1. Integrated Capacity Analysis Working Group
January 20, 2017
In-person meeting
drpwg.org

2. Agenda Time Topic 9:00 – 9:10 9: 10 – 11:00 11:00 – 12:00 12:00
Introduction, Review of Schedule
9: 10 – 11:00
Follow-up discussion on ICA methodology
Review of ORA 12 success criteria
11:00 – 12:00
Discussion of Recommendations
Consider prioritization of ICA long-term refinement items
12:00
E. Lunch

3. ICA and LNBA Working Group Background
ICA and 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 ICA and LNBA WG to:
Refine ICA and LNBA Methodologies and Requirements
Authorize Demonstration Project A and Project B
CPUC Energy Division role
Oversight to ensure balance and achievement of State objective (ensure adequate stakeholder representation in consensus statements, keeping WG activities on track with Commission expectations/needs, demonstration project results review, quality control on deliverables)
Coordination with both related CPUC activities and activities in other agencies (IDER CSF WG, CEC and CAISO interagency matters, interconnection/Rule 21/SIWG, other proceedings that may impact or be impacted by locational value calculation such as AB 350/IRP and LTPP/TPP/RPS)
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. Schedule Date Short Term Long Term Refinements IOU Implementation
February XX
WG Report filed
March
Begin LT Refinement Discussions
May? June?
Estimate: PD Issued
July
Estimate: Decision
Begin implementation (12 months)
September
Begin drafting report
November
Final LT Refinement report filed
July 2018
First round implementation complete
August 2018
Begin implementation of LT refinements

5. Follow-up items from 1/17 meeting
Written explanation of what other reasons a no-backflow screen might need to be used beyond operational flexibility (Ex: for some voltage control devices, how the screen would apply if it was used just for those cases) (priority for 1/20)
Computing cost and time estimates: outline of IOU discussion strategy with CYME/SYNERGI (priority for 1/20) 
Specific discussion on planning use case (ex: targeted grid modernization updates) (priority for 1/20) 
More detail on operational flexibility alternatives (including for SCE - more detail on "planned loading limit" described in GRC) (priority for 1/20) 
Development of common methodology table (priority for 1/20) 
Proposed options for hourly profiles (24, 48, 576, etc.) - benefits and trade-offs (priority for 1/20) 
PG&E specific: written explanation of policy on sharing KML file data
Written explanation of current applications of preexisting conditions
Written explanation of differences among IOUs with regarding to modeling common bus
PG&E and SDG&E to finalize functional maps this week 

6. ORA: proposed 12 success criteria
Background on ORA proposed figure for ICA WG report
The August 23 ACR states "ORA’s proposed twelve (12) criteria or metrics of success to evaluate IOU ICA tools, methodologies and results are adopted and should be used as guiding principles for evaluating ICA."  The attached figure is the first ORA cut at a response to this direction for inclusion in the ICA WG report.   The figure is intended to show the status of the ICA tools based on the IOU Demo A reports, with the understanding that Demo A was a major step in an evolutionary development process. 
This figure is based on two important assumptions, which should be vetted by the WG before the figure itself is discussed:
The WG report will inform a PD or ACR that adopts a full scale ICA implementation plan,
The longest lead time activity, SCE and SDG&E extraction and validation of circuit models, can be bifurcated from other important developmental activities
The second assumption is the basis of differentiating yellow "go" issues from red "no-go" issues.

7. ICA Working Group Meeting
January 20, 2017

8. No-backflow question beyond operational flexibility
Written explanation of what other reasons a no-backflow screen might need to be used beyond operational flexibility (Ex: for some voltage control devices, how the screen would apply if it was used just for those cases) (priority for 1/20)
As shown on SCE’ ICA report page 30 figure 21, voltage regulators are programed with specific settings to properly regulate voltage based on existing conditions (load only, load and DER,). In some cases, the VR may not be adequate to regulate in both directions such that the control/VR may need to be replaced or in some cases, the settings programmed in the control are specific to the existing condition and adding additional DER on the regulated side would require changes to the control settings. Therefore, for voltage regulators (field or substation), it is necessary to limit the ICA to reverse power because as not doing so may cause the VR to not regulate properly and create power quality/voltage issues on the regulated side.
Existing control/VR may not be adequate for reverse power flow
Existing setting on the control are not adequate for increased level of DER
SCE’s ICA Report Figure 21

