1. MTS Working Group January 28, 2016

2. Transmission - Distribution Operational Interface

3. The Context
Growth of DER creates operational challenges at the transmission-distribution interface
DER and DER aggregations bid into ISO market and receive dispatch instructions
ISO “sees” DER as if they’re located at the T-D substation => ISO does not know impact of its DER dispatches on the distribution system
Distribution operator (DO) must manage the system with numerous diverse DER, some acting autonomously, some responding to ISO dispatches, some able to provide DO services
These activities require new arrangements for coordination between DO and ISO

4. MTS mission … if we choose to accept it
Begin to detail the three-way relationship between (1) the DER or DER aggregation provider participating in the ISO wholesale market, (2) the ISO and (3) the DO
What is needed in the high-DER context to ensure reliability of distribution system operation and the T-D interface?
Real-time visibility, communication
Informing the DO of DER/DERA schedules and dispatches
Operating procedures to manage dispatches of multiple DER/DERA in the same local distribution area
DER services to support DO real-time operations
ISO – wholesale market
DER/DERA/
DERP
Distribution Operator (DO)

5. Next Steps for IOUs to Consider - Planning
Establish Process (or Registry) for tracking all resources participating with a DERP
Verify individual resources are not participating in other programs or part of other DERPs that could result in “double counting” of benefits
Ensure participating resources have valid interconnection agreements
Ensure participating resources are planned to be operated consistent with respective interconnection agreements
Modify Electric T&D Planning Processes
Develop process for assessing DER Aggregator impacts
Deliverability Assessment for DERPs
Streamline process for modifying interconnection agreements to better align with respective DERP’s proposed operation
Determine DER hosting capacity at the T&D interface point (e.g. substation level) and coordinate with the CAISO
Review Interconnection Standards for resources participating with a DERP

6. Next Steps for IOUs to Consider – Operations
DER Dispatch Coordination
Establish process for DER operations to be shared with the distribution system operator to which the DERs are connected.
Utility distribution company needs to be aware of CAISO DER dispatch instructions
DER Aggregation Monitoring Systems
Provide operational visibility to DER aggregation operations for distribution operation

7. MTS Working Group March 1st, 2016

8. Proposed 1H 2016 CA WG Focus
TOPIC 1: Integrated Distribution Planning Process (IDPP)
Define an IDPP that integrates California energy planning, interconnection processes and investment planning to achieve state policy objectives
WG Leads: Kevin Joyce & Mark Esguerra (Laura Manz for MTS)
TOPIC 2: Transmission-Distribution Operational Interface
Identify and develop process recommendations for Transmission-Distribution Operational Interfaces between CAISO and utility distribution operators to enable CAISO DER Initiative by April 1st
WG Leads: Mark Esguerra & Lorenzo Kristov (Paul De Martini for MTS)
TOPIC 3: Distribution Portfolio Framework
Identify issues, frame considerations and develop a Distribution Portfolio Framework that can inform the IDER and DRP proceedings along with other CA policy considerations
WG Leads: Heather Sanders & Merrian Borgeson (Paul De Martini for MTS)

9. Transmission - Distribution Interface

10. Subteam Objective
Develop a coordination framework for the distribution utility (UDC) and the wholesale market and transmission operator (ISO) to coordinate activities to ensure stable, reliable operation of the distribution and transmission systems and their interfaces, in an electric system that features high penetration of DER, both behind and on the utility side of the meter.
Form of final deliverable to be determined

11. Proposed Approach Describe the context
Focus on single local distribution area (LDA) = single T-D substation
High volume & diversity of DER, with wholesale market participation
Specify a sequence of use cases or scenarios
Identify essential elements that must comprise a coordination framework for each use case
Aim for a comprehensive picture; stay out of the weeds
Do it for the simplest use case first; add complexity only after having a complete picture for the simplest case
Focus on real-time operations first; let real-time operating needs drive any forward requirements
(Only later) Develop specific design details for implementing the needed elements

