Stake holder Consultation Notes - Hydro One...Overall weighted cost of capital (WACC) is 6.76%, with a rate base calculated at $6,477M. The return on capital is $438M, income taxes

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Filed: 2013-12-19 EB-2013-0416 Exhibit A-20-1 Appendix E Page 1 of 109

Stakeholder Consultation Notes December 2, 2013

Hydro One Networks Inc. | 2

Table of Contents

1. Welcome by Allan Cowan, Director Major Applications, Hydro One Networks ............................ 4

2. Introductions and Agenda by Bob Betts, Facilitator, OPTIMUS | SBR .......................................... 4

3. Application Filing Timeline by Allan Cowan, Director Major Applications, Hydro One

Networks .................................................................................................................................... 5

4. Revenue Requirement and Common Costs by Glenn Scott, Director Corporate Planning

& Finance, Hydro One Networks and Facilitated Discussion by Bob Betts, Facilitator,

OPTIMUS | SBR .......................................................................................................................... 5

5. Core Work Program by Paul Brown, Director Distribution Asset Management, Hydro One

Networks and Facilitated Discussion by Bob Betts, Facilitator, OPTIMUS | SBR ........................... 9

6. Distribution Cost Allocation / Rate Design by Henry Andre, Manager Distribution Pricing,

Hydro One Networks & Line Loss Study Update by Benjamin Grunfeld, Consultant,

Navigant Consulting and Facilitated Discussion by Bob Betts, Facilitator, OPTIMUS | SBR ......... 14

7. Custom Framework – Adjustments and Reporting by Allan Cowan, Director Major

Applications, Hydro One Networks and Facilitated Discussion by Bob Betts, Facilitator,

OPTIMUS | SBR ........................................................................................................................ 19

8. Closing Remarks / Next Steps by Allan Cowan, Director Major Applications, Hydro One

Networks .................................................................................................................................. 30

9. Appendices ............................................................................................................................... 31

Appendix A Summary of Stakeholder Session ........................................................................ 31

Appendix B Key Actions and Considerations .......................................................................... 32

Appendix C Meeting Agenda ................................................................................................... 34

Appendix D Presentation Slides…. ..... ….………………………………………………………………………………35

The presentation materials used in this Session and background materials can be found at this link:

http://www.hydroone.com/RegulatoryAffairs/Pages/DxRates.aspx

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Participants

Stakeholders

Shelley Grice, Association of Major Power Consumers of Ontario (AMPCO) Julie Girvan, Consumers Council of Canada (CCC) Peter Thompson, Canadian Manufacturers & Exporters (CME) David MacIntosh, Energy Probe Research Foundation Roger Higgin, Energy Probe Research Foundation John McGee, Federation of Ontario Cottagers Indy J. Butany‐DeSouza, Horizon Utilities Corporation Patrick Hoey, Hydro Ottawa Limited Ceiran Bishop, Ontario Energy Board (OEB) Harold Thiessen , Ontario Energy Board (OEB) Lisa Brickenden, Ontario Energy Board (OEB) Miriam Heinz, Ontario Power Authority (OPA) Tom Ladanyi, Ontario Power Generation Inc. (OPGI) Alfredo Bertolotti, Power Workers' Union (PWU) Larry Iwamoto, Powerstream Inc. Vitalika Quenville, Powerstream Inc. Paula Zarnett, Rogers Cable Communications Anita Varjacic, Rogers Partners LLP Don H. Rogers, Rogers Partners LLP Daliana Coban, Toronto Hydro‐Electric System Limited (THESL) Kaleb Ruch, Toronto Hydro‐Electric System Limited (THESL) Patrick McMahon, Union Gas Mark Garner, Vulnerable Energy Consumers Coalition (VECC)

Hydro One Networks Inc. Susan Frank, Hydro One, Vice President and Chief Regulatory Officer Allan Cowan, Hydro One, Director – Major Applications (presenter) Nicole Taylor, Hydro One, Regulatory Analyst Naiyu Zhang, Hydro One, Regulatory Analyst Ruth Greey, Hydro One, Senior Regulatory Advisor Glenn Scott, Hydro One, Director–Business Planning & Support (presenter) Ryan Lee, Hydro One, Manager‐Financial Plan & Analysis Paul Brown, Hydro One, Director‐Distribution Asset Management (presenter) Lyla Garzouzi, Hydro One, Manager – Distribution Development Henry Andre, Hydro One, Manager ‐ Distribution Pricing (presenter) Ian Malpass, Hydro One, Director – Pricing Rob Berardi, Hydro One, Director – Management Accounting

Other Participants

Bob Betts – Facilitator, OPTIMUS | SBR Jesse Egger – Notetaker, OPTIMUS | SBR Nick Mirkovic – Notetaker, OPTIMUS | SBR Steve Klein – Vice President and Practice Manager, OPTIMUS | SBR Benjamin Grunfeld (Presenter) – Consultant, Navigant Consulting Inc.

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1. Welcome by Allan Cowan, Director Major Applications, Hydro One Networks

Allan Cowan welcomed the audience to the fourth stakeholder consultation session pertaining to Hydro

One’s distribution custom rate application for test years 2015‐2019. Allan explained that each of the

four sessions have been different, by design, in order to encourage transparency and understanding

surrounding the rates application. He noted that the fourth session was unique from the perspective

that Non‐Disclosure Agreements were required to be signed by participants due to Ontario Security

Commission requirements related to the forward‐looking nature of the financial material to be

presented and discussed. Allan stated that due to the requisite confidentiality, the notes and slides

from the session would not be posted until after the rate application is filed with the Ontario Energy

Board (OEB). He then indicated that OPTIMUS | SBR was present to facilitate the session and take notes

and proceeded to introduce Bob Betts.

2. Introductions and Agenda by Bob Betts, Facilitator, OPTIMUS | SBR

Bob Betts thanked the audience and identified this as the fourth of a series of sessions hosted by Hydro

One to discuss the upcoming application.

Bob proceeded to review the agenda for the session. He indicated the day’s session would be split in to

two primary sections, with the first focusing on quantitative issues including forward‐looking financial

projections, specifically revenue requirement, capital expenditures, operating expenses, corporate

common costs, customer classification study results and overall bill impacts. The second section is

designed to focus on the remaining issues that have not yet been determined such as annual

adjustments, off‐ramps, and performance and outcome measures. The afternoon was designed to

foster an interactive discussion between Hydro One and stakeholders on these outstanding matters,

hopefully resulting in a mutually acceptable approach.

Bob continued by providing an overview of emergency procedures. He identified for everyone the

session is being recorded for note taking purposes only and indicated the recordings will be destroyed

once the notes are accepted. Bob then proceeded to have all attendees introduce themselves, stating

their name and the organization they represent (see list of participants above). Following the

introductions, Bob reviewed the procedures for the meeting highlighting general meeting etiquette and

protocols. He encouraged the audience to feel free to ask questions and provide comments throughout

the day.

In concluding his introductory remarks, Bob emphasized the importance of these sessions to Hydro One

and their objective to have full, open and active dialogues with stakeholders on all aspects of this

application. He also indicated the notes and materials would be available from the Hydro One website

(www.HydroOne.com/RegulatoryAffairs). Bob then welcomed Allan Cowan back to the podium.

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3. Application Filing Timeline by Allan Cowan, Director Major Applications, Hydro One Networks

Allan Cowan thanked the audience for their attendance and began by explaining that while Hydro One’s

original plan called for an application date in the first quarter of 2014, the Regulatory Affairs group is

now hoping to file on December 19, 2013. Allan described the December 19th filing as a high‐level

application sufficient to satisfy the OEB’s filing requirements to initiate the application process and to

remove the shroud of confidentiality associated with today’s information. He indicated that a filing

update would follow on about January 31, 2014, which will include all additional details and supporting

documentation.

Allan stressed that Hydro One is determined to allow all stakeholders to have ample time to evaluate

the filings. Allan went on to state that the two planned filings would not include 2013 actual financial

results due to unavailability at the date of filing; they would be filed in a blue page update scheduled to

be filed in May, 2014. Allan then asked the audience if there were any questions pertaining to the

expected timeline.

4. Revenue Requirement and Corporate Common Costs by Glenn Scott, Director Corporate Planning & Finance, Hydro One Networks and Facilitated Discussion by Bob Betts, Facilitator, OPTIMUS | SBR

Glenn Scott introduced himself and explained that the forward‐looking financial projections he would

present would be high level in nature, reflecting the first of two stages in the planned filing process.

Glenn proceeded to outline the material he planned to review; an overview of revenue requirement,

rate increases, issues surrounding regulatory asset recovery and capital and OM&A expenditures,

including corporate common cost details. As a reminder to all present, he reviewed the disclaimer slide

regarding forward‐looking financial information.

Glenn then went on to explain the approach taken by Hydro One to the application process and

presentation of financial projection estimates. To aid this process he outlined Hydro One’s value

proposition, which includes five principle goals that all relate to the delivery of safe, reliable and

affordable service. The five goals as presented by Glenn are as follows:

1. Keeping rates low – annual total bill impact at / less than inflation

2. Improving customer satisfaction and building a trusted partner relationship

3. Preserving net income

4. Full visibility on assets and targeted investments to minimized customer impacts

5. Improving operating efficiencies and cost savings

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Glenn stressed the importance of Hydro One’s data analysis capabilities, allowing increased levels of

cost savings. He noted that productivity changes discussed in earlier stakeholder sessions were included

in Hydro One’s business plan and that the bill impact component of the session would show that Hydro

One’s proposed increases are very close to the level of projected inflation. Glenn also discussed the

customer voice initiative implemented within the company; reliability of service and overall bill impact

were ranked as the two most prevalent issues by customers, with bill impact rated most important.

Glenn then went on to highlight key figures as they relate to the calculation of 2015 distribution revenue

requirement. The deemed capital structure is 60% debt and 40% common equity. The average cost of

debt is 4.79%, while the average cost of equity is 9.71%. Overall weighted cost of capital (WACC) is

6.76%, with a rate base calculated at $6,477M. The return on capital is $438M, income taxes total

$55M, cost of service is $918M (comprised of OM&A at $564M and Depreciation of $354M), resulting in

a revenue requirement of $1,411M. Glenn noted that rate base reflects audited 2012 financials.

At this point Roger Higgin, Energy Probe Research Foundation, asked for the 2013 revenue requirement.

Ryan Lee, Hydro One, answered that the IRM based total was $1,223M.

Glenn moved to a bar chart showing the distribution rate increases from 2013 to 2019 inclusive and

their principle drivers. From a historical perspective he noted that there was no increase in 2012, and

the Board approved increases in 2013 of 1.4% and 2.6% in 2014.

Julie Girvan, Consumers Council of Canada, asked why there are still riders in 2015 to 2019 even though

the smart meters and smart grid riders would have been eliminated by 2015. Ryan Lee explained that

some of the regulatory accounts have surplus balance and some have deficit balance. In this case, there

is a net deficit balance of all accounts for disposition and it is to be recovered from rate payers through a

rider in 2015.

He then pointed to the requested large increase of 11.5% in 2015 indicating that it is made up of 18.5%

from four increasing components: rate base at 12.8%, OM&A at 2.6%, Rate Reclassification at 1.8% and

1.2% for changing rate riders. Those increases are being offset by 7.0% attributable to decreasing

components such as the discontinuation of Smart Meters and Smart Grid riders. He noted that the very

large rate base component is a catch‐up of 4 years of Capex at about $600 Million per year and

depreciation at about $300 Million. As a result, the 2015 rate base increase is approximately $1.2

Billion.

Glenn tried to further clarify the changes by saying that the Smart Meter and Smart Grid components

will effectively be moving into rate base and OM&A, representing 4.5% of the total 12.8% rate base

increase and almost all of the 2.6% OM&A increase.

Hydro One is projecting increases for 2016, 2017, 2018 and 2019 to be 7.4%, 3.6%, 3.0% and 2.9%

respectively. Glenn pointed stakeholders to two important characteristics of requested rate change in

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this period, first that rate increases due to rate base will remain very consistent and reasonably low at

between 4.2% and 3.5%, and second that OM&A actually shows a declining trend over the period.

Glenn then addressed Hydro One’s concern about the customer impact of the large 11.5% increase in

2015. To mitigate that impact, Hydro One is proposing a rate smoothing strategy that would bring the

2015 increase down to 7.0%, with similar increases of approximately 7.0% for 2016, 2017, 2018 and

2019.

Glenn then presented specific revenue requirement financial projection amounts, reflecting the

percentage gains and offsets described above. He noted that the financials do not exhibit any rate

smoothing impacts, nor do they include any load impact effects. The highlights pointed out by Glenn

include OM&A costs of $564M, $610M, $614M, $604M and $600M for 2015, 2016, 2017, 2018 and

2019, respectively. Other highlights include revenue requirements of $,1,367M, $1,470M, $1.525M,

$1,570M and $1,621M for 2015, 2016, 2017, 2018 and 2019, respectively.

Glenn moved on to discuss regulatory asset figures, which breaks down to a total of $40.4M to be

recovered in riders over the next 5 years. The major components as described by Glenn include pension

($55.6M), OEB ($9.1M), smart meters ($6.5M), tax (‐$20.7M) and the retail settlement variance account

(RSVA) (‐$6.2M). He explained that the total amount would represent approximately $8M in riders in

each of the next five years.

Glenn then presented a bar chart similar to the one presented earlier showing the projected rate

increases, except in this case, it depicted how Rate Smoothing would be used to establish a steady 7.0%

rate increase in each of the five years from 2015 to 2019. He pointed that a deferral account that would

be used to postpone rate recovery from the first year and the under‐recovery and over‐recovery in each

year, emphasizing that the balances in the deferral account would be subject to interest costs to

ratepayers until the smoothing efforts were completed.

Susan Frank, Hydro One, interjected to point out that the Hydro One board struggled with proposing an

increase as steep as 11.5%. However, the primary elements contributing to the increase are related to

accumulation from previous years’ investments in capital assets; therefore the rate smoothing was

being proposed as an alternative rate recovery method for the OEB to consider, keeping in mind the

mandate of protecting Ontario energy consumers. Susan pointed out that rate smoothing is a practice

commonly used in the United Kingdom, exhibiting recognition to the customer desire for stable energy

bills. Susan stressed that Hydro One was not pushing this smoothing strategy (7% steady over five

years) over any other rate recovery pattern, and as always was seeking to work in partnership with the

OEB and Ontario stakeholders. Another pattern could be higher in the beginning and lower at the end.

