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The Power to Deliver
Recommendations for the
future of electricity
distribution in Ontario
Table of Contents
Foreword.............................................................................................................................................. iii
Guide for Readers.................................................................................................................................. v
Acknowledgements.............................................................................................................................. vi
Executive Summary...............................................................................................................................1
Introduction and Background................................................................................................................9
A. History of LDC Evolution in Ontario..........................................................................................9
B. Distribution Sector Contributions to Ontario’s Economy........................................................11
C. Ipsos Reid Survey....................................................................................................................12
The Challenges Facing Distribution.....................................................................................................15
A. Infrastructure Investment.......................................................................................................16
B. New and Emerging Technologies............................................................................................17
C. Conservation and Demand Management...............................................................................25
D. Renewable and Distributed Generation.................................................................................26
E. Costs.......................................................................................................................................26
F. Regulation and Government Policy........................................................................................28
G. Human Resources...................................................................................................................28
H. Breakdown of the Bill..............................................................................................................30
Efficiency Opportunities......................................................................................................................31
A. Efficiencies Through Regulatory Streamlining........................................................................33
B. Efficiencies From Scale and Contiguity....................................................................................37
C. Efficiencies From Reducing Regulatory Constraints on Scope of Operations..........................44
D. Changes to the CDM Framework............................................................................................50
E. Efficiencies Through Curtailment of Electricity Retailers........................................................59
F. Estimates of Potential Efficiency Gains...................................................................................61
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Alternative Industry Models................................................................................................................62
A. Model 1: Status Quo...............................................................................................................63
B. Model 2: Expansion of Incentives and Opportunities.............................................................63
C. Model 3: Expansion of LDCs to Municipal Boundaries...........................................................64
D. Model 4: Shoulder-to-Shoulder Robust Efficient LDCs............................................................65
E. Implementation Alternatives..................................................................................................66
Conclusions and Recommendations...................................................................................................68
Appendix A: Responses to Ontario Distribution Sector Review Panel Questions................................75
Appendix B: The U.S. Electricity Distribution Industry........................................................................77
Appendix C: LDCs Achieving Efficiencies through Collaboration:
Examples from Across the Province....................................................................................................91
Appendix D: LDC Reliability Indicators................................................................................................97
Appendix E: LDC Service Quality Indicators.........................................................................................99
Appendix F: LDC Cost Performance Indicators..................................................................................100
Appendix G: Efficiency Opportunity Fact Sheets...............................................................................101
1. Regulatory Constraints on Scope..........................................................................................101
2. Water and Waste-Water Services.........................................................................................103
3. Regulatory Streamlining.......................................................................................................104
4. Street lighting.......................................................................................................................106
5. Electric Vehicle Infrastructure...............................................................................................108
6. Conservation and Demand Management.............................................................................110
7. On-bill Financing...................................................................................................................112
8. Electricity Retailers...............................................................................................................113
Appendix H: Innovation from the Ground Up...................................................................................115
Appendix I: The Case for Reform.......................................................................................................135
Endnotes...........................................................................................................................................147
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Foreword
The Electricity Distributors Association (EDA) is pleased to submit this proposal − a series of
recommendations that address increasing the efficiency of Local Distribution Companies (LDCs).
Our proposal is not submitted in isolation. We understand and appreciate that the Government of
Ontario and its energy agencies are in the midst of a benchmarking study and in one case, a merger
of two important organizations with provincial mandates – the Independent Electricity System
Operator (IESO) and the Ontario Power Authority (OPA). The EDA and our members applaud these
activities, the goal of which is to create better value for electricity consumers. These consumers are
the customers of our members, and our members’ focus is on providing customer value every day.
We are pleased to put forward the system-wide recommendations to further this value.
The Ontario Distribution Sector Review Panel (Panel) has a mandate to:
“Provide advice and make recommendations to the Minister of Energy regarding
issues related to Ontario’s electricity distribution sector and distribution models,
including opportunities for consolidating distributors”.
The EDA supports the work of this Panel – in fact we called for such a review in November 2011 in
our paper titled Electricity is the Answer.
Our province’s dependence on reliable electrical power continues only to grow, and our ability
to continue to meet demand and maintain reliability is paramount. The goal of creating a more
efficient electricity system in Ontario, as a whole, is valid. That drive for efficiency, however, must
never place reliability at risk.
Our submission to the Panel, The Power to Deliver, is very much a proposal that addresses many
issues facing Ontario’s electricity sector. This paper demonstrates that Ontario’s outdated regulatory
model has become a significant barrier in the ability of our members to grow and make the kind of
long-term investments that are critical to renewing our infrastructure. You will also read that our
local members have been addressing Canada’s so-called “Innovation Gap” for decades, as each of
our members develop and test new ideas that, once successfully implemented on a local basis, are
often taken as best practice across our entire industry.
Indeed, the seventy-five member LDCs that serve the province are a broad well of innovation, and
one that needs only the freedom to create and test to develop more system-wide tools for efficiency.
Since 1998, the number of electricity distributors has dropped from more than three hundred to
today’s number of seventy-five. Every year, some of our members determine – voluntarily – that it
is in the best interests of their customers and their shareholders to merge with another member.
So the central question for the Panel, we suggest, is not whether consolidation is necessary, but
whether the heart of any recommendation the Panel may make should benefit Ontario’s more
than 12-million electricity consumers.
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Infrastructure changes require a long view. Short horizons, radical changes, and the quick adoption
of new technologies on a mass scale are all prone to the Law of Unintended Consequences. We’ve
experienced this with the Green Energy Act, provincially mandated conservation and demand
management programs (CDM), and as far back in recent history as de-regulation, re-regulation,
and break-up of Ontario Hydro.
A review of the efficiency potential with Ontario’s electricity distribution sector is not an academic
exercise. As such, the EDA has followed a robust process of stakeholder participation in developing
this proposal. We can state with confidence that every member of our Association has participated
in forming our recommendations and this proposal represents the industry’s position that has
earned the broad support of the EDA’s membership (see Acknowledgements for more detail). This
proposal is a reflection of our overall operating philosophy, that the people who are on the ground,
in each community, working every day with local customers and suppliers, can provide the most
relevant and experienced input into the process.
As the sector responsible for 20 per cent of the cost that customers pay for electricity, we are
pleased to put forward our recommendations for efficiency. We are also confident that efficiencies will be found for the other 80 per cent. A holistic approach to efficiency is required in Ontario’s
power system; including generation, transmission, distribution and delivery as well as regulatory
reform. Much can be accomplished when we work together with a long view towards creating
more value for our customers.
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Guide for Readers
The Proposal before you is a significant document. There is a great deal of information within it and
this information is presented as the basis for well-considered recommendations as well as a series
of options on how to best implement them.
Fully two-thirds of the document is made up of Appendices. In the Appendices you will find the details
of much of the information presented in the document. The data referenced in this document is
current as of 2010, except where more recent data is available and in which case is specifically
noted. Also, the Panel had several specific questions for the EDA. The questions and our
responses are included in Appendix A for ease of reference.
Section 1 of the proposal provides the reader with background information on how Ontario’s LDCs
came to be, what our members are responsible for, and a summary of their current attitudes as it
relates to the Panel’s mandate.
Section 2, The Challenges Facing Distribution, is analysis of the current regulatory, policy, and
implementation issues, concerns, and opportunities that our members are working with as well
as outlining the implications the present situation has on the end goal – increased LDC efficiency.
Section 3 provides the reader details of how the EDA believes that new efficiencies in electricity
distribution can be achieved. These recommendations fall into the categories economies of scale,
economies of scope, the development and delivery of CDM programs, and an overall reform of
the regulatory process.
Section 4 outlines several implementation options for these recommendations, all of which
are founded upon creating measureable cost savings for Ontario’s electricity customers.
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Acknowledgements
This Proposal to the Ontario Distribution Sector Review Panel has been developed under the
guidance of a Committee of the EDA Board of Directors and has been approved by the Association’s
Board of Directors which is representative of the membership on the basis of size and geography.
The proposal reflects the substantial input provided by the Association’s members. Fully 100 per
cent of the membership participated in at least one of the member outreach initiatives that have
taken place over a three-month period which included:
• An all-member meeting
• Four all-member conference calls and weekly email bulletins designed to solicit input and
ensure members were fully informed about the development of the EDA’s submission
• In-person meetings for member LDCs organized on the basis of size constituencies with the
Sector Review Committee of the EDA Board of Directors
• A confidential survey conducted by a recognized third-party market research firm to gather
input from LDCs with 80 per cent of LDC CEOs participating.
• Individual outreach by the EDA to members unable to participate in other activities
The EDA Board of Directors wishes to thank the individuals and teams below for the hard work, debate,
wise counsel, and technical expertise that each has provided in the preparation of this submission.
THE EDA’S SECTOR REVIEW COMMITTEE OF THE BOARD
Jim Keech, Committee Chair and President and CEO, Kingston Hydro Corp.
Max Cananzi, EDA Chair and President and CEO, Horizon Utilities Inc.
Rene Gatien, EDA Vice Chair and President and CEO, Waterloo North Hydro Distribution Inc.
Brian Bentz, President and CEO, PowerStream Inc.
Ed Houghton, President and CEO, Collus Power Corp.
Robert Mace, President and CEO, Thunder Bay Hydro-Electric Distribution Ltd.
Charlie C. Macaluso, President and CEO, Electricity Distributors Association
CONTRIBUTING CONSULTANTS ON THE PROJECT:
Dr. Adonis Yatchew, a professor of economics at the University of Toronto, and a Senior Consultant
at the firm of Charles River Associates a leading global consulting firm. He has assisted in a variety
of litigation proceedings and has testified on numerous regulatory matters. He holds a Ph.D. in Economics from Harvard University.
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Mr. Gary Saleba, a principal and president of EES Consulting in the U.S. providing both management
and strategic consulting advice to clients. Mr. Saleba has over 25 years of experience with electric,
natural gas, water, waste-water, and disposal utilities. Mr. Saleba has extensive experience in utility
rates, financial planning, management audits, professional development educational seminars,
marketing, consumer research, forecasting, integrated resource planning, cost-benefit analyses,
strategic planning, and mergers and acquisitions.
Ipsos Reid, one of the world’s leading survey-based marketing research firms and a market leader in
Canada. Ipsos Reid offers a full line of custom, syndicated, omnibus, panel, and online research products
and services, guided by industry experts and bolstered by advanced analytics and methodologies.
The EDA also acknowledges the contributions of its staff. Their input into this process, technical
advice, and the crafting of this proposal has been invaluable. They, and every one of the people and
organizations who have collaborated on this proposal, should take great pride in this body of work
knowing it is among the most important this Association has produced.
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Executive Summary
The Electricity Distributors Association – the voice of Ontario’s local electricity distribution companies
– respectfully submits this proposal to the Ontario Distribution Sector Review Panel (Panel).
This proposal is Ontario’s electricity distribution sector’s response to the Panel’s official mandate
to provide advice and make recommendations to the Minister of Energy regarding issues related
to Ontario’s electricity distribution sector and distribution models, including opportunities for
consolidating distributors.
The province’s electricity distribution system that operates today is a reflection of the industry
restructuring that occurred in the late 1990s. At that time, the guiding principle of this restructuring
was the premise that Ontario was moving towards a competitive electricity market. One of many
results was that electricity distribution was separated from services such as water and waste-water
treatment, conservation, street lighting ownership and maintenance, and other activities. Over
the past decade, many facets of a deregulated industry model have since been abandoned.
New themes now dominate the industry.
Over the past decade government policy towards distribution has begun to shift once again. Distributors are now permitted to own and operate distributed-generation facilities. They are involved in
the delivery of Conservation and Demand Management (CDM) programs, they have been required
to install smart meters and many have investigated or implemented improved grid technologies.
However, these expanded roles have not been realized without substantial increases in administrative and regulatory costs and complexities.
It is important to remember that electricity is critical to the prosperity of Ontario’s economy and
social fabric. Ontario’s LDCs play an important role in ensuring that provincial customers receive
reliable service at reasonable prices. They:
• serve 4.8-million residential, business and institutional customers;
• employ over 10,000 Ontarians;
• provide in excess of $360-million annually in dividends to shareholders;
• contribute more than $260-million annually to the Provincial government through payments in lieu of taxes (PILs) (excludes Hydro One distribution);
• bear responsibility for assets with a book value of about $16-billion (the market value is
much higher);
• invest approximately $2-billion annually in capital upgrades and grid modernization, thereby
creating additional jobs.
While this proposal makes it clear that while there are case-by-case opportunities for LDCs to consolidate voluntarily for valid business reasons, the overall notion that Ontario’s distribution sector is
inherently inefficient – and therefore a cost burden to the system – is absolutely incorrect.
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We anticipate that the Panel will be looking to the United States for best practice examples and
opportunities. Upon such a review, the Panel will note that for the entire United States, there are
about 3,200 entities serving retail customers. Given a population of about 310-million and about
115-million electricity customers nationwide this corresponds to an average utility size of about
36,000 customers. A similar calculation for Ontario produces a substantially higher number. With a
population approaching 13-million and approximately 4.8-million electricity customers, we obtain
an average utility size of about 60,000 customers. Germany and Denmark, which, like Ontario are
leaders in renewable electricity, also have more distributing entities on a per capita basis than our
province.
Further, as it concerns our neighbours to the south:
• First, small, medium and large distribution entities routinely operate side-by-side and quite
successfully.
• Second, large utilities are not necessarily the least costly.
• And third, U.S. utilities frequently provide multiple services such as electricity distribution,
water and waste-water services.
Still, the question before the Panel is whether or not Ontario may benefit from consolidation in the
electricity distribution sector.
Much has changed from the mid-1990s that gave birth to the present structure. Yet, the Panel
should note less than two decades ago, the number of LDCs in Ontario was more than 300. Today,
that number has dropped to 75, while every year the number of customers served continues to rise.
As an outcome of good business practices, mergers and strategic alliances continue to be developed.
And, there is now smart-grid innovation and the wide-scale development of variable energy resources
such as wind and solar as well as large province-wide conservation and demand programs.
Our members agree that there are opportunities in the sector where consolidation makes sense;
but not, however, as mandated by a central authority. But as the issue of consolidation is on the
table, the Panel will see that this proposal documents several ways to achieve it.
When the Panel considers the efficiency of our industry, we recommend that the Panel assess our
industry’s dynamic efficiency; that is, our ability to respond and adapt to a changing environment.
In competitive markets, organizations that are unable to adapt sufficiently quickly fall by the
wayside or are absorbed by other, more successful organizations.
While electricity transmission and distribution are natural monopolies, the same rule applies.
Ontario’s transmission and distribution companies have been able to evolve and adapt to changing
demands. Well-conceived incentive regulation can ensure that they continue to do so in the future.
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In our view, any structural changes to the distribution sector should:
• Be voluntary and commercially based;
• Where possible, support contiguous or shoulder-to-shoulder mergers to optimize planning
synergies;
• Increase levels of service and reliability to customers; and,
• Reduce costs in the short and long term.
It is the opinion of our members that a centralized and directed approach to consolidation will not
achieve the savings that the government may now envision. Indeed, the costs of such restructuring
could exceed the benefits. We therefore recommend that the Panel consider other meaningful
efficiency-improvement measures, as detailed in this proposal. This includes economies of scale
and scope as well as a regulatory approach that fosters innovation. Inefficiencies in Ontario’s
distribution system are more reflective of the province’s cumbersome and restrictive regulatory
environment than any other single issue.
In our proposal, the Panel will see that we estimate that the potential annual savings to customers
are approximately $540-million, broken down as follows:
• Expansion of the scope of LDC operations to manage water and waste-water services
assuming 7 per cent savings on total distribution costs of all LDCs − $180-million
• Permission for LDCs to carry out street lighting work − $15-million
• Expansion of LDC role in the development of CDM programs that are suitable to customer
needs and that deliver programs with limited OPA involvement − $20-million
• Improvement of the regulatory framework within which LDCs operate − $15-million which
represents 33 per cent of the current expense for LDCs
• Curtailment of energy retailer operations in the residential sector assuming 15 per cent
of those customers are currently on retail contracts − $260-million
• Voluntary consolidation of LDCs with savings of $50-million
With Province-wide electricity bills exceeding $12.8-billion, these savings should have a beneficial
impact of reducing customer costs by approximately five per cent.
There is a high degree of consensus among our members. The overwhelming majority of Ontario
LDCs would like to expand and grow their businesses. Our members are interested in increasing
the scope and the scale of their activities. They believe mergers should be voluntary, incentive-driven
and based on the prospect of being able to retain benefits for their shareholders and customers.
All utilities currently cooperate with other LDCs in one form or another, leading to improved
efficiencies and cost savings for customers. The key challenges are seen to be regulation,
infrastructure renewal, and government policies and directives.
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We offer for the Panel’s consideration, four models for Ontario’s distribution sector:
Model 1: Status Quo
The “status quo” model assumes continuation of the present industry structure and regulatory
and legislative framework. Continuing on the present path would not cause one to anticipate disaster –
there is no imminent crisis that is looming. However, pressures are building. First, regulation is becoming
progressively more onerous and an obstacle to change. Second, aging distribution infrastructure needs
to be replaced or refurbished on an ongoing basis and utilities need to expand the system to continue
to meet customer needs. Both activities require a capital infusion. Third, there is an expanding gap
between provincial CDM aspirations, and the ability of the system to reach the targets under the
present regime.
The most visible challenges to the industry as a whole reside in the generation segment, in
particular cost pressures associated with the nuclear program and renewable generation.
While the “status quo” may be able to sustain itself for a period of time, the overarching disadvantages
of maintaining the status quo in the distribution segment of the industry are the foregone efficiency
gains and the restrictions on further evolution.
Model 2: Expansion of Incentives and Opportunities
The electricity industry is by nature one that breeds a risk-averse culture because of the overarching
mandates for safety and reliability. But the current regulatory and policy environment within which
Ontario LDCs operate is far more restrictive than necessary in areas unrelated to these two mandates.
In fact, the lack of regulatory incentives for innovation, for example with respect to scope economies,
reinforces risk-averse tendencies. Model 2 therefore focuses on the elimination of unnecessary
constraints and the creation of productive incentives and opportunities. In all cases, a high
degree of regulatory certainty is essential if innovative paths are to be followed.
This model would develop incentives and mechanisms that would expand economies of scope and
encourage voluntary transactions that would bring scale efficiencies and benefits to customers and
shareholders. Incentives and mechanisms would focus on:
• enhancing growth through scope by reducing regulatory and other barriers;
• facilitating more access to equity by the LDC/shareholder through regulatory and legislative
changes; and,
• expanding shared services between utilities.
Model 3: Expansion of LDCs to Municipal Boundaries
Model 3 would permit, encourage and incent LDCs to expand to municipal boundaries as a
means to foster greater scale, improved efficiency and consistent customer service. (It is important
to reemphasize that Model 3 is intended to build on the elements that would have already been in
place under Model 2.)
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Model 3 proposes that previous provisions under the Power Corporation Act, which facilitated
expansion of LDCs to municipal boundaries, be revisited. Expansions of this type will benefit the
customers seeking to be served by the local utility. The added local customers will allow further
economies of scale for the LDC.
Many core components of the above model sequence can be implemented with relative ease, in
part because they involve rescinding policies and regulations, and revisiting the intent of previous
policies and legislation. None of these recommendations represent uncharted territory. However,
the pace of change and the end-state depend largely on the future structure of legislation and regulation, and the intentions and resolve of the Government.
Model 4: Shoulder-to-Shoulder, Robust, Well-Resourced and Efficient LDCs
One of the principles which underlies this model is the potential for gains arising out of economies
of contiguity. The technology of electricity distribution is such that it is more efficient to serve customers that populate a contiguous self-contained area. A utility may serve multiple areas, but it is
preferable if each of its service areas is of sufficient size so that economies of scale are also realized.
The EDA does not view expanding the Provincial government’s role in distribution as an efficient or
desirable consolidation option.
One of the difficulties that is likely to be encountered is the rate treatment of low-density customers. A rural-rate subsidy will be required. The establishment of a separate entity which serves these
customers and which receives appropriate transfers may comprise a practical solution.
We suggest two options for implementation:
Option A: Under this alternative, the Government and regulator proceed with the necessary
changes to enable the above sequence of models, but do not predetermine the end-state.
Option B: Under this alternative, it is concluded that the Province is best served by shoulder-to-shoulder distributors, i.e., Model 4. Therefore, the Government and regulator then
proceed with promoting the realization of Model 4.
Option A focuses on changes in the setting within which utilities operate. Option B focuses on the
“end-state” structure for the distribution industry. The EDA is willing and fully prepared to work
with the Government, utilities and stakeholders to determine the preferred option.
Highlights of this Proposal
Efficiency Savings. We estimate that the implementation of efficiency-improving measures
such as enhanced regulation, expansion of scope economies, improved CDM design and
delivery and curtailment of electricity retailers would reduce customer bills by approximately
$540-million, or about five per cent of total customer electricity costs.
Regulatory Streamlining. Regulatory systems can be enhanced by providing flexibility to
utilities whereby they could choose fast-track approvals with lesser information requirements
and consolidated applications, or more detailed approval processes. Efficient utilities could
receive a streamlined review based on established benchmarks or milestones.
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Economies of Scope. There are significant opportunities for efficiency gains through
economies of scope. Historically, Ontario multi-utilities exhibited on average seven per cent
lower costs for electricity customers than pure distribution utilities. An Ipsos Reid survey
conducted for the EDA identified 18 ways that LDCs could expand their scope of activities.
Regulatory and legal impediments which limit LDC ability to engage in these activities
should be eliminated.
Economies of Scale. Voluntary mergers among distributors may lead to further efficiency
savings. However, the vast majority of Ontario electricity customers are served by electricity
utilities which are sufficiently large to have achieved scale efficiency. Mandated mergers, for
the purposes of simply reducing the number of distributors and creating larger utilities, are
therefore unlikely to achieve material savings and could erode yardstick competition which
has a beneficial impact on efficiency and innovation. Alternatively, voluntary mergers offer
potential savings.
Technology and Innovation. Technology is a primary determinant of industry structure
and therefore technological change should be a primary driver of changes in industry
structure. As new technologies emerge and proliferate, there may be increased incentives
for restructuring. Market forces and technology should drive change in the future structure
of the industry.
Diversity. Electricity industries, like ecosystems, have multiple participants striving to
advance individual and collective interests. Within such systems, diversity is often more a
benefit than a hindrance. In the Ontario electricity industry, a diversity of distributors seeking
alternative business models and solutions to the challenges they face provide an important
benefit to the industry as a whole. Diversity benefits need to be considered in any discussion
of industry restructuring.
Industry Structure. The right of LDCs to expand to municipal boundaries should be revisited.
With the creation of an enabling environment, the industry may eventually be comprised of
shoulder-to-shoulder utilities servicing all areas of the Province.
Curtailment of Electricity Retailers. As the Province has moved away from the competitive
model and introduced a regulated price plan for residential customers there is no longer
the need for electricity retailers to provide rate-smoothing contracts to the residential sector.
Furthermore, by offering fixed prices, electricity retailers are undermining a fundamental
objective of government policy – the implementation of time-of-use (TOU) rates. Electricity
retail contracts for the residential sector should therefore be phased out.
Conservation and Demand Management. CDM program design should be devolved to
distributors as has been the case in the past. Distributors are best positioned to respond
to local needs by designing programs that take into account local conditions. Increased
customer participation can be attained through devices such as “on-bill financing” of
conservation investments.
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Access to Capital. Two impediments limit LDC access to capital. First, municipalities are not
permitted to invest in the utilities they own. Second, there are limitations on private equity
investments in distributors. Both impediments should be reduced in order to permit wider
access to capital for Ontario’s distribution utilities. Tax-exempt status for LDCs with greater
than 51 per cent of municipal ownership should be considered.
Ipsos Reid Survey. There is a high degree of consensus amongst Ontario LDCs. The overwhelming majority would like to expand and grow their businesses. They are interested
in increasing the scope and the scale of their activities. They believe mergers should be
voluntary, incentive-driven and based on the prospect of being able to retain benefits for
their shareholders and customers. All utilities cooperate with other LDCs in one form or
another, leading to improved efficiencies and cost savings. The key challenges are seen
to be regulation, infrastructure renewal, and government policies and directives.
Infrastructure Investment. Aging LDC infrastructure needs to be refurbished or replaced
on an ongoing basis and new investment is required to meet system growth and expansion.
The essentiality of electricity to the economy and to society mandates the continuation
of the record of excellent service and reliability.
Smart-grid Technologies. Utilities should continue expanding their functional capabilities to
accommodate new and emerging technologies such as smart-grid systems and distributed
generation. Implementation of these technologies should be achieved on a cost-effective
basis as determined by individual utilities and the regulator. Incentive based approaches
should be implemented where possible.
Distributed-generation. Distributors should be permitted to own and operate both renewable
and non-renewable generation greater than 10 MW. As renewable supply increases it may
be appropriate for LDCs to acquire non-renewable dispatchable generation to compensate
for fluctuating renewable supplies.
Cooperative Ventures. Ontario utilities cooperate extensively in numerous areas which
improves efficiency and diffusion of best practices. Such cooperation should be encouraged
and any regulatory obstacles should be eliminated.
Overall, there is a high degree of consensus
amongst Ontario LDCs. The overwhelming majority
would like to expand and grow their businesses.
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Introduction and Background
A.History of LDC Evolution in Ontario
Over the course of the 20th century, the electricity industry in Ontario followed the public
power model whereby most of the electricity was generated, transmitted and distributed by publicly
owned entities. Most prominent among these was Ontario Hydro. The delivery of electricity to
urbanized areas was performed by community-based entities such as Hydro-Electric Commissions
and Public Utility Commissions. The latter were typically multi-utilities involved in other activities
such as water services, waste-water management, street lighting and conservation. Distributor
activities were governed primarily by the Public Utilities Act and the Power Corporations Act.
Over time, many municipally owned LDCs were established. By the 1970s there were over 300 LDCs
in Ontario, many of which were multi-utilities. Eventually, these were encouraged to extend their
service territories to municipal boundaries. Such expansions, supported by enabling legislation such
as the Bill 185 (1994), Amendment to the Power Corporation Act required the transfer of assets
from Ontario Hydro to an LDC municipal service territory.
During the 1990s, a number of restructuring and deregulation models were proposed. An active
debate took place and formal mechanisms for changing the industry were initiated. By the late
1990s, as part of the preparation for deregulation of the electricity marketplace, LDCs were
required to cease their broad range of services and to focus exclusively on the “poles and wires”
business. Furthermore, LDCs were no longer afforded the opportunity of absorbing surrounding
service areas as had previously been the case. The number of distribution utilities fell dramatically.
The figure on page 10 displays data on the number of LDCs from 1985 (at which time there were
316) to the presently existing 75 LDCs. In 1975, there were actually 353 local distribution companies
in Ontario in addition to Ontario Hydro’s Power District, the predecessor of the distribution
component of Hydro One.
Many utilities acquired or merged with neighbouring utilities on a voluntary basis. Others were
purchased by Hydro One. Still others merged as a result of consolidation of municipalities.
Industry restructuring was enabled by legislative changes. Bill 35, the Energy Competition Act, 1998,
enacted the Electricity Act and the Ontario Energy Board Act. This legislation set the legal framework
for restructuring the old Ontario Hydro into successor companies, commercializing the distribution
industry, and the opening of the competitive wholesale market in electricity on May 1, 2002. The
Electricity Act 1998 created the initial institutional structure. The Ontario Energy Board Act 1998
granted new regulatory powers to the Ontario Energy Board (OEB) over the various entities, among
them distribution and transmission companies. (Previously, Ontario distributor rates were regulated
by Ontario Hydro.)
9
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In 2002, Ontario’s short-lived foray into a fully competitive market structure for electricity began
and ended. Shortly after the market opened, prices rose, after which the Provincial government
moved quickly to stabilize prices.
The Electricity Restructuring Act 2004 established a new entity, the Ontario Power Authority (OPA),
which would be the provincial procurer of the majority of long-term supply. In 2004, the Provincial
government “unfroze” electricity rates. A “hybrid” market was now in the process of being established.
The Act also dispensed with the “wires-only” model for Ontario distributors. In 2005, the Ontario
government further clarified that LDCs would retain ownership and operation of smart meters.1
Figure 1: Ontario Electricity Industry Timeline
In 2006, the Energy Conservation Leadership Act was passed. It effectively recognized that for
conservation to be truly effective, energy-management planning needed to take place not just
at the provincial level, but at the local community level as well. A subsequent Ministerial Directive
declared that the OPA was to directly provide CDM programs only where LDCs were unable to do so.2
In effect, the LDCs were recognized as the primary vehicle for delivery of CDM programs.
At about the same time, the Renewable Energy Standard Offer Program (RESOP) was launched,
the purpose of which was to promote the development of renewable energy systems.
10
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In 2009, the Provincial government passed the Green Energy and Green Economy Act (Green Energy
Act), the central purpose of which was to promote renewable electricity production and conservation
and demand management programs. The Act established feed-in-tariff programs for renewable
energy and required distribution and transmission entities to connect such facilities. Distributors
were permitted to own small-scale renewable energy generating facilities. The Act also introduced
new objectives for the OEB, including the promotion of renewable energy, conservation and demand
management, and smart-grid technologies. It also required distributors to achieve conservation and
demand management targets to be set by the OEB.
Notably, the Act provided for more active Government involvement in the management of renewable energy, conservation and smart-grid initiatives through Ministerial directives. The approach
marks a potentially substantial increase in government involvement in decision-making and
management of the electricity sector.
In 2012, the Government put forward legislation to merge the OPA and the IESO into a single
entity, the Ontario Electricity System Operator (OESO). Benchmarking of Hydro One and Ontario
Power Generation has become an important governmental objective. Furthermore, the Drummond
Report, which was commissioned by the Ontario Government with the purpose of developing debt
reduction mechanisms for the Province, recommended that Hydro One and Ontario Power Generation
seek to improve their finances through strategic partnerships.3
Thus, over the past decade, government policy towards distribution has begun to shift once
again. Distributors are now permitted to own and operate distributed-generation facilities. They
are involved in the delivery of CDM programs, they have been required to install smart meters and
many have investigated or implemented improved grid technologies. However, these expanded
roles have not been realized without substantial increases in administrative and regulatory costs.
B.Distribution Sector Contributions to Ontario’s Economy
Electricity is critical to the prosperity of every economy and Ontario’s LDCs play an important role
in ensuring that provincial customers receive reliable service at reasonable prices. Ontario LDCs:
• serve 4.8-million residential, business and institutional customers;
• employ over 10,000 Ontarians with a payroll of more than $800-million annually;
• provide in excess of $360-million annually in dividends to shareholders;
• contribute more than $260-million annually to the Provincial government through
payments-in-lieu of taxes (excludes Hydro One Distribution);
• bear responsibility for assets with a book value of about $16-billion; (the market value
is much higher);
• invest approximately $2-billion annually in capital upgrades and grid modernization,
thereby creating additional jobs.
11
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C.Ipsos Reid Survey
An Ipsos Reid survey was conducted on behalf of the EDA over the period June 11-22, 2012. Of the
75 Ontario distribution utilities, 59 were able to participate and were interviewed by telephone. In
almost all cases the CEO of the LDC was interviewed. The purpose of the study was to gather opinions on some important issues facing the LDCs, and to assist the EDA with its planning and stakeholder relationships.
The main objectives were to:
• investigate the interest among the EDA members to expand the scope and scale
of their business;
• determine the most favourable ways to achieve expanded scope and scale;
• pinpoint possible challenges facing the EDA members in growing their business;
• gauge current levels and the degree of interest in cooperation between LDCs;
• develop an understanding of what the LDCs believe they will look like in the future.
Expansion of Business
Almost all LDCs are interested in expanding their business. The expansion of scope has slightly
more enthusiasm behind it than scale expansion, but LDCs in general are receptive to expanding
their business in many ways.
Expansion of Scope
Most believe that LDCs of the future are bigger in scope and services, but LDCs are split on whether
they need scale expansion to match the scope expansion. Most believe that CDM should be a growth
business for LDCs.
From among the 18 different ideas of scope expansion tested, over a dozen attracted solid interest
from most of the LDCs, suggesting that scope expansion is highly palatable to LDCs. The top areas
of interest include CDM program design, street lighting maintenance services, and electric vehicle
charging infrastructure.
12
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LDC Interest in Expansion of Scope of Activities
Activity
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
11.
12.
13.
14.
15.
16.
17.
18.
