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Exhibit A2 Tab 2

Schedule 1 Page 1 of 10

BUSINESS PLANNING AND BUDGETING 1

2

1.0 PURPOSE 3

This evidence presents an overview of OPG’s business planning and budgeting process that 4

underpins this application. 5

6

2.0 OVERVIEW 7

The nuclear revenue requirements requested in this application are based on OPG’s 2016-8

2018 Business Plan, which also includes a financial projection for the 2019-2021 period. The 9

business plan builds on the success of OPG’s Business Transformation initiative, reflects 10

OPG’s four key strategic imperatives of operational excellence, project excellence, financial 11

strength and social licence, and is aligned with Ontario’s 2013 Long-Term Energy Plan (“2013 12

LTEP”). At a high level, the plan is specifically focused on: 13

Prudent management of OPG’s costs; 14

Safe, efficient and environmentally conscious operation of existing generation assets; 15

Successful execution of the Darlington Refurbishment Program (“DRP”) and Pickering 16

Extended Operations initiative; 17

Workforce renewal and ensuring availability of key resources in critical skill areas; 18

Improvement in the company’s financial outlook, which is dependent on the outcome 19

of this application; and 20

Supporting Ontario’s climate change objectives. 21

22

A copy of the 2016-2018 Business Plan is provided in Attachment 1. The business plan 23

includes corporate-level consolidated information as well as summarized financial plans, 24

operational targets and key initiatives for OPG’s major business units.1 25

26

Corporate business planning instructions for the 2016-2018 business planning cycle issued in 27

May 2015 set the context within which the business units developed their business plans in 28

support of the company’s strategic imperatives. These imperatives encompass a number of 29

1 See Appendices 5-7 to the 2016-2018 Business Plan in Attachment 1

Filed: 2016-05-27 EB-2016-0152 Exhibit A2 Tab 2 Schedule 1 Page 2 of 10

initiatives to drive productivity and continuous improvement over the planning period, 1

including: 2

Embedding cost reductions and efficiencies achieved to date in the longer term while 3

identifying and implementing initiatives to further improve OPG’s cost structure, without 4

compromising safe and reliable operations; 5

Continuing to pursue labour contract negotiations with the objective of facilitating 6

further efficiencies and cost improvements, and supporting the strategy for the end of 7

Pickering commercial operations; 8

Continuing to advance pension and benefits reforms; and 9

Pursuing initiatives to improve operating and financial performance. 10

11

A copy of OPG’s 2016-2018 Business Planning Instructions is provided in Attachment 2. Also 12

included in Attachment 2 is supplementary instructions issued in summer of 2015 in relation to 13

the Pickering Extended Operations scenario discussed below. 14

15

As part of the company’s 2016-2018 business planning cycle, planning information was 16

developed for the period from 2016 through to 2021. The planning information for the six-year 17

period was developed on the same basis and through a consistent process. This included 18

using consistent operating and costing inputs and assumptions (e.g., generation performance, 19

asset life cycle plans, major project execution including the DRP, labour and non-labour 20

costing, etc), applying a similar level of planning detail, utilizing the same corporate planning 21

tool, and generating the same key financial metrics. The final planning assumptions for the 22

six-year planning horizon included successful execution of OPG’s plan to extend the safe 23

operation of the Pickering station to 2022/2024 and the execution of the four-unit DRP, both 24

as approved by OPG’s Board of Directors in November 2015 and announced by the Province 25

in January 2016. 26

27

The nature of OPG’s operations and the resources required to operate the company’s 28

generation assets are inherently subject to change as maintenance and outage requirements 29

evolve and aging equipment issues emerge over time. This is particularly the case for OPG’s 30

aging nuclear facilities, as underscored by the major work programs unfolding at the nuclear 31

Filed: 2016-05-27 EB-2016-0152

Exhibit A2 Tab 2

Schedule 1 Page 3 of 10

stations over the next 5-10 years. As such, while specific resource targets were set for the 1

2016-2018 period, other tools such as benchmarking, other performance indicators and trend 2

analysis were utilized to develop business unit inputs into the 2019-2021 financial projection. 3

4

Section 3 provides a description of the 2016-2018 Business Planning process. Section 4 5

summarizes how OPG’s 2016-2018 Business Plan meets the objectives of the 2013 LTEP. A 6

more detailed overview of a typical planning process is provided in Attachment 3. An overview 7

of the asset management and project review process is provided in Attachment 4. The 8

processes described in these attachments are largely unchanged from those presented in EB-9

2010-0008 and EB-2013-0321 and are provided for reference. 10

11

3.0 2016-2021 BUSINESS PLANNING PROCESS 12

13

3.1 Planning Context and Assumptions 14

While OPG has achieved significant staff reductions over the last five years, the company 15

continues to face significant operational and financial challenges and uncertainties in the 16

period covered by this application, including: 17

Planned unit refurbishment outages as part of the DRP will reduce planned generation 18

levels starting in 2016, while a significant portion of the costs associated with the full 19

time operation of these units remains; 20

As OPG conducts work in support of Pickering Extended Operations and undertakes 21

the DRP, physical nuclear plant aging management risk and other uncertainties around 22

the nuclear generation forecast increase. In recognition of this forecasting risk, OPG 23

proposes a mid-term review of its nuclear production forecast, in mid-2019, as 24

discussed Ex. A1-3-3, section 3.0. 25

There is a risk of potentially significant income reductions over the business plan 26

period related to the OEB’s future decisions on recovery methods for pension and 27

other post-employment benefit (“OPEB”) costs. Although the business plan assumes 28

that pension and OPEB costs included in the nuclear revenue requirements are limited 29

to forecast cash amounts (in line with OPG’s proposal in Ex. F4-3-2), it also assumes 30

that the OEB provides sufficient assurance of future recovery of pension and OPEB 31

Filed: 2016-05-27 EB-2016-0152 Exhibit A2 Tab 2 Schedule 1 Page 4 of 10

accrual costs recorded in the deferral account (including associated taxes) to the end 1

of the test period, through the generic consultation or otherwise, such that OPG’s 2

income is not affected; 3

While OPG believes that the forecast credit metrics and operating cash flows in the 4

2016-2018 Business Plan will support OPG’s investment grade credit rating, a different 5

outcome of this application, including with respect to the nuclear rate smoothing 6

trajectory, could result in a weaker financial position and increase the risk of a credit 7

rating downgrade during a period of increased borrowing. The business plan reflects 8

OPG’s rate smoothing proposal set out in Ex. A1-3-3, which has been developed with 9

consideration of both customer impacts and OPG’s financial needs; 10

OPG is experiencing skill shortages in certain areas that need to be addressed 11

through workforce renewal plans, particularly as an aging demographic continues to 12

result in significant staff attrition levels. With respect to Management staff, OPG’s 13

focus is on ensuring continued ability to retain and attract qualified employees. The 14

plan also reflects the key outcomes of the 2015 round of collective bargaining and 15

associated pension reforms discussed in Ex. F4-3-1; 16

Although OPG’s pension and OPEB accrual costs and cash amounts are both 17

projected to decline significantly during the period to 2021, the company’s cost levels 18

and financial results remain sensitive to changes in financial market conditions in the 19

areas of pension and OPEB and nuclear decommissioning and waste management. 20

The business plan also does not reflect the potential impacts from the 2017 Ontario 21

Nuclear Funds Agreement (“ONFA”) Reference Plan, which is being developed and 22

will be subject to the Province’s approval, as discussed in Ex. C2-1-1. 23

24

OPG has continued its progress in managing costs through the 2016-2018 business planning 25

process and, through it, the consideration of the impact of the company’s operations on 26

customers. This includes an emphasis on continuous improvement aimed at both ensuring 27

that headcount reductions and efficiencies gained during the Business Transformation 28

initiative are sustained, and challenging the company to find further cost reductions and 29

efficiency gains. As further discussed in section 3.3, the final OM&A and staffing levels in the 30

approved business plan support the achievement of these objectives. 31

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Exhibit A2 Tab 2

Schedule 1 Page 5 of 10

OPG is also attempting to increase the return on the shareholder’s investment in the 1

company. OPG’s overall shareholder return has been well below the rate of return approved 2

by the OEB for the prescribed facilities. Particularly during the capital intensive DRP period, 3

the company must also ensure that it has sufficient cash flow and adequate credit metrics to 4

support access to cost effective financing. 5

6

OPG continues to employ leading practices in the business planning process, including top-7

down target setting for key resource envelopes such as OM&A, capital and headcount. OPG 8

also continues to review budgeting practices to ensure financial targets and resource plans 9

are held at an appropriate level of detail in the organization, and to implement other business 10

plan process improvements with a view to support an effective, integrated and timely planning 11

process. 12

13 3.2 Business Planning Guidelines and Cycle 14

OPG’s continues to prepare three-year business plans focused on effectively driving shorter-15

term performance. For the 2016-2018 business planning cycle, the three-year base resource 16

targets for capital, OM&A and staffing levels were communicated in the 2016-2018 Business 17

Planning Instructions. These targets were focused on driving further productivity and efficiency 18

improvements and leveraging the demographic profile of the workforce, which allowed 19

previous headcount reduction commitments to be substantially advanced by one year. This 20

helped to manage costs in the business planning period. In recognition of the planned 5-year 21

nuclear rate application, as discussed in section 2.0, the business units were requested to 22

develop a 2019-2021 financial projection using the same process and on a consistent basis 23

with the 2016-2018 planning information. (Attachment 2, pp. 35-40) 24

25 As work to assess the feasibility of operating the Pickering station beyond 2020 was in 26

progress, the 2016-2018 Business Planning Instructions initially reflected operation of 27

Pickering to 2020 as the base case planning assumption. The instructions (Attachment 2, p. 8) 28

and related communications (Attachment 2, pp. 33-35) also identified that the option of 29

extended operations at the Pickering station beyond 2020 was being considered as a scenario 30

and requested business planning information to be developed on that basis in addition to the 31

Filed: 2016-05-27 EB-2016-0152 Exhibit A2 Tab 2 Schedule 1 Page 6 of 10

base case. This information also informed the economic assessment of the Pickering 1

Extended Operations. 2

3

In order to ensure that the approved 2016-2018 Business Plan reflected OPG’s and the 4

Province’s decisions with respect to Pickering Extended Operations, the timing of business 5

plan finalization and submission to the Board of Directors was deferred until those decisions 6

were known. As discussed in Ex. F2-2-3, the Board of Directors approved OPG’s plan to 7

extend the safe operation of Pickering in November 2015 and the Province announced its 8

approval in January 2016. Following this, in 2016, OPG finalized the 2016-2018 Business 9

Plan using planning information developed under the Pickering Extended Operations 10

scenario. The final 2016-2018 Business Plan was approved by the Board of Directors in May 11

2016 and forms the basis for this application. 12

13

3.3 Review Process and Approvals 14

The corporate targets and business planning instructions discussed above set the context with 15

which the business units developed their business plans. Once the guidelines were issued, 16

each business unit identified objectives, performance targets, resources, key initiatives and 17

risk mitigation strategies that informed the development of their plans. 18

19

Each business unit identified the work programs and projects required to achieve their 20

business objectives taking into account the corporately issued targets. Where necessary, 21

tradeoffs were made by the business units to deal with emerging issues, such as the 22

management of aging plant assets. Reviews were undertaken within each of the business 23

units so that the resulting plans reflected the highest priority work needed to meet safety 24

goals, regulatory commitments, and operational milestones. High-level performance targets 25

were set by each business unit taking into account key initiatives. Project portfolios of both 26

OM&A and capital project investments maintained and prioritized within each business unit 27

allowed the highest priority investments, including those related to public and employee safety 28

and regulatory commitments, to be incorporated into the business unit plans. 29

30

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Exhibit A2 Tab 2

Schedule 1 Page 7 of 10

In light of the impact of the pending Pickering Extended Operations decision on the timing of 1

the 2016-2018 business planning cycle, draft business unit plans and other planning 2

information for the 2016-2021 period was submitted for consolidation into the corporate plan 3

through fall 2015. During this period and into early 2016, a series of review meetings were 4

held within each business unit and briefings on business unit plan information (including the 5

impact of Pickering Extended Operations) were presented to the President and Chief 6

Executive Officer (“CEO”), the Chief Financial Officer and other senior executives on OPG’s 7

enterprise leadership team. The final consolidated 2016-2018 Business Plan, including the 8

projection for 2019-2021, was approved by OPG’s Board of Directors in May 2016. Final 9

concurrence with the OPG-Board approved plan is required from the Province in accordance 10

with the Memorandum of Agreement (Ex. A1-4-1, Attachment 2). The 2016-2018 Business 11

Plan was submitted for the Province’s concurrence following Board of Directors’ approval in 12

May 2016. 13

14

Business unit plans continue to be subject to review and challenge at multiple levels within 15

OPG, including business unit management, local controllership, the central business planning 16

function in Finance, OPG’s senior executive up to and including the CEO, and finally the 17

Board of Directors. The reviews included an assessment of business unit plans against 18

corporate targets and the company’s strategic imperatives. This ensured that a rigorous 19

process of work identification and prioritization had occurred within each business unit and 20

corporately. Risks are also identified at several stages and are tracked through risk registers. 21

Risk mitigation plans are specified and monitored regularly to ensure risks are managed and 22

changes to risks are flagged for management action as required. 23

24

Overall, OPG has developed a challenging plan that will drive cost reductions and adherence 25

to the company’s operational and project execution milestones, and positively contribute to 26

improved financial performance. At the business unit level, both Nuclear operations OM&A 27

costs (excluding DRP costs and costs to enable Pickering Extended Operations)2 and total 28

Support Services’ OM&A costs increase, on average, by less one per cent year over the 29

2015-2021 period, which is overall lower than the rate of inflation. After an initial planned 30

2 Ex. F2-1-1

Filed: 2016-05-27 EB-2016-0152 Exhibit A2 Tab 2 Schedule 1 Page 8 of 10

increase in 2016 necessary for hiring to fill emerging critical skill gaps following a period of 1

higher than expected attrition, staffing levels from ongoing operations (i.e. excluding the DRP) 2

decline over the planning period to below 2015 levels. The total OPG cumulative savings 3

associated with regular staff reductions since the beginning of 2011 accumulate to over $1 4

billion by 2016, and well over that figure by the end of the planning horizon. 5

6

The 2016-2018 Business Plan also reflects regulatory and safety work programs at the 7

generating sites, inspection and maintenance activities at the generating facilities in 8

accordance with OPG’s aging and life cycle management programs, required work in support 9

of safe and reliable post refurbishment operations of the Darlington units, and investments to 10

enhance the overall performance and reliability of the generating fleet. Where possible, base 11

generation assumptions continue to be based on actual operating experience with a focus on 12

driving realistic improvement targets over the planning period, subject to increased 13

uncertainties related to Pickering Extended Operations and the DRP. 14

15

3.4 Customer Impacts 16

As set out in the OEB’s Decision with Reasons in EB-2010-0008 (pp 13), in respect of 17

business planning, OPG’s “…obligation is to plan taking account of the requirements of its 18

business and to propose payment amounts which represent recovery of an efficient and 19

reasonable level of costs”. OPG continues to employ this perspective in developing its 20

business plans, which includes consideration of the economic climate, trends in electricity 21

costs and consumers’ ability to pay. For additional discussion of OPG’s customer engagement 22

activities, refer to Ex. A1-3-2. 23

24

Under the 2016-2018 Business Plan assumptions that reflect the payment amounts requested 25

in this application, OPG will continue to be a lower cost generator of electricity in the province, 26

with prices that are expected to remain significantly below the average cost of other 27

generation. 28

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Exhibit A2 Tab 2

Schedule 1 Page 9 of 10

4.0 Ontario’s Long-Term Energy Plan Objectives 1

As outlined in more detail in Appendix 3 to Attachment 1, OPG’s 2016-2018 Business Plan 2

meets the objectives of the 2013 LTEP, including the following for the prescribed assets: 3

4

LTEP Projects and Initiatives OPG’s 2016-2018 Business Plan

Begin refurbishment of one Darlington unit in 2016

Project on schedule as approved by Shareholder

Meet Refurbishment principles as outlined in LTEP

Refurbishment plan adheres to LTEP principles

Contribute to reduction in OM&A within the sector

Savings from significant headcount reductions to date and further efficiency improvement opportunities reflected in the plan

Expected continued operations of Pickering to 2020

The plan reflects Shareholder’s approval to proceed with plans to pursue extended Pickering operations up to 2024

5

Filed: 2016-05-27 EB-2016-0152 Exhibit A2 Tab 2 Schedule 1 Page 10 of 10

LIST OF ATTACHMENTS 1

2

Attachment 1: 2016-2018 Business Plan 3

Attachment 2: 2016-2018 Business Planning Instructions 4

Attachment 3: Business Planning and Budgeting Process Overview 5

Attachment 4: Asset Management and Project Review Processes 6

1

FOR APPROVAL by the Board of Directors ______________________________________________________________________________________

May 13, 2016

OPG’s 2016-2018 BUSINESS PLAN

DECISION REQUIRED The purpose of this submission is to seek the Board’s approval of OPG’s 2016-2018 Business Plan, including a financial projection for the 2019-2021 period. ISSUE OPG’s business plan must be approved by OPG’s Board of Directors. Upon Board approval, the business plan is submitted to the Shareholder for review and concurrence in accordance with the Memorandum of Agreement between the Shareholder and OPG. In the second quarter of 2016, OPG plans to file a 5-year nuclear and hydroelectric rate application with the Ontario Energy Board (OEB) for the 2017-2021 period. The application will be based on OPG’s forecast of costs and production under a custom incentive regulation approach for the nuclear operations, and an incentive ratemaking formula for the hydroelectric operations. To support the basis for the rate application, OPG’s 2016-2018 Business Plan includes a financial projection for the 2019-2021 period. The information for all years has been prepared on the same basis and through a consistent process. ANALYSIS

Overview Typically, a 3-year business plan is submitted to the Board annually for approval. The 2016-2018 Business Plan was not submitted to the Board in 2015 due to ongoing work to assess the feasibility of operating Pickering beyond 2020. As approved by the Board in November 2015 and announced by the Province in January 2016, OPG has now concluded that it will pursue continued Pickering operations to 2024. The 2016-2018 Business Plan reflects resource and outage plans in support of achieving safe and reliable operations at Pickering consistent with the business case approved by the Board. The 2016-2018 Business Plan is also consistent with the approved Darlington refurbishment budget and schedule. OPG’s business plan is focused on providing value to the Shareholder and electricity customers through its strategic imperatives. The plan also incorporates the Shareholder’s direction and expectations, and meets the objectives of Ontario’s 2013 Long-Term Energy Plan (LTEP) as outlined in Appendix 3. The plan projects net income growing to and average annual regulated rate increases from the planned 5-year rate application of ~0.7% or ~$1.05 on a typical residential customer’s monthly bill, and an overall customer cost of OPG’s generation that will continue to track considerably below that of other generators in Ontario. Return on equity (ROE) is projected to

To increase the return on the Shareholder’s investment to more commercial levels, the Company will focus on maximizing production, continuing to pursue cost efficiencies, and increasing net income by exploring new business growth strategies in both the core business and emerging generation technologies.

As such, OPG’s debt ratio in the plan ranges between and

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EB-2016-0152

Exhibit A2-2-1

Attachment 1

Page 1 of 37

2

The business plan is highly dependent on the outcome of OPG’s upcoming OEB rate application and OEB decisions related to the recovery of pension and other post-employment benefit (OPEB) costs on an accrual basis. Different regulatory outcomes from those assumed in the plan could significantly lower net income, cash flow, and returns to the Shareholder, leading to higher borrowing requirements and increased risk to OPG’s credit rating. This may in turn necessitate curtailment of project or other expenditures. Highlights of the 2016-2018 Business Plan, including the financial projection for the 2019-2021 period, are as follows:

2016 2017 2018 2019 2020 2021

Net Income Attributable to the Shareholder ($ millions)

Return on Equity (%)

Production (net of Surplus Baseload Generation) (TWh)

OM&A Expenses from Ongoing Operations ($ millions)

Capital Expenditures ($ millions)

Headcount from Ongoing Operations

Average Impact of 2017-2021 Rate Application on

Residential Customer's Monthly BillN/A Average increase of ~$1.05/month annually for

2017-2021

Main Assumptions Activities commence in 2016 to achieve Pickering continued operations beyond 2020 The Darlington refurbishment is executed consistent with approved project budget and schedule New nuclear and hydroelectric regulated rates are effective January 1, 2017 Pension and OPEB costs allowed in the 2017-2021 nuclear revenue requirement are limited to cash

amounts, with the difference between accrual and cash amounts (for nuclear and hydroelectric) continuing to be recorded in a deferral account. The OEB assures recovery of these amounts, including associated taxes, through the generic proceeding on this issue or otherwise.

Key Risks Failure to maintain cost and schedule commitments for the Darlington Refurbishment project OEB decision(s) that do not provide adequate cash flow and/or recovery of costs, including

assurance of recovery of pension/OPEB accrual costs (and associated taxes) Ability to retain and attract qualified management employees and leadership talent during the

Darlington refurbishment and continued Pickering operations Adverse impact of life management and equipment aging issues on nuclear generation Impact of financial market conditions on pension, OPEB, and nuclear waste obligations and funds

Further details of the key planning assumptions for the 2016-2021 period are found in Appendix 2. An overview of the 2016-2018 Business Plan, organized by each of OPG’s four strategic imperatives, is provided below. A discussion of the specific elements of the plan is found in Appendix 1, with the underlying detailed financial and headcount information included in Appendix 4.

