May 19 Topic Presenter. 10:55-11:30 Rate Base, Depreciation, Nuclear Liabilities, Pension/OPEB, Deferral and Variance Accounts

Transcription

1 May 19 Topic Presenter 8:00 8:30 Arrival and Continental Breakfast 8:30-8:40 Welcome and Introductions 8:40-8:50 Facilitator s Opening Remarks and Session Protocol 8:50-9:40 Application Overview and Regulatory Framework 9:40-10:10 Nuclear Operations OM&A, Capital Projects and Production Forecast 10:10-10:25 Break 10:25-10:55 Support Services and Compensation Costs 10:55-11:30 Rate Base, Depreciation, Nuclear Liabilities, Pension/OPEB, Deferral and Variance Accounts 11:30-11:50 Cost of Capital 11:50-12:15 Closing Remarks 12:15-12:30 Questions / Wrap Up/Adjourn Chris Fralick VP, Regulatory Affairs Steve Klein OPTIMUS SBR Barb Reuber EB Case Manager Carla Carmichael VP, Nuclear Donna Rees Director, Total Rewards Alex Kogan VP, Business Planning and Reporting Randy Pugh Director, Ontario Regulatory Affairs Chris Fralick VP, Regulatory Affairs Steve Klein OPTIMUS SBR 12:30-2:00 Lunch

2 V A L U E S SAFETY I N T E G R I T Y E X C E L L E N C E P E O P L E A N D C I T I Z E N S H I P Stakeholder Information Session OPG Regulated Facilities Payment Amounts May 19, 2016

3 Facilitator s Opening Remarks Introductions: Facilitator, Steve Klein and Optimus SBR support team Meeting Facilities Safety and Security Review Note-taking Process Room Configuration / Session Approach 2

4 Session Protocol Mobile phones / Smartphones / PDAs Off or Silenced If necessary, step out of the room to take or make a phone call WiFi access -- Guest_33, no passcode required; select, open browser and accept the terms and conditions No electronic recordings of session proceedings Avoid side discussions while others speaking All questions are good ones All comments are appreciated Everyone will have a chance to be heard Facilitator will moderate session as necessary Materials and notes will be posted on the Ontario Power Generation website following Application submission to the OEB at: 3

5 V A L U E S SAFETY I N T E G R I T Y E X C E L L E N C E P E O P L E A N D C I T I Z E N S H I P OPG s Payment Amounts Application Stakeholder Information Session May 19, 2016

6 Agenda May 19 Topic Presenter 8:00 8:30 Arrival and Continental Breakfast 8:30-8:40 Welcome and Introductions 8:40-8:50 Facilitator s Opening Remarks and Session Protocol 8:50-9:40 Application Overview and Regulatory Framework 9:40-10:10 10:10-10:25 Break Nuclear Operations OM&A, Capital Projects and Production Forecast 10:25-10:55 Support Services and Compensation Costs 10:55-11:30 Rate Base, Depreciation, Nuclear Liabilities, Pension/OPEB, Deferral and Variance Accounts 11:30-11:50 Cost of Capital 11:50-12:15 Closing Remarks 12:15-12:30 Questions / Wrap Up/Adjourn 12:30-2:00 Lunch Chris Fralick VP, Regulatory Affairs Steve Klein OPTIMUS SBR Barb Reuber EB Case Manager Carla Carmichael VP, Nuclear Donna Rees Director, Total Rewards Alex Kogan VP, Business Planning and Reporting Randy Pugh Director, Ontario Regulatory Affairs Chris Fralick VP, Regulatory Affairs Steve Klein OPTIMUS SBR 2

7 V A L U E S SAFETY I N T E G R I T Y E X C E L L E N C E P E O P L E A N D C I T I Z E N S H I P OPG s Payment Amounts Application Stakeholder Information Session: Application Overview and Regulatory Framework Barbara Reuber EB Case Manager

8 Objective of Information Session Preview OPG s application for new payment amounts to assist stakeholder review of the application Supplement previous stakeholder consultation sessions with details on regulatory approvals sought Three sessions in focused on changes to the regulatory framework February 2016 session covered methodology for determining hydroelectric and nuclear payments amounts, Pickering Extended Operations and Darlington Refurbishment Program March 2016 session provided a tour and more detailed information on the Darlington Refurbishment Program Information presented in this information session is subject to confirmation in final payment amounts application 4