Percentage of
LDCs Interested
CDM Design
Street Lighting Maintenance Services
Electric Vehicle Charging Infrastructure
Water and Waste-water Management
Energy Storage
Non-Renewable Generation (less than 10 MW)
Streetlight Ownership
Energy From Waste
Energy Audits
Renewable Generation (greater than 10 MW)
Water and Waste-water Ownership
Financing Conservation and Demand Management
Combined Heat and Power
District Heating
Non-Renewable Generation (greater than 10 MW)
Electrical Inspections
Financing Customer-Owned DG
Transmission Ownership (greater than 10 kV)
92%
92%
90%
78%
78%
75%
75%
75%
73%
71%
69%
69%
69%
58%
51%
49%
47%
46%
While a slim majority of LDCs want to handle the expansion of scope within the LDC, nearly half
want to handle it within an affiliated company.
The key barriers to the expansion of scope are primarily regulatory issues, followed by financing/
capital issues and the Affiliate Relationships Code.
Expansion of Scale
There are differences in views among LDCs on whether the size of the utility will dictate its ability
to meet future challenges, and a majority disagrees that LDCs of the future are necessarily bigger
in scale and size. However, most strongly believe that LDCs that increase their scale should be
permitted to conduct a wider scope of activities.
There is a good deal of appetite for scale expansion of all sorts, with the exception of acquiring
assets in a service area that doesn’t border their current service area.
LDCs believe that incentives could be offered to enable voluntary, commercially driven mergers
such as changes in the transfer tax, and the prospect of a reasonable rate of return.
Reflecting on key barriers to scale expansion, regulation once again rises to the top. However,
a lack of willing participants, political will, and capital availability are seen as key barriers.
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Cooperation Among Utilities
Every LDC interviewed is cooperating with other LDCs in some capacity. The greatest degree of
cooperation appears to be with mutual aid, engineering standards, CDM and smart metering.
Most LDCs offered other areas in which they’re currently cooperating with other LDCs, and many
had other ideas of where LDCs could cooperate, or where they would be interested in cooperating.
It appears that many LDCs see cooperation as a key way by which to manage scale and scope
expansion. In fact, most LDCs want to handle LDC-led conservation in partnership with other LDCs.
Few want to go it alone.
The Future of LDCs
Once again, regulation rises to the top of the list as being among the key challenges for LDCs over
the next ten years. Infrastructure issues as well as political interference are also key challenges.
When describing the LDC of the future, the characteristics that were common themes include an
expansion of scope, technological innovation and smart metering, and, to a lesser extent, scale
expansion.
Most believe that their LDC is well prepared to meet the challenges of the future. They believe
that LDCs of the future are high-tech and innovative, and that innovation is their driving principle.
As part of this, most believe that implementing smart-grids is the key to the way forward.
While most believe that regulatory oversight should be the same for all LDCs regardless of public
or private ownership, they are split on whether regulatory oversight should be the same for LDCs
of all sizes.
The top challenges for LDCs include government policies and directives, regulation, human resources,
and price increases for the total bill. Other challenges, while widespread, are secondary to these.
While faced with many regulatory challenges, the rate-approval process, regulatory costs and the
intervenor process are seen as the most critical.
LDCs are evenly split on whether they are confident or not that they will meet their provincial targets
for reducing energy usage in kilowatt-hours (kWh), or reducing peak demand in kilowatts (kW).
Summary
Overall, there is a high degree of consensus amongst Ontario LDCs. The overwhelming majority
would like to expand and grow their businesses. They are interested in increasing the scope and
the scale of their activities. They believe mergers should be voluntary, incentive-driven and based
on the prospect of being able to retain benefits for their shareholders and customers. All utilities
cooperate with other LDCs in one form or another, leading to improved efficiencies and cost
savings for customers. The key challenges are seen to be regulation, infrastructure renewal,
and government policies and directives.
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Hydro One Remote Communities
The Ontario electricity industry has an exemplary record of providing the highest standards of
service and reliability. It has done so in the face of major changes within the industry. The essentiality of electricity to our economy and society mandates that this record continue to be upheld.
However, the industry continues to face major challenges.
Updated_EDA Report _FINAL(i-114pages).pdf 23
Sault Ste.
Marie
PUC
Distribution
Inc.
Cat Lake
Northern Ontario
Wires Inc.
Cochrane, Iroquois
Falls, Kapuskasing
Hydro One Remote Communities
Windsor
Amherstburg,
LaSalle,
Leamington,
Tecumseh
Essex, Harrow,
Belle River,
Comber,
Kingsville,
Cottham
Parkhill, Strathroy,
Mount Brydges, Newbury,
Dutton, Wallaceburg, Dresden,
Bothwell, Thamesville,
Ridgetown, Chatham-Kent,
Blenheim, Merlin, Tilbury,
Wheatley, Erieau
Entegrus Powerlines Inc.
Stratford, St. Mary's,
Seaforth, Hensall, Brussels,
Zurich, Dashwood
Sarnia, Point Edward, Petrolia,
Alvinston, Oil Springs, Watford
E.L.K.
Energy Inc.
Elora, Fergus
Centre Wellington
Hydro Ltd.
Waterloo North Hydro Inc.
Holstein, Mount
Forest, Arthur
Wellington North
Power Inc.
Collingwood,
Stayner, Creemore,
Thornbury
Halton Hills
Hydro Inc.
Guelph Hydro Electric
Systems Inc.
Whitby Hydro
Electric Corporation
Cobourg
Lakefront
Utilities
Inc.
Oshawa PUC Networks Inc.
Newmarket,
Tay Township,
Perth County
Toronto Hydro-Electric
System Limited
Innisfil Hydro
Distribution
Systems Limited
Enersource Hydro
Mississauga Inc.
Hydro One Brampton
Networks Inc.
Orangeville,
Grand Valley
Orangeville
Hydro Limited
Midland Power
Utility Corporation
Wasaga
Orillia Power
Distribution
Distribution
Inc.
Corporation
Newmarket –
Tay Power
Distribution Ltd.
Ajax, Beaverton,
Belleville, Bowmanville,
Cannington,
Gravenhurst, Newcastle,
Orono, Pickering, Port
Hope, Port Perry,
Sunderland, Uxbridge
Aylmer, Belmont,
Burgessville, Beachville,
Clinton, Embro, Ingersoll,
Otterville, Port Stanley,
Norwich, Tavistock,
Thamesford, Clinton,
West Perth
Erie Thames Powerlines
Corporation
Stratford, St. Mary's,
Seaforth, Hensall, Brussels,
Zurich, Dashwood
Tillsonburg Hydro Inc.
Fort Erie,
Port Colborne
Canadian
Niagara Power Inc.
(Fortis)
Renfrew
Hydro
Peterborough,
Marie
Lakefield, Norwood
Sault Ste.
Kashechewan First Nation
Essex
Powerlines
Corporation
ENWIN
Utilities Ltd.
E.L.K.
Energy Inc.
Bluewater Power
Distribution Corporation
Cochrane, Iroquois
Falls, Kapuskasing
Northern Ontario
Wires Inc.
Fort Albany Power Corporation
Entegrus Powerlines Inc.
Festival Hydro Inc.
West Coast Huron
Energy Inc.
Gananoque
Hydro
Hawkesbury Inc.
Westario
Power Inc.
Distribution Ltd.
Wasaga
Distribution
Inc.
Orangeville
Hydro Limited
COLLUS Power
Corporation
Wellington North
Power Inc.
Innisfil Hydro
Distribution
Systems Limited
Veridian
Connections Inc.
Newmarket –
Tay Power
Distribution Ltd.
North Bay Hydro
Distribution Limited
Orillia Power
Distribution
Corporation
Midland Power
Utility Corporation
Parry Sound
Power Corporation
Westport,
Prescott,
Bracebridge,
Burk's Falls,
Huntsville, Magnetawan,
Cardinal,
Iroquois,
Sundridge
Morrisburg, Williamsburg
Rideau St. Lawrence
Lakeland Inc.
Power
Distribution
Cornwall Street
Railway Light and
Power Company
(Fortis)
Alfred, Plantagenet
Hydro 2000 Inc.
PowerStream Inc.
Oshawa PUC Networks Inc.
Centre Wellington Hydro One Brampton
Toronto Hydro-Electric Whitby Hydro
Networks Inc.
Hydro Ltd.
Electric Corporation
System Limited
Halton Hills
Guelph Hydro
Enersource Hydro
Hydro Inc.
Electric
Mississauga Inc.
Waterloo North Hydro Inc. Systems Inc.
Milton Hydro
Oakville
Hydro
Distribution Inc.
Kitchener-Wilmot
Electricity Distribution Inc.
Hydro Inc.
Cambridge and North Burlington
Niagara-on-the-Lake
Dumfries Hydro Inc.
Hydro Inc. Grimsby
Woodstock
Power Inc. Hydro Inc.
Horizon Utilities
Hydro Services
Brantford Power Inc.
Corporation
Inc.
Brant
Niagara Peninsula
County Power
Energy Inc.
Inc.
London
Norfolk
Haldimand
Hydro Inc.
Power
County Hydro Inc.
Canadian
Distribution
Tillsonburg
Niagara
Power
Inc.
Inc.
Welland
St. Thomas
Hydro Inc.
(Fortis)
Hydro-Electric
Energy Inc.
System Corp.
Erie Thames Powerlines
Corporation
Eastern Ontario
Power (Fortis)
Sudbury, West
Nipissing
Co-operative
Hydro Embrun
Greater Sudbury
Inc.
Hydro Inc.
Ottawa, Casselman
Hydro Ottawa Limited
Espanola, Webbwood,
Massey
Kingston Hydro
(Utilities Kingston)
PUC
Peterborough
Distribution
Distribution
Incorporated
Inc.
Espanola Regional
Hydro Distribution
Corporation
Chapleau Public
Utilities Corp.
Hearst Power Distribution
Company Limited
Hydro One
Service Area
Algoma Power Inc.
Almonte, Beachburg,
Killaloe, Pembroke
Dubreuil Forest
Products Ltd.
Ottawa River Power
Corporation
Veridian
Connections Inc.
North Bay Hydro
Distribution Limited
Milton Hydro
Oakville Hydro
Guelph, Rockwood
Distribution Inc. Electricity Distribution Inc.
Kitchener-Wilmot
Hydro Inc.
Cambridge and North Burlington
Niagara-on-the-Lake
Dumfries Hydro Inc.
Hydro Inc. Grimsby
Woodstock
Power Inc. Hydro Inc.
Horizon Utilities
Hydro Services
Brantford Power Inc.
Corporation
Inc.
Brant
Hamilton, St. Catharines
County Power
Inc.
Norfolk
Haldimand
Niagara Peninsula
Power
County Hydro Inc.
Energy Inc.
Distribution
Niagara
Falls, Lincoln,
Inc.
Welland
Pelham, West Lincoln
Hydro-Electric
System Corp.
Waterloo, Woolwich, Wellesley
London
Hydro Inc.
St. Thomas
Energy Inc.
Hanover, Huron-Kinloss,
Kincardine, Saugeen Shores,
South Bruce, Wingham,
Brockton, Minto
Alliston, Aurora, Barrie,
Beeton, Bradford West,
Gwillimbury, Penetanguishene,
Markham, Richmond Hill,
Thornton, Tottenham, Vaughan
PowerStream Inc.
Parry Sound
Power Corporation
Bracebridge, Burk's Falls,
Huntsville, Magnetawan,
Sundridge
Lakeland Power
Distribution Ltd.
COLLUS Power
Corporation
Thunder Bay Hydro Electricity
Distribution Inc.
Sudbury, West
Nipissing
Greater Sudbury
Hydro Inc.
Westario Power Inc.
Festival Hydro Inc.
West Coast Huron
Energy Inc.
Goderich
Five Nations
Energy
Attanapiskat First Nation
DRAFT
Atikokan
Hydro Inc.
Espanola, Webbwood,
Massey
Bluewater Power Distribution
Corporation
ENWIN
Utilities Ltd.
Essex
Powerlines
Corporation
Fort Frances
Power
Sioux Lookout
Hydro Inc.
Espanola Regional
Hydro Distribution
Corporation
Chapleau Public
Utilities Corp.
ONTARIO’S ELECTRICITY
DISTRIBUTION SYSTEM
LOCAL DISTRIBUTION COMPANY
SERVICE AREAS
Kenora Hydro Electric
Corporation Ltd.
Algoma Power Inc.
Dubreuil Forest
Products Ltd.
Hearst Power Distribution
Company Limited
Kashechewan First Nation
Fort Albany Power Corporation
Lakefront
Utilities
Inc.
Hydro One
Service Area
Renfrew
Hydro
Peterborough,
Lakefield, Norwood
Kingston Hydro
(Utilities Kingston)
Peterborough
Distribution Incorporated
Almonte, Beachburg,
Killaloe, Pembroke
Ottawa River Power
Corporation
Gananoque
Eastern Ontario
Power (Fortis)
Hydro
Hawkesbury Inc.
Cornwall Street
Railway Light and
Power Company
(Fortis)
Alfred, Plantagenet
Hydro 2000 Inc.
March 2012
Westport, Prescott,
Cardinal, Iroquois,
Morrisburg, Williamsburg
Rideau St. Lawrence
Distribution Inc.
Co-operative
Hydro Embrun
Inc.
Ottawa, Casselman
Hydro Ottawa Limited
The Challenges Facing Distribution
15
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A.Infrastructure Investment
In recent years, investment in distribution has been and continues to be driven by the need for
replacement, expansion and upgrades. The Ontario electricity distribution industry collectively
holds a portfolio of assets of widely varying ages some of which date back to the 1940s and 1950s.
Engineering as well as statistical analyses suggest a trade-off between replacement, refurbishment
and maintenance costs. These processes must be undertaken on a continuous basis if long-term
costs are to be minimized and reliability is to be ensured.
There is also considerable need for investment in generation and transmission. Many Ontario
generation assets are aging or, in the case of coal, are being retired to promote environmental
objectives. Investment in transmission has been driven by several factors including the need to
improve grid reliability, integrate renewable generation, and improve interconnections with
neighbouring jurisdictions.
Distribution utilities need to be able to upgrade infrastructure to accommodate distributed
generation and to take advantage of evolving technologies. In this connection, regional cooperation
in transmission and distribution planning is essential.4
Growth in demand for electricity, albeit at a reduced rate, is also an important investment driver.
Current forecasts suggest that on average, demand will grow at less than one per cent per year over
the next two decades.5 The growth will not be distributed evenly across distribution utilities. For example, utilities that serve expanding suburban areas are likely to experience faster demand growth.
Current long-term demand forecasts may be low if penetration rates of electric vehicles or other
electricity intensive technologies are higher. As suggested earlier, the share of electricity in total
energy consumed has been growing and is projected to continue to grow. On the other hand, if the
price of electricity increases more quickly than currently forecast, there will be a dampening effect
on demand.
The share of electricity in total energy consumed has
been growing and is projected to continue to grow.
Finally, distributors are the direct interface between the electricity supply chain and the end user.
In today’s changing electricity environment, informing and educating customers is even more
essential. Some utilities have already invested in online systems which allow customers to view
their recent consumption patterns and the prices that they pay.
16
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B.New and Emerging Technologies
Smart Grid-based Innovation
Advances in information and communication technologies have created an environment where
various new technologies can now, or in the near future, be incorporated into electricity grids.
These technologies have the potential of improving operations in multiple dimensions by:
• increasing the efficiency with which power is delivered,
• improving reliability through remote sensing and automated recovery,
• improving response times in the event of malfunctions,
• facilitating the integration of distributed generation, renewable resources, storage and
electric vehicle charging technologies, and
• improving overall system security.
Among the important enabling technologies are devices which permit simultaneous measurement
of key characteristics at numerous points throughout the grid. Information of this type can provide
system operators with earlier warnings of any system instabilities which may be emerging and that
may require attention.
Ontario is at the forefront of this technological frontier with legislators, regulators, utilities and
other corporations and organizations taking a direct role. The Ontario Smart Grid Forum, under the
auspices of the IESO, draws on representatives from various companies and organizations, including
Ontario transmission and distribution utilities.
To ensure cost-effective investments in this area, it is important to keep certain factors in mind. First,
the overlay of these new technologies onto existing systems must not risk impairment of reliability of
service. Second, there are disadvantages to the earliest adopters since this is when prices are usually
the highest and the technology has not yet stabilized. Some utilities, for whom these innovations are
presently less crucial, may delay implementation until the technology reaches greater maturity.
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Although one would expect that information technology will improve industry productivity, history
suggests that this will not necessarily occur quickly. During the 1980s and 1990s, there was a general expectation that computers would have a dramatic impact on productivity of the overall economy. This was not to be the case. In fact, during the same period that computer technology was
becoming ubiquitous, productivity was actually slowing. Acceleration in productivity did not occur
until much later, during the late 1990s. The electricity industry has the added important characteristic that assets are long-lived so that the capital stock changes slowly and, as a consequence, capital
intensive technological changes may need to be implemented over a period of time. In short, the
useful economic lifetime of electricity industry assets is measured in decades.6
Longer pay-off periods are not an argument to avoid investment in these new technologies. The
expected pay-off period should, however, be considered in regulatory settings where prices incorporate the expectation of productivity growth (e.g., through the “X-factor” in price cap regulation).
Thus, while some smart-grid investments could lead to immediate and observable improvements in
productivity, others are likely to have a longer gestation period.
Smart Meters and Time-of-Use Pricing
The nature of electricity systems is such that system
operators must adjust supply to meet demand at
any given moment. Although operator management of demand has been part of electricity
operations for many years, for example through
interruptible load, this component has comprised
a relatively small portion of the overall supplydemand balance. The inability to affect demand
response over short intervals has generally
increased the level and volatility of system costs.
Recent technological advances have created
the possibility of greater responsiveness on the
demand side. Major categories of technologies which are central to demand response include:
• meters that record electricity consumption by time-of-day enable the implementation
of static TOU rates which can be calibrated to approximate expected system costs averaged
over time;
• information systems that transmit current system costs to consumers enable the implementation of dynamic TOU rates which reflect actual system costs;
• information and control systems that facilitate end-user response to real-time prices; these
include “apps” which permit integration of price and usage information in real time, and
smart appliances which can automate response to such information.
18
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Ontario has engaged in province-wide installation of smart meters. This has been a costly undertaking but the payoffs can be significant. Implementation of TOU rates is well underway. Nevertheless,
there are important and ongoing issues relating to their use. TOU experiments have been conducted for many years and in many jurisdictions, but the results vary significantly and the determination of optimal TOU rates remains an ongoing project. Among the central issues are the elasticity of
response and the importance of real-time information. Studies conducted elsewhere suggest that
the ratio of peak to off-peak prices is a critical determinant of customer response and that real-time
pricing can lead to responsive participation by end-use customers.
A number of Ontario utilities have conducted
time-of-use pricing experiments and analyses. These
include Hydro Ottawa, Veridian Connections, Oakville
Hydro, Newmarket-Tay Hydro, Hydro One, Toronto
Hydro and Milton Hydro.
A number of Ontario utilities have conducted time of use pricing experiments and analyses.
These include Hydro Ottawa, Veridian Connections, Oakville Hydro, Newmarket-Tay Hydro, Hydro
One, Toronto Hydro and Milton Hydro. The results have been generally supportive of a material
customer response to TOU pricing. Future analyses that incorporate further refinements will no
doubt help to inform better use of these technologies.
An accurate understanding of
customer response to increasingly
sophisticated technology can be of
great value. For example, the majority of Ontarians are on TOU rates.
The installation of the required
metering technology is now a sunk
cost. It would be extremely valuable
to determine the incremental system
and customer benefits arising from
the implementation of the next level
of technology which would permit
real-time transmission of price information to customers.
These are analyses best conducted at the local level by distributors, since responsiveness varies
widely by location. For example, utilities in northern parts of the Province tend to be winter-peaking
because of electric-heating demand. Utilities in southern Ontario are much more strongly affected
by air-conditioning demand during the summer, indeed some experience their annual peaks during
the summer.
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A realistic assessment of the response is further complicated by the difficulties in predicting the
effectiveness of “apps” which can be used by end-use customers to adapt consumption patterns
to real-time information and penetration rates of smart appliances and control devices.
Keeping in mind that early implementation is not necessarily optimal in all cases, knowledge of
the resulting benefits could inform both the timing and the type of systems that will ultimately
be installed.
In all these areas, Ontario distributors can play an important continuing role in data collection and
analysis, in rate design and in post-implementation assessment. Furthermore, the presence of a
variety of distributors with differing characteristics and business models provides opportunities
for innovation through a diversity of approaches.
Ensuring Investment in New Technologies in Ontario
Ontario is leading North America in the installation of smart meters. The technologies associated
with smart meters provide the opportunity to move forward with smart grid and other innovative
emerging technologies. The information available through smart-grid technologies will allow better
distribution system monitoring and control to reduce the occurrences of outages and to improve
response and restoration times when they do occur.
Smart meters allow customers to monitor their consumption, but smart-grid technologies could
allow customers to control their consumption remotely. Smart grids will increase the opportunities
for improved demand response and energy conservation. The communication networks could also
be used to allow remote meter reading of gas and water consumption. The smart-grid communication networks could also be used to connect and manage electric vehicles and electricity-storage
facilities. The networks could be leveraged by other service providers to allow other services such
as security monitoring. Additional information on electric-vehicle infrastructure can be found in
Efficiency Opportunity Fact Sheet #5 in Appendix G.
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These opportunities for improving the functioning and reliability of the grid arise from technological developments in sensing, communications, control, and power electronics. These technologies
provide better visibility of the instantaneous state of the grid, and make possible the engagement
of demand as a resource for meeting system requirements.
If the technologies are properly deployed and supported by facilitating policies, they can help
address the upcoming challenges to the industry including aging infrastructure and facilitating
the integration of renewable and distributed generation.
To leverage the operational benefits of its smart
meters and communication networks, distributors
need to invest in people, devices, tools and
applications.
To leverage the operational benefits of its smart meters and communication networks, distributors need to invest in people, devices, tools and applications (e.g. transformer monitoring for asset
management, home displays and load control for demand response). The major initial investment
in smart grid was the smart meter communication system. Building the next phase will require a
new policy commitment and regulatory support that recognizes the higher initial costs in systems,
equipment, and skilled resources required to obtain a longer-term benefit. To encourage further
investments in the smart grid, consideration should be given to providing a higher rate of return on
smart-grid investments.
Further policy support is needed to encourage distributors to continue moving forward and to
leverage the lead obtained from being early adopters in smart meter technology. These new technologies and capabilities will provide further societal benefits and should be supported by the
regulator. The regulator should view investments used to monitor and control distribution networks
as part of the normal system expansion and renewal to support reliability and safety. The regulator
should also encourage distributors to leverage their smart-grid systems to provide additional services, such as customer demand response and load control, electric vehicle charging management
and remote meter reading for other utilities.
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These new investments to manage the integration of distributed generation, electric vehicles, and
demand response will require significant investments in new and emerging technologies that will
provide new capabilities. However, there is a general observation that regulators typically have a
tendency to be conservative when considering investments in new unproven technologies. This
tendency of traditional regulatory oversight to be overly conservative could become more and more
expensive over time if opportunities to enhance efficiency and reduce cost through innovation are
not exploited. This is an issue because it seems both regulators and utilities are penalized or criticized for unanticipated poor outcomes but not adequately rewarded for good outcomes. Keeping
the lights on is a challenge in itself, yet we all take this for granted. Nonetheless, regulatory changes
are needed to provide adequate incentives for investments in unfamiliar technologies while also
ensuring that these investments benefit customers.
Regulators typically have a tendency to be
conservative when considering investments in
new unproven technologies.
Recent examples in Ontario of conservative decisions by the regulator include rejections of distributor proposals for recovery of smart-grid feeder automation, line and transformer monitoring,
prepaid smart metering, roof-top solar panels, and electric vehicles and supporting charging
infrastructure.
One of the OEB objectives flowing from the Green Energy
Act, 2009, is to facilitate the implementation of the smartgrid in Ontario. On Nov. 23, 2010 a detailed Directive was
issued to the OEB requiring the OEB to provide guidance to
distributors that propose to undertake smart-grid activities.
The OEB noted that there were a number of technical issues
which needed to be addressed in order to provide this guidance. The OEB had issued direction to those distributors
who wished to include smart-grid development activities
and expenditures in their distribution system plans. The focus
of the filing requirements was on smart-grid demonstration projects, smart-grid studies or planning exercises and smart-grid education and training. The filing
requirements also established deferral accounts for demonstration expenditures on smart-grid
technology by distributors as well as for education, training and studies.
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As a result, distributors have been discouraged from further smart-grid investment and instead
encouraged to focus on demonstration pilots until further guidance is provided. In November 2011
the OEB issued a staff discussion paper raising a number of questions, but no further notices on
smart grid have come forward since that time. The OEB had established a smart-grid working group
to provide input on the discussion paper. The working group agreed that collaboration among electricity stakeholders will help achieve innovation, and could be achieved by establishing a forum for
the sharing and discussion of ideas related to smart grid.
Many distributors have already established user groups of similar technologies to share information, and purchase services and equipment jointly to enable smart-grid investments. Some distributors are carrying out pilot studies on some new smart-grid technologies and a few have already
begun to more widely deploy certain proven smart technologies.
Recently a number of demonstration projects were awarded Smart Grid Funding by the Province.
The Smart Grid Fund provides targeted financial support to Ontario-based demonstration projects
that test, develop and bring to market the next generation of smart-grid solutions.
The Ministry of Energy ran a competition for the funds and recently made announcements on the
recipients. One project involves Oakville Hydro, and consists of the installation of 225 high resolution wireless meters on the medium-voltage supply monitoring approximately 16,000 customer
endpoints in Oakville. The technology allows for full system monitoring of power usage based on
real-time data. This should allow more direct grid management, improved outage management,
line-loss reduction and better detection of power theft.
Another recipient was Burlington Hydro which is involved in a community smart-grid energy plan
that integrates smart-grid technologies including distribution automation, increased distributed
generation capacity, and home energy management. This also involves a community-based working
group developing a long-term, coordinated approach to energy sustainability for Burlington.
Burlington Hydro is also recognized as a leader in establishing the GridSmartCity® partnership.
GridSmartCity partners (which include
Burlington Hydro, Cambridge and North
Dumfries Hydro, Guelph Hydro, Halton Hills
Hydro, Kingston Hydro, Kitchener-Wilmot
Hydro, Milton Hydro, Niagara Peninsula
Energy, Oakville Hydro, and Waterloo North
Hydro) focus on a culture of cooperation
and collaboration in order to enhance the
efficiency and sustainability of local
distribution networks to deliver
electricity into their communities.
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The Region of Durham won smart-grid funding for a control centre involving three utilities to enable
control, dispatching, monitoring, asset condition assessment and load modeling/control/balancing
of their systems. The “Durham Smart Grid Demonstration Project” is a collaboration which includes
Siemens Canada, Oshawa PUC Networks Inc, Whitby Hydro, Veridian Connections, Intellimeter,
Energent WirelE, University of Ontario Institute of Technology (UOIT), Durham College, the City
of Pickering and the Region of Durham.
Bluewater Power, London Hydro and Hydro One are involved in a number of jointly sponsored research studies including:
• Large Scale Photovoltaic Solar Power Integration in Transmission and Distribution Networks
• Increasing Renewable Generation Connectivity in the Transmission System of Ontario
through use of Innovative Distributed Generation (DG) DG Controls
• Smart Grid Management and Control of Short Circuit Currents to Increase DG Connectivity
in Constrained Areas in Ontario
• Technology Development for Wide Area Integrated Management of Distributed Generators
using Innovative Embedded Inverter Control Systems
The large-scale PV study has just concluded and the others are in various stages. As such the findings and recommendations have not been implemented. Once implemented they expect to see
reduction of system losses of up to one per cent, the ability to connect more DG to existing
infrastructure with savings, and improved power quality within their systems.
Toronto Hydro has also been demonstrated to be a leader in adopting new, leading-edge technologies and has been actively sharing the results of its activities at forums and conferences. Toronto
Hydro projects include feeder automation to improve reliability and faster restoration times, and
power-line and transformer monitors to reduce response time and outage duration and identify
potential problems before they cause outages. Toronto Hydro is monitoring which transformers
are overloaded prior to failure and detecting power-line disturbances and allowing proactive work
before an interruption occurs. Toronto Hydro is using feeder-automation technology to improve the
reliability of ten of their worst performing feeders to automatically detect and isolate faults. The
activities on smart grid carried out by Toronto Hydro are recognized as leading-edge globally.
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PowerStream and Veridian have also been active in sharing information on their leading-edge
activities to implement smart-grid technologies.
These smart-grid activities by the distributors in Ontario clearly demonstrate the benefits of diversity and the ability for the sector to share information and share responsibilities in carrying out
leading-edge research. Toronto Hydro is recognized as a global leader in smart-grid technology
despite being significantly smaller than many other electricity companies moving towards smartgrid investments. Many years ago before smart meters were mandated by the government, utilities
such as Milton Hydro and Newmarket-Tay Hydro took the lead in promoting and demonstrating the
benefits of smart meters. Today, companies like Burlington Hydro continue to push forward to find
new approaches to adopt new technologies. The distribution sector in Ontario has demonstrated
its ability to effectively implement smart meters and TOU pricing. For the next phase, involving the
integration of new smart-grid technologies, we anticipate that some distributors will continue to be
in the lead while others will be willing to wait and see and move forward only when there are fewer
risks, clear benefits and more acceptance from the regulator.
Smart-grid activities by the distributors in Ontario
clearly demonstrate the benefits of diversity and
the ability for the sector to share information and
share responsibilities in carrying out leading-edge
research.
C.Conservation and Demand Management
Utilities are required to meet CDM targets set by the Ontario Energy Board (OEB). The OPA has
developed a series of Province-wide programs and utilities rely upon these programs to achieve
their CDM objectives.7 The OPA programs include:
• demand-response programs under which end-use customers receive incentives to reduce
consumption at certain peak times (these arrangements may be voluntary or contractual);
• small-business programs designed to promote energy-efficient lighting;
• building retrofit programs;
• support for energy audits;
• incentives for improvements in energy use by industrial and commercial enterprises;
• incentives for energy-saving upgrades in new residential construction.
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In a few cases to date, larger utilities have proposed additional programs that they are developing. The proponents of these programs must demonstrate that they are not duplicative of OPA
programs. As part of the OEB review process, the OPA is asked to provide its opinion on the utilityspecific programs and whether they are duplicative.
Centralization of the provision of some CDM
programs is probably beneficial. On the other hand,
it discourages innovation by distributors.
It would seem that the balance has not been struck properly. Centralization of the provision
of some CDM programs is probably beneficial. On the other hand, it discourages innovation by distributors. Many of these development initiatives could be provided by single distributors or groups
of distributors. With a multiplicity of utilities engaged in development, a competitive selection
process will likely result in more rapid evolution and testing of programs. Centralization of this function also reduces the incentives for cooperative efforts by groups of utilities and for consolidation.
Unfortunately, the OEB has turned down a major application by Toronto Hydro for the development
of conservation programs. (Hydro One also submitted an extensive application, but subsequently
withdrew it.)
In addition, the OPA has been slow to develop programs for issuance to utilities and some programs
are proving to be too complex for customer participation.
D.Renewable and Distributed Generation
Policies and legislation passed by the Ontario Government have dramatically increased the role that
renewable technologies will play in forthcoming years. The basis for negotiating renewable supply
has changed fundamentally. Non-utility generation programs of the 1980s and 1990s were based
on avoided costs. That is, contracts that were being negotiated with prospective generators were
based upon the costs that Ontario Hydro could avoid. In contrast, rates for the FIT and microFIT
programs are based upon estimates of the costs that wind and solar providers would need to
recover in order to enter the market.
The supply mix directive, issued by the Minister of Energy in February 2011, envisions over 10,000
MW of non-hydraulic renewable energy capacity in the Province by the year 2018. Because wind
and solar sources have relatively low capacity factors, this will represent about 10 to 15 per cent of
total energy generated in Ontario. Most of this capacity will be comprised of wind and solar generation.
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Despite the high current costs of non-hydraulic generation, particularly solar and wind energy, pressures to further increase their share are likely to intensify. First, Ontario’s use of coal in the generation of electricity is to end in 2014, increasing the need for “clean generation”. Second, whatever
the objective risks associated with nuclear generation, the events in Japan in March 2011 are likely
to have negative implications for nuclear generation through increased costs, greater regulatory
hurdles and adverse public opinion.
As the share of variable energy resources increases, the challenges of balancing the system also
increase mainly because of the variability and difficulty in predicting supply from these sources.
To accommodate them, increased transmission and reserve capacity may be required.
A significant portion of renewable supply will consist of small-scale DG projects. In order to successfully integrate this supply without compromising reliability, smart distribution system technologies
will be required. In due course, energy-storage technologies may reduce the variability and unpredictability of wind and solar energy. However, such enabling technologies are not yet available at
cost-effective prices.