Operational Excellence The business plan reflects funding and staffing levels aimed at sustaining top performance at the Darlington nuclear station, continuing safe and reliable operation of the Pickering nuclear station, and maintaining strong cost-effective performance at OPG’s hydroelectric and thermal facilities. Operating performance targets for safety and reliability over the planning period will continue to drive operational excellence, including the ultimate goal of zero injuries. The plan strives for continued improvement in operational cost effectiveness of OPG’s generating assets, including staffing levels. Benchmarking studies indicate that OPG has reduced the gap to the average nuclear staffing benchmark from 17% in 2011 to 4% in 2014. With further headcount reductions since 2014, OPG is confident that its nuclear staffing levels are currently at the benchmark level. OPG also benchmarks the costs of the Pickering and Darlington stations against other nuclear stations. On a per unit

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EB-2016-0152

Exhibit A2-2-1

Attachment 1

Page 2 of 37

3

basis, OPG’s all-in operating and capital expenditures for the stations continue to be amongst the lowest in the industry. OPG’s nuclear stations also continue to target strong reliability performance, including, for the 2016-2018 period, a top-quartile forced loss rate performance of 1.0% for the Darlington station and a 5.0% forced loss rate for the Pickering station consistent with planned investment levels at the station. The detailed operational targets and associated initiatives for the Nuclear business unit are found in Appendix 5. OPG’s Nuclear strategic planning framework is included in Appendix 6. The hydroelectric stations also continue to exhibit strong cost effectiveness performance, with OPG’s regulated hydroelectric fleet’s operating costs, excluding the gross revenue charge (GRC) payable to the Province, benchmarking in the second quartile relative to the peer group. OPG strives to maintain an appropriate balance between maintenance and investment levels for its hydroelectric facilities and their performance by utilizing a differentiated investment strategy across the hydroelectric fleet to maintain reliability while not compromising on safety or the environment. Although OPG’s investment levels in its regulated hydroelectric facilities are currently below average levels compared to peers and despite the fact that many of OPG’s facilities are significantly older than the peer group stations, effective planning, maintenance, and risk management have allowed OPG’s stations to benchmark in the second quartile for reliability. Hydroelectric operating targets for the 2016-2018 period also include strong fleet-wide availability factors averaging 89.7%. The detailed operational targets and associated initiatives for the Hydro Thermal Operations are found in Appendix 7. Planned electricity production from OPG’s virtually emission-free generating fleet ranges from to per year over the 2016-2018 period,by 2021. Declining nuclear production over the period reflects the Darlington refurbishment outages, with the first unit outage scheduled to commence in October 2016. Higher production is expected from the regulated hydroelectric stations as forecast surplus baseload generation (SBG) conditions improve. The production plan includes incremental outage days for the Pickering units to undergo inspection and testing in order to attain sufficient confidence in the station’s continued operations beyond 2020. Regulatory approvals by the Canadian Nuclear Safety Commission (CNSC) will be required for the continued operating period as part of the operating licence renewal, expected in 2018. The business plan builds on efficiencies achieved to date, with a focus on pursuing further opportunities for cost effectiveness improvement across the generating business units and support services. Starting in 2016, OPG is adopting Total Generating Cost (TGC) per MWh as an enterprise-wide measure of operational cost effectiveness, in addition to TGC per MWh metrics for each of Nuclear and Hydroelectric operations. TGC is defined as the total of OM&A expenses from ongoing operations, fuel and hydroelectric GRC expenses for OPG-operated stations, and capital expenditures for sustaining projects. Enterprise-wide targets for TGC per MWh range from to over the planning period, as

to the Darlington refurbishment outages, and sustaining capital expenditures fluctuate reflecting work on large sustaining hydroelectric projects. OPG continues to leverage staff attrition in certain areas. Full-time headcount from ongoing operations is planned to , compared to ~9,000 at the end of 2015, reflecting planned hiring in areas where significant attrition is creating critical skill shortages.

* Excludes Darlington refurbishment headcount

11,686

11,215

10,664

10,085

9,489

9,010

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021

Headcount from Ongoing Operations*

Actual

2016-2018 Business Plan & 2019-2021 Projection

Production Actual

(TWh) 2015 2016 2017 2018 2019 2020 2021

Nuclear 44.5 46.8 38.1 38.5 39.0 37.4 35.4

Regulated Hydroelectric 30.4 32.2 32.1 32.7 31.5 32.1 32.0

Contracted Generation Portfolio 2.5

Total Production (Net of SBG Losses) 77.4

Business Plan Projection

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EB-2016-0152

Exhibit A2-2-1

Attachment 1

Page 3 of 37

4

headcount from ongoing operations is projected to decrease to as Pickering units approach their end of life and further efficiencies are realized.

Project Excellence OPG remains focused on delivering projects safely, on time, on budget and with high quality. Major projects over the business plan period are consistent with the 2013 LTEP and include the refurbishment of the Darlington units,

and investments in the redevelopment and expansion of existing hydroelectric sites. OPG will continue to undertake investments in its existing generation assets to improve performance and sustain their long-term value, consistent with the 2013 LTEP.

Total annual capital expenditures including the Darlington refurbishment range from

The business plan assumes that the first Darlington unit to undergo refurbishment, Unit 2, returns to service in February 2020. OPG is targeting to install at least 284 fuel channels as part of the Unit 2 refurbishment by the end of 2018. The second unit refurbishment is assumed to commence immediately after Unit 2 is returned to service and the third unit refurbishment is assumed to start in 2021, subject to the Province’s approval. Planned refurbishment project expenditures are ~$6.5 billion over the 2016-2021 period. Darlington Refurbishment project milestones for the 2016-2018 period are summarized in Appendix 5.

Financial Strength In line with the Company’s commercial mandate, OPG’s business plan is focused on increasing net income and return on the Shareholder’s investment, through higher revenues and a continued focus on efficiency improvements, and ensuring that the Company is able to cost effectively fund its major projects and obligations. In pursuing commercial objectives, OPG takes into account the impact on Ontario electricity customers by continuing to seek further efficiencies in the Company’s cost structure. Net income attributable to the Shareholder is forecast to increase

This will allow OPG to

contribute in earnings and taxes to the Shareholder over the 2016-2018 period. By 2021, net income attributable to the Shareholder is projected to reach The increases in income generally reflect the growth in the regulated rate base as Darlington refurbishment capital is placed in-service, and assumed new regulated rates that take effect at the beginning of 2017. The 2016 budgeted results assume the sale of OPG’s head office property, an asset of OPG’s unregulated business,

471

706

1,231

1,095 1,121 979

858 1,195

1,376

2015 Actual 2016 2017 2018 2019 2020 2021

Capital Expenditures

Sustaining Capital Hydroelectric Development

Darlington Refurbishment

$ millions

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EB-2016-0152

Exhibit A2-2-1

Attachment 1

Page 4 of 37

5

Compared to 2015, annual OM&A expenses from ongoing operations

due to lower pension and OPEB costs. The plan also incorporates continued efficiency improvements expected to be achieved through business unit and support group initiatives, including attrition-based staff reductions in certain areas. The nuclear outage cost profile over the period includes maintenance work expected to be performed on the Darlington units during refurbishment outages, as well as the incremental costs to enable Pickering continued operations. Improved financial results over the planning period will depend on the results of the planned 5-year OEB application for new regulated rates effective January 1, 2017 and the growth in the regulated rate base. Consistent with the Province’s regulation amendment in 2015, the rate application will propose nuclear rate smoothing starting in 2017, which will moderate price spikes during the Darlington refurbishment and eventual Pickering closure period by deferring collection of a portion of the Company’s regulated revenues, including interest on the deferred amounts, until after the end of the Darlington Refurbishment project. OPG’s rate application will therefore seek approval of annual nuclear revenue requirements as well as a smoothed nuclear base rate trajectory. The difference between the approved nuclear revenue requirement and the approved nuclear base rate trajectory will be recorded in the deferral account established by the regulation amendment. OPG’s financial results will reflect amounts deferred in a given year as revenue and income of that year. The estimated combined effect of nuclear and hydroelectric rates assumed from the 2017-2021 rate application is an increase in a typical residential customer’s monthly bill, on average, of ~$1.05 each year over the period to 2021. Under these assumptions, ~$1.2 billion in revenues and associated interest would be deferred for future collection under nuclear rate smoothing by the end of 2018 and ~$2 billion by the end of 2021. Hydroelectric base rates are assumed to increase under an incentive rate-making approach starting in 2017. Regulated rates in 2016 include base rates that are unchanged from 2015 and previously approved rate riders in effect to the end of 2016 for the collection of deferral and variance account balances. The assumed nuclear rate trajectory from the 2017-2021 rate application reflected in the plan is below the 2013 LTEP assumptions for OPG’s nuclear rates.

Operating cash flow dips in 2017 as nuclear production decreases and collection of a portion of revenues is deferred under nuclear rate smoothing, and then improves with assumed regulated rate increases. Management believes that the forecast credit metrics and operating cash flow levels, combined with the support for future collection of rate smoothing deferrals in the 2015 regulation amendment, will support OPG’s current investment grade credit rating during the planning period. A different outcome of the upcoming rate application could result in a weaker financial position and increase the risk of a credit rating downgrade.

* Information beyond 2021 is included for illustrative purposes

* Excludes Darlington refurbishment OM&A expenses and all OEB variance and deferral account offsets

** Includes centrally held pension /OPEB costs

-1.5

0

1.5

3

4.5

6

0

50

100

150

200

250

2016 2018 2020 2022 2024 2026 2028 2030 2032 2034 2036 2038

Nuclear Revenue Requirement and Impact of Nuclear Rate Smoothing*

Nuclear Revenue Requirement Recovered in the year

Nuclear Revenue Requirement Deferred

Smoothed Nuclear Rate

Unsmoothed Nuclear Base Rate

$/MWh $ billions

1526 55 107 104

552 577 579 571 581 584 590

500 354 198 171 131 115 99

2015 Actual 2016 2017 2018 2019 2020 2021

OM&A Expenses from Ongoing Operations*

Operating Business Units (Excl. Pickering Extension Enabling)

Pickering Extended Operations Enabling Costs

Support Services

Other**

$ millions

Filed: 2016-05-27

EB-2016-0152

Exhibit A2-2-1

Attachment 1

Page 5 of 37

6

Assurance of recovery of pension and OPEB costs on an accrual basis (including associated taxes) through OEB regulated rates is a major risk to the business plan. As the generic proceeding related to the treatment of pension and OPEB costs for regulated utilities in Ontario is ongoing, the plan assumes that the recovery of pension and OPEB costs as part of the 2017-2021 period is limited to cash amounts and that the difference between cash and accrual amounts continues to accumulate in an existing OEB authorized deferral account (for both nuclear and hydroelectric operations). The account balance is projected to accumulate to ~$450 million by the end of 2016, with further additions of ~$450 million over the 2017-2021 period. The future outcome of the OEB generic proceeding and related OEB determinations are expected to determine the recoverability of the deferral account (and associated taxes). An OEB decision that results in a write-off of the deferral account balance to net income would result in material net income reductions of up to ~$900 million over the planning period, relative to the plan. This would weaken OPG’s credit metrics, increase the risk to the Company’s credit rating, and negatively impact the Province’s forecast financial results. In its 2015-2017 Business Plan concurrence letter, the Shareholder recognized that OPG’s existing accrual accounting methods for recovery of pension and OPEB costs are a fair representation of the long-term nature of these liabilities. The plan includes an increase in OPG’s nuclear decommissioning and nuclear waste management accounting liabilities of ~$2.3 billion at 2015 year-end, to reflect the planned refurbishment of the not yet refurbished Bruce nuclear units, in line with the announced contract between the IESO and Bruce Power. The associated December 2015 amendments to the lease and other agreements between OPG and Bruce Power related to the Bruce stations are also reflected in the plan. Impacts from the 2017 ONFA Reference Plan update process on the nuclear decommissioning and nuclear waste management liabilities and nuclear segregated funds continue to be developed and therefore are not incorporated into the business plan. The 2017 ONFA Reference Plan will be subject to review and approval by the Province.

Social Licence OPG remains committed to environmental sustainability, high standards of workplace, dam, public, and nuclear safety, and achieving excellent safety performance with the ultimate goal of zero injuries. During the planning period, OPG will continue to make investments to maintain and enhance the safety of its generating assets. This includes continuing to demonstrate strong industry leadership with OPG’s Dam Safety Program, which encompasses public safety and emergency management over the Company’s 238 dams and 65 hydroelectric facilities. Many aspects of the program are considered to be international best practice as determined by an independent panel of international experts. As part of the safe management of its hydroelectric generating facilities, OPG is also taking steps to better understand the potential changes in water flow conditions that these facilities may experience, including consideration of extreme weather events. This includes development of flood forecasting models in an effort to better predict potential impacts of these changes and to put in place appropriate risk mitigation plans. OPG’s focus on safety and climate change adaptation leverages the Company’s affiliation with scientific experts on climate change effects and its participation in the Ontario Climate Advisory Committee

5.7

1,465

2015 Actual 2016 2017 2018 2019 2020 2021

Total Debt and Operating Cash Flow

Total Debt ($b) Net Cash From Operations ($m)

Filed: 2016-05-27

EB-2016-0152

Exhibit A2-2-1

Attachment 1

Page 6 of 37

7

(OCAC), which is made up of representatives from the federal and provincial governments, conservation authorities, universities and industry. The OCAC provides advice to Environment Canada regarding climate needs from a practitioner perspective and facilitates information sharing on climate-related activities being undertaken by different agencies in Ontario. OPG is also continuing to maintain a strong focus on nuclear safety programs and continuing to invest in nuclear safety systems. In the past five years, as a result of lessons learned from the Fukushima accident, OPG has strengthened the nuclear safety program at its nuclear stations by acquiring and installing multiple portable emergency mitigating equipment units, which are dedicated to providing additional fuel cooling and protection of containment in case of an extreme external event for which the units were not originally designed. OPG has also enhanced its emergency preparedness and response capability by conducting emergency drills for extreme external events, ranging from a single-unit to multi-unit events, and by improving protocols and procedures in response to these events. Probabilistic safety assessment results have confirmed that these initiatives have further strengthened the safety of OPG’s nuclear plants. OPG will continue to operate with nuclear safety as an overriding priority. The plans for OPG’s hydroelectric operations consider the impact of water availability, its utilization and the associated environmental and stewardship responsibilities. OPG will continue to balance the economic, environmental, social, and legal requirements associated with the watersheds on which it operates while optimizing production from its hydroelectric stations. The current regulatory framework requires water management plans prescribing water elevation and flow limits to be authorized by the Province for all watersheds and interior rivers in Ontario. OPG has completed water management plans for all rivers on which it operates that are subject to water management plan requirements, through a collaborative approach with significant stakeholder engagement, and is legally obligated to operate within these constraints. Throughout the planning period, OPG will also continue to focus on building long-term, mutually beneficial working relationships with First Nations and Métis communities, including

OPG’s business plan supports Ontario’s climate change strategy and technology deployment and electrification objectives, including microgrids, energy storage technology and electric vehicles. In addition to continuing to drive a focus on environmental performance through business plan targets, the decisions to proceed with the Darlington refurbishment and to pursue continued operations at Pickering will contribute to achieving Ontario’s climate change objectives by leveraging OPG’s lower-priced, carbon-free baseload nuclear power. Job creation and other economic benefits from the Darlington refurbishment and continued operation of both stations will also accrue to the benefit of the Province. Taking into account the assumed rate increases over the 2017-2021 period, the cost to customers of electricity generated by OPG is expected to below the average non-OPG cost of electricity in Ontario to 2018 and by 2021. The expected average increase from OPG’s upcoming nuclear and hydroelectric rate application on a typical residential customer’s monthly bill over the period to 2021 is estimated to be ~0.7% each year. The rate of increase in the overall average price for OPG’s electricity continues to be significantly lower than the rate of increase for a typical Toronto Hydro’s residential customer bill. Over the last decade and projecting for the next 10 years, the average price for OPG’s generation ~5 ¢/kWh in 2005 to

while a typical Toronto Hydro customer’s bill increases from ~9 ¢/kWh in 2005 to over 25 ¢/kWh by 2025. Additionally, OPG’s contribution to the total customer bill has been declining over this period, as a result of lower OPG price increases and reductions in OPG’s generation volume.

6.4

10.5

2015 2016 2017 2018 2019 2020 2021

Customer Cost of OPG Generation

vs Non-OPG Generation

Avg. Customer Cost of OPG Generation

Avg. Customer Cost of Non-OPG Generation

¢/kWh

39%

Filed: 2016-05-27

EB-2016-0152

Exhibit A2-2-1

Attachment 1

Page 7 of 37

8

Key Risks to the Business Plan

1. Failure to maintain cost and schedule commitments for the Darlington Refurbishment project: There are financial and reputational risks to OPG if the actual costs of the Darlington Refurbishment project exceed the budget or if OPG does not meet the project schedule. In addition, failure to achieve the objectives of the refurbishment project may adversely impact the post-refurbishment performance of the station. Failure to execute the refurbishment of the first unit as planned may result in the Province not proceeding with OPG’s refurbishment of each of the remaining units. The ability to staff the refurbishment project with a highly skilled, trained and engaged workforce at all levels is critical to the ability to deliver the project on budget, on schedule and with high quality.

2. OEB decision(s) that do not provide adequate cash flow and/or recovery of costs: OPG’s ability to execute its operational and project strategies, contribute to the Province’s results, grow the business, and continue to invest in Ontario’s economy is dependent on fair recovery of costs and earning an appropriate return on the investment in the assets of the regulated operations through the OEB process. OEB decisions that do not allow for the full recovery of costs including pension and OPEB accrual costs, do not provide an appropriate return and/or do not provide sufficient cash flow will reduce OPG’s earnings, increase the credit rating risk, and diminish the Company’s ability to deliver on its strategic imperatives and fiscal commitments.

3. Inability to retain and attract leadership talent and qualified management employees during the Darlington refurbishment and continued Pickering operations: Given the combination of an aging workforce, management group compensation constraints, and significant projects and initiatives in progress, including the Darlington refurbishment and the continuation of Pickering operations, an approved executive compensation framework that attracts, aligns and retains executive talent is imperative. Effective, knowledgeable and engaged leadership and other management employees are critical to the successful implementation of OPG’s strategic imperatives.

4. Adverse impact of life management and equipment aging issues on nuclear generation: As Pickering station operations are extended further to 2024 and the Darlington station prepares for an additional 30+ years of operating life, management of life limiting and other critical components is essential to ensuring reliability and predictability in generation performance of the stations. Early identification of age-related degradation of station components and discovery of unexpected conditions require a timely risk management and continuing maintenance focus.

5. Impact of financial market conditions on pension, OPEB, and nuclear waste obligations and related funds: OPG’s financial results are sensitive to changes in underlying market conditions, including interest rates, equity and bond prices, and inflation rates. These factors can materially impact the earnings from, and contributions to OPG’s segregated nuclear funds and registered pension fund, which together manage ~$30 billion in assets. These factors can also affect the associated post-retirement and nuclear decommissioning and nuclear waste management obligations, which are a material driver of OPG’s costs.

* Represents Toronto Hydro residential customer bill breakdown as forecast by OPG

0%

20%

40%

60%

80%

100%

2005 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025

Breakdown of Total Electricity Service Charge for Toronto Residential Customer*

OPG Generation Share Non-OPG Generation Share

Delivery, Tax & Other Charges Share

Filed: 2016-05-27

EB-2016-0152

Exhibit A2-2-1

Attachment 1

Page 8 of 37

9

RECOMMENDATION / RESOLUTION It is recommended that the Board of Directors approve OPG’s 2016-2018 Business Plan including the financial projection for the 2019-2021 period. Recommended by: Approved for submission to the Board of Directors by:

_[original signed by:]______________ _[original signed by:]______________ Ken Hartwick Jeff Lyash Senior Vice President, President and CEO Finance, Strategy, Risk and Chief Financial Officer This Board memo was reviewed and approved for submission to the Board of Directors by the Audit and Risk Committee at their meeting on May 11, 2016. APPENDICES 1. 2016-2018 Business Plan Particulars 2. Key Planning Assumptions 3. Meeting the Province’s LTEP Objectives 4. Financial and Headcount Plan Information 5. Nuclear Financial Plan, Operational Targets, and Initiatives 6. Nuclear Strategic Framework 7. Hydro-Thermal Financial Plan, Operational Targets, and Initiatives 8. Business & Administrative Services Financial Plan, Operational Targets, and Initiatives

Filed: 2016-05-27

EB-2016-0152

Exhibit A2-2-1

Attachment 1

Page 9 of 37

10

Filed: 2016-05-27

EB-2016-0152

Exhibit A2-2-1

Attachment 1

Page 10 of 37

11

APPENDIX 1: 2016-2018 Business Plan Particulars

Regulated Rates In the second quarter of 2016, OPG plans to file a 5-year nuclear and hydroelectric rate application with the OEB for the 2017-2021 period. Consistent with the Province’s amendment to Ontario Regulation 53/05 in 2015, the rate application will include a rate smoothing proposal. Rate smoothing avoids large price spikes that would arise during the Darlington refurbishment and at the end of Pickering operations without rate smoothing, by deferring the recovery of revenues to the post-refurbishment period. Under rate smoothing, OPG’s rate application will seek approval of annual nuclear revenue requirements as well as a smoothed nuclear rate trajectory for the period. The difference between the approved revenue requirement and the approved base rate trajectory will be recorded in the deferral account, as discussed below.

