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MTS Working Group San Francisco F2F Agenda Dec. 9, 2014.

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Presentation on theme: "MTS Working Group San Francisco F2F Agenda Dec. 9, 2014."— Presentation transcript:

1 MTS Working Group San Francisco F2F Agenda Dec. 9, 2014

2 2 2 Agenda 9:00-9:05a Introductions 9:05-9:30aSummary of Prior Discussions & Objectives for Meeting 9:30-12:00nOptimal Locational Benefits Presentation 1: Ryan Hanley Presentation 2: Aram Shumavon 12:00-12:30nLunch break 12:30-1:30pOptimal Location Benefits 1:30-2:30pDistribution Process Planning Alignment Presentation 3: Lorenzo Kristov 2:30-3:30pIntegration Capacity Planning Erik Takayesu 3:30-4:00pWrap-up & Next Steps Morning & afternoon breaks as needed

3 3 3 Optimal Location Benefits Methodology

4 4 4 Context: AB327 Distribution Resources Plan Identifies optimal locations for the deployment of Distributed Energy Resources (DERs) DERs include distributed renewable generation, energy efficiency, energy storage, electric vehicles, and demand response Evaluates locational benefits and costs of DERs based on reductions or increases in local generation capacity needs, avoided or increased investments in distribution infrastructure, safety benefits, reliability benefits, and any other savings DERs provide to the grid or costs to ratepayers Proposes or identifies standard tariffs, contracts, or other mechanisms for deployment of cost-effective DERs that satisfy distribution planning objectives Proposes cost-effective methods of effectively coordinating existing commission- approved programs, incentives, and tariffs to maximize the locational benefits and minimize the incremental costs of DERs Identifies additional utility spending necessary to integrate cost-effective DERs into distribution planning Identifies barriers to the deployment of DERs, including, but not limited to, safety standards related to technology or operation of the distribution circuit in a manner that ensures reliable service

5 5 5 Optimal Analysis Optimal analysis based on cost minimization of: Planning objectives Societal objectives System Constraints Reliability Environmental Policy goals Safety Load serving capacity Asset utilization Affordability and cost objectives Resiliency and cyber security Customer choice Streamlined interconnection processes Environmental GHG and local area emissions Water-energy nexus Environmental Justice Low income access to reliable power Resiliency impacts Ease of access Job Creation Transportation electrification Regulatory certainty Thermal Limits Existing system capacity Operating flexibility Assets and their depreciation/age Institutional constraints Technology constraints System stability Limits of steady-state analysis Inability to account for uncertainty Protection Power Quality (voltage, etc)

6 6 6 Evolution of DRP Optimal Location Benefits Analysis Walk Jog Run No. of Benefit Categories & Sophistication of Analysis H 20162H Visibility & Initial DPA Locational Benefits Systemwide DRP including LTPP & TPP locational benefits Systemwide DRPs incl. Locational Societal Benefits What are the immediate benefit categories that can reasonably be evaluated within the next 3 months for the first DRP? What are the next logical set (and data and tools needed) for systemwide DRPs?

7 7 7 Objectives for Discussion Define avoided cost/benefit buckets to include in July 2015 Utility DRP optimal location analyses Identify methodology for calculating each avoided cost/benefit bucket Leverage/adapt existing CA methods where possible Identify data required for each analysis and its source & availability Identify linkage to existing CA planning processes

8 Avoided Cost Approach for Optimal Location Analysis Ryan Hanley

9 9 9 Objectives for July 2015 Optimal Location Analysis What does this analysis intend to accomplish? Identify optimal locations for DER deployment Consider mutually exclusive, collectively exhaustive locational avoided costs and benefits Illustrate a quantitative spread in DER locational value by utility planning area/substation What does this analysis NOT intend to accomplish? Completely replicate the CPUC/RMI/E3 avoided cost methodology Accurately account for the full value of DER assets (some value components do not differ by location, and so will not be included in this analysis) Consider only one DER technology type (this analysis is focused on the potential benefits of all/any DER, not a specified technology) Directly inform pricing for any DER tariffs / markets (tariffs and/or markets may be derived from the insights of this analysis, but this analysis is not a tariff pricing exercise).