In summary, current incentives for renewable energy projects have led to an abundance of applications, particularly for providers of small-scale solar and wind generation. Some of these are located
within municipal distributor boundaries. Distribution companies can no longer be thought of as
simply distributing electricity, but also of collecting it.
Distribution companies can no longer be thought of as
simply distributing electricity, but also of collecting it.
Distribution systems originally conceived and engineered to deliver electricity must be modified to
incorporate distributed generation. Furthermore, unlike conventional generation, the energy produced by solar and wind facilities fluctuates widely, sometimes over relatively short time intervals.
Power quality can be deprecated and in some instances reverse power flows can occur. Technical
integration within a distribution system presents new challenges, some of which may be
resolved using emerging technologies. Costeffective deployment of battery-type storage
or flywheel technologies may help to reduce
the magnitude of the impacts on distribution
systems in the future.
However, a concentration of new supply of
this type presents the host distributor with
new engineering and design issues and can
have impacts which may not be paid for by
the generator of renewable generation. It may
also be appropriate for LDCs to acquire non-renewable dispatchable generation to compensate for
fluctuating renewable supplies.
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E.Costs
In past years, Ontario has enjoyed electricity prices that are relatively low by international standards
and Ontario businesses have, to a greater or lesser degree, relied upon these prices in their locational and expansion decisions. Recent projections indicate that Ontario electricity prices will grow
46 per cent between 2010 and 2015 and approximately 100 per cent by 2030.8 A substantial portion
of the increase can be attributed to multiple changes to energy policy in the province. This in turn
puts pressure on cost structures throughout the industry and can affect regulated price increases
and subsequently the internal decision-making at utilities.
In some cases, mergers or amalgamations may lead to cost savings on the distribution portion of
the bill through improved economies of scale. In other cases, horizontal economies of scope, for
example through the sharing of resources among multiple service types, may also lead to reduced
costs. Cooperative planning, development and marketing of programs, such as those related to
CDM, can also lead to efficiency gains.
F. Regulation and Government Policy
The Green Energy Act has created new obligations for wires companies, such as the requirement
to connect renewable resources. The increased direct role of the Provincial government through
the issuance of directives is also likely to increase the uncertainty of the policy environment within
which utilities operate.
Utilities can and should be accorded a leading role
in shaping the regulatory model under which they
operate so as to streamline it administratively and
improve its effectiveness.
Utilities have experienced a marked rise in regulatory costs over the last decade. Even rate applications have become much more complex than they were a decade ago. Meeting regulatory obligations,
however, is only part of the picture. Utilities can and should be accorded a leading role in shaping
the regulatory model under which they operate so as to streamline it administratively and improve
its effectiveness.
G.Human Resources
There are a range of HR issues faced by Ontario distributors. Workforce demographics indicate a
large percentage of employees are reaching retirement within the decade. A high turnover of skilled
workers will be a significant challenge for the electrical sector as confirmed in the 2008 Canadian
Electricity Association Labour Market Information Study. The challenge of replacing experienced
and skilled workers includes the problem of insufficient skilled replacement workers, in part caused
by low awareness about career opportunities in the electricity industry. In the skilled trades it can
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take four years to become qualified to work on facilities, and as many as 10 years to become fully
proficient to work independently. As a result, entry-level workers must be hired well in advance of
the need for replacing retiring skilled trades staff. In addition to traditional skill shortages, new and
advanced skills are being required in areas such as engineering, regulation and CDM.
In the skilled trades it can take four years to become
qualified to work on facilities, and as many as 10 years
to become fully proficient to work independently.
In anticipation of the need to replace workers, many distributors are seeking to hire new entry-level
trade apprentices. Presently, the regulator has raised concerns about acquiring additional staff before
other staff retires. Some distributors seeking to obtain regulatory approval for new apprentices
including Toronto Hydro and Kingston Hydro were denied by the regulator. The regulator should recognize that entry-level apprentices need to be retained and trained well in advance of retirement of
senior staff. This need for additional entry-level apprentices should be recognized by the regulator
and the associated costs should be recoverable.
New engineering requirements are being addressed by distributors through
shared resources and cooperative
arrangements. The need for regulatory
expertise could be addressed in part
by regulatory reform.
CDM staffing has its own challenges.
CDM has been funded by a series of
short-term funding regimes such that
conservation staff are often hired on
short-term contracts. In order that
CDM can be built into the business
model for LDCs, and that CDM can be
seen as a viable career opportunity, a
new model for CDM delivery must be found such that distributors and workers can both make the
necessary long-term commitment to CDM.
Allowing distributors to retain sufficient numbers of new hires as part of a strategy to replace
retiring workers will reduce costs in the long term. If not, staff resources will be more expensive
if they are not home grown and need to be acquired elsewhere.
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H. Breakdown of the Bill
Approximately 20 per cent of the total customer electricity bill corresponds to electricity-distribution
revenue from LDCs, excluding Hydro One. The remainder covers the cost of power (primarily generation costs and global adjustment), costs of transmission, regulatory, debt retirement charge
and HST. However if Hydro One’s distribution revenue is included, the average distribution utility revenue in Ontario represents 24 per cent of the customer electricity bill (see first panel in the
figure on page 31; figures based on 2010 OEB Yearbook data). For the purpose of discussions in this
paper, the Hydro One distribution revenue is included in the overall distribution revenue.
Approximately 20 per cent of the total customer
electricity bill corresponds to electricity-distribution
revenue from LDCs, excluding Hydro One.
The commodity price of electricity is increasing at a much faster rate than the distribution rates in
the province.
This 24 per cent of total distribution revenue can be further broken down as follows:
• 10 per cent of customer bills corresponds to distributor Operations, Maintenance and
Administration (OM&A) costs; these are sometimes referred to as “controllable costs”
because it is presumed that utilities exercise some measure of control over these costs;
• 13 per cent are capital costs (depreciation, interest and return on equity);
• one per cent corresponds to taxes or payments-in-lieu of taxes (PILs).
The distribution of electricity is highly capital intensive with over half the costs being capitalrelated. The proportion is often higher in other jurisdictions. In Ontario, as a result of responsible
and conservative financial policies on the part of distributors, debt loads are relatively lower and
significant portions of physical assets remain used and useful, even though their book value has
been reduced to zero.
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However, as in many other jurisdictions, major portions of distribution infrastructure were put in
place many years ago and are approaching the end of their useful lifetime. Replacement of these
assets at current prices puts significant upward pressure on rates. Furthermore, aging assets that
remain in service require greater OM&A expenditures, which adds further pressure to costs. This is
a widely recognized phenomenon and supported by detailed statistical analyses of the electricitydistribution industry.
Distributor costs, especially the “controllable” component (i.e., OM&A costs) are rigorously monitored by the regulator using statistical benchmarking techniques.
Customer Bill Breakdown
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Efficiency Opportunities
A.Efficiencies Through Regulatory Streamlining
Increasing Regulatory Costs
Ontario distributors are regulated using a variant of incentive regulation (a combination of cost-ofservice rate filings every four years and price-cap regulation during the intervening years) which
can be particularly effective when certain conditions are present. Among these conditions are the
following: i) an environment where utility responsibilities and technologies remain relatively stable,
enhancing comparability of data on a year-to-year basis; ii) a dynamic technological environment
where production costs are dropping, thus reducing political pressure on regulators as rates can be
lowered without endangering necessary utility expenditures or profits; iii) private ownership which
can reduce political temptation to tamper with utility incentives.
However, these facilitating conditions are not currently present in Ontario. Utility responsibilities
are changing dramatically. There is upward pressure on costs arising from a variety of factors such
as renewable energy and CDM programs, DG and aging infrastructure. Public ownership continually
exposes utilities to increased risk of politically motivated micro-management in many dimensions,
including with respect to earnings.
The OEB, to its credit, has attempted to meet these challenges using sophisticated tools specifically
adapted to the Ontario environment. In order to manage the regulation of many disparate distributors, it has relied upon a variant of incentive regulation grounded in empirically based benchmarking.
In 2007, as part of its regulation of the electricity distributors, the OEB established a multi-year
electricity distribution rate-setting plan commencing with 2008 rates. Each year, a subset of
distributors is identified for regulatory cost-of-service review. The application must meet filing
requirements set by the OEB.
However, the growing utility responsibilities and capital-expenditure programs have made effective
regulation ever more challenging. Utilities have experienced increases in regulatory costs.
In 2011, the EDA conducted a survey of its LDC members and collected data on the total regulatory
costs incurred over the years 2008 to 2010. The results are summarized in the table on page 32.
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Regulatory Costs Incurred by LCDs9
IESO Admin Charges
OPA Admin Fees
OEB License Fee and Cost Assessments
ESA Cost Assessments
LDC Costs for Regulatory Compliance
TOTAL
2008
2009
$ in Millions
2010
$ 85.6
$ 38.8
$ 12.9
$ 1.9
$ 29.8
$ 169.0
$ 87.6
$ 61.0
$ 14.7
$ 2.1
$ 44.6
$ 210.0
$ 86.9
$ 52.0
$ 14.6
$ 2.0
$ 36.5
$ 192.0
Despite the move to incentive regulation, the
regulatory costs borne by Ontario utilities, and
ultimately by consumers, have grown substantially.
The increase in LDC costs for regulatory compliance is
largely attributed to increased scrutiny of distributors
by the regulator and increased costs associated
with intervenors.
The Case for Reform
In 2011, the EDA produced a policy paper entitled “The Case for Reform: How regulatory streamlining could benefit Ontario’s electricity consumers”. The analysis contained therein was guided by a
series of principles, in particular:
• There is a need to balance costs of regulation with the benefits to customers.
• The amount of regulation and reporting requirements should be proportionate to the policy
objective/outcome.
• Greater emphasis should be placed on policy outcomes, not process.
• Duplication and overlap of reporting requirements should be eliminated.
• Administrative expense to LDCs should be minimized.
• Distributors should be provided sufficient flexibility to address their local circumstances.
• Distributors should not be required to address social issues such as income redistribution.
• Distributors should be allowed to recover the costs of refurbishing or replacing aging infrastructure in a timely manner.
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• Increased certainty and transparency should be provided for cost recovery by distributors.
• Decision-making by regulators needs to be timely.
The study found that the regulatory application process could be improved substantially. It recommended:
• development of standardized templates to streamline the application process;
• creation of metrics to reduce the time, effort and expense associated with the review
of applications;
• incorporation of multi-year capital reviews within the regulatory cycle; and
• the use of productivity and inflation factors that truly reflect industry circumstances.
The paper also recommended revisions to the intervenor process. In particular, that:
• the OEB lead and pre-screen interrogatories to avoid duplication;
• intervenors be required to document their representative constituency; in particular, there
should be written evidence in the proceeding that the groups an intervenor claims to represent either acknowledge or support the appearance of the intervenor on their behalf;
• cost awards and eligibility for such awards be further reviewed.
The paper in its entirety can be found in Appendix I.
We note that Ontario’s Auditor General has recommended consultation with LDCs to reform
the cost and complexity of the rate filing process and achieve better coordination of intervenor
processes to eliminate duplication.10
Fundamental to efficacious regulation is the continued focus on the creation, reinforcement and
sustenance of incentives. In addition to the above recommendations, incentives might be strengthened by providing a menu of regulatory options to utilities whereby they could choose fast-track
approvals with lesser information requirements and consolidated applications, or choose more
detailed approval processes.
In summary, there is much room for efficiency gains through changes to regulatory processes. These
include “objective-oriented regulation”;11 stricter constraints on regulatory review by the OEB; modifications to the intervenor process; and, consolidation of the representation of consumer interests.
Increased coordination among regulatory entities may also serve to reduce regulatory costs.
Ontario’s Auditor General has recommended
consultation with LDCs to reform the cost and
complexity of the rate filing process and achieve
better coordination of intervenor processes to
eliminate duplication.
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Efficiency-based Regulation
The regulatory model discussed in this section is premised on the idea that differences in efficiency
should play a role in the degree of regulatory scrutiny that is required. The OEB presently conducts
an analysis of the efficiency of distributors. Distributors found to be efficient from the benchmarking analysis and that meet specified performance criteria should be recognized and rewarded not
only with a lower stretch factor (the current incentive), but also with a more streamlined, fast-track
approval process.
The argument has been raised that the existence of many small utilities absorbs too much in the
way of regulatory resources. This model proposes incentives for all distributors that would reduce
costs for the utility, customers and the provincial regulator.
Total Number of Customers Served by Small, Medium and Large Utilities
For distributors opting for the fast-track process approach, the fast-track approval process could
allow the efficient utilities to adjust rates with less onerous procedures than are presently in place.
This approach will provide incentive to distributors to achieve higher efficiencies based on benchmarks established by the OEB.
For Ontario’s distributors that are not meeting the efficiency benchmarks, rates would be approved
under a reformed regulatory model proposed in the previous section.
Additional information can be found in Efficiency Opportunity Fact Sheet #3 in Appendix G.
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B.Efficiencies From Scale and Contiguity
Scale and Contiguity
The efficiency of distribution utility and industry structure is affected by at least three important
factors. The first is contiguity. The wires business requires a single utility to serve all customers
within a contained area and for this reason service franchises have prevailed since the early years
of electrification. This does not imply that a utility must out of necessity serve only one contiguous
area – it may serve several areas each of which satisfies the contiguity property. Highly fragmented
service areas are inefficient and as a result, rarely observed.
A second factor affecting efficiency is the scale of operation. Generally, one would expect larger
distribution utilities to be more efficient. An important empirical question is the size at which scale
efficiency is achieved.
A third factor, mentioned earlier, is the scope of operations. By efficiently combining activities from
more than one type of service it may be possible to reduce overall costs. Scope will be discussed
more extensively in a subsequent section.
In broad terms, the evidence on these factors is as follows:
• Contiguity economies are not estimated directly in statistical models of electricity distribution essentially because most utilities are either completely contiguous or serve a relatively
small number of contiguous areas. Some would argue that the very fact that we rarely
observe highly discontiguous or overlapping service areas constitutes evidence of the need
for contiguity. However, the importance of contiguity economies can be inferred indirectly
by observing the effects of customer density. This variable is incorporated in most analyses
of distributor costs and it almost invariably has a statistically significant and material impact.
Ontario distributors typically serve contiguous areas, with a few exhibiting a modest degree
of fragmentation.
• Scale economies are frequently incorporated in models of electricity distribution. Data is
available from Ontario, Norway, New Zealand and a few other countries. These studies vary
significantly in their estimates of scale efficiency. However, there is empirical support for the
proposition that once a utility achieves sufficient size, unit costs remain relatively flat.
• Scope economies appear in a relatively small number of statistical analyses. However,
where they are included, there is support for the proposition that broadening the range of
offered services and the scope of activities can materially reduce unit costs.
It is worthwhile to consider the extent to which the geographic pattern of Ontario distribution
meets the contiguity criterion.
• The largest concentration of population is in the Golden Horseshoe which is served by a
series of contiguous utilities. Collectively these represent approximately 45 per cent of
customers in Ontario.
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• Hydro One Networks serves approximately 25 per cent of Ontario customers.
• Several utilities provide service to multiple non-contiguous areas. An expansion of their
service territories to create contiguous zones to the extent possible may be worthy of
consideration.
• There are a number of utilities which are surrounded by vast expanses of land with very
low population density.
Thus, while there would seem to be potential for some contiguity benefits through restructuring,
the magnitude of the gain viewed in terms of its impact on average provincial electricity rates, is
unlikely to be large. Requiring distributors to absorb distant or low-density customers may be
detrimental to the distributors’ current customers.
Requiring distributors to absorb distant or lowdensity customers may be detrimental to the
distributors’ current customers.
The Structure of the Distribution Segment
The structure of the distribution segment continues to attract attention. Over the years, the
sentiment that there are too many utilities and that substantial efficiency gains could be achieved
through consolidation has been expressed repeatedly. Important considerations need to be taken
into account, among which are the following:
First, competitive markets accommodate substantial variation in the sizes of firms, with small firms
often prospering alongside large ones. Thus, consolidation, while it may in some respects be appealing, is neither a necessary nor sufficient condition for efficiency in the distribution sector.
Second, by analogy with competitive markets, consolidation within the sector should not be an
end in itself, but should be driven by the benefits that would be derived from this activity.
Third, a number of factors may increase the incentives for further consolidation. Integration of DG,
smart-grid development, increased ownership of generation facilities, and conservation and demand management programs may create previously unavailable scale and scope economies which
would give larger utilities a cost advantage. If this is the case, mergers are more likely to occur
spontaneously without any additional incentives.
Fourth, contiguity is likely to continue to play an important role in determining which utilities
decide to amalgamate.
Fifth, as suggested earlier, the empirical evidence that is available does not support mandatory consolidation in the distribution sector. This does not imply that mutually advantageous consolidations
are not available.
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Sixth, distribution consolidation only affects the distribution portion of the electricity bill which means
any savings in the distribution sector only applies to 24 per cent (including Hydro One distibution) of
the total bill for the customer.
Seventh, the spatial distribution of Ontario customers presents challenges, as a portion is in lowdensity or remote locations. The rate impact of absorbing such customers requires careful consideration.
One may ask whether, in the face of industry changes such as smart-grid innovation and the widescale development of variable energy resources such as wind and solar, there are too many distributors in Ontario. The United States, a leader in advanced-grid technologies, has about 3,200
distributing entities of widely varying size (significantly more per capita than presently in Ontario).
Germany and Denmark, which are leaders in renewable electricity, also have more distribution entities on a per capita basis than Ontario.
Where there are contiguity or scale gains to be made through consolidation, the natural question
becomes how to achieve them. In subsequent sections we will discuss four models which should
lead to utility expansion and perhaps eventually, into the regionalization of distribution.
In some cases, mergers may, on balance, be unappealing because of rate or cost impacts. For example, labour costs at small utilities may be lower because living costs in the municipality are lower.
Absorption into a larger utility may lead to a substantial increase in labour costs. In such cases,
there may be alternative mechanisms by which certain economies may be captured, such as
cooperative efforts amongst groups of utilities or through outsourcing.
In considering the efficiency of firms within an industry, it is also necessary to assess their
dynamic efficiency; that is, their ability to respond and adapt to a changing environment. In competitive markets, firms that are unable to adapt sufficiently quickly fall by the wayside or are absorbed
by other, more successful firms. Electricity transmission and distribution are natural monopolies.
Nevertheless, Ontario transmission and distribution companies have been able to evolve and adapt
to changing demands. Well-conceived incentive regulation can ensure that they continue to do
so in the future.
In our view, structural changes to distribution sector should:
• be voluntary and commercially based;
• where possible, support contiguous or shoulder-to-shoulder mergers to optimize planning
synergies;
• increase levels of service and reliability to customers;
• reduce costs in the short and long term.
Ontario distribution companies have been able
to evolve and adapt to changing demands. Wellconceived incentive regulation can ensure that
they continue to do so in the future.
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Scale Economies Through Collaborative Efforts
In various areas of activity, firms can realize scale economies by collaborating or cooperating on a
voluntary basis with other firms having similar needs. The EDA has conducted a survey of its members to assess the extent to which such collaboration exists within the industry and the benefits to
the extent they are possible to quantify. Numerous instances of collaboration were identified (details are contained in Appendix C to this report) and the cumulative benefits and savings were
in the millions of dollars. Specific areas of collaboration include:
• billing services shared by multiple electricity distributors,
• billing services shared by various services (e.g., electricity, water and sewage),
• joint development of engineering standards and specifications,
• shared services based on meter technology,
• joint procurement of products and services,
• shared-services arrangements for regulatory filings,
• sharing “locates” services,
• delivery of CDM programs, and
• collaboration and aid during emergencies, extreme weather and natural disasters.
All of these activities have evolved organically on a voluntary basis as LDCs have found ways
to make the system work better for their business and consequently their shareholders and customers.
LDCs have identified that there are further opportunities for savings through enhanced collaboration. It
would be appropriate for incentives to be introduced and regulatory barriers reduced to foster and
accelerate additional collaboration to achieve additional savings to the benefit of customers.
Performance of Ontario Distributors
The diagram on page 41 graphs average revenue per customer against the number of customers
served by the utility. There is no systematic relationship between utility size and the efficiency of
the utility. The figures do not adjust for utility-specific factors such as the density of its customer
base, the age of assets, the customer mix, geographic or climatic influences, or total volume of sales.
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Average Annual Revenue per Customer by Utility Size
($/year vs. number of customers)
To adjust for various factors affecting individual utility performance, the OEB conducts an annual
analysis in which it assigns utilities to one of three efficiency categories. “Group 1” utilities are
those deemed to be most efficient; “Group 3,” the least efficient. (Details are provided in Appendix
F to this paper.) Two important inferences may be drawn from the data which are also displayed in
the bar chart on page 40.
First, as stated before, there is no systematic relationship between utility size and the OEB measures
of cost performance. Small, medium and large utilities may be found in all efficiency categories.
Second, there is a larger proportion of small utilities in the upper and lower groups (Groups 1 and
3). In contrast, medium and large utilities are concentrated in the middle group (Group 2). This may
suggest that small utilities have a higher propensity for finding innovative cost-saving solutions. At
the same time, there may be greater room for improvement among the 20 per cent of small utilities
assigned to Group 3.
The OEB also assesses each utility according to a series of “Service Quality Indicators” (SQI) and
reliability indices which measure the average frequency, length and duration of service interruptions. All Ontario utilities, regardless of size, have been consistently meeting their SQI and reliability
targets. (Additional details are provided in Appendices D and E.)
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Percentage of Distribution Utilities by OEB Cost Efficiency Category
Barriers to Accessing Capital
As part of the restructuring of the electricity sector, municipalities were given formal ownership of
their Municipal Electric Utility (MEU), which has provided them with a source of income and the
potential to realize significant proceeds if they sell their MEUs.
Section 94(1) of the Electricity Act provides for a transfer tax of 33 per cent of the fair market value
of “electricity property” transferred by an MEU or a municipality. However, the amount of transfer
tax payable is reduced by the amount of payments-in-lieu of taxes (PILs) that a MEU has already
paid up to and including the date of the transfer.
The transfer tax was designed to collect an amount equivalent to the PILs to be paid to help pay
down the stranded debt from the old Ontario Hydro.
Because of the chilling effect that transfer tax could potentially have on consolidation among LDCs
in Ontario, the provincial government introduced a series of “holidays” from the transfer tax, the
first in 2000, and subsequently in 2003, 2005, 2006 and 2008. The purpose of the exemption from
the transfer tax was to encourage consolidations among municipally owned LDCs. In each case, the
“holiday” came with a sunset period and it did encourage some consolidations in the sector. In
October 2009, the government made the exemption permanent for publicily owned consolidations.
This exemption recognizes that “public-to-public” consolidations would not affect the amount of
PILs paid towards the stranded debt.
Since the amount of transfer tax payable is reduced by the amount of PILs already paid by a utility, it
is estimated that almost 40 per cent of the potential transfer tax payable by LDCs would be reduced
when a utility is sold to a private entity.12
In order to provide LDCs with access to additional capital, both provincial and federal legislative
changes would be needed.
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Currently, the Ontario Regulation 438/97 under the Municipal Act, 2001 restricts municipalities to
make further investments into their LDCs by capping the total investments that can be made by a
municipality to the amount already invested at the time of incorporation of their LDC. We believe
that if LDCs are permitted to raise capital, the much-needed capital infusion into the industry would
occur, which could later translate into further consolidation.
In addition, the current restrictions imposed by subsections 149(1) (d.5) and 149(1) (d.6) of the
Income Tax Act (Canada) would also need to be relaxed. Currently, only LDCs with greater than 90
per cent of share capital owned by one or more Canadian municipalities are allowed tax-exempt
status under the Income Tax Act. If LDCs with more than 51 per cent of share capital owned by municipalities are allowed tax-exempt status, it will not only improve access to capital but would also
ensure that the payments-in-lieu of federal corporate taxes would continue to flow in to the provincial Consolidated Revenue Fund for the purpose of retiring the stranded debt.
In view of the above, we recommend a tax-exempt status for LDCs with greater than 51 per cent
of municipal ownership. This can be achieved through a cooperative tax arrangement between the
Province and Federal governments as recommended by Mr. Drummond in his latest recommendations to the province.
We recommend a tax-exempt status for LDCs with
greater than 51 per cent of municipal ownership
and municipalities should be given the opportunity
to invest directly in their utility.
Furthermore, municipalities should be given the opportunity to invest directly in their utility, thus
providing an additional source of capital to LDCs.
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C.Efficiencies From Reducing Regulatory Constraints on Scope
of Operations
The Multi-utility Option
Prior to industry restructuring when
Ontario municipal distributors were
regulated by Ontario Hydro, a number
of electricity distributors operated
as public utility commissions which
provided multiple services. Such
commissions exhibited, on average,
materially lower costs.13
As part of industry restructuring in the
late 1990s, electricity distribution was
separated from other activities which
could reside in related but separate
entities. This restructuring and separation was premised upon the industry moving towards a competitive electricity market. It too was a product of the deregulatory period in the Ontario electricity
industry. The deregulatory model has long been abandoned and new themes dominate the industry.
As the distribution segment of the industry evolves, incorporating increasing amounts of new
technology and widening the types of services for which it is responsible, new possibilities for crosshybridization and economies of scope will emerge. It would be desirable for the regulator and the
Government to take a forbearing approach in order that these new possibilities can thrive.
Multi-utilities exist in other jurisdictions. For example in the U.S., utilities can provide electricity,
gas, water and wastewater services, street lighting and energy conservation services. (Details are
provided in Appendix B to this document.) For municipal utilities owned by cities, it is also common
to provide garbage, recycling, and street lighting services to customers. Finally, several utilities have
been expanding to provide telecommunication services over fibre. As utilities invest in fibre infrastructure for SCADA systems and smart grid, providing reliable high speed service to customers has
helped recoup some of the cost of the fibre system. By efficiently combining activities from more
than one type of service, overall costs are reduced.
For example, in the U.S. utilities can provide
electricity, gas, water and wastewater services,
street lighting and energy conservation services.
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Utilities Kingston has been providing electricity, gas, fibre optics and water and sewer services for
the municipality since 2000 under one affiliate. Benefits of sharing overhead costs, equipment,
metering/billing services etc. include:
• savings of over $250,000/year from sharing billing services;
• savings of over $440,000/year from sharing of executive roles across the
different companies;
• savings of $240,000/year from sharing operations such as locates for underground
structures and fleet operations;
• savings of over $1-million/year on average from engaging in joint construction projects.
In short, given that there is no longer a market-based need for separation of certain activities
performed by distributors, it would be useful to reduce or eliminate regulatory restrictions on
utility structure and relationships with utility affiliates in order that utilities can decide for themselves whether to engage in scope-enhancing activities within the distribution utility or through
an affiliate.
Additional information is available in Efficiency Opportunity Fact Sheet #2 in Appendix G.
Utilities in the U.S.14
There are four main types of electricity utilities in the United States:
• investor-owned utilities (IOUs) are owned by shareholders and regulated by state and federal agencies (in particular, the Federal Energy Regulatory Commission, or FERC); they can
be vertically integrated and frequently provide a range of services including conservation
and demand management, net metering services, renewables resource investment as well
as non-electricity services;
• public-power utilities are owned by cities, counties or native groups; city owned utilities are
known as “munis”; these utilities are generally not regulated by state or federal agencies;
instead they are usually regulated by locally elected officials;
• cooperatives or “co-ops” are owned by their members, for example groups of farmers
or ranchers; these utilities were often established to serve rural areas; like public power
utilities, they are not regulated by federal or state agencies;
• federal utilities are owned by the federal government; this group includes the Bonneville
Power Administration and the Tennessee Valley Authority.
Close to 70 per cent of U.S. customers are served by IOUs and about 30 per cent are served by
public power utilities and cooperatives.
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The size of U.S. distribution utilities varies widely. IOUs are typically large, often serving millions
of customers over large geographic areas. The size of municipal utilities is typically determined by
the magnitude of the municipality. In many cases, the desire for local control has ensured that the
municipal utility has remained under the ownership of the municipality, rather than being sold to
a possibly much larger IOU. Cooperatives which serve rural areas are often comparable in size to
“small” Ontario utilities.
U.S. Distribution Companies - Average Size
California
Idaho
Illinois
Massachusetts
Michigan
Montana
Nebraska
New York
Oregon
Pennsylvania
Washington
IOU
Muni
Co-op
2 million
220,500
840,000
460,000
460,000
90,000
n/a
680,000
460,000
500,000
480,000
88,000
3,900
6,500
10,000
7,400
1,000
6,500
27,000
16,000
2,400
40,000
4,100
4,800
11,000
n/a
30,000
6,600
2,300
4,500
10,500
16,700
9,000
For the entire United States, there are about 3,200 entities serving retail customers.15 Given
a population of about 310 million and about 115 million electricity customers nationwide this
corresponds to an average utility size of about 36,000 customers. A similar calculation for Ontario
produces a substantially higher number. With a population approaching 13 million and approximately 4.8 million electricity customers, we obtain an average utility size of about 60,000.
Nor is there evidence that large utilities are substantially more efficient. With the exception of
Pennsylvania, in all the states that we considered, including the very populous states of California
and New York, the price per kWh was lower for munis than for IOUs. (See figure on page 47.) Perhaps not surprisingly, co-op prices were usually higher than muni prices, most likely because of the
density of their customer base. But even the co-op prices were often lower than those charged
by the large IOUs.
Furthermore, because munis are locally controlled utilities, they often expand services to include
additional city or county services, such as water, waste-water, garbage, recycling, street lighting,
cable and fibre telecommunication services. In addition, these utilities often focus on providing
additional long-term planning and community service to their service areas.
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Average Revenue per kWh by Utility Type ($/kWh)
As indicated earlier, a much more detailed account of the U.S. electricity industry may be found
in Appendix B. Here we summarize the most salient features of the review contained there:
• First, small, medium and large distribution entities routinely co-exist side-by-side.
• Second, large utilities are not necessarily the least costly.
• Third, it is not uncommon for municipal utilities to be regulated by the municipality and
not by the state regulator.
• Fourth, U.S. utilities frequently provide multiple services such as electricity distribution,
water and waste-water services.
Flexibility to Conduct Street Lighting Service in the LDC
Most LDCs are municipally owned, and many municipalities have expressed interest in having street lighting
work assumed or managed by the company they own.
In addition to cost savings estimated to be $15-million
provincially, the local utility may be able to provide excellent and responsive service to the municipality. LDCs and
municipalities have sought changes to the Ontario Energy
Board Act to provide more clarity on the permitted activities of an electricity distribution company to specifically
include the ability of an LDC to conduct street lighting
services for their local municipality, if the municipality
chooses to retain these services.
Private contractors will continue to provide street lighting
services to many municipalities, but qualified private contractors are not readily available in all areas
of the province. The LDC may also be able to manage the relationship with a private contractor on
behalf of the municipality, and this activity should be permitted.
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While street lighting services may be provided by an LDC through an affiliate company, the cost of
setting up separate corporate structures mean local utilities unnecessarily incur additional costs in
order to provide these essential services to their communities.
Additional information is available in Efficiency Opportunity Fact Sheet #4 in Appendix G.
Distributor-owned Generation
Recently, distributors have been given the opportunity to own modest amounts of distributed
generation and thus a certain degree of vertical re-integration has occurred. We note that, at present,
most utilities have chosen to situate this new generation within affiliates, rather than within the
distribution company itself. This may be, in part, to avoid the possibility of regulatory claw-back of
revenue and increased regulatory scrutiny. At the same time, it may be that economies of scope are
being lost. It would be helpful to determine whether, in the absence of regulatory considerations,
these utilities might have made their decisions differently.
Furthermore, there are restrictions on distributor ownership of distributed generation (DG). Section
71(3) of the OEB Act restricts distributor ownership of generation facilities to “a renewable energy
generation facility that does not exceed 10 megawatts”, “a generation facility that uses technology
that produces power and thermal energy from a single source” and “a facility that is an energy storage facility”. The present restrictions placed on distributors reduce flexibility and opportunities for
distributors to share benefits and address local system constraints through DG and other solutions.
Distributors should be afforded greater flexibility
in ownership of distributed generation as a separate
business within the distributor, as a joint partnership
with a third party, or as a rate-based asset.
Distributors should be afforded greater flexibility in ownership of distributed generation as a
separate business within the distributor, as a joint partnership with a third party, or as a rate-based
asset. Distributors need to be allowed to partner with other private entities for renewable-energy
generation in order to better take advantage of the opportunities for cogeneration and energy
storage facilities. In addition, it should be made clear that distributors should be permitted to
own or partner for DG facilities outside their service territory.