The 2016-2018 Business Plan assumes smoothed nuclear base rate increases of 11% per year beginning in 2017, until the end of the Darlington refurbishment period. The resulting rates are expected to be below unsmoothed nuclear base rates. The assumed nuclear rate trajectory from the 2017-2021 rate application reflected in the plan is below LTEP assumptions for OPG’s nuclear rates. In accordance with the regulation amendment, the portion of the approved revenue requirement deferred for future collection under rate smoothing will be determined by the OEB and captured in a deferral account, which will earn interest at a long-term debt rate reflecting OPG’s long-term borrowing cost as authorized by the OEB, compounded annually. Pursuant to the regulation, the OEB must authorize the recovery of the account balance over a period of up to 10 years beginning at the end of the refurbishment project. The rate smoothing illustration shown assumes recovery of the deferred balance over the 10-year period following the completion of the Darlington Refurbishment. Based on the assumed rate trajectory, the deferral account balance, including associated interest, is projected to grow to ~$1.2 billion by 2018 and ~$2 billion by 2021, peaking at ~$3.5 billion towards the end of the Darlington Refurbishment project. In accordance with US GAAP, rate smoothing deferrals in a given period will be recorded in the revenue and income of that period, with the deferral account recorded as a regulatory asset on the balance sheet. Accordingly, the collection of the deferred amounts in future years will not result in additional net income. The plan assumes hydroelectric base rate increases of ~1.5% per year under an incentive rate-making approach starting in 2017, off the existing base rates with some adjustments. In addition, most nuclear and regulated hydroelectric deferral and variance account balances accumulated to the end of 2015 since the last OEB approval as of December 31, 2014 are assumed to be cleared as part of the upcoming rate application. Overall, the estimated average impact on a typical residential customer’s monthly bill of the assumed rate increases from the 2017-2021 rate application is an increase of ~0.7% or ~$1.05 each year to the end of 2021.

* Information beyond 2021 is included for illustrative purposes

6.4

10.5

2015 2016 2017 2018 2019 2020 2021

Customer Cost of OPG Generation

vs Non-OPG Generation

Avg. Customer Cost of OPG Generation

Avg. Customer Cost of Non-OPG Generation

¢/kWh

39%

-1.5

0

1.5

3

4.5

6

0

50

100

150

200

250

2016 2018 2020 2022 2024 2026 2028 2030 2032 2034 2036 2038

Nuclear Revenue Requirement and Impact of Nuclear Rate Smoothing*

Nuclear Revenue Requirement Recovered in the year

Nuclear Revenue Requirement Deferred

Smoothed Nuclear Rate

Unsmoothed Nuclear Base Rate

$/MWh $ billions

Filed: 2016-05-27

EB-2016-0152

Exhibit A2-2-1

Attachment 1

Page 11 of 37

12

Taking into account the assumed rate increases over the 2017-2021 period, the cost to customers of electricity generated by OPG is expected to the average non-OPG cost of electricity in Ontario to 2018 and by 2021. Regulated rates in 2016 include base rates that are unchanged from 2015 and previously approved rate riders in effect to the end of 2016 for the collection of deferral and variance account balances.

Net Income and Return on Equity Although net income and return on equity (ROE) are forecast to improve over the planning period, different regulatory outcomes from those assumed in the plan could result in significantly lower net income and returns to the Shareholder. The 2016 budgeted net income attributable to the Shareholder of is

as by the impact of

higher nuclear generation in 2016. A number of other, largely offsetting factors are reflected in the change in net income from 2015 to 2016, including:

ue to higher capitalized interest for Darlington refurbishment capital expenditures, and interest expected to be recorded in an existing regulatory variance account in respect of the Darlington refurbishment pre-requisite projects coming in-service;

Higher earnings on the nuclear segregated funds in 2016, net of higher accretion expense on the nuclear decommissioning and nuclear waste management liabilities;

Reduction in hydroelectric revenues in 2016 due to a planned outage to rehabilitate the Sir Adam Beck Pump GS reservoir; and

Net income attributable to the Shareholder is planned to The primarily result from:

New nuclear and hydroelectric regulated rates assumed to come into effect at the beginning of 2017; Starting in 2017, recognition of regulatory assets for the portion of the nuclear revenue requirement,

including associated interest, deferred for future recovery under nuclear rate smoothing; Higher capitalized interest for the Darlington refurbishment capital expenditures;

These factors are partially offset

and Net income attributable to the Shareholder is projected to

as the first refurbished Darlington unit returns to service and enters rate base in February 2020 and as OPG’s ROE is forecast

OEB’s decisions related to the recovery of pension and OPEB costs (and associated taxes) are a major risk to OPG’s, and therefore the Province’s, future financial results. As the generic proceeding related to the treatment of pension and OPEB costs for regulated utilities in Ontario is ongoing, the plan assumes that the 2017-2021 approved nuclear revenue requirement limits the recovery of pension and OPEB costs to cash

Filed: 2016-05-27

EB-2016-0152

Exhibit A2-2-1

Attachment 1

Page 12 of 37

13

amounts, with the difference between accrual and cash amounts (for nuclear and hydroelectric operations) assumed to continue accumulating in an existing deferral account. In addition to the ~$450 million projected to be recorded in the account by the end of 2016, a further ~$450 million would be added during the 2017-2021 period. If the OEB indicates that the balance in the existing cash-to-accrual deferral account (and/or the associated taxes) are not likely to be recovered, net income will be significantly lower than forecast in the plan. Unfavourable income impacts could be up to ~$900 million over the planning period. Any write-offs are expected to be recorded in the period the applicable OEB decision is issued. In its 2015-2017 Business Plan concurrence letter, the Shareholder recognized that OPG’s existing accrual accounting methods for recovery of pension and OPEB costs are a fair representation of the long-term nature of these liabilities. OPG continues to believe that the accrual accounting basis aligned with OPG’s financial accounting requirements is the most appropriate rate recovery basis for the Company’s pension and OPEB costs.

Operations, Maintenance & Administration Expenses Annual OM&A expenses from ongoing operations, which exclude the impact of regulatory variance and deferral account offsets as well as Darlington Refurbishment project expenses,

The decreases in OM&A expenses from ongoing operations over the 2016-2018 period primarily reflect declining pension and OPEB costs, partly offset by incremental outage and other work program costs to enable Pickering continued operations in line with the business case approved by the Board of Directors, and an increase in other business unit expenditures across the organization, primarily driven by the following: Changes in nuclear outage scope, including:

o Maintenance work on Darlington Unit 2 to be performed during the refurbishment outage beginning in 2016, which would have otherwise occurred online or during regular outages;

o Deferral of Single Fuel Channel Replacement outage work at Pickering from 2015 to 2016; and o Single Fuel Channel Replacement outage work at Darlington scheduled for 2017.

Additional maintenance and other work programs at the nuclear stations to maintain asset reliability and address equipment aging issues;

Planned external hiring to fill critical skill gaps and support effective succession planning across the Company, which is discussed further in the Headcount section below;

Sustaining projects to maintain asset reliability at regulated and contracted hydroelectric stations, including unit overhauls, repair work, and civil structure remediation;

Labour cost escalation pursuant to collective agreements, and inflationary impacts; and Cost increases related to compliance and statutory requirements, including higher nuclear liability

insurance requirements pursuant to federal legislation, and Darlington refurbishment oversight costs. The increases in business unit expenditures are partially offset by the following over the 2016-2018 period: Incremental nuclear outage costs in 2015 related to the Darlington Vacuum Building Outage (VBO); A gradual decline in full-time staffing levels in 2017 and 2018, after the planned increase in 2016, to

reflect continuous efficiency improvements leveraging staff attrition, and other changes; Savings from the new information technology services outsourcing contract, which is effective in

2016, and completion of cyber security-related work in support of the nuclear operations in 2016; Completion of Niagara region bridge divesture activities in 2015; Higher expenses in 2015 associated with nuclear capital project write-offs; and

* Excludes Darlington refurbishment OM&A expenses and all OEB variance and deferral account offsets

** Includes centrally held pension /OPEB costs

1526 55 107 104

552 577 579 571 581 584 590

500 354 198 171 131 115 99

2015 Actual 2016 2017 2018 2019 2020 2021

OM&A Expenses from Ongoing Operations*

Operating Business Units (Excl. Pickering Extension Enabling)

Pickering Extended Operations Enabling Costs

Support Services

Other**

$ millions

Filed: 2016-05-27

EB-2016-0152

Exhibit A2-2-1

Attachment 1

Page 13 of 37

14

OM&A expenses from ongoing operations continue to decrease over the 2019-2021 period, reflecting the following: Completion of work programs to enable Pickering continued operations; Declining pension and OPEB costs; Reductions in staffing levels; and Decline in nuclear outage expenses in 2021 as no major outages are planned to occur at the

Darlington station in that year, partly offset by the incremental costs of the assumed station-wide Pickering VBO in 2021.

The declining pension and OPEB costs over the period are due to a combination of factors, including: projected pension asset return, the impact of increased employee contributions for PWU, Society and Management employees, a slightly higher accounting discount rate, and lower amortization of net historical actuarial losses. The regulated portion of these decreases is assumed to be offset by the pension and OPEB cash-to-accrual deferral account as discussed above, resulting in little impact on net income. The regulatory variance and deferral account offsets to OM&A expenses decline over the planning period as pension and OPEB costs decrease. The Darlington Refurbishment project expenses vary over the planning period with the expected timing of pressure tube and feeder removal activities and other work programs not eligible for capitalization.

Production Total OPG production is projected to from to This trend primarily reflects the impact of Darlington refurbishment outages over the period, including a partial overlap starting in 2021 between the assumed second and third unit refurbishments. The 2016 budgeted production of from 77.4 TWh in 2015, primarily as a result of the Darlington VBO in 2015 and a projected improvement in SBG conditions in 2016. The following other main factors affect the variability in the planned nuclear production over the period: Incremental planned

outage days at the Pickering station to enable continued operations in line with the business case approved by the Board;

Single Fuel Channel Replacement outage work at the Pickering station in 2016 and 2019 and at the Darlington station in 2017 and 2020;

Initial increase in the forced loss and planned outage days expected at the Darlington station as the first refurbished unit returns to service in early 2020; and

Assumed Pickering VBO in 2021 requiring the shutdown of all units for the duration of the outage.

The following are the main drivers of the forecast hydroelectric production for the period: Higher water flows on the Niagara and St. Lawrence rivers in 2016 and 2017, returning to median

levels thereafter; Improvement in SBG conditions in 2016 and 2017; Outages at the Sir Adam Beck units, including outages to accommodate Hydro One’s planned work

on the Beck switchyard and OPG’s planned work at the Sir Adam Beck 1 GS to rehabilitate the forebay and crossover canal in 2019 and the power canal liner over 2020 and 2021; and

Production and SBG Losses Actual

(TWh) 2015 2016 2017 2018 2019 2020 2021

Nuclear

Darlington 23.3 26.0 19.0 19.3 19.7 17.7 16.6

Pickering 21.2 20.8 19.1 19.2 19.4 19.6 18.8

Total Nuclear 44.5 46.8 38.1 38.5 39.0 37.4 35.4

Regulated Hydroelectric 30.4 32.2 32.1 32.7 31.5 32.1 32.0

Contracted Generation Portfolio 2.5

Total Production (Net of SBG Losses) 77.4

Regulated Hydroelectric SBG Losses 2.8 1.6 0.6 0.4 0.3 0.2 0.2

Contracted Plant SBG Losses 0.4

Total SBG Losses 3.2

Business Plan Projection

Filed: 2016-05-27

EB-2016-0152

Exhibit A2-2-1

Attachment 1

Page 14 of 37

15

Headcount The downsizing efforts from OPG’s Business Transformation initiative have been successful in achieving significant attrition-based headcount reductions across the organization since 2011, with cumulative savings from the reductions reaching $1 billion in 2016. However, attrition is resulting in skill shortages in certain areas (particularly in the Nuclear Operations and Nuclear Projects organizations), which is necessitating hiring to fill key vacancies. In 2015, OPG embarked on a workforce planning and resourcing initiative to address skill set gaps and optimize workforce planning strategies. After a planned initial increase of

as the Company continues to implement efficiency improvement initiatives and leverage attrition in certain areas. By the end of 2018, headcount from ongoing operations is expected to be than at the end of 2015. This includes ~160 employees in the Nuclear organization reflecting hiring to fill critical skill gaps, including operators in training, and ~25 employees in People & Culture, primarily in support of nuclear operator training and the Darlington refurbishment.

Employee productivity, as measured by GWh per headcount, improves during the 2016-2018 period, compared to 2015. Staffing levels from ongoing operations are expected to continue to decrease after 2018 and, by the end of 2021, are expected to be than at the end of 2015 and than at the end of 2018. The decrease over the 2019-2021 period reflects reductions in staffing levels as the Pickering station begins to approach its end of life, the impact of employee attrition,

The GWh per headcount productivity measure is expected to continue to improve over the 2019-2021 period. The projected staffing levels meet the expectation set out in the Shareholder’s 2015-2017 Business Plan concurrence letter that the Company’s non-nuclear full-time headcount be reduced by five per cent from 2015 planned levels by 2020. The Darlington refurbishment headcount, which is not considered part of ongoing operations, increases from ~235 in 2015 to ~500 in 2016 and remains relatively stable thereafter. The planned increase in 2016 includes engineering, operations, maintenance, and project management employees that are joining the project upon its transition to the execution phase.

* Excludes Darlington refurbishment headcount** Production is normalized by adding back hydroelectric surplus

baseload generation impacts and, in 2017-2021, the lower production due to the Darlington refurbishment outages

11,686

11,215

10,664

10,085

9,489

9,010

7.6 7.67.9

8.1

8.9

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021

Ongoing Operations Headcount and Productivity*

Actual

2016-2018 Business Plan & 2019-2021 ProjectionGWh per Headcount**

Filed: 2016-05-27

EB-2016-0152

Exhibit A2-2-1

Attachment 1

Page 15 of 37

16

Capital and Provision Expenditures OPG’s capital program is focused on continued efficient utilization of existing assets through sustaining expenditures, the refurbishment of the Darlington units, development of new and existing hydroelectric sites, and pursuit of other renewable energy opportunities, in line with the 2013 LTEP. Total capital expenditures range from

over the 2016-2018 period, an increase from in 2015, largely due to higher Darlington refurbishment expenditures as the project enters the execution phase. Planned Darlington refurbishment capital expenditures are consistent with the Board-approved total project budget and range from ~$900 million to $1.2 billion per year over the 2016-2021 period. The first refurbished unit is assumed to return to service in February 2020, with the second unit refurbishment commencing immediately thereafter and the third unit refurbishment starting in 2021, assuming necessary approvals from the Province. The lower refurbishment expenditures in 2019 and 2020 reflect lower expenditures during the commissioning of the first unit and the defueling of the second unit. Sustaining capital expenditures are planned to from 2015 to 2016, reflecting higher expenditures for nuclear, Nuclear sustaining capital expenditures increase from ~$315 million in 2015 to ~$350 million in 2016, reflecting: Additional demand for aging equipment management projects; Required work in support of safe and reliable post refurbishment operations not included in the

Darlington Refurbishment project scope; and Expenditures on regulatory programs.

Nuclear sustaining expenditures are planned to decrease over the 2017-2021 period, to below 2015 levels, as the Pickering station begins to approach its end of life and regulatory programs are completed. Additional Darlington expenditures over the period will bring investment levels closer to peers. In 2021, non-refurbishment capital project work at Darlington is temporarily restricted as two units undergo refurbishment. Forecast regulated hydroelectric sustaining capital expenditures over the 2016-2021 period, excluding the Sir Adam Beck Pump GS reservoir rehabilitation and the Sir Adam Beck 1 canal liner rehabilitation major projects, average at ~$120 million per year, an increase of ~$35 million from 2015. The increase reflects a number of projects including: The overhaul and upgrade of the DeCew Falls GS Unit 2 starting in 2016; Electrical equipment, headgate and sluicegate replacements in Eastern Operations; Rehabilitation of the forebay and crossover canal at the Sir Adam Beck 1 GS in 2019; Flow control equipment replacements in Northwest Operations; Unit overhauls at the Sir Adam Beck Pump GS; and Construction of a new powerhouse structure over the existing units at the R.H. Saunders GS, to

facilitate maintenance work. The total Sir Adam Beck Pump GS reservoir rehabilitation project expenditures are forecast to be ~$45 million over 2016 and 2017 and the total expenditures for the canal liner rehabilitation project at the Sir Adam Beck 1 GS are projected at ~$125 million over 2020 and 2021.

* Includes expenditures budgeted by the Nuclear organization and Support Services

471

706

1,231

1,095 1,121 979

858 1,195

1,376

2015 Actual 2016 2017 2018 2019 2020 2021

Capital Expenditures

Sustaining Capital Hydroelectric Development

Darlington Refurbishment*

$ millions

Filed: 2016-05-27

EB-2016-0152

Exhibit A2-2-1

Attachment 1

Page 16 of 37

17

In addition to the Darlington refurbishment, development projects over the planning period include:

Conversion of the Sir Adam Beck Units 1 and 2 to 60 Hz to increase capacity; Expansion/redevelopment of regulated hydroelectric stations that are approaching end of life, by

leveraging existing infrastructure (e.g., Ranney Falls, Coniston and Calabogie generating stations)

Planned expenditures against previously established provisions for nuclear station decommissioning and nuclear waste management range from ~$320 million to ~$365 million in the 2016-2018 period, increasing to ~$460 million by 2021, compared to $212 million in 2015. The increases over the period reflect the following: The Nuclear Waste Management Organization’s planned siting process activities for the Adaptive

Phased Management used fuel disposal program; Expenditures on the Darlington refurbishment nuclear waste containers; and Assumed expenditures for proceeding with OPG’s low and intermediate level waste deep geological

repository (L&ILW DGR), which reflects a planning assumption that a site preparation and construction licence for the project would be received in 2016. This assumption was finalized for planning purposes prior to the announcement by the federal Minister of Environment and Climate Change on February 18, 2016 that additional information on the environmental assessment (EA) for the project was being requested.

Eligible nuclear provision expenditures are funded from the nuclear segregated funds.

Financing, Liquidity and Credit Metrics OPG’s financial objectives include having sufficient liquidity and ensuring availability of cost effective funding. Maintaining an investment grade credit rating is critical to the Company’s ability to access cost effective financing. To support these objectives, OPG continues to monitor the FFO/Total Debt ratio and the Debt/EBITDA ratio, which are the core measures used in Standard & Poor’s credit rating methodology, and the FFO Adjusted Interest Coverage ratio, which is OPG’s main liquidity metric. OPG expects to have sufficient liquidity in 2016,

largely from the collection of regulatory account balances authorized by the OEB in 2015. Operating cash flow is then expected to decline to

primarily as nuclear production decreases by ~9 TWh while collection of revenues is deferred under nuclear rate smoothing. Operating cash flow is projected to increase starting in

as nuclear base rates are assumed to increase by 11% per year, partly offset by the impact of decreasing nuclear production.

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Exhibit A2-2-1

Attachment 1

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18

Total debt is forecast to as collection of revenue is deferred under nuclear rate smoothing and

The debt ratio ranges from which is levels reflected in the deemed capital structure used by the OEB to set regulated rates. The plan assumes that the Darlington refurbishment expenditures are financed through general-purpose long-term corporate debt, which continues to be sourced through the OEFC with 10-year maturities.

The cash flow forecast for 2016 assumes proceeds from the Shareholder-directed sale of OPG’s head office property, an asset of the Company’s unregulated business,

The 2016 forecast also reflects the purchase of nine million Hydro One Limited common shares for investment purposes to mitigate the risk of future price volatility related to OPG’s future share delivery obligations under collective agreement provisions.

Management believes that the forecast credit metrics and operating cash flow levels, combined with the support for future collection of nuclear rate smoothing deferrals from the Province’s regulation amendment in 2015, should continue to support OPG’s current investment grade credit rating. Different regulatory outcomes from those assumed in the plan could result in significantly lower cash flows, increased borrowing and weaker credit metrics, increasing the risk of a credit rating downgrade. In turn, this could increase costs, limit borrowing capacity, and/or necessitate curtailment of project or other expenditures.

* Calculated using the methodology per OPG's external financial filings

5.0

2015 Actual

2016 2017 2018 2019 2020 2021

FFO Adjusted Interest Coverage Ratio*

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Exhibit A2-2-1

Attachment 1

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19

Delivering Shareholder Value OPG’s Total Shareholder Return consists of net income, income taxes, hydroelectric gross revenue charge payments, and payments in lieu (PILs) of property taxes to the OEFC. The 2016 Total Shareholder Return on OPG’s fiscal basis is forecast at

including the effect of the assumed sale of the OPG head office property in 2016.

Risks The key risks associated with the 2016-2018 Business Plan are outlined below. Operational and Project Risks Major operational and project risks include the following: Failure to maintain the Darlington refurbishment cost and schedule commitments per the approved

project budget and schedule; Failure to meet the objectives of the first unit refurbishment, resulting in sub-optimal post-

refurbishment performance; Failure to obtain the Province’s approval for refurbishing each of the subsequent Darlington units; Inability to retain and attract effective, knowledgeable and engaged leadership talent during the

Darlington refurbishment and continued Pickering operations given an aging workforce and Management group compensation constraints;

Failure to appropriately staff operational and support groups in critical skill areas given ongoing demographic challenges and compensation constraints;

Inability to achieve production targets, including risks associated with unit capability factors, planned nuclear outage performance, nuclear station lifecycle management, and human performance;

Risk of increased operating costs as a result of greater-than-planned deterioration of station components and systems, discovery of unexpected conditions, and/or equipment failures; and

Risk of technical challenges in confirming ability to operate Pickering beyond 2020, and/or failure to obtain regulatory assurance from the CNSC in support of the station’s continued operations, including inability to renew the operating licence without conditions.