10 10 Analysis Process (Proposed) Identify DPA & Substations Perform Planning Analyses Calculate Potential Avoided Costs Rank Substations by Avoided Cost DRAFT

11 11 Background: Avoided Cost/Benefits Studies Reviewed E3 – Net Benefits of NEM in California (2013) Rocky Mountain Institute – A Review of Solar PV benefit and Cost Studies, 2 nd Edition (2014) Integral Analytics – Distributed Marginal Price (2014) Brattle – Value of Distributed Electricity Storage in Texas (Nov 2014) PG&E – Distribution Planning and Investment and Distributed Generation – 2014 GRC Testimony – Appendix C (2013) New York – Benefits and Costs (Nov 2014) Regulatory Assistance Project – US Experience with Efficiency as a Transmission and Distribution Resource (2012) Regulatory Assistance Project – Big Changes Ahead: Impacts of a Changing Utility Environment (2014) Regulatory Assistance Project - Designing Distributed Generation Tariffs Well (2014)

12 12 Potential Avoided Cost Approach for DRPs Calculate potential avoided costs/benefits in 6 categories ComponentCurrent GranularityPotential DRP Approach E3 Framework Generation Energy + LossesZonal (utility-specific for losses)Exclude in initial DRP, since system-wide benefit Generation CapacitySystem value (no use of LRA values)Add Incremental Local RA Wholesale Ancillary ServicesStatewideExclude in initial DRP, since system-wide benefit CO2 EmissionsStatewideExclude in initial DRP, since system-wide benefit Avoided RPSStatewideExclude in initial DRP, since system-wide benefit Transmission CapacityUtility (this is only for Transmission downstream of the CAISO) Exclude in initial DRP, since system-wide benefit Distribution Capacity  Capacity Upgrades Utility (SCE, SDGE), climate zone (PGE), substation data was included in NEM report, but data was not made public Use substation-specific planned capacity projects (10 year horizon) For WG Consideration Power Quality  Voltage Regulation, etc --Use substation-specific power quality investments Reliability  Routine Outages--Use substation-specific reliability investments Resiliency  Major Event Outages--Use substation-specific resiliency investments Emissions  Health Impacts--Use EPA estimates and industry assumptions by local area Fuel Price Hedge  physical hedge--Exclude in initial DRP, since system-wide benefit Market-Price Suppression  reduced wholesale energy prices --Exclude in initial DRP, since system-wide benefit Societal  jobs, etc--Exclude in initial DRP, since system-wide benefit DRAFT

13 13 Generation Capacity: Incremental Local RA Definition Avoidable incremental costs incurred to procure Resource Adequacy in CAISO-identified load pockets (i.e. Local Areas) Cost Calculation Approach Use latest CAISO local capacity requirements to identify incremental capacity needs beyond utility-owned generation and identify deficient sub-areas. Examples Local RA Procurement PG&E: Needs to purchase Bay Area Local RA at a premium in area to fulfill Local RA requirements 1 DRAFT

14 14 Distribution Capacity Definition Avoidable costs incurred to increase circuit and/or substation capacity to ensure system can accommodate forecasted load growth Cost Calculation Approach Use existing utility capacity 10-year plan by substation, and/or Perform load forecasting vs. capacity analysis to forecast needed capacity upgrades Examples Substation upgrades Transformer upgrades Circuit reconductoring DRAFT 2

15 15 Power Quality Definition Avoidable costs incurred to ensure power delivered is within required operating specifications (i.e. voltage, flicker, etc) Cost Calculation Approach Use existing utility power quality investment plan by substation, or Allocate systemwide power quality investment plan according to power quality statistics (i.e. customer complaints, voltage excursions, etc) by substation/local area Examples Voltage regulation investments Capacitor banks Load Tap Changers / Line Regulators Sensing equipment Line sensors / relays DRAFT 3

