Executive Summary€¦ · Web viewIn August 2014, the Commission began implementation of this requirement through Rulemaking (R.) 14-08-013, the Distribution Resource Planning proceeding

Distribution Resources Plan Rulemaking (R. 14-08-013)Locational Net Benefit Analysis Working Group

DRAFT Final Report – Due March 8, 2017 (request for extension)

Table of Contents

1 Executive Summary.............................................................................................................................1

2 Introduction and Background..............................................................................................................2

2.1 LNBA Demonstrations.................................................................................................................3

2.2 LNBA Working Group Role..........................................................................................................6

2.3 WG Meetings and Topics Discussed............................................................................................6

2.4 Categories of Recommendations.................................................................................................6

3 Discussion and Recommendations: Principles, Use Cases, Regulatory Process...................................9

3.1 Demo B projects have been completed as required....................................................................9

3.2 Draft principles for applying LNBA.............................................................................................10

3.3 Use Cases...................................................................................................................................12

3.4 Regulatory Process Recommendations.....................................................................................16

4 Discussion and Recommendations: Modifications to the LNBA Tool................................................18

4.1 Bulk System Benefits: Refinements to existing LNBA Value Types............................................18

4.1.1 Replace System Values with Local Values......................................................................18

4.1.2 Avoided transmission capital and operating expenditures............................................20

4.2 LNBA Tool Functionality: improving the heat map and spreadsheet tool, and incorporating complex DER Solutions......................................................................................................................23

4.2.1 Tool, Heatmap, and Presentation of Information..........................................................24

4.2.2 Accommodating Complexity in DER solutions................................................................25

4.3 Distribution Benefits: Analytical Scope, Additional Benefits, and Uncertainty..........................30

4.3.1 Analytical Scope.............................................................................................................30

4.3.2 Additional Benefits.........................................................................................................32

4.3.3 Uncertainty in the Distribution Planning Process...........................................................39

5 Appendix...........................................................................................................................................42

5.1 Parties Participating in the Working Group...............................................................................42

5.2 Acronyms...................................................................................................................................43

5.3 List of WG meeting Dates and topics covered...........................................................................43

5.4 Summary of all Recommendations............................................................................................45

1 Executive Summary[Note: This executive summary will need expansion/edits. To be addressed once the body is done.]

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Assembly Bill 327 (Perea 2013) established Section 769 of the California Public Utilities Code, which requires the Investor Owned Utilities (IOUs) to prepare a distribution resources plans thatidentify optimal locations for the deployment of distributed energy resources. In August 2014, the Commission began implementation of this requirement through Rulemaking (R.) 14-08-013, the Distribution Resource Planning proceeding. A Ruling from the Assigned Commissioner in November 2014 introduced the LNBA as a methodology which would specify the net benefits that DERs could provide in a given location. Further guidance issued in May 2016 authorized a demonstration project to perform LNBA methodology for one DPA.

Pacific Gas & Electric, Southern California Edison, and San Diego Gas and Electric submitted their final Demo B reports at the end of December 2016. These reports summarize demo results, lessons learned, and recommendations on methodology calculation and next steps regarding implementation of LNBA.

The purpose of the Locational Net Benefit Analysis (LNBA) Working Group (WG) Final Report is to summarize recommendations made by the WG since the California Public Utilities Commission (CPUC) issued its May 2, 2016 Assigned Commissioner’s Ruling (ACR) within the Distribution Resources Plan (DRP) proceeding, provide support to the CPUC to make a Proposed Decision on Demonstration B, and assist the Commission in developing a roadmap to outline an implementation plan for an LNBA system-wide rollout, as well as to identify methodological refinements needed to enhance the LNBA to meet additional future use cases. This report summarizes WG recommendations based on three criteria: 1) immediate priority based on relevance for existing use cases, and within the scope of short-term WG activities; 2) long-term refinement items prioritized for developing new methodology; and 3) additional refinements related to the development of additional use cases, in coordination with related CPUC proceedings (including the Integration of Distributed Energy Resources (IDER) proceeding (R 14-10-003), NEM 3.0, and the Integrated Resources Planning (IRP) process).

note: will fill in as recommendations are finalized.

WG Discussions have been facilitated by More than Smart, and the LNBA WG has met at least once per month, starting May 2016. It is expected to maintain this meeting frequency through Q2 2017. Meetings have been in person or via webinar and conference call (see Appendix).

2 Introduction and BackgroundThe genesis of the locational net benefit analysis is Assembly Bill (AB) 327 of 2014, which added section 769(b) to the California Public Utilities Code, requiring each California Investor Owned Utility (IOU) to submit a distribution resources plan proposal “to identify optimal locations for the deployment of distributed resources…” using an evaluation of “locational benefits and costs of distributed resources located on the distribution system” based on savings distributed energy resources1 provide to the electric grid or costs to utility customers.

1 Per AB 327, DERs includes distribution-connected energy efficiency, energy storage, distributed generation, demand response, and electric vehicles.

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Brandon Smithwood, 02/17/17,

Splitting hairs here, but I think this will be an important distinction in the spring. Originally the IOUs were not going to have a tool- they were going to do proprietary analyses. It was only in the ACR this spring that the Commission said they needed to create a spreadsheet.



Locational Net Benefit Analysis (LNBA), which evaluates DERs’ benefits at specific locations is one of several new analytical methods needed to achieve the future envisioned in the DRP - one where DERs are deployed at optimal locations, times, and quantities so that their benefits to the grid are maximized and utility customer costs are reduced.

In a May 2, 2016 ruling,2 the PUC directed the IOUs to demonstrate LNBA methods – in particular, methods to quantify DER benefits to the transmission and distribution (T&D) system – at a high level of granularity. This LNBA WG report provides recommendations on LNBA in response to the completion of that demonstration (Demo B) in order to inform a future Commission Decision on further evolution of LNBA. In accordance with the May 2, 2016 ACR in the DRP proceeding3 (R-14-08-013), the LNBA Working Group was established to monitor and provide consultation to the Investor Owned Utilities (IOUs) on the execution of Demonstration Project B and further refinements to LNBA methodology. CPUC Energy Division staff has oversight responsibility of the WG, but it is currently managed by the utilities and interested stakeholders on an interim basis. The utilities jointly engaged More Than Smart to facilitate the WG. The Energy Division may at its discretion assume direct management of the working group or appoint a working group manager4.

2.1 LNBA Demonstrations The May 2, ACR approved an LNBA methodology framework for Demo B, instructed the IOUs to apply the LNBA methodologies to one or more Distribution Planning Area(s) (DPAs), and directed the IOUs to submit a final report and results by the end of 2016.5 The table below from the May 2, ACR lists the components of the LNBA as defined for Demo B, and, for each, indicates a basic or “primary” LNBA methodology as well as a more complex “secondary” option.6

2 Available here: http://docs.cpuc.ca.gov/SearchRes.aspx?docformat=ALL&docid=161474143 3 A modified ACR was granted on August 23 to modify specific portions of the May 2, 2016 ACR. http://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M166/K271/166271389.PDF4 ACR R-14-08-013 Section 6: “LNBA Working Group”5 Ibid, at pp. 25-34.6 ibid, at pp. A26-A27.

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http://docs.cpuc.ca.gov/SearchRes.aspx?docformat=ALL&docid=161474143



2.1.1.1Table 1: Demo B LNBA Components

The T&D avoided costs, highlighted in the ACR table above, are the central focus of Demo B, since they are the LNBA component most sensitive to location.7 Most non-T&D components of the LNBA in Demo B are borrowed from the existing DER Avoided Cost calculator or DERAC 8 or are expansions upon the DERAC in the case of flexible and local RA and renewable integration cost. These non-T&D components are sometimes collectively referred to as system-level avoided costs.

Each IOU followed the high-level process below in applying the commission guidance in the LNBA demonstration projects:

7 Note that Table 2 of the ACR does not include DER costs – either the cost to procure or the cost to interconnect – as a LNBA component in Demo B, so the LNBA in Demo B is not a full net benefit analysis.8 https://ethree.com/public_projects/cpuc4.php

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1. Select one or more DPAs that include “one near-term and one longer-term distribution infrastructure project for possible deferral”9 and “at least one voltage support/power quality- or reliability/resiliency-related deferral opportunity in addition to one or more capacity-related opportunities;”10

2. Identify, for every location in the selected DPA(s), “the full range of electric services that result in avoided costs” including “any and all electrical services associated with distribution grid upgrades identified in (i) the utility distribution planning process, (ii) circuit reliability improvement process and (iii) maintenance process;”11

3. Prepare, for each location with an identified upgrade, a location-specific service specification, identify capabilities that are required of incremental DERs to provide that service;

4. Compute, for each location, a project deferral avoided cost that could be attributed to incremental DERs that meet the required capabilities and apply the approved LNBA methodology to calculate LNBA results;

5. Execute these steps under two different distribution planning DER growth scenarios: (a) the Utilities’ base distribution planning scenario and (b) the Very High scenario as filed in the July 2015 DRPs;

6. Make the results available via a heat map along with the DER growth scenario data on the Integration Capacity Analysis map;

7. Provide access to software and data used in Demo B and coordinate with the LNBA Working Group in monthly meetings and to coordinate with the Integrated Distributed Energy Resources (IDER) proceeding

The IOUs, in consultation with the LNBA WG, adopted the IDER Competitive Solicitation Framework Working Group’s (CSFWG’s) final consensus list of distribution services that DERs can potentially provide. The IOUs also, with help from a consultant, developed a public LNBA Tool which was used to calculate a total avoided cost for all locations within each DPA, including T&D upgrade deferral avoided cost for locations with a deferrable upgrade (i.e. an upgrade providing one of the services identified by the CSFWG. This LNBA Tool is based on the May 2, 2016 ACR’s “primary” LNBA methodology framework described above; however, the LNBA Tool is designed to easily incorporate many refinements, including several that are reflected in the secondary analysis.

The IOUs also jointly designed their heat maps that provide a visual depiction of Demo B’s LNBA results. Each feeder is color coded to provide indicative LNBA results according to the following key:

2.1.1.2Table 2: Demo B LNBA Results Heat Map key$ Indicates only system-level avoided costs and no T&D deferral value

$$ Indicates system-level avoided costs plus 0 to < 100 $/kW deferral value$$$ Indicates system-level avoided costs plus 100 to < 500 $/kW deferral value

$$$$ Indicates system-level avoided costs plus > 500 $/kW deferral value

Further information, including a downloadable version of each IOUs’ Demo B final report and links to the public tool and heat maps are available at More Than Smart’s DRP Working Group website.12

9 ibid, at pp. A25.10 ibid, at pp. A25.11 ibid, at pp. 28.12 Located here: http://drpwg.org/sample-page/drp/

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http://drpwg.org/sample-page/drp/



2.2 LNBA Working Group RoleThe activities of the WG are organized by (I) short-term work related to the Demonstration Project B and improvements to LNBA that could be adopted in a Q1 2017 Decision and (II) longer-term work related to ongoing refinements to LNBA methodology beyond that time frame conducted in parallel, but not directly related, to the Demonstration B. Short term work should be addressed by the time of the submittal of the final Demonstration B report.