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At a minimum, distributors should be permitted to receive payment in accordance with prevailing
feed-in-tariff (FIT) schedules and to hold DG assets under any of the following arrangements:
• through an affiliate, without the restrictions currently imposed by the Affiliate Relationships
Code; essentially, this would be equivalent to holding DG assets within the distribution entity, while maintaining separate accounting for the assets;
• within the distributor, with DG assets separated from other distribution assets;
• within the distributor, with assets separated from other distribution assets, but rate based
and earning a regulated rate of return, as part of a local integrated resource plan or in the
event that the FIT program is phased out.
The current restriction to renewable
facilities not exceeding 10 MW was
evidently based on typical technical
limits for connecting to distribution
systems. However, some distribution
systems in the Province can integrate larger units and for this reason
the restriction should be removed.
Furthermore, non-renewable DG is
a necessary complement to variable
renewable DG, and should be a permitted activity for distributors.
Energy storage facilities are an
important complement to intermittent generation. Such facilities can benefit both local ratepayers
and more distant customers by improving local distribution system reliability through the discharge
of power at times of local distribution system constraints, thus reducing the need for new
incremental distribution capacity.
If the FIT program is phased out, distributors would want the option to incorporate distributed
generation within the rate base. Local dispatchable generation provides benefits to ratepayers
through reduced line losses, improved power quality, congestion relief and deferred infrastructure.
Additional information on reducing regulatory constraints on scope expansion can be found
in Efficiency Opportunity Fact Sheet #1 in Appendix G.
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D.Changes to the CDM Framework
Overview
The role of Ontario’s distribution companies in conservation activities goes back many years. During the Second World War, Ontario LDCs first introduced conservation to Ontario consumers as part
of Canada’s war effort. Some forty years later, when conservation again became a public objective,
Ontario LDCs were at the forefront of development and delivery of conservation programs.
Prior to the centralization of conservation programs within the OPA, distributors were already
developing local CDM programs. Indeed, many of the OPA programs introduced in 2006 had
already been developed, tested, refined and managed by Ontario LDCs. Among these:
• peaksaver PLUS — which was initiated by Toronto Hydro and that is now in place
province-wide;
• Great Refrigerator Round-Up — LDCs in the Greater Toronto Area led an initiative that
has been incorporated into a Province-wide Program;
• Demand Response — which is based on Greater Sudbury Hydro’s “Shed a Kilowatt”
program and other distributor load-management programs.
It is essential to recognize that conservation programs need to be designed to meet local conditions
and needs. The demand for electricity varies significantly. It depends on weather and climate conditions, the mix of customers, the types of industrial uses of electricity in particular and energy more
generally, and the seasonal and temporal patterns of use. These factors in turn affect the potential
for resource conservation through reduced usage, changes in patterns of use, and substitution
of alternatives.16
For example, Northern Ontario communities are winter-peaking and require different conservation
programs than Southern Ontario communities where demand often peaks in the summer due to
air-conditioning load. Local distribution companies are best suited to take these factors into account
in the design and delivery of CDM programs.
The EDA has also concluded that there are systemic flaws with the current 2011-14 CDM policy
framework, which we outline in detail below. This may result in undesired outcomes for the Ontario
Government and for LDCs. LDCs will have difficulty achieving their mandated targets due to lack of
effective programs for consumers, slow rollout of provincially mandated OPA programs and lack of
collaborative and unique LDC programs.17 The Environmental Commissioner of Ontario (ECO) has
expressed similar concerns.18
There are systemic flaws with the current 2011-14
CDM policy framework.
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The current CDM framework also makes ineffective use of ratepayer funds. Less than one-third of
Tier 1 CDM programs currently in the market are producing significant savings. Funding is being
spent on CDM programs regardless of a program’s ability to deliver actual energy savings. Permitting LDCs to lead conservation will result in more cost-effective CDM.
Furthermore, there is a lack of innovation because of strict restrictions by the OEB on programs
that are designed by individual utilities or groups of utilities (i.e., Tier 2 and Tier 3 programs). There
is also a lack of long-term commitment to any CDM framework by government which hinders the
creation of a culture of conservation in Ontario. (This is strikingly different from governmental
commitment to FIT programs through long-term contracts.) LDC investment in the development
of internal capacity to meet evolving customer needs and in the delivery of ongoing programs
which could achieve persistent savings is therefore hindered.
Recent History of the CDM Framework in Ontario
The recent history of CDM in Ontario can be divided into three periods, during which we have seen
a gradual movement away from a decentralized approach and towards a much more centralized
model:
• during 2005-2007, (the so-called “Third-Tranche” period), LDCs designed and delivered
custom CDM programs within their service territories;
• for the period 2007-2010, LDCs contracted with the OPA to deliver standard programs
designed by the OPA; LDCs were also able to apply to the OEB for custom programs;
• the current CDM framework, which is in place for 2011-2014, LDCs are required to work
towards achieving OEB-mandated targets by 2014 using OPA programs and utilities have
the option to apply for LDC-specific and/or collaborative CDM programs.
Arguably the most successful and innovative CDM programs were developed during the “Third
Tranche” era. Province-wide OPA programs such as the “Great Refrigerator Round-up”, “peaksaver”,
the “Electricity Retrofit Incentive Program” (ERIP) and Demand Response which are currently being
delivered as part of the 2011-2014 suite of CDM Programs were first developed by LDCs during
this period.
The OEB examined CDM “Third-Tranche” programs conducted by utilities and found that LDCs were
successful in delivering CDM programs. The assessment was based in part on an examination of
“benefit-to-cost ratios reported in distributor’s 2008 CDM annual reports”. The study concluded
that LDCs were delivering programs to Ontarians in a “cost-effective manner”.19
A Ministerial Directive dated March 31, 2010 directed the OEB to establish CDM targets for each
distributor that totalled 1,330 MW of provincial peak demand savings and 6,000 GWh of reduced
electricity consumption over the four-year period. The Government also directed the OEB to amend
the distributors licence so that the target was a condition of licence. The OEB followed the directive
and in addition, established parameters under which LDCs were allowed to design, develop and
deliver CDM Programs.
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At present, LDCs are approaching the halfway point of the current framework. Though there have
been some benefits to LDCs and consumers, on the whole, as a result of inefficiencies in the current
framework, LDCs have been tracking below their mandated targets. Furthermore, not all segments
of Ontario consumers are getting access to and participating equally in CDM programs.
Multi-year CDM program funding has provided some level of certainty for LDCs, albeit only for a
four year time period. Consumers have benefitted to a degree since all LDCs in the Province are
participating in CDM delivery. If not for the problems articulated below, all consumers would have
access and be able to participate in conservation. Large industrial and commercial/institutional
consumers have also benefitted and are producing savings.
As mentioned earlier, some of these programs can trace their origins back to the “Third-Tranche”
era.
Inefficiencies in the Current Framework
The move towards a more centralized approach has not led to efficiencies in delivering CDM;
arguably it has created the opposite effect. Before proposing remedies, we provide details with
respect to each of those that the EDA has been able to identify through its members.
1. CDM Program Implementation Issues
A number of program implementation issues have arisen, mainly as a result of poor program design
and a lack of properly allocated resources. A few examples follow.
• The Application Process for the New Home Construction Initiative under the Residential
Program is cumbersome. Feedback from the building developer and contractor community
suggests the program will not attract wide participation unless significant program design
changes are implemented to streamline the application process. Changes that have been
recommended to the OPA have met with approval delays and are unlikely to be implemented
in time to produce meaningful results during the period of the current plan.
• Program elements such as the Direct Install Space Cooling Initiative, Midstream Electronics
Initiative and Midstream Pool Initiative have not been made available by the OPA even
though the initiative was finalized in early 2011. As a result, LDCs, particularly those with a
large proportion of residential customers, are missing out on opportunities to implement
potentially important energy-savings programs.
The Residential Demand Response Program is not
expected to be delivered on a Province-wide level
until the end of 2012 at which time two years of
potential savings would have been foregone by
the LDCs and by the Province.
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• The Residential Demand Response/peaksaver program has not developed successfully
because of delays in finalizing the technological requirements and funding levels of the
“In-home Display” device. Many LDCs are struggling to find a device that works synchronously with their meter technology, provides a substantial in-home energy monitoring tool
for customers and remains within the allotted budget established by the OPA. The Residential
Demand Response Program is not expected to be delivered on a Province-wide level until
the end of 2012 at which time two years of potential savings would have been foregone by
the LDCs and by the Province.
2. iCon Functionality
The OPA’s iCon system has become an ineffective management tool for LDCs, suppliers and customers. It was originally intended to be a portal through which customers could apply for programs and
check application status, and LDCs could process customer applications. However, customers have
indicated that the portal is onerous to navigate and has incomplete sections, resulting in customers losing interest in applying for CDM programs. Applications and supporting materials for several
programs and initiatives are not available on the website. Where they are available, online applications are evidently not processed in a timely fashion. As a result, LDCs are losing potential program
participants due to customer frustrations with the iCon system. Many LDCs have resorted to using
their own resources to help customers in completing online applications.
3. Roll out of CDM Programs
Several programs and initiatives were not available as of January 1, 2011 because of legal issues
with the schedules and because of resource constraints at the OPA. Due to the slow rollout of
programs, very few LDCs, if any, are following their original CDM strategy filed with the OEB.
Many anticipate re-filing new plans every year as a result of the uncertainty with program rollout.
The slow rollout of programs has resulted in loss of energy-saving opportunities and has
compromised the achievement of original targets.
4. Reach of CDM Programs
Perhaps with the exception of OPA programs that target large industrial and commercial/institutional consumers, much of the provincial customer base remains underserved with the existing suite of
programs. For example, there are few if any programs that specifically target small businesses.
With the exception of OPA programs that target
large industrial and commercial/institutional
consumers, much of the provincial customer base
remains underserved with the existing suite
of programs.
The residential-specific programs that are in market, such as the Appliance Exchange Initiative, have
reached their saturation point and have high degree of free ridership, leading to minimal savings for LDCs.
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5. Delays in Payment by the OPA
Timely payment of CDM project invoices remains an ongoing concern for LDCs. In some cases, LDCs
have not received payment for pre-2011 CDM programs (delays of 12 to 18 months). Although payment delays are not in concordance with the Master CDM Program Agreement, delays have continued. While larger LDCs have fared relatively better and have, thus far, been able to pay customers
and/or vendors (they have put their own cash flow at risk), medium and smaller LDCs and their
vendors are facing cash constraints on a regular basis. In some cases, contractors have notified LDCs
of postponement of CDM services.
6. Culture of Conservation Not Being Nurtured
With the lack of effective residential and small business programs coupled with a “hard stop” of
2014 for all current CDM programs, a culture of conservation in the province is not being allowed to
grow. The short-sighted time frame with a 2014 end-date limits the incentive for LDC to grow and
develop their internal CDM capacity.
7. Innovation Thwarted
The current framework had envisioned that approximately 20 per cent of LDC energy savings would
come from LDC-proposed (and OEB-approved) CDM programs, (known as Tier 2 and 3 programs).
The intent was to provide LDCs with the flexibility to tailor programs to their specific consumers,
subject to certain conditions. Those conditions included the requirement that OEB-approved programs not be duplicative of existing or planned OPA-contracted Province-wide programs.
In late 2010, Toronto Hydro and Hydro One submitted individual applications to have their Tier 2
and/or 3 programs approved by the OEB. The OEB rejected most of Toronto Hydro’s proposed
programs primarily because the OEB saw them as being “duplicative” to existing programs.
(Hydro One withdrew its applications.)
The EDA and the LDC sector vehemently objected to the decision. Particularly incongruous was the
OEB statement that, evidently based on the OPA testimony, the Tier 1 Programs are fully capable of
enabling distributors to meet 100 per cent of their mandated CDM targets without the addition of
Tier 2 and 3 programs. As mentioned, the current framework envisioned that approximately 80 per
cent of the Province’s energy savings and peak demand reduction goals could be achieved through
OPA province-wide programs. The EDA and LDCs also objected to the overly stringent duplication
guideline that has been set by the OEB.
Additionally, as part of the decision, the OEB requested that the OPA develop an approach to screen
proposed LDC Programs for “duplication” during future application processes. This clearly is beyond the scope of the OPA duties. The Government has specifically directed that the OPA develop
province-wide programs in collaboration with the LDCs. No role in the approval of Tier 2 and/or 3
Programs was given to the OPA. The EDA feels that a pre-screening process increases the layers of
bureaucracy and adds unnecessary expense to the LDCs in obtaining program approval.
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It is not surprising that in the present regulatory environment, there have been no further applications by LDCs for Tier 2 and/or 3 CDM programs. Current impediments to LDC originated CDM initiatives are thwarting a critical innovation channel.
A pre-screening process increases the layers of
bureaucracy and adds unnecessary expense to the
LDCs in obtaining program approval.
Additional information is available in Efficiency Opportunity Fact Sheet #6 in Appendix G.
A Business Approach to CDM
In the view of the EDA, it is important to move towards a “business approach” which will allow LDCs
to incur the financial risk and rewards in designing and delivering CDM programs at the local level
in order to meet local circumstances. This will require the devolution of responsibility for program
design and delivery, target setting, and funding to the LDCs from the OPA or its descendant.
After consulting with its membership, the EDA has produced recommendations on a new CDM
policy framework for Ontario to produce cost-effective, customer-centered CDM programs. The full
report “Innovation from the Ground Up: Locally Driven Conservation” may be found in Appendix H
of this submission.
A “business approach” will allow LDCs to incur
the financial risk and rewards in designing and
delivering CDM programs at the local level in
order to meet local circumstances.
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The key principles upon which the recommendations are based are as follows:
• The CDM framework should be designed to achieve the maximum cost-effective CDM,
over long time periods.
• The framework should enable innovation.
• The framework should promote the development of local capacity to design and deliver
CDM in Ontario.
• The CDM framework should establish the role of LDCs in CDM over a longer time period.
• The regulatory processes associated with CDM should balance scrutiny with simplicity.
• LDC CDM activities should be customer-centered.
• LDCs should have an appropriate level of control over outcomes, and should be
fairly compensated.
The approach envisions that LDCs will take on full responsibility for funding, designing and delivering CDM programs. LDC commitment to CDM should be in line with the timelines reflected in the
province’s Long Term Energy Plan (LTEP) (2030). The government would need to affirm that the
LDCs will be responsible for CDM as part of the LTEP until 2030.
In exchange for the increased risk there would be commensurate incentives for the electricity savings which would be verified by a third party. Rewards would be based on the number of kW of capacity and kWh of energy that are being saved. Poorly designed programs would not be rewarded.
LDCs could work individually, in groups and/or with the EDA. There are important benefits to the
business approach:
Innovation, efficiency and learning. The business approach will promote innovation, as all
LDCs will have the opportunity and incentive to design creative and cost-effective programs.
In earlier years, LDCs demonstrated their ability to design good CDM programs. As indicated
above, many of these programs were then adopted as the basis for provincial programs.
Third parties may also have the opportunity to design programs for LDCs, thus further
promoting innovation and competition. The business approach will promote efficiency and
economies of scale. LDCs have clearly demonstrated their ability to work together in many
areas. (Appendix C contains numerous examples.) Groups of LDCs with similar customers
will also work together to design locally relevant programs. New or modified programs that
are effective in one service territory will be expanded to other areas, thus promoting continual improvement and learning.
Maximum cost-effective CDM. With reduced regulation and the potential for significant and
sustained rewards, LDCs will be better motivated to aggressively pursue maximum costeffective electricity efficiency. Energy efficiency is the least-cost and least-harmful means
of addressing supply issues. Investing in the most cost-effective CDM will reduce electricity
costs for consumers. It will also support the province’s objectives of energy security, environmental sustainability, and competitiveness.
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Financial benefits for the province and ratepayers. The province will have a guarantee that
its resources are well spent – it will pay LDCs for only electricity savings. The payments to
LDCs will be less than the full value of CDM to the province.
Fair rewards for LDCs’ efforts. Because of the significant opportunities for profit, CDM will
become integrated into LDCs as a core business activity. Shareholders will be more enthusiastic about CDM activities, and will feel that they are fairly rewarded for their CDM efforts.
CDM that benefits customers. LDCs understand their customers, and will design programs
that meet their needs. Innovation and improvement in program design will also benefit
customers and provide them with choices for better managing their bills. Furthermore,
programs will stay in market as long as they are well-received by customers and are costeffective for LDCs.
Alignment of risks, control and rewards. Finally, the business approach aligns risk, control
and reward by allowing LDCs to fund, design and deliver CDM programs – and to be fairly
rewarded for the associated benefits to the province and to rate-payers.
In order to implement this business approach to CDM, several steps need to be taken. The process
used to establish the FIT may be used as a model for CDM. However, while FIT prices are typically
much higher than the cost of newly constructed conventional electricity generation, CDM prices
will be lower.
In order to effectively implement this plan, the province should determine the appropriate payment per kW and kWh of savings delivered through CDM. This can be achieved through a process
involving LDCs, the OPA and other energy sector stakeholders. Payment levels should be based on
the cost of new generation. (For example, after consultation, the province might conclude it should
be willing to pay up to 80 per cent of the cost of new generation.) Once this value is determined, it
should be locked down for a certain number of years, to enable LDCs to undertake CDM planning.
The value could be recalibrated every few years for new programs to account for the changing costs
of electricity.
The province can begin to offer per-unit payments immediately, for custom CDM programs funded
by LDCs. LDCs that want to invest corporate or investor money into custom programs can apply for
the CDM payment for the energy savings they achieve. OPA programs can still continue, enabling all
LDCs to maintain their current CDM activities and progress towards targets.
An appropriate application and approval process would be required to ensure that these custom
programs do not claim savings generated by OPA programs. Applications to the OPA (as under the
FIT program) would also confirm appropriate evaluation methods and would provide a level of
awareness/assurance to the province and to the LDCs. If no LDCs choose to provide CDM for the
pre-determined payment level, the province will not bear any costs. If LDCs are able to design and
deliver cost-effective programs using corporate or investor resources, both LDCs and the province
will benefit.
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The approach proposed here combines local autonomy, inventiveness and innovation resulting from
a diversity of approaches, and programs that exploit scale economies that arise from combined efforts of few or many utilities.
Additional information is available in Appendix H.
On-bill Financing of CDM
Consistent with a business approach and improved scope economies, utilities should be given the
authority to extend financing to their customers for CDM investments. Customers seeking to make
a long-term capital investment in order to reduce consumption as part of a CDM program may
need to engage in an onerous process to obtain funding from a conventional bank or other financial
institution. This in turn may reduce the uptake of current CDM programs. Indeed, in many cases,
substantial up-front subsidies or tax breaks are required to induce consumers to participate.
Utilities should be given the authority to extend
financing to their customers for CDM investments.
In order to implement such a program, S. 71 of the OEB Act would need to be amended.
Under this proposal, local utilities could offer low-interest loans. The customer would repay the loan
through an add-on to the standard bill. Energy savings resulting from the investment would help to
offset a portion of the costs. Such a program would be beneficial to customers seeking to upgrade a
heating system, insulate their homes, install new lighting or undertake some other utility-approved
efficiency investment.
Furthermore, as noted, some current CDM projects provide a significant direct financial subsidy to
encourage customers to participate, raising overall costs for the project. On-bill financing could be
used to reduce the need for significant upfront subsidies thus lowering the cost to other customers.
We note that on-bill financing is already being provided by many U.S. electric utilities.
With the LDC offering financial services, a customer can access funds and repayment options
through its utility where it already has a trusted, long-standing relationship with a business that
has strong and deep roots in the local community to foster greater participation in conservation
programs requiring capital investments.
Additional information is available in Efficiency Opportunity Fact Sheet #7 in Appendix G.
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E.Efficiencies Through Curtailment of Electricity Retailers
During the period of market deregulation, which occurred in the industry at the beginning of the
previous decade, electricity retailers were allowed to enter the electricity system to offer customers the benefits of competition and choice. Although the formation of an open market was eventually abandoned and regulated electricity rates retained, electricity retailers continue to do business
in Ontario. Under the current system and for residential customers, they are in effect outliers and
their continued presence affects the entire rate base.
The electricity retailer concept, legislated in Part V.1 of the OEB Act, provided that in a competitive
market, retailers would be allowed to serve consumers by allowing them to pay higher electricity
rates in exchange for the price stability and predictability that a fixed contract provides. Retailers
could also offer other services, such as energy-saving programs, energy audits, equipment maintenance or the option to have a portion of the rate support renewable energy projects.
After the Province turned away from the open market concept, the OEB developed an electricity
price plan that provided stable and predictable electricity pricing and ensured the price consumers
pay for electricity better reflected the price paid to generators. The OEB’s Regulated Price Plan (RPP)
in effect diminished the need for electricity retailers in Ontario by addressing the consumer’s desire
for predictable electricity rates. The OEB reviews the RPP twice a year to better reflect the true cost
of producing electricity while at the same time providing stable rates for customers.
Despite the impact the RPP has had on the need for electricity retailers, in recent years, legislative
attention has focused more on retailer practices. The government’s Electricity Consumer Protection
Act (ECPA) was passed in 2010 as a response to electricity retailers whose business practices were
increasingly viewed by the public as questionable. The new rules in the ECPA addressed the most
common complaints that the OEB received relating to retailers, specifically the provision to customers of copies of their contracts, improper procedures for reaffirmation calls, and poor business
practices relating to renewals.
Retailer practices such as door-to-door sales and the provision of potentially misleading informtion
to customers accounts for 70-90 per cent of complaint calls to the OEB. Customers, concerned about
rising electricity prices, may be signing with the belief that future
higher prices can be avoided by contracting with a retailer, even
though most of the projected price increases will be included in the
“global adjustment”. Contracts with retailers are typically for the cost
of power, and may not protect against increases in delivery, regulatory, global adjustment or other non-energy charges.
As a result of the ECPA, the OEB has expanded its regulatory oversight
of electricity retailers. The costs associated with expanding regulatory
tasks have an impact on the entire rate base.
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With a RPP structure that provides stability and predictability in price and electricity retailers whose
presence is a net cost to the regulatory system as a whole, government should curtail the role of
electricity retailers by:
1. Disallowing further electricity retailer contracts for residential customers
This may require that the Provincial government revisit the legislative and regulatory stipulations that allow for electricity retailers in Ontario, specifically Part V.1 of the OEB Act.
2. Phasing out existing contracts with residential customers by allowing them to expire
All standing contracts held between customers and electricity retailers should be allowed to
expire. The retailer will not be allowed to seek renewals with customers and the contracts
will be void on the expiry date. The Minister should use his powers as outlined in Section
1.2 of the ECPA to educate and advise consumers of the impending change.
3. Electricity retailing should only continue in circumstances where the value proposition
can be clearly demonstrated for institutional, industrial, and commercial customers.
Non-residential customers are better suited to make the complex business decisions associated with contracted electricity rates. Large businesses and power consumers may find
value in a retailer arrangement, but such retailers should remain under the authority of the
OEB and should demonstrate their value proposition to the regulator.
According to the Ontario Auditor General’s 2011 Annual Report, approximately 15 per cent of the
Province’s customers are currently signed up with a retailer and are paying between 35 to 65 per
cent more than customers paying RPP rates to their LDCs.20 Phasing out the role of electricity retailers for residential customers will save the electricity system approximately $260-million annually
based on a 50 per cent premium compared with RPP rates. Additionally, LDCs and customers will
benefit from reduced costs related to billing settlement processes, collections on defaults, and reduced need for regulatory oversight.
Phasing out the role of electricity retailers for
residential customers will save the electricity
system approximately $260-million annually
These significant cost savings are a result of reduced regulatory oversight and costs for enforcement for
non-compliant retailers, reduced distribution costs, reduced customer complaints and better price signals and demand response as all formerly retailer contracted residential customers will be on TOU rates.
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F. Estimates of Potential Efficiency Gains
As we have outlined earlier, a centralized and directed approach to consolidation is unlikely to
achieve material savings and indeed the costs of such restructuring could exceed the benefits. We
therefore recommend that the panel consider other meaningful efficiency improving measures
along the lines that we have discussed. In order to provide a magnitude of the potential efficiency
savings, we have conducted analysis on the potential savings to customers to be approximately
$540-million broken down as follows:
• expansion of the scope of LDC operations to manage water and waste-water services −
$180-million assuming seven per cent savings on total distribution costs of all LDCs annually
• permission for LDCs to carry out street lighting work − $15-million
• expansion of LDC role in the development of CDM programs that are suitable to customer
needs and that deliver programs without OPA involvement − $20-million annually
• improvement of the regulatory framework within which LDCs operate $15-million which
represents 33 per cent of the current expense for LDCs
• curtailment of energy retailer operations in the residential sector assuming 15 per cent are
currently on retail contracts − $260-million
• voluntary consolidation of LDCs at $50-million21
Potential savings to customers are estimated to be
approximately $540-million.
With Province-wide electricity bills exceeding $12.8-billion, these savings should have a beneficial
impact of reducing overall customer costs by almost five per cent.
Additional information can be found in Efficiency Opportunity Fact Sheets in Appendix G.
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Alternative Industry Models
It has been suggested by some that Ontario has too many distributors and that there are substantial
scale economies that could be realized through consolidation within this sector. As noted earlier,
Ontario is presently served by approximately 75 distributors of widely varying size. This is far fewer
than was the case in the 1990s when there were over 300 distributors (in 1975 there were 353
distributors).
A separate issue is whether, going forward, there will be new scale economies to be realized as
distributors become progressively more involved in implementing smart technologies and ownership of distributed generation. This is an open question, the answer to which cannot be preordained
from existing data. However, we note that in other jurisdictions, for example various states in the
U.S., which are pursuing smart technologies, it is not uncommon to have many utilities of varying
sizes existing side by side. Furthermore, as is evident from the many examples contained in the
Appendix C, expansion is not a necessary condition for technology adoption and diffusion, or for
achievement of scale economies across utilities.
With these considerations in mind, we propose several graduated models for the distribution segment
of the Ontario electricity industry. The first is essentially the status quo, without implementation of the
efficiency enhancements described in this paper. The second allows the introduction of some new incentives which promote economies of scope. The third creates incentives for expansion of utilities to their
municipal boundaries. The fourth envisions an end-goal of shoulder-to-shoulder utilities.
We do not see these models as discrete alternatives, but rather as lying along a progression, with
each encompassing its predecessor. We see scope economies as representing an attractive source
of efficiency improvement and therefore the pursuit of scope economies comprises a core part of
our models. The central goal underlying the sequence of models is the creation of efficient, robust,
well-resourced, and where possible, shoulder-to-shoulder utilities through voluntary transactions.
In all cases we see an expanding role for municipal distributors. At its root, this expansion is driven
by three technological shifts. The proliferation of renewable distributed generation, the expansion
of conservation programs, and an increasingly information-based (smart) grid. Furthermore, while
electricity transmission is a function best performed by a single utility operating over a wide geographic area, distribution of electricity over much smaller areas, such as municipalities, enhances
accountability, provides for the opportunity to exploit scope economies by allying with other local
or municipal services, and allows a diversity of approaches and business models.
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The central goal underlying the sequence of models
is the creation of efficient, robust, well-resourced,
and where possible, shoulder-to-shoulder utilities
through voluntary transactions.
A.Model 1: Status Quo
The “status quo” model assumes continuation of the present industry structure and regulatory and
legislative framework. Continuing on the present path would not cause one to anticipate disaster
– there is no imminent crisis that is looming. However, pressures are building. First, regulation is becoming progressively more onerous and an obstacle to change. Second, distribution infrastructure
is aging and in need of capital investment. Third, there is an expanding gap between provincial CDM
aspirations, and the ability of the system to reach the targets under the present regime.
The most visible challenges to the industry as a whole reside in the generation segment, in particular upward cost pressures associated with the nuclear program and renewable generation.
While the “status quo” may be able to sustain itself for a period of time, the overarching disadvantages of maintaining the status quo in the distribution segment of the industry are the foregone
efficiency gains achievable through scope economies and regulatory streamlining, and the continuation of restrictions on further evolution.
B.Model 2: Expansion of Incentives and Opportunities
Presently, municipally owned distributors are constrained in their ability to exploit economies of
scope. They are also limited in their ability to acquire other distributors due to capital constraints,
for example, municipalities are not permitted to reinvest in their local distributor.
This model would develop incentives and mechanisms that would expand economies of scope and
encourage voluntary amalgamations that would bring scale efficiencies and benefits to customers
and shareholders. Incentives and mechanisms would focus on
• enhancing growth through scope by reducing regulatory and other barriers;
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• facilitating more access to equity by the LDC/shareholder through regulatory and legislative
changes;
• and, expanding shared services between utilities.
In order to achieve these objectives, regulatory or legislative changes may be required.
Earlier we have listed 18 possible areas of activity which could broaden the scope of LDC activities.
Many of these would require significant regulatory changes and a revised regulatory approach. For
example, decentralization of CDM design would imply a fundamental change in the direction of
recent policy. Procurement of non-renewable and larger renewable generation by LDCs would require revisions to legislation. (Local non-renewable or conventional generation that is dispatchable
will be increasingly desirable in order to balance intermittent renewable supply.) Expansion of LDC
activity into other municipal services (such as water, waste-water, street lighting, energy from waste
and district heating) would be greatly enhanced by changes to legislation that specifically authorize
multi-utilities and by a fundamental rethinking of the Affiliate Relationships Code.
Other areas of potential LDC activity are associated with nascent or immature technologies. Among
these are energy storage technologies and electric vehicle charging infrastructure.
The electricity industry is by nature one that breeds
a risk-averse culture because of the overarching
mandates for safety and reliability.
The electricity industry is by nature one that breeds a risk-averse culture because of the overarching
mandates for safety and reliability. But the current regulatory and policy environment within which
Ontario LDCs operate is far more restrictive than necessary in areas unrelated to these two mandates. In fact, the scarcity of regulatory incentives for innovation, for example with respect to scope
economies, reinforces risk-averse tendencies. Model 2 therefore focuses on the elimination of
unnecessary constraints and the creation of productive incentives and opportunities. In all cases,
a high degree of regulatory certainty is essential if innovative paths are to be followed.
C.Model 3: Expansion of LDCs to Municipal Boundaries
Model 3 would permit, encourage and incent LDCs to expand to municipal boundaries as a means
to foster greater scale, improved efficiency and consistent customer service. (It is important to reemphasize that Model 3 is intended to build on the elements that would have already been in place
under Model 2.)
Prior to 1999, municipal electric distributors were permitted to expand their service territories to
municipal boundaries under the Power Corporation Act (PCA). The Power Corporation Amendment
Act 1994 (Bill 185) encouraged municipalities to pass by-laws in order to assume control and management of the distribution assets within their entire municipal boundaries. At the discretion of the
municipality, the acquisition could be conducted in phases. The legislation set out a number of conditions and provided for the transfer of employees and assets from Ontario Hydro to the municipal
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commission at cost less the customer equity invested in the distribution system that had been built
to serve them. Bill 185 also transferred the rural rate assistance associated with those customers to
the expanding commission on a declining basis from 100 to 0 per cent over five years.
This provision for expansion by municipal distributors was removed with the introduction of Bill 35,
the Energy Competition Act, 1998, which enacted the Electricity Act and the Ontario Energy Board
Act, and revoked the Power Corporation Act. Over the years, municipalities have continued to receive requests from local residents who wish to be served by the local distributor. Under the present arrangement, distributors seeking to expand are required to negotiate a purchase of the assets
serving the customers of the provincially owned distributor.
Model 3 proposes that the intent of the previous provisions under the Power Corporation Act which
facilitated expansion of LDCs to municipal boundaries be reconsidered. Expansions of this type will
benefit the customers seeking to be served by the local utility. The added local customers will allow
further economies of scale for the LDC.
If necessary, provision could be made for density based rates, similar to those offered by the provincial distributor (i.e., different cost-based rates for rural and urban customers). Hydro One may lose
some of its more dense service territory possibly leading to higher rates for the remaining Hydro
One retail customers. In the alternative, rural-rate assistance may need to be increased, which
could result in the same total assistance directed to a smaller group of low density customers.
D.Model 4: Shoulder-to-Shoulder Robust Efficient LDCs
Once the elements of Models 2 and 3 have been implemented, then it may be appropriate to incent and encourage all distributors including the Provincial government to consider allocating the
remaining provincial assets to expanded distributors. The Province could participate as an equity
partner, an operating partner, or both.
Alternatively, the distribution assets could be sold, over time, to distributors. The objective would
be to move towards a model of shoulder-to-shoulder distributors that are robust and efficient, operate where appropriate as multi-utilities, potentially have multiple shareholders, are responsive to
their respective communities, and engage in progressive and innovative projects.
One of the principles which underlies this model is the potential for gains arising out of economies of
contiguity. The technology of electricity distribution is such that it is more efficient to serve customers that populate a contiguous, self-contained area. A single utility may serve multiple areas, but it
is preferable if each of its service areas is of sufficient size so that economies of scale are also realized.
