1. Locational Net Benefit Analysis Working Group
July 26, 2016
OAKSTOP, Oakland, CA
drpwg.org

2. Agenda Time Topic 9:00-9:15 Introductions 9:15–10:15
Discussion of Stakeholder Comments
10:15-11:45
Use Case Discussion (Procurement)
11:45-12:30
Lunch
12:30 -12:45
Distribution Grid Services
12:45 –1:45
Methodology Discussion (E3)
1:45-3:15
Data and Maps
3:15 – 3:30
Summary & Next Steps

3. LNBA Working Group Background
LNBA WG Purpose- Pursuant to the May 2, 2016, Assigned Commissioner’s Ruling (ACR) in DRP proceeding (R ), the Joint Utilities are required to convene the LNBA WG to:
Monitor and Support Demonstration Project B
Improve and refine LNBA methodology
Coordinate with IDER Cost Effectiveness WG on system-level valuation activities
Coordinate with IDER Competitive Solicitation Framework WG where objectives overlap (e.g. description of grid deficiencies and performance requirements)
CPUC Energy Division role
Oversight to ensure balance and achievement of State objective
Coordination with both related CPUC activities and activities in other agencies (CEC, CAISO)
Steward WG agreements into CPUC decisions when necessary
More Than Smart role
Engaged by Joint Utilities to facilitate both the ICA & LBNA working groups. This leverages the previous work of MTS facilitating stakeholder discussions on ICA and LBNA topics.

4. Draft LNBA Working Group Schedule to Date
May 2, Assigned Commissioner Ruling on ICA and LNBA
May 12, 2016 – First Joint Utility meeting on ICA and LNBA
June 1, 2016 – First in person meeting to get input on Joint Utility Implementation plans
June 9, – In person meeting to discuss LNBA Plans
June 16, 2016 –Utilities file LNBA implementation plans to CPUC
July 2016 – Q2, 2017 – Monthly LNBA WG meetings re/LNBA implementation
Q4, 2016 – Final Demo B report due
Q4, 2016 – Long-term LNBA refinement intermediate status report due
Q2, 2017 – Utilities submit Long-term LNBA refinement final report due

5. LNBA WG Schedule - May 2nd CPUC ruling
Short Term: May 2nd – end of Q4 2016
“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”
“Consult to the IOUs on further definition of grid service, and in coordination with the IDER proceeding”
Long Term: May 2nd - end of Q2 2017
“Continue advancement and improvement of LNBA methodology, consulting to IOUs on:
Methods for evaluating location-specific benefits over a long-term horizon that matches with the offer duration of the project
Methods for valuing location-specific grid services provided by advanced smart inverter capabilities
Consideration/development of alternatives to the avoided cost method (ex: distribution marginal cost method, etc.)
IOUs shall determine a method for evaluating the effect on avoided cost of DER working “in concert” in the same electrical footprint of a substation”

6. Proposed Schedule for LNBA WG topics
Element from Ruling
time frame (short or long term)
Date IOU completed/will complete
Date(s) WG will discuss
6.1.a Recommend a format for the LNBA maps to be consistent and readable to all CA stakeholders across the utilities' service territories with similar data and visual aspects (color, mapping tools, etc.)
short term
September- December
October
6.1.b Consult to the IOUs on further definition of grid service, as described in requirement (1)(B)(iv-v) of Section above, and in coordination with IDER proceeding
August
6.2.a. Methodology advancement and improvement: Methods for evaluating location-specific benefits over a long term horizon that matches with the offer duration of the DER project
long term
6.2.b Methodology advancement and improvement: Methods for evaluating location-specific grid services provided by advanced smart inverter capabilities (see smart inverter functions ID'd by Smart Inverter Working Group)
September
6.2.c Methodology advancement and improvement: Consideration and development of alternatives to the avoided cost method, such as distribution marginal cost or other methods
July
6.2.d Methodology advancement and improvement: IOUs shall determine a method for evaluating the effect on avoided cost of DER working "in concert" in the same electrical footprint of a substation
December

7. Discussion of Stakeholder Comments

8. Stakeholder Comments DPA Selection:
Unlike PG&E and SDG&E, SCE proposes to conduct Demo B in a different DPA than the one used for Demo C (LNBA Validation). What is the rationale for this approach? Creation of the LNBA methodology and validation of the methodology should be conducted in the same DPA.

