Advisory Committee on Innovation

Fourth Meeting: May 22, 2018

Thanks to Toronto Hydro for Hosting

For Committee’s use only

Not for further distribution

Agenda

8:30 – 9:00 am Continental breakfast (provided)

9:00 – 9:15 Introduction, Overview and Review of Agenda

9:15 – 10:00Member presentation

• Insights on Innovations

10:00 – 10:30 Roundtable discussion: Reflection on Discussions of May 3rd

10:30 – 11:00 Roundtable discussion: Planning

11:00 – 11:15 Break

11:15 – 12:45 Roundtable discussion: Planning (cont’d)

12:45 – 1:00 Reflection & next steps

1:00 pm Adjourn

2

Introduction, Review of Agenda, and OverviewContext, Focus Question, and Outline for Discussions

3

Context for Today’s Discussions

Transformation & Customer Value

Utilities are delivering value to consumers in a changing

environment

The regulatory

framework incents

utilities to focus on

long-term value

for money and

least-cost

solutions

Regional and

utility system

planning reflect

the continuing

evolution of the

sector

Utility infrastructure is

optimized during the

shift to a low carbon

economy

OEB’s Blueprint Goals & Objectives

Refresher/Adapted from from 1st Meeting

4

Demand

Traditional CapacityGrowth

Time

MVA

FUTURE OPPORTUNITY WITH DERLoad meeting capability grows incrementally through acquisition or operation of DERs – more efficient spending; growth rate of demand attenuated by customer’s own choices

MVA

Time

Demand

TODAYStep-wise increase in capability through expansion of traditional utility infrastructure –capacity additions not optimally suited to timing of need

Load-meeting Capability

Load-Meeting Capability in Distribution

Context – DER Integration

5

Context – Objectives of Planning

• Meet the needs of existing and future customers by

focusing on long-term value for money and least-cost

solutions

• Ensure an efficient, well-functioning electricity sector

• Ensure flexibility to meet an uncertain future in which

infrastructure is optimized during the shift to a low

carbon economy

• Ensure resources/solutions are valued on an equal

footing so that all potential alternatives are

appropriately considered when selecting investments

6

Focus Question

What changes, if any, should be made to utility system planning and/or regulation in Ontario to:

• Support more active network management strategies that reduce costs and enhance customer choice

• Level the playing field for competitive provision of electricity solutions by both traditional players and new businesses harnessing DERs

• Provide equal consideration of wires and non-wires solutions and make best use of existing assets; and

• Encourage a culture of innovation?

Keep this in mind throughout our meeting.

7

Outline for Today’s Discussions

• Current Planning & Regulatory Frameworks (OEB and

IESO)

• Enhancements to Support Coordinated & Cost-

effective Planning

• Readiness to Adopt Change – Combatting Biases

• Encouraging a Culture of Innovation

8

Current Planning & Regulatory FrameworksCommittee Discussion

9

Overview of OEB’s Current Regulatory Framework

Ontario Energy

Board. Report

of the Board

on Renewed

Regulatory

Framework for

Electricity

Distributors: A

Performance-

Based

Approach.

October 18, 2012. p. 33

Integrated

Approach to

Distribution

Network

Planning

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Focus of OEB Review

Utility’s business plan should:

• Address the utility’s challenges

• Integrate customer expectations & obligations

• Set performance commitments; and

• Demonstrate how results will be achieved

Utility’s system plan should:

• Demonstrate delivery of value, effective management of assets, and be optimized, prioritized and paced; and

• Address customer focus, operational effectiveness, public policy responsiveness, and financial performance outcomes

Rates Handbook for Utility Applications - Business Plan (pp 10-11)

Rates Handbook for Utility Applications – Planning (pp 12-15)

Distribution System Plan – Outcome evaluation (pp 405)

11

Regional Planning in Context

October 25, 2018 Ontario Energy Board 12

Source: Process Planning Working Group Report

Long-term Energy Plan/Integrated Power System Plan (Bulk System Planning)

Distribution Planning

Integrated Regional Resource Planning

(IRRP)

Regional Infrastructure Planning

(RIP or wires planning)

Bulk System Planning

500kV & 230 kV transmission Interconnections Inter-area network transfer capability System reliability (security and adequacy)

to meet NERC, NPCC & ORTAC Congestion and system efficiency System supply and demand forecasts Incorporation of large generation Typically medium- & long-term focused

