r1707007-sce response to alj ruling on working group two ... · sce’s below responses to question...
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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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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
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
5 See Working Group Two Report, at pp. 70-71.
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.
14 See Working Group Two Report, at p. 42.
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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
15 See Working Group Two Report, at pp. 49-50.
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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
16 See Working Group Two Report, at p. 54.
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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
SCE does not provide a response because this question is directed only to PG&E and
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.
18 See Working Group Two Report, at pp. 70-71.
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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
19 See Working Group Two Report, at pp. 83-84.
20 See Working Group Two Report, at pp. 80-81.
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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?
SCE does not provide a response because this question is directed to non-utility
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
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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
21 See Working Group Two Report, at p. 123.
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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”).
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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.
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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.
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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 See Working Group Two Report, at p. 133.
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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.
SCE does not provide a response because this question is directed only to PG&E and
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:
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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?
SCE does not provide a response because this question is directed to non-utility
stakeholders.
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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
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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)
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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CPUC Home
CALIFORNIA PUBLIC UTILITIES COMMISSIONService Lists
PROCEEDING: R1707007 - CPUC - OIR TO CONSID FILER: CPUC LIST NAME: LIST LAST CHANGED: JANUARY 10, 2019
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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
DAVID CHENG JACKIE PIERO STAFF ATTORNEY DIR - POLICY THE UTILITY REFORM NETWORK NUVVE CORPORATION 1620 5TH AVENUE, SUITE 810 2869 HISTORIC DECATUR ROAD SAN DIEGO, CA 92101 SAN DIEGO, CA 92106 FOR: THE UTILITY REFORM NETWORK (TURN) FOR: NUVVE CORPORATION
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)
Page 1 of 10CPUC - Service Lists - R1707007
2/1/2019https://ia.cpuc.ca.gov/servicelists/R1707007_84620.htm
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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)
SERJ BERELSON IVAN R. JIMENEZ MGR - REGULATORY STRATEGY REGULATORY ATTORNEY SUNVERGE ENERGY, INC. SMALL BUSINESS UTILITY ADVOCATES 950 MINNA STREET 548 MARKET STREET, STE. 11200 SAN FRANCISCO, CA 94103 SAN FRANCISCO, CA 94104 FOR: SUNVERGE ENERGY, INC. FOR: SMALL BUSINESS UTILITY ADVOCATES
STACY W. WALTER NICHOLAS CONNELL ATTORNEY SR. MGR - GOV'T AFFAIRS PACIFIC GAS AND ELECTRIC COMPANY ADVANCED MICROGRID SOLUTIONS 77 BEALE STREET, MC B30A 25 STILLMAN STREET, SUITE 200 SAN FRANCISCO, CA 94105 SAN FRANCISCO, CA 94107 FOR: PACIFIC GAS AND ELECTRIC COMPANY FOR: ADVANCED MICROGRID SOLUTIONS (AMS)
BRIAN T. CRAGG JEANNE B. ARMSTRONG ATTORNEY ATTORNEY GOODIN, MACBRIDE, SQUERI & DAY , LLP GOODIN MACBRIDE SQUERI & DAY LLP 505 SANSOME STREET, SUITE 900 505 SANSOME STREET, SUITE 900 SAN FRANCISCO, CA 94111 SAN FRANCISCO, CA 94111 FOR: INDEPENDENT ENERGY PRODUCERS FOR: CALIFORNIA SOLAR & STORAGE ASSOCIATION (IEP) ASSOCIATION F/K/A THE SOLAR ENERGY INDUSTRIES ASSOCIATION (SEIA)
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.
