Draft-MASTERFILE Stakeholder Session 4 finalFINAL SBR.ppt … · · 2017-02-23assumptions, undue reliance should not be placed on these forward-looking statements. Except to the

Distribution Custom Rate Application 2015-2019

Stakeholder Session #4December 2, 2013

Stakeholder Consultation

Agenda8:45 am Registration

9:05 am WelcomeAllan Cowan, Director Major ApplicationsHydro One Networks

9:10 am Introductions and Agenda Bob Betts, Facilitator, OPTIMUS|SBR

9:20 am Application Filing TimelineAllan Cowan, Director Major ApplicationsHydro One Networks

9:30 am Revenue Requirement and Common Costs and Facilitated Discussion

Glenn Scott, Director Corporate Planning & FinanceHydro One Networks

Bob Betts, Facilitator, OPTIMUS|SBR

10:30 am Break

10:45 am Core Work Programand Facilitated Discussion

Paul Brown, Director Distribution Asset ManagementHydro One Networks


11:30 amDistribution Cost Allocation / Rate Design and Facilitated Discussion

Henry Andre, Manager Distribution PricingHydro One Networks


12:30 pm LUNCH

1:30 pmCustom Framework – Adjustments and Reporting and Facilitated Discussion(includes a15min Break)

Allan Cowan, Director Major ApplicationsHydro One Networks


3:30 pm Closing Remarks/Next Steps Allan Cowan, Director Major ApplicationsHydro One Networks

3:45 pm Adjourn 2

Facilitator’s Remarks

Introductions Facilitator, Bob Betts & OPTIMUS | SBR support team

Meeting Facilities

Safety Review

Note taking process

Participant Introductions

3

Meeting Process

Mobile phones “Off” or “Silenced”

Avoid side discussions while others speaking

All questions are good ones

All comments are appreciated

Materials and notes will be included in Hydro One’s rate application and will be posted on Hydro One’s Regulatory Website once application has been filed:

www.HydroOne.com/RegulatoryAffairs

4

2015-2019 Custom Distribution Rate ApplicationApplication Filing TimelineDecember 2, 2013

Allan Cowan

Director, Major Applications

6

Application Filing Timeline

Filing Dx Rate Application - December 19th, 2013

Supplemental Filing - January 31st, 2014

2013 Actual Results Update - May 2014

DRAFT - 2013 CONFIDENTIAL - Preliminary Figures

2015-2019 Custom Distribution Rate ApplicationRevenue Requirement &Common CostsDecember 2, 2013

Glenn Scott

Director, Corporate Planning and Finance

8

Presentation Overview

Overview of revenue requirement

Overview of rate increases

Regulatory asset recovery

Capital and OM&A expenditures– Corporate Common Cost details


Forward-looking Financial StatementsWe have included forward-looking statements in this presentation thatare subject to risks, uncertainties and assumptions. Such informationrepresents our current views based on information as at the date of thisreport. Any statement contained in this document that is not current orhistorical is a forward-looking statement.

We have based these forward-looking statements on historicalexperience, current conditions and various assumptions believed to bereasonable in the circumstances. Actual results could differ materiallyfrom those projected in the forward-looking statements. Because of theserisks, uncertainties and assumptions, undue reliance should not beplaced on these forward-looking statements.

Except to the extent required by applicable securities laws andregulations, we undertake no obligation to update or revise any of theseforward-looking statements, whether to reflect new information, futureevents or otherwise.

9DRAFT - 2013 CONFIDENTIAL - Preliminary Figures

Value Proposition

Safe, Reliable & Affordable

Service

Keep Rates Low(annual total bill impact at/less than

inflation)

Improve Customer

Satisfaction and Build a

Trusted Partner Relationship

Preserve Net Income

Improve Operating

Efficiencies and Cost Savings

Full Visibility on Assets and

targeted investments to minimize customer

impacts


Cost of Debt4.79%

Rate Base$6,477M

Cost of Capital6.76%

Cost of Equity9.71%

Capital Structure60/40

X

Return on Capital$438M

Cost of Service$918M

Income Taxes $55M

Revenue Requirement$1,411M

+

+

=

2015 Dx Revenue Requirement


OM&A$564M

Depreciation$354M

+

2.6% 3.3%

0.2%-0.6% -0.3%

12.8%

4.2%

3.5% 3.6% 3.5%

-1.2%

-3.3%

-1.3%

-1.2%

1.2%

1.8%

-0.1%-0.2%

-10.0%

-5.0%

0.0%

5.0%

10.0%

15.0%

20.0%

2013 2014 2015 2016 2017 2018 2019

OM&A and External Revenues Rate Base Smart Meter - OM&ASmart Meter - RB Smart Grid - OM&A Smart Grid - RBRiders Load, Rate Class & Seasonal Board Approved

