R1707007-SCE Response to ALJ Ruling on Working Group Two ... · SCE’s below responses to Question...

BEFORE THE PUBLIC UTILITIES COMMISSION OF THE

STATE OF CALIFORNIA

Order Instituting Rulemaking to Consider Streamlining Interconnection of Distributed Energy Resources and Improvements to Rule 21.

Rulemaking 17-07-007 (Filed July 13, 2017)

RESPONSE OF SOUTHERN CALIFORNIA EDISON COMPANY (U 338-E) TO

ADMINISTRATIVE LAW JUDGE’S RULING DIRECTING RESPONSES TO

QUESTIONS ON WORKING GROUP TWO REPORT

ALEXA MULLARKY

Attorney for: SOUTHERN CALIFORNIA EDISON COMPANY

2244 Walnut Grove Avenue Post Office Box 800 Rosemead, California 91770 Telephone: (626) 302-1577

E-mail: [email protected]

Dated: February 1, 2019

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STATE OF CALIFORNIA



RESPONSE OF SOUTHERN CALIFORNIA EDISON COMPANY (U 338-E) TO

ADMINISTRATIVE LAW JUDGE’S RULING DIRECTING RESPONSES TO

QUESTIONS ON WORKING GROUP TWO REPORT

I. INTRODUCTION

Pursuant to the Administrative Law Judge’s Ruling Directing Responses to Questions on

Working Group Two Report,1 Southern California Edison Company (“SCE”) respectfully provides

these responses to the questions raised therein. The responses are organized by issue, consistent

with the ALJ’s Ruling.

II. RESPONSES

A. Responses to Questions Concerning All Issues

1. For any proposals that developers support, and one or more utilities oppose based on a perceived reliability concern, explain whether and how developers and/or customers could voluntarily take on certain defined financial risks associated with the utility’s concerns, with agreement from the utility.

SCE’s below responses to Question No. 1 are limited to proposals that SCE opposed based

on reliability concern(s), as determined by SCE.

Proposal 8.i Option B: Rule 21 Initial Review Screen I (“Screen I”) asks whether a project

1 R. 17-07-007, Administrative Law Judge’s Ruling Directing Responses to Questions on Working Group Two Report, issued on December 7, 2018 (“ALJ’s Ruling”).

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is export or non-export. Currently, if a project is non-export, then it is allowed to bypass Screens

J, K, L, and M; and also is not required to undergo Supplemental Review so long as it passed

Screens A through H. Proposal 8.i Option B proposes not relocating Screen I, and instead, to

continue to allow non-exporting projects of all sizes to skip Screens J, K, L, and M.2

Due to reliability concerns, SCE does not support Proposal 8.i Option B.3 As described

more fully in SCE’s response to Question No. 11, not relocating Screen I could cause non-export

projects to be approved for interconnection, but then later find that system reliability issues, such

as overvoltage conditions, have occurred because power flow analysis was not performed during

the review process. These reliability issues may occur when, for example, a non-export project

reduces its load on the feeder, but the load was being used by previously-approved exporting

projects for balancing generation on the distribution feeder and maintaining the distribution feeders

within thermal and voltage ratings. As explained more fully in SCE’s response to Question No.

11, SCE believes that this reliability concern may become more likely as DER penetration

increases and the level of ICA margin at various parts of the distribution system is diminished.

Importantly, for distribution feeder power flow analysis, export and non-export projects have the

exact same effect on the grid when ICA values are low, and thus, should be reviewed equally to

ensure that safety and reliability of the grid is maintained. In sum, the failure to evaluate non-

export projects above 30 kVA in accordance with all of the Rule 21 Screens could lead to safety

and reliability issues.

SCE does not believe that the solution suggested in Question No. 1—shifting cost

responsibility—is sufficient. SCE’s fundamental concern is that Proposal 8.i Option B raises

safety and reliability concerns, which cannot be fixed by any cost-shifting agreement. Other

2 R. 17-07-007, Working Group Two Final Report, filed on October 31, 2018 (“Working Group Two Report”), at pp. 54-56.

3 Proposal 8.i Option B is also opposed by Pacific Gas & Electric Company (“PG&E”), San Diego Gas & Electric Company (“SDG&E”), and The Utility Reform Network (“TURN”). See Working Group Two Report, at p. 54.

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possible remedial actions, such as reduction of generation, would only be reactionary, i.e., these

actions could only be taken after the reliability issue had occurred. Instead, SCE maintains that

Proposal 8.i Option A—which proposes relocating Screen I to the Rule 21 technical framework

overview so that non-exporting projects above 30 kVA are reviewed under all Screens—is the best

alternative to ensure that reliability and safety issues do not occur.

Proposal 8.m Option B: The ICA is information regarding a system’s hosting capacity.

Proposal 8.m Option B proposes using 100% of the ICA-OF 576 hour profile for evaluation of

interconnection requests that are based on Typical PV Output Profiles.

SCE, together with PG&E, SDG&E, and TURN, does not support this proposal due to

reliability concerns. As described in the Working Group Two Report,4 using this type of profile

can lead to potential safety and reliability issues under certain distribution configurations. Indeed,

when reliability issues are not prevented, safety risks can and do occur. For example overvoltage

conditions could occur on line sections within the distribution feeder, which could lead to SCE

inadvertently providing its customers with voltage levels that are too high, which in turn, can

damage equipment and contribute to unsafe grid conditions.

These safety and reliability risks would not be mitigated by developers and/or customers

taking on certain defined financial risks, as suggested by the Commission. SCE reiterates that its

fundamental concern—reliability—cannot be adequately addressed through any cost-shifting

agreement. Instead, SCE maintains that the best way to mitigate these risks is for the Commission

to adopt Proposal 8.m Option A, which proposes a hybrid approach, applying a 10% buffer to the

ICA-SG and no buffer to 100% of ICA-OF for PV operational profile Interconnection Requests.

2. For any proposals that developers support, and one or more utilities oppose based on a perceived reliability concern, should the Commission require the utilities to pilot the proposal in an isolated geographic area? If yes, include a description of the proposed parameters for the pilot.

No, SCE does not support a pilot to test proposals that SCE opposes due to reliability

4 See Working Group Two Report, at pp. 70-71.

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concerns – namely, Proposal 8.i Option B and Proposal 8.m Option B. As outlined above in SCE’s

response to Question No. 1, Proposal 8.i Option B and Proposal 8.m Option B could cause

reliability and safety issues. Further, any data or information that would be obtained from a pilot

of these proposals would not be applicable to the rest of the distribution system given the

significant differences in distribution system configurations; and would not be indicative of what

could occur in the future given that the distribution system is highly configurable.5

B. Responses to Questions Concerning Issue 6

3. In order to consider whether to adopt the proposed draft Distributed Energy Resource Aggregation Agreement (Agreement), explain whether the Commission needs to first determine if the Agreement governs only the capabilities or the actual performance of generating facilities? Please also explain whether you think the Agreement governs only the capability or the actual performance of generating facilities.

SCE understands this question to be asking whether, prior to considering whether to adopt

the proposed Rule 21 Distributed Energy Resource Aggregation Agreement (“Agreement”), the

Commission should first determine if the Agreement governs only the capabilities of distributed

energy resource aggregators (“Aggregators”),6 as opposed to the actual performance of

“generating facilities.” SCE believes that, yes, the Commission should first determine the scope

of the Agreement and whether it governs capabilities and/or actual performance.

SCE believes that the Agreement has been drafted to govern only the capabilities of

Aggregators, not their performance. Specifically, the “Applicability” section of the Agreement

states: “This Agreement governs the terms and conditions under which the Supplier will provide

the communication functions required under Section Hh of the Company’s California Public

Utilities Commission (“CPUC”) approved Electric Rule 21 Tariff (“Rule 21”) on behalf of one or


6 The Agreement defines an Aggregator as “an entity that provides the communication capability functions required in Section Hh of Rule 21 on behalf of one or more Participating Generating Facilities that utilize inverter-based technologies.”