Rate Regulation Risks OEB’s rulings impacting OPG’s rate regulated operations may be unfavourable compared to assumptions in the plan, including the following: Inability to receive sufficient assurance from the OEB for future recovery of the pension and OPEB

cash-to-accrual deferral account balance projected at ~$450 million by the end of 2016 with further additions totalling ~$450 million over the 2017-2021 period, and associated taxes, which would result in a write-off against net income;

An OEB-set nuclear rate smoothing trajectory that does not provide sufficient cash flow to fund operations, projects and/or obligations, and/or to maintain the current investment grade credit rating. A credit rating downgrade would increase borrowing costs and could reduce borrowing capacity;

OEB-approved revenue requirements that do not allow for recovery of the full costs of the regulated operations and/or do not allow the regulated business to earn an appropriate return; and

An effective date for new regulated rates that is later than the assumed January 1, 2017 date, which would lower revenue and cash flow compared to the plan.

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Exhibit A2-2-1

Attachment 1

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20

Financial Risks Key financial risks impacting OPG’s business plan include the following: Impact of financial market conditions on key inputs to the 2017 ONFA Reference Plan update cycle,

including discount rates and escalation factors; Cost estimate changes as a result of the 2017 ONFA Reference Plan update that can significantly

increase the nuclear decommissioning and nuclear waste management liabilities and future required contributions to the associated segregated funds, and decrease earnings, compared to the plan;

Risk of lower than planned returns on nuclear segregated and pension fund assets as a result of various market factors, including equity prices, interest rates, inflation, and commodity prices, which would lower net income and potentially increase future funding requirements compared to the plan;

Risk of lower discount rates and other differences in economic assumptions for pension and OPEB accounting valuations, compared to the plan, due to different underlying financial market conditions; and

Uncertainty with respect to the timing of the Shareholder-directed sale of the head office property.

Plan-Over-Plan Net Income Changes Net income attributable to the Shareholder in is than the previous plan. Net income attributable to the Shareholder of is than the previous plan. The main drivers of the changes are outlined in the table below.

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Exhibit A2-2-1

Attachment 1

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21

APPENDIX 2: Key Planning Assumptions

Key Planning Assumptions Unit 2 is the first Darlington unit to be refurbished, from October 2016 to February 2020. Province’s

approval is received to refurbish the second unit starting immediately after the first unit is returned to

service, as well as the third unit starting in 2021.

All six operating Pickering units operate until 2022, with four units operating until 2024. The plan

includes additional costs, beginning in 2016, and outage days, beginning in 2017, to achieve Pickering

operations beyond 2020, in line with the business case approved by the Board of Directors.

A station-wide Vacuum Building Outage takes place at Pickering in 2021

The plan reflects currently approved station service lives, for accounting purposes, for the Pickering GS

to the end of 2020 and for the Darlington GS to 2052. The Pickering service life will be reassessed

following completion of technical work confirming ability to achieve operations beyond 2020.

The site preparation and construction licence is received in 2016 for the proposed L&ILW DGR. This assumption was finalized prior to the February 18, 2016 announcement by the federal Minister of Environment and Climate Change requesting additional information on the EA for the project.

The following major projects are carried out at the Sir Adam Beck plants:

o Sir Adam Beck Pump GS reservoir rehabilitation is completed in the first half of 2017

o Sir Adam Beck Units 1 & 2 are converted to 60 Hz over the 2018-2020 period

o Sir Adam Beck 1 canal liner rehabilitation takes place over 2020 and 2021

Nuclear base rates increase by 11% per year under nuclear rate smoothing, starting in 2017.

Hydroelectric base rates increase by ~1.5% per year, off the existing base rates, with some

adjustments, under an incentive regulation approach starting in 2017.

Recoveries for pension and OPEB are limited to cash requirements in the 2017-2021 rate application,

pending the outcome of OEB’s generic consultation and any other applicable determinations on the

matter, with the difference between cash and accrual amounts continuing to accumulate in the existing

deferral account (for nuclear and hydroelectric operations).

At Shareholder’s direction, OPG’s head office property, an asset of the unregulated business, is sold

Nuclear Fund investments earn 5.15%/yr

Pension fund investments earn 6%/yr. An accounting discount rate of 4.1% is used for valuing pension

costs and 4.2% for other post retirement benefit costs.

Actuarial funding valuations of OPG’s registered pension plan are carried out as of January 1, 2017 and

as of January 1, 2020

Due to inherent uncertainties, inflationary impacts on salary costs are assumed for periods after the

expiry of the current collective agreements

Due to uncertainties and their preliminary nature, impacts on the nuclear decommissioning and nuclear

waste management liabilities and the associated segregated funds from the 2017 ONFA Reference

Plan update process are not reflected in the plan, as they continue to be developed

Existing OEFC debt platform continues to be used for long-term corporate debt purposes,

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Exhibit A2-2-1

Attachment 1

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22

APPENDIX 3: Meeting the Province’s LTEP Objectives

Meeting the Province’s LTEP Objectives The 2016-2018 Business Plan meets the objectives of Ontario’s 2013 LTEP, as summarized below:

LTEP Projects and Initiatives OPG’s 2016-2018 Business Plan

Lower Mattagami project in-service by 2015 All units in service ahead of June 2015 target

Thunder Bay on advanced biomass in 2015 Project completed on schedule

Begin refurbishment of one Darlington unit in 2016 Project on schedule as approved by Shareholder

Meet Refurbishment principles as outlined in LTEP Refurbishment plan adheres to LTEP principles

Explore business opportunities outside Ontario

Export products and services internationally

Contribute to reduction in OM&A within the sector Savings from significant headcount reductions to date and further efficiency improvement opportunities are embedded in the plan

Aboriginal participation in Peter Sutherland Sr. GS (formerly New Post Creek) development and large renewable projects

Partnerships with First Nations include the Lower Mattagami River project, the Peter Sutherland Sr. GS and the Nanticoke solar project

Maintain site preparation licence for Darlington New Build

Plan supports maintaining licence and associated Environmental Assessment

Source additional renewable energy, including solar Capital investment opportunities included in plan

Nanticoke solar project awarded under IESO’s LRP program

Consider potential Little Jackfish hydroelectric development

Expected continued operations of Pickering to 2020 The plan reflects Shareholder’s approval to proceed with plans to pursue continued Pickering operations up to 2024

Flexibility for up to ~3,000 MW of capacity post 2019

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Exhibit A2-2-1

Attachment 1

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23

APPENDIX 4: Financial and Headcount Plan Information

Key Financial Metrics Actual

(in millions of dollars unless otherwise noted) 2015 2016 2017 2018 2019 2020 2021

Net Income Attributable to the Shareholder 402

Net Income 417

Earnings Before Tax 509

Return on Equity* 4.0%

Nuclear Total Generating Cost per MWh** ($/MWh) 66.3 63.7 74.8 73.0 73.3 76.1 75.1

Hydroelectric Total Generating Cost per MWh** ($/MWh)

Enterprise Total Generating Cost per MWh** ($/MWh)

FFO / Total Debt Ratio (%) (Minimum threshold of 9%)

Debt / EBITDA Ratio (times) (Maximum threshold of 5.5)

FFO Adjusted Interest Coverage Ratio* (times)

(Minimum threshold of 3) 5.0

Debt Ratio 35%

Net Cash from Operations 1,465

Cash Balance at Year-End 464

Total Debt at Year-End 5,697

Total Return to Shareholder***

OM&A Expenses from Ongoing Operations

Darlington Refurbishment Capital Expenditures 706 1,231 1,095 1,121 979 858 1,195

Darlington Refurbishment In-Service Additions 147 350 374 9 - 4,809 -

Capital Expenditures excluding Darlington Refurbishment 670

In-Service Additions excluding Darlington Refurbishment

Nuclear Waste and Provision Expenditures

Projection

*** Calculated as: Net Income Attributable to Shareholder + Income Taxes + Gross Revenue Charge + Property Tax PILs

Business Plan

* Calculated using the methodology per OPG's external financial filings

** Total Generating Cost (TGC) is calculated as: (OM&A expenses from ongoing operations + fuel and Gross Revenue Charge expenses for

OPG-operated stations + sustaining capital expenditures)/OPG generation adjusted for surplus baseload generation losses. Nuclear TGC/MWh

adjusted for lower production due to the Darlington refurbishment outages is: $63.3/MWh in 2017, $61.8/MWh in 2018, $64.9/MWh in 2019,

$63.2/MWh in 2020 and $57.3/MWh in 2021. Hydroelectric TGC /MWh for 2015 is as estimated.

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Attachment 1

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24

Operating Statement - Years Ended December 31 Actual

(in millions of dollars) 2015* 2016 2017 2018

Electricity Generation Revenues 5,063

Fuel and Gross Revenue Charge 687

Generation Sales Gross Margin 4,376

Net Trading Margin

Non-Electricity Generation Gross Margin

Total Gross Margin

OM&A Expenses 2,753

Accretion on Nuclear Waste and Other Liabilities 895

Earnings on Nuclear Funds (703)

Depreciation and Amortization 1,100

Property Taxes 45

Restructuring 6

Total Expenses 4,096

Income before Interest and Other Income 665

Net Interest Expense 180

Other (Income)/Expense** (25)

Income before Tax 509

Income Tax 92

Net Income 417

Net Income Attributable to the Shareholder 402

Net Income Attributable to Non-Controlling Interests 15

Business Plan

* Presentation of 2015 information may differ from OPG’s externally published financial reports for consistency with planning period information

** Includes representing OPG's share of equity income from its ownership interests in In 2016, also includes an asset of OPG's unregulated business.

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25

Actual

(in millions of dollars) 2015* 2016 2017 2018

Assets

Current assets

Cash and cash equivalents 464

Short-term investments 110

Accounts receivable 641

Prepaid expenses 92

Fuel inventory 344

Materials and supplies 96

1,747

Property, plant and equipment and intangible assets

Fixed and intangible assets (net) 20,693

Other assets

Nuclear fixed asset removal and nuclear waste management funds 15,136

Long-term materials and supplies 337

Regulatory assets (net) 5,808

Investments subject to significant influence 336

146

21,764

Total Assets 44,203

Liabilities

Current liabilities

Short-term notes payable 225

Accounts payable and accrued charges 1,199

Deferred revenue due within one year 12

Current income taxes payable 66

Long-term debt due within one year 273

1,775

Long-term debt 5,199

Other liabilities

Fixed asset removal and nuclear waste management liabilities 20,169

Pension liabilities (non-current) 2,597

Other post-employment benefit liabilities (non-current) 3,085

Long-term accounts payable and accrued charges 207

Deferred revenue 246

Deferred income taxes 880

27,184

Equity

Common shares 5,126

Retained earnings 5,098

Accumulated other comprehensive loss (319)

Equity attributable to non-controlling interests 140

10,045

Total Liabilities and Equity 44,203

Other long-term assets

Balance Sheet - As at December 31 Business Plan

* Presentation of 2015 information may differ from OPG’s externally published financial reports for consistency with planning period information

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26

OM&A Expenses by Business Unit Actual

(in millions of dollars) 2015 2016 2017 2018 2019 2020 2021

Nuclear Operations* 1,450 1,495 1,535 1,564 1,612 1,596 1,518

Nuclear Projects* 138 127 184 164 152 164 153

Hydro Thermal Operations

Commercial Operations & Environment 37 44 43 41 42 41 45

Total Operations

Business and Administrative Services

(Chief Information Officer, Real Estate, Supply Chain) 293 298 296 287 290 290 293

Finance (excl. Insurance) 51 57 58 56 56 55 56

Insurance 30 43 45 48 53 54 54

Assurance (incl. Nuclear Oversight) 10 11 12 11 12 12 12

People & Culture (incl. Centralized Training) 116 111 115 114 116 117 119

Corporate Office 38 42 39 38 38 39 39

Corporate Business Development 14 15 15 16 16 16 16

Total Support Services 552 577 579 571 581 584 590

Total Business Unit Expenditures

Centrally Held Pension and OPEB 433 268 132 81 53 32 21

Other (incl. Cost of Goods Sold) 66 87 66 90 79 83 78

Total Ongoing Operations

OEB Variance and Deferral Account Offsets (273) (144) (151) (79) (54) (60) (43)

Darlington Refurbishment Project 2 1 42 14 4 48 20

Nuclear New Build 1 1 1 1 1 1 1

Total OM&A Expenses

ProjectionBusiness Plan

* Total Pickering extended operations enabling costs included in Nuclear Operations and Nuclear Projects are: $15M in 2016, $26M in 2017, $55M in 2018,

$107M in 2019 and $104M in 2020. Nuclear Projects line represents the total Nuclear OM&A project portfolio, including Pickering extension enabling costs,

as w ell as base and outage costs of the Nuclear Projects organization.

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Attachment 1

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27

Regular Headcount by Business Unit* Actual Actual Actual

2013 2014 2015 2016 2017 2018 2019 2020 2021

Nuclear Operations 5,668 5,491 5,297 5,400 5,448 5,432 5,367 5,267 5,202

Nuclear Projects 302 274 253 284 277 277 267 257 257

Hydro Thermal Operations

Commercial Operations & Environment 169 180 165 180 175 174 166 165 165

Total Operations 7,984 7,501 7,171

Business and Administrative Services

(Chief Information Officer, Real Estate, Supply Chain) 1,010 947 870 892 869 859 852 839 839

Finance 307 273 266 278 268 261 255 249 249

Assurance (incl. Nuclear Oversight) 58 57 53 57 57 57 57 57 56

People & Culture (incl. Centralized Training) 580 576 531 557 563 556 561 557 551

Corporate Office 91 86 77 84 83 83 82 81 81

Corporate Business Development 55 49 42 48 48 48 48 48 48

Total Support Services 2,101 1,988 1,839 1,916 1,888 1,864 1,855 1,831 1,824

Total Ongoing Operations 10,085 9,489 9,010

Darlington Refurbishment Project 181 189 237 501 512 520 545 524 519

Total Regular Headcount 10,266 9,678 9,247

ProjectionBusiness Plan

* As reported/projected at each year-end; not restated for subsequent budget transfers between organizations

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28

Actual

2015 2016 2017 2018 2019 2020 2021

Sustaining

Nuclear 315 353 279 258 282 278 199

Regulated Hydroelectric

Sir Adam Beck 1 Canal Liner Rehabilitation - - 1 1 1 62 62

Sir Adam Beck Pump GS Reservoir

Rehabilitation 1 39 6 - - - -

Other Projects 83 127 139 110 121 122 106

Total Regulated Hydroelectric 84 166 146 111 122 184 168

Contracted Generation Portfolio

Other Projects

Total Contracted Generation Portfolio

Support Services 46 39 24 30 27 27 27

Total Sustaining Capital 471

Generation Development Projects*

Hydroelectric Development

Sir Adam Beck Units 1 & 2 Conversion - 0 2 17 43 27 -

Ranney Falls GS Expansion 1 4 34 19 8 - -

Coniston GS Redevelopment - 0 2 7 19 17 -

Calabogie GS Redevelopment - 1 3 8 19 26 -

Other

Total Hydroelectric Development

Darlington Refurbishment Project*** 706 1,231 1,095 1,121 979 858 1,195

Solar Developments

905

Total Capital Expenditures 1,376

Projection

(in millions of dollars)

* Projects in definition phase are budgeted by Corporate Business Development and projects in execution phase are budgeted by Hydro Thermal Operations

Business PlanCapital Expenditures

Total Generation Development Capital

*** Includes expenditures budgeted by the Nuclear organization and Support Services

Actual

(in millions of dollars) 2015 2016 2017 2018 2019 2020 2021

Nuclear Operations 158 209 249 266 324 380 379

Nuclear Projects* 45 94 71 82 70 73 66

Support Services 9 19 18 16 14 14 15

Total Nuclear Provision Expenditures 212 322 338 364 409 468 460

Total Provision Expenditures

* Includes expenditures for the Darlingtion Refurbishment Project nuclear waste containers

ProjectionBusiness PlanProvision Expenditures

Nuclear Decommissioning and Nuclear Waste

Management Expenditures

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29

Actual

(in millions of dollars) 2015* 2016 2017 2018 2019 2020 2021

Opening Cash Balance 610 464 283 247 281 244 234

Net Operating Cash Inflows before the following: 2,356

Interest Paid (269)

Nuclear Funds Contribution (143)

Pension Fund Contribution (362)

OPEB Payments (118)

Net Cash from Operations 1,465

Investing Activities

Sustaining Capital Expenditures (471)

Darlington Refurbishment (706) (1,231) (1,095) (1,121) (979) (858) (1,195)

Other Generation Development

Cash Outflow for Capital Investments (1,376)

Pre-tax Proceeds from Assumed Sale of OPG Head Office -

Investment in Hydro One Shares

Other 3 - - - - - -

Net Cash Outflow for Investing Activities (1,553)

Financing Activities

General Corporate - Debt Issuance/Refinancing - 400 1,500 850 600 550 100

(OEFC)- Debt Retirement (500) (270) (900) (395) (365) (660) (185)

Project Financing - Debt Issuance/Refinancing 245

(Private Placement)- Debt Retirement (3)

Short-Term Notes (LME) - Net Issuance (Repayment) 225

Dividends Paid -

Distribution Paid to Non-Controlling Interests (16)

Other

Net Cash from Financing Activities (58)

Net Cash (Outflow) Inflow for Period (146)

Ending Cash Balance 464

Total Debt at Year-End 5,697

* Presentation of 2015 information may differ from OPG's externally published financial reports for consistency with planning period information.

ProjectionFinancing and Liquidity Outlook - Years Ended Dec 31 Business Plan

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Exhibit A2-2-1

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30

APPENDIX 5: Nuclear Financial Plan, Operational Targets, and Initiatives Financial Plan

Actual

(in millions of dollars) 2015 2016 2017 2018 2019 2020 2021

OM&A

Base 1,157 1,180 1,192 1,210 1,232 1,247 1,259

Outage Incremental 316 332 390 372 343 327 326

Project Portfolio 115 94 111 91 82 82 87

Pickering Continued Operations Enabling Costs - 15 26 55 107 104 -

Darlington Refurbishment Project 2 1 42 14 4 48 20

Nuclear New Build 1 1 1 1 1 1 1

Total Nuclear OM&A 1,591 1,624 1,762 1,744 1,769 1,809 1,693

Capital

Project Portfolio (including Spares and Minor Fixed Assets)* 315 353 279 258 282 278 199

Darlington Refurbishment Project (excluding Support Services) 681 1,189 1,063 1,094 951 833 1,170

Total Nuclear Capital 996 1,542 1,342 1,352 1,234 1,111 1,369

Provision Expenditures

ONFA Funded 61 104 140 150 206 260 256

Internally Funded - Base 96 104 109 116 118 120 123

Internally Funded - Projects 40 39 39 40 40 40 40

Internally Funded - Darlington Refurbishment Waste Containers 6 56 32 43 30 33 26

Total Nuclear Provision Expenditures 203 303 320 348 394 453 445

Fuel Expense (Pickering and Darlington) 244 261 220 222 233 228 213

*In 2019, includes $15M related to the load of new fuel bundles into the refurbished Darlington Unit 2

Business Plan Projection

Operational Targets The key 2016-2018 targets for the Nuclear business unit are set out below. These targets are informed by the latest industry benchmarks and are designed to drive continuous performance improvement.

Metric

NPI

Max

Industry

Best

Quartile

2015

Actual

2016

Annual

Target

2017

Annual

Target

2018

Annual

Target

2015

Actual

20161

Annual

Target

20171

Annual

Target

20181

Annual

Target

All Injury Rate (#/200k hrs worked) N/A 0.66 0.44 0.24 0.24 0.24 0.22 0.24 0.24 0.24

Collective Radiation Exposure

(person-rem/unit)80.00 42.25 100.90 111.50 126.90 137.30 73.72 65.00 87.80 72.10

Unit Capability Factor (%) 92.0 89.4 79.4 77.6 71.5 72.0 76.9 91.1 85.1 86.0

Forced Loss Rate (%) 1.00 1.03 2.89 5.00 5.00 5.00 4.86 1.00 1.00 1.00

On-line Corrective Maintenance

Backlog (work orders/unit)N/A 11 125 55 28 28 24 20 15 10

WANO NPI (Index) N/A 92.9 68.5 72.3 71.1 71.1 83.7 87.3 84.3 93.0

Human Performance Error Rate N/A 0.0020 0.0055 0.0030 0.0030 0.0030 0.0031 0.0030 0.0020 0.0020

Total Generating Cost per MWh2 N/A $38.71 $64.00 $71.09 $76.48 $75.32 $52.40 $47.35 $47.85 $48.68

Pickering Darlington

1 Darlington targets reflect the impact of the Unit 2 Refurbishment starting in October of 2016, where applicable.

2 Metrics exclude centrally-held Pension and OPEB costs and asset service fees. Targets may change subject to allocations and assumptions being

finalized. Darlington metrics have been normalized after 2016 for generation forgone during the Unit 2 refurbishment. The non-normalized

Darlington target for 2017 is $63.76/MWh and 2018 is $63.50/MWh.