9 Application Drivers This is not a business as usual application Significant changes are proposed for both the Hydroelectric and Nuclear regulatory methodologies Setting the Hydroelectric payment amounts by applying the OEB s IRM formula without rebasing Custom IR for Nuclear Five-year terms for both technologies, with Nuclear production risk addressed through a mid-term review DRP is the largest project to come before the OEB to date Nuclear rate smoothing is a significant new consideration Clearance of audited 2015 deferral and variance ( D&V ) account balances except for the Pension & OPEB Cash Versus Accrual Differential Deferral Account Other drivers: Pickering Extended Operations, cost of capital, compensation and benefits 5

10 Scope of OPG s Application Application for the test period January 1, 2017 to December 31, 2021 Over $5 billion addition to Darlington rate base over the five year period Clearance of audited D&V account balances as at December 31, 2015 Amounts deferred in Rate Smoothing Deferral Account: $1.6 Billion Impact to typical customer s bill (rates and riders): Payment Amounts and Bill Impact Proposed Payment Amounts Smoothed Nuclear Payment Amount ($/MWh) Payment Rider ($/MWh) TBD TBD TBD Smoothed Nuclear rates and riders ($/MWh) Base Hydroelectric rates Payment Rider ($/MWh) TBD TBD TBD Hydroelectric rates and riders ($/MWh) Typical Residential Customer Impact ($/month) (1.29) Hydroelectric payment amounts for are illustrative only - final payment amounts will be determined annually, using I factor values. 6

11 Special Studies & Analysis Includes the following special studies and analyses: Cost of capital Hydroelectric Total Factor Productivity Hydroelectric benchmarking Nuclear benchmarking Nuclear staffing benchmarking Corporate support cost benchmarking Compensation benchmarking Darlington Refurbishment Program KPMG independent review of RQE Modus/ Burns & McDonnell oversight assessment of RQE Third party expert panel review of RFR Class 2 estimate KPMG independent review of risk management Modus/ Burns & McDonnell Q oversight report 7

12 Approvals Summary Payment amounts and riders (to clear audited D&V account balances as at December 31, 2015) for OPG s prescribed hydroelectric and nuclear facilities Continue the existing D&V accounts and establish four new accounts Rate Smoothing Deferral Account Midterm Nuclear Production Variance Account Nuclear ROE Variance Account; and Hydroelectric Capital Structure Variance Account Deemed capital structure of 51 per cent debt and 49 per cent equity and a combined ROE in accordance with the OEB s Cost of Capital Report Revenue requirement, rate base and production forecasts for OPG s nuclear facilities In-service additions to rate base and OM&A expenditures associated with the DRP, including $4,800.2 million in 2020 on Unit 2 return to service Rate-setting methodology for each technology, Nuclear rate smoothing proposal and a midterm review of nuclear production Declare OPG s current payment amounts interim as of January 1,

13 Hydroelectric Rate-Setting Methodology No Rebasing of hydroelectric rates Consistent with price-cap index methodology in the RRFE 5-year term X factor comprised of an independent Total Factor Productivity ( TFP ) and stretch factor based on independent total-cost benchmarking study OPG is proposing a productivity factor of zero, in light of a negative TFP finding by the independent consultant OPG is proposing a 0.3% stretch factor based on performance against benchmarks Inflation factor ( I ) based on the same input sub-indices as the OEB s 4GIRM I-factor, weighted to reflect the input cost of hydroelectric generation industry (1.8% as determined by an independent consultant) Annual adjustment formula: Base Rates x (1+I-X) 9

14 Hydroelectric Proposed Payment Amounts The application uses the current payment amounts as base rates The base rates are adjusted to correct for the one time allocation of 2015 nuclear tax losses to hydroelectric in the EB payment amounts order Proposed Payment Amounts Hydroelectric Rates 2016 Tax Adjusted Price Cap Index 1.50% 1.50% 1.50% 1.50% 1.50% 2016 Price Cap Adjusted Hydroelectric Payment Amount ($/MWh) Payment Rider ($/MWh) TBD TBD TBD Total ($/MWh) Payment Amounts for are illustrative only - final payment amounts will be determined annually, using I factor values. 10

15 Nuclear Rate Setting Methodology Custom IR Methodology based on the principles of RRFE and the OEB s prior guidance 5-year term based on extensive benchmarking Application of a stretch factor in addition to productivity measures included in an already challenging Business Plan Stretch factor based on total generating cost benchmarking that persists year-over year Combined stretch factor of 0.3% based on weighted average benchmarking result Applied to Base OM&A and allocated Corporate Support Services costs Annual reporting based on measures used in nuclear benchmarking Off-ramps triggered based on a ±300 ROE basis point deadband Customer engagement elements 11