16 16 Reliability (Routine outages) Definition Avoidable costs incurred to proactively prevent and mitigate routine outages, and Avoidable costs incurred in responding to routine outages Cost Calculation Approach Use existing utility reliability investment plan by substation, or Allocate systemwide reliability investment plan according to reliability statistics (i.e. SAIDI, CAIDI, SAIFI) by substation/local area Examples Investments / expenses Distribution Automation (FLISR, etc) Outage Restoration Tree Trimming DRAFT 4

17 17 Resiliency (Major Events) Definition Avoidable costs incurred to proactively harden the system in order to prevent or mitigate major or catastrophic events (e.g. earthquakes, hurricanes, flooding), and Avoidable costs incurred in responding to major or catastrophic events Risk of costs due to Local Capacity Deficiencies in local areas Cost Calculation Approach Use existing utility resiliency investment plan by substation, or Allocate systemwide resiliency investment plan according to societal lost productivity statistics by substation/local area Identify Sub-Area Local Capacity Deficiencies (according to CAISO) and attribute cost of risk to customers Examples Investments / expenses Hardening (e.g. walls) Redundant infrastructure Major Event Response Sub-Area Local Capacity Deficiency CAISO identified that the West Park Sub-area in the Kern local area has a 26 MW of deficiency of local generation in the case of a Category B contingency DRAFT 5

18 18 Local Health/Emissions Definition Societal healthcare costs caused due to local pollution Cost Calculation Approach Use forecasts of local emissions and EPA Societal Cost methodology for health impacts by local area Examples Avoided Criteria Pollutant Emissions Nox emissions SO2 Mercury VOC PM 2.5 PM 10 DRAFT 6

19 19 Next Steps Define avoided cost/benefit buckets to include in July 2015 Utility DRP optimal location analyses Develop methodology for calculating each avoided cost/benefit bucket Identify and share (as needed) data required for each analysis Develop end-to-end illustrative calculation to serve as model for utility calculations

20 Optimal Location Analysis Adaptation of E3 Aram Shumavon

21 Distribution Planning Process Alignment to IOU GRC and State Planning Processes Lorenzo Kristov

22 22 Bi-annual DPP Alignment w/CA Planning DRP Scenarios Use DER adoption scenarios to stress-test existing integration capacity and investment requests in GRC, Smart Grid Roadmaps & EPIC funding requests DRP Scenarios could show shifting RPS, bulk power, and wholesale generation to DG, and its impacts on the larger system. 3 scenarios using a) variant of LTPP “Trajectory” case, b) “High DER” customer adoption, and c) expanded policy driven preferred resources case Time horizons: 10 years at DPA level regarding scenario driven system-wide locational benefits analysis Locational benefits conducted at the distribution substation level Feeder level is too granular as the engineering options are considered at the distribution substation level for time periods >2 years Net benefit of deferral of traditional capital investment Net benefit of DER provided operational services (voltage, reactive power, etc.) Planning assumptions linked to CPUC/CEC inputs to IEPR/LTPP/TPP for consistency, but: Data and forecasts need to be more granular and linked to distribution infrastructure locations (perhaps a more local forecast required to provide data between the DPP and CEC) RA contribution from DER DER considerations for Transmission deliverability analysis Bi-annual DPP Process timing aligned with CA Joint Agency planning schedules to inform process Adapt Joint Agency planning process map elements to identify DPP and GRC linkages