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more Participating Generating Facilities that utilize inverter-based technologies.”7 The

“Communications Functions” section further provides, among other things, that “service(s) shall

be capable of authorized communications[.]”8 Requirements relating to the ability to provide

communication functions are therefore distinct from requirements relating to when and how action

must be performed in response to a communication, which is not contemplated by the Agreement.

To be clear though, under the terms of the Agreement, Aggregators are obligated to

demonstrate that they are actually capable of providing the communication functions set forth

therein. It is insufficient for an Aggregator to merely assert, without any testing or evidence, that

it is capable of providing such communication functions.

It is appropriate for the Agreement to govern only the capability of Aggregators, not their

performance, given both the scope of Issue 6 and the timeline for the development of smart inverter

technologies. Issue 6 asks whether the Commission should “require the Utilities to develop forms

and agreements to allow distributed energy resource aggregators to fulfill Rule 21 requirements

related to smart inverters? If yes, what should be included in the forms and agreements?”9 In

other words, Issue 6 tasks stakeholders with creating forms and agreements necessary to conform

to Rule 21 as it is written, not with revising Rule 21. Because Rule 21 requirements relate to the

capability of providing communication functions, not performance, so should the Agreement. 10

The timeline for developing smart inverter technologies and testing standards further

supports that the Agreement should only govern capability. Currently, there are no operational

requirements for the performance of smart inverter functions utilizing communications.11 And

7 See Working Group Two Report, at p. 12.

8 See id., at p. 13.

9 R. 17-07-007, Scoping Memo of Assigned Commissioner and Administrative Law Judge, issued on October 2, 2017, at p. 3.

10 See SCE’s Rule 21, Section Hh.5.

11 See, e.g., R. 17-07-007, Request of the California Solar & Storage Association for Extension of Time to Comply with Rule 21 Smart Inverter Communications Requirements, submitted on November 19, 2018, at p. 4.

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although stakeholders agree that, as reflected in Rule 21 Section Hh.5.a.4, the default

communications protocol for smart inverter communications shall be IEEE 2030.5, there currently

is not an industry consensus on the certification process for Aggregators. These critical steps,

among others, would need to be resolved prior to developing an agreement to govern when and

how action must be performed in response to a communication. SCE thus recommends that the

Agreement be construed to govern only capability. SCE expects that the Commission will

ultimately address actual performance through future action, and that an agreement to govern

performance will be developed at that time.

4. Does the Commission need to answer any other questions before parties continue negotiating the Agreement? If yes, explain both why an issue needs to be addressed now and your organization’s position on that issue.

As set forth above, SCE believes that the Agreement does, and should, only govern the

capability, not the performance, of Aggregators to provide the communication functions required

in Rule 21 Section Hh. Importantly, SCE also believes that it is critical that the Agreement require

Aggregators to demonstrate that they are actually capable of providing such communication

functions. However, due to, among other things, disagreements between stakeholders, there

continues to be a lack of clarity on how Aggregators should make this demonstration. SCE

believes such clarification should occur prior to finalizing the Agreement. SCE therefore requests

that the Commission provide guidance as to how an Aggregator should be required to demonstrate

its communication functions capabilities. SCE believes that answers to the following questions,

among others, may help to provide stakeholders guidance on this complex issue:

Question – What should the Aggregator certification requirements be?

SCE’s Position – As set forth in SCE’s Implementation Plan that was provided to the Smart Inverter Working Group (“SIWG”) on January 7, 2019, SCE believes that the SunSpec Alliance (“SunSpec”) should be allowed to be a certification body, while also allowing industry to develop other processes and submit these processes to a Nationally Recognized Testing Laboratory (“NRTL”) to certify.

Question – What level of testing should be required for an Aggregator to demonstrate that it is capable of communicating between the Aggregator and the Participating Generating Facility(ies)?

SCE’s Position – SCE believes that the Aggregator Agreement should require type-

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testing to verify the communication capabilities between the Aggregator and the Participating Generating Facility(ies).12

5. What procedural mechanism should the utilities use to seek Commission approval of the Agreement?

SCE recommends that the Commission order stakeholders to continue to negotiate the

terms and conditions of the Agreement, and based on the resolution of the issues identified above,

to set a deadline by which each IOU shall submit a Tier 3 Advice Letter setting forth its proposed

final Agreement. This deadline should be dependent upon the resolution of issues the Commission

determines must be resolved prior to finalizing the Agreement, such as those identified above in

SCE’s response to Question No. 4. SCE believes that this procedure will provide stakeholders

meaningful time to attempt to achieve a consensus, and comports with the stakeholder

understanding that this Agreement is “incomplete and in development[.]”13

6. What is the recommended deadline for the utilities to ask for such approval? Justify that deadline.

The deadline for submitting a Tier 3 Advice Letter should be dependent upon resolution of

the issues the Commission determines must be resolved prior to finalizing the Agreement, such as

those identified above in SCE’s response to Question No. 4. However, SCE believes that it is

necessary for the Agreement to be approved prior to any Aggregator participation under Rule 21.

C. Responses to Questions Concerning Issue 8

7. Answer the following questions related to costs and benefits:

a. What are the types and approximate magnitudes of costs and benefits of each proposal in the October Report?

While Working Group Two Members “discussed whether and how to consider the costs of

implementing” Issue 8 proposals,14 Working Group Two did not determine any level of financial

cost(s) or perform any cost-benefit analyses for any of the Issue 8 proposals. SCE recommends

12 Because the issue of what level of testing should be required was not resolved by the February 22, 2019 deadline to comply with smart inverter Phase III Functions 1 and 8, SCE’s Implementation Plan did not require testing, and instead, allowed for certification without testing. Nevertheless, SCE believes that, as a best practice, type-testing should be required.

13 Working Group Two Report, at p. 9.


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that before considering costs and benefits further, the Commission first determine whether a

proposal is safe and reliable. SCE would thereafter be supportive of the Commission directing the

IOUs to submit comments on the estimated costs and potential benefits of any proposals deemed

safe and reliable by the Commission. These comments could also consider what, if any, additional

procedural steps would be needed for the IOUs to pursue any proposals that appear to be favorable

from a cost-benefit perspective.

Although the Working Group Two Members did not conduct any cost-benefit analyses of

the Issue 8 proposals, they did, however, discuss cost responsibility as it relates to Proposal 8.d.

Specifically, SCE explained that, to allow Fast Track projects to re-submit their applications for

the purpose of modifying the size of their project if ICA values have changed in a way that causes

them to fail Fast Track, would create the potential that size changes to a queued-ahead party’s

project could shift cost responsibility to the detriment of a lower-queued party.15 A fundamental

cost responsibility principal for all projects processed under Rule 21 is that a cost shift based on

project modification is precluded if it would be to the detriment of a lower-queued project. Such

cost responsibility principals are also applied to projects processed under SCE’s Wholesale

Distribution Access Tariff (“WDAT”), under the jurisdiction of the Federal Energy Regulatory

Commission. Adoption of Proposal 8.d would undermine this fundamental principal, and could

result in a cost responsibility framework that is not aligned between Rule 21 and WDAT.

b. What perspective should the Commission use in the cost and benefit analysis (i.e., which costs and benefits should be considered by the Commission in determining whether proposed activities are just and reasonable and in ratepayers’ best interests)?