2.6%

11.5%

7.4%

3.6% 3.0% 2.9%

1.4%

Distribution Rate Increase


7%

+18.5%

- 7.0%

Revenue Requirement

13

$Millions (Forecast) 2015 2016 2017 2018 2019

OM&A 564 610 614 604 600Dep. & Am. 354 373 391 405 417

Return On Debt 186 201 216 234 257

Return on Equity 252 269 288 307 323

Income Tax 55 62 62 66 69

Revenue Requirement 1,411 1,515 1,571 1,615 1,666

Less: External Revenue (45) (45) (46) (45) (45)

Distribution Riders 8 8 8 8 8

Rates Revenue Requirement 1,375 1,478 1,533 1,578 1,629

Dx Rate Increase 11.5% 7.4% 3.6% 3.0% 2.9%

Rate Base 6,477 6,759 7,097 7,512 7,917Capex 649 655 639 655 669


Regulatory Asset Recovery

Net balance collected over a 5-year period* Includes RCVA, MicroFIT, SPC and Project Deferral balances

Regulatory Assets as of December 31st, 2013, plus forecasted interest ($Millions)Pension 55.6OEB 9.1Smart Meters 6.5DSC Exemption 5.5

Tax (20.7)Retail Settlement Variance Account (RSVA) (6.2)Smart Grid (5.2)Other* (4.2)

TOTAL 40.4


2.6% 3.3%

0.2%

-0.6%-0.3%

12.8%

4.4%

3.7% 3.6% 3.4%

-1.2%

-3.3%

-1.3%-1.2%

1.2%

1.8%

-0.2%

-4.5%

-0.6%

3.2% 3.9% 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 External Revenues Rate Base Smart Meter - OM&A Smart Meter - RB

Smart Grid - OM&A Smart Grid - RB Riders Load, Rate Class & Seasonal

Deferred Revenue Requirement Board Approved

2.6%

7.0%

7.0% 7.0% 7.0% 7.0%

1.4%

Smoothed Dx Rate Increase

15

- 11.5%

+18.5%

Deferred Revenue Requirement ($56M) ($66M) ($21M) $38M $105M


16

OM&A Expenditures Summary

$Millions (Forecast)

Forecast Bridge Test Years

2013 2014 2015 2016 2017 2018 2019

Sustaining 318 320 329 374 380 363 358

Development 12 18 15 18 17 17 18

Operations 23 30 30 34 35 42 41

Customer Service 137 134 118 116 114 113 115

Corporate Common Costs & Other

103 74 67 62 62 62 62

Property Taxes & Rights Payments

4 5 5 5 5 5 5

TOTAL 598 581 564 610 614 604 600


17

Capital Expenditures Summary



2013 2014 2015 2016 2017 2018 2019

Sustaining 303 286 308 335 360 380 383

Development 193 200 223 206 186 183 199

Operations 9 5 9 19 7 7 4



128 110 85 85 83 84 82

TOTAL 649 624 649 655 639 655 669


18

What are Corporate Common Costs?

Hydro One Corporate Common Costs:

OM&A− Corporate Common Functions & Services

(HR, Finance, Law, Real Estate & Facilities, etc.)− Asset Management − Information Technology− Cost of Sales

Capital− Transport, Work & Service Equipment− Real Estate− Information Technology


19

OM&A Corporate Common Costs



2013 2014 2015 2016 2017 2018 2019

Total Tx & DxCorporate Common Costs

139 144 137 134 136 126 130

Transmission Allocation 36 71 70 71 73 64 67

Distribution Allocation 103 74 67 62 62 62 62


20

Capital Corporate Common Costs



2013 2014 2015 2016 2017 2018 2019

Total Tx & DxCorporate Common Costs

193 196 155 153 149 152 147

Transmission Allocation 66 86 69 69 65 68 65

Distribution Allocation 128 110 85 85 83 84 82


21

Questions?