23 23 DPP Process Alignment for CPUC, CAISO, CEC The new DPP should align with the LTPP-TPP-IEPR timeline Main points to consider: When is it optimal to have a new DRP, i.e., the final result of the biennial DPP, to feed into the other processes? That is, where on the alignment timeline do we want the DPP to conclude? What are the key process steps of the DPP, what is the sequence in which they must be performed, and what inputs do they require from other processes? Currently, first DRP due in July If July 2017 is the next deadline then: DRP would provide useful and timely input to the IEPR demand forecast, which is planned to be released in draft form in September 2017 and finalized by December Likely that July 2015 DPR will not be as informative for the 2015 IEPR, still we should consider to what extent it will inform that forecast. CPUC, CECS, and CAISO will collaborate between September- December 2017 to develop “assumptions and scenarios” for TPP and LTPP for cycles beginning in January Developed in consultation with Lorenzo Kristov (CAISO)

24 24 Potential DPP Alignment Map for CPUC, CAISO, CEC Refer to Lorenzo’s Handout

25 Integration Capacity Analysis (hosting capacity) Erik Takayesu

26 26 Back-up Materials

27 27 Distribution Planning Analyses (summary of prior discussions)

28 28 Distribution Planning Process (DPP) Two step approach given the short time between ruling and statutory deadline of July 1, 2015 Focus 2015 Distribution Resource Plan (DRP) on: Identifying current DER 1 “integration” capacity based on existing and near-term planned (i.e., already authorized investments) Integration capacity is not a single value, but a range of values, it varies with type of DER, level of granularity, and by location. Comparison of current integration capacity with anticipated DER growth Prototyping locational benefits analysis for one (1) Distribution Planning Area within each IOU Refine stakeholder engagement model Ongoing DPP Annual distribution system DER integration capacity updates via revised RAM maps Bi-annual DRP to include system-wide Location Benefits analysis at the substation level that could serve as input into General Rate Cases and inform IEPR/LTTP/TPP processes (Note: the DPP and LTPP/IEPR/TPP have significantly different inputs and outputs but one can inform the other) 1 Term DER includes all forms of Distributed Generation, Demand Response, Energy Storage, Electric Vehicles and Energy Efficiency

29 DRP System-wide DER integration “integration” capacity assessment Substation level DER integration capacity (minimum level) Engineering analysis based on specific locational (load/DER/feeder) information, not “15% rule” heuristics, recognizing that the unique characteristics of each feeder will determine the integration capacity to integrate DER Comparison of existing & near-term changes to integration capacity to anticipated DER growth Continue to use existing distribution system planning criteria and guidelines, including capacity to support “1-in-10” year heat event and enable adjacent circuit load carrying in the event of circuit outage Revise Renewable Auction Mechanism (RAM) maps to convey distribution system capacity for DER integration Modified RAM maps are convenient means to communicate integration capacity availability Current maps use the static 15% rule, which is no longer appropriate and will require more complete engineering analysis largely completed by IOUs Locational benefits analysis for one (1) Distribution Planning Area (DPA) as defined uniquely by each IOU 10 year scenarios (3) driven DPA locational benefits analysis More granular “Trajectory” scenario High DER growth based on customer adoption greater than trajectory Preferred resources growth based on increased use of DER to address bulk power and resource adequacy needs Locational benefits conducted at the distribution substation level Results will be used to: Validate scenario and optimal location methodology and processes Use as prototype for biennial DRP process Use to prototype stakeholder feedback on process and results

30 30 Ongoing DPP Annual updates to feeder level DER integration capacity IOUs can provide annual updates to feeder capacity and publish via modified RAM maps Compare existing integration capacity to anticipated DER growth As in 2015, the engineering analysis will be more sophisticated and will not be based on the static 15% Rule Bi-annual DRP aligned with GRCs & broader CA planning 10 year scenario driven system-wide locational benefits analysis Locational benefits conducted at the distribution substation level DRPs done by each IOU concurrently starting in 2017 Planning assumptions linked to CPUC/CEC inputs to IEPR/LTPP/TPP Bi-annual DPP Process timing aligned with GRC process and CA Joint Agency planning schedules