As discussed above in SCE’s response to Question No. 7(a), no financial cost-benefit

analysis was performed by SCE as part of Working Group Two. Nevertheless, SCE urges the

Commission to focus on the safety and reliability of the operation of the electric grid when

considering whether proposed activities are just and reasonable and in ratepayers’ interests. While


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SCE appreciates and supports continued efficiency in interconnection processing, the overriding

focus must always be on grid safety and reliability, both for customers and grid operators. SCE

understands the continued push by stakeholders for expedited interconnection processing through

a minimized system of technical review, but maintains that we should not sacrifice safety and

reliability in favor of efficiency, as discussed throughout SCE’s responses. For these reasons, SCE

believes that safety and reliability should be at the center of any cost-benefits analysis conducted

by the Commission.

c. Who should perform an analysis of costs and benefits?

As set forth in SCE’s response to Question No. 7(a), Working Group Two did not perform

any cost-benefit analyses. SCE recommends that before considering costs and benefits further, the

Commission first determine whether a proposal is safe and reliable. SCE would thereafter be

supportive of the Commission directing the IOUs to submit comments on the estimated costs and

potential benefits of any proposals deemed safe and reliable by the Commission. These comments

could also consider what, if any, additional procedural steps would be needed for the IOUs to

pursue any proposals that appear to be favorable from a cost-benefit perspective.

d. Should there be a threshold magnitude of costs, above which it is appropriate for the Commission to consider costs, and below which it is not appropriate for the Commission to consider cost? Why or why not? If there should be such a threshold, what should that threshold be?

As previously discussed in SCE’s response to Question No. 7(a), no financial cost-benefit

analysis was performed by SCE as part of the Working Group Two stakeholder discussions. SCE

therefore does not have sufficient information to answer this question at this time.

e. Which proposals are likely to cross this threshold?

As previously discussed in SCE’s response to Question No. 7(a), no financial cost-benefit

analysis was performed by SCE as part of the Working Group Two stakeholder discussions. SCE

therefore does not have sufficient information to answer this question at this time.

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8. For Pacific Gas and Electric Company (PG&E) and San Diego Gas & Electric Company (SDG&E): What is the reason for not considering future implementation of a system for providing a visual indicator (i.e., “flagging” in the October Report) as part of the online Integration Capacity Analysis (ICA) data maps and/or portal, if the ICA values likely need an update?

SCE does not provide a response because this question is directed only to PG&E and

SDG&E.

9. For PG&E: Provide a detailed explanation of how the 15 percent screen is proposed to be used in ICA verification.

SCE does not provide a response because this question is directed solely to PG&E.

10. For non-utility stakeholders: If Proposal 8.d is adopted, how should the utilities manage the monthly ICA update process?

SCE does not provide a response because this question is directed to non-utility

stakeholders.

11. For the utilities: If Screen I is not moved to Rule 21’s technical framework overview, how soon and with what frequency do you anticipate that the distribution grid will experience overvoltage conditions and possible overloads that would otherwise have been addressed through the interconnection process? What is the range of typical cost for upgrades that would be required to mitigate these issues?

Currently, SCE allows non-export projects of all sizes to bypass Screens J, K, L, and M;

and does not require a non-export project to undergo Supplemental Review if it passed Screens A

through H. However, SCE has found this review process to be sufficient only in light of the

historically low DER penetration levels. For a comparison between historical levels of DER

interconnection requests to current levels see Figure 1 below, which depicts a very large increase

in DER interconnection requests between 1998 and 2018 – a trend that SCE expects to continue

based on upcoming Zero Net Energy requirements.

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Figure 1 – DER Penetration Levels

In September 2018, CALSSA and IREC requested a statistical evaluation of ICA-SG data.

That statistical data, which is depicted in Figure 2 below, indicated that 36% of the 3-phase

electrical nodes in SCE’s service territory have an ICA-SG value less than 100KW. This data

suggests that about 1/3 of SCE’s service territory 3-phase electrical system would be exposed to

undetected safety and reliability issues, such as overvoltage conditions, if SCE were to continue

to not perform technical evaluations for non-export projects of all sizes. SCE reiterates that while

non-export projects that have passed Screens A through H have not previously been required to

perform the power flow evaluation screens (i.e., Screens M, N, O, P), that was based on low levels

of DER penetration. SCE now has over 4,000 MW of interconnected DERs and an additional

yearly increase of approximately 600 MW of DER capacity, which continues to reduce the ICA

values that can be used for both export and non-export projects. As the statistical dataset confirms,

a significant portion of SCE’s 3-phase electrical system has a very low level of ICA, meaning that

non-export projects could require system upgrades, the need for which may not be identified if

non-export projects of all sizes continue to be allowed to bypass technical evaluation. Simply put,

we cannot—as certain stakeholders urge—maintain the “status quo” and wait to deal with this

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issue in another phase of this proceeding, or in another docket,16 because our DER penetration

levels are changing and our review needs to change with it. Accordingly, Screen I should be

moved to the technical framework overview so that non-exporting projects above 30 kVA are

reviewed under all Screens.

Figure 2 – ICA-SG Statistical Data

While SCE believes that the aforementioned safety and reliability issues would result if

non-exporting projects of all sizes continue to be allowed to bypass screens—i.e., if Screen I is not

moved to Rule 21’s technical framework overview—SCE does not, at this time, have sufficient

information available to answer when, or with what frequency, SCE could begin to experience

overvoltage conditions.

With regards to the range of typical cost for upgrades that would be required to mitigate

these issues, it is difficult to provide such an estimate given that costs could vary greatly based on

a project size, type, and system specific location. In some cases, simple low cost modification to

Voltage Regulation (“VR”) schemes, such as a change in the regulation control settings, may be

sufficient to resolve safety and reliability concerns. However, higher cost mitigation efforts may

be required in other cases, such as the installation of new VR devices or new protection devices,

or the upgrade of existing conductor(s). Additionally, projects that are located near a substation

are less prone to cause voltage related issues, while projects that are near the end of long feeders

have a higher likelihood of creating voltage related issues. It is therefore difficult to provide an


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estimate of average mitigation costs given the dependency of such costs on a project’s size, type,

and system specific location.

12. For Southern California Edison Company (SCE): When will SCE be able to determine if it can develop the additional capabilities at a reasonable cost?

SCE will need approximately six months to determine if it can develop the capability to

display, on ICA maps, locations where projects would likely fail Screen L, the available options

to do so, and the necessary tools and associated costs. Once this capability is fully evaluated,

funding may be required to implement and maintain the solution.

13. For SDG&E: Explain your position to proposal 8.1.

SCE does not provide a response because this question is directed solely to SDG&E.

14. For PG&E and SDG&E: Explain your opposition to Implementation Variation 1


SDG&E.

15. Under Screen M.d on page 68 of the October Report, would a buffer set at a certain level on the ICA-Operational Flexibility (OF) curve be preferable to using 100 percent of the lowest ICA-OF value? If yes, what level of buffer should be used in the following revised language: “Is the Photo Voltaic (PV) Interconnection Request real power production based on PV Watts or equivalent greater than [XX] percent of the ICA-OF value in any hour?”

No, given the infancy of the usage of the new ICA parameters, as well as the potential for

safety and reliability issues, including equipment overloads and system over-voltages, SCE urges

the Commission to adopt the proposed language for Screen M.d, as set forth on page 68 of the

Working Group Two Report. This language implements Proposal 8.m Option A,17 which proposes

using 100% of the lowest value in the ICA-OF 576 profile. SCE believes that using the lowest

value in the ICA-OF 576 profile is essential to ensure safety and reliability of the grid.18

16. If a project fails Screen M because generation exceeds 100 percent of the lowest ICA-OF value, what determines whether a project is required to go to Supplemental

17 Proposal 8.m Option A is also supported by PG&E, SDG&E, and TURN. See Working Group Two Report, at p. 65.


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Review or Detailed Study? List the additional steps of review that would be done in either study track, and the typical values for how much additional time would be required for each step?

