MTS Working Group
San Francisco F2F Agenda
Dec. 9, 2014
Agenda
9:00-9:05a
Introductions
9:05-9:30a
Summary of Prior Discussions & Objectives for Meeting
9:30-12:00n
Optimal Locational Benefits
• Presentation 1: Ryan Hanley
• Presentation 2: Aram Shumavon
12:00-12:30n
Lunch break
12:30-1:30p
Optimal Location Benefits
1:30-2:30p
Distribution Process Planning Alignment
• Presentation 3: Lorenzo Kristov
2:30-3:30p
Integration Capacity Planning
• Erik Takayesu
3:30-4:00p
Wrap-up & Next Steps
Morning & afternoon breaks as needed
2
2
Optimal Location Benefits Methodology
3
3
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 commissionapproved 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
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4
Optimal Analysis
Optimal analysis based on cost minimization of:
• Planning objectives
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Reliability
Environmental
Policy goals
Safety
Load serving capacity
•
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Asset utilization
Affordability and cost objectives
Resiliency and cyber security
Customer choice
Streamlined interconnection processes
• Societal objectives
• 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
•
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System stability
Limits of steady-state analysis
Inability to account for uncertainty
Protection
Power Quality (voltage, etc)
• System Constraints
Thermal Limits
Existing system capacity
Operating flexibility
Assets and their
depreciation/age
• Institutional constraints
• Technology constraints
5
5
Evolution of DRP Optimal Location Benefits Analysis
• What are the immediate benefit categories that can reasonably be evaluated
within the next 3 months for the first DRP?
No. of Benefit Categories &
Sophistication of Analysis
• What are the next logical set (and data and tools needed) for systemwide DRPs?
Run
Jog
Walk
2015-1H 2016
Systemwide DRPs incl.
Locational Societal Benefits
Systemwide DRP including LTPP
& TPP locational benefits
Visibility & Initial DPA Locational Benefits
2H 2016-2019
2020+
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6
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
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7
Avoided Cost Approach for
Optimal Location Analysis
Ryan Hanley
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).
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9
DRAFT
Analysis Process (Proposed)
Perform Planning
Analyses
Calculate Potential
Avoided Costs
$14
Potential Avoided Costs
Rank Substations by
Avoided Cost
$14
$12
$12
$10
$10
$8
$8
Millions
Millions
Identify DPA &
Substations
$6
$6
$4
$4
$2
$2
$-
Avoided Cost /
Substation
$-
Substation 1
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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, 2nd 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)
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11
Potential Avoided Cost Approach for DRPs
Calculate potential avoided costs/benefits in 6 categories
Component
Current Granularity
Potential DRP Approach
Generation Energy + Losses
Zonal (utility-specific for losses)
Exclude in initial DRP, since system-wide benefit
Generation Capacity
System value (no use of LRA values)
Add Incremental Local RA
Wholesale Ancillary Services
Statewide
Exclude in initial DRP, since system-wide benefit
CO2 Emissions
Statewide
Exclude in initial DRP, since system-wide benefit
Avoided RPS
Statewide
Exclude in initial DRP, since system-wide benefit
Transmission Capacity
Utility (this is only for Transmission
downstream of the CAISO)
Exclude in initial DRP, since system-wide benefit
2
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)
3
Power Quality  Voltage
Regulation, etc
--
Use substation-specific power quality
investments
4
Reliability  Routine Outages
--
Use substation-specific reliability investments
5
Resiliency  Major Event Outages
--
Use substation-specific resiliency investments
6
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
E3 Framework
1
For WG Consideration
DRAFT
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12
1
Generation Capacity: Incremental Local RA
DRAFT
• 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
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2
DRAFT
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
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14
3
DRAFT
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
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15
4
Reliability (Routine outages)
DRAFT
• 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
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5
Resiliency (Major Events)
DRAFT
• 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
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6
DRAFT
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
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•
•
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Nox emissions
SO2
Mercury
VOC
PM 2.5
PM 10
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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
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Optimal Location Analysis
Adaptation of E3
Aram Shumavon
Distribution Planning Process Alignment
to IOU GRC and State Planning Processes
Lorenzo Kristov
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
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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 2015. 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 2017.