She restated the point made earlier by Glenn that any deferral of the requested 11.5% increase in 2015

will invoke borrowing costs and will therefore represent a more costly option to rate payers. As such

Hydro One would be open to proposals that Rate Smoothing not be applied or that it be modified to

reduce carrying costs.

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Glenn added that if Stakeholders and the OEB accepted the Rate Smoothing proposed in this

application, that the year 2020 would see this deferral account recovery drop off entirely, potentially

leading to lower rates depending on other cost pressures.

Peter Thompson, Canadian Manufacturers & Exporters, asked how transmission costs contributed to the

current discussion. Susan explained that transmission filings will take place in the spring of 2014.

John McGee, Federation of Ontario Cottagers, then asked if borrowing costs as related to the rate

smoothing process would have any effect on the organization’s overall debt to equity ratio. Glenn

replied there would be no change to the debt to equity ratio.

Mark Garner, Vulnerable Energy Consumers Coalition, then asked if borrowing costs would be in the

tens of millions, perhaps even hundreds of millions. Ryan Lee responded that no, the sum would not be

in the tens of millions, it would be a smaller amount.

Roger Higgin asked a question regarding the relationship between increased distribution rates and

actual revenue requirement increased year over year. Glenn replied that all references to “Rate

Increase” in the previous slides were really referring to revenue requirement increases, and therefore

rate increases to individual customer classes could vary from that and Henry Andre would go in to more

detail later in the session.

Tom Ladanyi, Ontario Power Generation, remarked that TransCanada had recently received approval for

a similar deferral account and were allowed to claim an equity return on balances, he asked if Hydro

One was expecting that on this smoothing deferral account? Susan replied this was not the plan, Hydro

One assumed standard regulatory asset treatment.

Glenn proceeded to summarize OM&A and capital expenditures. He explained that Paul Brown would

later speak to sustaining, development, operations and customer service for both OM&A and capital

expenditures while Glenn would review the somewhat less substantial categories of corporate common

costs as well as property taxes and rights payment.

At this point Mark Garner asked if overall, OM&A and capital expenditure financial projections were in

line with previous years. Glenn replied yes, very much so.

Glenn started by saying that corporate common costs generally move up and down with the work

programs, but the Hydro One Board’s emphasis on efficiencies and productivity has led to the forecast

for common costs showing a decline from 2015 to 2019, despite an increase in Hydro One work

programs. He then described corporate common costs allocated to Distribution, which for OM&A

expenditures are projected as $67M for 2015 and $62M for 2016 through 2019. For capital

expenditures, corporate common costs allocated to Distribution range from $85M in 2015 to $82M in

2019, with little deviation in subsequent years.

Glenn then went into detail with respect to corporate common costs as presented within a transmission

and distribution allocation context. He discussed that time studies were conducted to derive the

8



allocation of these costs. Within OM&A corporate common costs, Glenn noted a slight movement in

transmission and distribution allocations between forecast 2013 and bridge 2014 years in total costs, to

reflect a one‐time provincial tax credit of $40M for 2013. He went on to explain the 2014 total sum of

$144M is due to a drop in distribution allocation of $30M (primarily due to the completion of the CIS

project) and no repeated tax credit on the transmission side. The 2015 total sum of $137M (decrease of

$7M) is the result of changes in regulatory costs and an environment provisions reduction.

Julie Girvan asked Glenn if Hydro One was prepared to “live with” these forecasts for rate purposes and

Glenn replied “Yes”.

Glenn concluded by stating that the details of the corporate common costs slides would be available in

the second of the two planned filings. The high level information, as presented by Glenn, will be

available in the December filing.

Bob Betts commented that the meeting was moving along very well and rather than taking an early,

morning‐break he invited Paul Brown to begin his presentation.

5. Core Work Program by Paul Brown, Director Distribution Asset Management, Hydro One Networks and Facilitated Discussion by Bob Betts, Facilitator, OPTIMUS | SBR

Paul Brown began by outlining what he intended to cover during his presentation. This included an

overview of both OM&A and capital expenditures; specifically, sustaining, development, operating and

customer service details within both expenditure categories.

Paul then provided the audience with context surrounding the upcoming application and Hydro One

Distribution’s asset base. Hydro one serves approximately 1.2M distribution customers comprised of

both rural and urban (mostly rural) residential and small business, local distribution companies, large

industrial customers and generators connected to the distribution grid. Paul specifically noted

generators as a growing customer base within the network. With respect to assets, Hydro One owns

over 120,000 circuit‐km of lines (approximately 3200 feeders), 1.6M poles, 1004 distribution stations, a

rural system with low density throughout Ontario and a radial system with limited transfer capability.

Paul explained primary goals, with respect to the management of distribution assets, centered on sound

investment strategies to ensure safe, reliable and efficient power delivery and to create and enhance

value for customers. Paul outlined that projects and programs are developed to address customer and

system growth needs, renew assets at the end of their life to ensure public/worker safety and service

continuity and improving reliability and efficiency throughout the organization. Paul also stressed other

priorities include the modernization of the distribution system to add customer value and effectively

responding to unplanned system events.

Paul then described the four primary components of the OM&A expenditures summary, which include

sustaining, development, operations and customer service. Investments within sustaining are the most

significant cost driver, with 2015‐2019 test period costs ranging from $329M to $380M annually. The

9



second most significant cost driver is customer service, accounting for between $115M and $118M

annually over the five year period under study.

Paul delved deeper into the sustaining cost category within OM&A expenditures, which includes cost

sub‐categories of stations, lines, metering and vegetation management. Specific cost items include

planned and corrective maintenance, trouble call response, line clearing and brush control, cable

locates, disconnects and reconnects, environmental and waste management. Costs related to stations

are predicted to remain quite stable at $28M to $29M per year over the five year test period, which Paul

noted is in line with the range of previous years of approximately $26M to $27M. Lines related costs are

expected to rise slightly, with a range of $141M to $157M over the test period, up from $148M in

forecast year 2013 and $134M in bridge year 2014 in order to address the ramp up in PCB testing of pole

mounted transformers to meet mandated government PCB requirements.

Paul then explained that metering expenditures rise in bridge year 2014 to $19M, up from $14M in

forecast 2013, and are projected to stay constant at $19M throughout the test period, which Paul noted

was the historical cost level. The return to more traditional spending levels is due to the dispensation

that Hydro One received from Measurement Canada for meter reverifications on some 2008 – 2014

meters expires.

Vegetation management expenditures are ramping up in 2016 and 2017, then tapering back down for

2018 and 2019. The ramp‐up is required to address a backlog in tree clearing, in order to allow Hydro

One to move to an 8‐year vegetation management cycle. Paul explained that a shorter vegetation

management cycle duration has been shown to lower SAIDI although the costs to achieve improvement

in this cycle are significant.

Paula Zarnett, Rogers Cable Communications asked if Hydro One would be filing a benchmarking study

on vegetation management. Lyla Garzouzi, Hydro One, indicated that a study would not be filed

highlighting that a study was filed in the EB‐2009‐0096 proceeding and the same conclusions are still

applicable.

John McGee, Federation of Ontario Cottagers asked where the savings will come from with respect to

the 8‐year vegetation management cycle. Paul indicated that once on an 8 year cycle, we see savings as

we go through the next cycle. Vegetation management becomes more of a pruning small branches

effort than a major delimbing and tree removal process.

Moving on from the sustaining component, Paul addressed the remaining three primary areas of

development, operations and customer service. Development OM&A cost projections range from $15M

to $18M within the test period, in line with bridge year 2014 at $18M. Development OM&A costs

include engineering and technical studies (including smart grid studies), standards and technology

support and distributed generation connections support. Operating OM&A cost projections range from

$30M to $41M over the test period, up from $23M in forecast year 2013. The increase is due to the

smart grid pilot assets, such as the DMS, becoming part of normal business and needing to be

10



maintained. Operations costs include operations support, maintenance of operating infrastructure and

environmental, health and safety.

Customer service cost projections are a more significant contributor to OM&A expenditures and range

from $113M to $118M over the five year period, down from $137M in forecast 2013 and $134M in

bridge 2014. Customer service costs are comprised of customer services, smart grid pilot and

conservation and demand management.

Paul shifted in to discussing smart grid OM&A expenditures. He outlined that in an effort to provide

some visibility to the Smart Grid OM&A, we have created a view for these expenditures that was

included in the numbers in the slide under Operating and Customer Service expenditure categories. He

explained that the contributing factors to total smart grid expenditures are smart grid pilot costs and

deployment costs. Smart grid pilot costs taper over the test period, from $5M in 2015 to $0M in both

2018 and 2019. Deployment costs increase, ranging from $5M to $17M throughout the period, as

technologies that show cost effective benefits will be further deployed to deliver customer value and

operational benefits.

To conclude the OM&A section, Paul discussed the primary drivers of changes in OM&A costs. Aging

assets and systemic problems are a significant factor in forecast costs, including issues such as large

scale testing of transformers for PCB contamination as well as an increased focus on defect corrections.

Another significant factor to changes in OM&A costs is reliability improvements and long‐term cost

optimization; a key issue in this area is addressing vegetation maintenance backlogs and maintaining an

eight year clearing cycle. At this point Paul explained that he had come to the end of the presentation

as it pertains to OM&A costs, and opened the floor to questions, before addressing the capital

programs.

Harold Thiessen, Ontario Energy Board asked Paul what was the cause of the vegetation maintenance

backlog mentioned earlier. Paul explained that it is partially funding and partially work management,

which has been exacerbated by several large, unpredicted storms.

Shelley Grice, Association of Major Power Consumers of Ontario asked Glenn a question about one of

his slides which indicated that environmental costs were going down while this presentation indicates

they are rising. Ryan Lee, Hydro One replied by saying that the corporate cost allocation for

environmental costs relates to amortization which is going down, however, the environment costs

themselves are going up, it is a matter of how it gets classified within the internal structure.

Paul then moved on to the capital expenditures segment of his presentation, again focusing on the four

primary cost groups of sustaining, development, operations and customer service. He started by saying

that most of the sustainment capital spending pressure facing Hydro One results from the bow wave of

aging assets. The costs are expected to rise significantly over the test period, ranging from $208M in

2015 to $383M in 2019. Sustaining capital expenditures are divided into Stations, Lines and Metering.

Principle cost sub‐categories include station refurbishments, mobile unit substations, component

replacements, trouble call and storm damage response, large sustaining line projects and meter

11



upgrades. Paul explained that Lines and Stations expenditures will be discussed in more detail shortly

but that metering capital expenditures are decreasing substantially as the Smart Meter project winds

down. Offsetting this will be an upgrade to metering telecommunications infrastructure that will be

completed by 2018.

Paul then explained that the total fleet of distribution poles is approximately 1.6 million, with an average

expected service life of 62 years. Each year approximately 20,000 poles are installed, a figure that

includes both new installations and end of life replacement. Paul stated that Hydro One is proposing

increased funding to address premature decay issues and mitigate the risk of the approaching new wave

of poles reaching expected service life over the period. Paul continued to explain that Hydro One

maintains 1,004 distribution and regulating station facilities, with an average expected service life of 50

years. The historical replacement rate is approximately four stations per year, and Hydro One is

proposing increased funding in this area to manage demographic pressures building up in order to, once

again, mitigate the risk of the approaching bow wave of stations reaching expected service life over the

period. Hydro One believes it must step up the station replacement program to eventually be replacing

forty stations per year.

Paul then shifted from sustaining to discuss development, which includes four primary cost sub‐

categories including connections and upgrades, system capability reinforcement, generation

connections and wholesale revenue meters. Development capital costs are made up primarily by new

connections, upgrades driven by load growth, reliability improvements and capital contributions to new

transmission connection capacity. The most substantial contributors to development capital are

connections and upgrades and system capability reinforcement, ranging from $109M to $123M and

$61M to $81M, respectively, over the 2015‐2019 test period. Paul explained that system capability

reinforcement expenses are relatively stable with the exception of required payments (capital

contributions) that must be paid for Transmission improvements. Generation connection expenditures

will ramp down as the amount of connections is expected to decrease.

Paul then discussed operating and customer service capital. Operating capital is comprised primarily by

upgrades and expansions to the operating infrastructure and control facilities, while customer service

capital is made up primarily by smart grid pilot costs. Paul explained a spike in 2016 operating expenses

is due to the Backup Control Centre new facility development project. Paul then spoke to customer

service capital and the declining spending in 2017 resulting from the winding down of Hydro One’s

Smart Grid pilot project and deployment expenditures will increase as cost effective technologies will be

implemented. Paul stressed that Hydro One’s approach embraced cost effective technologies that, by

design, drive both customer value and operational benefits.

To conclude his presentation, Paul reviewed the significant drivers to year over year changes in capital

costs. He discussed aging assets and systemic challenges including the increasing replacement rate of

wood poles, refurbishing aging distribution stations and replacing PCB contaminated equipment, as

mentioned earlier in his presentation. He also again spoke to reliability improvements and long term

cost optimization, including the increasing number of line refurbishment projects.

12



Mark Garner asked a question regarding the sustainment budget, noting that 2016 exhibited

acceleration in forecasted budget for lines relative to previous years. Paul responded that this is

primarily due to a necessary ramp up of the pole replacement program. Mark then asked why this

acceleration was taking place, and why the ramp up was not conducted in a more uniform manner. Paul

explained that the plan does ramp up replacement quantities each year so that an additional 5000 EOL

poles will be replaced per year by 2019. Mark again asked a question regarding the proposed timeline,

and why this ramp up did not begin five years prior. Lyla Garzouzi explained that age demographics play

an important factor, contributing to a huge spike going back to the 1950’s. At the end of 2011 an asset

inventory was completed, and the detailed poles age information largely led to the proposed

replacement ramp‐up. She confirmed that ultimately the ramp up is designed to achieve specific yearly

replacement levels, as mentioned earlier.

That completed Paul’s presentation. Bob Betts asked if there were any other questions for Paul and

there were none at that time so the group took their morning break.

10:35 AM Break

Bob Betts called the meeting back to order and asked if there were any questions that had occurred to

stakeholders during the break.

Roger Higgin asked a question regarding in‐service assets in relation to rate base, wondering if Hydro

One could mitigate rates by somehow adjusting the revenue requirement for a given year by reflecting

those projects that failed to go into service in the year in which they were planned to. Susan Frank said

they were not considering any kind of a variance account to do that and more importantly she was very

comfortable that they could control this spending to ensure there was no slippage.

John McGee then inquired as to the dual filing strategy from the perspective of Intervenors having

ample time to review filings at both stages. Allan Cowan answered that Hydro One is determined to

ensure that all parties will have ample time to address the various phases of the application and their

respective deadlines.