The technology of electricity distribution is such
that it is more efficient to serve customers that
populate a contiguous, self-contained area.
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It is worthwhile to consider the extent to which the geographic pattern of Ontario distribution
meets the contiguity criterion.
• The largest concentration of population is in the Golden Horseshoe which is served by a
series of contiguous utilities. Collectively these represent approximately 45 per cent of
customers in Ontario.
• Hydro One Networks serves approximately 25 per cent of Ontario customers.
• Several utilities provide service to multiple non-contiguous areas. An expansion of their
service territories to create contiguous zones to the extent possible may be worthy of
consideration.
• There are a number of utilities which are surrounded by vast expanses of land with very
low population density.
The spatial distribution of customers in Ontario suggests a second alternative to Model 4 under
which a cooperative utility to serve low-density and remote communities could be created. Shoulder-to-shoulder utilities would form voluntarily where possible and practical. It may be that widely
dispersed customers may be best served by a utility specifically designated to serve low-density or
remote customers that do not naturally fall into the catchment area of one or another municipaltype utility. Density-based rates and a rural-rate assistance program would need to be evaluated if
this path is selected. The EDA does not view expanding the Provincial government’s role in
distribution as an efficient or desirable consolidation option.
E.Implementation Alternatives
We outline two options for implementation of the above sequence of models. In all cases, we
believe that certain core components can be implemented with relative ease, in part because they
involve rescinding certain current policies and regulations, or revisiting the intent of previous policies and legislation. Among these are the decentralization and devolution of CDM design to LDCs,
a permissive policy and regulatory stance toward the multi-utility model, and revisiting the right of
LDCs to expand to municipal boundaries. None of these recommendations represents uncharted
territory. However, the pace of change and the end-state depend largely on the structure of
legislative and regulatory changes, and the intentions and resolve of the Government.
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Option A: Under this alternative, the Provincial government and regulator proceed with the
necessary changes to enable the above sequence of models, but do not predetermine the
end-state. It may be that the next status quo is a version of Model 2 or Model 3. Essentially,
the focus is on changes in the setting within which LDCs evolve, and not on the final state.
Option B: Under this alternative, it is concluded that the Province is best served by
shoulder-to-shoulder distributors, i.e., Model 4. Therefore, the Government and
regulator then proceed with promoting the realization of Model 4.
Option A focuses on changes in the setting within which utilities operate. Option B focuses on the
“end-state” structure for the distribution industry. The EDA is willing and fully prepared to work
with the Provincial government, utilities and stakeholders to determine the preferred option.
The pace of change and the end-state depend
largely on the structure of legislative and regulatory
changes, and the intentions and resolve of the
Provincial government.
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Conclusions and Recommendations
LDCs have safely and reliably delivered electricity for over 100 years through locally based companies. Prior to 1998, LDCs offered numerous services to customers and their local municipality. The
Energy Competition Act changed the LDC role dramatically. Over the past decade, the pendulum is
shifting back towards an expanding LDC role. There is an opportunity now to improve efficiencies
relating to regulation, economies of scope and scale. Devolution of CDM program design and
development to distributors will be both efficiency improving and more efficacious than the
present approach.
The internal structure of wires companies should be permitted to evolve in order to exploit potential economies of scope. The separation of wires functions from other activities, that is unbundling,
was sensible at a time when the main objective was to open the industry to maximum competition.
That model has long since been abandoned and combining some activities, to the extent that it
reduces costs, may be appropriate and should be pursued where beneficial.
Ontario is at the forefront in a number of areas of electricity industry development. This, combined
with a broader electricity industry structure that differs from most jurisdictions, suggests that one
cannot simply look for formulaic solutions or templates elsewhere.
The Ontario electricity industry underwent major changes during the last decade and a half, at very
considerable cost. In hindsight, given where the industry is today, the necessary changes could have
been achieved at much lower overall costs. Radical change today is also likely to be costly. We have
evaluated several graduated models for the distribution segment of the industry. There are multiple
nuanced differences among these models: no model is uniformly better than the others.
The most promising path for evolving the structure
of the distribution segment of the industry is to
proceed on a voluntary basis.
The best available empirical evidence indicates that the most promising path for evolving the
structure of the distribution segment of the industry is to proceed on a voluntary basis. Strategic
and advantageous mergers will occur as long as there are sufficient incentives to do so. Utilities
that are at the forefront of developing new and better business models will lead the way.
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Transmission and distribution functions are changing and emerging information-based technologies
require the development of new functional capabilities. Foremost among these are the incorporation of distributed generation and the integration and expanded utilization of smart-meter and
smart-grid systems. It should be recognized that these technologies alter the risk profile of distribution utilities which, when these risks achieve materiality, should be reflected in the returns that
utilities are permitted to earn.
Regulatory costs have grown steadily over the last decade and on their present path are likely to
grow still further. The intervenor process, although an important part of the review process, has
become a growing expense to customers. Capital expenditures to renew aging infrastructure, new
conservation programs, investment in systems which can accommodate distributed generation and
emerging information technologies will increase demands on regulators and wires companies.
Improving and streamlining the regulatory process will be essential, but this responsibility does not
reside with the regulator alone. Utilities may need to accept more risk and responsibility in order to
save regulatory resources. At the same time, they should be provided with a clear opportunity to
operate their businesses with as little regulatory and political intervention as possible.
It is natural to ask whether, after a decade of structural and legislative changes, we are in a better place. Considerable resources have been expended on restructuring resulting in a substantially
more elaborate institutional structure. In parallel, regulatory and administrative expenses have
increased dramatically for much of the industry. The broader objectives of decentralization and
deregulation have, in many ways, fallen by the wayside.
Perhaps the most important lesson from the past is not to jump on the next trend too vigorously
without careful reflection. Ratepayers have limited capacity for costly changes that prove to be
lacking in efficiency or effectiveness. This, in turn, can endanger legitimate long-term objectives.
In short, political capital must be expended wisely. The previous government embarked on a costly
marketization experiment. The present government has embarked on a path fundamentally driven
by the decarbonisation of the electricity sector. Both are laudable objectives. However, an armslength relationship between the political masters that set policy and the regulators who have deep
institutional knowledge of the industry is the preferred approach.
Perhaps the most important lesson from the past
is not to jump on the next trend too vigorously
without careful reflection.
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Summary of Recommendations
1. Efficiency Savings. The implementation of efficiency improving measures such as enhanced
regulation, expansion of scope economies, improved CDM design and delivery and curtailment of electricity retailers would reduce customer bills by about $540-million, or about
five per cent of total customer electricity costs. The recommendations which will lead to
these savings should therefore be implemented.
2. Regulatory Streamlining. Regulatory systems can be enhanced by flexibility to utilities
whereby they could choose fast-track approvals with lesser information requirements and
consolidated applications, or more detailed approval processes. Efficient utilities could
receive a streamlined review based on established benchmarks or milestones.
3. Economies of Scope. There are significant opportunities for efficiency gains through
economies of scope. Historically, Ontario multi-utilities exhibited on average seven per cent
lower costs for electricity customers than pure distribution utilities. An Ipsos Reid survey
conducted for the EDA identified 18 ways that LDCs could expand their scope of activities.
Regulatory and legal impediments which limit LDC ability to engage in these activities
should therefore be eliminated.
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4. Economies of Scale. Voluntary mergers among distributors may lead to further efficiency
savings. However, the vast majority of Ontario electricity customers are served by electricity
utilities which are sufficiently large to have achieved scale-efficiency. Mandated mergers, for
the purposes of simply reducing the number of distributors and creating larger utilities, are
therefore unlikely to achieve material savings and could erode yardstick competition which
has a beneficial impact on efficiency and innovation. It is estimated that approximately
$50-million in consolidation savings could be achieved through voluntary consolidations.
5. Technology and Innovation. Technology is a primary determinant of industry structure and
therefore technological change should be a primary driver of changes in industry structure.
As new technologies emerge and proliferate, there may be increased incentives for restructuring. Market forces and technology should therefore be principal drivers of change in the
future structure of the industry.
6. Industry Structure. The right of LDCs to expand to municipal boundaries should be
revisited. With the creation of an enabling environment, the industry may eventually
be comprised of shoulder-to-shoulder utilities servicing all areas of the Province.
7. Diversity. Electricity industries, like ecosystems, have multiple participants striving to
advance individual and collective interests. Within such systems, diversity is often more a
benefit than a hindrance. In the Ontario electricity industry, a diversity of distributors seeking
alternative business models and solutions to the challenges they face provide an important
benefit to the industry as a whole. Diversity benefits need to be considered in any
discussion of industry restructuring.
8. Conservation and Demand Management. CDM program design should be devolved to
distributors as has been the case in the past. Distributors are best positioned to respond
to local needs by designing programs that take into account local conditions.
9. On-Bill Financing. One of the obstacles to widespread adoption of conservation investments by retail consumers is the arrangement of financing. LDCs should be permitted to
arrange “on-bill financing” for their customers.
10.Curtailment of Electricity Retailers. As the Province has moved away from the competitive
model and introduced a regulated price plan for residential customers, there is no longer
the need for electricity retailers to provide rate smoothing contracts to the residential
sector. Furthermore, by offering fixed prices, electricity retailers are undermining a fundamental objective of government policy – the implementation of TOU rates. Electricity retail
contracts for the residential sector should therefore be phased out.
11.Infrastructure Investment. Aging LDC infrastructure needs to be refurbished or replaced on
an ongoing basis and new investment is required to meet system growth and expansion.
The essentiality of electricity to the economy and to society mandates the continuation of
the record of excellent service and reliability.
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12.Access to Capital. Two impediments limit LDC access to capital. First, municipalities are not
permitted to invest in the utilities they own. Second, there are limitations on private-equity
investments in distributors. Both impediments should be reduced in order to permit wider
access to capital for Ontario’s distribution utilities. Tax-exempt status for LDCs with greater
than 51 per cent of municipal ownership should be considered.
13.Smart-grid Technologies. Utilities should continue expanding their functional capabilities to
accommodate new and emerging technologies such as smart-grid systems and distributed
generation. Implementation of these technologies should be achieved on a cost-effective
basis as determined by individual utilities and the regulator. Incentive-based approaches
should be implemented where possible.
14.Distributed Generation. Distributors should be permitted to own and operate both renewable and non-renewable generation greater than 10 MW. As renewable supply increases it
may be appropriate for LDCs to acquire non-renewable dispatchable generation to compensate for fluctuating renewable supplies.
15.Cooperative Ventures. Ontario utilities cooperate extensively in numerous areas which
improves efficiency and diffusion of best practices. Such cooperation should be encouraged
and any regulatory obstacles should be eliminated.
16.Industry Model. We consider several graduated models for the distribution segment of the
Ontario electricity industry. We see these models as a progression which can be achieved
sequentially. The central goal is the creation of efficient, robust, well-resourced, and where
possible, shoulder-to-shoulder utilities through voluntary transactions.
a. Model 1 – Status Quo. Under this model, the industry continues along its present path.
While the “status quo” may be able to sustain itself for a period of time, the overarching
disadvantages of maintaining the status quo in the distribution segment of the industry
are the foregone efficiency gains achievable through scope economies and regulatory
streamlining, and the continuation of restrictions on further evolution.
b. Model 2 – Expansion of Incentives and Opportunities. This model envisions permitting
utilities to operate as multi-utilities thereby enhancing economies of scope, facilitating
access to capital, and encouraging expansion of shared services among utilities.
c. Model 3 – Expansion of LDCs to Municipal Boundaries. This model proposes that the
LDC right to expand to municipal boundaries be reconsidered, and that incentives and
processes be put in place that promote this goal.
d. Model 4 – Shoulder-to-Shoulder Robust Efficient LDCs. Once the elements of Models 2
and 3 have been implemented, then it may be appropriate to encourage all distributors
and the provincial government to allocate the remaining provincial distribution assets
not transferred by municipal utility expansion to distributors. The Province could choose
to participate as an equity and/or operating partner or to sell the assets to LDCs.
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Many core components of the above model sequence can be implemented with relative ease, in
part because they involve rescinding policies and regulations and revisiting the intent of previous
legislative and policy directions. Among these are the decentralization and devolution of CDM
design to LDCs, a permissive regulatory stance towards of the multi-utility model, and reinstatement of the right of LDCs to expand to municipal boundaries. None of these recommendations
represent uncharted territory. However, the pace of change and the end-state depend largely on
the future structure of legislation and regulation, and the intentions and resolve of the Provincial
government.
One of the difficulties that is likely to be encountered is the rate treatment of low-density customers. A rural-rate subsidy will be required. The establishment of a separate entity which serves these
customers and which receives appropriate transfers may comprise a practical solution. The EDA
does not view expanding the Provincial government’s role in distribution as an efficient or desirable
consolidation option.
17.Model Implementation. We suggest two options:
Option A: Under this alternative, the Provincial government and regulator proceed
with the necessary changes to enable the above sequence of models, but do not
predetermine the end-state.
Option B: Under this alternative, the Government determines that the Province should
be served by shoulder-to-shoulder distributors, i.e., Model 4. The Government and
regulator then proceed to vigorously promote the realization of Model 4.
Option A focuses on changes in the setting within which utilities operate. Option B focuses on the
“end-state” structure for the distribution industry. The EDA is willing and fully prepared to work
with the Government, utilities and stakeholders to determine the preferred option.
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Appendix A: Responses to Ontario Distribution Sector
Review Panel Questions
Sector Review Panel Questions:
a. Do you have a position on possible approaches to restructuring the utility sector, which is
based on data or experience?
The EDA proposes four sequential models for consideration. The first stage is status quo; the
second stage provides new incentives which promote economies of scope; the third stage
offers incentives to expand to municipal boundaries; and, once elements of two and three
have been implemented, the fourth model envisions a move toward shoulder-to-shoulder
distributors. The central goal underlying the sequence of models is the creation of efficient,
robust, well-resourced, and where possible, shoulder-to-shoulder utilities through voluntary
transactions.
For further details see the section “Alternative Industry Models” on pages 62 to 67.
b. How might such restructuring be arrived at?
The EDA proposes two options for implementation, with the first requiring necessary changes
to enable the sequence of the proposed models, with no predetermined end-state, and
the second involving a pre-determination of a structure and changes made to realize the
end-state. The pre-determination of a structure would be based on a voluntary approach
achieved through consultation between LDCs and government. For more details see the
“Alternative Industry Models” section, part E “Implementation Alternatives” on page 66.
c. What would the costs and benefits be of such restructuring, with particular regard to the
electricity ratepayer?
With respect to the benefits, if voluntary consolidation of the distribution sector is done
correctly the savings could be up to $50-million. There are other meaningful efficiency improvements which could provide a total of $540-million in savings if implemented. See the
section “Estimates of Potential Efficiency Gains” part G on page 61 and explanations of the
savings in the “Efficiency Opportunities” section on pages 33 to 61.
With respect to costs, we note on page 61 that a mandated approach to consolidation is
unlikely to achieve significant savings and likely the costs of such restructuring could exceed
the benefits.
d. What implementation issues and/or risks should be considered?
The EDA has identified seven important considerations that need to be taken in account
when considering consolidation. See the section “Efficiencies from Scale and Contiguity”
Part B on pages 37 to 43.
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e. What principles should govern restructuring?
In the section “Efficiencies from Scale and Contiguity” Part B on page 39 we note that
structural changes to the distribution sector should:
• be voluntary and commercially based;
• where possible, support contiguous or shoulder-to-shoulder mergers to optimize
planning synergies;
• increase levels of service and reliability to customers;
• reduce costs in the short term and long term.
f. Do you have any further research to share with the Panel to support your position?
Research is provided in Appendices B to F which include data on the U.S. electricity
distribution industry; Ontario LDC efficiencies achieved through collaboration; LDC Reliability
Indicators; LDC Service Quality Indicators; and LDC Cost Performance Indicators.
There is also other important data provided throughout the report.
g. How can utility innovation be encouraged to ensure that utilities are prepared to meet the
needs of the 21st century while providing maximum value to customers?
Building on existing smart meters and moving to the next phase of innovation requires
policy commitment and regulatory support that recognizes the higher initial costs in systems, equipment, and skilled resources required to obtain a longer-term benefit.
For further details see the section “New and Emerging Technologies” Part B on pages
17 to 25.
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Appendix B: The U.S. Electricity Distribution Industry
Overview of U.S. Electric Utility Structure
There are four main types of electric utilities operating in the United States. These four types of
utilities offer different services for their customers:
Investor-owned utilities (IOUs) are for-profit companies owned by their shareholders. Investor
owned utilities are regulated by State Utility Regulators. These utilities may have service territories
in one or more states. Each state will provide them a “franchise” or “certificate of public convenience
and necessity” to operate in specific areas of the state under certain terms and conditions. Their
generation, bulk power sales, and transmission are regulated by the FERC and their distribution
system and rates are regulated by the states, or in some cases by tribes. Regulated IOUs generally
focus on providing electric and/or gas services to customers. Depending on the regulatory environment, these utilities provide generation, transmission, distribution, renewable-resource investment,
economic-development programs, low-income programs and net-metering services.
Public-power utilities are not-for-profit utilities owned by cities, counties, and tribes. City-owned
utilities are referred to as municipal utilities, or “munis”. In some cases universities or military bases
own and operate their own utilities. These are generally not regulated by FERC or by states, since
their own local government has a legally devised system for their operation and management.
Because munis are locally controlled utilities, these utilities will often expand services to include
additional city or county services, such as water, waste-water, garbage, recycling, street lighting,
cable and fibre telecommunication services. In addition, these utilities often focus on providing
additional long-term planning and community service to their service areas.
Cooperatives, or co-ops, are not-for-profit entities owned by their members. These include
traditional rural utilities created by groups of farmers and ranchers who needed a way to get service
to their sparsely populated areas. Historically, federal policies supported these (often more expensive)
infrastructure developments through low-interest federal loans, which are now administered by
the U.S. Department of Agriculture’s Rural Utilities Service. Co-ops are similar to munis and provide
many of the same services as munis. For most states, co-ops are also regulated by locally elected
officials.
Federal utilities include the Bonneville Power Administration (BPA), the Tennessee Valley Authority
(TVA), and the Western Area Power Administration (WAPA). All three of these are wholesale-only
utilities that provide electricity to other (primarily municipal- and tribal-) utilities for distribution to
customers. BPA and WAPA are also called Power Marketing Administrations (PMAs). BPA and TVA
own both generation and transmission facilities. WAPA is a transmission-only utility providing power
from federal hydroelectric facilities in the West (operated by the U.S. Army Corps of Engineers, the
U.S. Bureau of Reclamation, and the International Boundary and Water Commission) to other retail
utilities. The federal utilities focus on providing generation and/or transmission services.
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The characteristics of the U.S. electric distributors are described below according to the number
of providers, end-use customers, sales (measured in megawatt-hours, MWh), generation (MWh),
and revenue. The data is taken from the American Public Power Association (APPA) 2012-2013
Annual Directory & Statistical Report. Figure 1 shows the number of providers according to ownership structure. Most providers are publicly owned.
Figure 1 Number of Electricity Service Providers in the U.S.
Figure 2 shows the number of customers served by each electric service provider type. While
there are a large number of publicly owned utilities, most customers in the U.S. are served by
investor-owned utilities (IOUs). The number of customers includes both full-service and
delivery-only customers.
Figure 2 Number of Customers by Utility Ownership
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Figure 3 illustrates the MWh sales to ultimate customers. The number of customers includes both
full-service and energy-only sales. Figures 2 and 3 show that power marketers have customers with
above-average electricity consumption.
Figure 3 MWh Sales by Utility Ownership
Figure 4 illustrates generation ownership. Nearly 80 per cent of the power generation in the U.S.
is provided by IOUs and Power Marketers.
Figure 4 MWh Generation by Utility Ownership
Lastly, Figure 5 shows the revenue collected by each utility type.
Figure 5 Revenue by Utility Ownership, $Millions
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Table 1 summarizes the data presented above. The last column shows the quotient when revenues
are divided by the MWh sales. Generally, publicly-owned utilities and cooperatives have lower rates
compared with IOUs.
Table 1. Summary of U.S. Electric Service Provider Data
Providers
Publicly Owned Utilities 61.7%
Investor-Owned Utilities 6.0%
Cooperatives
26.9%
Federal Power Agencies 0.3%
Power Marketers
5.2%
Customers
Sales
MWh
Generation
MWh
Revenue
14.5%
68.2%
12.8%
0.0%
4.4%
15.3%
57.3%
11.0%
1.2%
15.2%
10.0%
39.7%
5.1%
6.3%
38.9%
14.5%
60.9%
10.8%
0.5%
13.3%
Average Rate
(Revenues/Sales)
$
$
$
$
$
93.43
104.52
96.52
41.18
85.68
Individual State Results
In order to further detail the structure of electric utilities in the U.S., specific results by State was
gathered. The following sections provide summary data for several States.
California
California distribution consists of four co-ops, 36 munis, and six IOUs. The average size of the
co-ops are 4,100 customers, while the munis have approximately 88,000 customers and the IOUs
have an average of almost 2 million customers each.
Figure 6 California Energy Sales by Utility Ownership, kWh
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Idaho
Idaho distribution consists of 17 co-ops, 11 munis, and three IOUs. The average size of the co-ops
is 4,800 customers, while the munis have approximately 3,900 customers and the IOUs have
an average of 220,500 customers each.
Figure 7 Idaho Energy Sales by Utility Ownership, kWh
Illinois
Illinois distribution consists of 27 co-ops, 41 public utilities, and six IOUs. The average size of the
co-ops is 11,000 customers, while the public utilities have approximately 6,500 customers and
the IOUs have an average of 838,000 customers each.
Figure 8 Illinois Energy Sales by Utility Ownership, kWh
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Massachusetts
Massachusetts consists of 0 co-ops, 40 munis, and five IOUs. The average size of the munis is
approximately 10,000 customers and the IOUs have an average of 460,000 customers each.
Figure 9 Massachusetts Energy Sales by Utility Ownership, kWh
Michigan
Michigan consists of 10 co-ops, 41 munis, and nine IOUs. The average size of the co-ops is 30,000
customers, while the munis have approximately 7,400 customers and the IOUs have an average of
460,000 customers each.
Figure 10 Michigan Energy Sales by Utility Ownership, kWh
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Montana
Montana consists of 29 co-ops, one muni, and four IOUs. The average size of the co-ops is 6,600
customers, while the muni has approximately 1,000 customers and the IOUs have an average
of 90,000 customers each.
Figure 11 Montana Energy Sales by Utility Ownership, kWh
Nebraska
Nebraska consists of 10 co-ops, 149 munis, and 0 IOUs. The average size of the co-ops is 2,300
customers, while the munis have approximately 6,500 customers.
Figure 12 Nebraska Energy Sales by Utility Ownership, kWh
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New York
New York consists of four co-ops, 48 munis, and eight IOUs. The average size of the co-ops is 4,500
customers, while the munis have approximately 27,000 customers and the IOUs have an average of
680,000 customers each.
Figure 13 New York Energy Sales by Utility Ownership, kWh
Oregon
Oregon consists of 19 co-ops, 18 munis, and three IOUs. The average size of the co-ops is 10,500
customers, while the munis have approximately 16,000 customers and the IOUs have an average
of 460,000 customers each.
Figure 14 Oregon Energy Sales by Utility Ownership, kWh
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Pennsylvania
Pennsylvania consists of 13 co-ops, 35 munis, and 11 IOUs. The average size of the co-ops is 16,700
customers, while the munis have approximately 2,400 customers and the IOUs have an average of
500,000 customers each.
Figure 15 Pennsylvania Energy Sales by Utility Ownership, kWh
Washington
Washington consists of 18 co-ops, 40 munis, and three IOUs. The average size of the co-ops is 9,000
customers, while the munis have approximately 40,000 customers and the IOUs have an average of
480,000 customers each.
Figure 16 Washington Energy Sales by Utility Ownership, kWh
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Rate Comparison between Size of Utility
The State comparison shows that most States have a large number and different sizes of utilities.
While there are differences in the cost of financing for each type of utility, Figure 17 demonstrates
that large utilities (i.e. IOUs) in the U.S. do not necessarily result in lower rates.
Figure 17 Average Revenue per kWh by Utility Ownership, ($/kWh)
Scope of U.S. Electric Utility Structure
Utilities in the U.S. provide a variety of services for customers. While some states have allowed
deregulation, the majority of electric customers still receive power supply and distribution services
from their local electric utility. The following sections describe the common services provided by
electric utilities in the U.S.
“Standard” Electric Services
The primary services that have traditionally been provided by electric utilities in the U.S. involve
all the necessary tasks with providing electricity to the retail customer. These have generally been
generation, transmission and distribution services. However, by the early 2000s several U.S. states
had implemented retail choice for customers. Under these new regulations, retail customers could
now elect to receive power supply from alternate providers.
While the electric utilities still provide power to the majority of customers, the deregulation changed
the planning for generation resources and resulted in increased reliance on market purchases. Since
then, several states have suspended restructuring and retail choice and returned to the traditional
utility model.22
Ancillary Electric Services
In addition to providing the standard electric-utility services, electric utilities in the U.S. also provide
additional ancillary services to customers. These include investment in renewable resources, allowing
interconnection to distributed generation resources and providing net metering programs for smaller
renewable resources. In addition, electric utilities provide significant assistance to customers in the
area by offering conservation programs and demand-side management programs, such as water
heater control programs. Finally, the majority of electric utilities offer some type of low-income
and medical assistance to customers in need.
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Additional Utilities
A large share of U.S. electric utilities also provides additional utilities to customers. Most common
utilities provided are gas, water and waste-water services. For municipal utilities owned by cities,
it is also common to provide garbage, recycling, and street lighting services to customers. Finally,
several utilities have been expanding to provide telecommunication services over fibre. As utilities
invest in fibre infrastructure for SCADA systems and smart grid, providing reliable high-speed
service to customers has helped recoup some of the cost of the fibre system.
Community Emphasis
The final category of service that utilities provide in the U.S. is mainly provided by co-ops, city and
county utilities. Because these utilities focus their service on a local community, the emphasis on
supporting and growing the local economy is very strong. These additional services include staff
providing community services, planning guidance and assistance to meet the long-term goals of
the community.
Mergers and Acquisitions
Since 2008 there has been an average of three mergers or major acquisitions of IOUs.23 Prior to
2008 (2001-2007), the average number of mergers or major acquisitions was much higher at about
six per year. In the year 2000 there were 22 mergers or major acquisitions. The number of mergers
and acquisitions may be influenced by both regulatory and economic reasons. The energy crisis in
2000 might explain the large number of mergers and acquisitions. The lower numbers beginning in
2008 might be explained by the 2008 recession. Figure 18 summarizes the number of mergers and
major acquisitions by year. The green shaded areas denote recessionary periods as predicted by
the U.S. Treasury Spread.24
Figure 18 Historic Mergers and Acquisitions of Electric IOUs
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Scope and Scale Economies
Multi-utilities exist for several reasons. Perhaps the most important reason is the synergy observed
where direct economies of scope in the supply of services are available, but also the ability of the
firm to capture customers in different markets using a protected position as a regulated utility.25
This section of the report discusses the theory behind the cost efficiencies of multi-utilities,
as well as provides evidenced-based support for broadening the scope of utility service.
Cost-efficiency Theory
A natural monopoly, such as utility companies, is characterized as an industry where total production costs of a single firm is lower than that of several companies producing the same output.
Therefore, the concept of natural monopoly is closely related to the economies of scope and scale
in production.26 The optimum scope and scale of a natural monopoly, such as an electricity distribution company, is determined by both a measure of technical and allocative efficiency.27 Technical
efficiency is the ability of the utility to minimize cost for a given amount of output. For example,
technical efficiency may be achieved for electric utilities offering incentives for customer conservation. Conservation is generally a low-cost power source; therefore, utilities offering programs to
decrease electricity use can avoid the high marginal cost of power.
Allocative efficiency is the ability of the utility to use inputs in the correct proportions given prices
and technology. An example of allocative efficiency is the size of service area. If a service area is too
broad geographically, the utility may need additional administrative or technical offices to provide
service. These additional services might cause the utility to experience higher average costs if
the characteristics of the service territory reduce the input to output ratio. To illustrate, a utility
servicing a large city might decrease the ratio of inputs to outputs if the utility expanded to the rural
parts surrounding the city. The rural area requires a different share of input to output for service;
costs per unit of output are higher where population density is lower. A neighbouring rural utility
may have lower costs compared with the city utility for providing service to the expanded area due
to reasons of proximity or lower fixed costs associated with rural locations. In this example, the
optimum number of electric distributors over a region, and the scope or services offered, may
be determined by geographic or consumption characteristics (such as climate).
Horizontal Economies of Scope
This section provides some support for economies of scope at the electricity distribution level. The
results of these papers may or may not directly apply to other countries due to differences in regulations, policy, or other factors; however the consistent support for horizontal economies of scope
at the electric distribution level is important.
First, a Switzerland study finds that multi-utilities (offering water, gas, and electricity) exhibited significant cost complementarities between the distribution of electricity and other outputs (gas and
water) and a weak complementarity between gas and water (for data collected between 1997 and
2005). The paper concluded that Swiss multi-utility sector benefits from significant economies of
scope (horizontal) and scale.28
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Similarly, a study of Italian utilities found that small to medium utilities may benefit from cost reductions by evolving into multi-utilities providing similar network services such as gas, water, and
electricity.29
Lastly, a meta-analysis shows that for water and waste-water utilities, diseconomies of scale and
scope are more likely to be found in publicly-owned utilities than when the ownership is mostly
private.30 Likewise, it was more likely to find diseconomies of scope for large utilities. Lastly, the
study did show that multi-utilities are more likely to have scale and scope economies. These results
may be important in the decision to expand utility scope to water and/or waste-water services.
Vertical Economies of Scope
The theory behind deregulation in the electric utility industry states that the loss of efficiency from
unbundling distribution service from transmission or generation would be overcome by the gains
from competition. However, the recent empirical literature supports that divestitures and restructuring typically reduce the distribution efficiency. In their paper, Triebs, Pollit, and Kwoka31 reviewed
30 U.S. generation asset divestitures between 1994 and 2006. The results of their analysis showed
that distribution efficiency was reduced resulting from the divestitures; however, this effect is
reduced over time. Further divestitures decrease the unit cost of power in the long run. The net
impact is a benefit to utility customers since generation benefits outweigh distribution costs.
In another study, Kwoka (2002)32 finds evidence for cost complementarity for generation and transmission and distribution for medium and large utilities. Additionally, Kwoka found that some holding structures can offset losses from vertical integration but the same is not true for membership in
power pools.
Kaserman and Mayo provide empirical evidence for benefits of vertical integration in the generation
and transmission/distribution of electric supply.33 Their analysis considered 74 privately owned electric utilities in 1981. Similarly, in a study of technological efficiency benefits of vertical integration
concluded that separating functions of generation, transmission and distribution results in a loss of
technical efficiency among 70 electric utilities in 1990.34
Lastly, the U.S. Department of Energy (DOE) Energy Information Administration (EIA) data35 show
that for the period 1997 through 2009, increases in retail electric prices were significantly greater
in states with deregulated electric markets. Prices in deregulated states increased by 3.9 cents/kWh
over the period where prices in regulated states increased by only 2.6 cents/kWh. Figure 19 compares these trends.
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Figure 19 Historic retail electric prices
Even though the cost increase is greater in deregulated states, the annual growth in retail rates is
lower at 3.57 per cent on average compared with 3.61 per cent for regulated states. Note that the
power supply cost variation across states that is not due to regulation is not controlled for. It is
unclear whether these cost trends are due to states factors that such as regulation, state inflation,
and other factors.
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Appendix C: LDCs Achieving Efficiencies through
Collaboration: Examples from Across the Province
Many LDCs in the province, ranging from small to medium to large, collaborate on various activities
and processes to achieve efficiencies by adopting methods and practices that lead to economies
of scale. Effective co-operation among utilities occurs in numerous areas including joint procurement of hardware and software, shared billing services, the use of the same metering technologies,
design and delivery of CDM programs, health and safety training, and joint efforts in the fulfillment
of regulatory filings provide.
Though not all savings are directly quantifiable they provide valuable short-term and long-term
benefits to LDCs of all sizes and consequently to their customers. The effective implementation
and utilization of new technologies to implement state-of-the-art processes improve operational,
administrative and engineering procedures, reduce expenses and improve service to customers.
Various LDCs are involved in a number of these informal groups to maximize savings and
efficiencies for their own operations and in turn for their customers.
Below are several examples of collaboration amongst LDCs and with other organizations, utilities
and companies. Where possible, estimates of savings have been provided.
Shared Billing Services
A. Approximately eight LDCs, including Essex Powerlines, Erie Thames Powerlines and Oshawa
PUC Networks use the ASP Model for the hardware that houses its billing systems. These
LDCs share services such as bill printing, stuffing and mailing through a common vendor.