The aforementioned short-term work of the WG is defined in the ACR under Section 6.1:

6.1 Activity related to Demonstration Project Ba. Recommend a format for the LNBA maps to be consistent and readable to all California

stakeholders across the utilities’ service territories with similar data and visual aspects (color coding, mapping tools etc.).

b. Consult to the IOUs on further definition of grid service, as described in requirement (1)(B)(iv-v) of Section 4.3.1 above, and in coordination with IDER proceeding.

The WG and IOUs met monthly throughout the Demo B process: major decisions (e.g. adoption of the CSFWG service definitions) were made in consultation with the WG and WG feedback was incorporated into the design of the LNBA tool and heat maps. In particular, the LNBA WG expressed strong support for using technology-agnostic approaches to evaluating location-specific benefits in Demo B. The methods and tools reflected in this Demo B are therefore designed, to the maximum extent possible, to easily evaluate any DER or combination of DERs. In addition to these specific tasks, the Ruling directed the WG to “improve and refine the LNBA methodology.” (p. 35) The WG explored many aspects of the methodology and sets forth recommendations below.

2.3 WG Meetings and Topics DiscussedThe LNBA WG met over the following meeting dates to discuss proposed methodology for Demonstration B and review final Demo B reports. The WG launched on May 12, 2016, and included a total of 16 meetings over 10 months, with the final meeting occurring on February XX. The WG discussed a number of different topics relating to both the implementation of Demo B as well as long-term refinements to LNBA. The following represents a partial list of topics: Demo Implementation plans, use cases, DER grid services, presentation of data and maps, calculation of avoided transmission costs, data access issues, uncertainty in the planning process, smart inverter capabilities, alternatives to the avoided cost method, DERs working in concert, and the results of the Demonstration projects.

A full summary of WG documents including meeting dates, topics, agendas, presentation slides, and participant lists may be found in the Appendix.

2.4 Categories of RecommendationsThe WG collectively developed a list of recommendations from multiple organizations at the January 20 WG meeting.

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Laura Wang, 02/21/17,

From: CALSEIA



List of recommendations

[Note for reviewers of this draft: IOUs marked recommendations with an asterisk (*) that are already implemented in the current tool. These recommendations should be deleted or modified to clearly indicate what tool modification they are seeking.]

Recommendation Consensus Status3 Principles, Use Cases, Regulatory Process3.1 Demo B projects have been completed as required

IOU Demo B Projects Satisfy all CPUC Requirements Consensus??3.2 Future use cases considering locational value for resource

valuation: draft principles Adopt Guiding Principles Non-Consensus

3.3 Use CasesApprove LNBA Tool with Refinements for 2 proposed applications

Non-Consensus

Refine tool to support future sourcing options Consensus??Focus on use cases that can use “indicative values” ?

3.4 Regulatory Process RecommendationsDeferral Framework adoption prior to LNBA implementation

Consensus??

Opportunity to comment on Scope, Schedule, Budget ??4 Modifications to the LNBA Tool4.1 Bulk System Benefits: Refinements to existing LNBA Value

Types4.1.1 Replace System Values with Local Values

Develop locational specific avoided cost values for energy and capacity

Non-Consensus – clarification of wording needed

Develop locational line losses Non-Consensus4.1.2 Avoided transmission capital and operating expenditures

The broader cost-effectiveness framework should include a system-wide transmission value

??

Avoided transmission cost should be based on CAISO transmission revenue requirement

Non-Consensus

Initial development of the transmission avoided cost methodology should focus on specific areas/networks

Non-consensus -clarification of wording needed

Inclusion of non-deferral benefits to the avoided transmission cost methodology

Non-consensus

Develop an enhanced/additional power flow analysis tool with CAISO to determine load reductions required to achieve transmission project deferral

Non-consensus

4.2 LNBA Tool Functionality: improving the heat map and

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David, 02/21/17,

Note: There is also a more detailed summary table included at the end of the document as an appendix. If desired, that table could be used here instead of this simple summary.Either way, this Table will need to be updated and completed once all recommendations have been finished.



incorporating complex DER Solutions4.2.1 Tool, Heatmap, and Presentation of Information

Modify the Tool to Use in Planning Process ??Heat Map Granularity* ??Heat Map May Indicate Certainty of Investment ??

4.2.2 Accommodating Complexity in DER solutionsAllow Partial Deferral Value Non-ConsensusAllow multiple locations / multiple projects. ConsensusAllow multiple years of deferral*Value deferral beyond 10 years ??Include Data for Reactive Power Service Needed ConsensusDeferring Multiple Planned Upgrades* ?? Consensus??Further Work on Dependability Factor Non-ConsensusUse more than just peak hour when determining when load reductions can avoid capacity upgrades

Consensus??

4.3 Distribution Benefits: Analytical Scope, Additional Benefits, and Uncertainty

4.3.1 Analytical ScopeIncluding Cost of DER Penetration Non-ConsensusUse Base Growth Scenario Only Consensus (plus scope Q)Clarify Renewable Integration Cost Non-Consensus

4.3.2 Additional BenefitsOnly include benefits that reduce utility revenue requirement

Non-Consensus

T&D values to be included in future modifications LNBA Tool should only reflect values with established quantification

Non-Consensus

Modify Voltage SupportAsset life extension Non-ConsensusSituational awareness or intelligence Non-ConsensusIncreased reliability (non-capacity related): Non-ConsensusEvaluating Planned Upgrades Meant to Accommodate Additional DER Growth

Non-Consensus

Avoiding Maintenance Projects Non-ConsensusDownsizing Equipment Upgrades Non-ConsensusT&D benefit beyond 10 year planning horizon Non-Consensus

4.3.3 Uncertainty in the Distribution Planning ProcessExamine methods to reduce uncertainty in planning an utility investment

Non-Consensus

Incorporate an uncertainty metric in the LNBA tool (for planned projects)

??

Develop a methodology to incorporate projects that may occur unexpectedly (i.e. unplanned projects)

Consensus??

Allow projects that are multiple years in the future to be deferrable*

??

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Can CALSEIA clarify this one?



Each recommendation is presented in a consistent table format, with information as follows.

Recommendation Short name of recommendationConsensus? Consensus or non-consensusAction type Three possible Categories:

CPUC Policy Guidance: WG recommends CPUC clarify policy to govern use/application/implementation of LNBA

IOUs to implement modification: WG Recommends IOUs implement modification to the functionality, scope, methodology of the tool.

WG to analyze further: WG has identified a potential modification to the tool, but further research/analysis is necessary before a final determination can be made of how/if such a modification should be implemented

Priority High, Medium, or Low. Note that priority is not necessarily correlated with the expected time to implement a recommendation

Time Required Duration of time to implement a recommendation from the time work begins on the recommendation. Ranges in value from “N/A” for policy guidance that can be resolved immediately, to greater than 2 years for concepts that require significant analytical study to better understand.

Description Simple description of what the recommendation is seekingSupporting Arguments Arguments in favor of the recommendationOpposing Arguments Arguments against the recommendation

3 Discussion and Recommendations: Principles, Use Cases, Regulatory Process

OverviewThis section compiles general comments about the use of LNBA and recommendations for how work on LNBA should progress. In contrast with other categories, these recommendations are not concrete methodological improvements.

3.1 Demo B projects have been completed as requiredObjectiveThis section expresses the WG consensus that IOU Demo B implementations are fully compliant all requirements as set forth in the May 2nd and August 19th Assigned Commissioners Rulings.

DiscussionParties have many diverse recommendations and expectations for how the LNBA should be developed and refined prior to further implementation. However, parties recognize and agree that the LNBA as implemented in each IOU Demo B project is consistent with the specific CPUC requirements for the

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Demos. These requirements were primarily established in an Assigned Commissioners Ruling dated May 2, 2016, with some minor changes implemented through an Assigned Commissioner’s Ruling Dated August 19.

Recommendation IOU Demo B Projects Satisfy all CPUC RequirementsConsensus? ConsensusAction type CPUC PolicyPriority HighTime Required N/ADescription The WG recommends that the CPUC formally recognize that IOU Demo B

projects and reports are fully compliant with CPUC directives and requirements as set forth in the May 2nd and August 23rd ACRs, within the context of evaluating DERs in locations against planned utility upgrade projects.

Supporting Arguments See IOU Demo B Final Reports for complete explanation of how each project and report complies with the requirements.

Opposing Arguments None

3.2 Draft principles for applying LNBA

ObjectiveThe LNBA working group has struggled with recommendations to develop or improve LNBA methodologies without a concrete understanding of how LNBA might be used – especially for DER sourcing mechanisms. This section attempts to provide some clarity regarding how LNBA could be used by compiling recommendations from individual participants.

Discussion

As identified above in the Summary and detailed in section 3.3 below, a set of use cases exist which envision the LNBA methodology used to source DERs outside of the competitive solicitation process (e.g., using tariffs and incentive mechanisms). As the WG continues to refine methodology to meet the identified future use cases, the following draft principles for developing a more granular framework for assigning T&D benefits are proposed:

1. DER sourcing mechanisms using granular T&D benefits must have specific requirements that match needed quantities, hours and locations to capture those benefits. Mechanisms should require that DERs meet or exceed the specific needs. Location-specific incentives or other signals must be incorporated into the design of tariffs/programs that are assigned quantitative T&D benefits. It's not sufficient to simply improve the locational granularity of the cost-effectiveness analysis without a feedback to the way a tariff/program operates. If the requirements aren't met, no benefits should be assigned.

2. DERs must be dependable and their performance validated. DER deployments for T&D services via tariffs/programs should include M&V to evaluate how dependable DERs are, and those analyses should result in a dependability factor that is incorporated quantitatively in those

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CALSEIA



tariffs/programs to ensure that the identified needs are met (e.g. if back-up resources are required, the associated cost should be included).

3. Avoided costs cannot be realized twice. Utility customers should not pay twice for the same thing through tariffs/programs. An average T&D benefit should not be based on the same T&D projects and costs that underpin a locational T&D benefit. T&D costs which are avoidable through granular T&D-based tariffs/programs or direct procurement are not also avoidable through generic T&D-based tariffs/programs. Preferably, tariffs/programs should use either an average or a locational T&D benefit, but not both

4. Reduce cost shifts and base benefits on known avoided costs. Locational tariffs/programs should take a least-cost, best-fit approach across all options and should account for existing, embedded cost-shifts.

5. DER sourcing mechanisms should send cost signals as well as benefit signals. Where participating DERs cause increased cost that can easily be avoided, negative signals (e.g. penalties) should be sent. Additional incentives to participating DERs that don't cause those costs should be avoided. To wit: No extra compensation to a participant for avoiding a problem they are causing.

6. DER sourcing mechanisms should seek to reduce cost to utility customers. Granular T&D tariffs/programs providing incentives based on T&D benefits should provide incentives needed to get the adoption required to capture the benefit and no more, and should always be capped at the avoided cost. Non-financial mechanisms to signal locations with T&D benefits should be considered first as a least-cost option. If adoption before a T&D benefit-based incentive is sufficient to deliver that benefit, no additional incentive is appropriate unless some new operating behavior is required.

7. Use the latest information about grid needs to source DERs. The distribution system's needs are dynamic, and using out-of-date information will likely result in utility customers paying for nonexistent benefits.o Incentive mechanisms should not be created based on avoided costs that can’t or won’t

actually be avoided o Sourcing mechanisms should be developed based on needed quantities, and consider how

they fit with or replace other incentives (NEM, SGIP, etc.) o Comment about LNBA data?