9. Stakeholder Comments Methodology:
E3’s description of its proposed methodology for calculating locational deferral value is difficult to understand, seems unnecessarily complex, and appears biased against DER. Additional discussion requested to better understand the proposed approach and how it integrates with the IOUs’ proposed approach to the LNBA.

10. Stakeholder Comments Methodology:
The proposed LNBA approaches will result in values for locational avoided costs, not locational net benefits. To calculate net benefits, the IOUs must include the costs to procure and integrate/interconnect the DER in the calculations. The IOUs have indicated that they do no intend to include the costs of the DER in Demo B.

11. Stakeholder Comments Other:
How do the IOUs envision utilizing the LNBA results to support future DER deployment? How will the IOUs integrate the LNBA results with current and future DER procurement processes?

12. Definition of Net
For Discussion Only

13. Typical Net Benefit Analysis
Total Net Benefits = NPV (Benefits) – NPV(Costs) This is not how the 5/2 ACR defines LNBA for Demo B
For Discussion Only

14. ACR Definition of LNBA for Demo B
Locational Net Benefit Analysis
Is the sum of many components
DER cost is not one of the components, but can be determined through a competitive solicitation
Each component can be positive or negative
LNBA components which exist over multiple years are expressed as a net present value
For Discussion Only

15. ACR Definition of LNBA for Demo B
Example of a negative avoided cost in LNBA:
Energy storage device which is used to reduce feeder peak load may have a negative energy avoided cost:
The device has losses
Feeder peak can occur when CAISO prices are low
Charge during high electricity prices
Discharge during low electricity prices
(+)
(-)
For Discussion Only

16. ACR Definition of LNBA for Demo B
These are “net” sums of (+) and (-) values
NPV (yr1 Σ(+, +, -), yr2 Σ(+, +, -), yr3 Σ(+, +, -)… )
This is a “net” present value
For Discussion Only

17. LNBA Use Cases
For Discussion Only

18. LNBA Use Cases Demo B For Discussion Only
Heat Map of Potential Optimal Locations
Public/Indicative
Generic OR DER Specific
No DER Costs Included
Visual heat map to inform DER providers and stakeholder of locations where DERs may be most valuable.
Prioritization for DER Deferral Opportunities (Distribution Planning)
Confidential/Commercial
DER Costs May Be Included
Use LNBA to identify & prioritize locations for deploying DERs (results may be shared with a DPAG)
Future?
Demo B
For Discussion Only

19. LNBA and Competitive Solicitations
LNBA as defined for Demo B
Does not include DER Costs
Uses public inputs (e.g. E3 energy price forecasts)
Produces indicative results
Can be DER technology-agnostic
Competitive Solicitation Bid Evaluations
Include DER Costs
Use confidential inputs (e.g. IOU energy price forecasts, DER provider offer prices)
Produces commercial results
Are specific to the technology in a DER offer
Provides an open opportunity to build DER portfolios
For Discussion Only

20. LNBA and Competitive Solicitations
LNBA is currently defined as a public analysis for informational rather than commercial purposes
Analogous to RPS Calculator and Energy Storage Common Evaluation Protocol
In competitive solicitation bid evaluations, IOUs calculate same avoided cost components as LNBA using proprietary and commercially sensitive inputs
Competitive solicitation bid evaluations are subject to non-market-participant review in Procurement Review Group (PRG)
For Discussion Only

21. LNBA Demo B Methodology
Brian Horii
Energy and Environmental Economics, Inc.
July 22, 2016

22. Agenda Background on DERAC/ACM and LNBA Avoided cost theory
Example calculations

23. DERAC/ACM and LNBA
The Distributed Energy Resource Avoided Cost (DERAC) calculator, and the Avoided Cost Model (ACM).
ACM is an update to DERAC
Calculate system-wide hourly avoided costs for each IOU
Energy and Emissions
Generation Capacity
Ancillary services
Losses
RPS adder
Local T&D Capacity
LNBA will replace the hourly Local T&D Capacity numbers with Demo B hourly values.