SHERIDAN PAUKER TIM LINDL PARTNER COUNSEL KEYES & FOX, LLP KEYES & FOX LLP 436 14TH STREET, SUITE 1305 436 14TH STREET, STE. 1305 OAKLAND, CA 94612 OAKLAND, CA 94612 FOR: BOSCH BUILDING GRID TECHNOLOGIES FOR: SUNRUN, INC. F/K/A ROBERT BOSCH LLC
ALEX MORRIS GREGORY MORRIS SR. DIR., POLICY & REGULATORY AFFAIRS DIRECTOR CALIFORNIA ENERGY STORAGE ALLIANCE GREEN POWER INSTITUTE 2150 ALLSTON WAY, SUITE 210 2039 SHATTUCK AVENUE, STE 402 BERKELEY, CA 94704 BERKELEY, CA 94704 FOR: CALIFORNIA ENERGY STORAGE ALLIANCE FOR: GREEN POWER INSTITUTE (CESA)
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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
Information Only
BRIAN THEAKER DENISE GRAB DIR - REGULATORY AFFAIRS ATTORNEY NRG ENERGY, INC. - WEST INSTITUTE FOR POLICY INTEGRITY EMAIL ONLY EMAIL ONLY EMAIL ONLY, CA 00000 EMAIL ONLY, NY 00000
DINA ABDULHADI DONALD LIDDELL POLICY ASSOCIATE DOUGLASS & LIDDELL INSTITUTE FOR POLICY INTEGRITY EMAIL ONLY EMAIL ONLY EMAIL ONLY, CA 00000 EMAIL ONLY, NY 00000
ELLIS MAXWELL ERNST JOHN W. LESLIE, ESQ PACIFIC GAS AND ELECTRIC COMPANY PARTNER EMAIL ONLY DENTONS US LLP EMAIL ONLY, CA 00000 EMAIL ONLY EMAIL ONLY, CA 00000
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
MATTHEW PLUMMER MEGHA LAKHCHAURA STATE AGENCY REGULATIONS SUNRUN, INC. PACIFIC GAS AND ELECTRIC COMPANY EMAIL ONLY EMAIL ONLY EMAIL ONLY, CA 00000 EMAIL ONLY, CA 00000
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NADIM VIRANI REGULATORY CLERK PACIFIC GAS AND ELECTRIC COMPANY BRAUN BLAISING SMITH WYNNE, PC EMAIL ONLY EMAIL ONLY EMAIL ONLY, CA 00000 EMAIL ONLY, CA 00000
RICK UMOFF SAM SCHABACKER COUNSEL & DIR - STATE AFFAIRS POLICY MANAGER SOLAR ENERGY INDUSTRIES ASSOCIATION BLOOM ENERGY EMAIL ONLY EMAIL ONLY EMAIL ONLY, CA 00000 EMAIL ONLY, CA 00000
STEVEN RYMSHA TIM MASON DIR - GRID SOLUTIONS, PUBLIC POLICY POLICY DIRECTOR SUNRUN INC. LARGE-SCALE SOLAR ASSOCIATION EMAIL ONLY EMAIL ONLY EMAIL ONLY, AA 00000 EMAIL ONLY, CA 00000
MRW & ASSOCIATES LLC BRIAN LYDIC EMAIL ONLY INTERSTATE RENEWABLE ENERGY COUNCIL, INC EMAIL ONLY, CA 00000 PO BOX 1156 LATHAM, NY 12110
LON W. HOUSE BRANDON SMITHWOOD ENERGY ADVISOR MGR. - CALIF. STATE AFFAIRS ASSOCIATION OF CALIFORNIA WATER AGENCIES SOLAR ENERGY INDUSTRIES ASSOCIATION 10645 N. ORACLE RD., STE. 121-126 EMAIL ONLY ORO VALLEY, AZ 85737-9615 EMAIL ONLY, CA 90000
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
JESSALYN ISHIGO BRADLEY BARTZ ENVIRONMENTAL BUS. DEVELOPMENT OFF. PRESIDENT AMERICAN HONDA MOTOR, CO., INC. ABC SOLAR INCORPORATED 1919 TORRANCE BLVD. 24454 HAWTHORNE BLVD. TORRANCE, CA 90501 TORRANCE, CA 90505 FOR: AMERICAN HONDA MOTOR, CO., INC. FOR: ABC SOLAR INCORPORATED
FRED G. YANNEY GREGORY KLATT ATTORNEY DOUGLASS & LIDDELL YANNEY LAW OFFICE 411 E. HUNTINGTON DRIVE, NO. 107-356
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17409 MARQUARDT AVE. UNIT C-4 ARCADIA, CA 91006 CERRITOS, CA 90703 FOR: GOLDEN STATE WATER COMAPNY ON BEHALF OF BEAR VALLEY ELECTRIC SERVICE (BEAR VALLEY OR BVES)
DANIEL W. DOUGLASS ALEXA J. MULLARKY DOUGLASS & LIDDELL ATTORNEY 4766 PARK GRANADA, STE. 209 SOUTHERN CALIFORNIA EDISON COMPANY CALABASAS, CA 91302 2244 WALNUT GROVE AVENUE / BOX 800 FOR: WESTERN POWER TRADING FORUM ROSEMEAD, CA 91770