Regional Planning

230 kV & 115 kV transmission 115/230 kV autotransformers and

associated switchyard facilities Customer connections Load supply stations Regional reliability (security and

adequacy) to meet NERC, NPCC & ORTAC ORTAC local area reliability criteria Regional/local area generation & CDM

resources Typically near- & medium-term focused

Distribution Network Planning

Transformer stations to connect to the transmission system

Distribution network planning (e.g. new & modified Dx facilities)

Distribution system reliability (capacity & security

Distribution connected generation & CDM resources

LDC demand forecasts Near- & medium-term focused

Transmitter

IESO

IESO

Distributor

Industry & OEB Development of Regional Planning ProcessStakeholder Engagement

• Industry led Process Planning Working Group established by OEB to create a more structured & transparent regional planning process (2013)

• Regional Planning Process Advisory Group created by OEB to make improvements based on “lessons learned”

Regulatory Reforms to Support Regional Planning

• OEB amended Codes and IESO Licences to ensure information is shared among participants (distributors, lead transmitter, IESO) & deliverable timelines are met

• OEB amended Filing Requirements to require transmitters and distributors to submit a Regional Infrastructure Plan in support of a Rate or long-term contract application & created connection between Regional Planning & Distribution System Planning

• Modifications to TSC and DSC to ensure consistent approach to cost assessment and integration of Tx and Dx

October 25, 2018 Ontario Energy Board 13

Potential Enhancements to Distribution System Planning• Distributor planning begins with distributors assessing customer needs and

consideration of CDM for forecasting

• Distributor needs are then addressed through local planning by the distributor or addressed in the regional planning process

• Needs that do not go through the regional planning process are subject to distributor system planning

• Needs that do go through the IESO’s portion of the regional planning process (IRRP) are subject to the IESO’s alternatives analysis

• IRRP includes consideration of needs and broader opportunities

• Regional planning involves distributors, IESO and transmitters, and can involve multiple distributors collaborating to avoid upstream investments

What features, if any, of the Regional Planning process (e.g., alternatives analysis approach) could be adapted in distributor system planning?

How can distribution system planning build off of the current Regional Planning process to (e.g., increasing collaboration between utilities)?

October 25, 2018 Ontario Energy Board 14

Cost Responsibility to Facilitate Regional Plan Implementation

Proportional Benefit – Customer & Pool

• Currently, transmission connection investment costs are recovered from the triggering customer(s) even if broader network system benefits

• Propose proportional benefit methodology to allocate some costs to network pool to account for identified broader system benefits (e.g., reliability)

Regional Distribution Solution – Distribution Feeder Transfer

• Currently, opportunities to avoid a higher cost transmission connection investment may be lost unless distributors make joint investments

• Propose facilitating joint-distribution investments involving two distributors to avoid a higher cost upstream transmission connection investment

Capital Contribution – Annual Installments

• Currently, costs of transmission connection solutions to meet distributors’ capacity needs can be a barrier to regional plan implementation

• Propose implementing an annual payment approach to smooth impact on distribution rates over period of up to 5 years.

• Harmonized Codes across Tx and Dx designed to ensure consistency, reflect greater integration of the two systems, and equalize incentive to connect to either system

Which aspects of these policies could be adapted at the distribution level?

October 25, 2018 Ontario Energy Board 15

For Discussion

Focus Question from Slide 7 and the OEB’s Current Approach

What changes, if any, could be made to utility system planning and/or regulation in Ontario to:

• Support more active network management strategies that reduce costs and enhance customer choice

• Level the playing field for competitive provision of electricity solutions by both traditional players and new businesses harnessing DERs

• Provide equal consideration of wires and non-wires solutions and make best use of existing assets; and

• Encourage a culture of innovation?

16

Enhancements to Support Coordinated & Cost-effective Utility PlanningCommittee Discussion

17

Steps in Coordinated & Cost-effective Utility Planning

Planning Step Done Today?

Forecast of customer needs and changes in network use

Current information on asset condition

Process that broadens planners’ knowledge of potential

solutions

Limited

Process that exposes distributor’s needs to the market and

assesses alternatives in a standardized manner

Process to adapt operations / business to accommodate a

non-traditional solution

Limited

Prioritization of solutions/investment needs

Regulatory review for assurance of value to customers and

provide investors with confidence of recovery

Any additional steps?

Are the steps properly sequenced?18

Potential Ways of Broadening Knowledge of Solutions

CDM Guidelines already permit distributors to deploy CDM to defer assets, but uptake is limited.

