Download DRP Analysis – MTS Discussion Deck

MTS Working Group
San Francisco F2F Agenda
Mar. 23, 2015
Agenda
Morning (9a-12n)
• Opening & Introductions - Paul De Martini
• DRP Methodology - Mark Esquerra
• DPP Alignment - Lorenzo Kristov
12n - 1p Lunch
Afternoon (1-3:30p)
• 2015 Plan - Paul De Martini
• CA Proceedings (Technical Alignment) - All
• Next Steps
Morning & afternoon breaks as needed
2
2
Optimal Location Values & Methodology
Subgroup Objective
Develop a unified locational net benefits methodology for
the values identified in CPUC final guidance consistent
across all three Utilities.
• Discuss interpretations of final guidance
• Discuss quantification method for each DER benefit category
• Gain alignment on overall locational benefits methodology
Subgroup included representatives from the three CA IOUs
(PG&E, SCE, SDG&E), SolarCity and Kevala Analytics.
4
4
Not Required for
“Walk” Phase
MTS Identified Value Components
7
7
MTS Recommendations for Initial DRP
8
8
Final Guidance from Commission on Optimal
Location Benefit Analysis
• IOU Unified Locational Net Benefits methodology
‒ Based on E3 Cost-Effectiveness Calculator, but enhanced to include
following location-specific values (minimum):
# Minimum Value Components to include in Locational Net Benefit Methodology
1 Avoided Sub-Transmission, Substation and Feeder Capital and Operating Expenditures
2 Avoided Distribution Voltage and Power Quality Capital and Operating Expenditures
3 Avoided Distribution Reliability and Resiliency Capital and Operating Expenditures
4 Avoided Transmission Capital and Operating Expenditures
5 Avoided Flexible Resource Adequacy (RA) Procurement
6 Avoided Renewables Integration Costs
7 Any societal avoided costs which can be clearly linked to the deployment of DERs
8 Any avoided public safety costs which can be clearly linked to the deployment of DERs
9
9
Comparison of Final Guidance and MTS
Recommendations
# Final Commission Guidance
MTS Recommendations for Initial DRP
Does Final Guidance aligns with MTS
Recommendations? (Yes/No)
Avoided Sub-Transmission, Substation and
Feeder Capital and Operating Expenditures
Avoided Distribution Voltage and Power
2
Quality Capital and Operating Expenditures
Sub transmission, Substation and Feeder
Capacity
Yes
1
Avoided Distribution Reliability and
3 Resiliency Capital and Operating
Expenditures
4
Distribution Power Quality + Reactive Power Yes
Distribution Reliability + Resiliency
Avoided Transmission Capital and Operating
Transmission Capacity
Expenditures
Avoided Flexible Resource Adequacy (RA)
5
Procurement
Local Area Resource Adequacy
6 Avoided Renewables Integration Costs
7
Any societal avoided costs which can be
clearly linked to the deployment of DERs
8
Any avoided public safety costs which can be
Distribution Safety
clearly linked to the deployment of DERs
9
Emissions
10 + Losses
Transmission Congestion
Yes. Also, MTS defines Resiliency
capital/operating expenditures to be work
needed to meet requirements that are
above/beyond current distribution planning
criteria to address critical events that have a
high level of impact coupled with a high
probability of occurrence.
Yes
No. Flexible RA is a system value. MTS
recommends Local Capacity Requirement
values.
No. Renewables Integration Costs are
calculated at a system level.
No. MTS narrowed the societal benefits to
Emissions, while Final Guidance is more
broad and encompassing.
No. Final guidance focuses on public safety
costs, while MTS focuses on distribution
grid safety costs.
No. Final guidance does not explicitly
10
include transmission congestion + losses.
E3 Cost Effectiveness Methodology
• Utilize Distributed Energy Resources Avoided Cost Model
(DERAC)
• Current DERAC model has system values that may need to be
modified/replaced with locational specific values.
Avoided Cost Components in DERAC
Component
Basis of Annual Forecast
Basis of Hourly Shape
Generation Energy
Forward market prices and the
$/kWh fixed and variable operating
costs of a CCGT.
Historical hourly day-ahead market
price shapes from MRTU OASIS
Losses
System loss factors
Generation Capacity
Residual capacity value a new
simple-cycle combustion turbine
Top 250 CAISO hourly system loads.
Ancillary Services
Percentage of Generation Energy
value
Directly linked with energy shape
T&D Capacity
Marginal transmission and
distribution costs from utility
ratemaking filings.
Hourly temperature data
Environment
Synapse Mid-Level carbon forecast
developed for use in electricity
sector IRPs
Directly linked with energy shape
with bounds on the maximum and
minimum hourly value
Avoided RPS
Cost of a marginal renewable
resource less the energy market and
capacity value associated11
with that
resource
Flat across all hours
11
Proposed Locational Benefits Methodology
12
12
Discussion of Valuation Method from 3/12 Mtg
E3 DERACT
Component
Basis of Annual Forecast
Basis of Hourly Shape
Generation Energy
Forward market prices and the
$/kWh fixed and variable operating
costs of a CCGT.
Historical hourly day-ahead market
price shapes from MRTU OASIS
Losses
System loss factors
Generation Capacity
Residual capacity value a new
simple-cycle combustion turbine
Top 250 CAISO hourly system loads.
Ancillary Services
Percentage of Generation Energy
value
Directly linked with energy shape
T&D Capacity
Marginal transmission and
distribution costs from utility
ratemaking filings.