DISCLOSURE NOTE:

FORWARD LOOKING STATEMENTS AND INFORMATIONWe have included forward-looking statements in this report that are subject to risks, uncertainties and assumptions. Such information represents our currentviews based on information as at the date of this report. Any statement contained in this document that is not current or historical is a forward-lookingstatement. We have based these forward-looking statements on historical experience, current conditions and various assumptions believed to be reasonablein the circumstances. Actual results could differ materially from those projected in the forward-looking statements. Because of these risks, uncertainties andassumptions, undue reliance should not be placed on these forward-looking statements. Except to the extent required by applicable securities laws andregulations, we undertake no obligation to update or revise any of these forward-looking statements, whether to reflect new information, future events orotherwise.


~BREAK~

2015-2019 Custom Distribution Rate ApplicationCore Work ProgramDecember 2, 2013

Paul Brown

Director, Distribution Asset Management


Overview of OM&A Expenditures− Sustaining, Development, Operating and Customer

Service details

Overview of Capital Expenditures− Sustaining, Development, Operating and Customer

Service details


Forward-looking Financial Statements

We have included forward-looking statements in this presentation thatare subject to risks, uncertainties and assumptions. Such informationrepresents our current views based on information as at the date of thisreport. Any statement contained in this document that is not current orhistorical is a forward-looking statement.




26

Hydro One’s Distribution Business

Customer Base– About 1.2 million customers– Rural and urban– Residential and small business– Local distribution companies– Large industrial customers – Generators connected to the distribution grid

Assets– Over 120,000 circuit-km of lines (3200 feeders)– Over 1.6 million poles – 1004 distribution stations– 50 kV or less– Rural system with low density throughout the province– Radial system with limited transfer capability


27

Managing Distribution Assets

System investment strategies to ensure safe, reliable and efficient power delivery and to create value for customers

Develop projects and programs to:– Address customer and system growth needs

– Renew assets at their end of life to ensure public/worker safety and service continuity

– Improve reliability/efficiency

– Modernize the distribution system to add customer value

– Effectively respond to unplanned system events


28

OM&A Expenditures Summary



2013 2014 2015 2016 2017 2018 2019

Sustaining 318 320 329 374 380 363 358

Development 12 18 15 18 17 17 18

Operations 23 30 30 34 35 42 41



103 74 67 62 62 62 62

Property Taxes & Rights Payments

4 5 5 5 5 5 5

TOTAL 598 581 564 610 614 604 600


29

Sustaining OM&A



2013 2014 2015 2016 2017 2018 2019Stations 22 28 28 28 29 29 28Lines 148 134 141 150 152 155 157Metering 14 19 19 19 18 19 19Vegetation Management 134 139 142 178 180 161 153

TOTAL 318 320 329 374 380 363 358

Hydro One Sustaining OM&A Costs include: Planned & Corrective Maintenance; Trouble Call Response; Line Clearing & Brush Control; Cable Locates; Disconnects/Reconnects; and Environmental & Waste Management


Vegetation Management

30

Trees were the largest contributor (at 44%) to Hydro One Corporate SAIDI in the 2007-12 period.

Shorter vegetation management cycle durations has been demonstrated to lower SAIDI.


31



2013 2014 2015 2016 2017 2018 2019

Development 12 18 15 18 17 17 18

Operating 23 30 30 34 35 42 41


Development, Operating, Customer Service OM&A

Hydro One Development OM&A Costs include: Engineering & Technical Studies (including Smart Grid Studies); Standards & Technology Support; and Distributed Generation Connections Support

Hydro One Operating OM&A Costs include: Operations Support; Maintenance of Operating Infrastructure; and Environmental, Health & Safety

Hydro One Customer Service OM&A Costs include: Customer Services; Smart Grid Pilot; and Conservation & Demand Management


Smart Grid OM&A Expenditures

32

Total Smart Grid

Expenditures

Smart Grid Pilot

Deployment

+



2013 2014 2015 2016 2017 2018 2019Smart Grid Pilot(included in Customer Service)

7 9 5 4 2 0 0

Deployment(included in Operating)

0 6 5 9 10 17 15

TOTAL 7 15 10 13 12 17 15


Aging assets and systemic problems – Large scale testing of transformers for PCB contamination

– Increasing focus on defect corrections

Reliability improvements and long-term cost optimization– Addressing vegetation maintenance backlogs and maintaining an

eight year clearing cycle

33

Sources of Change to OM&A CostMain Drivers for Year-over-Year Changes


34

Capital Expenditures Summary



2013 2014 2015 2016 2017 2018 2019

Sustaining 303 286 308 335 360 380 383

Development 193 200 223 206 186 183 199

Operations 9 5 9 19 7 7 4



128 110 85 85 83 84 82

TOTAL 649 624 649 655 639 655 669


35

Sustaining Capital



2013 2014 2015 2016 2017 2018 2019Stations 48 51 64 68 69 76 77

Lines 213 204 228 247 267 283 296

Metering 43 32 17 21 24 21 11

TOTAL 303 286 308 335 360 380 383

Hydro One Sustaining Capital Costs include: Station Refurbishments; Mobile Unit Substations; Component Replacements; Trouble Call & Storm Damage Response; Large Sustaining Line Projects; and Meter Upgrades