31 31 Distribution Resource Plan Analyses AnalysisActionScopeGranularityTimingData Req’d Integration Capacity Existing, available distribution capacity for DER interconnections 2yr Snapshot-in-time view that also reflects IOU investment plans Power flow analysis per feeder Utility to communicate via modified RAM maps 2015 & Ongoing: All distribution feeders Feeder level 2yr outlook Every year Tbd by WG Optimal Locations 10yr Scenario driven analysis Trajectory High DER Preferred Resources Based on distribution capacity & operational services, transmission capacity, generation capacity & energy, BPS ancillary services, environmental, and other avoided costs/benefits Planning assumptions linked with CPUC/CEC/IEPR/LTPP/TPP planning Utility investment plans in GRCs and other reflect DER alternatives based on scenario driven locational benefits analysis Consider customer DER growth rates independent of central planning Utility to procure DER services via programs, tariffs, RFOs, etc. Utility to identify optimal locations via RAM type maps 2015: One (1) Distribution Planning Area Ongoing: System-wide beginning in 2017 Substation level by DPA 10 yr outlook Every 2 years Tbd by WG

32 32 Optimal Location Benefits (Discussion slides from 11/18/14 F2F discussion)

33 33 Optimal Locational Benefits Methods IOU Planning for Distributed Energy Resources Discussion led by Will Speer, Erik Takayesu & Manho Yeung

34 34 Overview Distribution Resource Plan Deployment of Distributed Resources Planning Process Optimal Locations Enhanced Tools and Communication Enabling Infrastructure

35 Deployment of Distributed Resources Locational targeting DERs can accomplish two objectives: 1.Maximize reliability benefits and defer capital upgrades 2.Minimize costs and impacts of interconnection

36 36 Integrating DERs into Planning Process Distributed energy resources have impacts at each stage of the planning process Existing methods minimally incorporate DERs Objective to optimize the use of DERs while maintaining safety and reliability

37 37 Analysis of Recorded Loads Improve ability to disaggregate demand from DER impacts when analyzing recorded loads

38 38 Determine Dependability Evaluate dependability of DERs based on statistical analysis and combinations of DERs

39 39 Develop Forecast Enhance forecasting sophistication by looking at profiles of load and DERs; enabled through new forecasting tools

40 40 Optimization Optimize ability to meet forecast through coordination of DERs with infrastructure upgrades and load transfers

41 41 Optimization Coordinate DER planning with infrastructure upgrades and system reconfiguration Short term Evaluate feasibility of DER to meet distribution planning needs beyond the 5 year window Incorporate optimization by matching the profiles of DER with the peak capacity profile at a substation level Incorporate optimal locations analysis to target locations projected to require load relief Longer term – Evaluate tool capabilities for incorporation DER profiles into project planning, and optimized operational performance Forecasting of DER penetration / targets Impact on sub-transmission and transmission grid

42 42 Strategically-sited Distributed Energy Resources can provide additional value to the grid. Identifying Optimal Locations  AB 327 requires submittal of a distribution resource plan proposal to identify optimal locations for the deployment of distributed resources  Existing public interconnection maps (Fig. 1) will be refined and expanded to better facilitate strategic project siting  New layers may provide data on potential system benefits, future projects to alleviate constrained areas, etc.  A formal process for updating and maintaining data based on interconnection and planning processes will be established Figure 1: Interconnection Map Overview Optimal Locations Grid Maximize DER benefit Customer Enable choice Developer Low-cost interconnection

43 43 Optimal Locations PV benefit is low Energy storage benefit is high No project(s) in 10 year plan High utilization Priority 4Priority 2 Priority 3Priority 1 (Most Optimal Locations) PV benefit is high Energy storage benefit is moderate No project(s) in 10 year plan High utilization PV benefit is low Energy storage benefit is high Project(s) identified in 10 year plan PV benefit is high Energy store benefit is moderate Project(s) identified in 10 year plan (Low) COST(High) (Low)BENEFIT(High) Priority 5 (No tangible grid benefit) PV and energy storage benefits are low Maximum utilization is less than 80% over the 10-year plan