A local planning approach that canvasses expanded set of solutions (resource options) to meet forecasted needs would involve:

• Access to market intelligence on end-use behaviors / preferences

• Resource profile (customer value and utility value [i.e., degree to which it can meet needs dependably and reliably])

• Cost-effectiveness analysis, including marginal and avoided costs

• Enhanced knowledge of customer plans for investment in self-generation, storage, etc

• 3rd parties and/or consumers understand system needs and how they can provide solutions to system issues

Adapted from Ontario Energy Board. Report on Gas Integrated Resource Planning. September 16, 1991. p. 4

19

For Discussion

What’s the OEB’s role, if any, to better

support integrated utility system planning?

How should the OEB require non-

traditional solutions to be assessed?

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Potential Enhancements to the Planning Toolkit

Rules-based valuation of conventional and novel solutions used to support investment decisions (e.g., New York’s Benefit Cost Analysis Handbook)

Go beyond current requirements in relation to information sharing for 3rd party solutions to system issues (e.g. data on capacity and constraints to inform locating potential). Current requirement focuses on making information available upon request. An example could be similar to what is provided in Toronto Hydro Load Relief Forecast Map1

‘Rules of engagement’ for 3rd party connection and access to the system (e.g., issues with behind the meter DERs that impact system planning and operation vis-à-vis dependability and persistence of resources)

A means of modeling the evolution of network use. High performance computing (HPC) offers significant potential in critical infrastructure applications areas like power and energy systems

What other enhancements could be made?211 Toronto Hydro Load Relief Forecast is provided in the Appendix to this presentation

Potential Enhancements to the Regulatory Toolkit

Under increasing penetration of distributed resources,

regulators and utilities face greater uncertainty in planning for

the evolution of network uses and efficient system costs. This

uncertainty can challenge regulatory reviews

Some jurisdictions have enhanced their toolkit to be able to:

• forecast the evolution of network uses, and

• estimate efficient expenditures needed to accommodate

that forecast

The MIT Utility of the Future report illustrates this in a novel

rules-based regulatory framework

22

MIT Framework Combines Established Regulatory Methods1

• Use of Reference Network Model (RNM) model2 to model anticipated evolution of network uses and forecast efficient costs

• Use of those forecasts to:

• set up profit-sharing incentives for cost saving efficiency efforts

• enable annual adjustments that reduce risk of uncertainty in the evolution of network use

• Equalized investment incentives for cost-saving efficiency efforts across both capital and operations spending (a pre-determined share of allowed total spend is capitalized)

1 Methods have been used in other jurisdictions including Spain, Sweden, or the United Kingdom2 Overview of the Reference Network Model is provided in the Appendix to this presentation

Focus for today is the 1st item… more on others next time

23

OEB’s Current Benchmarking Tools

• OEB does not currently forecast or estimate utility costs

• OEB does use empirical analyses to inform its rate setting:

• The OEB uses total cost statistical benchmarking of annually reported utility results for performance reporting, assessment and stretch factor assignment purposes

• Industry total factor productivity is estimated every 5 years to inform the setting of a productivity factor in rate setting

• Work is underway to expand OEB statistical benchmarking to include a detailed evaluation of costs at the program (or activity) level. Enhancing the monitoring of distributor performance is expected to drive greater cost discipline among distributors, incent greater efficiency and ultimately reduce costs for consumers.

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For Discussion

The forward-looking capabilities of RNM-based benchmarking contrast with statistical benchmarking, which analyzes past costs incurred by similar utilities to develop statistical estimates of efficient expenditures – it is backward-looking and cannot capture dynamic change unfolding in the sector

In contrast, RNM provides a tool with which to “peer into the future” and estimate efficient costs given expected changes in network uses (e.g., changes in demand and DER adoption) and in the cost and availability of different network assets over the regulatory period

Should the OEB build capability to forecast the evolution of network uses and estimate efficient expenditures? Why?

Is a RNM-based benchmarking feasible in Ontario? What alternative forward-looking approaches could be used?

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Potential Principles for Planning

• Inclusive – options identified and choices made in a transparent, inclusive and evidence-based manner

• Consistent approach to analyses – common methods of option evaluation are used

• Minimally distortive – potential for cross-subsidization between existing customers and early adopter customers transparent and mitigated. All customers are subject to contributions.