If a project fails Screen M because generation exceeds 100 percent of the lowest ICA-OF

value, then the next step would be to perform a review of distribution system topology to determine

possible issues with system flexibility, as described at pages 70 and 71 of the Working Group Two

Report. If no issues are detected, which will be the case for most projects, then the project will be

allowed to pass Screen M, and hence, will not proceed to Supplemental Review or Detailed Study.

SCE thus expects that most projects that fail Screen M due to the value of the ICA-OF will not

need to proceed to Supplemental Review because a relatively quick verification of SCE’s

distribution system topology will be able to confirm that values above the lowest ICA-OF will not

create system operational issues.

However, if system operational flexibility issues are identified based on distribution system

topology, then SCE would require the project to proceed to Supplemental Review, at which time

additional technical evaluation may be conducted to determine what, if any, additional equipment

is necessary to mitigate any system operation conditions.

17. What additional issues must be resolved prior to the Commission revisiting the queue management rules? Can these issues be resolved through comments? If so, how?

As set forth in the Working Group Two Report,19 SCE is opposed to the proposed queue

management changes for the reasons outlined therein. While SCE believes its response to Proposal

8.t in the Working Group Two Report is complete, SCE is supportive of a stakeholder workshop

to discuss queue management rules and practices, as well as the Commission directing

stakeholders to provide additional comments on the topic of queue management, if necessary.

To that end, SCE also takes this opportunity now to inform the Commission that there is

no indication that an ICA “land grab” is occurring, as claimed Proposal 8.t Option A.20 Available



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capacity is only part of the calculus as to whether a generating or storage project is viable. As

explained in the Working Group Two Report, there are several other factors, independent of

capacity or the cost of required interconnection facilities and distribution upgrades, which enter

into the viability of any given project, with the primary factor being the existence of an “off-taker”

and power purchase agreement (“PPA”). In SCE’s opinion, the points made in Proposal 8.t Option

A (requiring justification for extending Commercial Operation Date, tightening deadlines, and

allowing smaller projects to leap-frog larger projects that are moving slower) fundamentally seek

to solve a problem that does not exist (i.e., the supposed problem of ICA “land grabbing”) and

could cause more problems than they seek to remedy. For example, proper queue management

techniques are necessary for administering a level playing field among participants in the

interconnection process. Allowing parties to leap-frog others in the queue just because they may

be smaller, or have smaller upgrades that can be constructed quicker than larger queued-ahead

projects, might have a material impact on the queued-ahead project. There is an equitable solution

to this already in other jurisdictions, such as the CAISO and WDAT GIPs, whereby if a later-

queued project wishes to expedite the upgrades for a queued-ahead project, it can do so by

financing the queued-ahead upgrade(s) along with its own facilities and upgrades. It is a rare

project that is willing to go that route, but it is the fair and equitable approach. This option is not

contemplated in Proposal 8.t.

18. For PG&E: Explain why the timelines proposed would not work for most of the applications? (October Report at 83).

SCE does not provide a response because this question is directed solely to PG&E.

D. Responses to Questions Concerning Issue 9

19. For the non-utility parties: Describe any missing details of the Issue 9 proposal, including:

o What is the recommended buffer between the published maximum ICA-Static Grid and the corresponding output in the Limited Generation Profile? Provide justification for your response.

o What customers would you foresee using this option, and do all project sizes and asset types need this option?

o How should the utilities make the determination that generation profile

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reductions to maintain safety and reliability are necessary?

o Is there any limit to the amount of curtailment the utilities could require of a facility?

o If an upgrade is avoided due to an operational constraint, but the next customer elects to upgrade, does the operational constraint remain?


stakeholders.

20. For the utilities: List any missing details of the Issue 9 counter proposal.

SCE does not believe that there are missing details from the IOUs’ Issue 9 counter-

proposal, as set forth at pages 125-126 of the Working Group Two Report. However, the Working

Group Two schedule did not allow the IOUs the opportunity to discuss their counter-proposal with

stakeholders. SCE is therefore supportive of the Commission directing stakeholders to submit

comments on the Issue 9 counter-proposal.

21. For the utilities: How are voltage, thermal, VAR, and frequency controlled and monitored on the distribution grid? Include communication latency times (i.e., the lag between the time of an excursion event, the receipt of the information by a communications or control system or device about the occurrence of the excursion, and the completion of corrective action by the appropriate control method) for each monitoring or control method. If different methods are used in different parts of the utility’s distribution grid, describe each method.

The following summaries explain how voltage, thermal, VAR and frequency control are

monitored on SCE’s distribution grid:

Voltage – voltage control is accomplished using a combination of autonomously

controlled voltage regulation devices, such as substation load tap changers,

substation voltage regulators, field voltage regulators, and capacitor bank controls.

These voltage regulation devices operate autonomously based on specific settings

and measurements (voltage level, current level), and regulate voltage level based

on pre-programmed settings. While most of these voltage regulation devices can

be remotely operated with communication latency ranging seconds to minutes

depending on the location of the device, these operations are mostly for corrective

actions and not for continuous voltage control, which is instead accomplished

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locally and autonomously. Depending on the type of circuit, different voltage

regulation schemes are used to meet the local system needs. Depending on the age

of the voltage regulator device, monitoring for the device may or may not be

available. The distribution management system latency for voltage active control

is approximately 20 seconds, and return communication from a regulating device

to SCE’s distribution management system is approximately every six (6) hours,

depending on location of the voltage regulation device.

Thermal – thermal (loading) control on distribution feeders is mostly

accomplished through the annual planning process for long term needs, and through

real-time grid operations for short term needs. While there are some programs that

may aid load control (such as AC cycling), at this point, these programs are targeted

at the system level and are not able to deploy for specific distribution line section

loading. Therefore, SCE, thorough its annual planning process, plans for loading

conditions to be within equipment rating, and performs real-time distribution

operation as needed for real-time loading management. For monitoring thermal

conditions, SCE is only capable of monitoring thermal conditions at the

feeder/substation level or where SCE has distribution automatic reclosers.

Distribution latency times for thermal (loading) may be from seconds to minutes

depending on location and device type.

VAR – SCE uses capacitor banks located at substations and throughout the

distribution feeder to provide VAR support to SCE’s distribution system. These

capacitor banks rely on autonomous control (see section on voltage control above).

While most capacitor banks can be remotely operated with communication latency

ranging seconds to minutes depending on the location, these operations are mostly

for corrective actions and not for continuous reactive power control, which is

instead accomplished locally and autonomously. In some areas, SCE has been

transitioning to global control of these devices to optimize the voltage and reactive

18

power flow in the grid.

Frequency –Frequency is controlled through the Bulk Electric System (“BES”),

and is not controlled at the distribution level.

22. For the utilities: Approximately what percentage of your distribution grid—by customers served—is covered by each monitoring and control method?

SCE does not have active monitoring and control for voltage, thermal rating, VAR, or

frequency at the customer level. Instead, SCE has monitoring and control for each of these

elements at the system level (which does cover all customers connected to grid). However, issues

may occur at localized circuit line sections that may not have monitoring systems in place.

23. For the utilities: For the utilities’ concerns raised on page 123 of the October Report under the heading “IOU Perspective,” describe any missing equipment, communication infrastructure, experience and certification or testing that would be necessary to rely on generator controls/generation reductions, as well as the utilities’ current expected timeline for acquiring each missing element.

SCE believes that there are significant factors that need to be addressed prior to the

Commission approving the Issue 9 proposal, or any variation thereof.21 Specifically, SCE believes

that both the DER industry and the utilities need to have an adequate level of bi-directional

communication and controls capabilities to ensure that Limited Generation Profile DERs

connected with the grid operate safely and reliably. SCE believes the Joint IOU Issue 9 counter-

proposal to be preferable to the Issue 9 proposal while these communication and operation control

systems are deployed. Currently, the following experience, infrastructure, and standards—all of

which are necessary to rely on generator controls/generation reductions—are missing or lacking:

Lack of experience: while DER stakeholders indicate that controls capable of

ensuring that a project’s actual performance conforms with its submitted Limited

Generation Profile (i.e., “DER control systems”) are currently available, DER

control systems have never been deployed in any project connected within SCE

territory. As such, SCE lacks experience using DER control systems in the manner


19

suggested by Proposal 9.