Susan then asked Allan to provide additional details regarding the first planned filing. Allan briefly

explained that the first stage will include rate base, proposed rates and revenue requirement. It will not

contain detailed support for capital expenditure and OM&A, which will be included in the second filing.

Mark Garner then asked if the OEB will issue a standard notice regarding the appeal process, and when,

given the dual filing strategy. Allan responded that discussions are underway, but hopes the notice will

be provided following the first filing.

That concluded this round of supplemental questions and Bob Betts introduced the next presenter

Henry Andre, and explained that Henry will review cost allocation and rate design issues.

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6. Distribution Cost Allocation / Rate Design by Henry Andre, Manager Distribution Pricing, Hydro One Networks and Facilitated Discussion by Bob Betts, Facilitator, OPTIMUS | SBR

Henry Andre thanked the audience and briefly reviewed the material he planned to cover, including load

forecast, customer classification, cost allocation, rate design and bill impacts.

He began by indicating that the load forecasting methodology will be the same as in previous

distribution applications; he then addressed the load forecast assumptions. All forecasts are weather‐

normalized based upon 31 years of weather data, and are based on an Ontario economic growth

forecast of 2.4% over the 2015 ‐ 2019 test period. CDM forecasts assumptions are consistent with the

OPA’s Long Term Energy Plan, which is expected to be updated very shortly. When the updates become

available, the CDM forecast will also be updated. Finally the latest Smart Meter hourly data for 2012

was used to update load profiles in determining the cost allocations by rate class.

Henry then graphically displayed the chart showing forecast customer growth together with the load

forecast for 2015 to 2019. He indicated that the customer growth forecast is consistent with Hydro

One’s typical 10,000 to 15,000 additional customers per year. The forecast load in GWh shows little

change in 2015 to 2017, with a slight decline in years 2018 and 2019.

Harold Thiessen, Ontario Energy Board, asked if there had been any significant changes in load profiles

with the application of the 2012 hourly Smart Meter data which he believed was a new source of data.

Henry confirmed that this is a new source of data and he doesn’t know yet how significant changes are.

Alfredo Bertolotti, Power Workers' Union, then asked a question regarding the recently mentioned 2.4%

Ontario economic growth forecast assumption. This was answered by explaining that the assumption

comes from a mix of forecasts from both government and financial institutions.

John McGee then commented that the forecasted decline in demand (consumption) seemed a bit

ambitious, and asked if this chart will be updated throughout the five year test period. Henry deferred

to Susan Frank, who answered that the LTEP updates that Henry referred to would lead to a filing

update, they had not planned at this point to make annual updates to load forecast during the plan;

however, she would welcome further discussion about this in the afternoon during the discussion about

Annual Adjustments.

Henry then discussed customer classification and associated revenue impacts from classification

changes. There are three processes which will lead to potential changes to Customer Classifications. The

first is the Board‐directed Rate Class Review spoken about in previous stakeholder sessions, which

applied new GIS information to Hydro One’s density requirements, within the entire service territory to

see if any classification changes were required to align customers with Hydro One’s current definitions.

The review will result in 135,000 of Hydro One’s total 1.2 million customers changing rate classes. The

vast majority, about 111,000 will be moving to classes with lower rates, and the remaining 24,000

moving to higher rates. This largely results from the growth of previous smaller communities now

becoming dense enough to move to classes with lower rates. This change would result in a revenue

14



reduction of $39.7 Million. Henry noted that many customer bills would be lowered as a result of the

changes; however rates across all classes would increase by 3.4% to keep the change revenue neutral.

John McGee asked if the review included all classes and Henry confirmed that it did.

Mark Garner pointed out that the results show that while 111,562 customers are moving to lower rates

resulting in a $81 million revenue requirement reduction, 23,685 customers would be facing a total $41

million revenue requirement increase, and that looks like a very significant rate increase. Henry

confirmed that many of those 23,000 customers would be facing very significant increases.

Julie Girvan asked about the 3.4% increase facing all rate classes resulting from the reclassification and

how that compared to Glenn Scott’s earlier slide 15 which showed only a 1.8% impact from these

changes. Glenn Scott replied that the 1.8% was after adjustments for load forecasts and the other two

rate classification changes.

The second process was the Board‐directed review of Seasonal customers which also came out of the

2013 IRM Settlement agreement. Henry explained that approximately 11,000 of the total 157,000

seasonal customers exhibiting total consumption and monthly consumption patterns similar to those of

full time residential customers would be switched to a residential classification. The resulting decrease

of $6.7M in revenue would translate to an average increase of 0.5% across all rate classes.

Julie Girvan asked Henry to confirm that the rate reduction for 11,000 seasonal customers would result

in a rate increase for the remaining seasonal customers that do not change. Henry confirmed that there

would be a slight increase but that a later slide will show that it is not unlike the change seen by other

rate classes.

John McGee asked Henry to confirm his opinion that this new approach to defining the rate class would

require Hydro One to provide new definitions for certain rate classifications; Henry confirmed that

Hydro One would be doing that, particularly for the seasonal class.

Peter Thompson asked Henry to confirm that these to Rate Classification changes would by themselves

represent almost a 4% increase to manufacturers. Henry confirmed that taken independently of all

other changes these two would be almost 4%.

Mark Garner followed up on his previous question about the 24,000 customers facing large increases

from the Rate Class Review, asking if any would exceed a 10% increase and if yes, would Hydro One be

considering rate mitigation for those customers. Henry answered yes and yes to the two questions, and

that approximately 1000 customers will likely need rate mitigation consideration.

The third rate classification change would be the creation of an Unmetered Scattered Load (USL) rate

class as per the Board’s 2011 cost allocation review which suggested that all utilities create separate USL

rate classes and Hydro One will be doing that in this application.

15



In response to a question from Julie Girvan, Henry confirmed that this change will only affect the

General Service rate class since all USL customers are in that class, and the change will be revenue

neutral within the GS and USL classes.

Henry then described a number of important improvements that will affect cost allocation calculations

in this application. These included:

Hydro One will be using the Board’s latest Cost Allocation Model (“CAM”) which includes a

number of changes that the Board had incorporated as a result of their last reviews.

As was mentioned earlier, Hydro One will be using updated customer load profiles based on

2012 Smart Meter data.

Incorporating new Density Factors approved in their 2013 IRM Settlement Agreement.

Improvements to tracking of costs by US of A break‐out.

Updated Billing and Services factors as required by the Board’s most recent CAM.

Addressing a number of issues raised at previous applications; things such as allocation of direct

costs, and others.

All of these will be discussed in much greater detail in the application evidence.

Henry then moved on to discuss rate design issues, explaining first that there is an increasing share of

revenues that will be recovered through fixed charges, moving from 39% fixed and 61% volumetric

charges, to 42% fixed and 58% volumetric. This change is again consistent with the Board’s latest CAM.

This percentage is at the total level, fixed versus volumetric ratios will vary at the rate class level.

Julie Girvan questioned the jump at some of the class levels and Henry confirmed that some could see

substantial jumps in their fixed portions, for example UR and R1, with UR moving from $13 to $20 and

seasonal going from $20 to $25. Julie warned that there will be significant reaction to those levels of

change in the fixed component to the smaller customer with variable usage patterns.

John McGee agreed with Julie’s concern and suggested that Hydro One might want to consider phasing

this change in over a longer period of time like 4 or 5 years.

Hydro One will be proposing to move cost ratios for all customer classes to 1.02 to 0.98 phased‐in over

the five year period.

The application will include several new riders associated with new deferral and variance accounts, as

well as a rate smoothing rider proposed to mitigate rate impacts.

The final item regarding rate design in this application is that it will include an RTSR reflecting the

proposed 2014 Provincial Transmission rates.

Henry finally moved on to discuss the resulting Bill Impacts, first the average 2015 bill impact

components across all rate classes. The total average distribution impact will be 7.0%, representing 2.3%

on the Total Bill. The most significant contributor to these figures is revenue requirement generating a

15.5% increase in distribution rates or 5.2% on total bill, followed by the net result of Rate Classification

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and Forecast changes creating a 1.8% increase in distribution rates and 0.6% on the total bill. These are

offset to some extent by new account riders and the smoothing rider, reducing distribution impacts by

5.8% and total bill by 1.9%, and distribution impacts by 4.5% and total bill by 1.6% respectively.

Julie Girvan asked how these figures compare to the 11.5% total increase as presented by Glenn in the

bar chart on slide 12. Susan Frank answered that these figures represented the smoothed version so the

total remains the same. Henry commented that the figures are from a consistent set of numbers and do

not impact the accuracy of Glenn’s earlier numbers.

John McGee asked if these bill impact estimates for 2015 included HST or any additional fees, to which

Henry explained that yes, the estimates presented were bottom line impacts.

To conclude, Henry presented total bill impacts by rate class based upon generally accepted typical

consumption levels. Henry pointed out that the wide variation seen in 2015 was primarily due to

movement toward a 1.00 revenue to cost ratio for each rate class, moving some up and some down.

Julie Girvan asked why it appeared that the smoothing process began only in 2016, and not 2015. Henry

responded that smoothing was applied in 2015 across all rate classes but in 2015 we are also seeing the

impact of bringing the revenue to cost ratios within Board limits.

John McGee then asked if other consumption levels were considered. Henry replied that there will be

three figures for each rate class, high consumption, typical consumption and low consumption within

the filed evidence.

Henry concluded by thanking the audience, asking if there were any further questions, and proceeded to

introduce Benjamin Grunfeld, Navigant Consulting Inc., and explained that Ben would present the most

recent findings of the line loss study.

Benjamin Grunfeld, Navigant Consulting Inc., Line Loss Study Update

Ben began by stating that actual losses within the 2010‐2012 time period were under study and that the

study would provide recommendations regarding Hydro One’s reporting of variances of actual losses

going forward. Ben also noted that individual losses related to specific rate classes were also examined.

The initial focus was solely on the 2012 calendar year, due to the availability of hourly consumption data

for the majority of Hydro One’s customers through smart and interval meters. Ben explained the six

primary components to the line loss calculation that acted as the study’s source data; on both the

purchases side and the consumption side. Ben indicated that essentially, total purchases minus metered

consumption, is equal to the line losses for a specific period.

Ben made it clear that the calculation of 2012 losses required the analysis of a large quantity of hourly

consumption data, and that this was not the standard approach used in the industry. The majority of

utilities rely upon consumption data direct from their billing system, which is generally available on an

aggregate basis for an individual customer’s billing cycle. Annual consumption between January 1 and

December 31 is calculated by summing the consumption that occurs between the first and last actual

17



meter read. This calculation is then combined with an estimate of the proportion of consumption in the

last billing cycle before the first meter read that occurred within the year, as well as an estimate of

unbilled consumption after the last actual meter read. Ben explained that unbilled consumption is

typically estimated based on individual customer’s prior billing period consumption. Ben went on to

state that implementing this common approach over a number of years significantly reduces the

percentage of consumption that is estimated.

Ben went on to explain that Navigant’s recommendation to Hydro One is to estimate customer

consumption using the capabilities of the new Customer Information System (CIS), and to use that with

the purchase information to determine actual annual losses on a going forward basis. The CIS is able to

provide unbilled consumption for Hydro One’s 1.2M customers as of December 31st of each year. This is

made possible by the CIS developing a kilowatt‐hour per day metric during a specific base period and

then applying this base to an unbilled period. Ben believes that using this method will provide results

similar to the approach implemented using 2012 hourly consumption data. The base period is developed

using one of three methods listed below, depending on the availability of the necessary data inputs:

1. Consumption in the same billing period in the previous year

2. Consumption in the previous billing period

3. Consumption estimated by customer class

Ben also explained that the level of hourly data that was used to calculate actual losses in 2012 is not

available for prior years. Interval metered customers, those for whom hourly consumption data would

be available throughout the period, represent approximately 20% of total consumption. Customers with

smart meters and automated meter reads in 2012 represent approximately 50% of consumption. In

2010 and 2011 the proportion of customers with smart meters and automated meter reads would be

lower. Ben wrapped up with these final thoughts; as the amount of hourly data available declines, the

reliance on billing cycle data increases. As a result, Navigant recommends calculating the actual losses in

2010 and 2011 using an approach consistent with the approach that will be used going forward,

estimates based upon billing information adjusted to account for the billing date. As stated earlier,

Navigant expects that this approach will yield similar results when compared to the approach

implemented using 2012 hourly consumption data.

Ben then asked if there were any questions.

John McGee asked if the source data can be broken down by customer class. He noted that Hydro One

differentiates loss factors by class, which is perhaps unique in industry. Ben replied yes, sales can be

broken down by class with minimal effort; however, the challenge is when power comes in to the

system, one cannot discern from where it comes and where that same power ultimately ends up. This

creates difficulties in terms of calculating loss factors for individual rate classes. Susan added that this

issue is to be examined within Navigant’s final report, and will be included in the filed evidence. The final

Navigant report is expected to be completed in January, 2014.

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Susan needed all present to be aware that Ben was here to recommend a way for Hydro One to

determine line losses in 2010 and 2011, since clearly Hydro One has not been able to track losses during

that period. Prior to 2012 Hydro One’s capabilities were significantly less than present day. So Susan

asked for Ben to repeat his final recommendation on how to handle 2010 and 2011.

Ben reiterated that to do a 2012 type of analysis relies on a great deal of calculation based upon a pool

of dependable hourly data. That data is not available for 2010 and 2011, and the calculation required to

do it in the future is not warranted based on the quality of the results achieved. So Navigant’s final

recommendation is for Hydro one to rely more heavily on billed meter data that is available on a billing

cycle basis. For 2010 and 2011, Navigant is recommending a similar approach to the “going forward”

recommendation.

Peter Thompson asked if Hydro One had an account to collect losses from prior years. Ben responded

that Navigant’s study will identify the variance in terms of approved and actuals in both KWh and

dollars. It is then up to Hydro One and the Board to determine where that gets reported and if and

when it ever gets collected.

Mark Garner asked if he was correct that Navigant will compare the study done with the 2012 hourly

data to show that it provides results that are not significantly different from results generated from

billing data, using CIS capabilities to adjust consumption to the year end, and the proposal of the hybrid

methodology (using the old approach, but adjusting for the billed consumption versus actual

consumption at year end) does not represent a material change. This is particular true today with the

added features of Hydro One’s new CIS.

This should give all parties comfort that going forward, consumption determined from adjusted billing

data can be relied upon to reasonably estimate line losses.

Mark asked if there was any real advantage in smart meter hourly data with respect to cost savings for

consumers. Ben noted that this is not common practice amongst most utilities in Ontario currently,

rather utilities use the approach discussed throughout his presentation.