Recommendations

Recommendation Adopt Guiding PrinciplesConsensus? Non-consensusAction type CPUC PolicyPriority HighTime Required N/ADescription CPUC should adopt a set of guiding principles (based on the list above) to

help inform policy decisions across the multiple proceedings and tracks where locational values may potentially inform planning and/or procurement.

Supporting Arguments Rulings and Decisions in a number of different proceedings refer to the DRP with the expectation of using locational values for some purpose. However, it is frequently unclear exactly what those values are expected

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Monday 2/27 webinar


Reminder: we are hosting a webinar on this topic on Monday, 3/27 so comments on this entire section are due following the webinar.

Plano, Larsen, 02/21/17,

IOUs attempted to capture these in the 7 principles above.

Laura Wang [2], 02/21/17,

From TURN and combined here into principles

Laura Wang [2], 02/21/17,

From TURN and combined here into principles



to represent, and how they are expected to be used. While the specific purpose may vary from proceeding to proceeding, these principles will help inform future activities across proceedings.

Opposing Arguments SEIA: I strongly disagree with this. We have valued the ability of DERs to avoid T&D investments for years and they have demonstrably done so. In making the determination of this value more granular and location-specific we must be sure that we don’t artificially limit the value with a false premise that only deferring projects identified today

3.3 Use Cases ObjectiveThis section provides commentary on potential use cases for the LNBA.

Discussion

In completing the short-term activities, the IOUs developed an LNBA tool through Demonstration B in coordination and consultation with the LNBA Working Group. Working Group members have been presented with the following set of applications for the LNBA:

1. LNBA Public Tool to provide public information: LNBA provide a heat map and data that customers and DER providers can use to identify potential optimal locations for deploying DER, along with detailed information about the required attributes necessary to achieve deferral value. The objective of Demo B was to meet this use case (Demo B). The final public heat maps are a visual representation (feeder-level) of where DERs can defer or avoid planned utility infrastructure projects (as identified in the Distribution Investment Deferral Framework (DIDF), currently under development in DRP Track 3, sub-track 3). The developed LNBA tool serving this use case employs public data and indicative values to identify locational and system-level deferral benefits, in addition to specific identified project deferral value where applicable. The tool is technology-agnostic, and users may input a DER-specific profile to receive technology-specific estimates of the avoided cost, or net benefit, that their DER project would provide. Data available in the LNBA tool showing hourly load reduction needed in a given location to defer a planned upgrade may help developers create DER solutions that are designed specifically to defer or eliminate planned investments.

2. Prioritizing DER deferral opportunities: Components of the LNBA methodology may be used to develop a prioritization of DER deferral opportunities by utilities. Specifically, the analysis of T&D benefits that drives the LNBA tool relative to the magnitude and duration of required electrical characteristics to achieve cost deferral may be useful in prioritizing deferral opportunities. This prioritization process is a step in the Deferral Framework as proposed by the IOUs in the Deferral Framework Workshop (organized by CPUC as part of Track 3, sub-track 3. As with other steps in the Deferral Framework, the prioritization process would be reviewed with the

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SEIA:This is the only use case that seems time sensitive to me as we have these pilots coming up in the next few months. 1) Do the utilities acutally plan to use the tool in this way in these pilots?; 2) could we use the LNBA, with initial modificaitons, for these pilots but with the recognition that this methodology is interim?


SEIA:Beyond being intellectually interesting I struggle with what the practical value of this use case is.


SEIA: We did? Also, besides from #2 I don’t see any of these as being “near term”. Looking at the DER Action Plan



Distribution Planning (or Deferral) Advisory Group (DPAG or DDAG), a proposed stakeholder group in the DIDF that would provide feedback and advise the selection of deferral opportunities for solicitation via the Competitive Solicitation Framework (developed in the IDER proceeding. Note that not all components of the tool would be used in this process. For example, components of the tool based on DERAC values will not be used in this process. As a proprietary version of the LNBA tool would be used to evaluate bids, it is noted that the LNBA tool may be used to help in prioritization, but will not be used for final assessment. Additionally, the utilities are not planning to “re-run” the tool with alternative market sensitive numbers, as this would be inconsistent with the vision of the LNBA as a public tool, and would be duplicative of existing internal utility activities and analyses. Finally, under no circumstance will be market sensitive information be made public).

Also, the Working Group recommends a new use case that focuses on data needs to support the development of future sourcing options. This would provide the necessary linkage between the LNBA and IDER processes, ensuring informed and effective decisions can be made regarding various potential sourcing options.

More generally, the LNBA is designed as a public tool utilizing public indicative values. It is appropriate to develop future use cases for which public indicative values are appropriate. The tool does not use or provide market-sensitive information, nor does it provide internal data from utilities. The tool should not be used in applications that require internal, actual, market-sensitive values. Not only is this inconsistent with the purpose of the tool, but to modify the tool in this way would cause it to become duplicative of the IOUs’ internal tools.

The development of the LNBA Tool within Demo B represents a major step forward in providing DER developers with data on grid needs and indicative deferral values. However, it is emphasized that the LNBA addresses the narrow question of evaluating DERs in single locations against certain distribution upgrades that are already in IOU distribution system plans, and should not be construed as the advancement of a comprehensive, location-specific utility avoided cost calculator that could be used to proactively identify high-value locations for DER deployment.

Finally, the discussion above highlights the need to have a clear understanding of the connection between the Deferral Framework and LNBA. Both Deferral Framework and LNBA are based upon the same distribution planning activities and analyses. The planning activities include forecasting, needs assessment, and evaluation of conventional alternatives. The Deferral Framework will determine which of those conventional alternatives may potentially be deferred by DER alternatives. The subsequent list of potentially deferrable projects, including the attributed required to achieve the deferral, will drive the LNBA. The LNBA will combine the distribution deferral benefits and requirements with additional benefits related to the bulk system (transmission benefits, capacity benefits, CAISO market benefits.) Thus, the LNBA is an output of the Deferral Framework.

During these meetings, the WG also acknowledged the need for the development of a future LNBA use case in which LNBA develops location-specific avoided cost values for use in cost-effectiveness analyses

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Note – rephrasing to capture the activities ID’d in CPUC memo as ONE future use case rather than multiple


From CALSEIA. Do we still need this, given that language was included in below recommendation on - “refine tool to support future sourcing options”



and DER sourcing activities in related Commission proceedings (beyond those specific to new planning and investment processes under development in the DRP proceeding), as summarized in a recent CPUC Energy Division memo13. These proceedings/initiatives include:

- Integration of Distributed Energy Resources (IDER) proceeding (R. 14-10-003): the IDER identifies that LNBA may be used in the 1) development of a unified cost-effectiveness framework14 that can be used for technology-agnostic resource evaluation, and 2) identification of tariffs, contracts, or other mechanisms for the deployment of cost-effective DERS, and cost-effective methods of effectively coordinating existing Commission-approved programs, incentives, and tariffs to maximize locational benefits and minimize incremental costs of DER resources

- Net Energy Metering 3.0 (D. 16-01-044): the NEM successor tariff decision cited the ongoing work in DRP and IDER to defer significant changes to NEM incentive levels. Development of the NEM successor tariff is expected to consider LNBA-derived locational values

- Integrated Resource Planning: Future cycles of the IRP process post-2018 may utilize locational values as an input to help inform resource net cost estimates

The WG agreed that an additional primary goal of this report is to help the Commission develop a roadmap to work on the additional methodological refinements needed to facilitate the use of LNBA for this use case.

The LNBA WG believes it is important to identify time considerations (that is, which improvements need to be made before future iterations of the tool, within the context of IOU ability to develop and incorporate changes, and with regards to proposed timing of other proceedings), as well as the specific refinements that need to take place to enable the future use case, including the potential development of new methodological approaches, given that the LNBA is envisioned to provide an avoided cost value to indicate high-value locations for DER deployment, inform resource procurement decisions, and develop rates or tariffs for sourcing DERs (outside of identifying deferral opportunities through the competitive solicitation process).

The WG spent significant effort reviewing LNBA methodology in the context of Demo B in 2016, and collectively agree that the LNBA methodology as developed is not yet sufficient to meet this future identified use, and can only do so after addressing the methodological changes in further refinements proposed below, as well as in concert with other CPUC proceedings and initiatives. In general, the WG understands that the near-term applications of the current LNBA methodology are in regards to the Distribution Investment Deferral Framework (pilots?) and in the LNBA tool. This general understanding forms the basis for the proposed prioritization of LNBA recommendations included in this report.

Recommendations13 During the period in which the WG was developing this report, CPUC Staff distributed a Memo to WG members discussing potential future uses of LNBA in other proceedings. The WG did not have time to discuss the memo, and so while certain recommendations in the report may indirectly relate to various items contained in the Memo, the Report does not directly address or respond to the memo, which is available here: http://drpwg.org/wp-content/uploads/2016/07/CPUC-Memo-on-LNBA-Use-Cases-Feb-1-2017-mm7.docx14 R.14-10-003 Order Instituting Rulemaking, October 2, 2014, http://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M116/K116/116116537.PDF, p. 11.

Page 14 of 47


Brad (And others): not sure where to put this comment:“ some WG members believe that LNBA can increase transparency in utility planning. Prioritization of distribution system upgrades is normally done by the utilities in a closed process. LNBA can provide a small amount of visibility into distribution planning.”

http://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M116/K116/116116537.PDF

http://drpwg.org/wp-content/uploads/2016/07/CPUC-Memo-on-LNBA-Use-Cases-Feb-1-2017-mm7.docx



Recommendation Approve LNBA Tool with Refinements for two proposed applicationsConsensus? Non-ConsensusAction type CPUC Policy GuidancePriority HighTime RequiredDescription This would approve the LNBA Tool as developed under Demo B as a

resource for public information, and as one tool for use in selection of projects under the Distribution Investment Deferral Framework (DIDF)

Supporting ArgumentsOpposing Arguments Currently, the LNBA methodology and tool are not sufficiently developed

for full implementation within these two use cases. Additional refinement is required through the WG long-term refinement phase (through Q3 2017). The LNBA as developed (with modest modifications) may be used for pilots in the deferral framework, but limited to that.

Recommendation Refine tool to support future sourcing optionsConsensus? Consensus Action type VariesPriority VariesTime Required VariesBy Q3 2017 WG Long-Term Refinement Report (proposed)Description This would provide the necessary linkage between the LNBA and IDER

processes, ensuring informed and effective decisions can be made regarding various potential sourcing options. One such linkage relates to improving the locational granularity of avoided cost in the IDER cost-effectiveness track. Another linkage relates to other DER sourcing mechanisms that may be developed in the IDER, such as location-specific DER programs or tariffs.

A number of refinements are identified in this report, which will support improving the LNBA tool to inform participants in competitive solicitations, as well as potential future sourcing options such as programs and tariffs.

Evaluation of how well the LNBA tool meets the needs of future applications, and accompanying modifications, should occur in the WG’s long-term refinement phase. For example, the WG may identify several specific examples of sourcing mechanism and evaluate the ability of the LNBA tool to yield values that can determine compensation for different grid services.