Distribution Wood Poles

36

Total Fleet of Distribution Wood Poles is approximately 1.6 million Expected Service Life of Distribution Wood Pole is 62 years Approximately 20,000 poles are installed each year (new installations &

end of life replacement) Hydro One is proposing increased funding to address premature decay

issues and mitigate risk of the approaching bow wave of poles reaching expected service life over the period.


Distribution Stations

37

1, 004 Distribution and Regulating Station Facilities Expected Service Life of Distribution and Regulating Stations is 50 years Historical Replacement Rate has been approx. 4 stations/year Hydro One proposing increased funding to manage demographic

pressures and mitigate risk of the approaching bow wave of stations reaching expected service life over the period.


0

100

200

300

400

0-20 21-30 31-40 41-50 >50

25% of population is beyond expected

service life

Age Profile

# of

sta

tions

Age Group

38

Development Capital$Millions (Forecast)


2013 2014 2015 2016 2017 2018 2019Connections &Upgrades 104 106 109 112 116 119 123

System Capability Reinforcement 65 61 81 72 61 62 74

Generation Connections 20 33 33 23 9 2 2

Wholesale Revenue Meters 3 0 0 0 0 0 0

TOTAL 193 200 223 206 186 183 199

Hydro One Development Capital Costs include: New Connections; Upgrades Driven by Load Growth; Reliability Improvements; and Capital Contributions to new Tx Connection Capacity


39

Operating & Customer Service Capital



2013 2014 2015 2016 2017 2018 2019

Operating 9 5 9 19 7 7 4


Hydro One Operating Capital Costs include: Upgrades and expansions to the operating infrastructure and control facilities.

Hydro One Customer Service Capital Costs include: Smart Grid Pilot


Smart Grid Capital Expenditures

40

Total Smart Grid

Expenditures

Smart Grid Pilot

Deployment

+



2013 2014 2015 2016 2017 2018 2019Smart Grid Pilot(included in Customer Service)

16 23 23 10 4 0 0

Deployment(included in Sustaining)

0 6 7 15 16 20 20

TOTAL 16 29 30 25 20 20 20


Aging assets and systemic problems – Increasing the replacement rate of wood poles

– Refurbishing aging distribution stations

– Replacing PCB contaminated equipment

Reliability improvements and long-term cost optimization– Increasing number of line refurbishment projects

41

Sources of Change to Capital CostMain Drivers for Year-over-Year Changes


42

Questions?

DISCLOSURE NOTE:



2015-2019 Custom Distribution Rate ApplicationCost Allocation / Rate DesignDecember 2, 2013

Henry André

Manager, DistributionPricing


Load Forecast

Customer Classification

Cost Allocation

Rate Design

Bill Impacts


Forward-looking Financial StatementsWe have included forward-looking statements in this presentation thatare subject to risks, uncertainties and assumptions. Such informationrepresents our current views based on information as at the date of thisreport. Any statement contained in this document that is not current orhistorical is a forward-looking statement.




Load Forecast AssumptionsKey Changes


Same load forecast methodology used as in previous DX rate cases

All forecasts are weather-normal

Ontario economy is forecast to grow on average 2.4% over the 2015-2019 period

CDM forecasts are consistent with the current Long-Term Energy Plan

Smart meter hourly data was used in the load profile analysis by rate class

47

2015-2019 Load Forecast


GWh

Customer Classification Board-directed Rate Class Review

– Many customers will see lower bills as a result of the change however rates across all classes will increase by 3.4% to hold revenue requirement neutral

Board-directed review of Seasonal customer class– Moving ~11k Seasonal customers (out of 157k) with consumption pattern

similar to year-round customers to residential classes

– Decrease of $6.7M in revenue will result in average increase of 0.5% across all rate classes

New USL rate class per Board report48


# of Customers

% of Customers

Revenue Impact ($M)

Total 1,222,592 100%

No Change 1,087,345 89%

Change 135,247 11% (39.7)

Lower Rates 111,562 9% (80.9)