44 44 Improved Tools Enhanced Interconnection Maps Distribution Planning Interconnection Application Processing Distribution Circuit Modeling Grid Management System

45 45 Modernizing the Grid for Safety and Reliability Enhanced protection capabilities Decreased loading on assets reduces risk of catastrophic failure Increased situational awareness allowing for quicker response to outages and system events Increased ability to remotely operate devices allowing for improved response time

46 46 Grid Modernization Framework Monitor & Control Grid Infrastructure Grid Capabilities Communications Grid Devices Increased Monitoring & Awareness Advanced Automation Advanced Voltage Regulation Expanded Grid Communications Intelligent Grid Ops Management Real-time Grid Assessment Self Healing System External Grid Component Control 5-10 Year Year Fiber Optic Cable Licensed/Private Spectrum Enhanced Wireless Equipment High Speed Radios Field Area Network Grid Management System DVVC Demand Side Management Enhanced System Data Distribution Planning Planning Software Distribution Modeling DG Interconnection Enhanced Field Telemetry RFI RCS Capacitor Banks Substation Automation SLIMS Distributed Intelligence DER

47 47 Optimal Locational Benefits Methods Adaptation of Avoided Cost Framework for Distribution Resource Plans Discussion led by Ryan Hanley & Aram Shumavon

48 48 CPUC Avoided Cost Framework – Background Framework developed by Energy and Environmental Economics (E3) and adopted by the CPUC Originally adopted to evaluate cost-effectiveness of energy efficiency by the CPUC in 2004 (Rulemaking ) Subsequently, a Distributed Generation Cost-Effectiveness Framework was adopted by the Commission (D ) Demand Response Cost-Effectiveness Framework was adopted in 2010 Periodic updates on all three frameworks since 2010 Most recent methodology described in October 2013 study “California Net Energy Metering Ratepayer Impacts Evaluation”

49 49 CPUC Avoided Cost Framework – Component Definitions Source: CA NEM Ratepayer Impacts Evaluation, Oct 2013 (E3)

50 50 Hourly Forecast of Avoided Cost by Component

51 51 Monthly Forecast of Avoided Cost by Component Source: CA NEM Ratepayer Impacts Evaluation, Oct 2013 (E3)

52 52 Ranked Hourly Avoided Costs (Nominal $ over 20 years) Source: CA NEM Ratepayer Impacts Evaluation, Oct 2013 (E3)

53 53 Annual Forecast of Avoided Cost by Component Source: CA NEM Ratepayer Impacts Evaluation, Oct 2013 (E3)

54 54 Total Avoided Cost by Feeder/Substation (20-year NPV) Source: CA NEM Ratepayer Impacts Evaluation, Oct 2013 (E3) 20-year NPV of Electricity ($ /MWh) $4,250 $4,000 $3,750 $3,500 $3,250 $3,000 $2,750 $2,500

55 55 Potential Adoption Approach for DRPs ComponentCurrent GranularityPotential DRP Approach E3 Framework Generation Energy + LossesZonal (utility-specific for losses)Use CPUC model assumptions System CapacitySystem value (no use of LRA values)Use CPUC model assumptions Ancillary ServicesStatewideUse CPUC model assumptions CO2 EmissionsStatewideUse CPUC model assumptions Avoided RPSStatewideUse CPUC model assumptions Transmission CapacityUtility (this is only for Transmission downstream of the CAISO) Use CPUC model assumptions Distribution CapacityUtility (SCE, SDGE), climate zone (PGE), substation data was included in NEM report, but data was not made public Use Utility Capacity Projects (5-10 Yr Plans) plus CPUC assumption on Yr 10+ planning For WG Consideration Additional A/S  Volt/VAr, etc--Use industry assumptions (i.e. Sandia National Labs) Fuel Price Hedge  physical hedge--Use NREL assumptions Market-Price Suppression  reduced wholesale energy prices --Use NREL assumptions Reliability  Routine Outages--Use utility SAIDI statistics + Value of Service assumptions (Brattle Report, etc) Resiliency  Major Event Outages--Use industry assumptions (i.e. Department of Energy) Emissions  Health impacts--Use industry assumptions Societal  jobs, etc--Use industry assumptions