Supporting Arguments In order for the LNBA to provide the most value in the utility planning process it will be necessary to clearly understand how the LNBA results will be used in DER sourcing. The type of sourcing option will determine cost visibility for utility planners as well as what timeline and reliability a planner can consider a DER able to provide. All this information will be

Page 15 of 47


From SEIA, proposal on timing


Hi Brad – just noting that your proposal for a future “data” use case ended up here


Suggestion from SEIA to incorporate timing. If there’s not agreement on timing here, I can split this recommendation into 2 – 1) recommend to refine, 2) timeline for refinemnets


From SEIA



critical to insuring the best planning decisions are made.

Until these improvements are made, the tool is not capable of meeting the broader application of LNBA beyond the current Demo B scope.

Opposing Arguments

Recommendation Focus on use cases that can use “indicative values”Consensus? ??Action type CPUC Policy GuidancePriority HighTime Required N/ADescription Future Use Cases should be those applications for which public indicative

values are appropriate and sufficient.

Work on LNBA should focus on refining the “indicative values.” Work on LNBA should not attempt to utilize market-sensitive “actual” values

Supporting Arguments LNBA is a public-facing tool designed to provide information to developers. Using confidential data would mean the results of analysis could no longer be shared with the public.

IOUs already have internal models and other tools to estimate energy, capacity, and AS values. For IOU internal usage, the LNBA tool should not duplicate existing tools IOUs already use.

Opposing Arguments

3.4 Regulatory Process Recommendations ObjectiveThis section includes recommendations on an appropriate regulatory process including various steps that should occur prior to further implementation of the LNBA.

Discussion

Discuss connection and timing in coordination with the Distribution Infrastructure Deferral Framework.

Discuss need to revisit scope, schedule, cost, and get stakeholder input.

Recommendations

Recommendation Deferral Framework adoption prior to LNBA implementation

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Consensus? Consensus (?)Action type CPUC PolicyPriority HighTime Required Based on Track 3 scheduleDescription Prior to system-wide implementation, the Distribution Infrastructure

Deferral Framework (DIDF) envisioned under DRP Track 3 should be adopted

Supporting Arguments Deferral Framework is an internal process likely involving a yet-to-be-created stakeholder advisory group using market-sensitive information to identify deferrable projects. As discussed in the IOU presentation at the Deferral Framework workshop, IOUs plan to use technical screens to identify which projects are deferrable. This process involves internal, confidential information. The output of this process – a list of deferrable projects – will feed into the LNBA.

LNBA will start with the list of deferral projects and attributes, and add in indicative public values, to identify optimal locations for DER deployment. The projects used for LNBA is the same set of projects that is the output of the Deferral Framework. The LNBA will calculate the T&D benefit for each project using indicative values. The LNBA also adds in System-level values from the DERAC tool. These public values are not used in internal processes.

Therefore, CPUC adoption of a deferral framework is necessary so that IOUs have clear direction on which deferrable projects are included within LNBA analysis. Specific deferral screens should be approved by CPUC. It is envisioned that the LNBA will employ the list of deferral projects identified through DIDF and add in indicative public values to identify optimal locations for DER deployment.

Opposing Arguments

Recommendation Opportunity to comment on Scope, Schedule, BudgetConsensus?Action type CPUC Policy GuidancePriority HighTime Required 3-6 mo following other guidanceDescription Prior to system-wide implementation of LNBA, IOUs should submit

proposal with Scope, Schedule, and Budget for parties’ comments.

Supporting Arguments Implementation of Demo B required a significant resource commitment. IOUs do not necessarily have resources available to perform a system-wide version of Demo B.

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Is there a time estimate for development of DIDF? May be helpful to include



There are many questions about modifications to the LNBA. Some of these would significantly reduce the expense of LNBA (e.g., applying the deferral framework before rollout of LNBA for that use) but some changes could potentially increase the scope.

As the future scope is not yet well defined, neither schedule nor budget are well defined or understood.

Prior to further work on the LNBA, parties should have an opportunity to comment on the scope, schedule, and budget for future LNBA implementation, so that modifications can be made if appropriate.

Opposing Arguments

4 Discussion and Recommendations: Modifications to the LNBA Tool

OverviewThis section of the report contains discussions and recommendations relating to modification and refinement of the LNBA tool, including methodological changes, analytical changes, and changes to presentation.

4.1 Bulk System Benefits: Refinements to existing LNBA Value TypesOverviewThis section identifies proposed refinements to two types of existing values:

Certain benefits which use system level values from DERAC Transmission values, which are included in the tool but for which the current methodology

defaults to zero value: These are values to the bulk system, including transmission benefits, capacity benefits, and CAISO market revenues.

4.1.1 Replace System Values with Local Values

Objective: The current LNBA tool uses system-wide values for certain benefits. This section discusses recommendations to replace those system-wide values with more localized values.

Discussion

The ACR identifies both a primary and a secondary analysis option for Demo B’s LNBA methodology. Demo B primarily focused on the transmission and distribution avoided cost component, which

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Proposed language from IOUsMTS - Not sure if this makes sense timing wise, especially with long-term refinements?



considers four primary categories: 1) sub-transmission/substation/feeder level; 2) distribution voltage/power quality; 3) distribution reliability/resiliency; and 4) transmission-level.

While the ACR includes other avoided cost components, Demo B focused on the identified avoided T&D components due to their high variance between specific locations. Other avoided cost components (avoided generation capacity, avoided energy, avoided GHG, avoided RPS, avoided ancillary services) directly use values created under the DERAC tool. The IOUs referred to these components collectively as “system-level avoided costs.”

The WG recommended that additional components of avoided costs, which currently employ system-level values, should incorporate additional locational granularity.

Recommendation

Recommendation Develop locational specific avoided cost values for energy and capacityConsensus? Non-ConsensusAction type IOUs to implement modification to toolPriority HighTime Required 6-12 MonthsDescription Update certain system-wide avoided costs with more locational specific

avoided costs. More specifically, locational avoided costs for energy, capacity should be developed from CAISO LMPs and local RA.

Supporting Arguments The primary level of analysis potentially undervalues projects, as LMPs tend to be higher than system costs owing to congestion and line losses. Also, local resource adequacy values will serve to better capture generation capacity value in constrained areas.

Opposing Arguments It may be useful to first investigate whether there is enough price variability in LMPs or aggregate LMPs to warrant more granular locational values, before building these locational values in LNBA tool.

Recommendation Develop and include location specific line loss informationConsensus? Non-consensusAction type IOUs to implement enhancement to toolPriority MediumTime Required 3 months – 1+ yearDescription Many parties in the WG expressed desire to have the LNBA tool generate

line loss reduction information for any DER being deployed anywhere in the entire system. The IOUs while acknowledging it is possible to generate this information, have argued that the relative value of performing this task is not there as such an undertaking would be comparable to the development of the ICA and the resulting value variations for a DER will be almost negligible.

Supporting Arguments The system average line loss adder used currently is not a genuine

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From TURN recommendations – not a complete consensus rec



reflection of the line losses reductions most DERs will create. Line losses downstream from CAISO nodes raise avoided energy costs above system averages. In order for the LNBA tool to be the more accurate, some enhancement of the line loss calculations will need to occur.

Opposing Arguments The value variations will be very small relative to total project costs. Furthermore the total cost/effort it will require to generate these values is by itself a huge deterrent from pursuing them. The system average values will suffice in accounting for line loss reductions and will tend to slightly overestimate the avoided energy and capacity costs.

As an alternative the IOUS suggest the modification of the public LNBA tool to include a drop down of IOU specific line loss average %s for each of their transmission, distribution primary, and distribution secondary systems so that a user of the public LNBA system level tool can apply the loss reduction factors based on which of these systems they expect the DER to back feed. This will give the user an approximation of the additional energy and capacity values the utilities will value them for. In addition to this, for the internal utility version of the tool the IOUs could perform a calculation(s) via power flow software to calculate the actual line loss reduction achieved by a DER proposing an interconnection based on location specific data (secondary conductor type/length, transformer impedance, adjacent loads, etc.). This will appropriately limit the IOUs calculations to only DERs that are proposed and that the IOUS are performing LNBA for. Furthermore the IOU proposed enhancement could be deployed in months whereas the originally desired all-encompassing line loss reduction calculator could potentially take years to develop at each utility and at great expense to the rate payers .

4.1.2 Avoided transmission capital and operating expenditures

Objective:

This section considers methodological approaches to determining the potential avoided transmission cost that may be achieved through targeted DER deployment.

Discussion:

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The LNBA methodology as demonstrated in the IOU Demo B projects include multiple locationally-specific value components building upon DERAC. For avoided transmission capital and operating expenditures, the ACR guidance specifies that the IOUS shall, to the extent possible, quantify the co-benefit value of ensuring (through targeted, distribution-level DER sourcing) that preferred resources relied upon to meet planning requirements in the CAISO 2015-2016 transmission plan, Section 7.315 materialize as assumed in those locations.

It was concluded that the transmission plan did not identify specific projects that would be required in the absence of preferred resources or associated project costs, or provide information needed to develop DER load reduction requirements. Instead, the LNBA Tool contains a user input for a generic system-wide transmission benefit within Demo B. The value in the field is zero when the LNBA Tool is downloaded, but this does not imply that zero is the correct value or a default value. This is similar to the user input for avoided transmission in, the NEM Successor Tariff public tool (R. 14-07-002). The field was not pre-populated with a value but it was understood that no value should be considered “default,” zero or otherwise. However, the WG agrees that the actual value of DERs in avoiding transmission costs is non-zero. Marginal transmission costs have been estimated in the past through prior IOU GRCs,16 and distributed solar studies17 18.

The WG has placed high priority for determining a non-zero transmission benefit value as a long-term refinement item. To develop this value, the WG will focus on 1) understanding the shortfalls of the transmission system capability associated with the distribution facilities being analyzed; 2) developing a potential methodology for inclusion, 3) testing the functionality of the methodology within the LNBA tool; 4) ensuring that any avoided cost value adopted reflects the ability to actually avoid transmission cost in the near or long-term; and 5) coordinating with and understanding how CAISO’s transmission planning process reflects contribution of DERs to avoid or defer actual transmission investment.

The following recommendations are suggested starting points and considerations for methodology development.

Recommendations

Recommendation Tthe broader cost-effectiveness framework should include a system-wide transmission value.

Consensus?Action typePriorityTime Required

15 https://www.caiso.com/Documents/Draft2015-2016TransmissionPlan.pdf. See pp 333-337 for a complete list of specific locations.16 SCE’s 2011 recent GRC (A. 11-06-007) shows a marginal cost for CAISO-controlled transmission of $59.18 per kW-year (2012 $). See A.11-06-007, SCE Workpapers, “MCCR” sheet, “Input Sheet” tab, cells D17-D19.17 See the San Diego Distributed Solar PV Impact Study (Black & Veatch and Clean Power Research for the Energy Policy Initiative Center, University of San Diego School of Law, February 2014) at p. 38, Table 18, which calculated a marginal cost of CAISO transmission for SDG&E of $102.83 per kW-year18 August 2015 Vote Solar and SEIA analysis found marginal CAISO transmission costs of $87 per kw-yr.