Green = Max NPI Points Achieved (if applicable) or Best Quartile Performance

White = 2nd Quartile Performance

Yellow = 3rd Quartile Performance

Red = 4th Quartile Performance

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Darlington Refurbishment Project Targets

Milestone Target Completion Date

Unit 2 Execution Estimate Complete August 15, 2016

Unit 2 Refurbishment Start (Breaker Open) October 15, 2016

Unit 2 Reactor Defueling Complete February 2017

Heavy Water Storage & Drum Handling Facility In-Service May 2017

Unit 2 Reactor Component Removals Complete April 2018

Unit 2 Calandria Tube Installation Complete September 2018

At least 284 Unit 2 Fuel Channels Installed December 31, 2018

Initiatives The following initiatives are aimed at closing performance gaps in order to achieve targeted results for the Nuclear business unit:

Workforce Planning & Resourcing Initiative: This initiative focuses on developing and implementing

the resourcing strategy to support the safe operation of the plants and successful completion of the

Darlington refurbishment, while minimizing disruption and costs associated with the Pickering end of

commercial operations. A dedicated team will optimize workforce planning strategies across the Nuclear

business and provide oversight on the resourcing approval process.

Outage Performance: This initiative focuses on delivering predictable outage performance through

improved planning and execution of outage work to meet planned outage day targets. Areas for

improvement include: model work order development and utilization; outage schedule and resource

planning quality; implementation of a long-term purchased services agreement to optimize contracted

work and improve quality of supplemental staff execution; inspection and maintenance execution

improvements; Life Cycle Management Plan development improvements; and completing a feasibility

study for placing the Pickering station on a 30-month outage cycle.

Equipment Reliability: This initiative aims to improve equipment reliability, improve effectiveness of the

maintenance program and reduce equipment failures to meet forced loss rate targets.

Human Performance: This initiative focuses on: 1) Behaviours associated with procedural use and

adherence; 2) Leadership accountability whereby leaders understand and model the behaviours

expected from all staff; and 3) Supervisor effectiveness whereby supervisors set and communicate clear

expectations to positively influence behaviours.

Parts Improvement Project: This initiative focuses on obtaining the right parts on time, reducing churn

in the work management system, and ultimately improving equipment reliability through the completion

of 19 cross-functional sub-initiatives across the Engineering, Supply Chain, Fleet Operations &

Maintenance, and Work Management functions.

Inventory Reduction Initiative: This initiative is to develop a strategy to optimize inventory levels and

reduce costs by targeting half the historical growth rate for 2016. The 2016 growth rate would be lower

than benchmark.

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Exhibit A2-2-1

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APPENDIX 6: Nuclear Strategic Framework

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Exhibit A2-2-1

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APPENDIX 7: Hydro-Thermal Financial Plan, Operational Targets, and Initiatives Financial Plan

Actual

(in millions of dollars) 2015 2016 2017 2018 2019 2020 2021

OM&A

Regulated Hydroelectric 199 190 194 191 195 201 205

Contracted Generation Portfolio

Other*

Total Base OM&A

Regulated Hydroelectric 53 51 79 88 99 100 92

Contracted Generation Portfolio

Total Project OM&A

Regulated Hydroelectric 252 241 273 278 294 300 297

Contracted Generation Portfolio

Other*

Total HTO OM&A

Capital

Sustaining

Regulated Hydroelectric

Sir Adam Beck Unit 1 Canal Liner Rehabilitation - - 1 1 1 62 62

Sir Adam Beck Pump GS Reservoir Rehabilitation 1 39 6 - - - -

Other Sustaining Projects 83 127 139 110 121 122 106

Total Regulated Hydroelectric 84 166 146 111 122 184 168

Contracted Generation Portfolio

Other Sustaining Projects

Total Contracted Generation Portfolio

Total Sustaining Capital

Hydroelectric Development

Sir Adam Beck Units 1 & 2 Conversion - - 2 17 43 27 -

Other

Total Hydroelectric Development Capital

Thermal Decommissioning Provision Expenditures

364

Regulated Hydroelectric (net of SBG losses)** 319 340 340 349 333 338 337

Contracted Generation Portfolio 43

Other 2

2019-20212016-2018

Hydroelectric Gross Revenue Charge and Thermal Fuel

Expense

* Includes $5M to $6M per year for work in support of the Nuclear Organization

** Regulated hydroelectric gross revenue charge expenses assuming no SBG losses are: $363M in 2016, $348M in 2017, and $354M in 2018, $337M in 2019, $340M in 2020, and $338M in 2021.

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34

Operational Targets The key 2016-2018 targets for Hydro Thermal Operations designed to drive continuous performance are set out below.

2015

Actual 2016 2017 2018

All Injury Rate (#/200k hrs worked) 1.14 1.32 1.32 1.32

Environment

Signif icant Environmental Events (incl. Category A and B Spills) 0 0 0 0

Category C Spills 10 9 9 9

Environmental Infractions 6 9 9 9

Capacity (MW) 9,902 9,915 9,954 9,973

Regulated Hydroelectric 6,430

Contracted Generation Portfolio (Thermal and Hydro) 3,469

Wind (No Contract) 2 2 2 2

Hydroelectric Availability (%) 91.1 87.6 90.0 91.6

Regulated Hydroelectric 91.2 87.9 89.7 91.3

Contracted Generation Portfolio Hydroelectric

Hydroelectric Equivalent Forced Outage Rate (%) 2.0 1.8 1.6 1.6

Regulated Hydroelectric 1.8 1.6 1.6 1.6

Contracted Generation Portfolio Hydroelectric

Thermal Equivalent Forced Outage Rate (Operating) (%)

Total Hydroelectric Generating Cost per MWh* ($/MWh)

* Calculated assuming no production is foregone due to SBG losses; 2015 value as estimated

Business Plan

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35

Initiatives The Hydro-Thermal business unit continues to strive for performance excellence, through the following strategic initiatives and execution of key business plan deliverables:

Safety: This initiative focuses on the Prepare 4 Safety campaign and continued focus on improving

work protection performance.

Workforce Planning and Resourcing Efficiency: This initiative focuses on the continued review of

positions as they become vacant and challenge whether positions are required to be filled. Gaps in the

engineering area are being addressed through the re-introduction of the graduate engineer training

program and the hiring of senior engineers.

Environment: This initiative aims to continue good environmental performance through programs such

as Oil Containment Integrity Testing and Drainage Survey and support of the corporate environmental

management system.

Project Excellence: This initiative focuses on the successful execution of the

the Sir Adam Beck 1 Unit 1 and 2 conversions to 60 Hz, which will increase OPG’s asset base.

The rehabilitation of the Sir Adam Beck Pump GS reservoir

will ensure continued safe operations

Operational Excellence: This initiative focuses on sustaining hydroelectric availability and the thermal

Equivalent Forced Outage Rate (operating) across the business plan period, as per targets and

contractual limits, to ensure unit availability during the Darlington refurbishment.

Building Leadership Capability: This initiative focuses on continuous improvement in succession

planning, engagement in the company-wide leadership development program, mentoring of high

potential individuals, and continuing to strengthen and develop partnerships with host communities and

First Nations.

Productivity Improvements: This initiative focuses on continued review of opportunities for efficiency

gains from strategic initiatives, optimizing the productivity of maintenance staff, and focusing on the

Attendance Support Program.

Regionalization: This initiative will continue to explore further efficiencies through regionalization.

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APPENDIX 8: Business & Administrative Services Financial Plan, Operational Targets, and Initiatives Financial Plan

Actual

(in millions of dollars) 2015 2016 2017 2018 2019 2020 2021

OM&A

Chief Information Officer 121 118 118 115 114 112 111

Real Estate 103 104 106 106 108 109 112

Supply Chain 49 54 54 53 54 56 57

SVP Office 0 1 1 1 1 1 1

Base OM&A 272 277 280 275 277 278 280

Project OM&A - Chief Information Officer 21 21 16 13 13 13 13

Total BAS OM&A 293 298 296 287 290 290 293

Capital

Chief Information Officer 37 26 16 22 18 18 18

Real Estate 7 12 8 8 8 8 8

Darlington Refurbishment Project 19 32 21 18 18 17 17

Total BAS Capital 62 70 45 48 44 43 43

Nuclear Provision Expenditures 2 3 3 3 3 3 3

ProjectionBusiness Plan

Operational Targets Business and Administrative Services comprises the Company’s centralized supply chain, information technology management, and real estate services functions. The key 2016-2018 targets for Business and Administrative Services include the following:

2015

Actual 2016 2017 2018

Employee Safety

All Injury Rate (#/200k hrs worked) 0.13 0.32 0.32 0.32

Lost Time Injuries 0 0 0 0

Environment

Category C Spills 0 1 1 1

Environmental Infractions 0 3 3 2

Waste Diversion Target (%) N/A 80 85 90

Supply Chain

Unplanned Nuclear Generation Loss Due to Vendor Quality (days) 11 15 12 10

Stock-out Nuclear Materials (Critical 1 & 2 Parts) (%) * 1.8 1.0 TBD TBD

Strategic Sourcing ($m)

Supply Chain Achievement of Nuclear, HTO, and Refurbishment Project

Milestones (%) 100 100 100 100

Information Technology

Critical IT System Availability (%) 99.99 99.98 99.98 99.98

IT Projects Benefits Realization (%) 98 98 98 98

IT Execution Phase Project Adherence (Portfolio) (%) 97 95 95 95

* This target is assessed annually

Business Plan

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Initiatives Key initiatives of Business and Administrative Services focus on delivering cost effective, value added services in support of generation business unit operations and projects while continuing to improve efficiency. The initiatives include:

Strategic Sourcing: Supply Chain (SC) will maximize OPG spend leverage through a re-compete

sourcing strategy and enhanced spend category management to achieve a targeted value

improvement on an addressable spend of

Nuclear Parts Improvement Initiative: SC is leading 5 of 19 initiatives, as well as supporting 7

additional initiatives, that comprise this comprehensive cross-functional nuclear fleet initiative to improve

parts availability. SC will execute these modules in close collaboration with the Nuclear Engineering,

Work Management, Maintenance and Nuclear Operations functions.

Nuclear Inventory Management: SC is partnering with Nuclear Operations, Nuclear Waste, Finance

and Pickering End of Commercial Operations teams to develop a cross-functional understanding of

inventory drivers, identify opportunities for improvement and develop an executable plan to reduce

inventory levels and eliminate growth. SC will also implement a new process to reduce the requirements

for staging parts prior to work execution by reducing the volume of staged material.

Centralized Nuclear Warehouse Operations: SC will streamline nuclear warehouse operations by

completing the consolidation of 12 warehouses down to 5, supplying a modern facility for maintaining

inventory integrity.

Supplier Quality and Counterfeit, Fraudulent and Sub-Standard Parts: While SC has established

effective programs for managing these risks, continuous improvement opportunities will continue to be

identified through self-evaluation, benchmarking and third party review. A specific focus will be on

ensuring EPC contractors implement similar programs for their suppliers and sub-suppliers.

Cyber Security: Chief Information Office will continue to implement the 8-point cyber security program

to better ensure OPG remains vigilant, secure and resilient against growing and emerging threats. This

is in direct support of the new OPG Board Policy on Cyber Security.

Facility Services Optimization: Real Estate & Services (RES) will implement the Facilities Services

Delivery Model in Nuclear, streamlining business processes to improve efficiency and reduce resource

demands (e.g., custodial, grounds maintenance, transport & work equipment and building maintenance).

Nuclear Infrastructure & Facilities Projects: RES will execute infrastructure projects to address

bridge and roads improvements and the demolition of life expired facilities in support of the Darlington

refurbishment.

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2016-2018 Business Planning

Instructions

Issued by: Finance – Business Planning and Reporting May 29, 2015

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Table of Contents

1.0 Business Planning Context and Assumptions .......................................................................................2

1.1 Business Planning Context ...................................................................................................................2 1.1.1 Key Strategic Goals and Imperatives .............................................................................................2 1.1.2 Strategic and Select Business Unit Level Key Performance Indicators .........................................3

1.2 Business Planning Process Improvements ...........................................................................................3 1.3 Regulated Revenue Assumptions .........................................................................................................4 1.4 Collective Agreement Assumptions.......................................................................................................4 1.5 Operating and Other Planning Assumptions .........................................................................................5 1.6 Pickering End of Commercial Operations .............................................................................................7 1.7 Darlington Refurbishment Budget and Schedule ..................................................................................7

2.0 Resource Targets ..................................................................................................................................8

2.1 Capital, Project OM&A, and Non-ONFA Provision-Funded Project Targets...................................... 10 2.2 Targets for Nuclear Waste Management and Decommissioning Expenditures ................................ 12 2.3 Workforce Resourcing Plan Initiative ................................................................................................. 12

3.0 Key Process Changes ........................................................................................................................ 13

3.1 Streamlining Use of Responsibility Centres and Locals ..................................................................... 13 3.2 Planning versus Budgeting ................................................................................................................. 14 3.3 Other Changes ................................................................................................................................... 14

4.0 Schedule ............................................................................................................................................. 15

5.0 Business Planning and Budgeting Instructions .................................................................................. 16

5.1 Business Unit Information Submissions ............................................................................................. 16 5.1.1 Specific Information Requirements ................................................................................................... 17 5.1.2 Payroll Burden .................................................................................................................................. 18 5.1.3 Business Plan Presentations ............................................................................................................ 19 5.1.4 Cost Allocations for Support Services, CO&E and HTO .................................................................. 19 5.1.5 Nuclear Provision Expenditures ........................................................................................................ 20

5.2 Revenue and Gross Margin Submissions .......................................................................................... 20 5.3 Information Requirements for HTO Facilities ..................................................................................... 21 5.4 Non-Controlling Interest and Investments Subject to Significant Influence ....................................... 22 5.5 Other Information Submissions .......................................................................................................... 22 5.6 Finance Review and Sign-off ............................................................................................................. 23 5.7 Instructions for Use of the BPC Business Planning System .............................................................. 24 5.8 Budgeting for Service Providers ......................................................................................................... 25

5.8.1 Information Technology (IT) Requirements ...................................................................................... 25 5.8.2 Supply Chain Requirements ............................................................................................................. 26 5.8.3 Real Estate & Services Requirements ............................................................................................. 26 5.8.4 Other Support Services .................................................................................................................... 27

5.9 Capital, OM&A and Provision-Funded Projects ................................................................................. 27 5.9.1 Prioritized Project Lists ................................................................................................................ 28 5.9.2 Planning Business Cases ............................................................................................................ 28 5.9.3 BCS Preparation Assistance ....................................................................................................... 28

6.0 Other Planning Requirements ............................................................................................................ 28

6.1 Business Unit Risk Self-Assessment (BURSA) ................................................................................. 28 6.2 Corporate Safety ................................................................................................................................ 30 6.3 First Nations Initiatives ....................................................................................................................... 30 6.4 Environmental Planning Requirements .............................................................................................. 30

CONTACT INFORMATION

If you require further information on business planning assumptions, schedules, or requirements, please contact:

Alex Kogan – Vice-President, Business Planning & Reporting 400-3103

Vassa Chase – Director, Business Planning & Regulatory Finance 400-3272

Anthony Melaragno – Senior Manager, Financial Forecasts 400-4646

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1.0 BUSINESS PLANNING CONTEXT AND ASSUMPTIONS

1.1 BUSINESS PLANNING CONTEXT CONTACTS: ANDY TEICHMAN/ALEX KOGAN OPG’s 2016-2018 business planning cycle takes place against a backdrop of a range of external developments and drivers, including:

Continuing low electricity demand growth, with surplus power conditions expected to continue during the remainder of the decade

Heightened competition for a shrinking pool of new generation development opportunities

Ongoing pressures to contain electricity cost increases through operating efficiencies, including those in response to public sector compensation and pension/benefit restraint expectations

Continuing electricity sector scrutiny by the Shareholder, stakeholders and the public regarding cost transparency, efficiency and performance

Approaching planned refurbishments of Ontario’s nuclear fleet

Government’s focus on deficit elimination, which underscores the importance of OPG meeting its fiscal commitments by earning an appropriate return on its regulated and unregulated assets

Government efforts aimed at exploring and unlocking the value of public assets.

In this dynamic planning environment, OPG must maintain sufficient planning flexibility as it embarks on the 2016-2018 business planning cycle.

1.1.1 Key Strategic Goals and Imperatives

A key strategic goal for OPG is to improve its financial performance, and specifically its net income and return on equity. This goal continues to be supported by the following key strategic imperatives: 1) operational excellence; 2) project excellence; and 3) financial sustainability.

Operational Excellence – Focus on continued safe, efficient, environmentally responsible and reliable operating performance of OPG’s generating fleet, including delivering on the following supporting initiatives:

Focusing on continuous quality improvement, including benchmarking

Developing a strategy for the end of commercial operations at Pickering, including planning for the significant staff impacts that would result

Undertaking long-term life cycle asset planning and sustaining investment

Undertaking nuclear asset life optimization, including operation of Pickering to the end of 2020 while exploring the option of further life extension

Preparing Canadian Nuclear Safety Commission submissions in support of the Darlington license renewal and the final shutdown schedule/plan for Pickering

Developing a talent management and resourcing strategy to meet changing needs

Continuing to foster a corporate culture that reflects OPG’s corporate values and behaviours. Project Excellence – Deliver on OPG’s generation portfolio renewal/growth program that includes:

Developing the final budget and schedule for the four-unit Darlington refurbishment, mobilizing required infrastructure and resources, and executing the refurbishment program on time and budget

As per Ontario’s 2013 Long-Term Energy Plan (LTEP), maintaining the site preparation licence for the new nuclear build option, with potential for reassessment in future LTEP updates

Obtaining a construction licence for the planned low and intermediate level waste (L&ILW) Deep Geologic Repository (DGR) and proceeding with detailed project definition.

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Financial Sustainability – Drive towards improved financial sustainability, as supported by the following initiatives:

Developing and executing rate applications to the Ontario Energy Board (OEB)

Embedding achieved cost reductions and efficiencies for the longer term while identifying and implementing initiatives to further improve OPG’s cost structure

Continuing to pursue labour contract negotiations with the objective of facilitating further efficiencies and cost improvements, and supporting the strategy for the end of Pickering commercial operations

Continuing to advance pension and benefits reforms

Positioning OPG’s unregulated external services business for future growth

Pursuing other initiatives that improve financial performance, increase operating flexibility, and/or reduce costs without compromising safe and reliable operations.

1.1.2 Strategic and Select Business Unit Level Key Performance Indicators During 2014, a set of strategic Key Performance Indicators (KPIs) and select related Tier 2 (i.e. Business Unit level) KPIs, associated with OPG’s key strategic imperatives, were identified. During 2015 and 2016, efforts will be directed to further integrate these KPIs with existing planning and reporting processes.

Strategic KPIs associated with Operational Excellence focus on safety, production, environmental impact, and cost effectiveness. Those associated with Project Excellence focus on driving completion of major projects within approved project milestones and budgets. Financial Sustainability is assessed in relation to KPIs that include earnings, return on equity, average price for OPG’s generation, credit metrics, and operating, maintenance and administration expenses (OM&A).

1.2 BUSINESS PLANNING PROCESS IMPROVEMENTS CONTACT: VASSA CHASE Finance’s review of the business planning process resulted in a number of recommendations that are being phased in over 2014 and 2015, including:

Greater integration with OPG’s strategic planning

Enhanced integration and communication across operating Business Units and Support Services (collectively, BUs)

A reduction in the level of detail used for business planning and budgeting.

Significant steps were taken as part of the 2015-2017 business planning process to achieve greater integration with strategic planning and to facilitate enhanced cross-BU communication, including:

Leveraging an integrated enterprise planning approach, led by Corporate Strategy and Planning, in developing planning assumptions and guidelines

The advancement of the long-term financial outlook update process to earlier in the year

The replacement of individual CEO/CFO business plan review meetings with joint CEO/Enterprise Leadership Team (ELT) review sessions

Requirements to identify and confirm planned intracompany work for others under a common cost model (as summarized in section 5.8).

Last year’s business planning process also saw the implementation of the new business planning system, BPC. BPC delivers a more state-of-the-art technology to meet planning needs across the company, and supports OPG’s Financial Reporting System (FRS) and cost model. As part of the Enterprise Systems Consolidation Project, the optimization of FRS and the conversion of the previous planning system to BPC have resulted in significant reductions in the level of detail for business planning and budgeting. During the 2015-2017 business planning process, planning and budgeting occurred at a higher organizational level resulting in a reduction in the number of budget holders across the company. Overall, the 2015-2017 Business Plan (BP) saw a reduction of approximately 30% in the number of individual records in the planning system.