Lack of infrastructure: for these DER control systems to safely operate with the

grid, these DER controls need to have real-time information on the status and

condition of the grid, including loading levels and abnormal conditions. However,

currently there is insufficient communication and system infrastructure that can be

used to provide the DER control systems the real-time grid information that is

needed for the safe operation of these controls without causing grid issues. Without

sufficient real-time grid information, the DER controls could operate in a manner

that creates system overloads and/or overvoltage conditions, leading to safety and

reliability issues. SCE is evaluating several elements that are necessary to facilitate

bi-directional communication with DERs, including cybersecurity tools,

communication means, Advanced Distribution Management, and the DERMS

platforms. Given the complexity of the overall system, and ability to fund these

new control platforms, SCE is projecting to have initial deployment capability of

DERMS starting 2022.

Standards: There are currently no certification standards for these DER control

systems. Further, there are currently no standards being developed to address this

need, and thus, it may be years before a certification standard for DER control

systems is developed.

24. Should the Commission track cost that result when systems interconnect up to the defined hosting capacity limit, load subsequently disappears, and mitigations are therefore required later?

New reporting requirements are under review and actively being discussed as part of

Working Group Three Issue 12. Additionally, the ICA, which just went into active status on

December 28, 2018, remains in infancy stages, and tracking costs for the above scenario may be

premature at this time. For these reasons, SCE would support reviewing whether the Commission

should track costs for the above scenario as part of future stakeholder discussions within the

Interconnection Discussion Forum (“IDF”).

20

25. Should the Commission explore the idea of a cost recovery mechanism for the situation described in Question 24 above? For example, the utilities could track costs for upgrades that are required after systems interconnect through a process like the one described in the Issue 9 proposal. Interconnection fees for projects interconnecting through the new process could be adjusted annually to reflect the additional costs.

At this time, SCE does not support the Commission exploring cost recovery mechanisms

for costs for upgrades that are required after systems interconnect up to the defined hosting

capacity limit, load subsequently disappears, and mitigations are required. SCE believes that the

likelihood of this scenario and the need to consider cost recovery mechanisms to address it should

be better understood and analyzed before instituting any related tariff changes.

E. Responses to Questions Concerning Issue 10 (Proposals 4-8)

26. What are the benefits and drawbacks of including timelines in the utilities’ Rule 21 tariffs rather than within individual interconnection agreements?

Given the many drawbacks to including, within the utilities’ Rule 21 tariffs, timelines for

utilities to provide design and cost estimates (Issue 10, Proposal 6) and to construct interconnection

facilities and minor distribution upgrades (Issue 10, Proposal 7), these timelines should be set forth

in the interconnection agreement instead. SCE currently provides milestones and deadlines within

its interconnection agreement appendices, and this process has worked successfully in the past.

First, milestones are applicable to both utilities and interconnection customers on a project-

specific basis, and thus, cannot be fully described in Rule 21. Tariff language generally describes

processes and deadlines applicable to all projects, and it would be impracticable to specify the

various milestones that are applicable for the different types of projects. For instance, projects that

do not have customer constructed facilities (such as underground structures) will have different

milestones than projects that have customer-constructed facilities. Similarly, some projects may

have certified technology while others do not, some may require customer equipment or control

changes while others do not, and still others may be in known constrained generation capacity

areas while others are not – all of which impact milestones. Given the various type of projects,

the interconnection agreement is the most appropriate place to outline the specific milestones for

each project’s needs.

21

Second, a utility and customer must work together to meet deadlines, and milestones should

therefore be mutual. For example, depending on the scope of the work, SCE generally endeavors

to conduct its design work within 60 business days, but cannot begin to do so until the customer

has provided certain design information. A firm 60 business day deadline that is only imposed on

the utility is not tenable given the many contingencies that could affect the utility’s ability to meet

this deadline. For this reason also, SCE believes that milestones and deadlines are best provided

for in the interconnection agreement.22

Third, tariff timelines are static and would fail to account for market trends and changes,

such as unanticipated project types and volumes or resource constraints within the utility.

Procedural timelines represent an estimate of time required to complete any given action in a

process and depend heavily on average project complexity, project volume, and reasonable

fulfillment of customer requirements to enable a timely process continuum. The interdependencies

in the overall timeline (meaning, steps are generally serial in nature and although there are some

steps that can be done in parallel, most require a precedent step to be achieved before the next step

can commence) only adds to this complexity. A utility might be able to achieve 100% of its

timelines, but the project might still miss overall deadlines due to customer delay (and vice-versa).

Thus, any variation in project complexity and fulfillment of customer requirements challenges the

utility’s ability to deliver a result on par with tariff embedded timelines. This is exacerbated by

the prior mentioned variables pertaining to grid conditions, dramatic shifts, in market demand, and

resource constraints. Only if the market could guarantee no year-over-year changes in project

volume, complexity, or customer performance—an unlikely proposition—could SCE reasonably

prepare itself and deliver according to prescribed tariff timelines. However, the dynamics of grid

interconnection in a competitive power market environment indicate that static timelines will

periodically be missed as a result of the above-mentioned challenges.

While SCE thus believes that it is reasonable to require estimated timelines, and to measure

22 See also Working Group Two Report, at pp. 133.

22

and account for performance towards those timelines, SCE believes that both the utilities and

interconnection customers would be best served by placing those timelines in the interconnection

agreements. SCE is nevertheless supportive of tracking key procedural process timelines and

developing reporting metrics to assist the Commission in analyzing the efficacy of Rule 21

processes and identifying resource improvement opportunities. SCE notes that the development

of compliance tracking is also under active discussion within Working Group Three Issue 12.

27. For the utilities: For any timelines opposed in the proposals, are there longer

timelines that would be acceptable?

For the reasons set forth below, SCE does not support the following proposals, and

provides, where applicable, alternative timelines that would be acceptable:

Issue 10 Proposal 5 – rather than five (5) business days to make customer contact,

SCE believes that ten (10) business days is more realistic.23

Issue 10 Proposal 6 – SCE is generally acceptable to the proposed timeline of 60

business days to provide design and cost estimates. However, as indicated at page

133 of the Working Group Two Report, the process described in Proposal 6 is not

applicable to SCE because SCE estimates costs as part of the study reports (Fast

Track, Independent Study Process, and Distribution Group Study), and then

conducts a true-up after the project has been completed. SCE includes a milestone

table in its interconnection agreement appendices, which includes this 60 business

day timeline (depending on the scope of the work) for providing design and cost

estimates. As explained in SCE’s response to Question No. 26, SCE believes this

process to be working well.

Issue 10 Proposal 7 – SCE is generally acceptable to the proposed timeline of 60

business days to construct interconnection facilities and minor distribution

upgrades. However, as SCE advocated in its response to Question No. 26, this and


23

other associated timelines should be part of the milestones table in the

interconnection agreement, not the Rule 21 tariff.

Issue 10 Proposal 8 – rather than a 6-month deadline for final invoicing of projects,

SCE believes that a 12-month deadline is necessary. As SCE explained at page 136

of the Working Group Two Report, it typically takes 170 days after project

completion to receive and confirm all costs, and the reconciliation and invoicing

process, including management review and approval, requires an additional 60 days

(i.e., more than 7 ½ months). A complex project can easily extend these timelines.

While SCE strives to provide invoices in a timely manner, it is just as important

that the proper steps are taken to ensure accuracy, which takes time.