Page 21 of 47

Brandon Smithwood, 02/19/17,

This is an important point. Most of this bullet is really talking about costs that should be assessed at a system wide level.



DescriptionSupporting ArgumentsOpposing Arguments

Recommendation Avoided transmission cost should be based on CAISO transmission revenue requirement

Consensus? Non-consensusAction type WG to analyze furtherPriority HighTime Required Several Months to discuss, additional time to implementDescription As a methodology to calculate avoided transmission costs, use the CAISO

transmission revenue requirement allocated by CAISO coincident peak and/or specific location.

Supporting Arguments Marginal CAISO transmission costs can be calculated based on a regression of the CAISO base transmission revenue requirement (TRR) as a function of CAISO coincident peak in the same period. While TRR data can differentiate between “reliability”, “economic” and “policy-driven” CAISO transmissions designed to access renewable resources, DER deployment can reduce transmission investment in all three categories. Consider allocating the transmission revenue requirement socialized across the system only to the specific line segments identified.

Opposing Arguments The proposed methodology using CAISO’s transmission revenue requirement does not represent the marginal transmission cost nor location specific transmission project deferral value. The potential avoided transmission costs should be based on explicitly avoiding transmission projects identified by CAISO in its Transmission Planning Process. If we were to allocate transmission costs in this way it would result in many DERs being credited with value they are not necessarily creating, counter to the intent of LNBA to improve granularity and specificity.

Recommendation Initial development of the transmission avoided cost methodology should focus on specific areas/networks

Consensus? Non-consensus?Action type WG to analyze furtherPriority LowTime Required 3-6 MonthsDescription Transmission avoided cost calculations should focus on the low-voltage

network and/or transmission constrained areas first.Supporting Arguments Focusing on the low-voltage transmission network and transmission

constrained areas would provide greater transmission avoided cost. Limiting scope to specific sub networks will limit variables and potentially make generating the load reduction criteria easier to calculate.

Opposing Arguments Transmission projects are determined by CAISO and may not reflect a specific focus. Ideally we create a methodology that can account for all

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transmission projects/costs and not just that of specific sub networks.

Recommendation Inclusion of non-deferral benefits to the avoided transmission cost methodology

Consensus? Non-consensusAction type WG to analyze furtherPriority LowTime Required 3-6 MonthsDescription Include non-deferral transmission benefits to the transmission avoided

cost methodologySupporting Arguments Some parties argue frequency response, frequency stability, and other

services of value may be provided to the greater transmission network for DERs aggregated in mass and they should be credited for these services.

Opposing Arguments It is unclear what the specific non-deferral transmission benefits means. Further discussion is warranted to detail what are the specific non-deferral benefits.The methodology should be focused on attributing real avoided cost values to DERs where they avoid or defer transmission build-out

Recommendation Develop an enhanced/additional power flow analysis tool with the CAISO to determine load reductions required to achieve transmission project deferral

Consensus? Non-consensus

Action type WG to analyze furtherPriority MediumTime Required UnknownDescription Work with the CAISO to develop or enhance existing software to be able to

run a power flow analysis that is able to determine what series of load reductions could defer transmission projects. Then use these load reductions and the transmission deferral values as an additional LNBA layer in each of the IOU heat maps.

Supporting Arguments Developing a methodology similar to the one created for distribution deferral calculations will make the LNBA easier to interpret for DER developers and utility planners alike. Ideally the automated tool will be able to run thousands of DER scenarios to generate the most optimal set of load reductions at specific substations to defer transmission projects. If such a tool was developed the IOUs/CAISO could say with certainty that DERs installed at a specific location will achieve a hard dollar amount of deferral savings. The results of such a tool could then be integrated into the existing heat maps as an additional LNBA layer.

Opposing Arguments It is unclear what would be required to develop such a tool and if the desired outcomes are even achievable. CAISO’s involvement would most likely be required for a successful outcome and they are currently a party

Page 23 of 47


TURN


Refined recommendation based on comment, may not actually necessary to have in report since it was less a recommendation and more suggestion for LTR starting point



in the LNBA working group.

4.2 LNBA Tool Functionality: improving the heat map and spreadsheet tool, and incorporating complex DER Solutions

Objective: This section discusses improvements to better present how various DERs can achieve the potential benefits of the tool. This section does not consider changes to the underlying benefits analysis; those recommendations are discussed in the “Analytical Scope and Additional Benefits” section.

Within this section, there are two broad categories of recommendations. First, recommendations to better present the results of analysis. This section primarily

addresses details on how information is accessed and presented.

Second, recommendations to better show how different combinations of DERs can successfully deliver deferral value. This topic refers to modification to the tool to improve how specific DER projects are evaluated under the current LNBA Tool. In other words, this section considers adding functionality to better evaluate (and compare and contrast) specific DER technology types, as opposed to simply evaluating a generic production profile

4.2.1 Tool, Heatmap, and Presentation of Information

ObjectiveThis section considers recommendations to improve how information is presented on the heatmap and in the LNBA Tool.

Discussion

To show the results of Demo B on a visual map, IOUs color coded each feeder representing indicative LNBA results. The heat maps provide results over three time periods (short, medium, long term) and over two DER growth scenarios specified in the ACR. The maps are made publicly available and uses the same platform as the ICA map for ease of use. In addition, IOUs made data publicly available through an online downloadable dataset.

Recommendations

Recommendation Streamline the ToolModify the Tool to Use in Planning ProcessConsensus? UnclearAction type IOUs to implement modificationPriority ?Time Required ?Description Prior to system wide implementation of LNBA, further methodological

changes need to be made before the Tool may be used to help

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IOUs request that this recommendation be clarified or removed.


This was from SCE’s final Demo B report- I added some language but realized the rec is about using LNBA in the planning process, so maybe move up to use cases section.



streamlined the planning process and incorporate various aspects to help with planning for DERs as solutions to electric system needs.

This includes improvements to forecasting load profiles, developing alternatives to serve forecasted load profiles, and analyzing if DER portfolios can serve forecasted load profiles.

Supporting ArgumentsOpposing Arguments

Recommendation Heat Map GranularityConsensus? Already implementedAction type N/APriority N/ATime Required N/ADescription Heat map granularity should match needed granularity of resultsSupporting Arguments Publishing LNBA results onto a heat map is data intensive. It is

recommended that the online maps align granularity levels with the nature of the results. For example, if results do not differ on a section-to-section basis, or only differ with a negligible margin, the number of mapped line sections should be reduced to provide a more user-friendly experience, while minimizing impacts to map performance. Additionally, SCE recommends only publishing LNBA results from the forecast scenarios adopted for planning, as these align with the processes used to evaluate DER interconnections.

Explanation of how already implemented

In Demo B, the IOUs developed feeder-level DER benefits and reflected these in feeder-level heat maps.

Recommendation Heat Map May Indicate Certainty of InvestmentConsensus?Action type IOUs to implementPriorityTime RequiredDescription Certainty of utility investment is a key variable for DERs to avoid utility

distribution costs. Understanding which utility investments are more vs. less certain can be used alongside the current map interface indicating cost ($) of a deferrable project.

Supporting Arguments The heat map should indicate not just the relative dollar amount of potentially deferrable investment but also the certainty of investment. Projects with the highest certainty (as informed by the deferral framework criteria) and dollar amount may be prioritized for DER deferral.

This metric should be coordinated with the establishment of forecasting and investment uncertainty as a deferability criterion in the Deferral Framework in Track 3 sub-track 3.

Page 25 of 47

Eric Borden, 02/15/17,

I know you say this somewhere below as well but worth putting in this section too.


From TURN


This is from SCE’s final Demo B report – added clarifying language


LNBA results are at feeder level and so is Heat map, ergo this recommendation has been implemented already. IOUS suggest deleting.



4.2.2 Accommodating Complexity in DER solutionsObjective:The current tool considers whether a single load reduction profile in a location representing one resource or a composite resource, can achieve a distribution deferral. This section considers refinements to allow assessment of more complex DER solutions, including multiple locations, usage of smart inverters, and providing assessment of a partial deferral.

DiscussionIn general, the LNBA tool as designed under Demo B is technology-agnostic and is not designed to make any assumptions or conclusions about any specific resource type. Rather, users provide inputs about a resource, and LNBA provides information based on those inputs

In particular, the current LNBA tool is not designed to make assumptions about the performance of any particular resource. Rather, the LNBA tool provides information on the need, and the user can provide assumptions about a given resource.Sample profiles can be included in the LNBA tool. However, these would be “illustrative only.” An actual resource would not be guaranteed to perform similar to the same profile.

The dependability factor is not a necessary component to the LNBA and could be removed. If this were to occur, then Users would need to adjust the profile to account for dependability. Dependability is a sourcing question. LNBA provides needed attributes. It is a sourcing question of whether any resource (or resource portfolio) provides those attributes. For competitive solicitations, IOUs will evaluate dependability as part of the bid evaluation process. For programs and tariffs, dependability assumptions should be established as part of the program rules.

Recommendations

Recommendation Allow Partial Deferral ValueConsensus? Non-consensusAction type IOUs to implementPriority MediumTime Required 3-6 MonthsDescription Modify tool such that for projects that only meet some (but not all) of the

required attributes, the project would be assessed to have earned a corresponding percentage of the deferral value.

Supporting Arguments Demo B does not assign partial deferral value, or value mitigating needs prior to reaching project threshold criteria – instead, the current model assigns a zero deferral value for any DER that does not completely defer a three-year projected need, and may assign no additional value for additional deferral. Without this value assignment, potential project deferral identification and subsequent planning are also deferred. Deferral values should be calculated in proportion to a DER’s contribution towards

Page 26 of 47



meeting a deferral need.Opposing Arguments Ratepayers achieve zero savings unless a deferral is fully achieved. One

should not assume that other unspecified projects will also materialize to complete the deferral. This method of valuation does not adequately capture certainty of upgrades.

Rather than allow partial value for a partial deferral, the tool should be modified to allow multiple DER solutions to be input separately. This way, users can develop and analyze a portfolio of small projects that will collectively achieve the deferral and create the deferral value for ratepayers.

Recommendation Allow multiple locations / multiple projects.Consensus? ConsensusAction type IOUs to modify toolPriority HighTime Required 6-9 monthsDescription The LNBA Tool should be refined to allow for modeling of a portfolio of

projects, as a DER alternative to a larger distribution upgrade may require a portfolio of projects at numerous nodes.

Supporting Arguments A combined portfolio of DER capacity may provide deferral at a substantially lower cost than a single offer, particularly if customer DER capacity is divided among multiple separate aggregators. Under the existing tool, if two DER capacities are offered, which individually would not fully meet a defined need but would meet the need as a combined portfolio, the capacities would receive zero valuation.The WG should enhance the LNBA tool to support benefit analysis of deferring a project with multiple locational elements.

Opposing Arguments

Recommendation Allow multiple years of deferralConsensus? Already implemented.Action type N/APriority N/ATime Required N/ADescription To the extent that a DER offer provides greater than 3 years deferral value,

it should be recognized as such, as should a combination of smaller resources - two DER resource bids each supporting a 2-year deferral should be recognized as providing more value to ratepayers than a single resource offering 3 year deferral.

