database�structures�and�mathematical�methodologies�such�as�dimension�reduction�to�handle�distributed�data?�

� SCE,�along�with�eleven�respondents�(1,�2,�4,�5,�6,�7,�9,�10,�11,�12,�and�13)�have�the�ability�to�develop/evaluate�new�database�structures�and�mathematical�methodologies.��

�Question�5:�Can�your�facility�currently�conduct�time�series�analysis�to�dynamically�calculate�the�distributed�energy�resource�(DER)�hosting�capacity�for�any�given�node�within�the�distribution�and�transmission�system�for�any�hour�of�the�day?��

� SCE,�along�with�eight�respondents�(2,�4,�8,�9,�10,�11,�12,�and�13)�currently�conduct�time�series�analysis�to�dynamically�calculate�the�DER�hosting�capacity�for�any�given�node�within�the�distribution�and�transmission�system�for�any�hour�of�the�day.��

�Power�Systems:�This�category�is�comprised�of�the�following�three�questions:��Question�1:�Does�your�facility�currently�have�the�ability�to�conduct�hardware�in�the�loop�control�system�testing,�protective�relay�testing,�wide�area�protection�and�control�testing?�

� SCE,�along�with�twelve�respondents�(1,�2,�3,�4,�6,�7,�8,�9,�10,�11,�12,�and�13)�have�the�ability�to�conduct�hardware�in�the�loop�control�system�testing,�protective�relay�testing,�wide�area�protection�and�control�testing.��

�Question�2:�Does�your�facility�currently�have�the�ability�to�evaluate�smart�grid�development�for�inclusion�in�an�electrical�grid?�

� SCE,�along�with�twelve�respondents�(1,�2,�3,�4,�5,�6,�7,�9,�10,�11,�12,�and�13)�have�the�ability�to�evaluate�smart�grid�development�for�inclusion�in�an�electrical�grid.�

�Question�3:�Does�your�facility�currently�have�the�ability�to�run�large�scale�real�time�simulations�utilizing�control�system�and�relay�communications�equipment?�

� SCE,�along�with�ten�respondents�(1,�3,�4,�6,�7,�9,�10,�11,�12,�and�13)�have�the�ability�to�run�large�scale�real�time�simulations�utilizing�control�system�and�relay�communications�equipment.�Respondent�2�has�limited�ability�to�run�large�scale�real�time�simulations.�

�Substation�Automation:�This�category�is�comprised�of�the�following�four�questions:��

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Question�1:�Does�your�facility�currently�have�a�platform�to�test�integration�of�in�service�legacy�proprietary�substation�automation�systems�based�on�Modbus�Plus�and�Modbus�protocols�with�new�IEC�61850�open�standards�systems?�

� SCE,�along�with�ten�respondents�(1,�3,�6,�7,�8,�9,�10,�11,�12,�and�13)�have�a�platform�to�test�integration�of�in�service�legacy�proprietary�substation�automation�systems�with�new�IEC�61850�open�standards�systems.�

�Question�2:�Does�your�facility�currently�have�direct�connectivity�to�a�test�energy�management�system�for�testing�and�integrating�new�supervisory�control�and�data�acquisition�(SCADA)�systems?�

� SCE,�along�with�eight�respondents�(1,�2,�7,�8,�9,�10,�11,�and�13)�currently�have�direct�connectivity�to�a�test�energy�management�system�for�testing�and�integrating�new�SCADA�systems.�

�Question�3:�Does�your�facility�currently�have�an�in�house�real�time�digital�simulator�system�for�testing�of�substation�protection�and�automation�functions�to�fully�vet�and�test�next�generation�substation�automation�systems?�

� SCE,�along�with�ten�respondents�(1,�2,�3,�6,�7,�9,�10,�11,�12,�and�13)�currently�have�an�in�house�real�time�digital�simulator�for�testing�of�substation�protection�and�automation�functions�to�fully�vet�and�test�next�generation�substation�automation�systems.�

�Question�4:�Does�your�facility�currently�have�the�ability�to�mimic�a�large�substation�(up�to�70�racks)�for�testing�of�grid�modernization�equipment?�

� Five�respondents�(1,�7,�8,�11,�and�12)�currently�have�the�ability�to�mimic�a�large�substation�for�testing�of�grid�modernization�equipment.��

�Synopsis:�As�the�survey�results�show�among�the�seven�categories�(Controls,�Distribution�Automation,�Distributed�Energy�Resources,�Grid�Edge�Solutions,�Distribution�Grid�Analytics,�Power�Systems,�and�Substation�Automation)�of�SCE’s�testing�and�evaluation�needs,�there�is�a�wide�spread�of�capabilities�among�various�entities�and�only�Fenwick�Labs�has�all�the�capabilities�to�meet�SCE’s�testing�and�evaluation�needs.��The�responses�also�indicate�that�other�labs�are�1)�more�focused�on�testing�individual�pieces�of�equipment�and�2)�focused�on�testing�in�a�traditional�distribution�environment.��SCE�needs�to�additionally�1)��evaluate�how�a�piece�of�equipment�feeds�back�into�the�distribution�grid,�not�just�how�the�equipment�performs,�2)�evaluate�not�just�individual�pieces�of�equipment�but�the�impact�of�having�many�pieces�of�equipment�attached�to�the�grid.��The�other�conclusion�we�draw�from�these�responses�is�that�for�testing�more�advanced�capabilities�(e.g.�SA3),�there�are�very�few�alternatives�available.��It�is�more�cost�effective�and�efficient�to�use�the�Fenwick�Labs,�which�is�already�in�place�with�a�trained�staff,�rather�than�trying�to�replicate�these�capabilities�across�a�patchwork�of�multiple�entities.��

�

�

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Pomona�Lab:�Survey�Summary��Background:�To�determine�which�entities�possess�SCE’s�needed�capabilities�a�survey�was�conducted�targeting�universities,�national�labs�and�energy�consortia.�SCE,�along�with�12�entities�responded�to�the�survey,�which�was�divided�into�three�categories:�Electric�Transportation,�Garage�of�the�Future,�and�Energy�Storage�(Battery�Profiling,�Testing,�and�Evaluation�Capabilities).��Electric�Transportation:�This�category�contains�the�following�seven�questions�and�each�question�contains�sub�questions:��Question�1:�Does�your�facility�have�the�capability�to�conduct�fuel�economy�and�emissions�testing�of�light�duty�vehicles�according�to�federal�standards?�If�yes,�does�the�facility�have�the�capability�to�test�and�evaluate�the�following�types�of�vehicles:�conventional�ICE,�electric,�hybrid�electric,�and�gaseous�fueled?�

� SCE�and�respondent�5�have�a�facility�capable�of�conducting�fuel�economy�and�emissions�testing�of�light�duty�vehicles�according�to�federal�standards�and�have�the�ability�to�test�and�evaluate�all�types�of�vehicles.��

�Question�2:�Does�your�facility�have�the�capability�to�conduct�heavy�duty�engine�testing�according�to�federal�standards?�If�yes,�does�the�facility�have�the�ability�to�conduct�testing�on:�fuel�economy,�emissions,�hybrid�electric�drives�and�gaseous�fuel�engines?�

� Only�respondent�5�has�the�capability�to�conduct�heavy�duty�engine�testing�according�to�federal�standards.��

�Question�3:�Does�your�facility�have�the�capability�to�conduct�fuel�economy�and�emissions�testing�of�heavy�duty�vehicles�according�to�federal�standards?�If�yes�does�it�have�the�capability�to�test:�dynamometer,�on�road,�hybrid�electric�vehicles,�gaseous�fuel�vehicles,�PEMS�emissions�testing,�Bag�emissions�testing,�and�stationary�utility�or�other�vocational�cycles?��

� SCE�and�respondent�5�have�the�capability�to�conduct�fuel�economy�and�emissions�testing�of�heavy�duty�vehicles�according�to�federal�standards.��

�Question�4:�Does�your�facility�have�the�capability�to�test�electric�vehicle�supply�equipment?�If�yes,�does�the�facility�have�the�capability�to�test:�SAE�J1772�Levels�1�and�2,�SAE�J1772�Level�3�AC,�SAE�J1772�DC�Fast�Charging�Combo�CCS,�bidirectional�power�EVSE,�AC�3�phase�EVSE,�overhead�conductive�power�transfer�EVSE,�wireless�power�transfer�EVSE,�fast�charging�chAdeMo,�grid�simulation�impacts?�

� SCE,�along�with�seven�other�respondents�(1,�3,�5,�7,�9,�11�and�13)�have�the�capability�to�test�electric�vehicle�supply�equipment.�Respondent�11�possess�all�the�additional�testing�capabilities.�SCE,�along�with�respondent�9�have�89%�of�the�additional�capabilities.�Respondent�7�has�78%,�Respondents�5�and�3�have�67%,�and�Respondent�1�has�33%�of�the�additional�capabilities.��

�Question�5:�Does�your�facility�have�the�capability�to�test�full�plug�in�electric�vehicle�(PEV)�charging�systems�for�effect,�efficiency,�and�power�quality?�If�yes,�does�it�have�the�capability�to�test:�SAE�J2894/2,�California�Title�20,�and�vehicle�to�grid�systems,�IEEE�1547,�UL�1741?�

� SCE,�along�with�five�other�respondents�(1,�3,�5,�11,�and�13)�have�a�facility�capable�of�testing�full�plug�in�electric�vehicle�PEV�charging�systems�for�effect,�efficiency,�and�power�quality.�SCE,�along�with�Respondents�11�and�13�possess�all�the�additional�capabilities,�while�Respondent�3�has�67%�and�Respondent�1�has�33%�of�the�additional�testing�capabilities.��

�

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Question�6:�Does�your�facility�have�the�capability�to�test�auxiliary�power�systems?�If�yes,�does�your�facility�have�the�capability�to�test:�engine�generators,�battery�power�systems,�AC�power�inverter�systems,�DC�DC�power�systems,�hydraulic�power�systems,�power�thermal�management�systems,�electrical�isolation�and�personnel�protection,�HVAC�systems,�and�compressed�air�storage�systems?��

� SCE,�along�with�four�other�respondents�(5,�7,�11�and�13)�have�a�facility�capability�to�test�auxiliary�power�systems.�SCE�and�Respondent�11�possesses�all�the�additional�testing�capabilities.�Respondents�5�and�13�have�78%,�Respondent�7�has�22%�of�the�additional�equipment�testing�capabilities.��

Question�7:�Does�your�facility�have�in�house�CFR/EPA�specification�chassis�dynamometer?�If�so,�does�it�have�the�capability�to�test:�light�duty,�heavy�duty,�emissions�measurement,�PEV�charging�infrastructure,�gaseous�fuels?�

� SCE,�along�with�two�other�respondents�(5�and�11)�have�a�facility�that�contains�an�in�house�CFR/EPA�specification�chassis�dynamometer.�Respondent�5�has�all�additional�testing�capabilities,�while�SCE�has�67%�and�Respondent�11�has�40%�additional�testing�capabilities.��

�Garage�of�the�Future:�This�category�contains�the�following�two�questions,�the�first�being�a�multi�part�question�and�the�second�question,�contains�a�sub�question:��Question�1:�Does�your�facility�currently�operate�with�the�following�equipment�and/or�capabilities:�PV�simulators�allowing�simulation�of�PV�or�storage�(DC)�interactions,�energy�storage,�EVs,�DC�fast�charger,�roof�top�PV�to�allow�demonstration�and�evaluation�of�communications�and�controls�integration,�and�external�and�internal�network�interfaces��for�interfacing�with�controls�systems,�internet�based�entities,�and�internal�equipment?�

� SCE,�along�with�eleven�respondents�have�a�facility�that�currently�operates�with�the�aforementioned�equipment�and/or�capabilities.�SCE,�along�with�Respondents�2,�3,�4,�6,�8,�9,�11�and�13�have�all�the�capabilities.�While�Respondents�7�and�12�have�67%�and�Respondent�5�has�33%�of�the�testing�capabilities.��

�Question�2:�Does�your�facility�currently�have�the�ability�to�evaluate�and�utilize�several�modeling�tools�to�develop�distribution�circuit�models?�If�so,�does�your�facility�have�the�ability�to�simulate�and�evaluate�a�virtually�unlimited�set�of�use�cases�in�safe�and�controlled�conditions?��

� SCE,�along�with�eleven�respondents�have�the�ability�to�evaluate�and�utilize�several�modeling�tools�to�develop�distribution�circuit�models.�SCE�and�Respondents�1,�2,�3,�4,�6,�8,�9,�11,�12,�and�13�have�the�additional�ability�to�simulate�and�evaluate�a�virtually�unlimited�set�of�use�cases,�while�Respondent�7�does�not�have�the�ability.��

�Energy�Storage:�This�category�contains�the�following�eleven�questions,�two�of�which�have�sub�questions:��Question�1:�Does�your�facility�have�the�capability�to�test�large�battery�systems�with�maximum�ratings�of�900�V�DC,�1000�A�DC,�and�250�kW�in�large�temperature�controlled�settings?��

� SCE,�along�with�three�other�respondents�(4,�10�and�13)�have�the�capability�to�test�large�battery�systems�with�maximum�ratings�of�900�V�DC,�1000�A�DC,�and�250�kW�in�large�temperate�controlled�settings.�

�Question�2:�What�is�the�total�number�of�individual�tests�on�large�battery�systems�that�can�be�tested�at�any�given�time?�

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� SCE,�along�with�Respondents�5�and�13�can�run�more�than�one�test�on�large�battery�systems�at�any�given�time.�SCE�has�the�ability�to�run�4�tests,�Respondent�13�has�the�ability�to�run�3�tests,�and�Respondent�5�has�the�ability�to�run�two�tests.�

�Question�3:�Does�your�facility�have�the�capability�to�test�batteries�packs�with�maximum�ratings�of�445�V�DC,�265�A�DC,�and�125�kW�in�large�temperature�controlled�environments?��

� SCE,�along�with�five�respondents�(4,�5,�9,�10�and�13)�have�the�capability�to�test�batteries�packs�with�maximum�ratings�of�445�V�DC,�265�A�DC,�and�125�kW�in�large�temperature�controlled�environments.�

�Question�4:�What�is�the�total�number�of�individual�tests�on�batteries�packs�that�can�be�tested�at�any�given�time?�

� SCE,�along�with�Respondents�5�and�13�have�the�ability�to�perform�multiple�individual�tests�on�batteries�packs�at�any�given�time.�SCE�has�the�capability�to�run�14�individual�tests,�while�Respondents�5�and�13�have�the�capability�to�run�3�individual�tests.��

�Question�5:�Does�your�facility�have�the�capability�to�test�battery�cells�with�maximum�voltage�of�5�V�DC�and�400�A�DC�in�temperature�controlled�environments?�

� SCE,�along�with�six�other�respondents�(1,�4,�5,�9,�10,�and�13)�have�the�capability�to�test�battery�cells�with�maximum�voltage�of�5�V�DC�and�400�A�DC�in�temperate�controlled�environments.��

�Question�6:�What�is�the�total�number�of�battery�cells�that�can�be�tested�at�any�given�time?�

� SCE,�along�with�Respondents�1�and�5�have�the�ability�to�test�battery�cells.�SCE�can�test�two�battery�cells�at�any�given�time.��

�Question�7:�Does�your�facility�have�the�capability�to�test�a�complete�energy�storage�system�with�maximum�ratings�of�480�V�AC,�and�250�kW�and�up�to�140�sq�ft�footprint�per�system?�

� SCE,�along�with�seven�respondents�(1,�4,�5,�9,�10,�11,�and�13)�have�the�capability�to�test�a�complete�energy�storage�system�with�maximum�ratings�of�480�V�AC,�and�250�kW�and�up�to�140�sq�ft�footprint�per�system.�

�Question�8:�Does�your�facility�have�the�capability�to�test�individual�critical�components�of�an�energy�storage�system?�Such�as�the�power�conversion�systems,�battery�management�systems,�and�control�and�communications�interface?��

� SCE,�along�with�eight�respondents�(1,�3,�4,�5,�9,�10,�11,�and�13)�have�the�capability�to�test�individual�critical�components�of�an�energy�storage�system.�

�Question�9:�Does�your�facility�have�the�ability�to�conduct�grid�impact�testing�of�Energy�Storage�Systems�(ESS)?�If�so,�can�your�facility�conduct�testing�by�connecting�ESS’s�to�the�grid?�Can�your�facility�conduct�testing�by�utilizing�a�simulated�grid�that�can�run�profiles�for�grid�disturbances�at�various�voltage�and�phase�configurations?�

� SCE,�along�with�eight�respondents�(1,�3,�4,�9,�10,�11,�12,�and�13)�have�the�ability�to�conduct�grid�impact�testing�of�ESS.�SCE�and�respondents�4,�9,�and�11�have�the�ability�to�conduct�testing�by�connecting�ESS’s�to�the�grid�and�utilizing�a�simulated�grid.�Respondents�1,�3,�10,�12,�and�13�have�50%�of�these�capabilities.��

�

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Question�10:�What�is�the�total�number�of�ESS�that�can�be�tested�at�any�given�time?�� SCE�and�Respondent�13�have�the�ability�to�test�more�than�the�one�ESS�at�any�given�time.�SCE�has�

the�capability�to�test�at�a�maximum�18�ESS�and�24�cells.�Respondent�13�can�test�3�ESS.��Question11:�Does�your�facility�have�the�capability�to�conduct�evaluation�of�Photovoltaic�equipment�(i.e.,�PV�arrays�and�PV�inverters)?�

� SCE,�along�with�nine�respondents�(1,�2,�3,�4,�5,�9,�11,�12,�and�13)�have�the�capability�to�conduct�evaluation�of�Photovoltaic�equipment.�

�Synopsis:�As�the�survey�results�show,�there�is�a�wide�spread�of�capabilities�that�SCE�needs�among�various�entities�and�only�the�Pomona�Lab�has�all�the�capabilities�in�transportation�electrification,�vehicle�charging�equipment,�and�energy�storage�battery�profile,�testing�and�evaluation.�The�results�also�show�that�the�other�respondents�are�more�focused�on�testing�storage�in�a�traditional�distribution�environment,�and�the�Pomona�lab�is�also�capable�of�evaluating�how�storage�will�operation�in�the�grid�of�the�future,�which�will�be�a�more�DER�intensive�environment.��As�the�synergy�between�energy�storage�battery�systems�and�vehicles�continues,�it�will�be�important�to�use�a�single�facility.�Moreover,�using�a�single�facility�that�is�already�in�place�with�trained�staff�is�more�cost�effective�than�trying�to�replicate�these�same�capabilities�among�multiple�disparate�entities.��

�

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Equipment�Demonstration�&�Evaluation�Facility:�Survey�Summary��Background:�To�determine�which�entities�possess�SCE’s�needed�capabilities�a�survey�was�conducted�targeting�universities,�national�labs�and�energy�consortia.�SCE,�along�with�12�entities�responded�to�the�survey,�which�was�comprised�of�the�following�four�questions:��Question�1:�Do�you�currently�have�a�high�voltage�distribution�circuit�(12kV�35kV)�facility�dedicated�to�testing�new�equipment?�

� SCE�and�four�respondents�(9,�10,�12,�and�13)�have�a�high�voltage�distribution�circuit�facility.��20�additional�follow�up�questions�were�asked�to�determine�the�testing�and�evaluation�capabilities�of�the�high�voltage�distribution�circuit�facility.�Such�questions�include�whether�the�facility�is�integrated�with�other�distribution�circuits�fed�from�the�source�substation,�can�the�facility�test�voltage�impacts�of�DER�switching�devices,�Does�the�facility�have�a�capability�of�simulating�various�circuit�lengths,�etc.)�

o Of�the�20�additional�questions�regarding�capabilities,�SCE’s�EDEF�has�the�most�capabilities�at�90%.�Respondent�9�has�85%,�Respondent�10�and�Respondent�13�has�70%,�and�Respondent�12�has�30%�of�the�capabilities.��

�Question�2:�Do�you�have�a�facility�capable�of�monitoring�test�circuits�and�the�tests�performed�using�an�existing�distribution�management�system�(DMS)?�

� SCE,�along�with�three�other�respondents�(4,�9,�and�13)�have�a�facility�capable�of�monitoring�test�circuits�performed�using�an�existing�DMS.�

�Question�3:�Do�you�have�a�facility�capability�of�simulating�various�circuit�lengths?�

� SCE,�along�with�four�other�respondents�(4,�8,�10,�and�13)�have�a�facility�capable�of�monitoring�test�circuits�performed�using�an�existing�DMS.�

�

Question�4:�Do�you�have�a�facility�capability�of�simulating�different�circuit�configurations�(loop,�radial,�network)?�

� SCE,�along�with�four�other�respondents�(8,�9,�10,�and�13)�have�a�facility�capable�of�simulating�different�circuit�configurations.�

�Synopsis:�As�the�survey�results�show,�only�the�Equipment�Demonstration�&�Evaluation�Facility�has�all�the�capabilities�SCE�needs�for�evaluation�and�testing�new�equipment.�The�responses�also�indicate�that�other�labs�are�1)�more�focused�on�testing�individual�pieces�of�equipment�and�2)�focused�on�testing�in�a�traditional�distribution�environment.��SCE�needs�to�additionally�1)��evaluate�how�a�piece�of�equipment�feeds�back�into�the�distribution�grid,�not�just�how�the�equipment�performs,�2)�evaluate�not�just�individual�pieces�of�equipment�but�the�impact�of�having�many�pieces�of�equipment�attached�to�the�grid.��While�other�entities�possess�some�of�these�testing�and�evaluation�capabilities,�it�is�more�cost�effective�to�use�a�single�facility,�rather�trying�to�replicate�these�same�capabilities�with�multiple�disparate�entities.��

�

�

�

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Advanced Technology Laboratories2018 General Rate Case

Program Name: Advanced Technology Laboratories

Projects 1 Advanced Technology Labs - Fenwick2 Advanced Technology Labs - Pomona3 Equipment Demonstration and Evaluation Facility (EDEF)

2016 2017 2018 2019 2020Total Budget 9,397$ 8,342$ 5,559$ 7,385$ 10,142$

Project Component 2016 2017 2018 2019 2020New Equipment 2,416$ 2,596$ 2,231$ 3,087$ 2,482$ Equipment Refresh 1,600$ 1,738$ 1,600$ 2,500$ 5,837$ Other 178$ 178$ 103$ 103$ 103$

Fenwick Total 4,194$ 4,512$ 3,934$ 5,690$ 8,422$

Project Component 2016 2017 2018 2019 2020New Equipment 142$ 268$ -$ 236$ -$Equipment Refresh 1,023$ 647$ 410$ 244$ 505$Other 440$ 720$ 720$ 720$ 720$