• 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 SeptemberDecember 2017 to develop “assumptions and scenarios” for TPP and
LTPP for cycles beginning in January 2018.
Developed in consultation with Lorenzo Kristov (CAISO)
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Potential DPP Alignment Map for CPUC, CAISO, CEC
Refer to Lorenzo’s Handout
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Integration Capacity Analysis
(hosting capacity)
Erik Takayesu
Back-up Materials
26
Distribution Planning Analyses
(summary of prior discussions)
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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 DER1 “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
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2015 DRP
• System-wide DER integration “integration” capacity assessment
• Substation level DER integration capacity (minimum level)
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•
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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
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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
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•
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•
•
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
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Distribution Resource Plan Analyses
Analysis
Action
Scope
Granularity Timing
Data 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
• Substation
level by DPA
• 10 yr
outlook
• Every 2
years
• Tbd by WG
Ongoing:
• System-wide
beginning in
2017
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Optimal Location Benefits
(Discussion slides from 11/18/14 F2F discussion)
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Optimal Locational Benefits Methods
IOU Planning for Distributed Energy Resources
Discussion led by Will Speer, Erik Takayesu & Manho Yeung
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Overview
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•
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•
•
•
Distribution Resource Plan
Deployment of Distributed Resources
Planning Process
Optimal Locations
Enhanced Tools and Communication
Enabling Infrastructure
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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
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
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Analysis of Recorded Loads
Improve ability to disaggregate demand from DER impacts when
analyzing recorded loads
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Determine Dependability
Evaluate dependability of DERs based on statistical analysis
and combinations of DERs
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Develop Forecast
Enhance forecasting sophistication by looking at profiles of load
and DERs; enabled through new forecasting tools
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Optimization
Optimize ability to meet forecast through coordination of DERs with
infrastructure upgrades and load transfers
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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
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Identifying Optimal Locations
Strategically-sited Distributed Energy Resources can provide
additional value to the grid.

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
Customer
• Enable choice
Grid
Developer
• Maximize DER
benefit
• Low-cost
interconnection
Optimal
Locations
Figure 1: Interconnection Map Overview
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Priority 4
• PV benefit is low
• Energy storage benefit is high
• No project(s) in 10 year plan
• High utilization
Priority 2
Priority 3
Priority 1 (Most Optimal Locations)
•
•
•
•
•
•
•
•
•
•
PV benefit is low
Energy storage benefit is high
Project(s) identified in 10 year plan
(Low)
COST
(High)
Optimal Locations
PV benefit is high
Energy storage benefit is moderate
No project(s) in 10 year plan
High utilization
(Low)
PV benefit is high
Energy store benefit is moderate
Project(s) identified in 10 year plan
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
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Improved Tools
•
•
•
•
•
Enhanced Interconnection Maps
Distribution Planning
Interconnection Application Processing
Distribution Circuit Modeling
Grid Management System
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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
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Grid Modernization Framework
Grid Infrastructure
Monitor & Control
• Grid Management
System
• DVVC
 Distribution Modeling
 DG Interconnection
Communications
Grid Capabilities
2 - 5 Year
• Distribution Planning
 Planning Software
• Demand Side
Management
Increased Monitoring & Awareness
• Fiber Optic Cable
Advanced Automation
• Licensed/Private
Spectrum
• Enhanced Wireless
Equipment
 High Speed Radios
 Field Area Network
Advanced Voltage Regulation
Expanded Grid Communications
Grid Devices
Intelligent Grid Ops Management
5-10 Year
• Enhanced System Data