16 Nuclear Rate Smoothing Intended to mitigate rate impact and volatility associated with Darlington Refurbishment Program and Pickering End of Commercial Operations Consistent with rate smoothing amendments to O. Reg. 53/05 which came into force in January 2016 OPG will make entries into a new deferral account to delay recovery of revenue until a later date to smooth the impact on rates Carrying cost will apply as set out in O. Reg. 53/05 The smoothing proposal was developed with a focus on customers and financial performance 12

17 Nuclear Stretch Factor Nuclear payment amounts reflect five individual nuclear revenue requirements with incremental stretch reductions Stretch reductions persist year-over-year and create a meaningful incentive to continuously improve performance 13

18 Nuclear Proposed Payment Amounts and Revenue Requirement Nuclear rates are smoothed to reflect an11% increase year-over year 3,500 2,500 1, Nuclear Rates Proposed Payment Amounts Payment Amounts ($/MWh) Smoothed Payment Amount ($/MWh) Payment Rider ($/MWh) TBD TBD TBD Revenue Requirement ($M) (500) Total Cost of Capital OM&A Fuel Depreciation & Amortization Total Other Revenues Income and Property Tax 14

19 2000 Nuclear Drivers of Deficiency Nuclear Drivers of Deficiency ($M) Lower Production Darlington Refurbishment Program Costs Other OM&A Other Depreciation and Amortization 2015 Changes in Station Lives Pickering Extended Operations (Enabling Costs) Other Decrease in Fuel Costs 15

20 In Conclusion This is a five-year Nuclear and Hydroelectric application that includes a mega-project and new regulatory approaches for OPG. We recognize that it will be a significant amount of work for everyone involved. The bulk of the evidence addresses the Nuclear. prescribed assets and corporate costs because the Hydroelectric payment amounts will be set through the OEB s established IRM formula. We will work cooperatively with all parties to complete the review of OPG s application in an efficient and timely manner. 16

21 Questions? 17

22 V A L U E S SAFETY I N T E G R I T Y E X C E L L E N C E P E O P L E A N D C I T I Z E N S H I P OPG s Payment Amounts Application Stakeholder Information Session: Nuclear Operations OM&A, Capital Projects and Production Forecast Carla Carmichael VP, Nuclear Finance

23 Outline Nuclear Production Forecast Pickering Extended Operations Nuclear Operating Costs Nuclear Capital Expenditures Nuclear Benchmarking Nuclear Stretch Factor 2

24 Nuclear Production Forecast The reduction in generation starting in 2017 is largely due to the Darlington Refurbishment schedule (U2 out of service October 2016) and an increase in outage scope associated with Pickering Extended Operations. OPG is proposing a mid-term review in recognition of the challenges in forecasting production over a five year period given the complexity of the work program and risks / opportunities associated with fuel channel life Production Forecast Trend (TWh) Actual Budget Plan Plan Plan Plan Plan Darlington NGS Pickering NGS 3

25 Pickering Extended Operations Preliminary technical & economic assessments have been undertaken that demonstrate that extending Pickering operations is safe, technically feasible and has economic benefits. Estimated incremental OM&A expenditures of $307M between 2016 and 2020 are required to enable extended operations at Pickering. The investment in Pickering will provide about 62 TWh of net incremental electricity. The Ministry of Energy announced OPG would pursue operating six units until 2022 and four units until IESO analysis shows benefit from Extended Operations between $300M - $500M. The plan to extend Pickering s life will require approval from the Canadian Nuclear Safety Commission (CNSC) - Pickering is currently licenced to operate until August 31, Extending operations avoids approximately 8 million tonnes of greenhouse gas emissions. 4

26 Nuclear Operating Costs All Nuclear OM&A costs increase at an average rate of 0.9% per year, representing a challenging target over the five year period. Reflects a continued focus on maintaining lower staff levels and other cost control mechanisms. Nuclear Operation s current FTE target is at benchmark levels and continues to be during the test period. Hiring will be required over the next few years. Outage OM&A varies on an annual basis depending on the number and types of outages and the scope of work being planned (e.g. there are no planned outages at Darlington in 2021, VBO at Pickering in 2021). Project OM&A spending is generally stable and decreases in 2021 as Pickering approaches end of commercial operations. Includes $307M to enable Pickering extended operations. Nuclear OM&A ($M) 2,000 1,500 1, Actual Budget Plan Plan Plan Plan Plan Base OM&A Project OM&A Outage OM&A Pickering Extended Operations