9. Computing Time outline of Requirement Spects#
Task
Today’s State
Proposed State
Requirement 1
Model Creation
Manually triggered in-house built scripts gather data from GIS System
Develop systems to automatically detect significant distribution system changes and update models.
Further integrate other data sources, such as SCADA and DMS data
Engineers to guide development of solution
Dedicated servers to perform Extraction, Transformation, and Loading (ETL) of datasets
Enterprise databases to manage data 2
Model Validation
Manual validation of distribution circuit models
Develop enhanced algorithms to aid in the manual validation of distribution circuit models
Distribution Engineers to perform validation
Develop systems to store and manage engineers’ work
Develop interfaces to aid in the validation process 3
Implement ICA Methodology
Python based scripts
Implement final methodology on an enterprise system capable of handling large scale datasets
Engineers and developers to guide the implementation of the algorithm(s) 4*
Run ICA
Laptops and Desktops
Dedicated Servers
Dedicated servers to perform ICA 5
QA and QC
Engineers
Engineers + Validation Scripts
Engineers to perform validation of results and troubleshoot problems (e.g., power flow divergence)
Engineers to guide development of automated validation
Development of automated validation 6
Publication of Results
Local files, manual uploads, manual queries
Full integration of DERiM to ICA process
Engineers and IT SMEs to guide development of solution
Enterprise friendly databases to store and manage data 7
Periodic Updates
Updates can be performed manually on a limited dataset. Current staffing and technology do not support periodic updates
Automated process encompassing Tasks 1-6, including: identification circuitry changes requiring ICA update, end-to-end integration of processes and data
Personnel to oversee on-going process

10. Use Cases For Planning (Preliminary – for discussion only)
Use case 1: SCE envisions the use of ICA results to determine the appropriate system upgrades required to integrate forecasted DER. Combined with DER forecast, ICA can be used to identify limitations in the distribution system and take corrective actions in advance to allow the continue integration of DER without delay.
Use Case 2: SCE envisions the use of ICA results to maintain or improve system performance with higher levels of DER in the distribution system:
Using ICA information to improve reactive power planning (placements and sizing of capacitor band) by using the VAR profile information from ICA results to maintain adequate power quality
Regulator Placement: ICA results (voltage limits) can be used by engineers determine the most appropriate location for regulators and to optimize control settings to maintain adequate power quality (good voltage control)
Recloser Placement: ICA can be used to determine areas where the protection scheme, protection settings, or location of protective devices need to be modified in order to to allow higher levels of DER integration of DER.

11. More Detail on Operational Flexibility Options
IOU alternative
Given that there not feasible methodology to implement operational flexibility limits in an accurate and efficient manner, the IOUs propose the following:
Map two values of ICA:
Fast Track ICA Value: This value is one with lower risk of disconnection due to operational needs and applies current Operational Limitation – Low risk of potential operational problems for IOUs.
Can be used as to expedite the interconnection fast track process
Replace “fast track” eligibility limit
Increased in level of fast track capacity availability
Significant reduction in applicable screens
Removal of supplemental review process
Replace removed screens with checks and balances
Expedited SR Track ICA Value: This ICA value is one with higher risk of disconnection due to operational needs and does NOT apply the Operational Flexibility limit (to low side bus – no backflow to transmission allowed). Higher risk of operational problems for IOUs
Reduction in screens
Operational evaluation (Safety/reliability) screen still applied in the interconnection process (Supplemental Review process, ISP, DGS)

12. SCE – Provide more detail on "planned loading limit" described in GRC
SCEs GRC work paper title “DER Driven Circuit Upgrades Methodologies” is consistent with SCE’s ICA report as outlined in page 24, Section 4.4.1(Iterative method). In the ICA report, SCE indicates that the “practicable” level of ICA on a 12 KV feeder is 12MW which is essentially the Planned Loading Limit of SCE’s 12KV distribution feeders.
The GRC work paper states that the “maximum DER at the feeder level” is the Plan Loading Limit. The GRC work paper does provide an indication of the ICA value at the “NODE” and does not indicate that the feeder ICA can be apply to all the nodes.
Thus , the work paper intended to provide an indication that even if all various criteria (Thermal, protection, voltage, system flexibility, etc.) are not violated at the node for DER values greater than PLL (greater then 12MW), then the maximum DER at the feeder level is the PLL of the feeder.
For instance, near the substation, on a heavily loaded circuit:
Protection criteria would be greater than 12MW
Steady State Voltage would be greater than 12MW
Thermal criteria would be over 12MW
Voltage Fluctuation limit would be greater than 12MW
If the circuit was a highly loaded, then system flexibility at node outside the substation would be greater then 12MW
The work papers intention is to indicate that the limit would be PLL if all the criteria values exceed 12MW,