The increase in scale leads to a lower unit price. They also share an archiving system for
billing reports which reduces printing costs and subsequent storage requirements. The
practice has resulted in estimated savings in excess of $50,000 per LDC per year.
B. Thunder Bay Hydro currently provides a range of key LDC billing and related services to
four of its Northern neighbours − Fort Frances, Kenora, Sioux Lookout and Atikokan. These
services include usage of a common Customer Information System (CIS) for customer billing; use
of a common Electronic Business Transaction system for retailer transactions; a wholesale
settlement system for Net System Load Shape calculations; maintenance of the Advanced
Metering Infrastructure system for meter readings; and, an Operational Data Storage
system for Meter Data Management and Repository (MDM/R) interactions.
C. In addition to the above, Thunder Bay Hydro offers services such as maintenance of metering
technology inventory, delivery of CDM Programs, meter services for utility revenue meters,
bill collection services, shared human resources safety practices, after-hours customer and
maintenance services, and large-scale procurement of equipment and services. Each utility undertakes its own due diligence and makes decisions as to what level of products and
services they will purchase from Thunder Bay Hydro. The five LDCs estimate that, based
on the cost and resources that would be required by individual LDCs to develop, establish
and maintain the above billing and other services and to undertake their own procurement
activities, net savings exceed $1-million per year.
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D. Horizon Utilities provides payment processing services on behalf of Waterloo North Hydro
using a common CIS. Waterloo North Hydro payments are couriered to Horizon Utilities,
processed, and electronically uploaded the same day into Waterloo North Hydro’s billing
system. This service provides benefits to both utilities, leading to decreased costs and
better utilization of assets.
Multi-Utility Billing by LDCs
E. Utilities Kingston, an affiliate company of Kingston Hydro, has been delivering and managing services for electricity, gas, water, waste-water and fibre optics for the City of Kingston
since the early 2000s. The production of a single bill for multiple services saves Kingston
Hydro approximately $150,000 per year through shared billing, paper and mailing costs,
and an additional $200,000 per year through shared staff, CIS systems and collection
services. Customers also save time and money by paying a single bill.
F. Orangeville Hydro currently provides water and sewer billing services for the City of
Orangeville. The LDC charges $3.22 per customer per bill. Estimated savings are in excess
of $340,000 every year.
G. Essex Powerlines combines the electricity bill with water and waste-water, providing
considerable savings to the electricity customer due to shared costs for staffing (billing,
collecting, and call centre), forms, postage and contracted services. Savings are estimated
to be approximately $578,000 per year.
H. Since 2005, Niagara-on-the-Lake Hydro has provided water and waste-water billing and
call-centre service for the Town of Niagara-on-the-Lake. The actual staff time for this service is booked to the LDC’s service company and in turn, the service company charges the
Town a flat rate fee at cost (currently $1.25/customer/bill). The joint bill savings in postage
to the community is $22,000 annually in addition to savings on stationery, printing and office costs. The use of one CIS system to perform electricity and water billing has deferred
the need for the Town to purchase such a system which would be expected to cost over
$100,000 and would attract annual maintenance costs. Customers have benefitted from
the lower cost and from having access to one bill for multiple utility services.
I. Innisfil Hydro will be commencing water and sewer billing for the Town of Innisfil in August
2012. After assessing options to continue billing tri-annually for water and sewer services
or having the LDC bill for these service on a monthly basis, the Town concluded that having
the LDC provide multi-utility billing would save the town’s consumers 10 per cent of current
billing costs.
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J. Other LDCs that provide multi-utility billing include PowerStream, Horizon Utilities (for the
city of Hamilton) and Collus Power Corporation.
Joint Standards Development by the Utilities Standards Forum (USF)
K. The Utilities Standards Forum (USF) is a cooperative formed several years ago by a dozen
utilities in response to the ESA request for professional engineer approved standards under
Ontario Regulation 22/04. USF develops construction standards for Ontario LDCs as directed
by their members and has now grown to 48 members (one large utility, 16 medium size
utilities and 31 small utilities), serving over 1.2 million customers. The members have a
volunteer Board of Directors and technical working group. USF members pay a small annual
membership fee to cover technical and clerical services to produce the standards and obtain
approval from ESA. There is a direct cost savings associated with the reduction of effort and
staff (for example, engineering and technical support service for the approval of standards).
Annual avoided costs range from $50,000 to $70,000 for each of 16 medium-sized LDCs as
well as for the one large utility. Small LDC savings are estimated to be $10,000 to $20,000
per year. There are also the intangible benefits of industry collaboration and networking
on the engineering and operational areas of the business.
Shared Services Based on Meter Technology
L. Utility Collaborative Services (UCS) was formed by a group of utilities which relies on
Harris/Northstar (“Harris”) for their customer information system. Members include Centre
Wellington Hydro, Collus Power Corporation, Midland Power Utility Corporation, Niagaraon-the-Lake Hydro, Orangeville Hydro, Parry Sound Power Corporation, St. Thomas Energy,
Wasaga Distribution Inc. and Welland Hydro Electric Systems Corporation. Overhead costs
for establishing a CIS include the initial cost of purchasing the software, licensing of the software and ongoing maintenance and support. UCS was formed as a cost effective solution
to all three of these issues. The cost of licensing Harris is dependent on the number of
customers billed through the system. UCS members collectively bill more than 100,000
customers through Harris. As a result UCS qualifies for business enterprise licensing rates.
One of the primary goals of the UCS group is to create a standard billing system. This is
achieved by standardizing billing practices. A common system reduces maintenance and
support costs as all updates, upgrades and changes apply uniformly to all participating
utilities. UCS has been able to provide strategic resources that perform the majority of the
setup and maintenance functions. During the implementation of TOU rates, UCS resources
were used to complete mandatory Meter Data Management and Repository (MDM/R)
testing. The required testing was extensive and time sensitive and would have been
extremely difficult to complete without UCS assistance. Participants estimate that
savings from participation in UCS range in the hundreds of thousands of dollars.
Joint Procurement of Products and Services
M. Essex Powerlines is part of a buying group consisting of a number of LDCs in Southwestern
Ontario. Inventory is standardized across the various LDCs and lower material pricing is attained through volume discounts. Each LDC estimates direct savings of at least $15,000 per year.
There are also indirect administrative savings that are not easily quantifiable.
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N. In 2005, Horizon Utilities, PowerStream and several other larger LDCs in the Province
worked on a joint Request for Proposal for the purchase of smart meters. Given the size of
the LDCs and the volume of smart meters to be purchased, these LDCs were able to establish minimum meter specifications and favourable pricing that would not only apply to the
initial participating LDCs but also to those who joined later. LDCs have benefitted from bulk
pricing and product standardization.
O. The implementation of the government mandated smart meter system was achieved by
Niagara-On-The-Lake Hydro and 30 other LDCs through a cooperative arrangement with
the local Niagara Erie Power Alliance (NEPA) and a larger “Sensus” provincial user group.
An Ontario consultant was utilized to combine the purchasing power of over 30 provincial
Sensus users. As a result, participating utilities were able to secure low cost contracts for
hardware, installation, disposal and security audit services. In addition, NEPA members
constructed an AMI system consisting of shared towers and head-end systems. The shared
arrangement saved Niagara-On-The-Lake Hydro an estimated $200,000 in capital investment and continues to save this utility an estimated $25,000 per year in associated
maintenance fees.
Shared Services Arrangement for Regulatory Filings
P. For about a decade, Cornerstone Hydro Electric Concepts Inc. (CHEC), comprised of 12
LDCs in Central Ontario, has been collaborating on regulatory reporting, CDM, Conditions of
Service and a host of other services. Annual collective savings are approximately $450,000.
The LDCs have a number of working groups which meet in order to standardize utility
documents as well as OEB filings. When LDCs were required to submit their CDM strategies
to the OEB in December of 2010, a working group was formed to standardize and create
a template for the submission. The group has also created standardized templates for the
numerous filings and reconciliations required by the OPA and for Conditions of Service
updates to the OEB. The CHEC group has recently expanded their services to include
rates and compliance support for member utilities.
Sharing ‘Locates’ Services
Q. Kingston Hydro uses one source which “locates” underground structures relating to electricity, water, sewage, gas, fibre, traffic signals and streetlights. By using this consolidated
model Kingston Hydro is able to save approximately $96,000 per year.
R. Essex Powerlines has contracted out locates at a reduced price and has been able to
reassign resources to higher priority projects. The contracted resource can now conduct
multiple locates at a time which results in lower costs to the LDC. Savings are
approximately $50,000 per year.
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Delivery of Conservation and Demand Management (CDM) Programs
S. Horizon Utilities organized and coordinated an application to the OPA to hire three
Key Account Managers under the “capability building” funding of the Province-wide CDM
Programs. The purpose of these resources is to provide CDM services to Horizon, eight other
utilities36 and 30 large industrial customers. Participating large industrial customers have
access to dedicated personnel who assist them in applying for various industrial program
initiatives. Participating utilities have access to energy specialists who can assist in providing
better CDM service to customers, thus fostering a culture of conservation and enhancing
LDC capability to meet CDM targets.
T. Other examples of joint CDM delivery include joint procurement of vendors by PowerStream and Newmarket-Tay Hydro; the provision of CDM marketing and delivery services
by Thunder Bay Hydro on behalf of four of its Northwestern neighbours; the delivery of
CDM programs by Hydro Ottawa on behalf of Hydro Hawkesbury and Hydro 2000; and the
delivery of CDM programs by Horizon Energy Solutions on behalf of Oakville Hydro. As the
2011-2014 Province-wide CDM Program is only in its second year, it would be premature
to quantify the benefits of the joint application and delivery process.
U. In 2005, the largest LDCs in the Province, serving 1.2 million Ontarians, successfully collaborated in the design and delivery of CDM programs. Many of these programs, e.g. the Great
Refrigerator Round-Up and peaksaver (now peaksaver PLUS) have since been expanded
into province-wide programs.
Collaboration and Aid During Natural Disasters
V. In June 2010, a Fujita Scale Level 2 tornado touched down in Midland, Ontario causing
extensive damage to private property and public infrastructure. Midland Power was able
to call on neighbouring LDCs (among them Wasaga Beach and Collus Power) to assist in
the stabilization of its distribution system. Power was restored to all customers not directly
in the path of the tornado within 24 hours. Midland Power is part of an informal group of
12 LDCs that have a mutual-aid agreement. In the case of the tornado, Midland was able
save costs during a period of emergency operations. The cooperative arrangement not only
saved costs but benefitted customers through more rapid system recovery. Many LDCs have
formal mutual-aid agreements with neighbouring utilities. The members of the Niagara Erie
Power Alliance (NEPA) maintain mutual-aid agreements to assist one another in the event
of larger outages or major storm damage.
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Electricity Distributors Association and MEARIE
W. The EDA itself is an example of an efficiency improving cooperative effort by Ontario distributors. Virtually all distributors in Ontario are members of the Association. Over the years
the EDA has provided a broad range of services, at significant cost savings to utilities. It has
represented utility interests at regulatory proceedings, led efforts to redress jurisdictional
issues all the way to the Supreme Court of Canada and facilitated information exchange and
training services. Associations of this type are common in various industries. They provide
for scale economies in a variety of informational, administrative and regulatory areas.
A significant accomplishment of the Association was the creation the Municipal Electric
Association Reciprocal Insurance Exchange (MEARIE), which provides coverage specifically
designed for electricity distributors at significant savings to member utilities.
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Appendix D: LDC Reliability Indicators
The reliability of electricity distribution provided by LDCs is monitored by the OEB. Reliability
performance is assessed using the following, industry-standard indicators:
• SAIDI: System Average Interruption Duration Index (SAIDI) measures the average number
of hours of interruption per customer, per year. It is calculated as Total Customer Hours of
Interruption/Total Number of Customers Served.
• SAIFI: System Average Interruption Frequency Index (SAIFI) is an indicator of the average
numbers of interruptions each customer experiences. It is calculated as Total Customer
Interruptions/Total Number of Customers Served.
• CAIDI: Customer Average Interruption Duration Index (CAIDI) is an indicator of the average
length of interruption. It is calculated as Total Customer Hours of Interruption/Total
Customer Interruptions.
LDCs scrutinize their performance on a monthly basis and report them annually to the OEB.37
Statistics are reported both on a gross basis and adjusted for “loss of supply”. The statistics
reported below are on a “gross basis”. The latter is intended to capture reliability of delivery as
opposed to reliability of supply. As a result of the vulnerability of distribution and transmission
systems to weather, most interruptions experienced by customers are due to events affecting
the delivery system. This is a common feature of electricity systems worldwide.
The OEB does not set province-wide targets for these indices. The reason is that reliability depends
on numerous local factors such as weather, climate and customer density. The OEB’s approach
has been to require that each distributor maintain reliability within the range of its historical
performance. The results are summarized below.
According to SAIDI statistics for the 2005-2010 period, customers of small and large utilities have
experienced approximately three hours of interruption per year. Medium sized utilities have had
an average interruption rate of two hours per year. Hydro One, with its many customers located
in rural areas, has had an average interruption rate of close to 16 hours for this period.
SAIDI
Small LDCs
Medium LDCs
Large LDCs
Hydro One
2005
2006
2007
2008
2009
2010
Average
3.3
2.4
2.6
14.5
3.9
2.0
4.3
28.5
3.7
2.0
2.6
11.4
3.7
1.7
3.6
21.6
2.6
2.0
2.6
10.0
2.9
1.5
1.9
9.4
3.3
1.9
2.9
15.9
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SAIFI statistics for the 2005-2010 period indicate a strikingly uniform rate for frequency of interruption.
Customers of small, medium and large utilities have experienced, on average, about two interruptions
per year. Hydro One customers experience about four per year.
SAIFI - Annual
Small LDCs
Medium LDCs
Large LDCs
Hydro One
2005
2006
2007
2008
2009
2010
Average
1.5
1.9
1.9
3.9
1.5
2.1
2.0
5.2
2.4
2.1
2.0
4.1
2.1
1.7
1.9
4.8
1.8
1.7
1.8
3.6
2.0
2.0
1.7
3.3
1.9
1.9
1.9
4.1
The average duration of interruption as measured by CAIDI is about one hour for large utilities and
closer to two hours for small and medium utilities. This may be in part because of the relatively
more rural nature of a number of small utilities. Hydro One figures are higher.
CAIDI - Annual
Small LDCs
Medium LDCs
Large LDCs
Hydro One
2005
2006
2007
2008
2009
2010
Average
2.7
4.8
1.0
3.7
2.0
1.1
1.3
5.5
1.7
1.0
1.1
2.8
2.2
1.2
1.2
4.5
2.2
1.1
1.2
2.8
1.7
0.9
1.0
2.9
2.1
1.7
1.1
3.7
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Appendix E: LDC Service Quality Indicators
In order to monitor quality of electricity distribution and to ensure that adequate customer service
levels are maintained, the OEB has put in place a service quality regulatory regime. LDCs are required
to meet specified minimum standards for each of the following Service-Quality Indicators:39
1. Low Voltage Connections. The percentage of new low voltage (<750 Volts) connection
requests completed within five working days once prerequisites (engineering, safety, etc.)
have been satisfied. Must be met 90 per cent of the time.
2. High Voltage Connections. The percentage of new high voltage (>=750 Volts) connection requests completed within 10 working days once prerequisites (engineering, safety, etc.) have
been satisfied. Must be met 90 per cent of the time.
3. Telephone Accessibility. The percentage of phone calls to the utility’s general inquiry number answered in person within 30 seconds. Must be met 65 per cent of the time.
4. Appointments Met. The percentage of customer appointments (date and time) involving
a visit to customer premises met. Must be met 90 per cent of the time.
5. Written Response to Enquiries. The percentage of customer inquiries relating to a
customer’s account and requiring a written response where the response is provided
within 10 working days of receipt of the inquiry. Must be met 80 per cent of the time.
6. Emergency Urban Response. The percentage of emergency calls where a qualified service
person is on site within 60 minutes of the call (for urban calls). Must be met 80 per cent of
the time.
7. Emergency Rural Response. The percentage of emergency (fire, police, etc.) trouble calls
where a qualified service person is on site within 120 minutes of the call (rural calls). Must
be met 80 per cent of the time.
8. Appointment Scheduling. The percentage of customer appointment requests that take
place within five business days. Must be met 90 per cent of the time.
9. Rescheduling a Missed Appointment. The percentage of missed appointments where the
customer is contacted within one business day to reschedule the appointment. Must be
met 100 per cent of the time.
A review of Ontario Energy Board “Yearbooks”40 confirms that all Ontario distributors – small,
medium and large – have been consistently meeting these standards over the period for which
data are available.
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Appendix F: LDC Cost Performance Indicators
For purposes of evaluating the distributor costs, a consultant on behalf of the OEB has carried out
two benchmarking evaluations − an econometric benchmarking methodology and unit-cost index
benchmarking.41 Based on the results of these analyses, the OEB assigns distributors to one of three
efficiency groupings. We note that the approaches that are used have important limitations. For
example, the analyses rely on OM&A costs rather than total costs.
The distributors that achieve a superior rank in both the evaluations are assigned to Group 1, which
according to the OEB represents the most efficient group. Those distributors that rank relatively
poorly in both are assigned to Group 3. All other distributors, including those that rank superior or
inferior in only one of the evaluations, are included in the broad middle cohort, Group 2. Productivity targets are then set based on the group to which a utility has been assigned. The table below
summarizes the allocation to groups of small, medium and large utilities.
OEB Assessment of LDC Cost Performance
LDCs by size
SMALL
MEDIUM
LARGE
2012
Group 1
2011
21%
11%
11%
18%
11%
11%
2010
Average
No. of LDCs
14%
15%
11%
17%
12%
11%
7 out of 39
3 out of 27
1 out of 9
59%
85%
78%
70%
78%
89%
62%
83%
82%
24 out of 39
23 out of 27
7 out of 9
23%
4%
11%
16%
7%
20%
5%
11%
8 out of 39
1 out of 27
1 out of 9
Group 2
SMALL
MEDIUM
LARGE
58%
85%
78%
Group 3
SMALL
MEDIUM
LARGE
21%
4%
11%
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Appendix G: Efficiency Opportunity Fact Sheets
1.Regulatory Constraints on Scope
ISSUE: Regulatory Constraints to Expand LDC Scope
Currently, Sections 71 and 73 of the OEB Act restrict LDC and LDC affiliate operations to a few specific activities. This has led to the inability of LDCs to expand the scope of their businesses to maximize efficiencies by providing additional business services such as water and waste-water management services both inside and outside their service territory, street lighting, electric vehicle charging
infrastructure etc. These benefits from expanded scope, including cost and resource sharing amongst
several lines of related businesses such as customer and billing services, fleets and other equipment, and short- and long-term planning of infrastructure construction and maintenance, are not
being taken advantage of by Ontario’s LDCs due to barriers in the present regulatory framework.
The current framework restricts LDCs from pursuing options with their local municipalities to
expand their economies of scope at the discretion of the local municipalities to become more
efficient and provide benefits to both their customers and their shareholders.
SOLUTIONS
1) Legislative change to Section 71 of the OEB Act to allow LDCs to carry out a wider range of
activities as part of their core business. A precedent has been set under the Green Energy
Act given that DG is now a permitted activity for LDCs, while previously it was not permitted.
Section 71 (3) Exceptions should be amended by adding another exception for additional
activities defined by regulation, and regulations should be made to allow street lighting
maintenance, on-bill financing and electric vehicle recharging as permitted activities.
2) Allow more flexibility under the OEB’s Affiliate Relationships Code (ARC) especially around
separation of financial and accounting systems, limitations around sharing equipment,
resources and customer information to give LDCs the opportunity to conduct a wider range
of activities under the affiliate’s operations. For many medium and small LDCs, there is no
competition within their jurisdictions for activities such as street lighting for the ARC to apply.
3) Regulatory change to O. Reg 161/99 Section 5(2) to allow LDCs the ability to expand scope
so that they are able to bid for services outside their service territory e.g. for billing and
managing or operating water or waste-water services.
The EDA’s Sector Review Paper “Electricity is the Answer” calls for LDCs to be allowed to expand
their scope of operations that may lead to reduced overall costs for customers, provided regulations
are amended/established to allow LDCs those opportunities.
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EXAMPLES
Utilities Kingston in Eastern Ontario has been providing electricity, gas, fibre optics and water and
waste-water services for the municipality since 2000 under one affiliated company. The company
has reaped the benefits of sharing overhead costs, equipment, metering/billing services etc. which
in turn has benefitted local residents. The following information on cost savings has been provided
by the utility:
• Savings of over $250,000/year from sharing billing services
• Savings of over $440,000/year from sharing of executive roles across the different
companies
• Savings of $240,000/year from sharing operations such as locates for underground
structures, fleet operations etc
• Savings of over $1-million annually on average from doing joint construction projects
Consolidated customer services and conservation measures benefit customers as well.
CUSTOMER IMPACT
Prior to industry restructuring, many LDCs operated under public utilities commissions (PUCs) and
provided multiple services under one roof. These PUCs, on average, exhibited lower costs which
were beneficial to customers.
Increased savings could be achieved by expanding scope through the LDC, but barriers exist due to
regulatory constraints and regulatory risk.
Conducting scope activities within the LDC could maximize sharing of corporate service and reduce
governance costs.
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2.Water and Waste-Water Services
ISSUE: Water and Waste-water Services
There are restrictions on the LDCs’ ability to expand their current economies of scope to include
playing a greater role in the water and waste-water utility service.
Currently, LDCs are limited to operating/managing and providing billing services for water
utilities which are part of their municipal corporation (Section 5 (2) of Ontario Regulation 161/99).
A broader scope of water-service activities are permitted by an LDC affiliate, but not within the LDC.
Additionally, according to the OEB Accounting Procedures Handbook, LDCs providing services to
the water utility owned by their municipality are required to offset any revenues earned from their
distribution revenues. This creates a disincentive effect for LDCs to take on this increased responsibility.
SOLUTIONS
A regulatory change to section 5 of O. Reg 161/99 could permit LDCs the ability to expand their
scope outside their municipal jurisdiction in operating/managing or providing billing services for a
water utility. Amendments to the OEB Accounting Procedures Handbook to remove the requirement
for an LDC to offset any and all revenues associated with the water management services against
the distribution rates would also be required to provide incentive to both a municipal shareholder
and LDC to implement this efficiency. Rather than using all revenues to offset rates, sharing of
revenues between shareholders and ratepayers should be allowed.
EXAMPLES
Essex Powerlines combines the electricity bill with water and sewer, providing considerable savings
to the electricity customer due to shared costs for staffing (billing, collecting, and call centre), forms,
postage and contracted services. Savings are estimated to be significant at $578,000 per year.
Innisfil Hydro will be commencing water and sewer billing for the Town of Innisfil in August of 2012.
The Town, after assessing options to continue billing water and sewer services three times a year
on their own or to have the LDC bill for the same on a monthly basis, concluded that having the
LDC provide multi-utility billing would save the town’s consumers 10 per cent of current costs. This
endeavour is a win-win-win for Innisfil Hydro, the Town of Innisfil and most importantly, for Innisfil’s
population.
Prior to industry restructuring, a number of distributors operated within PUCs which provided more
than one service such as electricity and water. Such commissions exhibited, on average, materially
lower costs.
CUSTOMER IMPACT
Customers benefit from lower costs and receiving multi-utility services from one source and the
sharing of revenues from water services. It is estimated that LDCs performing water and wastewater services could produce up to $180-million in savings to electricity customers based on
seven per cent savings on total distribution costs for all LDCs annually.
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3.Regulatory Streamlining
ISSUE: Regulatory Streamlining
Prior to industry restructuring‚ a typical rate submission by a local distributor to Ontario Hydro was
perhaps 10 pages. Today, rate applications to the OEB are commonly over 1,000 pages, with many
applications over 2,000 pages. The Ontario Auditor General’s 2011 Annual Report states that the
average cost for a small utility to complete its Cost-of-Service (COS) Application is approximately
$100,000 and about $250,000 for a medium-sized utility. It can cost a large utility close to $1-million
to file its COS application. Ontario’s Auditor General reports that these costs account for between
15 to 55 per cent of the increase in revenue that the LDC is seeking approval for from the OEB and
the impact of the cost on the customer can range from $1 per customer (large LDCs) to $40 per
customer (for small LDCs). While all regulatory systems impose some level of cost on the regulated
industries, the question is whether the current framework and regulatory processes are providing
good value to electricity consumers in Ontario.
Early in the restructuring, the OEB recognized the value of reducing the need for annual rate
applications by introducing an Incentive Regulation Mechanism (IRM). The IRM allows LDCs to
apply for simplified rate approvals for the period of a few years. The concept was to provide ‘lighthanded’ regulation and allow utility management operating within a relatively stable environment
the freedom to manage the business and achieve and share the benefits of any productivity gains
achieved. However, IRM systems are not designed to function in an environment where costs are
changing rapidly and where utilities are frequently subject to new industry policy-imposed mandates.
The IRM process assumes distributors will experience increased productivity and steady inflation.
Instead distributors have been challenged in meeting new requirements that take the focus away
from increasing productivity. Distributors have also experienced higher industry sector inflation.
At the end of an IRM term, distributors are required to file COS applications which review all distribution present and future costs. These applications are extensive, but more work under tight timelines is
required to respond to questions from intervenors who often make requests for much more information
than was filed. The information requests are also often duplicative and onerous.
Staff and consultant resources needed to meet regulatory filing requirements take away staff
resources from other important activities. Distributors have been raising concerns that the efforts
associated with obtaining regulatory approval are too onerous and costly. In response, over the
past several months the OEB has been consulting with stakeholders and considering proposals for a
renewed regulatory framework. The EDA has been advocating proposals for streamlining regulation
during this consultation.
SOLUTIONS
The EDA recommends the following guidelines to streamline regulation in the sector:
• There is a need to balance costs of regulation with the benefits to customers.
• The amount of regulation and reporting requirements should be proportionate to the
policy objective/outcome.
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• More emphasis should be placed on policy outcomes, not process.
• Duplication and overlap of reporting requirements should be eliminated.
• Administrative expenses to LDCs should be minimized, streamlined.
• Distributors should be provided flexibility to address their local circumstances.
• Distributors should not be involved in addressing social problems.
• Distributors should be allowed to recover their costs to address aging infrastructure
in a timely manner.
• Increased certainty and transparency should be provided for cost recovery by distributors.
• Decision-making by regulators needs to be timely.
The EDA established the following specific recommendations for streamlined regulation in its policy
position paper “The Case for Reform” published in July 2011:
Revising the Regulatory Application Process:
• Develop standardized templates to streamline application process,
• Create metrics to limit review of application,
• Incorporate multi-year capital reviews within the regulatory cycle - reform the capital module for incorporating capital investments made during IRM period, and
• Ensure that productivity and inflation factors reflect industry circumstances.
Revising the intervenor process:
• Permit OEB to lead and pre-screen interrogatories to avoid duplication,
• Require intervenors to demonstrate representative constituency,
• Review cost awards and eligibility for cost awards,
• OEB to work with the regulated entities to address the concerns about the cost and complexity
of the current rate-setting filing requirements and the impact of their operations, and
• OEB better co-ordinate and evaluate intervenor participation in the rate-setting process in
an effort to reduce duplication and time spent on lower-priority issues.CUSTOMER IMPACT
CUSTOMER IMPACT
Streamlining the regulatory process will lower regulatory costs both for the distributor and the
regulator which will provide benefits to customers. Distributors will also free up resources to
better focus on improving operations and customer services. In 2010 it was estimated that the rate
application process and compliance with regulatory processes cost $45-million up from approximately
$29-million in 2008. Assuming a 33 per cent savings in regulatory costs, electricity customers could
save up to $15-million annually.
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4.Street lighting
ISSUE: Allow LDCs to conduct street lighting maintenance
LDCs are seeking a regulatory or legislative change to the OEB Act to provide more clarity on the
permitted activities of an electricity distribution company to specifically include the ability of an LDC
to conduct street lighting services for their local municipality, if the municipality chooses to retain
these services.
In 2007, the province committed to making a regulatory change to address S. 71 of the OEB Act
with respect to allowing LDCs to conduct street lighting maintenance. However, this change has
not been forthcoming and as a result there is an ongoing lack of clarity on the long-term direction
creating increasing problems for LDCs, for regulators and other oversight agencies.
LDCs are not requesting an exclusive right to perform street light maintenance services. They ask
that municipalities be allowed to choose an LDC provider without the LDC having to incur additional
administrative expense to establish a separate affiliate, which provides no value to customers.
LDC affiliated companies require establishing a separate legal company, separate accounts
and separate Board governance for no other reason than the restriction in S. 71 to be able to
provide service to the shareholder should the municipality choose to use the LDC for street
light maintenance services.
Street lighting maintenance was originally considered a competitive activity which should not
be provided directly by distributors to avoid any perceptions of cross subsidies to their street light
maintenance activities. Street lighting maintenance activities could be carried out and treated as a
separate activity with a separate account for the distributors that provide this service, much as is
allowed for distributed generation owned by distributors under the Green Energy Act.
Private contractors will continue to provide street lighting services to certain municipalities but
qualified private contractors are not available in all areas of the province and many LDCs have communities that are under-serviced by qualified private contractors. These distributors are unnecessarily
incurring additional costs in order to provide these essential services to their communities.
SOLUTIONS
The Green Energy Act has established a precedent by allowing LDCs to engage in competitive businesses within the LDC, not through an affiliated company. The Act permits LDCs to own and operate
renewable energy generation facilities that do not exceed 10 MW through Exception 3 of S. 71 of
the OEB Act.
This clarity and precedent should be extended in S. 71 to resolve the lack of clarity regarding street
lighting maintenance services. A regulatory or legislative change should be made that allows for
street light maintenance services within the defined service territory of the LDC to be permitted
as an LDC activity.
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CUSTOMER IMPACT
Estimated cost savings of allowing LDCs to incorporate street light maintenance services back into
their LDCs has the potential to save approximately $15-million, assuming streetlight services return
from affiliates to inside the LDC. This figure is the approximate savings incurred from eliminating the
duplication of accounts, governance, and administrative overlap that it takes to run an LDC affiliate
street light service provider. In addition, permitting LDCs to own street lighting assets could produce
savings through more efficient use of capital assets between the municipality and the LDC.
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5.Electric Vehicle Infrastructure
ISSUE: Electric Vehicle Infrastructure
Given Ontario’s generation mix, especially with the phase-out of coal plants, migrating to electric
vehicles in the transportation sector is seen as producing economic and environmental benefits in
the long term.
Electric vehicles will create new challenges for distributors. Distributors will need to encourage
customers to charge their electric vehicles during off-peak periods when the TOU price is lower and
the power system is under less stress. Charging during peak hours could have a significant impact
on the grid, but the grid may be less affected if the charging stations are “smart” and can be controlled by the distributor. Even if charging is carried out during off-peak periods, there may be local
system constraints and distribution system impacts where there is a higher penetration of electric
vehicles. This will require the distributor to control the charging and stagger the loads. Distributors
would also need to know where quick-charge installations are located, which cause significantly
higher peak demands, and ensure these are smart chargers controlled via the smart grid. The smartgrid deployment needs to plan and consider the potential impact from electric vehicle charging.
Recently some distributors purchased electric vehicles to gain some real-world experience with
their operating characteristics and their impact on the distribution system. These initiatives were
not supported by the regulator as it was not perceived to be within the mandate or role of the distributor, therefore costs were not approved. Distributors believe they should be taking a leadership
role in understanding the impacts of electric vehicles on the grid, understanding their operating and
charging characteristics, and facilitating their integration onto the grid through controlled charging
stations. These charging loads could have a significant impact and decisions being made today on
standards and technologies will have far-reaching implications.
SOLUTIONS
Section 71 of the Ontario Energy Board Act outlines the activities that an electricity distributor and/
or a distributor affiliate can provide. At present, electric distributors are not permitted to engage
in providing electric vehicle charging stations as a service within their legal structure and therefore
must have an affiliate company in order to provide such services. Therefore Section 71 needs to be
amended to permit the provision of electric vehicle recharging stations within the LDC, just as distributed generation ownership was subsequently permitted through an amendment to Section 71.
The integration of electric vehicles loads onto the electricity system should be seen as an integral
part of planning for future distribution system needs. Distributors need to put in place policies,
standards, and technologies to minimize the negative impacts on the grid system and encourage
electric vehicle owners to take advantage of the available off-peak generation.
Distributors should be encouraged by the regulator to gain experience with electric vehicle charging
by owning and operating charging stations and installing charging stations on customer premises. As
the number of electric vehicles increases and new smart-grid technologies are developed to control
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the charging, distributors should be encouraged to co-operate and share information, and work in
partnership with others to ensure charging stations are smart metered and connected to the smart
grid to allow remote control.