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The 2016-2018 business planning process will continue to leverage the planning process improvements and system enhancements implemented to-date, by focusing on further initiatives that reduce the planning and budgeting level of detail. As discussed in section 3.1, two such initiatives include:

Applying minimum requirements of at least 20 regular employees and $5M in financial activity for setting up and maintaining separate Responsibility Centres (RCs)

Streamlining the use of “Local” identifiers within each BU

In addition, this year’s planning process introduces the opportunity for BUs to separate certain planning and budgeting activity for non-labour costs by making the initial planning submissions at more summarized resource type (RT) and RC levels. Section 3.2 provides specific steps for the implementation of this option. As part of future business planning cycles, Finance will continue to evaluate opportunities for additional streamlining of the planning process, including further reducing the level of planning and/or budgeting detail. 1.3 REGULATED REVENUE ASSUMPTIONS CONTACT: COLIN ANDERSON In December 2014, OPG filed an application with the OEB requesting disposition of the balances in most of its deferral and variance accounts through nuclear and hydroelectric rate riders effective July 1, 2015. The 2016-2018 BP will reflect the outcome of this application, which is expected to be known prior to the finalization of the plan. For the hydroelectric assets, OPG plans to move to an incentive rate-setting mechanism in its next rate application, expected to be filed later in 2015. For the nuclear assets, OPG expects to develop a multi-year cost of service application with custom incentive regulation features. OPG is in the process of preparing the hydroelectric rate application for the period to 2020 and is evaluating its plans for the nuclear rate application. The information from the approved 2016-2018 BP may be used in setting post-2015 regulated rates for OPG’s regulated facilities. As in past business plans, Business Planning & Performance Reporting (BP&PR) will apply regulated rate revenue assumptions to the 2016-2018 BP, as determined in consultation with CO&E –Regulatory Affairs. Until new rates are made effective by the OEB, the existing cost-of-service rates established by the OEB’s November 2014 decision and December 2014 order will be assumed to continue. 1.4 COLLECTIVE AGREEMENT ASSUMPTIONS CONTACTS: MATT DOWDLE/TERRY FITZPATRICK The previous agreement with the Power Workers’ Union (PWU) expired on March 31, 2015. A new agreement was reached with the PWU in April 2015 and was ratified in May 2015. The 2016-2018 BP will reflect all applicable provisions of the new PWU agreement, and the OM&A targets provided in section 2.0 have been set on that basis. For further information on the new agreement, please contact Matt Dowdle in People and Culture (P&C) – Labour Relations at 400-6012. The current agreement with the Society of Energy Professionals (Society) expires on December 31, 2015.

Please contact Terry Fitzpatrick in P&C – Labour Relations at 400-3987 for further information regarding the current agreement.

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1.5 OPERATING AND OTHER PLANNING ASSUMPTIONS CONTACT: VASSA CHASE The following assumptions form the planning basis for the 2016-2018 BP:

2016-2018 Business Plan Assumptions

Pickering

End of life for all units is at the end of 2020 with no life management

Maintenance and operating activities support the safe and reliable operation of the units throughout the planning period

Preparation activities required to directly support the safe storage of the units will be funded from the Decommissioning Segregated Fund

Darlington

The Darlington outage plan is based on all units meeting the refurbishment schedule (i.e. no idle time)

The upcoming Darlington operating licence renewal is expected to span the planned refurbishment period

Plant investments will take into consideration current life cycle plans and are aligned with the refurbishment

Darlington Refurbishment

Pending the final refurbishment schedule, planning should proceed assuming the following 36-month refurbishment outages for each unit:

o Unit 2 – Mid October 2016 to Mid October 2019 o Unit 3 – Mid October 2019 to Mid October 2022 o Unit 1 – Mid March 2021 to Mid March 2024 o Unit 4 – Mid October 2022 to Mid October 2025

The final nuclear planning submission will reflect the final refurbishment budget and schedule for the four-unit refurbishment, with any necessary adjustments to non-nuclear submissions coordinated accordingly (see section 1.7)

Nuclear Waste Management

The construction license for the L&ILW DGR is obtained during the planning period, for targeted in-service at the end of 2025

A waste minimization and reduction program continues to be implemented, with a focus on the efficient management of nuclear waste material currently in storage and as generated at the sites

Loading of dry storage containers is maintained at the Darlington and Pickering Waste Management Facilities, and at a sustainable level for Bruce Power

Nuclear New Build Consistent with the 2013 LTEP, the site licence will be maintained for the

duration of the planning period

Bruce Power Pending further information regarding the refurbishment of the Bruce units

The generation plan will assume the following refurbishment schedule based on the 2013 LTEP with some adjustments:

o Bruce A Unit 4 – July 2018 to June 2022 o Bruce A Unit 3 – Jan 2021 to June 2024 o Bruce B Unit 5 – July 2022 to June 2025 o Bruce B Unit 6 – July 2024 to June 2027 o Bruce B Unit 7 – July 2026 to June 2029 o Bruce B Unit 8 – July 2028 to June 2031

Sufficient confidence to affect accounting changes (i.e., depreciation and asset retirement obligation) to the Bruce B station life on account of the refurbishment of the units is attained by the end of 2015

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2016-2018 Business Plan Assumptions (cont’d)

Hydroelectric

Ranney Falls expansion project execution starts in 2016, with the facility in service by mid 2019 as part of regulated assets

Sir Adam Beck Pump GS reservoir rehabilitation takes place during the station outage from April 1, 2016 to March 31, 2017, with the capital placed in service in 2017

Sir Adam Beck Units 1 and 2 are converted from 25 Hz to 60 Hz over the 2016-2018 period

The project execution of Coniston GS and Calabogie GS redevelopments begins in 2018, as part of regulated assets

System impactive hydroelectric unit refurbishment and outage programs are completed prior to the first Darlington refurbishment outage (e.g., Des Joachims Rehabilitation, Sir Adam Beck Unit 10)

Implementation of Provincial Dam Safety technical guidelines does not result in incremental expenditures

Thermal

Business and Administrative Services (BAS)

There are no significant real estate transactions during 2016-2018

A new IT contract is in place by January 2016

IT Cyber Security Program costs are included in the BAS business plan

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2016-2018 Business Plan Assumptions (cont’d)

Nuclear Funds and Nuclear Waste and Decommissioning Liabilities

Investments in the Nuclear Funds are assumed to earn 5.15% over the planning period

The plan will not reflect potential impacts on the Nuclear Funds and nuclear waste and decommissioning liabilities that may arise as a result of the 2017 ONFA Reference Plan update process, which is expected to conclude in 2016

Accounting Service Lives of OPG-Operated Nuclear Stations

Sufficient confidence to affect the following changes to the Pickering and Darlington estimated station service lives, for accounting purposes, is attained by the end of 2015:

o For Pickering, to reflect operation of all units to the end of 2020 o For Darlington, to reflect the final schedule for the four-unit

refurbishment and resulting post-refurbishment end-of-life dates

Interest Capitalization Rate

Non-project specific interest capitalization rate is 5.00%

Project specific interest capitalization rates are to be derived in consultation with Treasury

SAVH Rate for Projects

Planned capital expenditures, OM&A project expenditures, and provision project expenditures will reflect the common SAVH rate of 22% over the planning period

1.6 PICKERING END OF COMMERCIAL OPERATIONS CONTACTS: JOHN BLAZANIN/ALLAN WEBSTER

The 2016-2018 BP assumes that all Pickering units will operate until the end of 2020, followed by a period of preparation for safe storage. The planning submissions are expected to reflect work programs and resource levels necessary to support safe and reliable operations at Pickering until the end of 2020. OPG’s Pickering End of Commercial Operations (PECO) team is managing the overall planning and preparation activities in support of the end of Pickering commercial operations, including the safe storage project, station decommissioning, site repurposing, and company-wide resourcing implications. Prior to planning specific resources or activities in support of the end of Pickering commercial operations, BUs are to consult with the PECO team (John Blazanin at 905-421-9494 ext 3458 / Allan Webster at 905-421-9494 ext 3502). 1.6.1 Extended Pickering Operations Option Under the leadership of the PECO organization, OPG is assessing the feasibility of extending Pickering commercial operations beyond 2020 as a separate scenario. For the purposes of assessing this scenario, BUs are required to separately identify all material resources and generation impacts for extending the Pickering operations that would be incremental to the 2016-2018 planning submissions, including expenditures immediately required in 2016 to preserve the extension option. Further direction regarding this scenario, including details on information requirements and submission process, will be provided in a separate communication. 1.7 DARLINGTON REFURBISHMENT BUDGET AND SCHEDULE

CONTACTS: LEO SAAGI/STEVE WIACEK

The Darlington refurbishment costs and labour resource requirements for the initial July 27 business plan submission will reflect the information presented to the OPG Board of Directors in November 2014, adjusted for reclassifications to non-refurbishment project costs. This applies to the portion of refurbishment costs and labour resources that are budgeted by Support Services and CO&E.

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Planning information on the final budget and schedule for the four-unit refurbishment, including applicable supplementary data as outlined in section 5.1, is expected to be submitted on October 5 to BP&PR, Nuclear Finance – Business Planning & Benchmarking, and Support Services Controllership for incorporation into the consolidated OPG plan and the respective BU plans. This will include updated information on the refurbishment costs and labour resources that are budgeted by Support Services and CO&E. The updated BPC data load for 2016-2018 reflecting the final refurbishment budget and schedule must be completed by October 30, in conjunction with the finalization of the monthly trending. The BU business plan presentations for the CEO/ELT reviews, which will take place in mid to late-September, will not reflect the final refurbishment budget and schedule. The final refurbishment budget and schedule will be reflected in the BU business plan presentations to the OPG Board of Directors.

Resources in support of Darlington refurbishment being planned by Support Services and CO&E require approval by SVP, Nuclear Projects. As a general principle, only directly attributable support group costs that are related to construction or development activities of the refurbishment program may qualify as project capital costs.

2.0 RESOURCE TARGETS CONTACT: ANTHONY MELARAGNO This business plan will build on the significant attrition-based headcount reductions and efficiencies achieved over the last five years. By emphasizing continuous improvement, the plan will aim to ensure that the significant gains made to-date are sustained over the longer term, without compromising safe and reliable operations, and challenge the company to find further sustainable cost reductions and efficiency gains. To this end, the resource targets for the 2016-2018 BP substantially advance, by one year, headcount reduction commitments from the 2015-2017 BP and reflect projected labour resource needs identified through workforce planning processes. The resource targets also recognize that, due to high levels of attrition, additional temporary resources may be required to execute necessary work programs and maintain continued reliable performance of the assets. The targets for headcount and total OM&A from ongoing operations reflect updated assumptions for economic factors and include estimated impacts of the new PWU collective agreement. As in the prior year, targets for OM&A from ongoing operations reflect specific targets for project OM&A, discussed below. The resource targets assume a 2020 Pickering end of life and do not contemplate incremental resources that may be necessary to preserve the option of extending Pickering commercial operations beyond 2020. Refer to Section 1.6 for information requirements related to the end of Pickering commercial operations. The targets for the Darlington refurbishment organization are preliminary, as the final business plan will reflect the final budget and schedule for the four-unit refurbishment. Changes in assumptions regarding resource requirements for the refurbishment may also impact the non-refurbishment aspects of the Nuclear business plan (e.g., swing staff) and the business plans for Support Services and CO&E. Section 1.7 provides further details. The resource targets for the 2016-2018 BP, which were provided to BU planners in an advance communication on May 15, 2015, are outlined below.

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2016 2017 2018

Nuclear Operations & Projects (Excl. Darlington Refurbishment) 5,565 5,546 5,534

Hydro-Thermal Operations

Commercial Operations & Environment 171 166 166

Total Operations

Business and Administrative Services 870 850 802

Finance 255 250 241

Assurance 57 57 57

People & Culture 560 555 550

Law 22 22 22

Corporate Business Development & CRO 47 47 47

Corporate Office 61 60 60

Total Support Services 1,872 1,841 1,779

Total Ongoing Operations

Darlington Refurbishment 366 432 435

Total OPG

2016-2018 Regular Headcount Targets

Targets

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$ millions

2016 2017 2018

Nuclear 1,584 1,626 1,628

Nuclear Project Portfolio (Excl. Darlington Refurbishment) 95 110 95

Nuclear Operations - Base & Outage OM&A 1,489 1,516 1,533

Hydro-Thermal Operations

Hydro-Thermal Operations - Base OM&A

Hydro-Thermal Operations -

Hydro-Thermal Operations - Regulated Plants Project OM&A 60 90 70

Commercial Operations & Environment 40 41 40

Total Operations

Business and Administrative Services 294 284 277

Business and Administrative Services - Base OM&A 272 269 265

Business and Administrative Services - Project OM&A 22 15 12

Finance 51 51 50

Insurance 43 45 50

Assurance 11 12 11

People & Culture 112 112 115

People & Culture - Base OM&A 111 110 115

People & Culture - Project OM&A 1 2 -

Law 10 10 10

Corporate Business Development & CRO 15 15 16

Corporate Office 27 27 27

Total Support Services 564 555 555

Total Ongoing Operations

Darlington Refurbishment 13 69 38

Nuclear New Build 3 3 6

Total OPG*

Targets

2016-2018 Total OM&A Targets*

*Excluding centrally-held costs held at the corporate level, costs of goods sold, and the impact of regulatory deferral and

variance accounts.

2.1 CAPITAL, PROJECT OM&A, AND NON-ONFA PROVISION-FUNDED PROJECT TARGETS CONTACT: BOB GERRARD Resource targets for the 2016-2018 BP include capital and project OM&A targets for all applicable BUs. In addition, targets are provided for non-ONFA provision-funded projects. The 2016-2018 BP capital, project OM&A, and provision-funded project targets were developed by Corporate Strategy and Planning, in consultation with the BUs. These targets are based on the assumptions outlined in section 1.5. Material developments affecting those assumptions may necessitate revisions to the targets. Any such revisions will be undertaken in consultation with the BUs. The Darlington refurbishment targets are preliminary, as the final business plan will reflect the final budget and schedule for the four-unit refurbishment.

Filed: 2016-05-27

EB-2016-0152

Exhibit A2-2-1

Attachment 2

Page 11 of 40

Page 11

$ millions

2016 2017 2018

Sustaining Capital

Total Nuclear (Incl. MFA) 250 280 200

Regulated Hydroelectric (Incl. MFA) 109 136 105

Regulated Hydroelectric - Sir Adam Beck PGS Reservoir Rehabilitation 56 14 -

Contracted Plants (Incl. MFA)

Contracted Plants -

Total Hydro-Thermal Operations

Business and Administrative Services (Incl. MFA) 37 30 36

Finance 1 1 1

People & Culture 4 5 5

Commercial Operations & Environment 1 1 1

Corporate Office 1 1 1

Total Support Services and Commercial Operations & Environment* 44 38 44

Total Sustaining Capital

Value Enhancing Capital

Sir Adam Beck Units 1 and 2 Conversion 9 39 31

Total Hydro-Thermal Operations

Ranney Falls Expansion 14 16 11

Other Corporate Business Development

Total Corporate Business Development

Darlington Refurbishment* 886 942 1,013

Total Value Enhancing Capital

Total OPG

Targets

2016-2018 Capital Targets

*The Darlington Refurbishment line item reflects the portion of the preliminary Darlington Refurbishment Project capital target

to be budgeted by the Nuclear business unit. The portions of this target to be budgeted by Support Services and

Commercial Operations & Environment are reflected in the corresponding line items.

Filed: 2016-05-27

EB-2016-0152

Exhibit A2-2-1

Attachment 2

Page 12 of 40

Page 12

$ millions

2016 2017 2018

Nuclear Project Portfolio (Excl. Darlington Refurbishment) 95 110 95

Hydro-Thermal Operations - Regulated Plants Project OM&A 60 90 70

Hydro-Thermal Operations -

Total Hydro-Thermal Operations

Business and Administrative Services - Project OM&A 22 15 12

People & Culture - Project OM&A 1 2 -

Total Support Services 23 17 12

Darlington Refurbishment 13 69 38

Nuclear New Build 3 3 6

Total OPG

2016-2018 Project OM&A Targets

Targets

$ millions

2016 2017 2018

Darlington Refurbishment Retube Waste Containers 9 6 26

Nuclear Waste Management 40 40 40

Total OPG

2016-2018 Provision-Funded Project Targets (Excl. ONFA funded)

Targets

2.2 TARGETS FOR NUCLEAR WASTE MANAGEMENT AND DECOMMISSIONING EXPENDITURES CONTACT: BANH TRAN In addition to the targets for non-ONFA provision-funded project expenditures on nuclear waste management provided in section 2.1, targets for ONFA provision-funded project expenditures on nuclear waste management and decommissioning activities and all operating expenditures for these activities will be provided by Business Planning & Reporting (BP&R) – Nuclear Waste Management in a separate communication.

2.3 WORKFORCE RESOURCING PLAN INITIATIVE CONTACT: EMERISSA BABIN The OPG Integrated Workforce Resourcing Plan (WFP) initiative, which is being coordinated by P&C – Total Rewards & Solutions Centre (Total Rewards) and is also co-sponsored by the Chief Nuclear Officer, was launched earlier in 2015, with the long-term goal of optimizing labour resources across the company. A cross-functional team was established to drive the initiative. The purpose of the 2015 WFP initiative is to develop a single, updated company-wide demand forecast of regular and temporary labour resources, and to identify and address likely resourcing challenges and opportunities in meeting this demand in view of changes in OPG’s operating environment, including the end of commercial operations at Pickering. In recognition of the interrelationship between workforce planning and business planning, BP&R and Total Rewards have worked together to ensure that the two processes are aligned, where possible. BP&R is a participant on the WFP initiative team.

Filed: 2016-05-27

EB-2016-0152

Exhibit A2-2-1

Attachment 2

Page 13 of 40

Page 13

The work on the 2015 WFP initiative is expected to conclude by September 2015. The BU business plans need to identify and reflect any likely material savings resulting from the work on the WFP initiative, where not inconsistent with the planning assumptions outlined in these instructions. To that end, BU planners need to work closely with the corresponding WFP team members in developing the business plans. BU planners are also requested to assist WFP team members by providing them with any updates to the 2016-2018 forecast labour resource demand identified through this year’s business planning process. If the WFP initiative results in material changes subsequent to the initial planning submission date of July 27, BUs must communicate this to BP&PR, who will assess, on a case-by-case basis, the need for an adjustment to the business plans.

3.0 KEY PROCESS CHANGES CONTACT: VASSA CHASE The 2016-2018 business planning process continues to leverage the integrated enterprise planning approach led by Corporate Strategy and Planning, and the information and assumptions developed as part of the long-term financial outlook update process in the first half of the year. Further improvements as part of the 2016-2018 business planning process have enabled labour rates, including payroll burdens, to be updated in the business planning system earlier than in previous years, with final resource targets also communicated earlier to the BUs. As a result, last year’s earlier BU business planning submission date of end of July is retained for this year’s planning cycle. The end of July submission date allows for an earlier consolidation of preliminary 2016-2018 financial results, currently expected to be in time for the CEO/ELT review meetings of the BU business plans in mid to late September. The 2016-2018 business planning process will continue to leverage the process improvements and system enhancements implemented to-date, by focusing on initiatives to further reduce the planning and budgeting level of detail and provide an opportunity for BUs to separate certain planning and budgeting activity for greater flexibility. 3.1 STREAMLINING USE OF RESPONSIBILITY CENTRES AND LOCALS

CONTACT: VASSA CHASE

As part of this year’s planning cycle, Controllers are required to review all existing RCs to ensure that planning/budgeting occurs only for RCs that have at least 20 employees and $5M in combined financial activity (OM&A, capital expenditures, revenues, and provision expenditures). Planning/budgeting can also occur for RCs that meet the following exceptions:

i) Direct reports of ELT members ii) Facilities with energy supply agreements/commercial contracts iii) Requirements exist to separate rate-regulated activities

All other exceptions require prior written justification from the local Controller and approval by the respective BU Finance leader (i.e. VP Nuclear Finance, VP HTO Finance, Director Controllership for Support Services). Approvals should be forwarded to Director, Business Planning & Regulatory Finance and Director, Management Reporting. Exceptions approved in prior years should be reviewed by BU Finance leaders to ensure that justifications remain valid for the 2016-2018 planning period. A list of the 2015 RCs from the 2015-2017 BP for the respective organizations can be found on the Finance – Business Planning SharePoint site. Controllers are also requested to review the planning/budgeting “Local” identifiers for opportunities to reduce the level of detail. The Controllers should ensure that the use of “Locals” is consistent within the respective BUs and, in particular, is limited to instances where such identifiers are necessary for reporting and analysis of actual results.

Filed: 2016-05-27

EB-2016-0152

Exhibit A2-2-1

Attachment 2

Page 14 of 40

Page 14

3.2 PLANNING VERSUS BUDGETING CONTACT: VASSA CHASE The BPC system rollover capability maintains 2016 and 2017 OM&A information from the 2015-2017 BP and copies over the 2017 OM&A information into 2018 for all BUs. This information is then updated for new labour rates including payroll burdens. As a result, in many instances, it is appropriate to develop the 2016-2018 planning submissions by making adjustments to the copied data from last year’s plan.

For the initial BPC data load on July 27, labour costs must be planned for all years at the detailed RT level. BUs have the option, for their initial submission only, of using only the following higher Major Resource Type levels in making non-labour adjustments to copied data in BPC:

- Managed Tasks - Facilities & Utilities - Augmented Staff - Operating License - Materials - Real Estate - Business Expenses - Other

If this higher level approach is adopted for the July 27 submissions, BUs may plan against one (or more) RT within each Major Resource Type that is most meaningful to their organization (for a detailed RT listing within each Major Resource Type, refer to the Finance – Business Planning SharePoint site).

Irrespective of the approach adopted, the following specific RTs must also be planned during the initial data load, for tax purposes:

- 240: Materials - 242: Computer Equipment - 245: Service Equipment <$25,000 - 572 & 573: Meals in Canada, and Meals Outside of Canada

For the initial BPC data load on July 27, the BUs also have the option of making adjustments to last year’s planning data at higher level RCs, as follows:

For Nuclear and Hydro-Thermal Operations, station or support group level RCs can be used

For Support Services and CO&E, ELT direct report level RCs can be used

The BUs may also consider if some of the “Local” identifiers can be omitted from the initial BPC data load. “Locals” are required for the initial data load only to the extent necessary for meaningful plan-over-plan and year-over-year analyses. In all circumstances, the overriding principle for the initial BPC data load is to plan in sufficient detail, so as to provide meaningful plan-over-plan and year-over-year analyses.

