MTS Working Group January 28, 2016

Transmission - Distribution Operational Interface

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

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)

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

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

MTS Working Group March 1st, 2016

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)

Transmission - Distribution Interface

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

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

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

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

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

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

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

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

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

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

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