Higher Rates 23,685 2% 41.2

Cost Allocation

Using Board latest CAM

Updated customer load profiles

Incorporated Density Factors within CAM

Improvements to tracking of costs by USofA

Updated Billing and Services factors

Addressed # of issues raised at previous applications


Rate Design

Increasing share of revenues recovered via fixed charges

Bringing revenue-to-cost ratios for all classes within 1.02 to 0.98 over 5 years

New Riders– deferral/variance account rider

– smoothing rider

RTSR updated to reflect proposed 2014 Provincial Transmission rates


Average 2015 Bill Impact Components


Distribution Impact

Total Bill Impact

Revenue Requirement 15.5% 5.2%Rate Class Review, Seasonal Review & Load Forecast 1.8% 0.6%Net Variance/Deferral Riders -5.8% -1.9%Smoothing Rider -4.5% -1.6%Fixed/Volumetric Changes No ImpactRevenue-to-Cost Ratio Changes No ImpactTOTAL 7.0% 2.3%

52

“Typical” Total Bill Impacts by Rate ClassRate Class

Bill Assumption 2015 2016 2017 2018 2019

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%

Seasonal 400 kWh 2.9% 4.2% 4.6% 4.9% 5.0%

Gse 2,000 kWh 3.5% 2.4% 2.5% 2.7% 2.8%

Uge 2,000 kWh 8.3% 1.5% 2.4% 2.7% 2.5%

GSd 35,000 kWh120 kW 5.7% 2.9% 4.2% 4.7% 4.3%

Ugd 35,000 kWh120 kW 4.9% 1.9% 2.8% 3.2% 2.9%

St. Lgt 500 kWh 9.5% 4.0% 4.5% 4.5% 4.4%

Sen. Lgt 50 kWh 11.6% 8.8% 9.2% 9.2% 8.0%

USL 500 kWh 1.7% -0.3% 1.4% 0.5% 1.3%

Dgen 2,000 kWh 17.8% 15.1% 13.7% 12.3% 9.2%

ST 500,000 kWh1,000kW 2.1% 0.4% 0.3% 0.4% 0.4%


53

Questions?

DISCLOSURE NOTE:



©2013 Navigant Consulting Ltd. Confidential and proprietary. Do not distribute or copy.

E N E R G Y

D I S P U T E S & I N V E S T I G AT I O N S • E C O NO M I C S • F I N A N C I A L A D V I S O RY • M A N A G E M E N T C O N S U LT I N G

December 2, 2013

Line Loss Study UpdatePrepared for Hydro One Networks, Inc.

55©2013 Navigant Consulting Ltd. Confidential and proprietary. Do not distribute or copy. E N E R G Y

DISCUSSION DRAFT

»Initial focus was on 2012 because of the availability of hourly data (from smart meters and interval meters) representing the majority (72%) of Hydro One customers’ electricity consumption»There are six major components to the loss calculation

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 Study Update

PURCHASES CONSUMPTION

IESO Settlement Data(monthly, daily)

Distributed Generation(monthly)

Transfers from Host

Distributors(monthly)

89% 9% 2%% of Total Purchases

72% 27% 1%% of Total Consumption

Street and Sentinel Lighting

(hourly est.)

Smart / Interval Metered(hourly)

‘Match’ to customers with hourly data to

estimate unbilled in 2012

Bulk Metered(billing period)


DISCUSSION DRAFT

»This is not the standard approach used in the industry»Most utilities rely on consumption data from their billing system

– Actual consumption for a given customer within a year, as measured by the consumption that occurs between the first and last actual meter read within the year, is augmented with:

(i) an estimate of the proportion of consumption in the last billing cycle before the first meter read that occurred within the year and

(ii) an estimate of unbilled consumption after the last actual meter read– Unbilled consumption is typically estimated based on an individual customer’s prior year or prior billing

period consumption

»Using this standard approach cumulatively over a number of years, the percentage of consumption that is ‘estimated’ is significantly reduced (e.g. over one year it might represent ~8%, but over five years it would be approximately ~1.5%)

Navigant’s calculation of actual losses in 2012 required the collation and analysis of a large quantity of hourly consumption data


Jan 1 Dec 31First actual meter read within the period Last actual meter read within the period

Actual Consumption

Estimate of Unbilled ConsumptionProportion of consumption in prior billing cycle within the year