28. Proposal 4: For SDG&E and PG&E: Explain in detail, your perspective on the proposal and your current business practice for providing invoices to interconnection applicants.


SDG&E.

F. Responses to Questions Concerning Issue 11

29. On page 141 of the October Report, the utilities present five issues with expanding Proposal B1 to include all generating facilities with aggregate gross nameplate inverter rating under 30 kVA regardless of whether those systems are exporting or non-exporting. Propose solutions to each of the identified issues.

The five issues identified on page 141 of the Working Group Two Report all highlight the

fact that the non-exporting projects studied in the IOU Non-Exporting Storage Facilities Pilot

Programs are inherently different from exporting projects, and thus, findings from this pilot cannot

be used to support including all generating facilities with an aggregate nameplate inverter rating

under 30 kVA, regardless of whether they are non-export or export, in the Issue 11 proposal.

Indeed, given the fundamental differences between non-exporting and exporting projects, to do so

would be less of an expansion of the aforementioned pilot program’s findings, and more of an

“apples-to-oranges” comparison of interconnection processes that differ widely based on project

type. The issues identified on page 141 of the Working Group Two Report therefore include:

24

PURPA Jurisdiction Qualification – unlike exporting projects, non-exporting

projects do not present risks of a violation of the Public Utility Regulatory Policies

Act of 1978 (“PURPA”);

Insurance Certification – NEM projects that are less than 1 MW are not required to

provide a certificate of insurance; and

Forms and Agreements – exporting projects have different forms and agreement

from non-exporting projects. As such, new forms and agreements and/or additional

processes—none of which were studied during the aforementioned pilot due to the

scope of that pilot—would need to be developed to support including exporting

projects in the Issue 11 proposal. SCE, however, understands and strives toward

continuous improvement within interconnection processing and has commenced a

two-phase project providing interconnection system enhancements, with Phase 1

automation addressing Rule 21 non-export projects projected to be rolled out in the

fourth quarter of 2019. Phase 2 will provide enhanced processing for NEM, Rule

21 export and multi-tariff projects, with capability rollout occurring during 2020.

SCE is supportive of providing updates as to the status and rollout of these system

enhancements within the IDF. Further, SCE is currently working with stakeholders

in Working Group Three to supplement interconnection reporting to determine

whether there are opportunities for improvement in interconnection processing.

30. For non-utility stakeholders: What is the appropriate percentage of overall projects, on an annual nameplate basis by customer segment and technology type, that you expect to use the Lightening Review Process going forward (e.g., X percent of annual MW of residential rooftop + storage)? What are the public policy reasons the Commission should focus on streamlining the interconnection process for these specific project types?


stakeholders.

25

31. Provide rough estimates of the costs and benefits (in terms of shortened timelines, reduced interconnection study costs, staff time spent reviewing applications, costs to develop software, etc.) for each phase of the Lightening Review Process.

As indicated in SCE’s response to Question Nos. 7(a) and 7(c), Working Group Two did

not perform any cost-benefit analyses. SCE recommends that before considering costs and

benefits further, the Commission first determine whether a proposal is safe and reliable. SCE

would thereafter be supportive of the Commission directing the IOUs to submit comments on the

estimated costs and potential benefits of any proposals deemed safe and reliable by the

Commission. These comments could also consider what, if any, additional procedural steps would

be needed for the IOUs to pursue any proposals that appear to be favorable from a cost-benefit

perspective.

III. CONCLUSION

SCE appreciates the opportunity to provide these responses to the questions in the ALJ’s

Ruling on the Working Group Two Report.

Respectfully submitted, ALEXA MULLARKY

/s/ Alexa Mullarky By: Alexa Mullarky

Attorney for SOUTHERN CALIFORNIA EDISON COMPANY

2244 Walnut Grove Avenue Post Office Box 800 Rosemead, California 91770 Telephone: (626) 302-1577 E-mail: [email protected]

Dated: February 1, 2019


STATE OF CALIFORNIA



CERTIFICATE OF SERVICE

I hereby certify that, pursuant to the Commission’s Rules of Practice and Procedure, I have this day served a true copy of the RESPONSE OF SOUTHERN CALIFORNIA EDISON COMPANY (U 338-E) TO ADMINISTRATIVE LAW JUDGE’S RULING DIRECTING RESPONSES TO QUESTIONS ON WORKING GROUP TWO REPORT on all parties identified on the attached service list for R.17-07-007. Service was effected by transmitting copies via e-mail to all parties who have provided an e-mail address and by placing a copy in a sealed envelope and causing such envelope to be delivered via United States mail with first-class postage prepaid to the offices of the ALJ.

ALJ Kelly A. Hymes California Public Utilities Commission Division of Administrative Law Judges 505 Van Ness Avenue San Francisco, CA 94102-3214

Executed on February 1, 2019, at Rosemead, California.

/s/ Jorge Martinez Legal Administrative Assistant SOUTHERN CALIFORNIA EDISON COMPANY

2244 Walnut Grove Avenue Post Office Box 800 Rosemead, California 91770

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MATTHEW W. DWYER KEITH SWITZER ATTORNEY MGR - TARRIFFS & SPECIAL PROJECTS SOUTHERN CALIFORNIA EDISON COMPANY GOLDEN STATE WATER COMPANY 2244 WALNUT GROVE AVE. / PO BOX 800 630 EAST FOOTHILL BOULEVARD ROSEMEAD, CA 91770 SAN DIMAS, CA 91773-9016 FOR: SOUTHERN CALIFORNIA EDISON COMPANY FOR: GOLDEN STATE WATER COMPANY

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JONATHAN J. NEWLANDER KENNETH SAHM WHITE SR. COUNSEL ECONOMICS & POLICY ANALYSIS DIR SAN DIEGO GAS & ELECTRIC COMPANY CLEAN COALITION 8330 CENTURY PARK CT, CP32D 16 PALM CT. SAN DIEGO, CA 92123 MENLO PARK, CA 94025 FOR: SAN DIEGO GAS & ELECTRIC COMPANY FOR: CLEAN COALITION

TED KO SKY C. STANFIELD DIRECTOR OF POLICY ATTORNEY STEM, INC. SHUTE, MIHALY & WEINBERGER, LLP 100 ROLLINS ROAD 396 HAYES STREET MILLBRAE, CA 94030 SAN FRANCISCO, CA 94102 FOR: STEM, INC. FOR: INTERSTATE RENEWABLE ENERGY COUNCIL, INC. (IREC)

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CHRISTA SALO PAUL ANGELOPULO CALIF PUBLIC UTILITIES COMMISSION CALIF PUBLIC UTILITIES COMMISSION LEGAL DIVISION LEGAL DIVISION ROOM 4107 ROOM 4107 505 VAN NESS AVENUE 505 VAN NESS AVENUE SAN FRANCISCO, CA 94102-3214 SAN FRANCISCO, CA 94102-3214 FOR: ORA FOR: OFFICE OF SAFETY ADVOCATE (OSA)

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STEVE SHERR JASON B. KEYES SVP BUSINESS AFFAIRS & GEN. COUNSEL ATTORNEY FOUNDATION WINDPOWER, LLC KEYES & FOX LLP 505 SANSOME STREET, STE 450 436 14TH STREET, STE. 1305 SAN FRANCISCO, CA 94111 OAKLAND, CA 94612 FOR: FOUNDATION WINDPOWER, LLC FOR: TESLA, INC.