All this would be facilitated if it was made clear that distributors can own and operate electric
vehicle charging stations.
EXAMPLES
As noted previously, some distributors have taken the initiative to gain some real-world experience
with the charging and operating characteristics of electric vehicles and their potential impact on the
distribution system but the costs have been rejected by the regulator.
One distributor, working with an automotive manufacturer, has already demonstrated a project
where new technology will allow a fully or partially charged battery in an electric vehicle to provide
power to a home. This will allow customers to load shift by storing energy in the battery at off-peak
periods and supplying the stored energy back to the home during on-peak periods. The vehicle can
also function as an emergency back-up supply to the home.
CUSTOMER IMPACT
Distributors are essential partners in the adoption and promotion of electric vehicles. All customers
will benefit from increasing the off-peak load and using off-peak surplus capacity, thus avoiding the
costs of exporting power at a loss. Facilitating off-peak charging will also give electric vehicle owners
the confidence that their environmental impact is minimized and that their vehicle can be emissionfree due to using a power source that does not emit CO2. As electric vehicle technology improves
and oil prices continue to rise, electric vehicles will become more cost competitive and gain wider
consumer acceptance.
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6.Conservation and Demand Management
ISSUE: Conservation and Demand Management (CDM)
Systemic flaws with the current 2011-14 CDM policy framework will result in undesired outcomes
for the Ontario Government and LDCs.
LDCs will have difficulty achieving their mandated targets due to lack of effective programs for all
consumers, slow rollout (if at all) of provincially mandated OPA (Tier 1) programs and lack of Tier
2 and/or 3 programs (collaborative and unique LDC programs). This has been identified by Ontario’s
Environmental Commissioner as a risk in his annual report. As a result, Government’s overall
conservation targets may not be achieved.
There is a lack of innovation because of strict restrictions on Tier 2 and/or 3 program approvals
from the OEB. There is also a lack of long-term commitment to any CDM framework by government
which hinders the creation of a culture of conservation in Ontario by preventing the LDCs from
delivering ongoing programs and achieving persistent savings and from developing the internal
capacity to meet evolving customer needs.
SOLUTIONS
There should be a move towards a “business approach” which will allow LDCs to incur the financial
risk and rewards in designing and delivering CDM programs at the local level to meet local circumstances. This means devolving the responsibility for program design and delivery, target setting, and
funding to the LDCs from the OPA. In exchange for the increased risk there would be commensurate
incentives for the electricity savings achieved and verified by a third party, potentially the government
or central agency.
LDCs’ commitment to CDM should be in line with the timelines reflected in the province’s Long
Term Energy Plan (TEP) (2030). The government needs to affirm that the LDCs will be responsible
for CDM as part of the LTEP until 2030.
Regulatory oversight would only need to focus on ensuring proper separate accounting for CDM
design and delivery activities, and not on the prudency of CDM programs given that distributors
would have strong incentives to ensure programs achieve cost effective results.
EXAMPLES
There are several examples of successful LDC designed CDM programs, including:
• peaksaver PLUS – Toronto Hydro initiated program that is now in place province-wide
• Great Refrigerator Round-Up – GTA LDCs-led initiative that has been incorporated into a
Tier 1 program
• Demand Response – Based on Greater Sudbury Hydro’s “Shed a Kilowatt” third tranche
program
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A precedent has been made for separated activities within the distributor. Distributors are permitted
under the Green Energy Act to own and operate renewable energy generation facilities under 10 MW,
as a separate activity within the distributor, with separate accounting.
CUSTOMER IMPACT
The consumer experience with this current framework has been one of frustration and resignation.
The OPA’s focus in designing and developing CDM Programs has been more electricity systemcentric and not customer-centric. The OPA has tailored the programs to address electricity systems
needs and not tailoring programs to meet the needs of LDC consumers. As a result of this lack of
focus, application processes are onerous and cumbersome in nature, application approvals and
payments are delayed on a regular basis, and improvements in the programs through change
management are slow to come by. As a result of these issues, many customers are unwilling to
participate in CDM Programs and many LDCs have expressed concern over low consumer take-up.
In fact, some LDCs have shared that due to the frustrations with the application process there have
been instances where customers have given up on the application part-way through the process.
The above is an example of how the current CDM framework makes ineffective use of ratepayer
funds. Less than one-third of Tier 1 CDM programs currently in the market are producing significant
savings. Funding is being spent by the OPA on CDM programs regardless of a program’s ability to
deliver actual energy savings. Permitting LDCs to lead conservation and use a results-focused
approach will result in more cost-effective CDM that will produce more savings for less cost,
estimated at $20-million annually.
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7.On-bill Financing
ISSUE: On-bill Financing
There are restrictions on LDCs’ ability to expand their current economies of scope to include playing
a greater role in promoting and facilitating CDM programs by directly assisting customers with their
financing. Currently, LDCs are provided OPA-developed CDM programs. They are not provided with
an incentive to financially assist customer participation in CDM programs requiring upfront capital
investments. Customers seeking to make a long-term capital investment in order to reduce consumption
as part of a CDM program sponsored by the local distributor may have difficulty in convincing a loan
institution to provide financial assistance. If permitted by changing regulations, LDCs will have the
opportunity to improve the take-up of certain CDM programs, and directly benefit local customers
seeking to benefit from reducing their consumption.
SOLUTIONS
S. 71 of the OEB Act would need to be amended to permit LDCs to engage in providing financial
services to its customers seeking financial assistance to participate in a CDM program requiring
capital investments.
EXAMPLES
In practice, a local utility could have a program to offer financial assistance to customers seeking
to invest in a conservation project. The customer repays the loan by continuing to pay the average
monthly bill, plus an additional agreed-upon amount covering interest and principle repayment.
The program would remove a significant barrier to participation in certain CDM projects.
This program would be beneficial to customers seeking to upgrade a heating system, insulate
walls, install new lighting or undertake some other efficiency measure, but require a loan from the
distributor who then recoups the cost gradually over time in the customer’s monthly energy bill. This
approach spares the customer from trying to convince a financial institution about the expected benefits from the CDM project and also gives the customer the opportunity to reduce energy use, which
lowers electricity charges and offsets at least some of the monthly cost of the efficiency installation.
Some current CDM projects provide a significant direct financial subsidy encourage customers to
participate, raising overall costs for the project. On-bill financing could be used to reduce the need
for significant upfront subsidies thus lowering the cost to other customers. These solutions are
provided in many U.S. electric utilities.
CUSTOMER IMPACT
With the LDC offering financial services, a customer can access funds and repayment options through
its utility where it already has a trusted, long-standing relationship with a business that has strong and
deep roots in the local community to foster greater participation in conservation programs requiring
capital investments. The on-bill option will increase the take-up of various CDM programs and improve their effectiveness which will help more customers to lower their bills. The technical capability
to provide on-bill financing already exists with many LDC Customer Information Systems.
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8. Electricity Retailers
ISSUE: Electricity Retailers
Electricity retailers were allowed to enter the electricity system to offer customers the benefits of
competition and choice during the period of market deregulation which occurred in the industry at
the beginning of the previous decade. Although the formation of an open market was eventually
abandoned and regulated electricity rates continued, electricity retailers for residential customers
remain as outliers in the current system whose continued presence impacts the entire rate base.
The electricity retailer concept, legislated in Part V.1 of the OEB Act, provided that in a competitive
market retailers would be allowed to service consumers by allowing them to pay higher electricity
rates in exchange for price stability and predictability that a fixed contract provides. Retailers would
also offer services with a retail contract, such as energy-saving programs, energy audits, equipment
maintenance or the option to have a portion of the rate support renewable energy projects.
After the end of the open market concept, the developed an electricity price plan that provided
stable and predictable electricity pricing and ensured the price consumers pay for electricity better
reflected the price paid to generators. The OEB’s Regulated Price Plan (RPP) efficiencies removed
the value of electricity retailers in Ontario by addressing the consumer’s need for predictable
electricity rates. The OEB reviews the RPP twice a year to better reflect the true cost to produce
electricity while at the same time providing stable rates for customers.
Despite the impact the RPP has had on the purpose for electricity retailers, legislative attention
to these entities has focused more on their practices in recent years. The Electricity Consumer
Protection Act (ECPA) was passed in 2010 as a response to electricity retailers whose business
practices were increasingly viewed by the public as questionable. The new rules in the ECPA
addressed the most common complaints that the OEB received related to retailers, specifically
providing customers copies of their contracts, improper procedures for reaffirmation calls, and
poor business practices around renewals.
As a result of the ECPA, the OEB has expanded its regulatory oversight of electricity retailers. The
costs associated with an expanding OEB affects the entire rate base. Increasing the regulatory costs
of the OEB for entities whose customers remain a fraction of the Province’s total rate base is an
inefficient use of the regulator’s resources.
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SOLUTIONS
With an RPP structure that provides stability and predictability in price and electricity retailers
whose presence is a net cost to the regulatory system as a whole, the Provincial government should
phase out electricity retailer entities by doing the following:
• Disallow Further Electricity Retailer Contracts for residential customers
• Revisit the legislative and regulatory stipulations that allow for electricity retailers
in Ontario, specifically Part V.1 of the OEB Act.
• Phase out existing contracts with residential customers by allowing them to expire
• All standing contracts held between customers and electricity retailers should be
allowed to expire. The retailer will not be allowed to seek renewals with customers
and the contracts will be void on the expiry date. The Minister should use his powers
as outlined in Section 1.2 of the ECPA to educate and advise consumers of the
impending change.
• Electricity Retailing should only continue in circumstances where the value proposition can
be clearly demonstrated for institutional, industrial, and commercial customers.
Non-residential customers are better suited to make the complex business decisions associated
with contracted electricity rates. Large businesses and power consumers may find value in a retailer
arrangement, but such retailers should remain under the authority of the OEB and should
demonstrate their value proposition to the regulator.
CUSTOMER IMPACT
Phasing out the role of electricity retailers for residential customers will save the electricity system
upwards of $260-million annually.
These significant cost savings are a result of reduced regulatory oversight and costs for enforcement
for non-compliant retailers, collections on defaults, reduced distribution costs, reduced customer
complaints and better price signals and demand response as all formerly retailer contracted
residential customers will be on TOU rates.
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Appendix H: Innovation from the Ground Up
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Chair’s Message
In the early 1940s, local electricity utilities in Ontario first introduced the
notion of energy conservation to their customers. It was a time when our
nation was at war and needed to conserve as much of its resources as
possible. When the need for conservation again raised its head forty
years later, these same local electricity utilities took the lead to help their
customers use electricity wisely. And, before the Government of Ontario,
through the Ontario Power Authority (OPA), took over the role of
designing, managing and funding what we now know as conservation and
demand management programs (CDM) midway through the first decade of this century, local
distribution companies (LDCs) had already been working together to develop and manage their
own CDM programs.
Indeed many of the first programs introduced by the OPA in 2006 were first developed, tested,
refined and successfully managed by LDCs. It is a prime example of how LDC program ownership
fosters innovation and how good ideas spread throughout the province. What Ontario’s LDCs
recognized then, as now, is that different communities have different needs, especially when it
concerns electricity demand and conservation. Sometimes, far different.
An obvious example is how drastically electricity use patterns vary in a large, geographically
diverse province such as Ontario. In the south, peak electricity demand is reached in the
summer, with air conditioning ubiquitous in homes and office buildings. In the north, extensive
use of electricity to heat homes over long winters, along with limited use of air conditioning
during the shorter summers means winter peaks are more typical. A summer suite of
conservation programs cannot address the needs of the northern communities. Solutions that
are developed, delivered and managed locally take these obvious differences and the more
nuanced needs into account. Local authority over conservation programs will ensure they are
designed to meet customer and community needs today and into the future as these needs
evolve.
The current CDM framework is set until 2014 – but the EDA and its members strongly believe
that the system should and can change before then. The issues, solutions and potential
outcomes outlined in this report, Innovation from the Ground Up – Locally Driven Conservation,
provide a clear-cut case as to why distributors need to resume control of CDM by incorporating
it into their business from design through delivery.
Since 2006, centrally designed conservation programs have yielded results. LDCs have built
conservation expertise and capacity within their organizations, and a robust conservation supply
chain has been re-established in the province. Many Ontarians have participated in conservation
programs such as the refrigerator pick up program, and arguably much of the low hanging fruit
in terms of conservation results has been harvested.
For Ontario to get at the next level of meaningful savings, we need to create programs tailored
to the specific needs of specific communities. The time has come to return CDM leadership to
LDCs to unleash innovation at the local level and build on Ontario’s conservation success.
Max Cananzi, EDA Chair
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Contents
CDM in Ontario: recent history and current challenges .............................................................. 1
Challenges and outcomes of the 2011-2014 CDM framework ............................................. 1
The future of CDM ............................................................................................................... 3
Guiding principles ....................................................................................................................... 4
Spectrum of CDM framework models......................................................................................... 7
The business approach ............................................................................................................... 9
Benefits of a business approach ........................................................................................ 11
Transition plan .......................................................................................................................... 13
Piloting the business approach .......................................................................................... 13
Attitudinal changes ............................................................................................................ 14
Other practical changes ..................................................................................................... 15
Conclusions .............................................................................................................................. 17
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CDM in Ontario: recent history and current challenges
Local Distribution Companies (LDCs) in Ontario have offered conservation
and demand management (CDM) programs since the mid-1980s. Since
2004, provincial regulatory frameworks have cast LDCs as the central
delivery agents for CDM programs. Three different regulatory frameworks
have governed CDM between 2005 and 2011, and have created different
risks, roles, responsibilities and rewards for LDCs. The transitions between
these frameworks have not been smooth. Furthermore, the frameworks
have progressively increased LDCs’ regulatory requirements and
responsibility for outcomes, without increasing LDCs’ rewards or level of
control over outcomes.
Under the “third tranche” (2005-2007), LDCs designed and delivered
custom CDM programs within their service territories. The 2006 Supply Mix
Directive to the Ontario Power Authority (OPA) was accompanied by a new
CDM framework that featured centralized program design. Under the 20072010 framework, LDCs contracted with the OPA to deliver standard
programs designed by the OPA. LDCs also applied to the Ontario Energy
Board (OEB) for funding of service-territory-specific programs.
Most recently, the Green Energy and Green Economy Act (GEA) 2009
transformed the CDM landscape in Ontario. LDCs are now working to
achieve electricity and peak demand savings targets by 2014 using only
province-wide OPA programs. Though Board-approved programs (also
known as Tier II and III programs) are theoretically possible, as of February
2012, all applications for these programs have been rejected.
Under the 2011-2014 CDM framework, the achievement of electricity and
peak demand targets is a condition of licence for LDCs. Regulatory
requirements surrounding CDM plans, programs, budgets, marketing,
incentives and reporting are specified by the GEA and accompanying
Directives, CDM Code, Targets, Agreements and Program Schedules.
Challenges and outcomes of the 2011-2014 CDM framework
The GEA has created new opportunities for LDCs in CDM, renewable
energy, and smart grid development. However, it has also generated
significant challenges for LDCs. Some of the challenges vary based on the
size, capacity, location, and past experience of individual LDCs. Other
challenges are tied to the transition between frameworks. For example,
delays in launching province-wide programs have jeopardized LDCs’ ability
to meet targets by 2014.
However, there are deeper problems associated with the balance of risks
and rewards within the 2011-2014 CDM framework. LDCs have little control
over outcomes. Though LDCs were involved in program design working
groups, the Ontario Power Authority largely controlled the program design
process; LDCs report that their influence was severely limited. The OPA also
ELECTRICITY
DISTRIBUTORS
ASSOCIATION
1
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controlled many aspects of program delivery, with the goal – but not the
result – of increasing efficiency through centralization. At the same time,
LDCs have primary responsibility for achieving electricity and peak demand
savings, and are at risk of not being in compliance with their licenses if they
do not meet their targets. Finally, LDCs are required to submit strategies,
approval requests, and reports to two separate organizations (the OPA and
the OEB).
LDCs report the following disconcerting outcomes under the current CDM
framework:
CDM programs are not designed to best meet customer needs, but
instead focus on electricity system needs.
LDCs have very limited opportunities for innovation or
improvements in program design, or for unique programs that
target specific markets.
Program delivery processes and tools create bureaucratic barriers
to program participation.
Extensive regulatory approvals and reporting requirements do not
make effective use of provincial and LDC resources.
LDCs are required to meet targets over which they had little say,
that do not specifically address opportunities within their service
territory, and for which there is not a traceable path from the
provincial potential studies that supported them.
Even if LDCs had greater control over CDM program design and delivery,
current incentive structures would not motivate or reward cost-effective
CDM results; LDCs will not receive incentives until 2015, and the incentives
for results are not sufficient to capture the attention of senior
management. The incentive for cost effectiveness creates a disincentive for
exceeding targets.
Finally, the uncertainty inherent in the CDM system limits LDCs’ ability to
invest time and resources in effective CDM. The current framework dictates
that all programs must end December 31, 2014. However, developing good
CDM programs is a lengthy process. The stop/start approach to programs
means that LDCs do not have time to undertake new program design after
2012, meaning ideas for new programs will either be lost or put on hold
until after 2014. The stop/start approach also creates problems for
customers seeking to participate in programs. Furthermore, LDCs are not
confident hiring CDM staff and increasing their internal capacity given that
they have no guaranteed role in CDM post-2014.
2
ELECTRICITY
DISTRIBUTORS
ASSOCIATION
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The future of CDM
As discussed, the 2011-2014 framework has an inappropriate balance of
risks, responsibilities and rewards. In order to improve CDM outcomes for
customers, for LDCs, and for the province of Ontario, the Electricity
Distributors Association (EDA) Board and Policy Committee are in favour of
increasing LDCs’ responsibilities. This will lead to increased risks for the
LDCs, and LDCs expect rewards commensurate with this increase in
responsibility and risk.
This report presents the guiding principles that underpin this decision. It
describes the type of “business-oriented” framework that would achieve
this balance, and the benefits of this framework for customers, for LDCs,
and for Ontario. Finally, the report suggests steps to transition towards a
business-oriented framework. Though details remain to be worked out, the
high-level approach outlined in this paper can help the EDA move forward
on a better CDM framework for LDCs and Ontario.
ELECTRICITY
DISTRIBUTORS
ASSOCIATION
3
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Guiding principles
The EDA’s decisions regarding the future of CDM are based on a set of
guiding principles. These principles were established through workshops
and discussions involving the EDA’s CDM Caucus, CDM Policy Committee,
and Board from November 2011 to February 2012. The guiding principles
build on the EDA’s 2008 position paper entitled “LDC CDM Activities and
Funding Going Forward.” 1 The following principles also underpin the EDA’s
desired business approach to CDM, presented in the next section, The
business approach. If these principles guide the design of the CDM
framework, then CDM will become a core business activity for LDCs, to the
benefit of all Ontario energy sector stakeholders. 2
1) The CDM framework should be designed to achieve the maximum costeffective CDM, over long time periods. As long as the electricity savings
realized through CDM programs cost the province less than procuring that
electricity from other sources, CDM benefits customers and the province.
Pursuing maximum cost-effective CDM will ultimately reduce electricity
bills for consumers. This must be clearly understood by all stakeholders. In
achieving maximum cost-effective CDM, the framework will also advance
provincial policy objectives related to energy security, environmental
sustainability and economic competitiveness.
2) The framework should enable innovation, improvement and learning in
program design and delivery. This is required to achieve the maximum costeffective CDM, and is particularly important when considering the longterm need for CDM to evolve alongside technologies and markets.
3) The framework should promote the development of local capacity to
design and deliver CDM in Ontario. Again, this is required to achieve the
maximum cost-effective CDM, and is particularly important when
considering long-term CDM activities and outcomes.
4) The CDM framework should establish the role of LDCs in CDM over a
longer time period (e.g. through 2030, consistent with the Long Term
Energy Plan and Integrated Power System Plan (IPSP)). LDCs are uniquely
positioned to design and deliver CDM within their service territories.
However, for LDCs to effectively undertake CDM, it must make sense to do
so from a regulatory and business perspective. By establishing the role of
LDCs in CDM over a longer time period, LDCs will be more inclined to make
CDM a core activity, to use CDM to enhance their corporate reputation, and
to convey the importance of CDM to shareholders.3
1
Electricity Distributors Association. 2008. LDC CDM Activities and Funding Going Forward.
2
This supports the EDA 2008 guiding principle: CDM should be a long-term LDC activity with returns that
are independent of the distribution business.
3
This supports the EDA 2008 guiding principle: LDCs should have secure, predictable long-term funding for
CDM. LDCs should develop multi-year programs with multi-year budgets.
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5) The regulatory processes associated with CDM should balance scrutiny
with simplicity. 4 Regulatory requirements (e.g. reporting, applications,
approvals) should be streamlined as much as possible to maximize CDM
and alleviate unnecessary bureaucratic burdens, while protecting the
interests of ratepayers and the province. This will also contribute to
achieving maximum cost-effective CDM.
6) LDCs’ CDM activities should be customer -centric. Currently, CDM
programs are perceived as engineering-based solutions, aimed to solve
electricity system peak issues. Ontario needs customer-centric programs
that help residential and small business customers save energy and reduce
bills. This should include customer education, address customer
perceptions of the relationship between CDM and rates, and ultimately
help customers use electricity wisely (i.e. customers have choices and can
exercise some control over their bills).
7) LDCs should have an appropriate level of control over outcomes, and
should be fairly compensated. Figure 1 provides a conceptual model for
the relationship between compensation, risks to LDCs, and control. Where
LDCs assume a high degree of risk and/or responsibility, LDCs should have
sufficient control over outcomes to effectively mitigate those risks. At the
same time, LDCs should be fairly rewarded for taking on responsibility and
producing beneficial outcomes.
If there is more risk in CDM than in traditional “poles and wires” business
activities, then the potential compensation should also be higher. 5
Furthermore, where LDCs’ CDM activities benefit the province by replacing
more expensive electricity supplies, LDCs should receive a fair share of
these benefits. LDCs require financial returns at least commensurate with
those for other core activities of the utility to attract the attention of senior
management and to motivate efforts.
4
This supports the EDA 2008 guiding principle: Schedules for CDM program approvals and funding should
be sensitive to LDC business planning timelines and coordinated with program implementation schedules.
5
This supports the EDA 2008 position paper guiding principle: LDCs should receive incentives in order to
achieve the maximum economical level of CDM results.
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Control
Returns
In Figure 1, the line from the bottom left to the top right of the diagram
illustrates where risk, control, and returns are appropriately balanced. If
returns to LDCs are too high, given the level of risk they bear, then the
framework sits “above” the line and will not be acceptable to the province.
One of the central weaknesses of the current CDM framework in Ontario is
that LDCs assume high risk and responsibility without the appropriate
control or returns; the 2011-2014 framework thus falls “below” the line.
2011 -2014
Risk to LDC
Figure 1 Relationship between risk to LDC, potential returns, and control for CDM frameworks
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Spectrum of CDM framework models
There are a number of different CDM framework models that are
consistent with the guiding principle that LDCs should have an appropriate
level of control over outcomes, and should be fairly compensated. Table 1
identifies the characteristics of four frameworks that balance risks to LDCs,
potential returns, and control.
On the far left, the “regulatory model” involves no risk to LDCs, and offers
no opportunity for returns. Accordingly, LDCs have little control over
outcomes, as all activities are set or approved by the province (e.g.
programs and budgets). On the far right, the business approach involves
significant financial risk to LDCs, but offers very significant opportunity for
financial returns. Accordingly, LDCs have complete control over outcomes,
as they determine their budgets and design and deliver programs. Two
intermediate models – the “vigilant” model and the “enterprising” model –
provide low or medium risk, offer LDCs intermediate levels of control, and
offer some possibility of returns.
Table 1 The spectrum of CDM framework models
Element
Regulatory
model
Vigilant model
Enterprising model
Business model
No risk
Low risk
Medium risk
High risk
Targets
Top-down targets
Top-down targets
Bottom-up targets
Internal targets
only
Budgets
Set by OEB
Set by OEB
Approval requested
from OEB
Corporate
resources and
investors
Approvals
All activities set
or approved
Some activities
set / approved
Few activities set /
approved, primarily
internal planning
Internal
planning only
Penalties
No penalty
Possible minimal
penalty
Possible penalties
Possible losses
Incentives /
returns
No return
Possible small
return
Potential for large
returns
Potential for
very large
returns
Risk to LDC
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Figure 2 illustrates how these four models fall along a spectrum of risk,
control and potential returns. The EDA and its members have indicated
their desire to move towards the business approach (at the top right of
Figure 2). To support this new direction for CDM in Ontario, this report
further describes the characteristics of the business approach and its
benefits over the status quo. This report also provides options for “piloting”
the business approach, and presents practical changes that will promote
progress towards the business approach.
Returns
Enterprising
Control
Business
Vigilant
Regulatory
2011 -2014
Risk to LDC
Figure 2 Range of CDM framework models and their associated balance of risk to LDC, potential returns,
and control
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The business approach
In order to improve CDM outcomes for customers, for LDCs, and for the
province of Ontario, the Electricity Distributors Association (EDA) Board and
Policy Committee recommend increasing LDCs’ responsibilities . EDA
members have indicated that they are prepared to assume the greater risks
attendant with these responsibilities, but expect appropriate rewards,
commensurate with these increased responsibilities and risks. This
“business-like” approach would motivate LDCs to achieve the maximum
cost-effective electricity savings, and would provide fair returns for their
results.
Under the business approach to CDM, LDCs will take full responsibility for
funding, designing, and delivering CDM programs. LDCs will set internal
targets, will determine appropriate programs and budgets, and will use
corporate or investor resources to fund these resources. Working together
through the EDA, in smaller groups, or alone, LDCs will design and deliver
programs that save electricity and meet customers’ needs. LDCs will
evaluate programs’ electricity savings using the OPA’s evaluation protocols.
LDCs will be rewarded per kW and kWh saved over the lifetime of the
measures.
Payments from the province will provide LDCs with a fair share of the
financial benefits of the electricity savings for Ontario. Thus, LDCs will have
the opportunity to make significant profits from well-designed, costeffective programs, while providing the province with a lower-cost
alternative to new generation. However, the payments may not cover
program costs if programs are not well-designed. LDCs will thus bear
financial risk in undertaking CDM. Payments for lifetime savings will
encourage LDCs to pursue deep measures with longer lifetimes.
Since LDCs will not be investing provincial resources into CDM, approval
processes will be minimal. Up-front applications to the OPA will provide
LDCs and the province with a degree of assurance regarding CDM activities.
Program evaluations and savings verifications will be submitted for review
and compensation. LDCs may also be encouraged (or required) to share
internal CDM targets with provincial bodies to facilitate system planning.
The defining characteristics of the business approach as compared to the
2011-2014 framework are outlined in Table 2.
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Table 2 Comparison of CDM framework elements: 2011-2014 framework vs. business approach
10
Element
2011-2014 framework
Business approach
Risk to the province
Low financial risk: incentive
payments easily estimated
Low financial risk: guaranteed
results for payments
Risk of not meeting targets due
to limitations of framework
Initial uncertainty regarding
CDM levels and efficiency
Benefits for the
province
Relatively predictable short-term
costs and results
Long-term potential for
increased CDM results,
innovation and efficiency
Risk to the LDC
Medium risk: risk of not meeting
targets, not being in compliance
with license
Higher risk: Potential losses
from poorly designed CDM
Benefits for the LDC
Minimal effort required for
program design, no investment
of corporate resources
High potential returns, reduced
regulatory requirements,
improved customer relationship
Targets
Top-down
Internal targets only
Budget-setting
Set by OEB based on LDC service
territory
Internal budgeting
Funding for programs
Global Adjustment Mechanism
(GAM)
Corporate resources and
investors
Funding for results
Global Adjustment Mechanism
Global Adjustment Mechanism
Approvals
Custom programs must be
approved by OEB; CDM plans
must be “accepted” by OEB
Internal planning only; savings
must be verified
Incentives/rewards
Possible small reward based on
savings over 4 years; larger
reward for not spending all of
allocated budget
Payment per kW and kWh saved
over lifetime of measure based
on avoided cost
Penalties
Possible penalties if mandatory
targets not met
Potential for losses if programs
are poorly designed
Evaluation
Based on OPA evaluation
protocols
Based on OPA evaluation
protocols
Role of OPA/central
agency
Province-wide program design /
delivery, research, evaluation,
provincial branding for CDM
Market research, evaluation
protocols, and provincial
branding for CDM
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Benefits of a business approach
The business approach has many benefits over previous CDM frameworks.
These benefits are also aligned with the guiding principles discussed in the
section above.
Innovation, efficiency and learning. The business approach will promote
innovation, as all LDCs will have the opportunity to design creative and
cost-effective programs. During the third tranche period, LDCs
demonstrated their ability to design good CDM programs – many of these
programs were then adopted as the basis for provincial programs. Third
parties may also have the opportunity to design programs for LDCs, thus
further promoting innovation and competition.
At the same time, the business approach will enable efficiency and
economies of scale. LDCs recognize the importance of working together to
design and deliver programs that are relevant in all service territories.
Groups of LDCs with similar customers will also work together to design
locally relevant programs. New or modified programs that are effective in
one service territory will be expanded to other areas, thus promoting
continual improvement and learning.
Maximum cost-effective CDM. With the regulatory burden lifted and the
potential for large rewards, LDCs will be motivated to aggressively pursue
maximum cost-effective electricity efficiency. Energy efficiency is the leastcost and least-harmful means of supply. Investing in the maximum costeffective CDM will reduce electricity costs for consumers. It will also
support the province’s objectives of energy security, environmental
sustainability, and competitiveness. .
Financial benefits for the province and ratepayers . The province will have
a guarantee that its resources are well spent – it will only pay LDCs for
electricity savings. The payments to LDCs will be less than 100% of the
value of CDM to the province. By definition, CDM payments will be costeffective and will benefit ratepayers .
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Fair rewards for LDCs’ efforts. Because of the significant opportunities for
profit, CDM will become integrated into LDCs as a core business activity.
Shareholders will be more enthusiastic about CDM activities, and will feel
that they are fairly rewarded for their CDM efforts.
CDM that benefits customers. LDCs understand their customers, and will
design programs that meet their needs. Innovation and improvement in
program design will also benefit customers and provide them with choices
for better managing their bills. Furthermore, programs will stay in market
as long as they are well-received by customers and are cost-effective for
LDCs. CDM programs that meet the needs of customers will have more
success in-market and will help customers lower their electricity bills.
Alignment of risks, control and rewards. The business approach aligns risk,
control and reward by allowing LDCs to fund, design and deliver CDM
programs – and to be fairly rewarded for the associated benefits to the
province and to rate-payers.
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Transition plan
Moving from the 2011-2014 CDM framework to the business approach will
require a number of significant changes. By taking a systematic step-wise
approach to change, the electricity sector can effectively transition from
the current framework to a business approach to CDM.
Piloting the business approach
Ontario can “pilot” the business approach to CDM immediately, under the
2011-2014 framework. The process used to establish the Feed-In-Tariff (FIT)
may be used as a model for CDM. However, while FIT prices are
significantly higher than the cost of newly constructed conventional
electricity generation, CDM prices will be significantly lower than the cost
of new generation.
First, the province should determine the appropriate payment per kW and
kWh of savings delivered through CDM. The province should work with
LDCs, the OPA and other energy sector stakeholders to set this payment
level, based on the cost of new generation. For example, after consultation,
the province might conclude it should be willing to pay up to 80% of the per
unit cost of new generation for CDM results. Once this value is determined,
it should be locked down for a certain number of years, to enable LDCs to
undertake CDM planning. However, this value should be recalibrated every
few years for new programs to account for the changing costs of electricity.
The province can begin to offer this per unit payment opportunity
immediately, for custom CDM programs funded by LDCs (Tier 2/3). LDCs
that want to invest corporate or investor money into custom programs can
apply for the CDM payment for the energy savings they achieve. However,
the OPA programs will still continue, enabling all LDCs to maintain their
CDM activities and progress towards targets.
An appropriate application and approval process would be required to
ensure that these custom programs do not claim savings generated by OPA
programs. Applications to the OPA (like under the FIT program) would also
confirm appropriate evaluation methods and would provide a level of
awareness / assurance to the province and to the LDCs.
If no LDCs choose to provide CDM for the pre-determined payment level,
the province will not bear any costs. If LDCs are able to design and deliver
cost-effective programs using corporate or investor resources, both LDCs
and the province will benefit.
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Attitudinal changes
Several major attitudinal changes must occur as part of the transition. The
province must be willing to set incentives / payments at levels that reflect
the value of these savings, when compared to the alternatives (LDCs will
expect returns for CDM greater or equal to the return on investment for
other LDC expenditures). While the province may spend slightly more
money per unit of electricity saved, the province will have confidence that
more electricity savings will be produced, and that this electricity will be
cheaper than alternative energy sources.