There were no further questions or comments and the group broke for lunch.

12:15 PM Lunch

7. Custom Framework – Adjustments and Reporting by Allan Cowan, Director Major Applications,

Hydro One Networks and Facilitated Discussion by Bob Betts, Facilitator, OPTIMUS | SBR

Bob Betts welcomed parties back and began the afternoon by reminding parties that in the morning

they heard numbers and the impacts associated with this application and they clearly have a sense of

the magnitude of the filing. The afternoon session is aimed at using that knowledge and applying it to

the items that have not yet been determined in finalizing the application. These things include the

reporting and measurement of outcomes, what should be included in annual adjustment process, what

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are appropriate off‐ramps and what kind of things can be considered for recovery during the plan as

“Adjustments Outside of Normal Course of Business”.

He then invited Allan Cowan back to the podium and indicated that both Allan and Susan Frank would

be participating in this afternoon’s interactive session. Allan began by explaining that the session will

include four principle focus areas: Annual Reporting and Outcome Measures; Annual Adjustments, Off

Ramps and Adjustments Outside of the Normal Course of Business. He emphasized his hope that

everyone would be able to provide their input regarding how Hydro One can address these areas in its

application.

Beginning with Outcome Measures, Allan first explained the criteria that Hydro One is using to evaluate

effective outcome measures, these included:

The chosen outputs must allow Stakeholders to monitor key outcomes committed to in the application

Metrics need to be measurable, controllable, transparent, and not overly complicated”

There must be a manageable number of metrics.

Allan’s next slide presented “Examples of Distribution Outcome Measures” Allan explained that these

are examples of the kinds of outcomes that could be measured and what metric might apply to each.

The examples included:

Customer Focus o Customer Satisfaction (i.e. % satisfied)

Operational Effectiveness o System Reliability (i.e. # kms of forestry brush control & line clearing) o Asset Management (i.e. % of in‐service capital to forecast) o Overall Cost Performance (i.e. % OM&A / gross fixed costs)

Public Policy Responsiveness o Conservation Demand Management (i.e. Net Annual Peak Demand Savings (MW)) o Renewable Generation (i.e. # of connections, etc.)

Financial Performance o Liquidity (i.e. current assets / current liabilities)

Julie Girvan asked how this reporting of outcomes was different from the OEB Performance Scorecard

being established by the Board. Susan Frank responded saying from Hydro One’s perspective they are

two different things. She feels that the OEB Performance Scorecard is intended to measure performance

over the long term against the OEB’s expectation for all utilities. The Outcome Measurement concept is

to allow stakeholders and the OEB to evaluate whether the utility delivered the Outcomes they said they

would in their particular long term rate plan, in this case 2015 to 2019. What “outcomes” did the

spending promise and were they delivered. Susan directed the question back to participants “What do

you and customers want us to report on and be measured against?”

Mark Garner states that the majority of customer surveys show the same “motherhood” issues: “We

want lower prices and more service” and therefore have little value as a metric for their satisfaction. He

indicated that his clients would want to know what the objectives are relative to the spending included

in the plan, and then reporting on whether Hydro One is meeting or has met those objectives. For

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example, a large amount of money is to be spent on vegetation control, what is Hydro One’s goal in

doing that: lower or stable SAIDI/SAIFI results, lower long term costs, reduced number of tree‐caused

outages, etc.? Once the goal is established, next choose the metric that can evaluate it, i.e. SAIDI/SAIFI

reports, trends in tree management spending forecasts, hours or dollars spent clearing away storm

damage, etc. He added that Hydro One should share what metrics will be used to measure success with

consumers.

Mark added that with respect to the customer focus category, there is too much focus on initiatives that

are designed to show that Hydro One is a ‘good company’, for example the wide range of corporate

social responsibility initiatives undertaken by Hydro One.

Julie Girvan then stated that the outage issue should be a key focus of the outcomes reporting and the

communication of outage maintenance efforts should be evaluated by customers. She said that in rural

areas customers need to be kept abreast of outage developments. She noted that somehow measuring

this aspect of customer service would be ideal, keeping in mind that customers want reliable service at a

reasonable rate, and not much else.

Roger Higgins agreed with Julie, and added that customer centric performance measures should be the

primary focus of any scorecard developed in the future. Susan asks for clarification, and Roger explained

that scorecards are usually not class specific, but that the technology needed to provide this additional

information is already in place. He again stressed the importance of customer focus.

Peter Thompson added that distribution related bill stability is desired from industrial and small business

clients. He then suggested that sharing five years of distribution financial information, budget and

actual, by rate class, would be a level of transparency that would be much appreciated by consumers.

Mark then suggested that when outages occur, regardless of type of outage, perhaps surveys be

completed by affected consumers in order to find out how well the situation was handled, how well

consumers were able to understand what was happening surrounding the outage, and so forth. Susan

responded by using an example of bringing a car in for service; she stated that a couple days after the

return of your vehicle, the dealership asks if you were happy with service. Susan stated that she is not

sure how well that style of approach determines if initial goals were actually met.

Lisa Brickenden, Ontario Energy Board, suggested a transactional survey to maximize reporting results.

She stressed that surveys should have subject matter aligned with desired outcomes. Susan responded

that the challenge is measuring how well the initial objectives were understood by the consumer. It is

very simple for a consumer to look at their individual situation and report poor performance, while the

overall initial performance objectives may have been met or exceeded. Susan returned to the example

of bringing your vehicle in for a service check, and said that dealerships target a 70% positive feedback

level. Susan stated that a similar model could be considered, by asking consumers if a particular

transaction met their expectations.

Mark then repeated that the key elements of an effective strategy are to know if consumers at large are

satisfied or unsatisfied with service levels in the face of an outage, and that these are more likely to be

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measurable by transactional surveys than with general surveys. Mark added that the operational

outcome measurements will report on how frequently problems occur and allow Hydro One to make

improvements there; and while that is important to customers, customer satisfaction can be best

measured by how well the problem was handled.

Lisa then pointed out that in past studies, it has been noted that the earlier the consumer is contacted

or made aware of outage information, the more tolerant they are in terms of being satisfied with the

end result.

Ruth Greey, Hydro One, Senior Regulatory Advisor, pointed out that Hydro One already conducts a

variety of transactional surveys, particularly with large industrial consumers, and that these can be used

as a launching point to expand coverage using current baseline information.

Shelley Grice confirmed that a customer‐focused approach is most desired; she then asked if targets to

measure improvement in this area will be set by Hydro One. Susan responded yes, this will be included

in the high level plan moving forward.

Bob Betts then brought up the significant investment made by Hydro One in the CIS system build out,

and wondered if this has associated Outcome improvements that could be measured and reported

upon? Susan responded that it could, and that one of biggest issues in consumer service is the disdain

for estimated bills. She believes that the CIS system and smart meter rollout will, over time, will

decrease the need for estimated bills, so perhaps a goal of reducing the number of estimated bills could

be quantified and reported upon.

Paul Brown then stated that they are considering how they might be able to measure the value of an

investment, or the effectiveness of the recent implementation. He stated that Hydro One will think

about this issue further and see what can be done. He acknowledged that this approach may not

shorten the outage, but perhaps ensure that information is more readily available, offering the example

of providing consumers with an estimated time of service restoration.

Susan suggested that perhaps Hydro One should have Outcome goals associated with how quickly they

respond to an outage since that can be controlled. The duration of the Outage is often out of the utilities

control because it is dependent upon the nature and extent of the damage.

Ruth suggested that perhaps Hydro One could be measured against how accurate their estimation of

outage time is, for example if they advise customers power will be out for 48 hours, how accurate was

that compared to actual outage time. The more accurate it is, the more satisfied the customer will be.

Paula Zarnett noted that communicating with the customer is essential, repeating the example of letting

consumers know that the company is aware of an outage, and then later communicating that the

company believes that service has been restored, perhaps via automatic phone call. She also suggested

that consumer interaction should be measured to understand what proportion of consumers is reached

by the company’s efforts.

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Susan described the activities Hydro One is currently undertaking. She then asked how many areas

should be measured, and how does Hydro One decided which areas are tracked?

Julie Girvan suggested that related costs should dictate how many areas are measured. For example, if

costs to track one particular area are exorbitant, then certain performance tracking initiatives should be

foregone.

John McGee then shifted topics to call center performance measurements. He asked when a consumer

calls in, what metrics are used to measure the success of the interaction in terms of targets and trends.

Susan responded that this area is being tracked now, but there could be more emphasis on targets and

trends.

Roger Higgin then commented that it’s important to know which specific customers are out of service at

a given time, stating that Hydro One’s system currently indicates which transformers, feeders, etc. are

out, but it is not capable of identifying when and where individual customers are out. Susan replied that

they are moving in that direction, but it will be years before they can identify when each and every

customer might be out.

Mark moved to the area of Outcome measurement for operational effectiveness, specifically in regard

to development and if the spending and timing specific development projects is achieved. Mark went

on to comment on the area of Public Policy Responsiveness saying that this is very difficult to set

Outcome expectations for and that perhaps the only measurement is that the LDC is not chastised for

being “unresponsive” to Public Policy.

Lisa then returned the conversation to the issue of how many measurements are appropriate,

suggesting that the number 15 is likely too high. She indicated that the discussion seems to be focused

on restoration of service and related areas most important to consumers. She suggested that perhaps

the outcomes should be focused at a higher level, that is, be related to over goals and objectives, rather

than making sure that Hydro One didn’t install only 10 poles when they promised to install 15.

Mark suggested that even having one performance outcome for each of the four major categories might

be sufficient.

Susan responded that there are certain levels of detail they can report on, for example a plan to replace

15 poles ending up with only 10 poles actually being replaced. The reason why the stated target wasn’t

met is more challenging to report, track and measure relative to initial performance targets. The

usefulness of these measurements is debatable.

Bob then moved the conversation on to public policy responsiveness.

Lisa Brickenden stated from a Board Staff perspective, not speaking for the Board, that unless specific

suggestions to policy are included in filed evidence, and not general suggestions or just plain opposition

to various public policies, then it is not worthwhile to include in filings. The group then generally agreed

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that the category of public policy responsiveness should more appropriately be considered as public

policy directives to which that utilities must comply.

The conversation then shifted to financial performance, with Roger Higgin and Peter Thompson

suggesting that ROE be the key metric on which performance is based. Allan Cowan pointed out that

ROE is already included in all relevant filings and viewed with great importance.

Mark Garner then asked if there would be an opportunity to review the outcome performance reports

thus allowing stakeholders to identify concerns and pursue means to address those concerns. Susan

agreed that this was an appropriate area for consideration and development.

Lisa then commented that a ‘plan of execution’ metric is soon to be developed by the OEB, and details

would be forthcoming.

Lisa then asked that the value proposition slide be shown again (Slide 10 of Glenn Scott’s presentation

deck that includes keeping rates low, improving operating efficiency and cost savings, improving

customer satisfaction and building a trusted partner relationship, preserving net income, and full

visibility on assets and targeted investments to minimized customer impacts). She commented that

these might be considered when deciding what to include as desirable Outcomes. Susan agreed that

could be a good possibility.

Mark then asked about performance measurements, for example if one of the goals is to keep rates low,

then where in the plan does it explain how that will be done over the 5 year period. Allan responded to

that particular example by saying that the plan presented by Glenn does actually show OM&A costs

declining in the later years of the plan, citing measures in the plan to accomplish that including regular

head‐count management. Mark then also suggested that bond rating changes could be a useful metric

for Financial Performance.

Susan suggested the development of an “Other” category to capture Outcome areas that don’t fit neatly

into the Board’s four Outcomes. Bob asked the group about their thoughts on “Compensation outcome”

in this category. Mark indicated that it would be helpful to be able to see how Total Compensation was

moving through the five year term. Susan remarked that labor negotiations are conducted on a regular

schedule, and the information is generally shared with a wide range of stakeholders. Mark then noted

that most people are not worried about specific contracts, but whether overall compensation (including

contracting out) levels are rising or falling. Susan commented that there has been progress in this area,

making note of the increased use of contractors and consultants and the added organizational flexibility

this entails. Mark repeated that overall compensation levels are the key indicator; if rising, then more

information should be provided as to why and what can be done to mitigate.

Lisa proposed that there should be some Outcome associated with Innovation for example developing

or capitalizing on new technologies related to smart grid pilot initiatives and suggested that successes in

this area could be measured, for example a metric to track innovation within the company and

associated costs and benefits.

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Julie Girvan commented that it is important not to forget that dreaming up interesting metrics is not the

exercise under discussion, that cost mitigation should be the key focus as well as key metrics that

customers are interested in, for example those related to rate levels and reliability of service.

Susan then thanked everyone for their comments and suggestions and that the high level of

participation was very much appreciated. She then made note that not all ideas can be implemented in

upcoming filing, but some will be embraced and certainly warrant further focus and investment from

Hydro One.

In order to provide context to the discussion described above, please find below a list of ideas generated

by the stakeholder group, as noted by Hydro One as the conversation progressed:

1. Customer Focus

− Customer Satisfaction (i.e. % satisfied)

− Outage Mgmt / Restoration Time Information

− CELDI (Customer Experiencing Long Interruption Duration)

− Dx rate stability (by rate class) – measure actual impacts against filed

(and as a percentage of total bill)

− Outage performance surveys

− Transactional based surveys (measured as % satisfied) – customer class

specific

− Reduction of estimated bills

− Reduction in Outage Restoration time / Reduction in Time to Respond /

Estimating actual restoration time

− Call centre performance

2. Operational Effectiveness

− System Reliability (i.e. # kms of forestry brush control & line clearing)

− # of tree caused outages

− Reductions of outages by cause code

− Asset Management (i.e. % of in‐service capital to forecast)

− Overall Cost Performance (i.e. % OM&A / gross fixed costs)

− Key Capital and OM&A SDOC (Sustainment, Development, Operations

and Customer) category objectives (i.e. # customer connections under

Development)

− OM&A/customer (declining OM&A over plan)

− Declining ‘regular’ headcount

3. Public Policy Responsiveness / Directives

− Conservation Demand Management (i.e. Net Annual Peak Demand

Savings (MW))

− Renewable Generation (i.e. # of connections, etc.)

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− Should be linked specifically to proposed features of plan

4. Financial Performance

− Liquidity (i.e. current assets / current liabilities)

− ROE (approved vs actual)

− Capital spend to plan (plan execution)

− Bond Rating changes

5. OTHER

− Links to value proposition

− Compensation

− Successes in Smart Grid Pilot area (Innovation)

Allan Cowan then moved the session on to cover other issues to be included in the upcoming

application. First, the annual adjustments, with defined criteria including:

Externally driven and beyond utility’s control:

Ongoing / recurring changes either upward/downward: or

Primarily formula based.