27 Nuclear Capital Expenditures 2015/2016 expenditures reflect the addition of facility, infrastructure and plant and equipment aging management projects necessary to support operations at Darlington to the new end of life dates e.g. Primary Heat Transport Pump Motors. The investment in capital projects reflects the requirement to replace obsolete/lifeexpired plant equipment at Darlington and Pickering. Capital expenditures decrease in 2021 as Pickering approaches end of commercial operations. Nuclear Capital Expenditures ($M) Actual Budget Plan Plan Plan Plan Plan

28 Nuclear Benchmarking Summary of 2014 Benchmarking Report Darlington & Pickering continue to demonstrate strong safety performance Darlington Performance: 1 st quartile Total Generating Cost / MWh 2 nd quartile WANO Nuclear Performance Index & Unit Capability Factor Pickering Performance: 4 th quartile performance for all three metrics unit size and outage program are major contributors to results Scott Madden evaluated OPG s benchmarking methodology and confirmed that it is accurate and consistent with industry practices Goodnight Staffing Study Chronology of benchmarking studies: 2011 ~17% or 866 FTEs above benchmark 2013 ~8% or 394 FTEs above benchmark 2014 ~4% or 213 FTEs above benchmark OPG nuclear has achieved benchmark staff targets & closed the gap in

29 Nuclear Stretch Factor 0.3% stretch factor reductions are in addition to the initiatives in OPG s gapbased business planning needed to meet the business plan targets Applied to Nuclear Base OM&A and Allocated Corporate Support Services OM&A Constitutes approximately 75% of the OM&A spend, and is not variable, like Outage and Project OM&A Cumulative over the test period 8

30 V A L U E S SAFETY I N T E G R I T Y E X C E L L E N C E P E O P L E A N D C I T I Z E N S H I P OPG s Payment Amounts Application Stakeholder Information Session: Support Services and Compensation Costs Donna Rees Director, Total Rewards

31 Outline Support Services Costs Overview of costs and allocation to Nuclear Hackett Group Benchmarking Study* Compensation Costs Compensation Costs for Nuclear Willis Towers Watson Benchmarking Study* Staffing levels & collective bargaining * As directed in the OEB s decision in EB

32 Support Services Costs Support services costs assigned & allocated to the nuclear business are relatively stable over the test period The cost allocation methodology remains unchanged from previous applications Test Period 3

33 k$ or % Hackett Benchmarking Study Regulated corporate support costs and headcount both declined between 2010 and 2014 Normalized costs by function in 2014 improved compared to 2010, and in relation to peer benchmarks Normalized Costs by Function Between 2010 and 2014 Regulated Corporate Function Costs 10% Regulated Headcount 11% 2014 Corporate Function Costs (Regulated) Executive & Corporate Services 42% Finance 11% Info Technology 37% HR 10% 0 IT Cost (k$) Per End User HR Cost (k$) Per Employee Finance Cost as a % of Revenue Exec & Corp Serv as a % of Revenue 2010 OPG 2014 OPG Peer Group 4

34 Dollars FTE Compensation Costs for Nuclear The increase in compensation leading up to test period is largely driven by: Staffing needs associated with the Darlington Refurbishment project Workforce renewal required to sustain operations Costs remain stable over the test period Test Period 1, Base Salaries & Incentives (M$) 1,600 1, Overtime (M$) 1,200 1, Pensions & Benefits (M$)* Full Time Equivalents** *Pension and benefits include current service costs and are shown on an accrual basis. ** FTE includes both regular and non-regular FTEs. 5

35 Compensation Benchmarking OPGs overall gap to market for Total Direct Compensation is 5% and is considered to be at market (within +/-10% of the market) Total Direct Compensation includes base salaries and incentives The value of OPG s pension & benefit program continues to be higher than that provided by our comparator organizations. OPG has taken steps to reduce the gap through negotiated pension reforms 6

36 Collective Bargaining Highlights Wage escalation below inflation 1% annually for 3 years Pension Reforms PWU Agreement Apr to Mar Society Agreement Jan to Dec Increase to employee contributions* (effective 2015 / 2016) Pension to be based on highest 5 consecutive years instead of 3 (effective 2025) Eligibility for undiscounted pension change from R82 to R85 * (effective 2025) Offsets (identified employees only) Lump sum payment (1% first year, 2% second year) Share Performance Bonus Plan (annual award of Hydro One shares for up to 15 years) * Similar reforms introduced for Management Group staff 7