Supporting Arguments Additionally, while a 3 year deferral is typically the best balance between certainty of need and time to address the need, a project or combination of projects that offer 4 or more years of deferral should be valued for the additional deferral they offer, appropriately discounted to reflect lower probability of need (ex: a 20% reduction in for each year beyond three

Page 27 of 47


There seems to be more disagreement than agreement with this, so propose removing



Likewise, even if an offer does not provide a full 3 year deferral, a shorter deferral still pushes back the date by which capacity limits are forecast to be exceeded and allows additional time to procure the needed capacity, assuming that the forecast need still exists.

Opposing Arguments Tool already provides T&D deferral values for 1 to 10 years

Recommendation Value deferral beyond 10 years Consensus? ??Action type IOUs to modify toolPriorityTime RequiredDescription The current LNBA tool identifies potential project upgrades needed,

forecasting out up to 10 years, in alignment with current IOU distribution planning windows. Calculation of avoided costs should extend to the end of project life. The LNBA tool could use system average values to calculate avoided costs between Year 11, to the end of the project.

Supporting Arguments Forecasting out to 10 years coincides with existing utility distribution planning forecasts, but does not account for the full value of the DER project.

Opposing Arguments

Recommendation Include Data for Reactive Power Service NeededConsensus? ConsensusAction type IOUs to implement / May require further analysesPriority MedTime Required 1 year (mostly to develop method for hourly VAR requirement profile)Description Demo B LNBA tool only focuses on hourly load reduction, which does not

capture all attributes of some DERs, such as production of reactive power to avoid voltage-related investments (i.e. provide voltage support service). Incorporating tool functionality to take an 8760 VAR requirement input and DER VAR profile is not complex. However, developing that hourly VAR requirement input will take additional engineering analysis.

Supporting Arguments Voltage support, which is already a component of LNBA, can be provided by reducing/increasing load (a capability that all DERs have) or by injecting/absorbing reactive power (a capability of DERs with smart inverters). This recommendation would expand the way in which the voltage support project deferral requirements are stated so that smart inverter-based DERs could provide meet the deferral requirements through reactive power management.

Opposing Arguments NA

Recommendation Deferring Multiple Planned UpgradesConsensus? Already Implemented

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David, 02/21/17,

This is a tool recommendation; however, the tool does this already. IOUs propose removing this recommendation


SEIA: This is a bigger policy issue, but we need to balance certainty for upgrades with manageable “sourcing” processes (i.e., market certainty). I don’t think this comment needs to be addressed in this report, but raising it here.


TURN: I disagree with this. We need to address certainty in a more substantive way than reducing the value – the avoided cost is either avoided or not, there is no in-between in reality.


This is a tool recommendation; however, the tool does this already. IOUs propose removing this recommendation



Action type N/APriority N/ATime Required N/ADescription The ability to apply a DER solution to multiple project needs, if applicable.Supporting Arguments While it appears possible to combine the profiles of two or more DER to

create a single DER portfolio for assessment against a single project need, it is unclear how the tool can be used to estimate the contribution of a DER project or portfolio in meeting or reducing the requirements to more than one deferral project simultaneously. For example, mitigation of peak load on individual line sections may defer the need for local reconductoring, but the combined effect of this on multiple circuits may also defer an identified substation upgrade need.

Opposing Arguments Tool already provides this function. No action is necessary.

Recommendation Further Work on Dependability FactorConsensus? Non-consensus Action type WG to analyze further Priority LowTime Required 6 monthsDescription The WG should develop expectations around how developers will be

expected to arrive at a dependability factor, and consider different technology, weather inputs, and other factors.

Supporting Arguments The LNBA tool requires users of the tool to provide basic DER information, benefits that the DER can obtain, and a DER hourly profile. One component that a prospective project developer is required to input is a “local area dependability” value under the “DER Settings and Full Local T&D Avoided Cost” tab. This input is meant to scale the DER profile up or down. As it is currently applied, the dependability factor does not actually reflect whether a project more or less “dependable”.

Opposing Arguments This is really more of a sourcing questions than a planning question, and so the LNBA WG should not focus on this matter. This question should be primarily informed by learnings from the current demonstration and pilot projects that will deploy DERs to meet distribution needs.

The LNBA tool is based around need requirements. It is up to the developer to propose solutions that will meet the need, based on the particular attributes of their technology and projects.

It is better to have this conversation in IDER (where this conversation is definitely necessary) and then eventually incorporate the results here. For the time being, Developers can specify their dependability factor.

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TURN


Ask CALSEIA for clarification



Recommendation Use more than just the peak hour when determining when load reductions can avoid capacity upgrades.

Consensus? ConsensusAction type IOUs to implement modification to toolPriority LowTime Required 0Description In determining hours where reductions in peak loads can defer or avoid

capacity upgrades, hours should be based on the periods of highest thermal loads rather than simply on times of peak instantaneous demand

Supporting Arguments The IOUs have developed hourly load reduction requirements to defer capacity upgrades and capture the associated benefit in Demo B. These hourly load reduction requirements capture any hour that may have an overload, not just the peak hour.

Opposing Arguments N/A


Overview: This section discusses recommendations concerning the overall scope of the analysis that determines potential distribution benefits.

The current LNBA scope (as determined in the May 2 ACR) focuses on identifying the potential benefits of DER resources. This section considers recommendations to LNBA scope that go beyond identifying the benefits of DERs. (This section does not include recommendations concerning adding values related to the uncertainty of the planning process; such recommendations are considered in the Uncertainty section.). Additionally, this section includes other recommendations concerning the structure of the analysis.

4.3.1 Analytical Scope

ObjectiveThis section addresses general cross-cutting and cross-cutting recommendations that do not fall into the more specific sections that follow.

Discussion..

Need discussion on challenge of estimating interconnection costs Need discussion comparting scope with ICA and Track 3 Subtrack 1

Recommendations on Analytical Scope

Recommendation Include Cost of DER PenetrationConsensus? Non-consensus

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IOUs suggest deleting this recommendation as it is already implemented.



Action type IOU Modification of toolPriority MediumTime Required 2 years +Description The LNBA should take into account the cost of DER penetration using

various DER growth scenarios.

This should be done first by increasing hosting capacity limits found in the ICA (if necessary) – when a feeder has hit the limit of hosting capacity, it should be investigated which limit has been violated, and how much it would cost ($) to increase the hosting capacity to avoid the violation. It could then be estimated how much the hosting capacity has increased under DER growth scenario (MW) and the cost to do this ($). The cost to integrate various levels of DER could thus be estimated.

Additionally, some of these costs may be avoided or deferred by DERs themselves. These could then feed into the LNBA tool. It must be determined which violations are deferrable with DER’s themselves (e.g. by modifying generation output, with smart inverters, storage, etc.).

Supporting ArgumentsOpposing Arguments The IOUs understand that including the hosting-related costs of

incremental DERs would result in a more complete “net” valuation of those DERs; however, we do not current have the capability to estimate the cost of increasing hosting capacity system-wide on a circuit by circuit basis. Specifically, the IOUs do not have an automated capability to estimate the cost of increasing hosting capacity. Right now, this is a manual process that requires individual circuit analysis based on specific proposed projects. This is thus well beyond the scope of either the ICA or LNBA.

Note: the final aspect of this recommendation – deferring interconnection upgrade costs by additional DERs – is considered as its own recommendation in the section on Additional Benefits below.

Finally, the development and inclusion of a methodology for this value may be outside the scope of the LNBA.

Recommendation Use Base Growth Scenario OnlyConsensus? Consensus, with scope questionAction type CPUC PolicyPriority HighTime Required N/ADescription LNBA methodology should use the base DER forecast to determine value

of additional DER, rather than the high growth scenario

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Supporting Arguments The ACR defined two DER growth scenarios – a base DER growth scenario, and a very high DER growth scenario. In some of the IOU Demo B reports, it was determined that the impact of the very high DER growth scenario was not consistent or intuitive. Further, the high growth scenario depends on many policy interventions that cannot be assumed. Methodological choices for the high growth scenario and lessons learned from Demo B should be shared with the Track 3, sub-track 1 of the DRP.

Opposing Arguments This is potentially a question for Track 3, sub-track 1 on load and DER forecasts or Track 3, sub-track 3 on integration of DRP into planning.

Recommendation Clarify Renewable Integration CostConsensus? Already implementedAction type IOUs to implement modification to toolPriority LowTime Required 0Description Integration cost: The WG is unclear about the origin, development, and

application of the integration cost in the LNBA tool, the appropriateness of the adder in the LNBA, and whether it would be eliminated for the solar + storage option. This issue may be flagged as part of the cost-effectiveness framework.

Supporting Arguments NAOpposing Arguments As described in all three IOUs’ reports, the renewable integration cost is

obtained from D.14-11-042. These costs apply to stand-alone wind and solar resources, and reflect the increase in variable cost at the bulk-system-level associated with renewable integration. These do not represent “integration costs” associated with hosting or interconnection.

4.3.2 Additional Benefits

ObjectiveSeveral stakeholders have argued that the current LNBA implementation omits certain benefits provided by DERs. This section considers those additional benefits.

Note: This section does not contemplate the hypothetical additional value through consideration of “not yet identified” deferrable projects. This potential source of value is considered in the following section on Uncertainty in the planning process.

Discussion

Over multiple WG meetings, the joint IOUs consulted on and agreed upon electric services that DERS could potentially provide, for the purposes of Demo B. The ACR required the IOUs to consider the full range of electric T&D services that DERs can potentially provide that result in avoided costs. The values must include services associated with distribution grid upgrades identified in 1) the utility distribution planning process, 2) circuit reliability improvement process, and 3) maintenance process. The WG agreed to use the four grid services developed under the IDER Competitive Solicitation Framework (CSF)

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SEIA, CALSEIA, Vote Solar, Clean Coalition to fill out rationale here?


From Energy Division: To my recollection it’s been made clear that integration/interconnection costs are not reflected in the current LNBA cost-benefit calculation…


If this explanation is sufficient, the IOUS suggest deleting.



Working Group: 1) t&d capacity deferral; 2) voltage support; 3) reliability – back-tie services; 4) resiliency (microgrids). ).

The IOUs, in their final Demo B reports, also included a list of services DERs have the potential to provide, but did not include in Demo B, as well as a list of services DERs cannot currently provide.

Non-IOU Stakeholders recommended that LNBA also include means of evaluating the following grid services, to the best estimated non-zero value possible if an established, industry-recognized methodology for quantification of indicative values is available. For many benefits, there is non-consensus whether a method of quantification is currently recognized, or whether the benefit exists.

Moving forward, in developing methodology for these proposed values, it is important that the WG define the type of value derived (e.g., avoided utility expenditure) as well as who receives the benefit. Specifically, any value included in the LNBA need to specify whether it represents an “avoided utility expense" (CapEx or O&M) or some other kind of value, and should indicate the type and who receives the benefits (e.g. societal value, customer value).

This section considers recommendations first for how benefits should be considered, and then recommendations for specific benefits.

Recommendations – how potential benefit categories should be considered:

Recommendation Only include benefits that reduce utility revenue requirementConsensus? ??Action type CPUC PolicyPriority HighTime Required N/ADescription LNBA should focus exclusively on benefits that represent actual avoided

utility expenses; i.e., values that directly reduce a utility’s revenue requirement.