24. Avoided Cost Theory
LNBA will use the Real Economic Carrying Charge (RECC).
RECC used to calculate the annual economic value or “economic depreciation” of an asset.
Economic depreciation = value of deferring the asset and its future replacements by one year, in constant real dollars.
Any change in O&M costs is also included.
Economic value = Full Cost of Asset * RECC + DO&M
Full Cost of Asset = Present Value of revenue requirements associated with capital project
RECC =
(From EPRI Electric Utility Rate Design Study, How to Quantify Marginal Costs: Topic 4, 1977)

25. Calculation examples Discrete Deferral Value for one year
Deferral Value = Full Cost of Asset * RECC + DO&M
RECC Calculation
i = 2.5%, r = 7%, book life = 40 yrs
𝑟−𝑖 1+𝑟 𝑟 𝑁 𝑟 𝑁 − 1+𝑖 𝑁
RECC = 4.5%/1.07 *1.07^40/(1.07^ ^40) = 5.12%
Full Cost = Direct Capital * RRScaler = $8M * 150% = $12M
Deferral Value = $12M * 5.12% + $0.20M = $0.81M

26. Deferral Value for more than one year
RECC-based deferral values escalate with inflation each year.
Discounting the stream of annual deferral values yields the total present value of a multi-year deferral.
𝑫𝒆𝒇𝒆𝒓𝒓𝒂𝒍 𝑻 = 𝒚=𝟏 𝑻 𝑺𝒂𝒗𝒊𝒏𝒈𝒔𝑶𝒏𝒆 𝟏+𝒊 𝟏+𝒓 𝒚−𝟏
SavingsOne = Deferral value savings in the first year = $0.815M
Two year deferral = $0.815M + $0.815M *(1.025/1.07) = $1.6M

27. Demo B may include a range of cost values
Low, Medium, and High estimates for the same project

28. Avoided Cost can be Expressed in Multiple Ways
Prior examples showed the avoided cost as total dollar savings.
Other methods are
$/kW. Value normalized based on the amount of peak reduction needed to attain the deferrals
$/kW-yr. Value annulaized over multiple contract years
$/kW Avoided Cost for a Two Year Deferral

29. Effect of Uncertainty in MW need
Uncertainty in the MW needed for deferral increases the range of avoided cost results
High MW need is applied to Low Value case
Low MW need is matched to High Value case.

30. Avoided Cost in $/kW-yr
$/kW-yr take prior values and annualize them over a set period of years.
Useful for comparison to traditional DERAC/ACM T&D capacity costs, or for use in commercial contracts.
Annualization could use either a nominal or real discount rate.
For comparison to DERAC/ACM, a real discount rate would be used.
For commercial purposes, a real discount rate would be used if the payment value were to increase annually with inflation. If the payment were to be constant in nominal dollars, the nominal discount rate should be used.
Example using a 10 yr contract period and nominal discount rate

31. Treatment of Project Layers
DER may be able to affect multiple projects.
The LNBA tool will total the value for all upstream projects that DER could impact.
Note that the timing of the need for peak reductions could vary for the upstream projects, so a local resource may not be able to attain a full sum of the individual avoided cost values.
Also note that it may be more difficult for an IOU to achieve deferral of upstream projects because of the often higher peak reductions needed for such projects.

32. Peak Need Timing
LNBA Tool will also have the ability to allocate T&D capacity costs to hours of the year.
Allocating the costs to hours allows for probabilistic estimates of peak reductions from DER.
The exact methods are still under discussion.
Peak month/hour
Threshold-based peak period
Uniform weights vs proportional to load
The LNBA Tool will also include tools to reorder days based on weather and chronology so that data from unmatched years can be synchronized.