The province should acknowledge that CDM is cheaper than new
generation, and reduces electricity costs for consumers. The province
should thus embrace the opportunity to receive guaranteed results for
fixed payments.
Second, LDCs must be willing to invest corporate resources in CDM. This
involves accepting CDM as a core – potentially risky and potentially
profitable – business activity. For this to occur, LDCs must be confident that
they are capable of designing and delivering cost-effective CDM programs.
LDCs must also be confident that the province will follow through on its
commitments to payment levels for CDM results.
LDCs’ confidence will also increase if the Ministry can guarantee that there
will be a role for LDCs in CDM until at least 2030, consistent with the Long
Term Energy Plan and the IPSP. Establishing a simple and clear approval
process would also increase LDCs’ confidence in receiving full payments for
their savings.
Third, the province should accept some uncertainty in CDM for system
planning purposes. LDCs can provide estimates of their anticipated CDM
results, but these will not be guaranteed. However, even now there is not
complete certainty in CDM levels. Furthermore, after the initial start-up
period, system planners should be able to produce estimates of CDM levels
under the business approach, just as they must estimate other inherently
uncertain items, like changes in the size and structure of the economy.
Finally, general support for the business approach to CDM can be promoted
through increased understanding of CDM’s benefits and cost-effectiveness
– among LDCs, regulatory bodies and ratepayers.
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Other practical changes
Other short- and medium-term changes can also facilitate progress towards
the business approach. For example:
LDCs should be encouraged to start designing and delivering
custom programs now. This can be facilitated through:
o streamlining approvals for Tier 2/3 programs, and
o allowing CDM programs that are developed now to remain in
market post-2014.
Several options could be part of intermediate models post-2014, without
the full transition to the business model. For example, under the “vigilant”
or “enterprising” models presented in Table 1:
Incentives should be paid annually, start at the first unit of
electricity savings, and be based on lifetime savings of measures,
to increase LDCs’ motivation to achieve CDM results.
LDCs should have greater control over outcomes, including leading
customer-focused provincial program design, and leading planning
for customer-focused program delivery.
Provincial programs should be optional rather than mandatory.
Regulatory burdens associated with CDM should be significantly
reduced (e.g. CDM plans and custom programs).
LDCs should have greater control over the full use of CDM
budgets, including the allocation of these budgets towards custom
programs or provincial programs. Money would flow from LDCs to
the OPA, with the OPA functioning as a “pay-for-service”
organization. LDCs could pay to deliver OPA programs, or could
choose to invest this money in custom program designs.
The changes discussed in this section are summarized in Table 3. They are
also classified into two categories: structural/practical, and attitudinal
changes. Within each category, there are changes to be made in the shortterm (until the end of 2013) and medium-term (post-2014). There are also
changes that would facilitate a slower transition to the business model, by
adopting an “enterprising” or “vigilant” model post-2014.
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Table 3 Changes to transition from the 2011-2014 CDM framework to a new framework
Structural/practical
If moving to
business
approach:
Province to determine
appropriate per-unit payment
levels for CDM results
Short-term
(until end of
2013)
Minister to devote GAM funding
to per-unit payments for CDM
results
LDCs to secure investors and/or
corporate resources for CDM
Minister to allow CDM programs
to remain in market after
December 31, 2014
Attitudinal
LDCs, regulatory bodies, and the
community to increase
understanding of CDM – and its
cost-effectiveness compared to
new electricity supply
LDCs to demonstrate willingness
to accept risk and adopt CDM as
a core – and potentially risky –
business activity.
Minister to instruct OEB to
streamline approvals process for
Tier 2/3 programs
LDCs to be guaranteed role in
CDM until at least 2030
If moving to
business
approach:
Medium-term
(post-2014)
Minister to devote GAM funding
to per-unit payments for CDM
results
OPA/central agency to focus on
market research, evaluation and
provincial branding for CDM
LDCs to design and deliver
programs
LDCs to secure investors and/or
corporate resources for CDM
Province to increase confidence
in benefit of LDC-designed CDM
programs
Province to accept some
uncertainty in CDM levels, for
system planning purposes
If moving to
enterprising
or vigilant
model:
LDCs to lead provincial program
design and delivery
Province to increase confidence
in LDCs’ ability to responsibly
manage budgets, and design and
deliver programs
Medium-term
(post-2014)
LDCs to design and deliver
custom programs
Province to reduce regulatory
burden for CDM plans and
custom programs
Incentives to be paid annually,
start at first unit of impact, and
reflect lifetime savings
OPA to function as a “pay-forservice” organization
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Conclusions
Ontario’s 2011-2014 CDM framework features an imbalance between risks
to LDCs, rewards, and control over outcomes. In order to improve CDM
outcomes for customers, for LDCs, and for the province of Ontario, the EDA
supports increasing LDCs’ responsibilities, with attendant acceptance of
risk, and expectation of rewards commensurate with this increased
responsibility and risk. This “business-like” approach would motivate LDCs
to achieve the maximum cost-effective electricity savings, and would
reward them fairly for these savings.
LDCs want to move toward a CDM framework that offers a higher degree of
autonomy over CDM programs and greater potential for high returns based
on electricity savings achieved—the outcomes of the business approach to
CDM. Many details remain to be worked out, and challenges remain.
However, the business approach presents an exciting opportunity for all
stakeholders in Ontario.
This business approach to CDM means that LDCs will take on the
responsibility of funding, designing, and delivering CDM programs. In
return, they will receive a fair share of the provincial savings that stem from
each kW or kWh saved. This approach has a number of benefits, including:
enabling innovation, efficiency and learning
promoting maximum cost-effective CDM
providing guaranteed financial benefits for the province and
ratepayers
fairly rewarding LDCs’ for their CDM results
meeting customers’ needs
appropriately aligning risks, controls and rewards.
There will need to be a number of structural/practical changes, as well as
attitudinal changes to transition from the highly-regulated 2011-2014 CDM
framework to a business approach to LDC CDM. Some changes can occur
immediately, while others should begin post-2014.
Given the slow and lengthy process of framework development, planning
for an improved CDM framework post-2014 must start well in advance of
2014. Building on the high-level approach outlined in this paper, the EDA
and its members can act immediately – to initiate conversations, to explore
opportunities, and to achieve changes that will improve CDM outcomes for
all stakeholders in Ontario. The time for change is now.
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Appendix I: The Case for Reform
THE CASE FOR REFORM
How regulatory streamlining
could benefit Ontario’s
electricity consumers
JULY 2011
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Executive Summary
The Electricity Distributors Association (EDA) is the voice of Ontario’s 78 electricity utilities who safely and
reliably deliver electricity to 4.7 million residential, business and institutional customers. In 2010, the
Association initiated a project to consult with members on how to streamline the current regulatory
framework. This work has resulted in a number of specific recommendations supported by LDCs.
The key recommendations include:
o
o
o
Revising the IRM Application Process
Revising the Cost of Service Application Process
Revising the Intervenor Process
Adopting these recommendations would improve regulatory oversight, reduce regulatory costs and
ultimately benefit customers. The EDA continues to examine further opportunities to streamline regulation
for the sector.
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Background
The regulatory framework for Ontario’s local electricity distribution companies (LDCs) has undergone
significant changes over the past decade. More recently, LDCs have taken on new responsibilities and
roles related to the Green Energy and Green Economy Act (GEA) which has had further impact on the
regulatory framework.
In the midst of these changes, LDCs have found that the regulatory burden is consistently increasing.
LDCs have gained substantial experience and insight working under OEB oversight in the existing
regulatory framework. At the same time, there are increasing pressures to address the rising costs of
electricity.
Ontario LDCs firmly believe that now is the time to carefully review the regulatory processes to identify
areas that could be streamlined. The result will be a more efficient and cost-effective regulatory
framework that achieves policy objectives and has the potential to make electricity more affordable for
electricity consumers.
Guiding Principles for Regulatory Streamlining
In early 2011, the EDA Board of Directors developed the following Guiding Principles, to assist in
developing recommendations for streamlining regulation of the sector:
There is a need to balance costs of regulation with the benefits to customers;
The amount of regulation and reporting requirements should be proportionate to the policy
objective/outcome;
More emphasis should be placed on policy outcomes, not process;
Duplication and overlap of reporting requirements should be eliminated
Administrative burden to LDCs should be minimized, streamlined;
Distributors should be provided flexibility to address their local circumstances
Distributors should not be involved in addressing social problems;
Distributors should be allowed to recover their costs to address aging infrastructure in a timely
manner;
Increased certainty and transparency should be provided for cost recovery by distributors;
Decision-making by regulators needs to be timely.
The EDA Board appointed a committee which developed and brought forward proposals to all LDCs for
input. The members indicated strong support for the proposed recommendations.
In order to fully realize the business opportunities that will bring value to customers and shareholders
alike, LDCs need a regulatory model that builds efficiencies for utilities. There is a need to review the
regulatory system to produce favourable rate outcomes, bring more efficiency into the rate process and
create value to the customer and shareholders in terms of addressing the costs associated with the
regulatory system.
The Committee’s recommendations focus primarily on three significant burdensome areas:
Incentive Regulation Mechanism (IRM) application process
Cost of Service (COS) application process
Intervenor process
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Distribution Rate Application Process
Every four years an LDC brings forward an application to the OEB for a full review of its costs and
proposed rates. This is called a COS application.
In the years between these COS applications, rates are adjusted through an IRM application process
whereby rates are updated annually by a formula which adjusts upward for inflation and downward for
anticipated productivity improvements plus possible LDC-specific adjustments.
These possible adjustments in the IRM application include materially significant cost changes and
significant increases in capital investments. During each application process, intervenors (stakeholders
who participate in the hearing process) and OEB staff can ask questions and can file submissions to the
OEB with respect to its decision on the LDC’s application. Many intervenors are eligible to recover their
costs from the Applicant (LDC) for participating in the hearing process.
This process was established as a replacement of the more traditional rate approval process where LDCs
would file for a COS application each year. The IRM period between COS applications is designed to
encourage LDCs to achieve efficiencies through cost savings and be rewarded with higher returns.
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The Case for Reform
The EDA Board Committee identified the following challenges created under the current regulatory
process, and offers recommendations for change that would benefit LDCs, their shareholders, the
regulator and ultimately all electricity consumers in Ontario.
Challenge:
The OEB’s capital module materiality threshold in the IRM period is too high. This encourages
deferral of infrastructure renewal and often results in sharp rate increases for customers once
every four years.
Capital investments taken separately on a year-by-year basis are often too small to meet the OEB’s
materiality threshold and/or other screening criteria to be included in rates during the IRM application
period. As a result, LDCs will often defer these capital investments and include them at the time they
submit their COS applications when the materiality threshold does not apply.
This approach of excluding all capital investments in the interim rate adjustments has three
consequences:
1. LDCs are compelled to defer the much-needed capital investments for up to three years during a
time when infrastructure is in need of renewal.
2. LDCs that do undertake capital investments that do not meet the materiality threshold have no
certainty that they will be able to recover these costs. Moreover, LDCs must carry these costs
until their full cost-of-service application, thereby penalizing their shareholders.
3. Customers may ultimately experience sharper rate increase at the time the full COS application is
submitted, since all capital investments are included at that time.
Recommendation: Revise the Capital Module
Allow LDCs to obtain approval for multi-year capital investment plans in
COS proceedings – and then scrutinize applications for the capital module
during the IRM period based on the approved multi-year capital investment
plans.
All capital investments made during the IRM period should be incorporated
into rates during the same period.
Key benefits:
Enabling LDCs to submit and receive approval for multi-year capital investment plans would ensure much
needed capital investments are undertaken in a timely manner. This would streamline the annual process
to review capital module applications for both the OEB and LDCs making it more timely and cost
effective.
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Challenge:
Generic inflation and productivity factors used to adjust rates during IRM period don’t reflect the
current LDC-industry reality.
In the IRM period rates are adjusted annually for inflation and downward for anticipated productivity
improvements. The current inflation factor used is the Canada Gross Domestic Product Implicit Price
Index (Canada GDP-IPI), which is a generic indicator and it does not reflect the inflation pressures on
distribution industry in Ontario. Inflation factors that are more specific to the LDC industry would better
reflect the recent changing higher labour costs in the industry which are different from other sectors in the
economy.
The productivity factor used for LDCs in Ontario is based on the long-term total factor productivity (TFP)
trend from a representative set of U.S. electricity distributors over a long period beginning in the late
1980s.
This long-term US TFP data was selected because reliable long-term productivity data from Ontario LDCs
was not available at that time. At the time the US TFP data was selected, none foresaw the degree of
change that the Ontario electricity industry and LDCs would undergo as a result of overall industry
restructuring. The additional mandates to install smart meters, deliver conservation programs, implement
Time of Use pricing, connect renewable generation and develop the smart grid mean that the comparison
of US Distributors to Ontario LDCs is no longer valid and as such, the long-term past trends in the US
have not proven to be an accurate indicator of the actual productivity experience of Ontario LDCs.
As a result of their additional mandates, LDCs’ focus has been centered on responding to the constantly
changing requirements placed upon them. These increasing new responsibilities, coupled with constant
changes in the industry, have offset or delayed the expected improvements to productivity. Using the
current productivity factor results in rate decreases that are not sustainable as LDC businesses take on
increasingly broader scope.
IRM rate adjustments that are based on factors not reflective of the current industry reality result in a
“true-up” when LDCs bring forward their COS applications. The amount of the true-up can be substantial
over the period between COS applications, and as such can create price instability and uncertainty for
customers.
Recommendation: Revise the Productivity Factor and Inflation Factor
Use Industry-specific inflation factor to reflect changing labour costs in the
industry rather than using Canada GDP – IPI in the IRM formula.
Lower the current productivity factor in the IRM formula to reflect existing
productivity in the industry impacted by constant ongoing changes to
regulatory requirements.
The current productivity factor in the IRM formula should be lowered to be more reflective of current
productivity levels in the industry which has been and will continue to be affected by ongoing industry
changes.
The EDA proposes adjusting the inflation factor so it is more reflective of industry inflation and setting the
productivity factor at a level reflective of recent Ontario trends.
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Key benefits:
More gradual rate changes will help avoid customer “sticker shock” which occurs under the current
approach where rates increase sharply. The revised IRM process could also allow longer periods
between filings of COS applications, reducing the amount of resources allocated by both the regulator
and the LDC to this labour and time-intensive process. The new approach would also reduce the financial
burden currently placed on LDCs.
Challenge:
Existing COS templates are extensive and open to interpretation, leading to an unnecessarily
burdensome amount of administrative work.
The COS application process involves a full review of all the LDC’s costs. The OEB notes that a COS
application should provide sufficient detail to enable the OEB to determine whether the proposed rates
are just and reasonable and the onus is on the LDC to provide sufficient evidence to prove the need for,
justification and prudence of all its costs that are the basis for its proposed new rates.
The OEB has developed templates for filing COS applications that were designed to assist LDCs in
organizing the information to be provided. LDCs are required to file an application which usually includes
many volumes of information. However, the current existing COS templates are too extensive and open
to interpretation which results in unnecessary administrative burden on LDCs to compile this information.
Recommendation: Revise the Cost of Service Application Process
Develop/revise the standardized templates for filing COS Applications to
make the filing process as standardized as possible. Limit the textual
component of the application to explaining cost increases or just variances
in general, and reduce administrative paperwork by 30-50 per cent.
Develop metrics to evaluate an LDC’s application provided in the
standardized format.
OEB should provide updates or revisions to filing requirements well before
the application deadline (i.e. in January but not in June – just two months
before the application is due for filing).
Evaluate LDC’s COS application based on the metrics developed:
o If within a permissible range – limited review of application (Note:
range should be based on defined variables/cost drivers such as
urban/rural mix, geography, underground plant, etc.)
o If beyond the permissible range – review of the application
LDCs request that the OEB develop new and revised templates for filing COS application to make the
filing process more standardized and confine the textual component of the application to explaining cost
increases or variances in general. Significant effort is required to provide the level of detail required by the
current template, and current practice among OEB staff and intervenors indicates that they focus on only
a small portion of the entire application. There is an opportunity to reduce the amount of administrative
work by 30-50 per cent while still retaining all relevant information simply by revising the templates.
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To further facilitate the review of a COS application, the OEB should develop metrics including
permissible ranges to be used to evaluate an LDC’s application. If the information contained in the LDC’s
application falls within the established permissible range, the application could be efficiently evaluated
through a more limited review. This permissible range should be LDC-specific and be based on defined
variables/cost drivers which take into account the specific situation of the LDC such as urban/rural mix,
the extent of underground plant and local geography, and other factors which influence costs. Once
established, using metrics will reduce the administrative cost and the regulatory burden on both the OEB
and LDCs resulting in significant cost and time savings.
Notwithstanding the above recommendations, any updates or revisions to application filing requirements
should be provided well before the application deadline (i.e., a minimum of eight months prior to filing
deadlines) to enable LDCs sufficient time to compile their applications well before the due date for filing.
Key Benefits:
A revised template that focuses solely on relevant information, coupled with pre-established evaluation
metrics will reduce administrative activity and costs for all parties and facilitate timely approvals.
Challenge:
Requests for information from intervenors and OEB staff are essentially duplicative in nature,
however are worded such that they appear subtly different, necessitating a tailored response. This
results in additional administrative burden with limited added value.
The situation is further aggravated by the fact that many intervenors serve common interests, with
some representing a subset of a broader interest group. Since intervenors are allowed to recover
their costs, the amount of work undertaken by intervenors, along with their growing numbers, has
led to a sharp increase in cost awards payable which ultimately is borne by the customer.
Intervenors are expert consultants or counsels who participate in the review of applications on behalf of
customer groups they represent. Intervenors are eligible for cost awards from the applicant for their time
spent in reviewing the application, preparing questions on the application and participating in the process.
Some intervenors appear genuinely interested in addressing the concerns of their constituents as
effectively as possible. However, due to lack of proper safeguards, the current process has become
cumbersome and more costly than strictly necessary. For example, questions appear to be designed to
elicit more material than necessary to effectively review the applications.
The OEB has established rules to prevent abuse of the cost award process. For example, intervenors
must demonstrate that they do not unduly repeat questions asked by other parties, that they make effort
to co-operate with other parties to reduce duplication, or that they don’t act to unnecessarily lengthen the
duration of the process. Nevertheless, the current process does often result in duplication as intervenors
do not always follow a coordinated approach in filing questions.
Compounding the issue is that both intervenors and OEB staff have the same deadline for filing their
questions on the application. As a result questions are often essentially duplicative, but only just different
enough to require a tailored response.
Intervenors are eligible for cost awards if they primarily represent the direct interests of customers or
primarily represent a public interest relevant to the OEB’s mandate, such as an environmental group
.
However, some intervenors do not appear to represent a unique interest as they represent a subset of a
larger group of customers already represented by another intervenor, often leading to duplication of
questions in the regulatory process.
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In all cases, intervenor costs are ultimately reflected in rates, so it is in the customer’s interest to ensure
these costs are reasonable and controlled.
Recommendation: Revise the Intervenor Process
Reduce the duplication of effort between OEB staff and intervenors in
raising interrogatories.
o OEB staff to take leadership role and issue the first round of
interrogatories
o Intervenors to review OEB staff interrogatories and only then raise
their own interrogatories without duplicating staff effort
o OEB staff should screen interrogatories from intervenors for
duplication, relevance and materiality
Intervenors should represent a clearly definable/distinct interest that is
relevant to the issue being reviewed and OEB should be more strict in
providing intervenor eligibility
Establish a cap on cost awards provided to intervenors so that costs and
benefits of their review are balanced
Revise cost award eligibility rules so that parties with access to financial
resources are not eligible for total cost recovery e.g. only 80 per cent of
recovered through cost awards
Intervenors could act jointly in order to qualify for joint funding
There is opportunity to reduce duplication of requests for information by having OEB staff take on a
greater leadership role in the entire application review process. OEB staff could develop the preliminary
list of questions (i.e. interrogatories) on LDC applications. Intervenors would then be required to review
the OEB staff interrogatories prior to submitting their own interrogatories with the requirement that these
questions not be duplicative. OEB staff would screen the interrogatories for duplication, relevance and
materiality before issuing them to the LDC applicant.
In order to encourage intervenors to make best use of resources, the EDA proposes that the OEB
establish a cap on cost awards for each proceeding. The cap would be based on the anticipated effort
required, as presently done for some OEB consultations. This would encourage intervenors to focus on
issues that are material and help ensure the cost awards are better balanced with the benefits they
provide.
To keep overall costs of the proceedings reasonable, the EDA proposes that cost award eligibility rules
be revised so that parties with access to financial resources are not eligible for total cost recovery e.g.
only 80% of expenses are recoverable through cost awards. This would encourage groups being
represented by intervenors to undertake more active oversight of the work undertaken by the
consultant/counsel working on their behalf. Presently, there is no cost driver to encourage groups to
adequately oversee the intervenors working on their behalf and ensure their interests are being
represented efficiently and effectively.
Intervenors should represent a clearly definable and distinct interest that is relevant to the issue being
reviewed. There is an opportunity for the OEB to tighten rules around intervenor eligibility. This approach
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would reduce the overlap among intervenors and reduce the costs associated with funding two groups
essentially representing the same interest.
Key benefits:
The proposed changes to the intervenor process will ultimately reduce costs associated with regulation
and lead to more timely assessment of LDC applications. In addition, intervenors would be more focused
on issues material and important to the groups they represent.
Ultimately, the customer would benefit from regulatory cost reductions in the form of more stable,
affordable rates.
Additional Recommendations:
The OEB should conduct periodic review (every two to three years) of the
reporting requirements to examine relevance and to avoid duplication.
The Social Agency Role for LDCs should be removed.
New requirements that involve significant implementation efforts should be
coordinated between agencies and government to reduce overlapping
implementation timelines that impact on LDC workload.
LDCs should not be compelled to take on the role of acting as a social agency. Recent examples include
the requirement of LDCs to assist low income customers by adopting special customer service rules. The
role of assisting low income customers should remain with social agencies that have the expertise and
infrastructure to provide this assistance. LDCs should not be burdened with the administrative costs of
implementing such social programs.
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Conclusion
LDCs are experiencing increasing resource pressures associated with the steadily increasing regulatory
burden year-over-year. The current regulatory process needs to be streamlined and simplified to reduce
regulatory and administrative burdens in the interest of customers, LDCs and shareholders.
Implementation of the proposed recommendations will:
o
Avoid sharp rate increases caused by the current regulatory approach and move to gradual rate
changes.
o
Reduce administrative/regulatory burden on both the regulator and LDCs.
o
Reduce the undue financial burden on LDCs.
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Endnotes
1 Ontario Regulation 427/06 under Electricity Act, 1998 – Smart Meters: Discretionary Metering
Activity and Procurement Principles, http://www.e-laws.gov.on.ca/html/regs/english/elaws_
regs_060427_e.htm.
2 Directive to the OPA from the Minister of Energy, July 13, 2006, http://www.powerauthority.on.ca/
about-us/directives-opa-minister-energy-and-infrastructure.
3 Drummond Report, Chapter 17, http://www.fin.gov.on.ca/en/reformcommission/chapters/report.
pdf.
4 In 2011, the Ontario Energy Board initiated “a consultation aimed at promoting the cost-effective
development of electricity infrastructure through coordinated planning on a regional basis between licensed distributors and transmitters”. http://www.ontarioenergyboard.ca/OEB/Industry/
Regulatory+Proceedings/Policy+Initiatives+and+Consultations/Regional+Planning
5 “Demand is expected to grow moderately (about 15 per cent) between 2010 and 2030.”
IPSP Planning and Consultation Review, May 2011, page 1-3.
6 In contrast, the useful economic lifetime of capital assets in the information industry itself, such
as factories (or “fabs”) that manufacture computer memory, is much shorter, typically 2 to 3 years.
Productivity growth, driven by technological innovation, occurs at much faster rates.
7 See https://www.saveonenergy.ca/.
8 “Over the next 20 years, prices for Ontario families and small businesses will be relatively predictable. The consumer rate will increase by about 3.5 per cent annually over the length of the long-term
plan. Over the next five years, however, residential electricity prices are expected to rise by about 7.9
per cent annually (or 46 per cent over five years).”Ontario’s Long-Term Energy Plan, page 59,
http://www.mei.gov.on.ca/en/pdf/MEI_LTEP_en.pdf.
9 IESO Admin Charges: The charges applied by the IESO to all market participants for operating the
wholesale market for electricity and ancillary services in Ontario. This is included in the Regulatory
Charge on customers’ bills.
OPA Admin Fees: The charges are applied by OPA for planning and procuring electricity supply from
diverse resources and facilitating the measures needed to achieve ambitious conservation targets.
This is also included in the Regulatory Charge on customers’ bills.
OEB License Fee and Cost Assessments: OEB License fee and Cost Assessments include cost awards
provided to stakeholders and intervenors for OEB consultations and generic proceedings respectively.
These costs are embedded in the distribution rate of each LDC.
Electrical Safety Authority (ESA) Cost Assessments: The charges that are applied by ESA to individual
LDCs. This is embedded in the Distribution rate of each LDC.
LDC Costs for Regulatory Compliance: These include regulatory staff costs, costs of preparing and
filing regulatory applications. OEB hearing and intervenor costs are included in this figure.
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10 2011 Annual Report Office of the Auditor General of Ontario - Section 3.02,
http://www.auditor.on.ca/en/reports_en/en11/2011ar_en.pdf.
11 ‘Objective’ or ‘principle’ based approaches have gained traction in financial regulation partly
as a result of the financial collapse of 2008.
Some of the ideas developed there may be relevant for regulating energy industries.
12 LDCs began paying PILs on October 1, 2001. The amount of PILs paid by LDCs from 2002 to 2011
was estimated to be using OEB yearbook data for 2005 to 2010 period.
13 Statistical estimates from data in the mid-1990s indicated that distributors that were part of public
utility commissions exhibited lower average per-customer costs in the range of 6 per cent to 10 per
cent. See “Scale Economies in Electricity Distribution: A Semiparametric Analysis”, Journal of
Applied Econometrics, volume 15, pages 187-210, Tables I(a) through II(c).
14 See Appendix B for a detailed description of the U.S. electricity industry and the role of multi-utilities.
15 The Future of the Electricity Grid, An Interdisciplinary MIT Study, MIT 2011, page 6, available at
http://web.mit.edu/mitei/research/studies/the-electric-grid-2011.shtml.
16 In economist terms, the elasticity of demand response depends on a number of variables which vary
by location and conditions.
17 There are currently 3 levels of programs. Provincially mandated OPA programs are termed “Tier 1”
programs. “Tier 2” programs are those designed cooperatively by multiple utilities. “Tier 3”
programs are designed by individual utilities.
18 In the latest report, released June 5, 2012 the Commissioner states: “As a result of the [Ontario
Energy] Board’s action, both gas and electricity distributors are being deterred or restricted from
promoting conservation to its full potential, and consequently hurting the public good. As the ECO
has previously stated, the recent rulings have been indifferent and even hostile towards conservation, the opposite of what the government intended when the Board’s objectives were amended.
For example, the CDM Guidelines will likely limit the development of BAPs [Ontario Energy BoardApproved Programs]…. As noted in the ECO’s Annual Energy Conservation Progress Report – 2010
(Volume Two), the ECO is uncertain that the distributor targets will be achieved. Both consumption and peak demand targets are dependent on distributors implementing the OPA-Contracted
Province-Wide programs and BAPs. The ECO notes with discouragement that the OEB’s decisions
on duplication and its need to issue CDM Guidelines mean that almost half way through the 2014
target period, no BAPs are approved and LDCs only nowhave a complete set of rules within which
to develop programs.” Restoring Balance, A Review of the First Three Years of the Green Energy Act,
Annual Energy Conservation Progress Report – 2011 (Volume One), Environmental Commissioner
of Ontario, page 42, http://www.eco.on.ca/index.php/en_US/pubs/energy-conservation-reports/
restoring-balance.
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19 “Third Tranche Conservation and Demand Management Spending Staff Report”, Ontario Energy
Board, December 15, 2009, page 12.
20 Chapter 3, Section 3.02, 2011 Report of the Auditor General of Ontario http://www.auditor.on.ca/
en/reports_en/en11/302en11.pdf
21 The estimated savings of $50 million is based on an assumption that LDCs representing 25 per cent
of total provincial Operating, Maintenance & Administration (OM&A) Expenses could become more
efficient if consolidated, and that a savings of 15 per cent of total OM&A for those LDCs can be
achieved. It should be noted that some of the potential savings may already have been achieved
through cooperative efforts, and that distances and the non-contiguous nature of many LDCs may
prevent achievement of savings at the level we have estimated. The estimate does not provide for
transition costs.
22 Current Status of Electricity Restructuring by State. http://www.eia.gov/cneaf/electricity/page/restructuring/restructure_elect.html
23 “Compilation of Investor-Owned Transactions – Mergers and Major Acquisitions” American Public
Power Association. Updated April 2012.
24 Recession data taken from N.Y. Federal Reserve.
25 Calzorai, Giacomo and Carlo Scarpa. “Regulating a Multi-Utility Firm.” January 2006. Journal
of Economic Literature.
26 Filippini, Massimo and Mehdi Farsi. “Cost Efficiency and Scope Economies in Multi-output utilities
in Switzerland.” 2003. Strukturberichterstattung Nr. 39. Study on Behalf of the Secretariat for
Economic Affairs.
27 Farrell, m. J. (1957). “The Measurement of Productive Efficiency,” Journal of the Royal Statistical
Society, Series A, 120 (30): 253-290.
28 Filippini, Massimo and Mehdi Farsi. “Cost Efficiency and Scope Economies in Multi-output utilities
in Switzerland.” 2003. Strukturberichterstattung Nr. 39. Study on Behalf of the Secretariat for
Economic Affairs.
29 Fraquelli, Giovanni, Massimiliano Piacenza, and Davide Vannoni. “Scope and Scale Economies in the
Multi-Utilities: Evidence from Gas, Water, and Electricity Combinations.” July 2002. http://www-3.
unipv.it/websiep/wp/174.pdf
30 Carvalhho, Pedro, Rui Cunha Marques, and Sanford Berg. “A Meta-Regression Analysis of Benchmarking Studies on Water Utilities Market Structure.” August 2011.
31 Triebs, Thomas P., Michael G. Pollit, and John E. Kwoka. “The Direct Costs and Benefits of U.S.
Electric Utility Divestitures.” September 2010. Cambridge Working Paper in Economics.
32 Kwoka, J.E. “Vertical economies in electric power: evidence on integration and its alternatives.”
International Journal of Industrial Organization. 20(5): 653-671.
33 Kaserman DL, Mayo JW. “The Measurement of Vertical Economies and the Efficient Structure
of the Electric Utility Industry. Journal of Industrial Economics. 39:483-502.
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34 Lee B, Spiller. “Separability Test for the Electric Supply Industry.” 1995. Journal of Applied
Econometrics. 10(1): 49-60.
35 American Public Power Association. “Retail Electric Rates in Deregulated and Regulated States: 2009
Update.” March 2010. www.APPAnet.org.
36 The participating utilities are Bluewater Power, Brantford Power, Canadian Niagara Power Inc.,
Entegrus, Erie Thames, Essex Powerlines, Horizon Utilities, Niagara Peninsula Energy and
Welland Hydro.
37 http://www.ontarioenergyboard.ca/OEB/Industry/Rules+and+Requirements/Reporting+and+Record
+Keeping+Requirements/Yearbook+of+Distributors
38 Ontario Energy Book annual yearbooks of electricity distributors, http://www.ontarioenergyboard.
ca/OEB/Industry/Rules+and+Requirements/Reporting+and+Record +Keeping+Requirements/
Yearbook+of+Distributors.
39 Until 2009, the OEB tracked a tenth indicator ”Cable Locates” which measured the percentage
of requests for locating cables that were completed within five working days.
40 http://www.ontarioenergyboard.ca/OEB/Industry/Rules+and+Requirements/Reporting+and+Record
+Keeping+Requirements/Yearbook+of+Distributors
41 See, for example “Report for the Ontario Energy Board, Third Generation Incentive Regulation
Stretch Factor Updates for 2012 (EB-2011-0387), December 1, 2011, Power Systems Engineering Inc.
http://www.ontarioenergyboard.ca/OEB/Industry/Regulatory+Proceedings/
Applications+Before+the+Board/Electricity+Distribution+Rates/3rd+Gen+Stretch+Factors
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Electricity Distributors Association
3700 Steeles Ave. West, Suite 1100, Vaughan, ON L4L 8K8
Tel. 905-265-5300 Toll Free 1-800-668-9979 Fax 905-265-5301
www.eda-on.ca
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