56 56 Methodology for Avoided Cost Component Forecasts Source: CA NEM Ratepayer Impacts Evaluation, Oct 2013 (E3)

57 57 Analysis for Integrated DER Avoided Cost study Source: Methods for analyzing the benefits and costs of distributed PV, Sept 2014, NREL

58 58 Optimal Locational Benefits Methods Integral Analytics Approach Discussion led by Dave Erickson

59 59 Source of “dotted line box” is More Than Smart Working Group: Methods for analyzing the benefits and costs of distributed PV, Sept 2014, NREL Geo-Spatial Forecasts (acre, circuit, bank) Only a geo-spatial view with econometric methods is able to forecast local, granular needs & new resources. New DERs, Commuter Rail, EV, or anything where change or locale is not in past data history. 20 Year Congestion Forecast (update LMPs) CYMEDist (by bank) Losses, Voltage, PF Limiting Factors Other Costs Local DMCs or DMPs Shadow price of the optimization/ DRP per bank for customer/ acre Optimal DER mix 10 Year Sub-hourly Modeling Local Customer/ Vendor Response Rational price response yields optimal DRP. If not, next annual DRP DMCs adjust price signals. Last resort, mandate locations for DER types. Existing Averaged Avoided Costs (E3) “Global” Anchors the local granular avoided costs Supply/Grid Used to “center” the granular DMC detail and distributions. Blending occurs at banks in most cases. AMI KW KVAR Detailed Usage & Service Transformer Analytics Local “penalty” reverse flow, granular supply cost to serve Fixed DMC/ Yr Variable DMC Sub-5 Minute DER Smart Inverters Zigbee HAN Storage Thermal Inertias, etc. Intra Hour Forecasting Overnight Reconciliation Integration of Average Costs (E3) & Local Granular Costs for an Optimal DRP Customer DER Savings Shapes Acre Level Load Forecast snaps to CYME “node” or circuit section Sharing of DER vendor plans ?

60 60 Data Types and Sharing Process

61 61 Proposed Data Types ` EDFSDG&EPGESCECal SEIANRGCESASolar CityCAISOPetra Basic demographics x Populations of electricity using equipment x EV and communical charging station populations x BUG populations and characteristics x Relevant generation production characterisitcs xx Distribution peak and load characteristics xxxxx List of distribution system expenditures x Customer class-level load patterns and expenditures x DMP and DPC (Distribution Marginal price & cost) analysis by feeder xx DG Interconnection process information x Local Capacity requirements from the annual TPP x Planning forecasts: Identifying capacity constraints xxxxx DER data - Relating to its penetration, functionality, and performance xxx Optimal Location Maps xxx Solar PV RAM Map x Real-time customer electric meter data x Parties Data Type Source: CPUC (http://www.cpuc.ca.gov/PUC/energy/Distribution_Resources_Plan_Comments.htm)

62 62 Proposed Data Types Source: CPUC (http://www.cpuc.ca.gov/PUC/energy/Distribution_Resources_Plan_Comments.htm) Available TodayAvailable Over Time Inputs Basic Demographics Populations of Electricity Using Equipment BUG population and characteristics List of distribution system expenditures DG interconnection process information EV and communication charging stations Relevant generation production characteristics Distribution peak and load characteristics Customer class level load pattern and expenditures DER data—relating to its penetration, functionality, and performance Outputs Local capacity requirements from the annual TPP Solar PV RAM map DMP and DPC (Distributed Marginal Price and Cost) analysis by feeder Planning forecasts (identifying capacity constraints) Real-time customer electric meter data Optimal location maps


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