CASE ADMINISTRATION GARY STERN SOUTHERN CALIFORNIA EDISON COMPANY MANAGING DIR. 8631 RUSH STREET, GO4, 2ND FL. SOUTHERN CALIFORNIA EDISON COMPANY ROSEMEAD, CA 91770 8631 RUSH STREET ROSEMEAD, CA 91770
KATHRYN ENRIGHT NGUYEN QUAN SOUTHERN CALIFORNIA EDISON COMPANY MGR - REGULATORY AFFAIRS 2244 WALNUT GROVE AVENUE BEAR VALLEY ELECTRIC SERVICE ROSEMEAD, CA 91770 630 E. FOOTHILL BLVD. SAN DIMAS, CA 91773 FOR: BEAR VALLEY ELECTRIC SERVICE (GOLDEN STATE WATER COMPANY)
JOSH GERBER JOSEPH M. MCCAWLEY FOUNDER & PRINCIPAL REGULATORY CASE MGR. 33 NORTH ENERGY LLC SAN DIEGO GAS & ELECTRIC COMPANY 1050 HYGEIA AVE., NO. A1 8330 CENTURY PARK COURT, CP32F ENCINITAS, CA 92024 SAN DIEGO, CA 92123
CLAY FABER PAUL MARCONI DIR - REGULATORY AFFAIRS DIR SAN DIEGO GAS & ELECTRIC COMPANY BEAR VALLEY ELECTRIC SERVICE 8330 CENTURY PARK CT., CP32D 42020 GARSTIN DRIVE, PO BOX 1547 SAN DIEGO, CA 92123-1530 BIG BEAR LAKE, CA 92315 FOR: SAN DIEGO GAS & ELECTRIC COMPANY
JEFF HIRSCH MICHAEL BROWN JAMES J. HIRSCH & ASSOCIATES CONSULTANT 12185 PRESILLA ROAD LAW OFFICE OF MICHAEL BROWN SANTA ROSA VALLEY, CA 93012-9243 1712 19TH STREET, STE. 215 BAKERSFIELD, CA 93301 FOR: SMALL BUSINESS UTILITY ADVOCATES (SBUA)
ANDREW YIP JEREMY WAEN DIRECTOR - BUSINESS DEVELOPMENT MGR. - REGULATORY AFFAIRS BOSCH BUILDING GRID TECHNOLOGIES PENINSULA CLEAN ENERGY 101 JEFFERSON DRIVE 2075 WOODSIDE RD. MENLO PARK, CA 94025 REDWOOD CITY, CA 94061
MARC MONBOUQUETTE ALIA SCHOEN
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SR.MGR - REG & GOV'T AFFAIRS PUBLIC POLICY MANAGER EMOTORWERKS BLOOMENERGY 846 BRANSTEN ROAD 1299 ORLEANS DRIVE SAN CARLOS, CA 94070 SUNNYVALE, CA 94089
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.
JOSE ALIAGA-CARO JUSTIN H. FONG CALIF PUBLIC UTILITIES COMMISSION CALIF PUBLIC UTILITIES COMMISSION INFRASTRUCTURE PLANNING AND PERMITTING B TRANSPORTATION ENFORCEMENT BRANCH AREA AREA 505 VAN NESS AVENUE 505 VAN NESS AVENUE SAN FRANCISCO, CA 94102-3214 SAN FRANCISCO, CA 94102-3214
VALERIE KAO MARCEL HAWIGER CALIF PUBLIC UTILITIES COMMISSION STAFF ATTORNEY DIVISION OF ADMINISTRATIVE LAW JUDGES THE UTILITY REFORM NETWORK ROOM 5005 785 MARKET ST., STE. 1400 505 VAN NESS AVENUE SAN FRANCISCO, CA 94103 SAN FRANCISCO, CA 94102-3214 FOR: THE UTILITY REFORM NETWORK (TURN)
JAMES BIRKELUND AMARA HAYASHIDA PRESIDENT & GEN. COUNSEL CASE MGR. - REGULATORY AFFAIRS SMALL BUSINESS UTILITY ADVOCATES PACIFIC GAS AND ELECTRIC COMPANY 548 MARKET STREET, STE 11200 77 BEALE STREET, B23 SAN FRANCISCO, CA 94104 SAN FRANCISCO, CA 94105 FOR: SMALL BUSINESS UTILITY ADVOCATES
HAROLD HIRSCH JOSEPHINE WU PACIFIC GAS AND ELECTRIC COMPANY CASE COORDINATOR 245 MARKET STREET PACIFIC GAS AND ELECTRIC COMPANY SAN FRANCISCO, CA 94105 77 BEALE STREET, MC B9A, RM 2364B SAN FRANCISCO, CA 94105
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
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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
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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
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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
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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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