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JULIA A. LEVIN ANNE SMART EXECUTIVE DIR. VP, PUBLIC POLICY BIOENERGY ASSOCIATION OF CALIFORNIA CHARGEPOINT, INC. PO BOX 6184 254 EAST HACIENDA AVENUE ALBANY, CA 94706 CAMPBELL, CA 95008 FOR: BIOENERGY ASSOCIATION OF FOR: CHARGEPOINT, INC. CALIFORNIA (BAC)

WILLIAM H. WEAVER DANIEL MARSH SENIOR COUNSEL MGR - RATES & REGULATORY CALIFORNIA INDEPENDENT SYSTEM OPERATOR LIBERTY UTILITIES 250 OUTCROPPING WAY 933 ELOISE AVE. FOLSOM, CA 95630 SO. LAKE TAHOE, CA 96150 FOR: CALIFORNIA INDEPENDENT SYSTEM FOR: LIBERTY UTILITIES (CALPECO OPERATOR CORPORTATION (CAISO) ELECTRIC) LLC

MATTHEW MCVEE CHIEF REGULATORY COUNSEL PACIFICORP 825 N.E. MULTNOMAH ST, SUITE 2000 PORTLAND, OR 97232 FOR: PACIFICORP

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KAREN KHAMOU LEE TREVINO PACIFIC GAS & ELECTRIC COMPANY PACIFIC GAS AND ELECTRIC COMPANY EMAIL ONLY EMAIL ONLY EMAIL ONLY, CA 00000 EMAIL ONLY, CA 00000

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SHARON YANG NORMAN A. PEDERSEN ATTORNEY ATTORNEY LKP GLOBAL LAW, LLP HANNA AND MORTON LLP 1901 AVENUE OF THE STARS, SUITE 480 444 SOUTH FLOWER ST. SUITE 2530 LOS ANGELES, CA 90067 LOS ANGELES, CA 90071-2916

JOSEPH H. PARK DANIEL W. MARSH DIR - LEGAL SERVICES MGR - RATES & REGULATORY AFFAIRS LIBERTY UTILITIES (CALIFORNIA) LIBERTY UTILITIES (CALIFORNIA) 9750 WASHBURN ROAD 9750 WASHBURN ROAD DOWNEY, CA 90241 DOWNEY, CA 90241-7002 FOR: LIBERTY UTILITIES (CALPECO ELECTRIC) LLC

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MARC MONBOUQUETTE ALIA SCHOEN



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LAURA D. BEATON ADENIKE ADEYEYE ATTORNEY CALIF PUBLIC UTILITIES COMMISSION SHUTE, MIHALY & WEINBERGER LLP COMMISSIONER GUZMAN ACEVES 396 HAYES STREET ROOM 5303 SAN FRANCISCO, CA 94102 505 VAN NESS AVENUE FOR: INTERSTATE RENEWABLE ENERGY SAN FRANCISCO, CA 94102-3214 COUNCIL, INC.

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KELSEY PIRO KRISTIN CHARIPAR CASE MGR. ATTORNEY PACIFIC GAS AND ELECTRIC COMPANY PACIFIC GAS AND ELECTRIC COMPANY 77 BEALE STREET 77 BEALE STREET, MC B30A SAN FRANCISCO, CA 94105 SAN FRANCISCO, CA 94105

LARISSA KOEHLER MAGGIE CHAN SENIOR ATTORNEY REGULATORY AFFAIRS ENVIRONMENTAL DEFENSE FUND PACIFIC GAS AND ELECTRIC COMPANY 123 MISSION STREET, 28TH FLOOR 77 BEALE ST., MC B9A / PO BOX 770000 SAN FRANCISCO, CA 94105 SAN FRANCISCO, CA 94105 FOR: PACIFIC GAS AND ELECTRIC COMPANY

MARK ESGUERRA MELICIA CHARLES



PACIFIC GAS AND ELECTRIC COMPANY SUNRUN INC. 77 BEALE STREET 595 MARKET STREET, 29TH FL. SAN FRANCISCO, CA 94105 SAN FRANCISCO, CA 94105

SARINA URIZA TYLER CAPPS PACIFIC GAS AND ELECTRIC COMPANY NAVIGANT CONSULTING, INC. 77 BEALE ST., B9A ONE MARKET ST, SPEAR TOWER, STE 1200 SAN FRANCISCO, CA 94105 SAN FRANCISCO, CA 94105

WILLIAM CHUNG FRANCESCA WAHL PRODUCT MGR. SR. POLICY ASSOCIATE, BUS. DEVELOPMENT PACIFIC GAS AND ELECTRIC COMPANY TESLA, INC. 77 BEALE STREET 444 DE HARO STREET, STE. 101 SAN FRANCISCO, CA 94105 SAN FRANCISCO, CA 94107

JOHN W. ANDERSON BENJAMIN C. BODELL DIR - ENERGY MARKETS ATTORNEY OHMCONNECT, INC. GOODIN MACBRDIE SQUERI & DAY LLP 350 TOWNSEND ST., SUITE 210 505 SANSOME STREET, STE. 900 SAN FRANCISCO, CA 94107 SAN FRANCISCO, CA 94111

JOHN MCINTYRE LOUISE DYBLE ATTORNEY ATTORNEY GOODIN, MACBRIDE, SQUERI & DAY, LLP WINSTON & STRAWN 505 SANSOME ST., STE. 900 101 CALIFORNIA STREET, STE. 3500 SAN FRANCISCO, CA 94111 SAN FRANCISCO, CA 94111

MEGAN M. MYERS SARA STECK MYERS ATTORNEY ATTORNEY AT LAW LAW OFFICES OF SARA STECK MYERS LAW OFFICES OF SARA STECK MYERS 122 - 28TH AVENUE 122 - 28TH AVENUE SAN FRANCISCO, CA 94121 SAN FRANCISCO, CA 94121 FOR: CENTER FOR ENERGY EFFICIENCY AND FOR: CENTER FOR ENERGY EFFICIENCY AND RENEWABLE TECHNOLOGIES (CEERT) RENEWABLE TECHNOLOGIES

CASE ADMINISTRATION ERIK JACOBSON PACIFIC GAS AND ELECTRIC COMPANY DIR - REGULATORY RELATIONS EMAIL ONLY PACIFIC GAS AND ELECTRIC COMPANY EMAIL ONLY, CA 94177 77 BEALE ST., MD B23A / PO BOX 770000 SAN FRANCISCO, CA 94177 FOR: PACIFIC GAS AND ELECTRIC COMPANY

ALLIE DETRIO RACHEL BIRD POLICY MANAGER DIR - POLICY & BUS. DEVELOPMENT, WEST ENGIE SERVICES BORREGO SOLAR SYSTEMS, INC. 500 12TH STREET, SUITE 300 360 22ND STREET, SUITE 600 OAKLAND, CA 94607 OAKLAND, CA 94612

VIRGINIA VARNEY WILLIAM PLAXICO BORREGO SOLAR BORREGO SOLAR 360 22ND STREET, STE. 600 360 22ND ST., STE. 600 OAKLAND, CA 94612 OAKLAND, CA 94612



PHILLIP MULLER MARC KOLB SCD ENERGY SOLUTIONS GRID DEL SOL CONSULTING 436 NOVA ALBION WAY 46 VISTA DEL SOL SAN RAFAEL, CA 94903 MILL VALLEY, CA 94941

ANTHONY HARRISON RENEE SAMSON DIR - PUBLIC POLICY DIR - UTILITY SOLUTIONS CHARGEPOINT CHARGEPOINT, INC. 254 E. HACIENDA AVENUE 245 HACIENDA AVENUE CAMPBELL, CA 95008 CAMPBELL, CA 95008

CHRISTOPHER DEVON DELPHINE HOU CALIFORNIA INDEPENDENT SYSTEM OPERATOR CALIF. INDEPENDENT SYSTEMS OPERATOR 250 OUTCROPPING WAY 250 OUTCROPPING WAY FOLSOM, CA 95630 FOLSOM, CA 95630