• Flexibility – flexibility is valued while paying due accord to inter-generational concerns and stranding risk

Would these principles achieve the goals and objectives set out in the OEB Blueprint?

What other principles should the OEB consider in its development of policies in support of regional and utility system planning?

26

Encouraging a Culture of InnovationCommittee Discussion

27

Further Supports for Innovation

• A key LTEP theme is the removal of barriers to innovation that prevent utilities – and their customers –from benefitting from efficiencies realized through innovation

• Today, stakeholder forums and steering committees are venues for regulated entities and others to raise issues of concern

• OEB LTEP Implementation Plan

• the OEB will develop a more formal mechanism for encouraging utilities to explore innovation

28

Ofgem’s “Regulatory Sandbox”

• The sandbox is designed to enable innovators to trial business products, services

and models that cannot operate under existing regulations.

• Application-based two step process:

1. “Fast frank feedback” to assess whether proposal could operate in current

regulatory framework and whether sandbox is needed

2. If regulatory barriers are identified and eligibility criteria are met, innovators apply

for a sandbox and Ofgem assesses the proposals

• Provides a way for innovators to:

• test trial runs in a real world application

• take responsibility to come to Ofgem with novel products or services that they

believe are hindered by existing regulation; not a permanent change or lasting

exemption to any requirement

• Eligibility criteria for sandbox:

• The proposal is genuinely innovative

• Potential for delivering consumer benefits and protection

• A regulatory barrier exists that truly inhibits the progress of a trial

29

Ofgem’s “Regulatory Sandbox”

• Those granted a sandbox may receive any or all of the following support:

• Tailored guidance on interpretation or compliance with regulatory requirements

• Guidance on how Ofgem might enforce particular regulatory requirements

• Derogations or exemptions from certain regulatory requirements

• 1st Sandbox round launched in early 2017 – 30 expressions of interest

• Most proposals did not identify a specific regulatory barrier and could likely operate within the current regulatory framework

• 3 sandboxes awarded - two of which involve peer-to-peer energy trading

• 22 of 30 proposals were found to be able to be accommodated within existing regulatory framework

30

For Discussion

• What are the barriers to innovation by regulated

utilities?

• What type of support, if any, is needed from the

regulator?

• Is the Ofgem approach appropriate for Ontario? Why?

Why not?

• Is a more integrated approach preferred? What would

need to change in OEB’s processes, or those of

utilities, to embed a culture of innovation ?

31

Capability Building to Keep Abreast of Sector Evolution

Assuming process and regulatory issues are resolved,

DERs and non-conventional solutions may still not

appear due to residual cultural or planning bias

• What planning and regulatory biases prevail in

Ontario?

• What contributes to them?

• How should they be addressed?

• What’s the OEB’s role, if any, to address planning

biases?

32

Focus Question Revisited

In light of today’s discussions, what changes, if any, should be made to utility system planning and/or regulation in Ontario to:

• Support more active network management strategies that reduce costs and enhance customer choice

• Level the playing field for competitive provision of electricity solutions by both traditional players and new businesses harnessing DERs

• Provide equal consideration of wires and non-wires solutions and make best use of existing assets; and

• Encourage a culture of innovation?

33

Reflection & Next Steps

34

AppendixSupporting Material

35

Toronto Hydro Load Relief Forecasts

36

Background on Reference Network Model1

The MIT paper advocates use of a reference network model (RNM) to facilitate forward-looking

benchmarking

• The RNM is a distribution planning model which emulates the engineering design process of an

efficient electric distribution company by specifying the placement and layout of all major

distribution network components connecting one or more primary transmission interconnection

substations with all power injection or consumption points

• It equips the regulator with a forward-looking tool to benchmark efficient network expenditures

and help the regulator overcome information asymmetries vis-a´-vis regulated utilities

Inputs Output

The location and power

injection/withdrawal profile of all

network users as well as a

catalog containing technical and

cost information about available

equipment, probability of

component failure, and the cost

and time burden of maintenance

actions

The RNM constructs a network to serve all network users

while minimizing total network costs (including CAPEX,

OPEX, and a specified penalty for ohmic network losses)

and meeting 3 specified quality of service constraints:

1. maximum system average interruption duration index

(SAIDI)

2. maximum system average interruption frequency index

(SAIFI); and

3. maximum acceptable voltage range at every node1 Adapted from Massachusetts Institute of Technology. Utility of the Future. December, 2016. pp. 153-5

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