Pomona Total 1,605$ 1,635$ 1,130$ 1,200$ 1,225$

Project Component 2016 2017 2018 2019 2020New Equipment 90$ 350$ 350$ 375$ 370$ Infrastructure Improvements 3,488$ 1,700$ -$ -$ -$ Other 20$ 145$ 145$ 120$ 125$

Total 3,598$ 2,195$ 495$ 495$ 495$

Total Budget (Constant Dollars $000)

Total Budget - Equipment Demonstration and Evaluation Facility (EDEF)

Total Budget - Advanced Technology Labs - Fenwick

Total Budget - Advanced Technology Labs - Pomona

AT Labs - 1 of 5 8/10/2016

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Energy Storage Integration Pilot Program2018 General Rate Case

Project Name: DESI 2

Project Components 1 Project Management2 Design & Engineering3 Construction4 Equipment

2016 2017 2018 2019 2020Total Budget 3,313$ 1,741$ -$ -$ -$

Consulting Services 21$ 43$ -$ -$ Total Project Management 21$ 43$ -$ -$ -$

Environmental Services 3$ -$ -$ -$ -$ Environmental Services Labor5 1$ -$ -$ -$ -$ Site Acquisition1 424$ -$ -$ -$ -$ Site Acquisition Labor5 10$ -$ -$ -$ -$ Site Survey 64$ -$ -$ -$ -$ Civil Design and Engineering Services 207$ -$ -$ -$ -$ Civil Engineering Labor5 13$ -$ -$ -$ -$ Construction Permits 6$ -$ -$ -$ -$

Total Design & Engineering 728$ -$ -$ -$ -$

Consulting Services 26$ 26$ -$ -$ -$ Site Development2 303$ 303$ -$ -$ -$ Civil Engineering Labor5 -$ 7$ -$ -$ -$ Environmental Services 23$ -$ -$ -$ -$ Environmental Monitoring Labor5 1$ -$ -$ -$ -$ Interconnection Facilities & Upgrades3 145$ 170$ -$ -$ -$ System Engineering Labor5 26$ 12$ -$ -$ -$ Construction Management Services 87$ 63$ -$ -$ -$ Construction Management Labor5 8$ 16$ -$ -$ -$ Training Services -$ 6$ -$ -$ -$

Total Construction 620$ 603$ -$ -$ -$

BESS Power & Energy Components4 1,821$ 980$ -$ -$ -$ BESS Sales Tax 124$ 67$ -$ -$ -$ BESS Communication & Control -$ 24$ -$ -$ -$ Auxillary Power -$ 24$ -$ -$ -$

Total Equipment 1,945$ 1,096$ -$ -$ -$

1 Site Acquisition includes cost for the purchase of land used for Battery Energy Storage System (BESS) and interconnection equipment.

Project Management

Design & Engineering

Construction

Equipment

2 Site Development includes costs to develop the BESS site, including site clearing, grading, trenching, foundations, fencing, electrical ground system, facility lighting and landscaping.3 Interconnection Facilities and Upgrades includes cost labor, materials and installation of facilities to connect the BESS to the distribution circuit, including primary cable, isolation switch, ground detector, metering, and related structures. 4 BESS Power and Energy Components includes costs for BESS design, engineering, and installation of BESS components, including powerconversion system, battery modules, transformer, primary switch gear, system enclosure, fire suppression system, and HVAC. 5 Labor includes costs for SCE labor, using market reference point rates for the following job classifications: Analyst - Program/Project 3, Engineer 1, Engineer 3, Engineering Manager 2, Land Services Assistant/Agent 4, Manager - Project/Product 1, Manager - Project/Product 2, and Technical Specialist/Scientist 3.

DESI 2 - Total Budget ($000)

ESIP - 5 of 10 8/10/2016

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