ERIC KIM JILL POWERS MARKET / INFRASTRUCTURE POLICY CALIFORNIA INDEPENDENT SYSTEM OPERATOR CALIFORNIA ISO 250 OUTCROPPING WAY 250 OUTCROPPING WAY FOLSOM, CA 95630 FOLSOM, CA 95630

JOHN GOODIN KIM PEREZ CALIFORNIA INDEPENDENT SYSTEM OPERATOR CALIFORNIA ISO 250 OUTCROPPING WAY 250 OUTCROPPING WAY FOLSOM, CA 95630 FOLSOM, CA 95630

PETER KLAUER LORENZO KRISTOV CALIFORNIA INDEPENDENT SYSTEM OPERATOR CALIFORNIA ISO 250 OUTCROPPING WAY 250 OUTCROPPING WAY FOLSOM, CA 95630 FOLSOM, CA 95630-8773

AUDRA HARTMANN BRAD HEAVNER PRINCIPAL POLICY DIR. SMITH, WATTS & HARTMANN CALIFORNIA SOLAR & STORAGE ASSOCIATION 925 L STREET, SUITE 220 1107 9TH STREET, NO.820 SACRAMENTO, CA 95814 SACRAMENTO, CA 95814 FOR: CALIFORNIA SOLAR & STORAGE ASSOCIATION (CALSSA) F/K/A CALIFORNIA SOLAR ENERGY INDUSTRIES ASSOCIATION

JOSEPH OMOLETSKI STEVEN KELLY ASSOC. ENERGY SPECIALIST POLICY DIR CALIFORNIA ENERGY COMMISSION INDEPENDENT ENERGY PRODUCERS ASSOCIATION 1516 NINTH STREET, MS-45 1215 K STREET, STE. 900 SACRAMENTO, CA 95814 SACRAMENTO, CA 95814

LYNN HAUG RONALD LIEBERT ATTORNEY ATTORNEY AT LAW ELLISON SCHNEIDER HARRIS & DONLAN LLP ELLISON SCHNEIDER HARRIS & DONLAN LLP 2600 CAPITOL AVENUE, SUITE 400 2600 CAPITOL AVENUE, STE. 400 SACRAMENTO, CA 95816 SACRAMENTO, CA 95816



ANDREW B. BROWN BRIAN S. BIERING ATTORNEY AT LAW ATTORNEY ELLISON SCHNEIDER HARRIS & DONLAN LLP ELLISON SCHNEIDER HARRIS & DONLAN LLP 2600 CAPITAL AVENUE, SUITE 400 2600 CAPITOL AVENUE, SUITE 400 SACRAMENTO, CA 95816-5905 SACRAMENTO, CA 95816-5905

JEDEDIAH GIBSON TAM HUNT, J.D. ATTORNEY AT LAW CONSULTING ATTORNEY ELLISON SCHNEIDER HARRIS & DONLAN LLP COMMUNITY RENEWABLE SOLUTIONS, LLC 2600 CAPITOL AVENUE, SUITE 400 13-3585 MOKU ST SACRAMENTO, CA 95816-5905 PAHOA, HI 96778 FOR: ON BEHALF OF BEAR VALLEY ELECTRIC FOR: GREEN POWER INSTITUTE SERVICE

CATHIE ALLEN DIR - REGULATORY AFFAIRS PACIFICORP 825 NE MULTNOMAH ST., STE 300 PORTLAND, OR 97232 FOR: PACIFICORP

State Service

CALIFORNIA PUBLIC UTILITIES COMMISSION BRIAN KORPICS EMAIL ONLY CALIF PUBLIC UTILITIES COMMISSION EMAIL ONLY, CA 94102 DEMAND RESPONSE, CUSTOMER GENERATION, AN AREA 505 VAN NESS AVENUE SAN FRANCISCO, CA 94102-3214

CAROLYN SISTO CHLOE LUKINS CALIF PUBLIC UTILITIES COMMISSION CALIF PUBLIC UTILITIES COMMISSION PROCUREMENT STRATEGY AND OVERSIGHT BRANC ENERGY SAFETY & INFRASTRUCTURE BRANCH AREA ROOM 4102 505 VAN NESS AVENUE 505 VAN NESS AVENUE SAN FRANCISCO, CA 94102-3214 SAN FRANCISCO, CA 94102-3214

CHRISTOPHER PARKES DIANA L. LEE CALIF PUBLIC UTILITIES COMMISSION CALIF PUBLIC UTILITIES COMMISSION OFFICE OF THE SAFETY ADVOCATE LEGAL DIVISION AREA 2-D ROOM 4107 505 VAN NESS AVENUE 505 VAN NESS AVENUE SAN FRANCISCO, CA 94102-3214 SAN FRANCISCO, CA 94102-3214 FOR: OSA

FOREST KASER GABRIEL PETLIN CALIF PUBLIC UTILITIES COMMISSION CALIF PUBLIC UTILITIES COMMISSION PRESIDENT PICKER DEMAND RESPONSE, CUSTOMER GENERATION, AN AREA AREA 4-A 505 VAN NESS AVENUE 505 VAN NESS AVENUE SAN FRANCISCO, CA 94102-3214 SAN FRANCISCO, CA 94102-3214

JOSEPH A. ABHULIMEN KELLY A. HYMES CALIF PUBLIC UTILITIES COMMISSION CALIF PUBLIC UTILITIES COMMISSION



ENERGY SAFETY & INFRASTRUCTURE BRANCH DIVISION OF ADMINISTRATIVE LAW JUDGES ROOM 4209 ROOM 5104 505 VAN NESS AVENUE 505 VAN NESS AVENUE SAN FRANCISCO, CA 94102-3214 SAN FRANCISCO, CA 94102-3214

LIAM WEAVER MARY CLAIRE EVANS CALIF PUBLIC UTILITIES COMMISSION CALIF PUBLIC UTILITIES COMMISSION ENERGY SAFETY & INFRASTRUCTURE BRANCH DEMAND RESPONSE, CUSTOMER GENERATION, AN AREA AREA 505 VAN NESS AVENUE 505 VAN NESS AVENUE SAN FRANCISCO, CA 94102-3214 SAN FRANCISCO, CA 94102-3214

MATT MILEY OGEONYE ENYINWA CALIF PUBLIC UTILITIES COMMISSION CALIF PUBLIC UTILITIES COMMISSION LEGAL DIVISION WATER BRANCH ROOM 5135 ROOM 4108 505 VAN NESS AVENUE 505 VAN NESS AVENUE SAN FRANCISCO, CA 94102-3214 SAN FRANCISCO, CA 94102-3214

REESE ROGERS SOPHIE MEYER CALIF PUBLIC UTILITIES COMMISSION CALIF PUBLIC UTILITIES COMMISSION INFRASTRUCTURE PLANNING AND PERMITTING B INFRASTRUCTURE PLANNING AND PERMITTING B AREA AREA 505 VAN NESS AVENUE 505 VAN NESS AVENUE SAN FRANCISCO, CA 94102-3214 SAN FRANCISCO, CA 94102-3214

TIM G. DREW ABTIN MEHRSHAHI CALIF PUBLIC UTILITIES COMMISSION MECHANICAL ENGINEER ENERGY SAFETY & INFRASTRUCTURE BRANCH CALIFORNIA ENERGY COMMISSION AREA 4-A 1516 STREET, MS-45 505 VAN NESS AVENUE SACRAMENTO, CA 95814 SAN FRANCISCO, CA 94102-3214

FILIBERTO A. PINEDA MINA BOTROS CALIF PUBLIC UTILITIES COMMISSION CALIF PUBLIC UTILITIES COMMISSION OFFICE OF THE SAFETY ADVOCATE ENERGY SAFETY & INFRASTRUCTURE BRANCH 300 Capitol Mall 180 Promenade Circle, Suite 115 Sacramento, CA 95814 Sacramento, CA 95834

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