DISCUSSION DRAFT

»Hydro One’s new CIS is capable of determining unbilled consumption for each of Hydro One’s ~1.2 million customers as of December 31 of each year»The CIS uses customer consumption data by billing cycle to estimate unbilled consumption and revenue on a monthly/annual basis»The system develops a kilowatt-hour per day metric during a specified base period and applies it to unbilled period

– The base period is developed using one of three methods, depending on the availability of data in the system (pictured, to the right)

»Navigant expects that this approach will yield similar results when compared to the approach implemented using 2012 hourly consumption data

Going forward, Navigant recommends that Hydro One use the capabilities of its new CIS to determine actual losses on an annual basis


• Based on actual meter reads• If an actual meter read is not

available the system will move to the next meter read

• System adjusts for changes billing cycle length

• If a full billing period is not available, system will pro-rate the consumption based on the meter read data available

• System will estimate consumption using a customer profile developed for each rate class (e.g. R1, R2, Seasonal, etc.)

1. Consumption in the same billing

period in the previous year, or

2. Consumption in the previous billing

period, or

3. Consumption estimation by

customer class


DISCUSSION DRAFT

»The amount of hourly consumption data for Hydro One customers declines prior to 2012– Interval metered customers, those for whom hourly consumption data would be available throughout the

period, represent ~20% of total consumption– Customers with smart meters and automated meter reads in 2012 represent ~50% of consumption

»As the amount of hourly data available declines, the reliance on billing cycle data increases

»As a results, Navigant recommends calculating the actual losses in 2010 and 2011 using an approach consistent with the approach that will be used going forward

»Navigant expects that this approach will yield similar results when compared to the approach implemented using 2012 hourly consumption data

The level of hourly data that was used to calculate actual losses in 2012 is not available for prior years


59

Questions?

DISCLOSURE NOTE:



~LUNCH~

2015-2019 Custom Distribution Rate ApplicationCustom Framework:Adjustments & ReportingDecember 2, 2013

Allan Cowan

Director, MajorApplications


Annual Reporting/Outcome Measures

Annual Adjustments

Off Ramps

Adjustments Outside of Normal Course of Business


Forward-looking Financial Statements

We have included forward-looking statements in this presentation thatare subject to risks, uncertainties and assumptions. Such informationrepresents our current views based on information as at the date of thisreport. Any statement contained in this document that is not current orhistorical is a forward-looking statement.




Annual ReportingOutcome Measures

Criteria:

Outputs to allow Board and Intervenors to monitor key outcomes committed to in the application

Metrics need to be measurable, controllable, and transparent

Manageable number of metrics


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

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

Public Policy Responsiveness− Conservation Demand Management (i.e. Net Annual Peak Demand

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

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

65

Examples of DistributionOutcome Measures


Annual Adjustments

Criteria:

Externally driven beyond utility’s control Ongoing / recurring changes either upward/downward Formula based


Annual Adjustments

Adjustments:

(1) Cost of CapitalBased on OEB issued Return On Equity and deemed Short Term debt rate in Nov each year and on Hydro One’s actual long term debt issued

(2) Working CapitalBased on change in Commodity Prices (including global adjustment)

(3) Tax Rate Changes (100%)Based on government directed tax change within the year


Adjustments (cont’d):

(4) 3rd party flow-through costs Based on change in:

- Retail Transmission Service Rate (RTSR), - Wholesale Meter Service Charge (WMSC), - Smart Metering Entity Charge (SME), - Rural Rate Protection Charge (RRRP), - OEB Charges

(5) Clearing of Variance Accounts (e.g. RSVAs, pension) Schedule bi-annually (i.e 2016 and 2018) based on the latest

year-end audited financial actuals.

Annual Adjustments


Implementation:

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.

Annual Adjustments


The Board’s Renewed Regulatory Framework for Electricity outlined that a regulatory review may be initiated if:

Return on Equity is outside the +/- 300 basis point earnings deadband; or

Performance erodes to unacceptable levels

Off-Ramps


Criteria:

Externally driven beyond utility’s control Unexpected Very material impact

71



Adjustments:

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 Material unforeseen weather events Accounting Framework changes

72



Implementation:

Hydro One will file when an event or cumulative events are materially impactive

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

May require a written proceeding

73



74

Questions?

DISCLOSURE NOTE:



Thank you for attending!Check our website for further information:www.HydroOne.com/RegulatoryAffairs

Any questions or comments can be directed to:[email protected]

Documents

Draft-MASTERFILE Stakeholder Session 4 finalFINAL SBR.ppt … · · 2017-02-23assumptions, undue reliance should not be placed on these forward-looking statements. Except to the