Examples of Annual Adjustments proposed by Hydro One include:

1) Cost of Capital

Based on OEB issued Return On Equity and deemed Short Term debt rate in November of each year, as well as Hydro One’s actual long term debt issued updated every year during the term

2) Working Capital

Based on change in Commodity Prices, including global adjustment. (Discussed at length during Hydro One’s first stakeholder session)

3) Tax Rate Changes (100%)

Flow through based on government directed tax change within the year

4) 3rd party flow‐through costs

Based on changes in: o Retail Transmission Service Rate (RTSR), o Wholesale Meter Service Charge (WMSC), o Smart Metering Entity Charge (SME), o Rural Rate Protection Charge (RRRP), o OEB Charges

5) Clearing of Variance Accounts (e.g. RSVAs, pension)

bi‐annual based on the latest annual audited financial results.

26



Hydro One will present to the Board an update of adjustments for the upcoming year as part of the draft

rate order filed in November of each year.

Allan then went on to briefly review two potential off‐ramps, identifying that these are consistent with

the OEB’s Renewed Regulatory Framework for Electricity (RRFE). These include:

Return on Equity falls outside the +/‐ 300 basis point earnings dead band; or Utility performance erodes to unacceptable levels

Allan then shifted in to a discussion pertaining to ‘adjustments that fall outside the normal course of

business’. The criteria for these include:

Externally driven and beyond the utility’s control;

Unexpected; or

Having a very material impact on operations.

Allan listed the examples that proposed by Hydro One including:

Restructuring of the industry New Government Directives or Legislation Market Rules/Code changes Environmental law changes Technical standard changes New investments resulting from the newly developed Regional Plans of a significant material

nature Material unforeseen weather events Accounting Framework changes

With respect to implementation, Hydro One will file when an event or cumulative events take place and

the situation requires only a particular component of the plan to be examined and possibly tracked in a

variance account and adjusted through a rate rider/adder. Allan also noted that in such an event, a

written proceeding may be required by the OEB.

Allan briefly recounted the material covered and opened the floor to any questions. He explained that

the audience should feel free to bring up any issue reviewed throughout the day.

Roger Higgin asked if any components of the five year plan reflect potential M&A activity. Allan replied

no, and pointed out that the Norfolk Power acquisition is also not reflected in the plan, that Norfolk shall

have a separate filing and financial statements. He went on to say that should any more M&A activity

take place, the same treatment shall be applied.

Mark Garner then asked if any rate harmonization will take place as a result of acquisitions. Allan

responded no, not over the 5 year projected period.

Mark then asked if working capital annual adjustments would be supported by a lead/lag study. Allan

explained that the most recent study will be part of this application.

27



Julie then asked if there was currently any plan to enact an earning sharing mechanism in the filing;

Susan Frank stated that this was not an initiative that was slated for further development.

Mark then asked about new debt issues and whether there is a standard approach to ensure minimum

yield is paid by Hydro One. Allan explained that the team works to time the market to obtain the lowest

rate, however points out that they are unable to dictate rates to the marketplace.

Peter Thompson asked for the potential effect that the Annual Adjustments could have on the $1.4

Billion revenue requirement. Susan replied that the major effect would be associated Cost of Capital

adjustment. While Working Capital should be smaller, but it is based upon the commodity price and it is

difficult to say where it could go over five years. Susan summed up by saying that all of these

adjustments are by definition beyond their control and therefore largely unpredictable.

Roger Higgin then added that it is important to measure potential scenarios, for example economic

recession and potential implications and associated risks in this event. Allan acknowledged that should

a recession occur the budgeted financials would be at risk. Susan stressed that with any five year

forecasting exercise, especially as it pertains to OM&A and capital expenditure plans, there is always an

element of risk with respect to assumptions surrounding demand and revenue levels.

Peter Thompson asked if this was an incentive plan and Allan indicated it is a cost of service plan with

built in productivity. Peter asked if Hydro One had reviewed the PEG Report with respect to the

Enbridge Incentive Rate Plan. Allan indicated that they had, but that both circumstances and options

were different for Hydro One and Enbridge and Hydro One does not feel that the PEG report would

apply to them. Allan acknowledged that that Enbridge like Hydro One had specific things happening to

them which required a customized approach to both, thus generating two very different applications.

The Board has created rules for custom applications for electrics and Hydro One is following those.

Peter went on to ask what benefits the ratepayer would see from Hydro One’s plan. Allan first

mentioned how this approach avoids the painful spike in rates that is inherent to IRM plans that this

Cost of Services application has allowed for mitigation of that.

Susan added that the plan has productivity built into it, as can be seen by the tight constraints on OM&A

over the five year term.

Lisa then discussed potential efficiency gains over the five year period and from a design standpoint,

why some sort of “carryover incentive” is not included in plan. Susan asked for clarification, and

perhaps a specific example. Lisa offered the example of the allowance of gains achieved (for example,

spending less than the OEB approved amount in a specific area); this amount would potentially be

allowed to be carried over to the next filing term. Susan explained that various deferral and variance

accounts exist to not only collect shortfalls but also return surpluses to consumers.

Susan continued to explain that the entire five year plan is designed to serve the balanced interests of

both Hydro One and their customers, and that the information, financial or otherwise, is being

28



presented in a manner as transparent as possible. She then again confirmed the existence of risk within

the plan, and stated that the Hydro One Board is confident in the planned filing.

Mark then asked how Hydro One plans to define ‘material unforeseen weather events’. He asked for

clarification on what exactly defines a ‘material event’. Susan responded that they will look in to how

they might categorize various events in major buckets.

Julie asked if there were any unforeseen events that should potentially be listed as a cost savings

contributor, to which Susan asked for specific examples. Mark suggested that a restructuring of the

industry might be a potential cost savings contributor. Susan explained that yes, industry shifts may be

viewed in this manner and would be considered in the framework of an Adjustment Outside of the

Normal Course of Business.

Ceiran Bishop, Ontario Energy Board, asked why that example would be considered outside the normal

course of business. Susan explained that fundamental operating parameters not initiated by the utility

would fall into this group.

There was a general discussion about the considering variations to the 300 basis point off‐ramp,

including: the potential for a lower threshold like 200 basis point, or an asymmetrical off‐ramp or an off‐

ramp that had a lower threshold in the case of consecutive years of under or over earning. There was no

conclusive outcome to that discussion.

The focus of discussion went to the Adjustment Outside of the Normal Course of Business. Mark asked

what kind of “unforeseen weather events” would be considered “material”; both Susan and Allan

answered “a major ice storm” as an example. Mark suggested that materiality still needs some

definition and Susan agreed they would come up with a materiality definition; however, she did indicate

that Hydro One considered these events to be of very significant impact, the kind of thing that would

make them say that they can’t continue business without some relief.

Mark asked for as definition of Adjustments Outside of the Normal Course of Business as compared to

an off‐ramp. Susan said that an off‐ramp applies to things that show that the plan cannot be continued,

while the Adjustments are things that materially impact parts of the business, but don’t jeopardize the

entire plan, these would need to be addressed by the Board with specific relief considered by the Board.

Mark asked that each of the three adjustment options have clear definitions included in the application.

Lisa asked for an example of an adjustment for new investments resulting from the newly developed

Regional Plans. Susan described a scenario which could drive the need for more electricity in a region,

not all of the investment would be in transmission. There could be some significant amount of

distribution infrastructure investment that should be eligible for this kind of relief.

Ceiran asked whether insufficient visibility with respect to regional plan outcomes contributes to this.

Susan said yes, and stated that she was unable to speculate what would be coming up and the extent to

which funding would be available.

29



Mark then brought up transmission related issues, noting there will likely be many situations over the

course of the next five years that fall under this category and are likely not anticipated within the plan.

Susan responded that there is uncertainty surrounding regional planning and potential required

investments from distributors; she noted however that the degree of uncertainty was so high that

further discussion at this time is not warrented.

Bob Betts asked if there were any other items to be discuss, and there were none.

8. Closing Remarks / Next Steps by Allan Cowan, Director Major Applications, Hydro One Networks

Allan concluded the session by thanking everyone for participating and for their valuable feedback. He

explained that he hoped to shape the application to reflect as much of this feedback as possible from all

four stakeholder sessions. He concluded by stating that he wishes the audience well and again extended

his thanks for their openness and contributions.

Bob Betts also thanked the audience and adjourned the meeting.

30



9. Appendices

Appendix A. Summary of Stakeholder Session Hydro One’s 4th Stakeholder Session was conducted to present information to stakeholders and gather

feedback on items related to Hydro One’s Distribution Custom Rate Application 2015‐2019. The 5

primary topics discussed in the stakeholder session were:

1. Application Filing Timeline

2. Revenue Requirement and Common Costs

3. Core Work Program

4. Distribution Cost Allocation / Rate Design / Line Loss Study

5. Custom Framework – Adjustments and Reporting

Throughout the Session, there was open discussion with stakeholders covering questions, issues of

concern, additional information for consideration, requests for detail or explanation, and requests for

further input and consultation.

Hydro One’s internal specialists explained the rationale, approach and results, and indicated where

further details and explanations would be provided in the filing.

31



Appendix B. Key Actions and Considerations Application Filing Timeline

Planned initial filing date is December 19, 2013

The initial filing will include high‐level information and financial projections

Supplementary filing with all supporting documentation and detailed financial projections to

follow on approximately January 31, 2014

Blue page update to be filed in approximately May, 2014

Hydro One would like to allow all stakeholders to have ample time to evaluate the filings

Revenue Requirement and Common Costs

Five key goals of Hydro One’s value proposition related to the delivery of safe, reliable and

affordable service

o Keeping rates low

o Improving customer satisfaction and building a trusted partner relationship

o Preserving net income

o Full visibility on assets and targeted investments to minimized customer impacts

o Improving operating efficiencies and cost savings

Key elements of upcoming filings

o Hydro One ongoing capital structure is 60% debt, 40% common equity

o Overall cost of capital of 6.76%

o Rate base of $6,477M

o Return on capital of $438M

o Revenue requirement of $1,411M

Hydro One is aware that reliability of service and overall bill impact are the two most prevalent

issues for consumers

Rate smoothing strategy proposed to mitigate impact of planned 2015 rate increase (which

would result in an increase of approximately 7% for each of 2015, 2016, 2017, 2018, 2019)

Core Work Program

Hydro One serves approximately 1.2M customers

Hydro One assets include over 120,000 circuit‐km of lines, 1.6M poles and 1004 distribution

stations

Primary goals focused on sound investment strategies to ensure safe, reliable and efficient

power delivery and to create and enhance value for customers

32



Overview of OM&A and capital expenditures (sustaining, development, operating and customer

service)

Of the four primary components of OM&A sustaining, development, operating and customer

service, investments within sustaining are the most significant cost driver, with 2015‐2019 test

period costs ranging from $329M to $380M annually

Second most significant cost driver is customer service, accounting for between $115M and

$118M annually over the five year test period

Vegetation management expenditures will exhibit a sharp increase in 2016 and 2017 and then

stabilize in 2018 and 2019, due to a backlog in tree clearing

Development OM&A cost projections range from $15M to $18M within the test period

Operating OM&A cost projections range from $30M to $41M within the test period

Aging assets and systemic problems are a significant factor in forecast costs, as is reliability

improvements and long‐term cost optimization (such as addressing vegetation maintenance

backlogs and maintaining an eight year clearing cycle)

Stakeholder concerns focused on implications of the rate smoothing alternative strategy

Distribution Cost Allocation / Rate Design

Key topics include load forecast, customer classification, cost allocation, rate design and bill

impacts

Load forecast assumptions based upon 31 years of weather data and an Ontario economic

growth forecast assumed at 2.4% over the five year test period

Total revenue impact from customer classification changes estimated at ‐$39.7M

Rates across all classes to increase by 3.4% to maintain revenue requirement needs

Approximately 11,000 seasonal customers, from a total of approximately 157,000, to be

switched to a residential classification

Stakeholder concerns focused on economic growth and related demand assumptions, as well as

revenue impacts from classification changes and related cost ratios

Hydro One will be releasing new customer classification definitions

Custom Framework – Adjustments and Reporting

Focus on annual reporting, the measurement of Outcomes, Off Ramps and what should be

included in the annual adjustment process

Metrics are required to be measurable, controllable and transparent

Must be a manageable number of metrics

Categories of outcome measures included customer focus, operational effectiveness, public

policy responsiveness/directives, financial performance and other

33



Appendix C. Meeting Agenda

8:45 a.m. Registration

9:05 a.m. Welcome Allan Cowan, Director Major Applications Hydro One Networks

9:10 a.m. Introductions and Agenda Bob Betts, Facilitator, OPTIMUS|SBR

9:20 a.m. Application Filing Timeline Allan Cowan, Director Major Applications Hydro One Networks

9:30 a.m.

Revenue Requirement and Common Costs and Facilitated Discussion

Glenn Scott, Director Corporate Planning & Finance Hydro One Networks Bob Betts, Facilitator, OPTIMUS|SBR

10:30 a.m. Break

10:45 a.m.

Core Work Program and Facilitated Discussion

Paul Brown, Director Distribution Asset ManagementHydro One Networks Bob Betts, Facilitator, OPTIMUS|SBR

11:30 a.m.

Distribution Cost Allocation / Rate Design and Facilitated Discussion

Henry Andre, Manager Distribution Pricing Hydro One Networks Bob Betts, Facilitator, OPTIMUS|SBR

12:30 p.m. Lunch

1:30 p.m.

Custom Framework – Adjustments and Reporting and Facilitated Discussion

Allan Cowan, Director Major Applications Hydro One Networks Bob Betts, Facilitator, OPTIMUS|SBR

3:30 p.m. Closing Remarks / Next Steps Allan Cowan, Director Major Applications Hydro One Networks

3:45 p.m. Adjourn

34

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(45)

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ribut

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rs8

88

88

Rate

s Rev

enue

Req

uire

men

t1,3

75

1,4

78

1,5

33

1,5

78

1,6

29

Dx

Rate

Incr

ease

11.5

%7.

4%3.

6%3.

0%2.