13. Development of common methodology table
CYME/SYNERGY Parameters
SCE
PGE
SDG&E
Affects to ICA
Source Voltage Input
SCADA
Simulated LTC
LTC will control the voltage 
Affect to the Steady State Voltage ICA limit
Source Voltage
Unbalanced
Balanced
Unbalanced 
Allocation Method
AMI (kW) or Connected KVA/SCADA
Hourly AMI to each meter adjusted to SCADA at Breaker
AMI (kW) at peak hour or average demand from billing data
Affects profile at the node level and thus may affect the themal and voltage ICA values
Load power factor assumptions
0.95 PF
RES: 95% COM: 85% IND: 85% AGR: 85%
SDG&E to update
May affect thermal and voltage ICA
Convergence Tolerance
0.1%
0.25%
 0.1%
Affects timing and convergence of network models
Iterations 60
500
 20
May afect timing of network power flow solution
Loading Limits
Nominal
 Nominal
Affects Thermal ICA
Pre-Fault Voltage
Affects Protection ICA
Fault Impedance
R = X = 0
R=X=0
R = X = 0 
Fault Types Analyzed
3-Phase and Phase - Ground

14. (Q7) Written explanation of current applications of preexisting conditions
SCE analyzed pre-existing conditions to determine if DER would worsen or help with mitigation of preexisting condition.
For example, if a low voltage pre-existing condition existed on a feeder, then a DER(gen) may improve or eliminate the low voltage condition. Therefore, ICA for generation was not restricted on such feeder. This can be more complex problem in the presence of LTCs, where the addition of DER(gen) on one feeder can cause the LTC to reduce voltage on the bus further worsening an existing low voltage on adjacent feeder. Since none of the substation transformers in the demo A DPAs had LTC, all such violations would not be worsening by the addition of DER(gen) and thus SCE did not limit ICA for those conditions.
From SCE’s perspective, each pre-existing condition must be looked at to determine proper action in relation to ICA and to not reduce ICA unless DER worsen the pre-existing condition.

15. (Q8) Written explanation of differences among IOUs with regarding to modeling common bus
SCE modeled a common bus for each substation in the Demo. However, two of the substation were experiencing convergence issue and had to be run one feeder at a time. Those issues persisted even when the tolerance and number of iterations was increased. Prior to the overall system rollout, SCE plan to consult with CYME to determine whether anything else can be done to ensure all models converge in the common bus configuration. This will be critical to achieve, especially for substations with LTCs.
While common bus simulation may be required for substation which have LTCs, it may not provide any additional accuracy, limitations or increases to ICA and thus may be increasing the complexity of the simulation without any additional benefit.

16. ORA: proposed 12 success criteria
ORA Criteria
SCE
SDG&E
PG&E
Comments
1.Accurate and meaningful results
A. Meaningful scenarios
Reverse flow at substation bussbar? ACR scenarios best for use cases?
B.Reasonable technology assumptions
Need plan to incorparate smart inverter data
C.Accurate inputs (i.e. load and DER profiles)
Track 3
D.Reasonable tests (i.e. voltage flicker)
No concerns/alternatives from working group
E. Reasonable test criteria (i.e. 3% flicker allowed)
F.Tests and analysis performed consistently using proven tools, or vetted methodology
Tools being developed as part of Demo A and LT refinements
G. Meaningful result metrics provided in useful formats
See #5
Duplicative
2.Transparent methodology
IOUs have been open to information requests
3.Uniform process that is consistently applied
LT Item
QA/QC of custom Python scripts TBD
4.Complete coverage of service territory
Not required at this point
5.Useful formats for results
6.Consistent with industry, state, and federal standards
7.Accommodates portfolios of DER on one feeder
Uniform Gen map, plus DER translator
8.Reasonable resolution
–Spatial
Optimal (lower) resolution TBD; nodal reduction proposal
–Temporal
Optimal (lower) resolution TBD; 576 vs. 24 hours
9.Easy to update based on improved and approved changes in methodology
10.Easy to update based on changes in inputs (loads, DER portfolio, DER penetration, circuit changes, assumptions, etc.)
Tweaks to circuit models in CYME/Synergi required for convergence are currently lost when new data from GIS and other data sources is incorporated into power flow circuit model
11.Consistent methodologies across large IOUs
See #3
12.Methodology accommodates variations in local distribution system