33. Threshold-based Allocation
Based on T&D loads
Identifies the peak period as all hours where load is above the threshold
Also known as PCAF method
For proportional weights
For uniform weights

34. Distribution Services, Attributes and Performance and Measurement Requirements
Subteam 1a
Competitive Solicitations Framework Working Group Meeting Integrated Distributed Energy Resources Proceeding
Mark Esg
uerra

35. Integrated Distribution Planning Process Framework
Topics to Cover
Integrated Distribution Planning Process Framework
Definition of Basic Distribution Services
Distribution Service Attributes
Performance Requirements 2

36. Integrated Distribution Planning Framework
Distribution Resources Plan (DRP) Integrated Distributed Energy Resources
(IDER)
1 4 5
2 3
Distribution Planning Assessment
Assumptions, Scenarios & Scope
Distribution Grid Needs
Evaluate Options
Sourcing
Develop forecasts, assumptions and planning scenarios.
Distribution Grid Studies
Distribution Grid Needs
Prioritize Grid Needs
Sourcing Process to satisfy needs identified in DRP
Load Serving Capacity
DER Hosting Capacity
DER Aggregator Requirements
Coordination with
Transmission Planning
Distribution Capacity
Voltage Support Requirements
Protection
Safety and Reliability
Investment framework/technical feasibility
Demand forecasts
DER forecasts
DER Growth Scenarios
Implement “Wires” alternatives for locations deemed infeasible for DERs 3 2 4 1 55
- Mendocino Old Kearney 3 - Point Arena
- Shingle Springs Molino
Overall Substation Location Map
Implement “Wires” Solution 3

37. Definitions of Basic Distribution Services
Distribution Capacity
Load modifying or supply services that DERs provide via dispatch of power output (MW) or reduction in load that is capable of reliably and consistently reducing net loading on desired distribution infrastructure.
Voltage Support
(Voltage control through real and/or reactive power)
Improved steady-state voltage to avoid voltage related investment. Dynamic voltage management to keep secondary and primary voltage within Rule 2 limits.
Reliability (Back-Tie)
Load modifying or supply service capable of improving local distribution reliability and/or resiliency. Service provides fast reconnection and availability of excess reserves to reduce demand when restoring customers during abnormal configurations.
Resiliency (Microgrid)
Load modifying or supply service capable of improving local distribution reliability and/or resiliency. Service provides fast reconnection and availability of excess reserves to reduce demand when restoring customers during abnormal configurations. Service also provides power to islanded end use customers when central power is not supplied and reduce duration of outages.

38. Distribution Service Attributes
Locational Specificity of Distribution Services
Level or Magnitude of Required DER
Response
Timing and Duration of DER Response
DER Availability and Assurances

39. Performance Requirements
System Availability
Data Availability
Response Time
Quality of Response

40. APPENDIX

41. Distribution Planning Assessment Assumptions, Scenarios & Scope
Distribution Grid Needs 3
Hypothetical examples of Distribution Service
Attributes 1 2 3
4 5
Distribution Planning Assessment
Assumptions, Scenarios & Scope
Distribution Grid Needs
Evaluate Options
Distribution Portfolio

42. Distribution Capacity: Substation Transformer Overload
Distribution Grid Need
An MW rated substation transformer is forecasted to overload in the summer months.
Substation transformer capacity deficiency is determined to be:
‒ 1.4 MW by 2019
‒ 2.6 MW by 2020
‒ 3.6 MW by 2021
Traditional “wires” solution is to replace existing or install an additional transformer, after exhausting available capacity through field switching onto adjacent distribution feeders.