9%

Rate

Base

6,4

77

6,7

59

7,0

97

7,5

12

7,9

17

Capex

649

655

639

655

669

DRA

FT -

2013

CO

NFI

DEN

TIA

L -P

relim

inar

y Fi

gure

s

47

Reg

ulato

ry A

sset

Rec

over

y

Net

bal

ance

col

lect

ed o

ver a

5-y

ear p

erio

d*

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udes

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icro

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SPC

and

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ject

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erra

l bal

ance

s

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ulato

ry A

sset

s as

of D

ecem

ber

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st, 2

01

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s fo

reca

sted

inte

rest

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nsio

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art M

eter

s6.

5D

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xem

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tail

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emen

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ianc

e A

ccou

nt (R

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)(6

.2)

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t Grid

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ther

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14D

RAFT

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13 C

ON

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NTI

AL

-Pre

limin

ary

Figu

res

48

2.6%

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%-0

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12.8

%

4.4%

3.7%

3.6%

3.4%

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%

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%

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%

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%

1.2%

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%

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%

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%

3.2%

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4.1%

-15.

0%

-10.

0%

-5.0

%

0.0%

5.0%

10.0

%

15.0

%

20.0

%

2013

2014

2015

2016

2017

2018

2019

OM

&A

and

Ext

ern

al R

even

ues

Ra

te B

ase

Sm

art M

ete

r -

OM

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art M

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r -

RB

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rid

- O

M&

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t Gri

d -

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ers

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ate

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ss &

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al

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ferr

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quire

me

ntB

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rove

d

2.6%

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7.0%

7.0%

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Smoo

thed

Dx

Rate

Incr

ease

15

-11.

5%

+18.

5%

Def

erre

d Re

venu

e Re

quire

men

t

($

56M

)($

66M

)

($2

1M)

$38M

$105

M

DRA

FT -

2013

CO

NFI

DEN

TIA

L -P

relim

inar

y Fi

gure

s

49

16

OM

&A

Ex

pen

ditu

res

Sum

mary

$Mill

ions

(F

orec

ast)

Fore

cast

Bri

dge

Test

Yea

rs

20

13

20

14

20

15

20

16

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er

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134

118

116

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113

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ents

45

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06

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60

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DRA

FT -

2013

CO

NFI

DEN

TIA

L -P

relim

inar

y Fi

gure

s

50

17

Capita

l Ex

pen

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res

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mary

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ions

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cast

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dge

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rs

20

13

20

14

20

15

20

16

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3

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TOTA

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64

9

65

5

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5

66

9

DRA

FT -

2013

CO

NFI

DEN

TIA

L -P

relim

inar

y Fi

gure

s

51

18

Wha

t are

Cor

por

ate

Com

mon

Co

sts?

H

ydro

One

Cor

pora

te C

omm

on C

osts:

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−C

orpo

rate

Com

mon

Fun

ctio

ns &

Ser

vice

s (H

R, F

inan

ce, L

aw, R

eal E

state

& F

acili

ties,

etc

.)−

Ass

et M

anag

emen

t −

Info

rmat

ion

Tech

nolo

gy−

Cos

t of S

ales

Capita

l−

Tran

spor

t, W

ork

& S

ervi

ce E

quip

men

t−

Real

Esta

te−

Info

rmat

ion

Tech

nolo

gy

DRA

FT -

2013

CO

NFI

DEN

TIA

L -P

relim

inar

y Fi

gure

s

52

19

OM

&A

Cor

por

ate

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mon

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ts

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ions

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ast)

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cast

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dge

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rs

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13

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14

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15

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16

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01

82

01

9

Tota

l Tx

& D

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ate

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mm

on C

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7

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6

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0

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smiss

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Allo

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71

70

71

73

64

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Dist

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ion

Allo

catio

n10

374

67

62

62

62

62

DRA

FT -

2013

CO

NFI

DEN

TIA

L -P

relim

inar

y Fi

gure

s

53

20

Capita

l Cor

por

ate

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mon

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ts

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ions

(F

orec

ast)

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cast

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dge

Test

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rs

20

13

20

14

20

15

20

16

20

17

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01

82

01

9

Tota

l Tx

& D

xCo

rpor

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mm

on C

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smiss

ion

Allo

catio

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86

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69

65

68

65

Dist

ribut

ion

Allo

catio

n12

8 11

0 85

85

83

84

82

DRA

FT -

2013

CO

NFI

DEN

TIA

L -P

relim

inar

y Fi

gure

s

54

21

Que

stio

ns?

DIS

CL

OSU

RE

NO

TE

:

FOR

WA

RD

LO

OK

ING

STA

TE

ME

NT

SA

ND

INFO

RM

AT

ION

We

have

incl

uded

forw

ard-

look

ing

stat

emen

tsin

this

repo

rtth

atar

esu

bjec

tto

risks

,unc

erta

intie

san

das

sum

ptio

ns.S

uch

info

rmat

ion

repr

esen

tsou

rcur

rent

view

sba

sed

onin

form

atio

nas

atth

eda

teof

this

repo

rt.A

nyst

atem

entc

onta

ined

inth

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cum

entt

hati

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tcur

rent

orhi

stor

ical

isa

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ard-

look

ing

stat

emen

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veba

sed

thes

efo

rwar

d-lo

okin

gst

atem

ents

onhi

stor

ical

expe

rienc

e,cu

rren

tcon

ditio

nsan

dva

rious

assu

mpt

ions

belie

ved

tobe

reas

onab

lein

the

circ

umst

ance

s.A

ctua

lres

ults

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ffer

mat

eria

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ecte

din

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look

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emen

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ecau

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xcep

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ligat

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orre

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emen

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even

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FT -

2013

CO

NFI

DEN

TIA

L -P

relim

inar

y Fi

gure

s

55

~BREA

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apita

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AL

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res

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Forw

ard

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kin

g F

inanc

ial S

tate

men

ts

We

have

incl

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look

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state

men

tsin

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pres

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subj

ect

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ks,

unce

rtain

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and

assu

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chin

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pres

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base

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info

rmat

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the

date

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port.

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state

men

tcon

tain

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this

docu

men

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histo

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ard-

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We

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base

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ts.Be

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the

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orre

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.

25D

RAFT

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13 C

ON

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NTI

AL

-Pre

limin

ary

Figu

res

59

26

Hyd

ro O

ne’s

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trib

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FT -

2013

CO

NFI

DEN

TIA

L -P

relim

inar

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gure

s

60

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Mana

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istr

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s

DRA

FT -

2013

CO

NFI

DEN

TIA

L -P

relim

inar

y Fi

gure

s

61

28

OM

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rs

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13

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14

20

15

20

16

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2

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8

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ratio

ns23

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tom

er

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ice

137

134

118

116

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mon

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5 5

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5

TOTA

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60

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FT -

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CO

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DEN

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L -P

relim

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gure

s

62

29

Sust

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; D

iscon

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conn

ects;

and

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ironm

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l & W

aste

Man

agem

ent

DRA

FT -

2013

CO

NFI

DEN

TIA

L -P

relim

inar

y Fi

gure

s

63

Veg

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n M

ana

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FT -

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CO

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DEN

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inar

y Fi

gure

s

64

31

$Mill

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mar

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rid P

ilot;

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Con

serv

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n &

Dem

and

Man

agem

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DRA

FT -

2013

CO

NFI

DEN

TIA

L -P

relim

inar

y Fi

gure

s

65

Smart

Gri

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M&

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Total Smart

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cast

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13

20

14

20

15

20

16

20

17

2

01

82

01

9Sm

art G

rid P

ilot

(incl

uded

in C

usto

mer

Ser

vice

)7

95

42

00

Dep

loym

ent

(incl

uded

in O

pera

ting)

06

59

1017

15

TOTA

L7

15

10

13

12

17

15

DRA

FT -

2013

CO

NFI

DEN

TIA

L -P

relim

inar

y Fi

gure

s

66

A

ging

ass

ets

and

syste

mic

pro

blem

s –

Larg

e sc

ale

testi

ng o

f tra

nsfo

rmer

s fo

r PC

B co

ntam

inat

ion

–In

crea

sing

focu

s on

def

ect c

orre

ctio

ns

Re

liabi

lity

impr

ovem

ents

and

long

-term

cos

t opt

imiz

atio

n–

Add

ress

ing

vege

tatio

n m

aint

enan

ce b

ackl

ogs

and

mai

ntai

ning

an

eigh

t yea

r cle

arin

g cy

cle

33

Sour

ces

of C

hang

e to

OM

&A

Cos

tM

ain

Driv

ers

for Y

ear-o

ver-Y

ear C

hang

es

DRA

FT -

2013

CO

NFI

DEN

TIA

L -P

relim

inar

y Fi

gure

s

67

34

Capita

l Ex

pen

ditu

res

Sum

mary

$Mill

ions

(F

orec

ast)

Fore

cast

Bri

dge

Test

Yea

rs

20

13

20

14

20

15

20

16

20

17

2

01

82

01

9

Susta

inin

g30

3 28

6 30

8 33

5 36

0 38

0 38

3

Dev

elop

men

t19

3 20

0 22

3 20

6 18

6 18

3 19

9

Ope

ratio

ns9

5 9

19

7 7

4

Cus

tom

er

Serv

ice

1623

2310

40

0

Cor

pora

te

Com

mon

Cos

ts &

Oth

er12

8 11

0 85

85

83

84

82

TOTA

L6

49

6

24

64

9

65

5

63

9

65

5

66

9

DRA

FT -

2013

CO

NFI

DEN

TIA

L -P

relim

inar

y Fi

gure

s

68

35

Sust

ain

ing C

apita

l

$Mill

ions

(F

orec

ast)

Fore

cast

Bri

dge

Test

Yea

rs

20

13

20

14

20

15

20

16

20

17

2

01

82

01

9St

atio

ns48

5164

6869

7677

Lines

213

204

228

247

267

283

296

Met

erin

g43

3217

2124

2111

TOTA

L303

286

308

335

360

380

383

Hyd

ro O

ne S

usta

inin

g C

apita

l Cos

ts in

clud

e: S

tatio

n Re

furb

ishm

ents;

Mob

ile

Uni

t Sub

statio

ns; C

ompo

nent

Rep

lace

men

ts; T

roub

le C

all &

Sto

rm D

amag

e Re

spon

se; L

arge

Sus

tain

ing

Line

Proj

ects;

and

Met

er U

pgra

des

DRA

FT -

2013

CO

NFI

DEN

TIA

L -P

relim

inar

y Fi

gure

s

69

Dis

trib

utio

n W

ood P

oles

36

To

tal F

leet

of D

istrib

utio

n W

ood

Pole

s is

appr

oxim

atel

y 1.

6 m

illio

n

Expe

cted

Ser

vice

Life

of D

istrib

utio

n W

ood

Pole

is 6

2 ye

ars

A

ppro

xim

atel

y 20

,000

pol

es a

re in

stalle

d ea

ch y

ear (

new

insta

llatio

ns &

en

d of

life

repl

acem

ent)

H

ydro

One

is p

ropo

sing

incr

ease

d fu

ndin

g to

add

ress

pre

mat

ure

deca

y iss

ues

and

miti

gate

risk

of t

he a

ppro

achi

ng b

ow w

ave

of p

oles

reac

hing

ex

pect

ed s

ervi

ce li

fe o

ver t

he p

erio

d.D

RAFT

-20

13 C

ON

FIDE

NTI

AL

-Pre

limin

ary

Figu

res

70

Dis

trib

utio

n St

atio

ns

37

1,

004

Dist

ribut

ion

and

Regu

latin

g St

atio

n Fa

cilit

ies

Ex

pect

ed S

ervi

ce L

ife o

f Dist

ribut

ion

and

Regu

latin

g St

atio

ns is

50

year

s

Hist

oric

al R

epla

cem

ent R

ate

has

been

app

rox.

4 s

tatio

ns/y

ear

H

ydro

One

pro

posin

g in

crea

sed

fund

ing

to m

anag

e de

mog

raph

ic

pres

sure

s an

d m

itiga

te ri

sk o

f the

app

roac

hing

bow

wav

e of

sta

tions

re

achi

ng e

xpec

ted

serv

ice

life

over

the

perio

d.

DRA

FT -

2013

CO

NFI

DEN

TIA

L -P

relim

inar

y Fi

gure

s

0

100

200

300

400

0-20

21-3

031

-40

41-5

0>5

0

25%

of p

opul

atio

n is

beyo

nd e

xpec

ted

serv

ice

life

Age

Prof

ile

# of stations

Age

Gro

up

71

38

Dev

elop

men

t Ca

pita

l$M

illio

ns

(For

ecas

t)Fo

reca

stBri

dge

Test

Yea

rs

20

13

20

14

20

15

20

16

20

17

2

01

82

01

9C

onne

ctio

ns &

Upg

rade

s10

410

610

911

211

611

912

3

Syste

m C

apab

ility

Re

info

rcem

ent

6561

8172

6162

74

Gen

erat

ion

Con

nect

ions

2033

3323

92

2

Who

lesa

le

Reve

nue

Met

ers

30

00

00

0

TOTA

L1

93

20

02

23

20

61

86

18

31

99

Hyd

ro O

ne D

evel

opm

ent

Capita

l Cos

ts in

clud

e: N

ew C

onne

ctio

ns; U

pgra

des

Driv

en b

y Lo

ad G

row

th; R

elia

bilit

y Im

prov

emen

ts; a

nd C

apita

l Con

tribu

tions

to n

ew

Tx C

onne

ctio

n C

apac

ity

DRA

FT -

2013

CO

NFI

DEN

TIA

L -P

relim

inar

y Fi

gure

s

72

39

Oper

atin

g &

Cus

tom

er S

ervi

ce

Capita

l$M

illio

ns

(For

ecas

t)Fo

reca

stBri

dge

Test

Yea

rs

20

13

20

14

20

15

20

16

20

17

2

01

82

01

9

Ope

ratin

g9

59

197

7 4

Cus

tom

er S

ervi

ce16

2323

104

00

Hyd

ro O

ne O

per

atin

g C

apita

l Cos

ts in

clud

e: U

pgra

des

and

expa

nsio

ns to

the

oper

atin

g in

frastr

uctu

re a

nd c

ontro

l fac

ilitie

s.