Hourly temperature data
Environment
Synapse Mid-Level carbon forecast
developed for use in electricity
sector IRPs
Directly linked with energy shape
with bounds on the maximum and
minimum hourly value
Avoided RPS
Cost of a marginal renewable
resource less the energy market and
capacity value associated with that
resource
Flat across all hours
13
MTS Recommendations
No Change
13
Avoided Sub-transmission, Substation and Feeder
Capital & Operating Expenses
• Definition
• Avoidable costs incurred to increase capacity on subtransmission, substation and/or distribution feeders to ensure
system can accommodate forecast load growth
• Cost Calculation Approach
• Use existing utility capacity 10-year plans by substation and/or
• Perform load forecasting vs. capacity analysis to forecast needed
capacity upgrades
• Benefit/Avoided Cost is value of deferring capacity work
• Examples
• Substation upgrades
• Transformer upgrades
• Distribution feeder reconductoring/reconfiguration
14
14
Avoided Distribution Voltage and Power Quality
Capital and Operating Expenses
• 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
• Perform load forecasting vs. voltage/power quality analysis to
forecast needed voltage/power quality upgrades
• Benefit/Avoided Cost is value of deferring voltage/power quality work
• Examples
• Voltage regulation investments
15
15
Avoided Distribution Reliability and Resiliency Capital
and Operating Expenses
• Definition
• Avoidable costs incurred to proactively prevent/mitigate routine
outages (reliability) and major outages (resiliency)
• Avoidable costs incurred in responding to routine outages
(reliability) and major outages (resiliency)
• Distribution Resiliency costs defined as spending needed to meet reliability
expectations that are above/beyond distribution planning criteria to address
major outage events.
• 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
• Benefit/Avoided Cost is value of deferring reliability/resiliency work
• Examples
• Investments / expenses
• New/Upgraded Distribution feeders
• Microgrids
16
16
Avoided Transmission Capital and Operating
Expenses
• Definition
• Avoidable costs incurred to increase capacity on transmission line
and/or substations to ensure system can accommodate forecast
load growth
• Cost Calculation Approach
• Use existing CAISO TPP plan by substation and/or
• Perform load forecasting vs. capacity analysis to forecast needed
capacity upgrades
• Benefit/Avoided Cost is value of deferring transmission capacity work
• Examples
•
•
•
•
Substation upgrades
Transformer upgrades
Transmission line reconductoring/reconfiguration
Voltage regulation investments
17
17
Avoided Flexible Resource Adequacy Procurement
•Flexible RA determined at system level.
• Instead of Flexible RA, recommend using Local RA.
• Alternate Definition (Avoided Local RA Procurement)
• Avoidable incremental costs incurred to procure Resource
Adequacy (RA) in CAISO-identified local areas (e.g. LCR)
• Cost Calculation Approach
• Use latest CAISO local capacity requirements to identify
incremental capacity needs beyond current generation and
identify deficient sub-areas.
• Benefit/Avoided Cost is value of deferred Local Capacity or transmission
• Examples
• Local RA Procurement
• PG&E: Needs to purchase Bay Area Local RA at a premium in area to
fulfill Local RA requirements
18
18
Avoided Renewable Integration Costs
•Renewable Integration determined at system level. Not
location specific
• Definition
• Avoidable incremental costs to integrate renewables onto electric
system.
• Cost Calculation Approach
• Current cost calculation is an interim method for calculating
renewable integration costs at a system level, which is to be
replaced in 2015.
• Utilities to coordinate efforts with development of the updated RPS
Calculator and Renewables Integration Charge to factor in locational
specific values
19
19
Societal Avoided Costs
• Definition
• Avoidable incremental costs that are borne by the public, as well
as environmental benefits (improvements in air and water quality
and land impacts) that can be clearly linked to deployment of
DERs.
• Cost Calculation Approach
• Until more data is available in this area, qualitatively describe the
Societal Avoided Costs –
• Potentially use CalEnviro Screening tool
• In some cases, DERs impose costs on society, such as increased
taxes for those not participating with DERs
Examples
• Criteria Pollutant Emissions/Local Air Assessments/ Health
Impacts
20
20
Avoided Public Safety Costs
• Definition
• Avoidable incremental public safety related costs that can be
clearly linked to deployment of DERs.
• Cost Calculation Approach
• Until more data is available in this area, qualitatively describe the
Public Safety Benefits
• In some cases DER could potentially increase costs and hazards
for safety related items
21
21
Recommendations
• Utilize E3’s DERACT as starting point
• Review and compare T&D deferral benefit calculations among the IOUs
• Develop criteria/service terms for DERs regarding deferring T&D Projects
• Flexible RA will be incorporated in methodology as a system value
• Generation related integration costs incorporated using interim integration
adder adopted by CPUC – System value
• Locational RA will be included to the extent a DER solution can address this
requirement
• Societal & Public Safety will be included as qualitative factors unless
quantitative data is available.
• For all categories, DERs will sometimes increase cost. Net Benefit will account
for any increased costs.
22
22
Distribution Planning Process Alignment
w/State Planning & Regulatory Processes
Potential DPP Alignment Map w/CA Planning
Refer to Lorenzo’s Handout
24
24
Potential DPP Alignment w/GRCs
Refer to Lorenzo’s Handout
25
25
2015 MTS WG Scope
2015 Activity
• Support utility development of July filings related to DRP, data,
demonstrations and state planning alignment as requested
• Define services (incl. functional requirements) for deferred capital,
voltage/reactive power management and reliability/resilience. Plus
identify procurement methods (e.g., RFPs, tariffs, other) related to these
services
• Define incremental operational functions to integrate and optimize DER
related to the values identified in the CPUC final guidance. This includes
identifying technology and new processes leveraging industry practices
and CA developments (incl. measurement, information protocols, etc.)
• Facilitate dialog with California EE/DR community to discuss methods
and practice to align utility program design with operational needs
27
27