12. Sequence of Use Cases
Medium-size end-use customer, with a mix of BTM devices, participating in wholesale market
Customer/resource is a single POI on the distribution system
May be a micro-grid or smart building
Virtual resource = aggregation of diverse sub-resources at different POIs on distribution grid
Wholesale market participants
Sub-resources on both sides of customer meter
Passive end-use customers with BTM solar plus storage – not in wholesale market
All of above, plus merchant DG and storage on utility side, bi- directional DR in wholesale market

13. Some Elements of a Coordination Framework
Information exchanges between UDC, ISO, DER – specify content and timing
Short-term forecasting (real-time to day-ahead) of net load and autonomous DER behavior
Situational awareness – sensing and data systems
Ability to calculate expected distribution system impacts of ISO dispatches of DER; “feasibility” of ISO dispatches
Control systems & DER services needed to support UDC operations
Operating procedures to deal with the unexpected
Procedures for sharing revenue-quality meter data for financial settlements
Regulatory oversight

14. Next Steps Get together for a working session in March
Pick first use case and describe the scenario in detail
Maintain the “start simple” principle, perhaps using a sequence of sub-cases of the use case and adding complicating features one at a time
Describe the needed elements of the coordination framework as comprehensively as possible, without getting hung up on details (e.g., software apps or technologies)
Gradually work through more use cases, building the coordination framework as needed for each new scenario

15. Draft for discussion purposes only
MTS Working Group Transmission-Distribution Interface Sub-team March 11, 2016 sub-team meeting, San Francisco

16. Proposed approach for today’s meeting
Review sub-team framework & context assumptions
Focus on single local distribution area (LDA) = single T-D substation
High volume & diversity of DER, with wholesale market participation
Specify the first use case or scenario
For that use case, identify the needs or essential elements of a coordination framework for reliable operations
Start with real-time operational requirements (e.g., voltage stability, phase balance, flow limits, etc.)
Work backwards from real-time to identify forward requirements at various time frames (see diagram next page)
Focus on communication/coordination needs – don’t try to solve how to meet the needs at this point in our process
As time allows, specify the second use case and repeat step 3 for that case
Draft for discussion purposes only

17. First two use cases
In addition to “non-participating” end-use customers, some having rooftop solar PV, the LDA has one or more large commercial customers with behind-the-meter devices that enable them to provide imbalance energy and A/S to the wholesale market
Each such customer/resource is at a single point of interconnection on the distribution grid; i.e., no aggregation over multiple POIs
Assume initially the resource does not provide distribution services
Expand the previous case to include one or more “virtual” resources, each resource an aggregation of sub-resources at different POIs within the LDA, each resource able to participate in the wholesale market
Again, assume initially the resources do not provide services to the distribution utility
Draft for discussion purposes only

18. Distribution and transmission time frames
Distribution operations
Two-weeks: outages, etc.
Day-ahead scheduling
Intra-day scheduling
Real-time
45 days – major outage scheduling
Multi-day-ahead unit commitment
Day-ahead scheduling
Intra-day unit commitment
15-min dispatch
5-min dispatch
Real-time
Real-time bids at T-75 min
Transmission & wholesale market operations
Draft for discussion purposes only

19. Some elements of a coordination framework
Information exchanges between UDC, ISO, DER – specify content and timing
Short-term forecasting (real-time, day-ahead, weeks ahead) of net load and autonomous DER behavior
Situational awareness – sensing and data systems
Ability to calculate expected distribution system impacts of ISO dispatches of DER; “feasibility” of ISO dispatches
Control systems & DER services to support UDC operations
Operating procedures to deal with unexpected conditions or conflicting needs
Procedures for sharing revenue-quality meter data for financial settlements
Regulatory issues related to the above
Draft for discussion purposes only

20. Sub-team objective
Develop a coordination framework for the distribution utility (UDC) and the wholesale market and transmission operator (ISO) to coordinate activities to ensure stable, reliable operation of the distribution and transmission systems and their interfaces, in an electric system that features high penetration of DER, both behind and on the utility side of the meter.
Form of final deliverable to be determined
Draft for discussion purposes only