Hyd

ro O

ne C

usto

mer

Ser

vice

Capita

l Cos

ts in

clud

e: S

mar

t Grid

Pilo

t

DRA

FT -

2013

CO

NFI

DEN

TIA

L -P

relim

inar

y Fi

gure

s

73

Smart

Gri

d C

apita

l Ex

pen

ditu

res 40

Total Smart

Grid

Expe

nditu

res

Smart G

rid Pilot

Deployment

+

$Mill

ions

(F

orec

ast)

Fore

cast

Bri

dge

Test

Yea

rs

20

13

20

14

20

15

20

16

20

17

2

01

82

01

9Sm

art G

rid P

ilot

(incl

uded

in C

usto

mer

Ser

vice

)16

2323

104

00

Dep

loym

ent

(incl

uded

in S

usta

inin

g)0

67

1516

2020

TOTA

L1

62

93

02

52

02

02

0

DRA

FT -

2013

CO

NFI

DEN

TIA

L -P

relim

inar

y Fi

gure

s

74

A

ging

ass

ets

and

syste

mic

pro

blem

s –

Incr

easin

g th

e re

plac

emen

t rat

e of

woo

d po

les

–Re

furb

ishin

g ag

ing

distr

ibut

ion

statio

ns

–Re

plac

ing

PCB

cont

amin

ated

equ

ipm

ent

Re

liabi

lity

impr

ovem

ents

and

long

-term

cos

t opt

imiz

atio

n–

Incr

easin

g nu

mbe

r of l

ine

refu

rbish

men

t pro

ject

s

41

Sour

ces

of C

hang

e to

Capita

l Cos

tM

ain

Driv

ers

for Y

ear-o

ver-Y

ear C

hang

es

DRA

FT -

2013

CO

NFI

DEN

TIA

L -P

relim

inar

y Fi

gure

s

75

42

Que

stio

ns?

DIS

CL

OSU

RE

NO

TE

:

FOR

WA

RD

LO

OK

ING

STA

TE

ME

NT

SA

ND

INFO

RM

AT

ION

We

have

incl

uded

forw

ard-

look

ing

stat

emen

tsin

this

repo

rtth

atar

esu

bjec

tto

risks

,unc

erta

intie

san

das

sum

ptio

ns.S

uch

info

rmat

ion

repr

esen

tsou

rcur

rent

view

sba

sed

onin

form

atio

nas

atth

eda

teof

this

repo

rt.A

nyst

atem

entc

onta

ined

inth

isdo

cum

entt

hati

sno

tcur

rent

orhi

stor

ical

isa

forw

ard-

look

ing

stat

emen

t.W

eha

veba

sed

thes

efo

rwar

d-lo

okin

gst

atem

ents

onhi

stor

ical

expe

rienc

e,cu

rren

tcon

ditio

nsan

dva

rious

assu

mpt

ions

belie

ved

tobe

reas

onab

lein

the

circ

umst

ance

s.A

ctua

lres

ults

coul

ddi

ffer

mat

eria

llyfr

omth

ose

proj

ecte

din

the

forw

ard-

look

ing

stat

emen

ts.B

ecau

seof

thes

eris

ks,u

ncer

tain

ties

and

assu

mpt

ions

,und

uere

lianc

esh

ould

notb

epl

aced

onth

ese

forw

ard-

look

ing

stat

emen

ts.E

xcep

tto

the

exte

ntre

quire

dby

appl

icab

lese

curit

ies

law

san

dre

gula

tions

,we

unde

rtake

noob

ligat

ion

toup

date

orre

vise

any

ofth

ese

forw

ard-

look

ing

stat

emen

ts,w

heth

erto

refle

ctne

win

form

atio

n,fu

ture

even

tsor

othe

rwis

e.

DRA

FT -

2013

CO

NFI

DEN

TIA

L -P

relim

inar

y Fi

gure

s

76

20

15

-20

19

Cus

tom

D

istr

ibut

ion

Rate

A

pplic

atio

nCo

st A

lloca

tion

/ Rate

Des

ign

Dec

embe

r 2, 2

013

Hen

ry A

ndré

Man

ager

, Dist

ribut

ion

Pric

ing

77

Pres

enta

tion

Ove

rvie

w

Lo

ad F

orec

ast

C

usto

mer

Cla

ssifi

catio

n

C

ost A

lloca

tion

Ra

te D

esig

n

Bi

ll Im

pact

s

44D

RAFT

-20

13 C

ON

FIDE

NTI

AL

-Pre

limin

ary

Figu

res

78

Forw

ard

-loo

kin

g F

inanc

ial S

tate

men

tsW

eha

vein

clud

edfo

rwar

d-lo

okin

gsta

tem

ents

inth

ispr

esen

tatio

nth

atar

esu

bjec

tto

risks

,un

certa

intie

san

das

sum

ptio

ns.

Such

info

rmat

ion

repr

esen

tsou

rcu

rrent

view

sba

sed

onin

form

atio

nas

atth

eda

teof

this

repo

rt.A

nysta

tem

entc

onta

ined

inth

isdo

cum

entt

hati

sno

tcur

rent

orhi

storic

alis

afo

rwar

d-lo

okin

gsta

tem

ent.

We

have

base

dth

ese

forw

ard-

look

ing

state

men

tson

histo

rical

expe

rienc

e,cu

rrent

cond

ition

san

dva

rious

assu

mpt

ions

belie

ved

tobe

reas

onab

lein

the

circ

umsta

nces

.A

ctua

lre

sults

coul

ddi

ffer

mat

eria

llyfro

mth

ose

proj

ecte

din

the

forw

ard-

look

ing

state

men

ts.Be

caus

eof

thes

eris

ks,

unce

rtain

ties

and

assu

mpt

ions

,un

due

relia

nce

shou

ldno

tbe

plac

edon

thes

efo

rwar

d-lo

okin

gsta

tem

ents.

Exce

ptto

the

exte

ntre

quire

dby

appl

icab

lese

curit

ies

law

san

dre

gula

tions

,we

unde

rtake

noob

ligat

ion

toup

date

orre

vise

any

ofth

ese

forw

ard-

look

ing

state

men

ts,w

heth

erto

refle

ctne

win

form

atio

n,fu

ture

even

tsor

othe

rwise

.

45D

RAFT

-20

13 C

ON

FIDE

NTI

AL

-Pre

limin

ary

Figu

res

79

Load F

orec

ast

Ass

umptio

nsK

ey C

hang

es

46D

RAFT

-20

13 C

ON

FIDE

NTI

AL

-Pre

limin

ary

Figu

res

Sa

me

load

fore

cast

met

hodo

logy

use

d as

in p

revi

ous

DX

rate

cas

es

A

ll fo

reca

sts a

re w

eath

er-n

orm

al

O

ntar

io e

cono

my

is fo

reca

st to

gro

w o

n av

erag

e 2.

4% o

ver t

he 2

015-

2019

per

iod

C

DM

fore

casts

are

con

siste

nt w

ith th

e cu

rrent

Lon

g-Te

rm E

nerg

y Pl

an

Sm

art m

eter

hou

rly d

ata

was

use

d in

the

load

pro

file

anal

ysis

by ra

te c

lass

80

47

20

15

-20

19

Loa

d F

orec

ast

DRA

FT -

2013

CO

NFI

DEN

TIA

L -P

relim

inar

y Fi

gure

s

GW

h

81

Cust

omer

Cla

ssif

icatio

n

Boa

rd-d

irec

ted R

ate

Cla

ss R

evie

w

–M

any

custo

mer

s w

ill s

ee lo

wer

bill

s as

a re

sult

of th

e ch

ange

how

ever

rate

s ac

ross

all

clas

ses

will

incr

ease

by

3.4%

to h

old

reve

nue

requ

irem

ent n

eutra

l

Boa

rd-d

irec

ted r

evie

w o

f Se

aso

nal c

usto

mer

cla

ss–

Mov

ing

~11k

Sea

sona

l cus

tom

ers

(out

of 1

57k)

with

con

sum

ptio

n pa

ttern

sim

ilar t

o ye

ar-ro

und

custo

mer

s to

resid

entia

l cla

sses

–D

ecre

ase

of $

6.7M

in re

venu

e w

ill re

sult

in a

vera

ge in

crea

se o

f 0.5

% a

cros

s

all r

ate

clas

ses

N

ew U

SL r

ate

cla

ss p

er B

oard

rep

ort

48D

RAFT

-20

13 C

ON

FIDE

NTI

AL

-Pre

limin

ary

Figu

res

# o

f Cu

stom

ers

% o

f Cu

stom

ers

Rev

enue

Im

pact

($

M)

Tota

l1

,22

2,5

92

10

0%

No

Cha

nge

1,08

7,34

589

%

Chang

e1

35

,24

71

1%

(39

.7)

Low

er R

ates

111,

562

9%(8

0.9)

Hig

her R

ates

23,6

852%

41.2

82

Cost

Allo

catio

n

U

sing

Boar

d la

test

CA

M

U

pdat

ed c

usto

mer

load

pro

files

In

corp

orat

ed D

ensit

y Fa

ctor

s w

ithin

CA

M

Im

prov

emen

ts to

trac

king

of c

osts

by U

SofA

U

pdat

ed B

illin

g an

d Se

rvic

es fa

ctor

s

A

ddre

ssed

# o

f iss

ues

raise

d at

pre

viou

s ap

plic

atio

ns

49D

RAFT

-20

13 C

ON

FIDE

NTI

AL

-Pre

limin

ary

Figu

res

83

Rate

Des

ign

In

crea

sing

shar

e of

reve

nues

reco

vere

d vi

a fix

ed

char

ges

Br

ingi

ng re

venu

e-to

-cos

t rat

ios

for a

ll cl

asse

s w

ithin

1.

02 to

0.9

8 ov

er 5

yea

rs

N

ew R

ider

s–

defe

rral/

varia

nce

acco

unt r

ider

–sm

ooth

ing

rider

RT

SR u

pdat

ed to

refle

ct p

ropo

sed

2014

Pro

vinc

ial

Tran

smiss

ion

rate

s

50D

RAFT

-20

13 C

ON

FIDE

NTI

AL

-Pre

limin

ary

Figu

res

84

Ave

rage

2015

Bill

Im

pact

Co

mpon

ents

51D

RAFT

-20

13 C

ON

FIDE

NTI

AL

-Pre

limin

ary

Figu

res

Dis

trib

utio

n Im

pact

Tota

l Bill

Im

pact

Reve

nue

Requ

irem

ent

15.5

%5.

2%Ra

te C

lass

Rev

iew

, Sea

sona

l Rev

iew

& L

oad

Fore

cast

1.8%

0.6%

Net

Varia

nce/

Def

erra

l Rid

ers

-5.8

%-1

.9%

Smoo

thin

g Ri

der

-4.5

%-1

.6%

Fixe

d/Vo

lum

etric

Cha

nges

No

Impa

ctRe

venu

e-to

-Cos

t Rat

ioC

hang

esN

o Im

pact

TOTA

L7

.0%

2.3

%

85

52

“Typ

ical”

Tot

al B

ill Im

pact

s by

Rate

Cla

ssRate

Cla

ssBill

A

ssum

ptio

n2

01

52

01

62

01

72

01

82

01

9

UR

800

kWh

-3.2

%0.

6%0.

4%0.

4%0.

7%

R1

800

kWh

-1.0

%1.

4%0.

9%0.

7%1.

1%

R2

800

kWh

2.9%

4.4%

4.5%

5.0%

5.1%

Seaso

nal

400

kWh

2.9%

4.2%

4.6%

4.9%

5.0%

Gse

2,00

0 kW

h3.

5%2.

4%2.

5%2.

7%2.

8%

Uge

2,00

0 kW

h8.

3%1.

5%2.

4%2.

7%2.

5%

GSd

35,0

00 k

Wh

120

kW5.

7%2.

9%4.

2%4.

7%4.

3%

Ugd

35,0

00 k

Wh

120

kW4.

9%1.

9%2.

8%3.

2%2.

9%

St. Lg

t50

0 kW

h9.

5%4.

0%4.

5%4.

5%4.

4%

Sen.

Lgt

50 k

Wh

11.6

%8.

8%9.

2%9.

2%8.

0%

USL

500

kWh

1.7%

-0.3

%1.

4%0.

5%1.

3%

Dgen

2,00

0 kW

h17

.8%

15.1

%13

.7%

12.3

%9.

2%

ST50

0,00

0 kW

h1,

000k

W2.

1%0.

4%0.

3%0.

4%0.

4%

DRA

FT -

2013

CO

NFI

DEN

TIA

L -P

relim

inar

y Fi

gure

s

86

53

Que

stio

ns?

DIS

CL

OSU

RE

NO

TE

:

FOR

WA

RD

LO

OK

ING

STA

TE

ME

NT

SA

ND

INFO

RM

AT

ION

We

have

incl

uded

forw

ard-

look

ing

stat

emen

tsin

this

repo

rtth

atar

esu

bjec

tto

risks

,unc

erta

intie

san

das

sum

ptio

ns.S

uch

info

rmat

ion

repr

esen

tsou

rcur

rent

view

sba

sed

onin

form

atio

nas

atth

eda

teof

this

repo

rt.A

nyst

atem

entc

onta

ined

inth

isdo

cum

entt

hati

sno

tcur

rent

orhi

stor

ical

isa

forw

ard-

look

ing

stat

emen

t.W

eha

veba

sed

thes

efo

rwar

d-lo

okin

gst

atem

ents

onhi

stor

ical

expe

rienc

e,cu

rren

tcon

ditio

nsan

dva

rious

assu

mpt

ions

belie

ved

tobe

reas

onab

lein

the

circ

umst

ance

s.A

ctua

lres

ults

coul

ddi

ffer

mat

eria

llyfr

omth

ose

proj

ecte

din

the

forw

ard-

look

ing

stat

emen

ts.B

ecau

seof

thes

eris

ks,u

ncer

tain

ties

and

assu

mpt

ions

,und

uere

lianc

esh

ould

notb

epl

aced

onth

ese

forw

ard-

look

ing

stat

emen

ts.E

xcep

tto

the

exte

ntre

quire

dby

appl

icab

lese

curit

ies

law

san

dre

gula

tions

,we

unde

rtake

noob

ligat

ion

toup

date

orre

vise

any

ofth

ese

forw

ard-

look

ing

stat

emen

ts,w

heth

erto

refle

ctne

win

form

atio

n,fu

ture

even

tsor

othe

rwis

e.

DRA

FT -

2013

CO

NFI

DEN

TIA

L -P

relim

inar

y Fi

gure

s

87

©201

3 Nav

igant

Cons

ulting

Ltd.

Co

nfide

ntial

and p

ropr

ietar

y. Do

not d

istrib

ute or

copy

.

ENER

GY

DISP

UTES

& IN

VEST

IGAT

IONS

•

ECO

NOM

ICS

• F

INAN

CIAL

ADV

ISO

RY •

MAN

AGEM

ENT

CONS

ULTI

NG

Decem

ber 2

, 2013

Line Loss Study Update

Prepared for Hydro One Networks, Inc.

88

55©2

013 N

aviga

nt Co

nsult

ing L

td.