Budgeting to enable 2016 reporting and facilitate the rollover of 2017 and 2018 planning details into future plans must be completed by September 30. Budgeting requires the pushing down of higher-level planning data to the detailed RT and RC levels, and the use of “Locals” to the extent necessary to enable reporting and analysis of actual results. No changes to annual planned amounts (OM&A, capital expenditures, revenue, provision expenditures) from the initial July 27 BPC data load can be made on account of finalizing the detailed budgets. The only changes permitted from the initial submission are those resulting from the CEO/ELT reviews or other corporately driven changes, which must be reflected in the BPC budgeting detail by September 30. As the last step, in October, the BUs will be required to update the BPC data for the Darlington refurbishment budget information, as discussed in section 1.7. 3.3 OTHER CHANGES

CONTACT: VASSA CHASE

The following changes are also being introduced as part of the 2016-2018 business planning process:

Full-time equivalent (FTE) calculations for regular labour costing must use the half-year rule. That is, when a regular headcount is added or removed during the year, 0.5 of an FTE must be added

Filed: 2016-05-27

EB-2016-0152

Exhibit A2-2-1

Attachment 2

Page 15 of 40

Page 15

or removed in that year for labour costing purposes. There are no exceptions to this requirement without the explicit approval by BP&PR.

There may be a need to change labour costing assumptions, including payroll burdens, during the planning process, due to adjustments resulting from the collective bargaining process and/or updated pension and other post-employment benefit (OPEB) cost projections. These changes will either be incorporated into the detailed standard labour rates (SLR) or budgeted at the BU-leader level, with corresponding adjustments to the targets, if affordable. BP&PR will provide further information on any such changes including timing.

Although the plan will continue to cover a period of three years, BPC will contain labour rates, including burdens, for years 2019 and 2020 that allow planning for those years for the BUs that require it.

4.0 SCHEDULE CONTACT: ANTHONY MELARAGNO The following is the schedule of the key activities for the 2016-2018 business planning process. Business planning activities require significant coordination among various organizations in the business during the business planning timeframe. At times, the same information is used by different users, but at different times during the business planning process. It is critical to the integrity of the consolidated OPG plan that information provided to different business planning users is consistent.

MONTH BUSINESS PLANNING ACTIVITY

April – May

Historical labour data submission by P&C to BP&R – Management Reporting & Forecasting (MR&F) – by early April

Completion of labour rate review by MR&F – April 20

Major planning assumptions endorsed by the Enterprise Leadership Team – May 12

Approved business planning targets issued – May 15

Standard labour rates (including burdens) are updated in BPC version W01 for 2016-2018 – May 15

Final business planning instructions issued – May 29

June Continuing site and BU plan development

July

BU submissions of inputs into the Energy Production and Revenue Plan to CO&E – Integrated Revenue Planning – July 3

Calculations of nuclear fuel bundles (including Bruce) provided by BAS – Supply Chain to BP&R – Nuclear Waste Management – July 3

BUs to CO&E – Commercial Contracts & Power Marketing – July 13

BU submissions of 2016-2018 BPC planning input to BP&PR (note: all planned intracompany work for others must be identified and agreed upon by the service recipient and service provider beforehand) – July 27

Submissions of corporate level information including depreciation, employee incentive costs and other centrally-held costs to BP&PR – July 27 (see section 5.5 for details)

August

Review of including inputs and assumptions, by senior Finance staff – August 4 (refer to section 5.2 for details)

Finance review and sign-offs by BU Controllers submitted to BP&PR – August 7

Energy Production and Revenue Plan submitted by Integrated Revenue Planning to BP&PR – August 10

Planning business cases and project information submitted by BUs to Finance –Investment Planning – August 10

Nuclear asset retirement obligation and Nuclear Funds balance projection provided to BP&PR by BP&R – Nuclear Waste Management – August 14

Finance review and sign-off by Director, Accounting submitted to BP&PR – August 14

BUs submit supplementary financial information, analyses and reconciliations to BP&PR, including plan-over-plan and year-over-year analysis – August 21

Variance and deferral account information provided by Regulatory Finance – August 25

Filed: 2016-05-27

EB-2016-0152

Exhibit A2-2-1

Attachment 2

Page 16 of 40

Page 16

Draft CEO/ELT business plan presentations, including Energy Production and Revenue Plan, submitted to BP&PR – August 28

September

Draft consolidated 2016-2018 financial results prepared by BP&PR – mid September

CEO/ELT reviews of BU business plan presentations – mid to late-September

Support Services groups, CO&E and Hydro-Thermal Operations (HTO) submit assigned/allocated costs to Support Services Controllership (see section 5.1.4 for details) – September 22

Revisions to BU BPC submissions based on CEO/ELT reviews and inclusion of budgeting level detail – no later than September 30

Updated Finance reviews and sign-offs (as required), no later than September 30

October

Submission of planning information on the updated Darlington refurbishment budget and schedule to BP&PR, Nuclear Finance – Business Planning & Benchmarking, and Support Services Controllership – October 5 (see section 1.7)

BUs submit draft Board of Directors business plan presentations to BP&PR – October 20

BUs finalize 2016/2017 monthly trending and update BPC data for the refurbishment budget and schedule (no other changes to annual amounts are permitted) – October 30

November Approval of the 2016-2018 BP by OPG’s Board of Directors – November 13

December

Finalization of cost allocations and loading of budgets into reporting systems

Issuance and acknowledgement of budget letters

Conversion of planning information to Shareholder’s fiscal basis

Note: Draft planning information may be reviewed with OPG’s Shareholder throughout the business planning process. 5.0 BUSINESS PLANNING AND BUDGETING INSTRUCTIONS 5.1 BUSINESS UNIT INFORMATION SUBMISSIONS CONTACT: ANTHONY MELARAGNO Business planning submissions are required from each BU for each of the three years of the 2016-2018 BP by the dates specified in the business planning schedule (see section 4.0). Information submissions will reflect OPG’s reporting segment structure: Regulated – Nuclear Generation, Regulated – Nuclear Waste Management, Regulated – Hydroelectric, Contracted Generation Portfolio, and Services, Trading and Other Non-Generation. Further details continue to be required for the HTO facilities, as discussed in section 5.3. BUs will use BPC to submit the majority of financial and headcount information. All other information will continue to be submitted through the Finance – Business Planning SharePoint site. Representatives from each applicable BU were previously identified for purposes of the SharePoint access, with responsibility rights granted accordingly. As in the past, individual BU folders will only be accessible by members of that specific BU, as well as the BP&PR team. For questions regarding SharePoint access, contact Kris Rowsell at 400-3378. The BU submissions should include the following: July 27 – Quantitative resource and financial information

Submitted through BPC, in accordance with the details in section 5.7

By RC and RT, in line with the direction provided in section 3.2

The initial submission must contain summarized monthly detail for 2016 and 2017, with emphasis on realistic forecasts for the first quarter of each year (for Shareholder’s fiscal year-end purposes) and annual information for 2018

Any changes to planning submissions subsequent to July 27, other than those explicitly contemplated by these instructions, must be reported to, and confirmed with BP&PR.

Filed: 2016-05-27

EB-2016-0152

Exhibit A2-2-1

Attachment 2

Page 17 of 40

Page 17

August 21 – Supplementary financial information and supporting year-over-year, plan-over-plan and plan-to-target analyses

Year-over-year analysis of changes in resources (e.g., regular and non-regular headcount, base OM&A, project OM&A, outage OM&A, capital expenditures, non-generation revenues and cost of goods sold, and provision expenditures)

o Analysis should be provided in the form of a year-over year continuity (roll) in a level of detail that is sufficient to fully explain the major drivers contributing to the change

o Work program changes should be separated from rate changes o Analysis should include year-end 2015 projections assumed in preparing year-over-year

changes

Plan-over-plan comparison (2016-2018 BP versus 2015-2017 BP)

Plan-to-target reconciliations including drivers of variance

Submitted through the Finance – Business Planning SharePoint site in the form of Excel spreadsheets and/or other documents.

August 28 – Business Plan PowerPoint presentations for CEO/ELT reviews (refer to section 5.1.3 for details) 5.1.1 Specific Information Requirements Contact: Anthony Melaragno

OM&A

OM&A expenses reconciled to total OM&A targets outlined in section 2.0, with project OM&A reconciled to project OM&A targets outlined in section 2.1

o If the submission exceeds targets, reconciliations should identify specific sources of variance from targets, underlying drivers, and mitigation measures taken

Year-over-year and plan-over-plan analyses should specifically identify material changes driven by outage profiles, non-standard projects, or non-recurring or infrequent events

o Significant drivers for non-labour resource changes should be separately identified o Nuclear outage OM&A analysis should be provided including a summary of scope, outage

duration and incremental OM&A costs. Staffing

Details of regular and non-regular headcount (excluding augmented staff), including regular headcount reconciled to the targets outlined in section 2.0, and FTE funding for each of regular and non-regular labour

o If the submission exceeds targets, reconciliations should identify specific sources of variance from targets, underlying drivers, and mitigation measures taken

o Staffing details must be consistent with information generated through the 2015 WFP initiative (see section 2.3)

o Summary headcount analyses, including projected attrition, hiring, and plans to meet the hiring demand including the use of temporary and contract resources, as applicable, should be provided.

Capital

Capital expenditures, including intangible assets and capital spares, balanced to project listings, as directed in section 5.9, and expenditures on minor fixed assets, together reconciled to capital targets outlined in section 2.1

o Reconciliations should identify specific reasons for variance and underlying drivers

Expenditures on capital spares expenditures should continue to be identified and input into BPC as a separate classification

Consistent with capital project plan BPC details and project lists, the following is to be provided: o Capitalized interest forecasts on a monthly basis for 2016 and 2017 and annually for 2018,

including forecasts for any supplemental adjustments o In-service addition forecasts on a quarterly basis for all three years, including in-service addition

forecasts for any supplemental adjustments. Monthly details are required where a single in-service addition is at least $50M, as well as for all Darlington refurbishment amounts. In addition, in-service addition forecasts are required for the third and fourth quarters of 2015.

Filed: 2016-05-27

EB-2016-0152

Exhibit A2-2-1

Attachment 2

Page 18 of 40

Page 18

o Quarterly asset retirements/write-offs forecasts are to be provided for all three years. Monthly detail is required where a single asset retirement/write-off is at least $50M.

Fuel Expense

The following fuel expense details must be submitted to BP&PR and Integrated Revenue Planning as part of the inputs into the Energy Production and Revenue Plan, which is due on July 3:

o Nuclear fuel o Gross revenue charges and related costs – both excluding and including forgone production

due to surplus baseload generation conditions o thermal stations.

Provision Expenditures/Provisions

Nuclear decommissioning and waste management provision expenditures, in line with guidance provided in section 5.1.5

o Expenditures should be provided for: Decommissioning – Pickering Units 2 & 3, Pickering Units 1 & 4, Pickering

Units 5-8, and Commissioning Oversight Used Fuel Storage Low and Intermediate Level Waste – Operations

o Expenditures should be reconciled to targets to be provided by BP&R – Nuclear Waste Management (see section 2.2)

o If submissions exceed targets, reconciliations should identify specific sources of variance, underlying drivers, and mitigation measures taken

New provisions or provision updates (First Nations and other) expected during the planning period and any related draw downs

First Nation provision expenditures (draw downs of existing provisions)

Environmental provision expenditures

Nuclear Segregated Funds

Submission of planning information for reimbursements from the nuclear segregated funds must be consistent with the planned draw downs of the nuclear decommissioning and waste management provision, and will be coordinated by BP&R – Nuclear Waste Management

Working Capital Items

Monthly detail for 2016 and annual detail for 2017 and 2018 for the following: o Fuel inventory o Materials and supplies inventory

Nuclear Outages

Summary nuclear outage schedule by facility for the planning period Revenue and Gross Margin

As outlined in section 5.2 5.1.2 Payroll Burden Contact: Vassa Chase

This year’s business planning process will see payroll burden rates calculated and reset for all years. The updated burden rates have been incorporated into version W01 of BPC on May 15. The BU-leader level burden amounts from the 2015-2017 BP must therefore be removed from version W01 before beginning to plan for 2016-2018. The impact of any subsequent changes to 2016-2018 planned burdens (either positive or negative) will form part of the BU business plan by either being incorporated into the planning SLRs in BPC or, as in the last several years, budgeted in BPC at the BU-leader level. If affordable, targets will be adjusted correspondingly. BP&PR will provide further information on any such changes including timing.

Filed: 2016-05-27

EB-2016-0152

Exhibit A2-2-1

Attachment 2

Page 19 of 40

Page 19

In 2016, the rate variance account (primary pay) will be charged with actual pay, including updated burden. Differences between (i) actual burden amounts, and (ii) the total burden amount reflected in the SLR and at the BU-leader level (if any) will be journalized monthly to a centrally held account in 2016. This will ensure that no variance from budget results in 2016 with respect to the BU-leader level burden (if any). As in prior years, costs relating to employee incentive plans will be budgeted as a centrally-held cost at the corporate level. For further details regarding the use of BPC for the 2016-2018 business planning cycle, refer to section 5.7.

5.1.3 Business Plan Presentations Contact: Vassa Chase The CEO/ELT review presentations, which will take place in mid to late-September, will be based on the BPC submissions. Draft presentations are to be provided to BP&PR on August 28, in advance of the scheduled CEO/ELT review meetings. The submissions are to be made through the Finance – Business Planning SharePoint site. As noted in section 1.7, the CEO/ELT review presentations will not reflect the final Darlington refurbishment budget and schedule, which will be available in early October. This information will be incorporated in the business plan presentations to the Board of Directors. The draft Board of Directors presentations are to be submitted to BP&PR on October 20. While the structure and scope of the CEO/ELT review presentations continues to be determined by the BUs, the minimum presentation requirements are as follows:

Strategic Objectives & Key Operating Performance Measures over the planning period

Key Planning Assumptions

Financial Plan – Including 2015 year-end projection o BUs that have major work performed by groups outside of their organization (e.g., Darlington

refurbishment) should note the cost of such planned work in order to present a complete cost of the project or work program

Staff Plan – Including summary hiring plan to meet planned labour demand over 2016-2018 and 2015 year-end projection (including use of temporary and contract resources, as applicable), consistent with the work undertaken as part of the 2015 WFP initiative and incorporating likely material savings identified through that work

Generation Plan (as applicable)

Key Initiatives – Including strategic sourcing initiatives and resulting savings reflected in the financial plans

Program Write-ups

Plan-over-Plan Comparisons (2016-2018 BP versus 2015-2017 BP) – including an analyses of changes in resources (OM&A, capital, provision expenditures, headcount) and programs

Plan-to-Target Comparisons – Including drivers of variance and steps taken to mitigate submissions in excess of targets

Year-over-Year Changes – Including explanations of material factors contributing to the changes

Risks and mitigation strategies incorporating the requirements of section 6.1.2. Integrated Revenue Planning is required to submit to BP&PR, by August 28, a presentation summarizing the Energy Production and Revenue Plan, including key assumptions, dependencies, risks, and major changes from last year’s plan, either as part of the CO&E business plan presentation or as a standalone document.

5.1.4 Cost Allocations for Support Services, CO&E and HTO Contacts: Jenny Ruz/Michelle Girard

Support Services groups, CO&E and HTO are required to assign/allocate all submitted costs on the basis of OPG’s cost model, and in line with the current reporting segment structure and HTO information requirements in section 5.3. Support Services groups and CO&E are expected to provide the rationale for any management estimates made for the purposes of cost assignment/allocations. As in prior years, a template for this information will be provided by, and must be submitted to, Support Services Controllership.

Filed: 2016-05-27

EB-2016-0152

Exhibit A2-2-1

Attachment 2

Page 20 of 40

Page 20

HTO site Controllers are also required to submit to Support Services Controllership allocation factors between regulated and contracted plants, where applicable, for all years of the business plan. These factors must continue to be applied consistently across the hydroelectric operations in accordance with established methodologies. The submission date for the above information is September 22. 5.1.5 Nuclear Provision Expenditures Contact: Banh Tran Planning for nuclear decommissioning and waste management provision expenditures requires the same rigour and change management process as OM&A and capital expenditures. Similar to OM&A, provision programs are classified as either base or project. Each provision program is to have a designated executive sponsor responsible for scope, life-to-date and annual expenditures, and approval of the budget with the executing organization. Only expenditures that are directly attributable to nuclear waste management and decommissioning activities and included in the provision should be planned as provision expenditures. Directly attributable, for the purposes of nuclear provision expenditures, is defined as follows:

For support groups such as P&C, Regulatory Affairs, Finance, and BAS, directly attributable is defined as:

o Costs of staff that is fully dedicated to the support of the nuclear waste management and decommissioning programs. Timesheet tracking of partial support from multiple employees does not qualify.

Staff working on nuclear waste management and decommissioning specific project activities and work programs as a normal part of their function. These work activities will be tracked within the Tempus time reporting system.

Business planning for nuclear provision expenditures must follow the schedule and process set out in these instructions, including loading of BPC data, requirements for supplementary analyses, and business plan presentation content. Any changes to planning submissions for provision expenditures after July 27, other than those explicitly contemplated by these instructions, must be reported to, and confirmed with, BP&PR. These changes must also be reported to BP&R – Nuclear Waste Management. 5.2 REVENUE AND GROSS MARGIN SUBMISSIONS CONTACTS: BILL WILBUR/VASSA CHASE The accountabilities for revenue and gross margin information submissions to BP&PR are outlined below. While BP&PR may initially receive some of this information from groups other than those identified below, it is ultimately the responsibility of the identified groups to make formal submissions in accordance with these instructions. Any additional sources of revenue expected during the planning period should be identified to BP&PR and Integrated Revenue Planning by the group responsible for managing the revenue source. BU submissions of inputs into the Energy Production and Revenue Plan are to be provided to Integrated Revenue Planning by July 3. Specific information requirements for inputs into the Energy Production and Revenue Plan will be communicated by Integrated Revenue Planning. BU cost inputs for determining must be submitted to CO&E – Commercial Contracts & Power Marketing by July 15. If there are changes to these inputs following July 15, updated information must be provided to Commercial Contracts & Power Marketing as soon as possible. By August 4, including inputs and assumptions, will be jointly reviewed by Commercial Contracts & Power Marketing, Integrated Revenue Planning, and senior Finance staff from Hydro-Thermal Controllership, Shared Financial Services – Revenue Accounting & Reporting, and BP&PR. Unless otherwise specifically noted in the business planning schedule, the below revenue and gross margin submissions are due to BP&PR on July 27.

Filed: 2016-05-27

EB-2016-0152

Exhibit A2-2-1

Attachment 2

Page 21 of 40

Page 21

REVENUE SOURCE BUSINESS PLANNING ACCOUNTABILITY

Generation/Capacity Revenue (incl. new projects)

Ancillary and other revenues

CO&E – Integrated Revenue Planning (as part of the Energy Production and Revenue Plan) BP&PR will apply regulated rate assumptions to compute generation revenues for the regulated facilities

CO&E – Integrated Revenue Planning (as part of the Energy Production and Revenue Plan)

Nuclear Non-Generation Revenue*

Isotope Sales

Heavy Water / Detritiation Sales and Services

Bruce Lease Rent (incl. rent rebate payments) and L&ILW Services

CO&E – Commercial Contracts & Power Marketing (Revenue) Nuclear (Cost of Goods Sold)

Nuclear Non-Generation Revenue*

Engineering Services

Investment Recovery

Nuclear

HTO Non-Generation Revenue* HTO

Training and Other Revenue* P&C

*For items marked with an asterisk in the table above, the identified groups are responsible for inputting the planning submission into BPC, including monthly trending for 2016 and 2017.

5.3 INFORMATION REQUIREMENTS FOR HTO FACILITIES CONTACT: ANTHONY MELARAGNO Where applicable, HTO’s detailed planning submissions should continue to provide information for each of the facilities or groupings listed below. For the purposes of the HTO business plan presentation, it is expected that information will be aggregated, as appropriate, consistent with OPG’s segment reporting structure. The specific HTO facilities/groupings are as follows:

Niagara Operations

Saunders GS

Eastern Operations – excluding Saunders GS and Lennox GS

Central Operations – excluding

Northeast Operations – excluding

Northwest Operations – excluding

Filed: 2016-05-27

EB-2016-0152

Exhibit A2-2-1

Attachment 2

Page 22 of 40

Page 22

The submissions should address all applicable information requirements outlined in these instructions for each of the above facilities/groupings. Directly attributed and allocated HTO regional operations and HTO central office OM&A should be shown separately. 5.4 NON-CONTROLLING INTEREST AND INVESTMENTS SUBJECT TO SIGNIFICANT INFLUENCE

CONTACT: VASSA CHASE

5.5 OTHER INFORMATION SUBMISSIONS CONTACT: ANTHONY MELARAGNO The accountabilities for information submissions related to other cost items for the 2016-2018 BP are outlined below. While BP&PR may initially receive some of these items from groups other than those identified below, it remains the responsibility of the accountable group to make the formal submissions in accordance with the business planning schedule. Key assumptions and dependencies should be identified in the submissions.