37 Conclusions Staff at OPG s regulated facilities constitute a critical infrastructure for the provinces electric supply Compensation is at market relative to benchmarks Support services costs have improved against benchmarks QUESTIONS? 8

38 V A L U E S SAFETY I N T E G R I T Y E X C E L L E N C E P E O P L E A N D C I T I Z E N S H I P OPG s Payment Amounts Application Stakeholder Information Session: Rate Base, Depreciation, Nuclear Liabilities, Pension/OPEB, Deferral & Variance Accounts Alex Kogan VP, Business Planning and Reporting

39 Outline Rate Base Depreciation Expense Nuclear Liabilities and Bruce Lease Net Revenues Pension and OPEB Costs Deferral & Variance (D&V) Accounts and Income Taxes 2

40 Nuclear Rate Base 3 Rate base increases from ~$3.7B in 2015 to ~$8.6B by 2021, of which ~$5.5B is for the Darlington Refurbishment Program (DRP) DRP additions are ~$5.5B over , including ~$4.8 B for Unit 2 return to service in 2020, Unit Refurbishment Early In-Service, Facilities & Infrastructure Projects and Safety Improvement Opportunities Pickering rate base is close to fully depreciated by end of period as current accounting end of life is reached Asset retirement costs decrease by ~$400M between 2015 and 2016 due to 2015 nuclear liabilities adjustment related to Dec accounting station end-of-life date changes $B Nuclear Prescribed Facilities Rate Base Darlington Refurbishment Program Net Plant Darlington (excl. DRP) Net Plant Pickering Net Plant Nuclear Support Divisions Net Plant Asset Retirement Costs 2015 Actual 2016 Budget 2017 Plan 2018 Plan 2019 Plan 2020 Plan 2021 Plan

41 Nuclear Depreciation Expense Post 2015 depreciation reflects changes in end of life dates anticipated in OPG s December 2015 accounting order application (EB ) As of Dec 31, 2015, Pickering life is to end of 2020 and Darlington to end of 2052 DRP depreciation increases as capital is placed in service, including return to service of Unit 2 in February 2020 Pickering depreciation declines significantly after 2020 end of life date Future changes to end-oflife dates will be subject to existing accounting order requirements (if $10M impact). This would include future reassessment of Pickering life in light of confirmation of extended operations beyond 2020 $M Nuclear Depreciation & Amortization Darlington Refurbishment Program Darlington (excl. DRP) Pickering Nuclear Support Divisions Asset Retirement Costs 2015 Actual 2016 Budget 2017 Plan 2018 Plan 2019 Plan 2020 Plan 2021 Plan 4

42 5 Nuclear Liabilities and Bruce Lease Net Revenues Total nuclear liability costs (prescribed & Bruce) are largely stable, averaging ~$450M/yr over , and reflect 2015 nuclear liabilities adjustment and station life changes The 2015 adjustment increased total liabilities by ~$2.3B, largely due to updated Bruce refurbishment agreement and resulting life extensions for Bruce Units 3-8. Life extensions also act to reduce near term depreciation for existing asset retirement costs Reflects used fuel disposal activities and additional used fuel related to extended station lives, and rebalancing of central waste management facility costs from prescribed to Bruce stations 2016 impacts recorded in D&V accounts (Bruce variance act & station life changes deferral act established in EB ) Forecast Bruce Lease net revenues become negative starting in 2016 as a result of above changes in nuclear liabilities and station lives 2017 ONFA Reference Plan is under development and will be subject to Province s review and approval; impacts will be reflected in existing D&V accounts $M Nuclear Liabilities Revenue Requirement Impact Prescribed Facilities Bruce Facilities 2015 Actual 2016 Budget 2017 Plan 2018 Plan 2019 Plan 2020 Plan 2021 Plan

43 Pension and OPEB Costs 6 Proposing to continue EB treatment by limiting nuclear revenue requirement inclusion to cash amounts, with differences from accrual costs (nuclear & hydro) captured in existing deferral account, pending outcome of OEB s generic consultation on pension & OPEB costs (EB ) As per EB submission, OPG s position is that accrual basis of recovery (applied in EB and EB ) is appropriate and should continue upon conclusion of EB Cash to accrual differential is significantly reduced from EB , mainly from lower pension costs (e.g., higher employee contributions, asset returns) Over , total pension cash amounts are marginally higher than accrual costs OPEB cash to accrual differential (~$85M/yr for Nuclear) is shrinking over the period * Represents amounts for the Registered Pension Plan $M $M Nuclear Pension Costs* Accrual Costs Cash Amounts 2015 Actual 2016 Budget 2017 Plan 2018 Plan 2019 Plan 2020 Plan 2021 Plan Nuclear OPEB Costs Accrual Costs Cash Amounts 2015 Actual 2016 Budget 2017 Plan 2018 Plan 2019 Plan 2020 Plan 2021 Plan