Societal Cost Test is under discussion in IDER. LNBA should not include such benefits until IDER resolves. Societal benefits are largely not local

Supporting Arguments Only benefits that actually reduce revenue requirement actually lead to ratepayer savings.

Benefits that not reduce a utility’s revenue requirement do not actually lead to ratepayer savings. If any such values are included in the LNBA, it must be clearly indicated who receives these benefits, and how exactly these benefits are accrued.

Opposing Arguments

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Recommendation T&D values to be included in future modifications LNBA Tool should only reflect values with established quantification

Consensus? Non-consensusAction type CPUC PolicyPriority HighTime Required N/ADescription There are many “potential” values that have been suggested. However,

many of these proposed values do not have a clear means of quantification established due insufficient information, insufficient control infrastructure, or lagging regulatory processes.

Values should only be included in the LNBA if they have an established, industry-recognized methodology for quantification. “Placeholder” values must not be used, especially if there is debate about whether the value is positive or negative.

Supporting Arguments The LNBA tool is not designed to speculate on potential sources of value. For potential values that do not have a defined method of quantification, additional research and analysis is necessary to determine whether or not these values actually exist.

Opposing Arguments Many services are currently represented as providing zero value. Where an industry-recognized methodology has not yet been established, the best estimated value, or range of values, should still be used.

There is not consensus over what qualifies as an “industry-recognized” methodology.

The Commission should consider research on these values to determine their existence and magnitude (e.g., existing peer reviewed research on asset life extension).

Recommendations – Modifying Existing Benefits

Recommendation Modify Voltage Support Consensus?Action type IOUs to make revisionPriorityTime RequiredDescription DERs can potentially provide voltage support in areas where customers

experience low/high voltage conditions outside of Rule 2 limits. Voltage support services are planned capital investments needed to correct excursions outside voltage limits and supporting conservation voltage reduction strategies in coordination with utility voltage/reactive power

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From SEIA


From Clean Coalition


Alternatively: “empirically proven”


Can both arguments make a suggestion here on proposed timing and process for including values?



control systems.

In the existing LNBA tool, voltage support project deferral requirements are expressed in terms of load reduction rather than reactive power injection or absorption. This ensures that non-inverter-based DER technologies such as energy efficiency are able to be evaluated as DER solutions to deferrable voltage support projects.

Supporting Arguments Demo B only focuses on hourly load reduction needed to avoid a planned upgrade. This does not effectively capture the ability of DERs to provide voltage support. DERs produce reactive power to avoid voltage-related investments. In addition to the load reduction requirement calculated in the LNBA Tool for thermal and safety constraints, the LNBA Tool should have a reactive power production requirement for voltage constraints.

Opposing Arguments

Recommendations: Specific Additional Benefits Values

Recommendation Asset life extension/reductionConsensus? Non-ConsensusAction type WG further study requiredPriority MediumTime Required 2+ yearsDescription DERs, by reducing thermal stress on existing distribution equipment, may

potentially extend equipment lifetime. Conversely, DERs could shorten an asset’s life through additional usage and strain. The impact of DERs on asset life should be explored.

Supporting Arguments The IOUs identified this potential service in Demo B final reports, and noted that it is currently difficult to accurately quantify this benefit, recommending its further inclusion as a long-term refinement item.

Opposing Arguments Significant effort would need to be undertaken to study asset life extension/reduction.

Recommendation Situational awareness or intelligenceConsensus? Non-consensusAction type WG further study requiredPriority lowTime Required 2+ yearsDescription This service was identified in the IDER CSF WG Final Report and in Demo B

final reports, but not formally defined.

Supporting ArgumentsOpposing Arguments This hypothetical benefit has not been discussed or even clearly defined

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SEIA, CALSEIA, Vote Solar, Clean Coalition Comment. Can those parties help fill in supporting arguments?


From CALSEIA



within the context of the LNBA WG. To date, there is no analysis to provide any sense of the scope or magnitude of additional “situational awareness provided by DERs: there is no indication of the specific information that will be provided to IOUs, there is no indication of the format, quality or frequency of such information, and there is no indication of whether DER providers intend to provide this information freely or expect that IOUs will provided additional payments for this information.

More critically, there is no indication of the usefulness of this information. How much information is necessary to begin to improve “situational awareness? How many DERs are necessary on a particular circuit in order to provide this level of information? What is the necessary level of reliability of this information?

Finally, there is no sense of the value of this information. Does this information reduce ratepayer expense? How so? If not, do other parties somehow benefit from this information? How?

These questions are complicated and challenging. It would be inappropriate for the WG to spend time on this matter.

Recommendation Increased reliability (non-capacity related):Consensus? Non-consensusAction type IOUs to implement change to LNBAPriority MediumTime Required 12 monthsDescription Include benefits associated with increased reliability provided by DERs, e.g.

through reducing the frequency, duration or magnitude of customer outages.

Supporting Arguments The LNBA methodology should value increased reliability and location. For example, if a DER provides reliability service in a location where the cost or value of reliability is above average, to a relatively small set of customers but those customers have a high "value of service", then the value that the specific DER provides could be significant

Opposing Arguments LNBA currently includes the value of increase reliability from DERs where DERs can defer or avoid an otherwise necessary investment to bring reliability up to an acceptable level. Right now these are defined as providing back-tie capacity (a function which can enable switching operations to reduce the number of customers on outage) or microgrid services (a function which can reduce the frequency and duration of outages for remote customers with an unreliable connection to the grid).

If a particular customer or set of customers places a value on reliability above the standard level that is provided, that customer can make

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investments in DERs to improve their reliability. This should not be a cost that other customers bear through additional incentives for that customer’s DER investment.

Recommendation Evaluate Planned Upgrades Meant to Accommodate Additional DER Growth

Consensus? Non-consensusAction type WG to analyze furtherPriority MediumTime Required Up to 24 monthsDescription Any planned upgrades that are due to the need to accommodate

additional DERs on the grid, which may be avoided or deferred by DERs, should also be included as a deferrable project.

Supporting ArgumentsOpposing Arguments Where upgrades are needed to accommodate DERs that increase load (e.g.

to serve electric vehicles), such upgrades would be identified in the normal distribution planning process, and would already be considered deferrable in LNBA.

In cases where upgrades are needed to accommodate DERs that are interconnecting as a wholesale resource, the DER owner/developer would be responsible for that upgrade cost, and should be able to take actions that would reduce that cost in the interconnection process.

The remaining upgrades to accommodate DERs might be deferrable by DERs; however, there is not yet an established framework for identifying and planning for those upgrades. Today, these are identified and managed as they emerge. When a planning framework has been established, these upgrades could be considered as deferral opportunities. Wherever possible, a DER that is causing a problem that requires an upgrade should be required to take reasonable actions to mitigate that problem without additional compensation.

Utility customers should not provide additional compensation to DER owners/providers to mitigate a problem they are causing and which could be easily mitigated.

Recommendation Utilities should identify investments in DER integration that reduce the need for other investments.

Consensus?Action typePriorityTime RequiredDescriptionSupporting Arguments

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SEIA, CALSEIA, Vote Solar, Clean Coalition:Can those parties help fill in supporting arguments?


IOUs request clarification on this recommendation.



Opposing Arguments

Recommendation Avoiding Maintenance ProjectsConsensus? Non-consensusAction type WG further study requiredPriority LowTime Required 2+ yearsDescription LNBA methodology should value benefits of DER in reducing the frequency

or scope of future maintenance projects.

Supporting Arguments Maintenance projects are not scheduled far enough in advance for DERs to defer specific maintenance needs. However, DERs can likely defer maintenance in many cases – this value should be quantified.

Installing DER on a distribution feeder reduces loading on upstream equipment. If an upstream distribution facility fails and needs to be replaced, then the IOUs’ distribution engineers would not necessarily specify replacement equipment with equipment of the same capacity as the failed device. Instead, they would account for the fact that the DER is on the feeder and may result in the replacement facility being smaller and less costly than a “like-for-like” replacement. LNBA methodology should value benefits of DER allowing for installation of less costly equipment in the event of an unexpected equipment failure.

Opposing Arguments There is currently no reliable evidence that DERs actually defer maintenance projects. At minimum, additional data and analysis must be gathered. However, it is quite possible that additional DERs increase the need for maintenance projects.

Recommendation Downsizing Replacement EquipmentConsensus? Non-consensusAction type WG further study requiredPriority LowTime Required 2+ yearsDescription LNBA methodology should value benefits of DER allowing for installation of

less costly equipment in the event of an unexpected equipment failure.

Supporting Arguments Maintenance projects are not scheduled far enough in advance for DERs to defer specific maintenance needs. However, DERs can likely defer maintenance in many cases – this value should be quantified. Installing DER on a distribution feeder reduces loading on upstream equipment. If an upstream distribution facility fails and needs to be replaced, then the IOUs’ distribution engineers would not necessarily specify replacement equipment with equipment of the same capacity as the failed device. Instead, they would account for the fact that the DER is on the feeder and

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may result in the replacement facility being smaller and less costly than a “like-for-like” replacement.

Opposing Arguments In theory, this benefit is possible. In reality, this benefit is likely to be small or non-existent: The incremental cost savings of downsizing any particular piece of equipment are quite modest. Furthermore, given that ultimately load tends to grow, downsizing replacement equipment may actually be adding to the long-term cost, as in the future another replacement may become necessary to upsize the equipment. Utility investments are “lumpy” by their nature. When an equipment replacement is necessary, it generally does not make sense to downsize equipment.

At minimum, this benefit would require significant additional study and analysis to ensure that downsizing does in fact increase expected ratepayer benefits.

Recommendation T&D benefit beyond 10 year planning horizonConsensus? Non-consensusAction type WG to analyze furtherPriority LowTime Required 6 monthsDescription The T&D deferral value should be determined beyond the 10 year planning

window Supporting Arguments DERs could potentially solve projects beyond the 10 year planning window.

A potential solution to determine a system value for time periods beyond the 10 year planning window.

Opposing Arguments One of the main purposes of the LNBA methodology development was to determine locational values, not continue generic/system wide T&D benefits. The suggestion of using system values for years beyond the 10 year planning window contradicts this guideline.

4.3.3 Uncertainty in the Distribution Planning Process

Objective: Improve the comprehensiveness and accuracy of the distribution capacity component of LNBA by capturing the effects of forecast error on planned distribution upgrades: capacity additions currently planned for future years may be cancelled as the plans are refined due to lack of need; locations with no current planned capacity addition may require such an upgrade as distribution plans are refined due to an unforeseen need.

Discussion:

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The LNBA tool is based upon the distribution planning. The forecasts underlying the planning analyses are by definition uncertain. Due to changing forecasts, it is possible that new projects may become necessary, adding to the value of DERs. It is similarly possible that current projects may become unnecessary, reducing the value of DERs. Furthermore, the current planning forecasts only extend 10 years; there is no analysis beyond the 10 year period. This section considers recommendations to modify the tool to address these sources of uncertainty.