• Enhanced Field
Telemetry
Self Healing System
 RFI
External Grid Component Control
 RCS
 Capacitor Banks
Real-time Grid Assessment
46
• Substation Automation
• SLIMS
• Distributed Intelligence
• DER
46
Optimal Locational Benefits Methods
Adaptation of Avoided Cost Framework for Distribution Resource Plans
Discussion led by Ryan Hanley & Aram Shumavon
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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 04-04-025)
• Subsequently, a Distributed Generation Cost-Effectiveness Framework was
adopted by the Commission (D. 09-08-026)
• 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”
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CPUC Avoided Cost Framework – Component Definitions
Source: CA NEM Ratepayer Impacts Evaluation,
Oct 2013 (E3)
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Hourly Forecast of Avoided Cost by Component
50
Monthly Forecast of Avoided Cost by Component
Source: CA NEM Ratepayer Impacts Evaluation,
Oct 2013 (E3)
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Ranked Hourly Avoided Costs (Nominal $ over 20 years)
Source: CA NEM Ratepayer Impacts Evaluation,
Oct 2013 (E3)
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Annual Forecast of Avoided Cost by Component
Source: CA NEM Ratepayer Impacts Evaluation,
Oct 2013 (E3)
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53
Total Avoided Cost by Feeder/Substation (20-year NPV)
$4,250
20-year NPV of Electricity ($ /MWh)
$4,000
$3,750
$3,500
$3,250
$3,000
$2,750
$2,500
Source: CA NEM Ratepayer Impacts Evaluation,
Oct 2013 (E3)
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For WG Consideration
E3 Framework
Potential Adoption Approach for DRPs
Component
Current Granularity
Potential DRP Approach
Generation Energy + Losses
Zonal (utility-specific for losses)
Use CPUC model assumptions
System Capacity
System value (no use of LRA values)
Use CPUC model assumptions
Ancillary Services
Statewide
Use CPUC model assumptions
CO2 Emissions
Statewide
Use CPUC model assumptions
Avoided RPS
Statewide
Use CPUC model assumptions
Transmission Capacity
Utility (this is only for Transmission
downstream of the CAISO)
Use CPUC model assumptions
Distribution Capacity
Utility (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
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
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Methodology for Avoided Cost Component Forecasts
Source: CA NEM Ratepayer Impacts Evaluation,
Oct 2013 (E3)
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Analysis for Integrated DER Avoided Cost study
Source: Methods for analyzing the benefits and
costs of distributed PV, Sept 2014, NREL
57
Optimal Locational Benefits Methods
Integral Analytics Approach
Discussion led by Dave Erickson
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58
Integration of Average Costs (E3) & Local Granular Costs for an Optimal DRP
Detailed Usage & Service
Transformer Analytics
Local “penalty” reverse flow,
granular supply cost to serve
Overnight Reconciliation
AMI
KW KVAR
Customer DER
Savings Shapes
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.
Fixed DMC/ Yr
Variable DMC
CYMEDist
(by bank)
Losses, Voltage, PF
Limiting Factors
Other Costs
Acre Level Load
Forecast snaps to
CYME “node” or
circuit section
Sharing of DER
vendor plans ?
Local DMCs or DMPs
Shadow price of the
optimization/ DRP per
bank for customer/ acre
Sub-5 Minute DER
Smart Inverters
Zigbee HAN Storage
Thermal Inertias, etc.
Intra Hour Forecasting
Optimal DER mix 10 Year
Sub-hourly Modeling
20 Year
Congestion
Forecast
(update LMPs)
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.
Source of “dotted line box” is More Than Smart Working Group:
Methods for analyzing the benefits and costs of distributed PV, Sept 2014, NREL
59
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.
Data Types and Sharing Process
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60
Proposed Data Types
Parties
EDF
`
Basic demographics
Populations of electricity using equipment
EV and communical charging station populations
BUG populations and characteristics
Relevant generation production characterisitcs
Distribution peak and load characteristics
SDG&E
x
x
x
x
x
x
PGE
SCE
x
Cal SEIA
Customer class-level load patterns and expenditures
CESA
Solar City
x
CAISO
Petra
x
x
x
x
List of distribution system expenditures
Data
Type
NRG
x
DMP and DPC (Distribution Marginal price & cost) analysis
by feeder
x
x
x
x
DG Interconnection process information
Local Capacity requirements from the annual TPP
Planning forecasts: Identifying capacity constraints
x
DER data - Relating to its penetration, functionality, and
performance
x
x
Optimal Location Maps
x
x
x
x
x
x
x
x
x
Solar PV RAM Map
x
Real-time customer electric meter data
Source: CPUC (http://www.cpuc.ca.gov/PUC/energy/Distribution_Resources_Plan_Comments.htm)
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61
Proposed Data Types
Available Today
Available 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
•
•
•
•
Source: CPUC (http://www.cpuc.ca.gov/PUC/energy/Distribution_Resources_Plan_Comments.htm)
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62