Confi

denti

al an

d pro

priet

ary.

Do no

t dist

ribute

or co

py.

EN

ER

GYDISC

USSI

ON D

RAFT

»Init

ial fo

cus w

as on

2012

beca

use o

f the a

vaila

bility

of ho

urly

data

(from

smar

t mete

rs an

d inte

rval

meter

s) re

pres

entin

g the

majo

rity (7

2%) o

f Hyd

ro O

ne cu

stome

rs’ el

ectric

ity co

nsum

ption

»The

re ar

e six

major

comp

onen

ts to

the lo

ss ca

lculat

ion

Navigant was retained to calculate actual system‐wide losses from 2010 to

2012 and to recommend a methodology for Hydro One going forward

Line Loss S

tudy Upd

ate PU

RCHA

SES

CONS

UMPT

ION

IESO

Se

ttleme

nt Da

ta(m

onthl

y, da

ily)

Distr

ibuted

Ge

nera

tion

(mon

thly)

Tran

sfers

from

Host

Distr

ibutor

s(m

onthl

y)

89%

9%2%

% of

Total

Pur

chas

es72

%27

%1%

% of

Total

Con

sump

tion

Stre

et an

d Se

ntine

l Lig

hting

(hou

rly es

t.)

Smar

t / Int

erva

l Me

tered

(hou

rly)

‘Matc

h’ to

custo

mers

with

hour

ly da

ta to

estim

ate

unbil

led in

2012

Bulk

Meter

ed(b

illing

perio

d)

89

56©2

013 N

aviga

nt Co

nsult

ing L

td.

Confi

denti

al an

d pro

priet

ary.

Do no

t dist

ribute

or co

py.

EN

ER

GYDISC

USSI

ON D

RAFT

»This

is no

t the s

tanda

rd ap

proa

ch us

ed in

the i

ndus

try»M

ost u

tilitie

s rely

on co

nsum

ption

data

from

their b

illing

syste

m–

Actua

l con

sump

tion f

or a

given

custo

mer w

ithin

a yea

r, as

mea

sure

d by t

he co

nsum

ption

that

occu

rs be

twee

n the

first

and l

ast a

ctual

meter

read

with

in the

year

, is au

gmen

ted w

ith:

(i)an

estim

ate of

the p

ropo

rtion o

f con

sump

tion i

n the

last

billin

g cyc

le be

fore t

he fir

st me

ter re

ad th

at oc

curre

d wi

thin t

he ye

ar an

d(ii)

an es

timate

of un

billed

cons

umpti

on af

ter th

e las

t actu

al me

ter re

ad–

Unbil

led co

nsum

ption

is ty

picall

y esti

mated

base

d on a

n ind

ividu

al cu

stome

r’s pr

ior ye

ar or

prior

billin

g pe

riod c

onsu

mptio

n

»Usin

g this

stan

dard

appr

oach

cumu

lative

ly ov

er a

numb

er of

year

s, the

perce

ntage

of c

onsu

mptio

n tha

t is ‘e

stima

ted’ is

sign

ifican

tly re

duce

d (e.g

. ove

r one

year

it mi

ght r

epre

sent

~8%

, but

over

five

year

s it w

ould

be ap

prox

imate

ly ~1

.5%)

Navigant’s calculation of actual losses in 2012 required the collation and

analysis of a large quantity of hourly consumption data

Line Loss S

tudy Upd

ate

Jan 1

Dec 3

1Fir

st ac

tual m

eter r

ead w

ithin

the pe

riod

Last

actua

l mete

r rea

d with

in the

perio

d

Actua

l Con

sump

tion

Estim

ate of

Unb

illed C

onsu

mptio

nPr

opor

tion o

f con

sump

tion i

n prio

r billi

ng cy

cle w

ithin

the ye

ar

90

57©2

013 N

aviga

nt Co

nsult

ing L

td.

Confi

denti

al an

d pro

priet

ary.

Do no

t dist

ribute

or co

py.

EN

ER

GYDISC

USSI

ON D

RAFT

»Hyd

ro O

ne’s

new

CIS

is ca

pable

of

deter

minin

g unb

illed c

onsu

mptio

n for

each

of

Hydr

o One

’s ~1

.2 mi

llion c

ustom

ers a

s of

Dece

mber

31 of

each

year

»The

CIS

uses

custo

mer c

onsu

mptio

n data

by

billin

g cyc

le to

estim

ate un

billed

cons

umpti

on

and r

even

ue on

a mo

nthly/

annu

al ba

sis»T

he sy

stem

deve

lops a

kilow

att-h

our p

er da

y me

tric du

ring a

spec

ified b

ase p

eriod

and

appli

es it

to un

billed

perio

d–

The b

ase p

eriod

is de

velop

ed us

ing on

e of

three

meth

ods,

depe

nding

on th

e ava

ilabil

ity of

da

ta in

the sy

stem

(pict

ured

, to th

e righ

t)

»Nav

igant

expe

cts th

at thi

s app

roac

h will

yield

simila

r res

ults w

hen c

ompa

red t

o the

appr

oach

im

pleme

nted u

sing 2

012 h

ourly

cons

umpti

on

data

Going forward, Navigant recommends that Hydro One use the

capabilities of its new CIS to determine actual losses on an annual basis

Line Loss S

tudy Upd

ate

•Ba

sed

on ac

tual m

eter r

eads

•If a

n actu

al me

ter re

ad is

not

avail

able

the sy

stem

will m

ove

to the

next

meter

read

•Sy

stem

adjus

ts for

chan

ges

billin

g cyc

le len

gth

•If a

full b

illing

perio

d is n

ot av

ailab

le, sy

stem

will p

ro-ra

te the

cons

umpti

on ba

sed o

n the

me

ter re

ad da

ta av

ailab

le

•Sy

stem

will e

stima

te co

nsum

ption

using

a cu

stome

r pro

file de

velop

ed

for ea

ch ra

te cla

ss (e

.g. R

1, R2

, Sea

sona

l, etc.

)

1. Co

nsum

ptio

n in

th

e sam

e billi

ng

perio

d in

the

prev

ious

year

, or

2. Co

nsum

ptio

n in

th

e pre

vious

billi

ng

perio

d, o

r 3. Co

nsum

ptio

n es

timat

ion

by

cust

omer

clas

s

91

58©2

013 N

aviga

nt Co

nsult

ing L

td.

Confi

denti

al an

d pro

priet

ary.

Do no

t dist

ribute

or co

py.

EN

ER

GYDISC

USSI

ON D

RAFT

»The

amou

nt of

hour

ly co

nsum

ption

data

for H

ydro

One

custo

mers

decli

nes p

rior t

o 201

2–

Inter

val m

etere

d cus

tomer

s, tho

se fo

r who

m ho

urly

cons

umpti

on da

ta wo

uld be

avail

able

throu

ghou

t the

perio

d, re

pres

ent ~

20%

of to

tal co

nsum

ption

–Cu

stome

rs wi

th sm

art m

eters

and a

utoma

ted m

eter r

eads

in 20

12 re

pres

ent ~

50%

of co

nsum

ption

»As t

he am

ount

of ho

urly

data

avail

able

decli

nes,

the re

lianc

e on b

illing

cycle

data

incre

ases

»As a

resu

lts, N

aviga

nt re

comm

ends

calcu

lating

the a

ctual

losse

s in 2

010 a

nd 20

11 us

ing an

ap

proa

ch co

nsist

ent w

ith th

e app

roac

h tha

t will

be us

ed go

ing fo

rwar

d

»Nav

igant

expe

cts th

at thi

s app

roac

h will

yield

simila

r res

ults w

hen c

ompa

red t

o the

appr

oach

im

pleme

nted u

sing 2

012 h

ourly

cons

umpti

on da

ta

The level of hourly data that was used to calculate actual losses in 2012 is

not available for prior years

Line Loss S

tudy Upd

ate

92

59

Que

stio

ns?

DIS

CL

OSU

RE

NO

TE

:

FOR

WA

RD

LO

OK

ING

STA

TE

ME

NT

SA

ND

INFO

RM

AT

ION

We

have

incl

uded

forw

ard-

look

ing

stat

emen

tsin

this

repo

rtth

atar

esu

bjec

tto

risks

,unc

erta

intie

san

das

sum

ptio

ns.S

uch

info

rmat

ion

repr

esen

tsou

rcur

rent

view

sba

sed

onin

form

atio

nas

atth

eda

teof

this

repo

rt.A

nyst

atem

entc

onta

ined

inth

isdo

cum

entt

hati

sno

tcur

rent

orhi

stor

ical

isa

forw

ard-

look

ing

stat

emen

t.W

eha

veba

sed

thes

efo

rwar

d-lo

okin

gst

atem

ents

onhi

stor

ical

expe

rienc

e,cu

rren

tcon

ditio

nsan

dva

rious

assu

mpt

ions

belie

ved

tobe

reas

onab

lein

the

circ

umst

ance

s.A

ctua

lres

ults

coul

ddi

ffer

mat

eria

llyfr

omth

ose

proj

ecte

din

the

forw

ard-

look

ing

stat

emen

ts.B

ecau

seof

thes

eris

ks,u

ncer

tain

ties

and

assu

mpt

ions

,und

uere

lianc

esh

ould

notb

epl

aced

onth

ese

forw

ard-

look

ing

stat

emen

ts.E

xcep

tto

the

exte

ntre

quire

dby

appl

icab

lese

curit

ies

law

san

dre

gula

tions

,we

unde

rtake

noob

ligat

ion

toup

date

orre

vise

any

ofth

ese

forw

ard-

look

ing

stat

emen

ts,w

heth

erto

refle

ctne

win

form

atio

n,fu

ture

even

tsor

othe

rwis

e.

DRA

FT -

2013

CO

NFI

DEN

TIA

L -P

relim

inar

y Fi

gure

s

93

~LU

NCH

~

94

20

15

-20

19

Cus

tom

D

istr

ibut

ion

Rate

A

pplic

atio

nCu

stom

Fra

mew

ork

:A

dju

stm

ents

& R

epor

ting

Dec

embe

r 2, 2

013

Alla

n C

owan

Dire

ctor

, Maj

orA

pplic

atio

ns

95

Pres

enta

tion

Ove

rvie

w

A

nnua

l Rep

ortin

g/O

utco

me

Mea

sure

s

A

nnua

l Adj

ustm

ents

O

ff Ra

mps

A

djus

tmen

ts O

utsid

e of

Nor

mal

Cou

rse

of B

usin

ess

62D

RAFT

-20

13 C

ON

FIDE

NTI

AL

-Pre

limin

ary

Figu

res

96

Forw

ard

-loo

kin

g F

inanc

ial S

tate

men

ts

We

have

incl

uded

forw

ard-

look

ing

state

men

tsin

this

pres

enta

tion

that

are

subj

ect

toris

ks,

unce

rtain

ties

and

assu

mpt

ions

.Su

chin

form

atio

nre

pres

ents

our

curre

ntvi

ews

base

don

info

rmat

ion

asat

the

date

ofth

isre

port.

Any

state

men

tcon

tain

edin

this

docu

men

ttha

tis

notc

urre

ntor

histo

rical

isa

forw

ard-

look

ing

state

men

t.

We

have

base

dth

ese

forw

ard-

look

ing

state

men

tson

histo

rical

expe

rienc

e,cu

rrent

cond

ition

san

dva

rious

assu

mpt

ions

belie

ved

tobe

reas

onab

lein

the

circ

umsta

nces

.A

ctua

lre

sults

coul

ddi

ffer

mat

eria

llyfro

mth

ose

proj

ecte

din

the

forw

ard-

look

ing

state

men

ts.Be

caus

eof

thes

eris

ks,

unce

rtain

ties

and

assu

mpt

ions

,un

due

relia

nce

shou

ldno

tbe

plac

edon

thes

efo

rwar

d-lo

okin

gsta

tem

ents.

Exce

ptto

the

exte

ntre

quire

dby

appl

icab

lese

curit

ies

law

san

dre

gula

tions

,we

unde

rtake

noob

ligat

ion

toup

date

orre

vise

any

ofth

ese

forw

ard-

look

ing

state

men

ts,w

heth

erto

refle

ctne

win

form

atio

n,fu

ture

even

tsor

othe

rwise

.

63D

RAFT

-20

13 C

ON

FIDE

NTI

AL

-Pre

limin

ary

Figu

res

97

Ann

ual R

epor

ting

Out

com

e M

easu

res

Crite

ria:

O

utpu

ts to

allo

w B

oard

and

Inte

rven

ors

to m

onito

r key

ou

tcom

es c

omm

itted

to in

the

appl

icat

ion

M

etric

s ne

ed to

be

mea

sura

ble,

con

trolla

ble,

and

tra

nspa

rent

M

anag

eabl

e nu

mbe

r of m

etric

s

64D

RAFT

-20

13 C

ON

FIDE

NTI

AL

-Pre

limin

ary

Figu

res

98

C

usto

mer

Foc

us−

Cus

tom

er S

atisf

actio

n (i.

e. %

sat

isfie

d)

O

pera

tiona

l Effe

ctiv

enes

s−

Syste

m R

elia

bilit

y (i.

e. #

km

sof

fore

stry

brus

h co

ntro

l & li

ne c

lear

ing)

−A

sset

Man

agem

ent (

i.e. %

of i

n-se

rvic

e ca

pita

l to

fore

cast)

−O

vera

ll C

ost P

erfo

rman

ce (i

.e. %

OM

&A

/ gr

oss

fixed

cos

ts)

Pu

blic

Pol

icy

Resp

onsiv

enes

s−

Con

serv

atio

n D

eman

d M

anag

emen

t (i.e

. Net

Ann

ual P

eak

Dem

and

Savi

ngs

(MW

))−

Rene

wab

le G

ener

atio

n (i.

e. #

of c

onne

ctio

ns, e

tc.)

Fi

nanc

ial P

erfo

rman

ce−

Liqui

dity

(i.e

. cur

rent

ass

ets

/ cu

rrent

liab

ilitie

s)

65

Exam

ple

s of

Dis

trib

utio

nO

utco

me

Mea

sure

s

DRA

FT -

2013

CO

NFI

DEN

TIA

L -P

relim

inar

y Fi

gure

s

99

Ann

ual A

dju

stm

ents

Crite

ria:

Ex

tern

ally

driv

en b

eyon

d ut

ility

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Any

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Regu

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Hyd

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109

Documents

Stake holder Consultation Notes - Hydro One...Overall weighted cost of capital (WACC) is 6.76%, with a rate base calculated at $6,477M. The return on capital is $438M, income taxes