Development of LNBA methodology requires making certain assumptions and scenario development regarding DER growth, long-term forecasting, and value of DER to determine which planned projects may be deferred by DERs. IOUs’ distribution load forecasting methodology, which feeds into the annual distribution planning process, determines growth projection over 10 years. Two different DER growth projections were used in Demo B, per ACR requirements. The IOUs then use peak load information and detailed hour load profile data to understand load reduction need for future planned projects under each DER scenario. The WG recommends the following refinements to better incorporate uncertainty and inform decision making (some of these refinement items will be developed along parallel DRP Track 3 activities):

Recommendations:

Recommendation Examine methods to reduce uncertainty in planning and utility investment

Consensus? Non-consensusAction type WG to analyze furtherPriority MediumTime Required 12-24 moDescription The LNBA working group should examine ways to reduce uncertainty in

distribution and transmission planning, which primarily stems from forecast uncertainty.

Supporting ArgumentsOpposing Arguments Out of scope – load forecasting and DER scenario development are not

part of LNBA, though they drive the distribution planning outputs used in LNBA

Recommendation Incorporate an uncertainty metric in the LNBA tool (for planned deferrable projects)

Consensus? ??Action type WG to analyze furtherPriority HighTime Required 12 monthsDescription The deferrable distribution upgrades which form the basis for distribution

benefits in LNBA are uncertain. Upgrade projects planned for future years in one planning cycle may not be ultimately implemented because future planning cycles with updated load forecasts show a reduced need. When such forecasted projects are assumed to be deferrable and hence provide an opportunity for DERs to capture the associated benefit, the quantification of that benefit should not assume that the project is 100%

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certain.Supporting Arguments An uncertainty metric for future projects would increase the accuracy of

quantification of T&D benefits in LNBA.Opposing Arguments NA

Recommendation Develop a methodology to incorporate deferrable projects that may occur unexpectedly (i.e. unplanned projects)

Consensus? ConsensusAction type WG to analyze furtherPriority HighTime Required 12 monthsDescription As described above, due to forecast uncertainty, planned upgrade

projects for future years are uncertain. Because projects toward the later years in a utility’s ten-year distribution upgrade plan tend to be less concrete than those in the earlier years, the utilities in Demo B focused on near term projects.19 Forecast uncertainty also results in new, unanticipated upgrade projects emerging within the forecast horizon in future planning cycles due to updated load forecasts. The IOUs should develop a method to quantify the likelihood of an unplanned project emerging in a location based on forecasted conditions and forecast uncertainty.

Supporting Arguments C) maintenance that is deferred by DERs.

LNBA heat maps should identify areas approaching saturation, or areas where future needs are most anticipated.

Some distribution upgrades are not identified in annual distribution planning. These short lead-time upgrade projects are not considered deferrable by DERs. However, DERs that may not defer a planned upgrade at the time they were installed may actually reduce demands on a feeder and reduce the need for the IOU to perform an unexpected upgrade. LNBA methodology should include the value of DERs in avoiding or reducing the likelihood of unplanned distribution upgrades.

Needs will be identified and projects proposed in the future as the existing grid capacity reaches saturation. Where increasing customer demand would otherwise result in triggering future mitigation project planning, earlier changes in DER deployment or operation relative to the base case can delay or avoid ever reaching this threshold. This value should be recognized. While less precise than the cost of specific project proposals, areas approaching saturation can be clearly identified based on the rate of growth and existing capacity headroom. Mitigating such projected customer demand has less urgency than in areas where upgrade thresholds have already been crossed, and the value of such mitigation

19 For example, six of nine deferral opportunities studied by PG&E are scheduled for 2018, and the three others are planned for 2019, 2020 and 2022.

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From SEIA:Can we clarify what this means? Are we talking about doing the LNBA in pockets where there is expected to be really high or really low value rather than rolling it out system wide?



should be proportionately discounted, but should not be ignored.

If an upstream distribution facility fails and needs to be replaced, then the IOUs’ distribution engineers would not necessarily specify replacement equipment with equipment of the same capacity as the failed device. Instead, they would account for DER on the feeder and may result in the replacement facility being smaller and less costly than a “like-for-like” replacement. The Demo B reports do not attempt to quantify such benefits. In future versions of the Tool, there should be proxy value that reflect the potential benefits of DERs avoiding these unexpected upgrades or allowing for the installation of less costly equipment in the event of an unexpected equipment failure.

Finally, LNBA inputs and methodology must be refined to account for projects which materialize between planning cycles.

Opposing Arguments NA

Recommendation Allow projects that are multiple years in the future to be deferrableConsensus? Already includedAction type Policy Guidance OR IOUs to implement modification to tool OR WG to

analyze furtherPriority High, medium, LowTime Required 6mo, 12 mo, 12-24 moDescription (Brief description of what this recommendation actually means, for

someone who has not been part of WG)Supporting ArgumentsOpposing Arguments

--- . -

5 Appendix5.1 Parties Participating in the Working GroupThe following stakeholder groups attended at least one meeting or webinar of the LNBA WG:

- ABB Group- Advanced Microgrid

Solutions- Alcantar & Kahl- AMS

- Artwel Electric- Bloom Energy- CAISO- California Energy

Storage Alliance

- California Energy Commission

- California Public Utilities Commission

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IOUs recommend deleting as this is already done– in Demo B, any project providing a service that DERs could also provide is deferrable, regardless of the year it is expected in the distribution planning horizon.

Eric Borden, 02/15/17,

Given that distribution planning every year shouldn’t the LNBA just be refreshed every year?



- CPUC Office of Ratepayer Advocates

- California Solar Energy Industries Association

- City of Burbank- Clean Coalition- Community Choice

Partners- Community

Renewables- Comverge- Cross Border Energy- DNV GL- ECCO International

Inc.- Energy and

Environmental Economics

- Electric Power Research Institute

- Energy Foundation- Environmental

Defense Fund- Gratisys Consulting- Greenlining Institute- Helman Analytics- ICF International

- Independent Energy Producers Association

- Independent advocates

- Independent consultants

- Integral Analytics- Interstate

Renewable Energy Council

- Kevala Analytics- Lawrence Berkeley

National Laboratory- Lawrence Livermore

National Labs- MRW & Associates- Natural Resources

Defense Council- Northern California

Power Agency- NextEra Energy- New Energy Advisors- Nexant- Open Access

Technology International

- Pacific Gas and Electric Company

- PSE Healthy Energy- Quanta Technology - Sacramento

Municipal Utilities District

- San Diego Gas & Electric

- SEIA- Shute, Mihaly &

Weinberger LLP - Siemens- Smart Electric Power

Alliance - SoCal REN- SolarCity- Solar Retina- Southern California

Edison- Stem Inc. - Strategy Integration- Sunrun- SunPower- TerraVerde

Renewable Energy- The Utility Reform

Network- UC Berkeley- Vote Solar

5.2 Acronyms5.3 List of WG meeting Dates and topics covered

Meeting Date Topic(s)May 12 – 1:00pm-3:00pmWebinar (combined ICA/LNBA WG webinar)

Opening meeting

June 1- 9:00am-3:00pm In person (combined ICA/LNBA WG meeting)

First discussion of demonstration implementation plan before June 16th submission

June 9 – 9:00am-3:30pmIn person (combined ICA/LNBA WG meeting)

Second discussion of demonstration implementation plan before June 16th submission

July 5 – 2:00pm-4:00pm Call to discuss submission of demonstration implementation

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Conference call, combined ICA/LNBA WG call)

plan

July 26 – 9:00am-4:00pmIn person

Discussion of submitted stakeholder comments on demonstration implementation plansUse cases (focusing on procurement use case)Grid services (6.1.b)E3 methodology Data & maps (6.1.a)

August 31 – 9:00am – 4:15pmIn person (combined ICA/LNBA WG meeting)

Clarification on use casesInitial scoping discussion on long-term refinement issues (6.2.1.(A-D))

September 30 – 9:00am-4:00pmIn person (combined ICA/LNBA WG meeting)

Demo B status updateData access discussion

October 19 - 9am-12:30pm (webinar)

Second scoping discussion on long-term refinement issues (6.2.1.(A-D))

October 27 – 12:30pm-2:30pm(webinar)

Grid services and project deferability criteria for Demo B

November 16 – 9am-12:00pm(webinar)

Review of outlineData (long-term refinement)Review of LNBA toolAvoided transmission cost component

December 13 – 1pm-2pm Status updateJanuary 6 – 9am-4pm In person (combined ICA/LNBA WG meeting)

Presentation of IOU Demo B reports

January 11 – 1pm-3pm(webinar)

Discussion on planning use case Presentation of LNBA Tool

January 20 – 9am-4pmIn person (combined ICA/LNBA WG meeting)

Discussion on use cases and recommendations

February xx Discussion of WG Recommendations

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5.4 Summary of all RecommendationsRecommendation Consensus? Action Type Priority Time

Required Description

3 Principles, Use Cases, Regulatory Process3.1 Demo B projects have been completed as

requiredIOU Demo B Projects Satisfy all CPUC Requirements

3.2 Future use cases considering locational value for resource valuation: draft principles Adopt Guiding Principles

3.3 Use CasesRefine tool to support future sourcing options

3.4 Regulatory Process RecommendationsDeferral Framework adoption prior to LNBA implementationOpportunity to comment on Scope, Schedule, Budget

4 Modifications to the LNBA Tool

4.1 Bulk System Benefits: Refinements to existing LNBA Value Types

4.1.1 Replace System Values with Local ValuesDevelop locational specific avoided cost values for energy and capacityDevelop locational line losses

4.1.2 Avoided transmission capital and operating expendituresAvoided transmission cost should be based on CAISO transmission revenue requirement

Non-Consensus

Application of the transmission avoided cost methodology should focus on specific areas/networksInclusion of non-deferral benefits to the avoided transmission cost methodology

4.2LNBA Tool Functionality: improving the heat map and incorporating complex DER Solutions

4.2.1 Tool, Heatmap, and Presentation of Information

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David, 02/21/17,

This table to be filled in once all of the individual recommendations are finalized.



Recommendation Consensus? Action Type Priority Time Required Description

Streamline the Tool*Heat Map Granularity*

4.2.2 Accommodating Complexity in DER solutions

Allow Partial Deferral Value Non-Consensus

Allow multiple locations / multiple projects.Allow multiple years of deferral*Include Reactive Power ServiceDeferring Multiple Planned Upgrades*

Further Work on Dependability Factor Non-Consensus


4.3.1 Analytical Scope

Including Cost of DER Penetration Non-Consensus

Use Base Growth Scenario Only4.3.2 Additional Benefits

Only include benefits that reduce utility revenue requirement

Non-Consensus

Only include values with established quantification

Asset life extension Non-Consensus

Situational awareness or intelligence Non-Consensus

Increased reliability (non-capacity related): Non-Consensus

Evaluating Planned Upgrades Meant to Accommodate Additional DER Growth

Non-Consensus

Avoiding Maintenance Projects Non-Consensus

Downsizing Equipment Upgrades Non-Consensus

T&D benefit beyond 10 year planning horizon

Non-Consensus

4.3.3 Uncertainty in the Distribution Planning Process

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Recommendation Consensus? Action Type Priority Time Required Description

Examine methods to reduce uncertainty in planning an utility investment

Non-Consensus

Incorporate an uncertainty metric in the LNBA tool (for planned projects)Develop a methodology to incorporate projects that may occur unexpectedly (i.e. unplanned projects)Allow projects that are multiple years in the future to be deferrable*

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