Distribution
Resources Plan
By Erik Takayesu, PE
Director, Electric System Planning
Southern California Edison
More Than Smart Webinar
August 4, 2015
Erik Takayesu, PE
Director
Electric System Planning
Southern California Edison
Erik Takayesu is the Director of Electric System Planning for Southern California Edison.
The organizations he currently oversees include Grid Modernization, Distribution and
Transmission System Planning and Engineering, Distribution Automation, Power Quality,
Generation Interconnection Planning and Studies. He has held various roles at SCE,
including managing Grid Operations, Reliability Engineering, and Asset Management.
As part of modernizing the electric grid, Erik has been instrumental in leading the efforts
to develop SCE’s Distribution Resource Plan. His organization is also developing the
strategy for enabling the electric grid to integrate Distributed Energy Resources.
Erik has a bachelor’s degree in Electrical Engineering from the California State University
at Long Beach, is a licensed PE, and holds his master’s degree in Organizational
Leadership from Gonzaga University.
1
Overview
I.
Assembly Bill 327 and PUC Code Section 769
II.
General Structure of the DRP
III.
Analysis, Methodologies, and Demonstration Projects
IV. Conclusion
2
California’s Distribution Resource Plan (DRP)
 AB 327 (2013) requires utilities to submit a Distribution Resources Plan (DRP)
proposal by July 1, 2015
 Identifies optimal locations for distributed energy resources (DERs)
 Establishes Section 769 that acknowledges the need for investment to integrate costeffective DERs
 Requires unified methodology for determining circuit integration capacity and net
benefits methodology
 Recognizes need to revise tariffs and incentives to promote DER in locations that
provide the greatest net benefits to the grid
 Provides for discussion on safety benefits, barriers to deployment, and integration with
existing Commission approved programs and coordination with the General Rate Case
 The Final Guidance Document for Section 769 issued February 6, 2015
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Described as “New Framework for Distribution Planning”
Intended to move IOUs towards seamless integration of DERs
Outlined requirements for analysis, methodologies, and demonstration projects
Based on More than Smart: A Framework to make the Distribution Grid More Open,
Efficient and Resilient
3
Guidance for Public Utilities Code Section 769:
A New Framework for Distribution Planning
• Supporting California’s 2030 and 2050 GHG reduction targets
• Beginning the process of moving towards full integration of DERs in distribution
system planning, operations, and investments
• Modernizing the electric distribution system to accommodate two-way flows of
energy and energy services throughout the IOUs’ networks
• Enabling customer choice of new technologies and services that reduce
emissions and improve reliability in a cost efficient manner
• Animating opportunities for DERs to realize benefits through the provision of
grid services
Creating a “plug-and-play” distribution grid for DERs
4
General Structure of DRPs
1
Overview and
Policy Support
• Executive Summary
• Policy Goals
4
Tariffs and
Contracts
• Existing tariffs
• Recommendations for
incorporating locational
value and demonstration
projects
• Interconnection Policies
2
ICA, Locational Value,
Demonstration & Deployment
• Integration Capacity Analysis
• Locational Value Analysis
• Demonstration & Deployment
5
Safety
Considerations
• Safety/reliability
standards
• Major considerations for
DER owners/operators
• Outreach activities
3
Data
Access
• Data Access Policies
• Proposed policies and procedures for
sharing utility and third party data
• Opportunities and limitations
6
Barriers to
Deployment
• Regulatory, safety and
grid insight barriers
• Proposed solutions to
barriers including
technology
development and
deployment
7
Coordination w/ Capital
Investment Plan, GRC &
Phasing of Next Steps
•
•
•
•
Utility and CEC forecasting
High-level Capital
Coordination with GRC
Phasing of Next Steps
Integration Capacity Analysis
To determine the hosting capacity available for DERs, each utility:
• Evaluated each circuit’s DER hosting capacity by considering thermal ratings,
protection system limits, and power quality standards to meet safety standards
• ICA analysis performed by line section, between 3 – 4 segments per circuit
• Displayed results via online maps
Key Takeaways:
1.
The higher the distribution voltage, the higher the potential integration capacity. For
example, the chart above shows that the 12kV line segments have more hosting capacity
than the 4kV line segments.
2. The closer the line segment is to the substation, the more DERs it can accommodate. In
the above chart, Line Segment 1 is closest to the substation.
6
Locational Net Benefits Methodology (LNBM)
The unified methodology is to be based on the Commissionapproved E3 Cost-Effectiveness Calculator, but enhanced to include
location-specific values
• Objective is to identify optimal locations where DERs could
provide a high benefit value
• Avoided sub-transmission, substation, and feeder-level CapEx
and O&M related to forecasted load growth
• Avoided CapEx and O&M related to ensuring distribution voltage
and power quality
• Avoided CapEx and O&M related to maintaining/enhancing
distribution reliability and resiliency
• Avoided system and local-area transmission CapEx and O&M
• Avoided flexible RA and renewables integration expenditures
• Avoided societal costs and avoided public safety costs linked to
the deployment of DERs
7
DER Growth Scenarios
“[T]he Utilities shall develop three 10-year scenarios that project expected
growth of DERs through 2025, including expected geographic dispersion
at the distribution feeder level and impacts on planning”
Scenario 1: IEPR Trajectory Case
Intended to reflect a modest base scenario for California’s resource and
infrastructure planning. Reflects a “modestly conservative future world
with little change from existing procurement policies” and “business as
usual practices”.
Scenario 2: IEPR High Growth Case
This scenario “diverges from the Trajectory scenario by assuming a high
incremental amount of demand-side small PV and a low incremental
amount of demand-side CHP”.
Scenario 3: Very High Growth Case
Provides that such goals include: Governor’s 2030 Energy Policy, Zero Net
Energy, 2030 GHG reductions, Governor’s Zero Emission Vehicle Action
Plan, Commission’s 2020 Energy Storage Requirements, Commission’s
Demand Response (DR) Goal of 5% of peak load managed by DR, and
Reliability Improvement
8
Demonstrate Projects
Five Demonstration Projects
A. Demonstrate Integrated Capacity
Analysis
B. Optimal Locational Benefit Analysis
C. Field Demonstration of DER
Locational Benefits
D. Distribution Operations at High
Penetrations of DERs
E. Demonstrate DER Dispatch to Meet
Reliability Needs (a.k.a., microgrid)
9
Conclusion
• DRPs represent an important step towards embracing and
implementing the Commission’s DRP vision and meeting changing
customer expectations
• Utilities will incorporate DRPs into their distribution system planning
and operations to meet current and future DRP goals
• DRPs will support the facilitation of DER development and
encourage customer value creation, including robust
recommendations to overcome barriers to DER deployment
• The DRPs will help to enable a fully integrated, low-carbon electricity
system, and it is clear that utility grid modernization investments
must keep pace with DER technology innovation
10