44 Deferral & Variance Accounts and Income Taxes Audited Dec 31, 2015 balances (less 2016 amortizations from EB ) proposed to be cleared, except for Pension & OPEB Cash to Accrual account Proposed amortization through riders over Jan 1, 2017 to Dec 31, 2018, with previously approved EB /EB Pension & OPEB Cost variance amortization continuing Recoveries over 2017/18 are ~$215M for Nuclear and ~$85M for Hydroelectric Excluding previously approved Pension & OPEB Cost variance, net credit of ~$(50M) for Nuclear, and net debit of ~$70M for Hydro Proposing to continue existing accounts, and establish new accounts related to rate smoothing, mid-term nuclear production review and cost of capital Next clearance (hydro & nuclear) contemplated as part of proposed mid-term nuclear production review using Dec 31, 2018 audited balances Relatively modest amount of income taxes for nuclear facilities over (~$50M total), reflecting capital cost allowance deductions for DRP capital expenditures, deferral of pension/opeb accrual costs, and ONFA contributions 7

45 V A L U E S SAFETY I N T E G R I T Y E X C E L L E N C E P E O P L E A N D C I T I Z E N S H I P OPG s Payment Amounts Application Stakeholder Information Session: Cost of Capital Randy Pugh Director, Ontario Regulatory Affairs

46 Outline Cost of Capital Study Capital Structure Trend Cost of Equity and Nuclear Liabilities Cost of Debt 2

47 Cost of Capital Study Conclusion Study conducted by Concentric Energy Advisors recommends 49% (currently 45%) as a floor for OPG s common equity ratio: 1) Change in Risk: Increase in business and financial risk since EB , in particular for OPG s nuclear business unit 2) Comparative Analysis: Common equity ratio of peer group comprised of regulated utilities with significant hydro or nuclear generation and investment grade credit rating similar to OPG: Mean 49%, Median 50%. OPG considered riskier than peer for many reasons, including asset composition 3) Change in Asset Mix: EB Decision: Common equity ratio was reduced 47% to 45% was based on increase in the relative rate base of less risky hydroelectric generation. Darlington Refurbishment increases the rate base of more risky nuclear generation 3

48 Ratio of Hydroelectric Rate Base / Nuclear Rate Base Cost of Capital Study: Change in Asset Mix 4

49 Capital Structure 5

50 Short-Term Debt: Cost of Debt Capital Comprised of commercial paper No change proposed in forecast cost methodology 2015 approved rate is 2.89% Forecast rate steadily increases from 1.41% (2017) to 3.65% (2021) Long-Term Debt: Comprised predominantly of 10-year term debt held by OEFC No change proposed in forecast cost methodology 2015 approved rate is 4.86% Combined forecast and existing debt cost steadily decreases from 4.89% (2017) to 4.48% (2021) The main driver of the cost decrease is redemption of Corporate-wide and Niagara Tunnel 10-year debt issued from 2007 to Redeemed debt is at a higher cost (>5%) than the forecast cost of new debt issues (<5%) 6

51 Cost of Equity and Nuclear Liabilities Return on Equity: 2015 approved rate is 9.30% 1) Hydro: Maintains OEB approved ROE (Variance proposal removed) 2) Nuclear: Submission based on 9.19% ROE (2016 approved generic ROE) No change in methodology: OEB approved revenue requirement will reflect 2017 OEB approved ROE Proposal: New variance account to record annual changes in approved ROE Cost of Nuclear Liabilities: No change in methodology: OEB approved Lesser of ARC and UNL approach 2015 approved rate is 5.37% (approved weighted average accretion rate) Changes in nuclear station life reflected in OPG s approved Accounting Order application (EB ) in changes reduce the weighted average accretion rate to 5.11% in 2016 The 5.11% rate is applied consistently from 2017 to Any changes to liability costs (e.g., updated ONFA reference plan) will be recorded in D&V accounts 7

52 Going Forward Materials and notes will be posted on the Ontario Power Generation website following Application submission to the Ontario Energy Board at: 1