43. Distribution Capacity: Substation Transformer Overload
Potential DER Solution for Overload Need:
Attributes of DER performance must match overload issue attributes to provide relief of capacity constraint
Other attributes of DERs must address grid issues stemming from DERs
providing relief of capacity constraint (e.g. ramp rate)
DER Attributes to Procure
YEAR
2017
2018
2019
2020
2021
Distribution Capacity Need (MW) -
1.4
2.6
3.6
Distribution Capacity Need (MVAr)
Months when needed
Aug-Sept
July-Sept
Days when needed
Mon-Fr
Time when needed
16:00-19:00
15:00-20:00
14:30-20:30
Duration (hours/day) 3 5 6
Frequency of Need (days/month) 1

44. Voltage Support Services: Steady State Under Voltage
Forecast Under Voltage Issue:
A pump station customer is planning to convert two pumps from diesel to electric by 2020
Rule 2 Limit
The pumps will add an extra 1 MW to peak load condition. Customer is located close to the end of a radial feeder M
Projected under voltage conditions near the end of the feeder is found to occur around forecasted peak loading times
Rule 2 Limit

45. Voltage Support Services: Steady State Under Voltage
Potential DER Solution for Overload Need:
Attributes of DERs should match under voltage issue attributes to stay within Rule 2 voltage thresholds (±5% of nominal voltage)
Attributes of under voltage issue
Needed voltage changes (ΔV) to stay within Rule 2 limits
Locations where under voltage occur
Times and duration when under voltages occur
Other attributes of DERs must address grid issues stemming from DERs providing
voltage support (e.g. ramp rate)
DER Attributes to Procure YEAR
Distribution Capacity Need (kW)
Distribution Capacity Need (kVAR) at lagging PF 60 at lagging PF Duration (hours/day)
Frequency of need (days/month) 8 8
Time Needed 17:00-20:00 17:00-20:00
Days Needed Mon-Fr Mon-Fr
Months Needed June-July May-July
Electrical Proximity from Voltage Issue
- - -
0.5 Circuit Miles of SPID 77943XXXXX
0.5 Circuit Miles of SPID 77943XXXXX
Ramp Rate (kW/min)
N/A
N/A 12

46. Voltage Support Services: Steady State Under Voltage
Location Matters: G M
Almost Identical Voltage Profile when Compared to no DER Scenario
Rule 2 Limit GM
Voltage is Back within Rule 2 Limits
Rule 2 Limit 13

47. Demo B Mapping
For Discussion Only

48. ACR Requirements
“LNBA results shall be made available via heat map, as a layer along with the ICA data in the online ICA map.” (pg. 32, (1))
“The electric services at the project locations shall be displayed in the same map formats as the ICA, or another more suitable format as determined in consultation with the working group.” (pg. 32, 4.4.2(1))
“The DER growth scenario used in the distribution planning process for each forecast range should be made available in a heat map form as a layer in conjunction with the ICA layers identified earlier.” (pg. 32, 4.4.2(2)a)
For Discussion Only

49. Demo B Map Use the same line segmentation as the ICA map
Demo B map will display only deferrable projects
Deferrable projects would be defined by work done in the IDER proceeding Distribution Services Subteam
Due to the selection of the primary analysis (Table 2, pg ), areas with no deferrable projects would result in the same, system-wide avoided cost
To show the impacts of the DER growth scenarios coupled with LNBA results, each DER growth scenario would be a user selectable layer on the map
For Discussion Only

50. Demo B Map LNBA Results [GR2-Near-Term] Click here to get addl. detail
LNBA Results [GR1-Mid-Term]
Growth Scenario 1
Set of Layers
LNBA Results [GR1-Long-Term]
-Need a layer for each DER?
-One layer with sum of DER MW?
-One layer with peak MW DER impact?
-Need a layer for 3 time horizons?
DER Penetration [GR1]
Growth Scenario 2
Set of Layers
For Discussion Only

51. Demo B Map – Discussion Topics
The ACR requires the utilities to determine the LNBA for the DER growth scenarios. As mentioned in previous WG, these are not real projects at this point.
Is it more valuable to use the utilities’ base forecasts to determine LNBA instead of one or both prescribed growth scenarios?
The ACR specifies three time frames: near term, intermediate and longer term, should this be the basis for displaying projects on the LNBA Map?
If DER growth forecasts are to be displayed on heat map, what level of granularity?
For Discussion Only

52. Summary & Next Steps