17. List of ICA Long Term Refinement
Comprehensive ICA and LNBA data access (incorporating 3.2.b and 3.2.d)
From ACR:
Automated data analysis
Expansion of the ICA to single- phase feeders[1];
Integration into streamlined interconnection
Ways to make ICA information more user-friendly and easily accessible (data sharing);
Integration of the ICA with the growth scenarios in order to inform decision-making
Interactive ICA maps;
ICA that allows DERs to serve peak load conditions, while maintaining grid stability during low-load conditions
Market sensitive information (type and timing of the thermal, reactance, or protection limits associated with the hosting capacity on each line);
Potential coordination with national labs – “DER siting and optimization tool for California”
Method for reflecting the effect of potential load modifying resources on integration capacity;
Further identified by WG in January:
Development of ICA validation plans, describing how ICA results can be independently verified; and
Smart inverter capabilities
Definition of quality assurance and quality control measures, including revision control for various software and databases, especially for customized or “in-house” software
Smart meter data
Deep dive – hourly components within ICA (general trend showed more significant changes with location than with hours)
As identified by Working Group in interim long-term refinement report:
Alternative operational flexibility methodologies
Ongoing discussion on short vs. long-term recommendations

18. Discussion

19. Locational Net Benefits Analysis Working Group
January 20, 2017
In-person meeting
drpwg.org

20. Agenda Time Topic 1:00 – 1:15 1:15 – 2:15 2:15 – 3:15 3:15 – 4:00
Introduction, Review of Schedule
1:15 – 2:15
Discussion of use cases
2:15 – 3:15
Review of stakeholder comments
3:15 – 4:00
D. Discussion of Recommendations

21. Stakeholder comments
We received stakeholder comments from the following people/organizations:
Tool:
Evaluate portfolios of DERs in multiple locations
Dependability factor
Karey Christ Janer (1/10)
Integration cost
TURN (1/13)
Metrics to indicate certainty of deferrable project
CALSEIA, SEIA, Clean Coalition, Vote Solar (1/18)
Hourly DER generation should not be input manually
Comments cover:
Use cases:
Methodology:
Adequate use in utility system planning
Incorporate local RA values
Use for tariffs
Avoided energy cost calculation
Additional values of DER services
Other:
Additional DER attributes beyond load reduction
Incorporate lessons learned from other DRP/IDER pilots
Value increased reliability
Proportional value assignment
Granular locational values using LMPs
All comments may be found online at
Avoided costs beyond 10 year time horizon
Avoided transmission cost value
DER growth scenarios

22. Discussion
Please refer to the LNBA draft outline and draft consolidated recommendations online at drpwg.org (dated 1/26)

23. Options for WG report schedule
At 1/6 meeting, it was mentioned that this Working Group may request an extension of the final report deadline.
If extension request – refer to proposed schedule in ICA WG slide deck.
If the WG would still like to submit a final report by 1/31, proposed schedule:
All Recommendations must be submitted by COB Monday 1/23. (No new recommendations may be added after this date)
MTS will consolidate and circulate by 1/25
Parties may submit reactions / comments / support and opposition statements by 1/29  (No new recommendations will be added, only comments to recommendations previously submitted Monday)
MTS will consolidate comments into single document and provide to IOUs on 1/30. 
IOUs will file on 1/31

24. Suggestions for framing WG recommendations
IOU’s suggest stakeholders organize recommendations into the following two main categories:
1. Response to DEMO B Implementation and Recommendations for LNBA Refinements:
Based on what was done in Demo B per 5/2 ACR, what refinements to methodology should be implemented and how prioritized?
We already have a number of topics in scope for long-term refinements; based on review of Demo B, how should this scope be modified?
2. Next Steps and Regulatory Process:
What are the necessary next steps to refine and implement LNBA?
What is the appropriate regulatory process within the DRP?
What are processes or decisions in related proceedings are necessary to inform LNBA implementation?
Some potential next steps to occur prior to future LNBA implementation:
CPUC Adopted deferral framework to inform which grid needs are fed into LNBA (note: adoption of screens for deferral framework is critical step to drive the scope of LNBA and ensure efficient use of resources.)
Discuss and implement high priority refinements to methodology (e.g. improve on system-level components)
Gather key inputs / insights from IDER
Identify lessons-learned from first round of DER sourcing pilots to inform implementation of LNBA (IDER Pilots; DRP Demo C Pilots)
IOUS submit budget, scope, and schedule proposal for further implementation of refined LNBA. (IOUs suggest stakeholders have an opportunity to review and comment prior to implementation.)