ITEM BUSINESS PLANNING ACCOUNTABILITY

Depreciation/Amortization – July 27 o Based on current net book values of fixed/

intangible assets, and station end-of-life dates / average asset class service lives expected to be in effect during the planning period, including changes expected from the Depreciation Review Committee process

Finance – Shared Financial Services – Accounting

Property Tax (separately showing amount to be charged against the nuclear decommissioning provision) – July 27

BAS – Real Estate & Services – Property Assessment and Taxation

Insurance – July 27 o Summary of assumptions regarding increased

nuclear liability limits and associated costs to be included

o Amounts charged against nuclear decommissioning provision to be shown separately

Finance – Treasury (costs submitted as part of the Finance BPC submission)

Employee incentive plans (centrally-held cost) – July 27

P&C – Total Rewards & Solutions Centre

Vacation accrual and fiscal calendar adjustment (centrally-held costs) – July 27

Finance – Shared Financial Services – Accounting

Pension Guarantee Fee (centrally-held cost) – July 27

Finance – BP&R – Actuarial

Accretion on Nuclear Waste Obligations and Earnings on Nuclear Segregated Funds – August 14

Finance – BP&R – Nuclear Waste Management

Pension and OPEB Costs – final update (as required) by August 18

Finance – BP&R – Actuarial

Filed: 2016-05-27

EB-2016-0152

Exhibit A2-2-1

Attachment 2

Page 23 of 40

Page 23

Deferral and Variance Accounts – by August 25

Finance – BP&R – Regulatory Finance

Asset Service Fees, Accretion on Non-Nuclear Decommissioning Obligations, and Interest Expense

Finance – BP&PR (for interest, reflecting inputs from Treasury and capitalized interest from BUs)

Income Taxes, and Commodity Tax Recaptured Input Tax Credits (centrally-held cost)

Finance – Income Tax

5.6 FINANCE REVIEW AND SIGN-OFF CONTACT: VASSA CHASE The following senior Finance staff will complete and submit to BP&PR a financial review and sign-off for the business planning submissions for the groups that they support/represent:

All BU Controllers by August 7 (note: Non-generation revenue and will be included in the review and sign-off by Support Services Controllership)

VP HTO Finance, Director, Accounting and Director, Business Planning & Regulatory Finance jointly by August 14 –

Director, Accounting by August 14 – depreciation & amortization (excluding amortization of deferral and variance accounts) and centrally-held costs per section 5.5, as well as inputs to BP&R – Nuclear Waste Management for nuclear waste obligations and segregated funds

Senior Manager, Nuclear Waste Management by August 14 – nuclear decommissioning and waste management obligations based on inputs provided

Director, External Reporting & Accounting Policy by August 21 – pension and OPEB assumptions, calculations and accounting treatment

Senior Manager, Regulatory Finance by August 25 – deferral and variance account assumptions, calculations and accounting treatment

Director, Taxation – income taxes and centrally-held commodity tax Recaptured Input Tax Credits

Assistant Treasurer – Treasury inputs The sign-off will confirm that the Finance staff have reviewed the planning submissions and are in agreement with the following (as applicable) in respect of the submissions:

Appropriateness and consistency of financial/economic assumptions

Compliance of submissions with US Generally Accepted Accounting Principles (GAAP), including consistency of their application

Completeness and accuracy of the financial submissions on the basis of known operational assumptions

Basis of investment decisions identified in the plan

Compliance of financial/economic assumptions and calculations with contractual, legal, regulatory or other requirements, and OPG governance

Compliance with these business planning instructions, including the requirement to use the half-year rule for determining FTEs in costing planned labour (see section 3.3)

Material asset removal costs, in-service additions, and asset retirements have been identified in the appropriate period and have been correctly classified in accordance with US GAAP

Interest capitalized on construction and development in progress has been calculated using interest rates per the planning instructions and in accordance with US GAAP

Planned costs have been appropriately classified as capital, OM&A or provision expenditures in the appropriate period in accordance with US GAAP

Planned contractual milestone accruals have been budgeted in the appropriate period

Valuation of materials and supplies inventory and related obsolescence charges are appropriate

Valuation and depreciation/amortization of fixed and intangible assets (based on station/asset class services lives) over the planning period are appropriate in accordance with US GAAP

Underlying assumptions and valuations for provisions included in the plan, other than for nuclear decommissioning and waste management, (e.g., First Nations, environmental, etc) are based on measurability and probability of occurrence criteria in accordance with US GAAP

Based on planning assumptions outlined in these instructions, assumptions underlying the obligations for nuclear decommissioning and waste management are appropriate, and the obligations would be fairly stated in accordance with US GAAP

Planned regulatory asset and liability balances are appropriately stated in accordance with US GAAP

Filed: 2016-05-27

EB-2016-0152

Exhibit A2-2-1

Attachment 2

Page 24 of 40

Page 24

Derivative financial instruments have been identified and appropriately recognized/valued in accordance with US GAAP, based on planning assumptions

Inputs into calculations are appropriate and consistent with costs and other planning submissions to BP&PR

All material accounting implications of current or anticipated policy changes have been identified and included in the planning submissions

Income and other tax calculations have been appropriately performed

Other items included in the plan are reasonably stated, in light of planning assumptions outlined in these instructions and taking into account the risk of error, materiality, degree of judgement required, the nature of the item (recurring vs. non-recurring/unusual), and the complexity of accounting

As in prior years, the sign-off may take the form of a memorandum or e-mail addressed to Vice-President, Business Planning & Reporting and/or Director, Business Planning & Regulatory Finance.

5.7 INSTRUCTIONS FOR USE OF THE BPC BUSINESS PLANNING SYSTEM CONTACT: KAREN MOONEY Planning in BPC for 2016-2018 will use version W01, which reflects updated SLR including payroll burden rates. The additional working versions W02 and W03 will be available to isolate the impact of the new SLR, including burdens, on last year’s planned data. BUs must contact the BPC administrator to request data to be copied into W02 and W03 for this purpose, within the July 28 to August 10 window. The versions of BPC will be as follows:

W03 contains the approved 2015-2017 BP information, rolled over for the 2016-2018 planning horizon. This version will be used to isolate the impact of the new SLR, before updated burdens, by comparing to version W02.

W02 will contain the new SLR, which reflect actual 2015 experience but not the 2016-2018 burden updates, applied to the rolled over 2015-2017 BP information. Version W02 can be compared with version W03 to isolate the impact of SLR changes excluding burdens.

W01 contains the approved 2015-2017 BP rolled over for the 2016-2018 planning horizon, with the new SLR including updated payroll burden rates, by job family. The BU-leader level burden amounts from the 2015-2017 BP are reflected in this version as part of the roll over of last year’s data, and therefore must be backed out in isolating the impact of updated burdens.

The BPC details required in order to consolidate information for the 2016-2018 BP include:

Work program and project information trended on a monthly basis for 2016 and 2017 and annually for 2018

Total labour requirements balanced to the total labour supply in BPC Headcount trending that reflects realistic assumptions Realistic assumptions for project initiation and vacancy management

Final trended information is required on a monthly basis for budget year 2016 and for 2017. By end of day on October 30, all trending must be completed in W01, and BUs will be locked out of BPC for the 2016-2018 business planning process. At that point, the trending by the BUs will be considered final and, for the 2016 budget year, ready for upload to the reporting systems. By October 30, BU Controllers must ensure that the trended BPC input (BU OM&A, capital, provision expenditures, non-generation revenue as per section 5.2, and headcount) is complete and accurate, based on reasonable assumptions, agrees to the CEO/ELT-approved resource levels, and reflects the updated Darlington refurbishment information per section 1.7. Additionally, the following input will be reflected in BPC:

MR&F is responsible for developing the BPC trending of labour rate variances, to be held at the corporate level

In consultation with the responsible groups, BP&PR will develop trending for accretion expense and earnings on nuclear segregated funds, applicable centrally-held costs, and, based on in-service information provided by the BUs, depreciation & amortization expense

Filed: 2016-05-27

EB-2016-0152

Exhibit A2-2-1

Attachment 2

Page 25 of 40

Page 25

Trended BPC input for generation revenue will be provided by Integrated Revenue Planning by November 18, incorporating regulated revenue assumptions from BP&PR as required

Trended BPC input for deferral and variance accounts will be provided by Regulatory Finance by November 18.

5.8 BUDGETING FOR SERVICE PROVIDERS

CONTACTS: JENNY RUZ/BOSCO YUAN/MICHELLE GIRARD

OPG’s cost model is a company-wide set of business rules that are the foundation of financial planning, budgeting and cost reporting, and define how OPG accounts for resources. Under the cost model, an organization at OPG plans for all the resources for which it is accountable (i.e. labour – regardless of where the resources work or what they work on, materials, purchased services, etc). For projects, this means that the project manager holds all the resources for the project, with the exception of internal labour that is provided and budgeted by another OPG organization. The cost model applies to all BUs without exception. The cost model requires service recipients (in most cases the operating business units) to identify and estimate the annual resources that they expect to be supplied by other OPG organizations (in most cases Support Services) for intracompany work. The identification and communication of this information must occur during the initial phase of the planning process, with agreement required between the service providers and service recipients by the initial BPC submission date of July 27. This will ensure that service providers’ planning submissions adequately reflect the necessary resource levels (such as OM&A, capital including minor fixed assets, and provision expenditures) in accordance with the cost model. BUs are strongly encouraged to formally document the agreed upon service requirements and associated costs via Service Level Agreements. Resources in support of the Darlington refurbishment being planned by Support Services and CO&E require approval by SVP, Nuclear Projects. Additional guidance regarding services provided by certain specific Support Services organizations is provided below. For CO&E – Environment requirements, refer to section 6.4. 5.8.1 Information Technology (IT) Requirements

IT requirements should be communicated to the appropriate BU IT contact within BAS as identified below. The BAS business plan will include resources for all business-related IT needs, IT projects, and IT components of business initiatives. As in the prior year, BAS will plan/budget for all cyber security program costs. The following IT expenditures will be included in each BU business plan, rather than in the BAS business plan, as they are directly related to station process control, which is not available through existing IT commodity contracts:

Process control hardware and software in Nuclear and HTO

Engineering tools (hardware) and new software in Nuclear and HTO (annual maintenance for most existing software is covered by BAS)

Where a BU is asking IT to assume budget accountability for existing items (e.g., annual maintenance contracts), a list of these items and their related costs should be provided to IT for inclusion in the BAS business plan. If there is uncertainty as to whether or not a particular contract or a specific item is identified in the BAS business plan, one of the contacts listed below should be consulted.

IT Projects – Ian Roberts (400-3579 at Head Office)

Nuclear – Alewyn Mouton (703-5476 at Darlington Energy Centre)

HTO and Support Services – Denise Robert (400-2084 at Head Office)

Enterprise Architecture and Cyber Security – Mike Borsch (400-8274 at Head Office)

Filed: 2016-05-27

EB-2016-0152

Exhibit A2-2-1

Attachment 2

Page 26 of 40

Page 26

5.8.2 Supply Chain Requirements

Supply Chain’s focus is on providing cost effective acquisition and timely availability of materials and services. During the planning period, Supply Chain will continue to work with Nuclear Fleet Operations, Maintenance, and Engineering to further refine and align performance measures across the groups. Supply Chain will also continue to administer, negotiate and execute contracts in support of the Darlington refurbishment, other nuclear projects, and hydroelectric development projects. Supply Chain will require, early in the planning process, the BU demand information for materials and supplies and fleet vehicles in order to support continuing implementation of the following key strategies underlying the 2016-2018 BP:

Parts Availability – Managing and organizing the acquisition and distribution activities in support of on-line and outage improvement strategies, work order readiness, vendor quality and supplier performance management, improving equipment reliability, and reducing replenishment of out-of-stock material

Materials and Supplies Management – Working collaboratively with the stations and Nuclear support organizations to improve material availability via work management, on-line and outage planning, and project management processes. In addition, Supply Chain and the Nuclear business unit will work to identify materials and supplies requirements in support of the end of commercial operations at Pickering, and in support of the safe storage and decommissioning of the Pickering units.

Strategic Sourcing – As in the prior year, BUs are expected to identify strategic sourcing savings based on analysis of their procurement plans in consultation with Supply Chain, and to reflect these savings in their business planning submissions. Strategic sourcing savings must be separately identified in the respective BU business plan presentations for CEO/ELT review.

BUs should consult the following Supply Chain contacts, by service area, to identify business unit requirements:

Supply Services Pickering – Ajay Upadhyaya (701-3890)

Supply Services Darlington – Janet Donegan (703-7322 at 1908 Colonel Sam Drive)

Supply Services Waste/IMS – Robert De Bartolo (905-421-9494 ext 3470 at 1340 Pickering Parkway)

Supply Services OPG Projects – Phil Reinert (703-3661 at Darlington Energy Centre)

Strategic Sourcing – Iftikhar Haque (702-5023 at 889 Brock Road)

Warehouse and Logistics – Dave Hudson (704-6609 at Whitby Warehouse)

5.8.3 Real Estate & Services Requirements

Real Estate & Services requirements (e.g., new leases, lease renewals, facility enhancements/modifications, furniture, staff moves, surveys, imagery, printing, graphics, etc) for each BU (including the Darlington refurbishment organization) are to be clearly identified to Real Estate & Services for consideration and inclusion in their planned work programs. Real Estate & Services will consolidate all facility costs in accordance with an overall leasing strategy, tracking costs by facility. Consistent with OPG’s centre-led model and under the OPG Organizational Authority Register, only Real Estate & Services has requisitioning authority for the acquisition, management, and disposal of real estate rights and interests, and related transactions, as well as home purchases and purchase guarantees. Any changes or anticipated changes to the operating status of OPG’s generation facilities as well as dispositions, acquisitions, and leases that could potentially have a financial impact on the property taxation and assessment of any OPG owned property should be communicated to Real Estate & Services – Property Assessment and Taxation, in order to capture the corresponding impacts on property taxes in the 2016-2018 BP.

Filed: 2016-05-27

EB-2016-0152

Exhibit A2-2-1

Attachment 2

Page 27 of 40

Page 27

Real Estate & Services has identified the following contacts by service area:

Real Estate Services – Ron Murphy (400-7201 at Head Office)

Facility & Project Services – Don Seedman (400-3289 at Head Office)

Business Infrastructure Services – Keith Skrepnek (703-2507 at 1908 Colonel Sam Drive)

Property Assessment and Taxation – Alim Yhap (400-4197 at Head Office)

5.8.4 Other Support Services

The P&C organization is responsible for the following Human Resources services: Total Rewards (compensation, pension and benefits), Payroll, Talent Management, Business Change Management, Employee and Labour Relations, and field HR Business Partner support. In addition to Human Resources, P&C is accountable for providing value added support in the areas of Learning & Development, and Health & Safety.

For assistance on P&C matters in developing the 2016-2018 BP, BUs should consult with the following contacts:

Health & Safety – Dave Milton (400-3238 at Head Office)

Business Partners Nuclear – Connie Hergert (702-5133 at 889 Brock Road)

Business Partners HTO – Darlene McVeity (405-4144 at Kipling)

Business Partners Corporate – Melanie Braaten (702-5122 at 889 Brock Road)

Learning & Development – Al Shiever (702-5095 at 889 Brock Road)

The Law division provides legal advice and solutions to legal issues faced by OPG. For assistance on legal matters in developing the 2016-2018 BP, the BUs should contact Brenda MacDonald (400-3603 at Head Office).

5.9 CAPITAL, OM&A AND PROVISION-FUNDED PROJECTS

CONTACT: ROBERT PRILLER This section specifies the requirements for submission of the 2016-2018 BP capital, OM&A and provision-funded project portfolio listings and supporting Planning Business Case Summaries (BCSs). BUs are requested to provide their project information by August 10 to Richard Wong in Finance – Investment Planning. Section 5.9.1 specifies the listing requirements for the project portfolios. Section 5.9.2 provides the criteria for projects requiring Planning BCSs and the information requirements for Planning BCSs. Questions on these requirements should be directed to Robert Priller at 400-2670 or Silvester Wong at 400-2360.

Filed: 2016-05-27

EB-2016-0152

Exhibit A2-2-1

Attachment 2

Page 28 of 40

Page 28

5.9.1 Prioritized Project Lists

BUs are required to identify all capital, OM&A and provision-funded projects having cash flows within the business planning period. The submitted projects must be prioritized to maximize value, while considering risks and OPG’s business objectives, as well as efficient alignment with business unit strategies, facility life cycle plans (as applicable), condition assessments, and Shareholder expectations. The listing format and information requirements have not changed from the previous year and are provided in the Project Listing Template, available in the Investment Planning Toolkit section of the Finance page on the OPG intranet. Definitions and explanations for the various fields in the template are provided in the Targets worksheet of the template. To facilitate review, consolidation and reporting, it is essential that BUs provide all information in the format specified in the listing template. It is also requested that each BU provide a description of their prioritization process. 5.9.2 Planning Business Cases

BUs are required to submit Planning BCSs, or an equivalent document, for projects listed in their portfolio that are not fully released and meet the following criteria:

Projects planned for release in 2016 with cash flows greater than $1M in 2016

Projects planned for release in 2016, 2017, or 2018 with a total project cost greater than $5M For the purpose of these instructions, not fully released projects include:

Projects with no previous releases

Projects with previous release(s) other than a full execution phase release

Previously released projects that are forecasting significant changes in scope/cost and are planned/expected to have a superseding execution phase release

The information requirements for Planning BCSs are specified in the Planning Business Case Summary form (OPG-FORM-0102). Additional information and explanations are provided in Developing and Documenting Business Cases (OPG-STD-0076). Both of these documents are available in the Investment Planning Toolkit on the Finance OPG web site. The above requirements include projects in support of non-generation business opportunities. While the Planning BCS form sets out the information requirements, BUs will often have existing documents that meet the specified information requirements. When such documents (e.g., Type 1, 2 or 3 BCSs) are available and up-to-date, particularly with respect to project prioritization, cash flows and alignment with corporate strategic business objectives, they can be submitted in place of the Planning BCS. All Planning BCSs should be reviewed and signed-off by the appropriate project sponsor (e.g., Asset Manager, Engineering Director, etc) and the local Controller.

5.9.3 BCS Preparation Assistance

For assistance with BCS preparation and project grouping, please contact your local Controller or either Robert Priller at 400-2670 or Silvester Wong at 400-2360 of Investment Planning.

6.0 OTHER PLANNING REQUIREMENTS 6.1 BUSINESS UNIT RISK SELF-ASSESSMENT (BURSA) CONTACT: COLIN THOMSON Each Business Unit must identify known risks to their plan, and should include an assessment of risks as well as plans for risk treatment (mitigation). When introducing a new initiative in a business plan presentation, BUs are required to briefly describe any potential benefits as well as any potential downsides (risks) of embarking on that initiative.

Filed: 2016-05-27

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Exhibit A2-2-1

Attachment 2

Page 29 of 40

Page 29

Important BURSA Dates:

BURSA kick-off email – August 10

Enterprise Risk Management (ERM) meetings with BU risk SPOCs – August 17-28

BU risk SPOCs submit BURSA to ERM via the Governance, Risk and Compliance (GRC) tool – September 11

6.1.1 Business Unit Risk Self-Assessment Process

The goal of the Business Unit Risk Self-Assessment is to identify, assess, and document risks that could impact the achievement of BU objectives over the 2016-2018 business planning period. Longer-term strategic risks (spanning beyond the business plan timeframe) should also be discussed with ERM. The BURSA process is a key component of the quarterly ERM reporting process. In addition to identifying risks to achievement of OPG’s business plan objectives, the BURSA risk detail also forms the basis for quarterly risk reporting to the committees of the OPG Board of Directors. ERM consolidates and reviews all individual BU risk submissions (including business plan presentations and GRC updates) and reviews them with OPG’s senior executives.

NOTES: 1 BU risk SPOCs should ensure all reportable enterprise risks (at minimum) are incorporated in the Business Plan

presentations. Reportable risks are those with a residual risk rating greater than or equal to 30 using the ERM risk rating criteria.

2 The BURSA template will be provided with the Q3 BURSA kick-off email.

3 Existing risks should be updated based on any plan-over-plan changes to the Business Plan assumptions.

For further details please visit the ERM Website (on PowerNet under Business Functions > Ethics, Law, Regulation, Risk & Strategy > Risk ) and the BURSA Information Page.

Step 1: Identify Risks

• Confirm BU objectives and related initiatives and programs

• Identify risks to achieving objectives, initiatives and programs (consult SME's as needed)

• Analyze Business Plan assumptions as a potential source for additional risks

Step 2: Complete BURSA Template

• BU member completes BURSA template for each new risk

• BU member submits template to BU risk SPOC

Step 3: Review and Consolidate BU Risks

• BU risk SPOC reviews and consolidates new and existing BU risks

• BU risk SPOC updates existing risks in Governance, Risk and Compliance (GRC) tool and BU risk registers where applicable.

BURSA PROCESS

2. BURSA TEMPLATE

BURSA template completed for new risks.

2

Responsibility: BU Member

3. GRC UPDATE

Existing risks updated3 and

new risks entered into GRC and BU risk registers. Responsibility: BU risk SPOC

1. BUSINESS PLAN PRESENTATION

Business Plans identify the most significant risks

1 impacting BU objectives. These risks are

identified throughout the business plan presentation where appropriate, with the most significant risks summarized on a separate slide. Responsibility: BU member / BU risk SPOC

3 MAIN DELIVERABLES FROM BURSA PROCESS (TO BE COMPLETED BY BU)

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Exhibit A2-2-1

Attachment 2

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Page 30

6.1.2 Business Plan Presentation Risk Content Recommendations

Instructions, tools and slide templates will be distributed by ERM to all BU risk SPOCs in the Q3 BURSA kick-off email. Specifically, the following should be noted:

The summary slide(s) should include a brief description of each risk, an assessment of the residual risk rating, and proposed plans for risk treatment

A slide template to document risks will be included in the Q3 BURSA kick-off email or can be accessed by following this link Business Plan Presentation Risk Template

Enterprise-wide risks do not need to be included in a specific BU’s business plan presentation.

6.1.3 Risks Impacting Business Continuity and Emergency Management

Risk identification should ensure that all of the 40 Emergency Management Ontario hazards identified in the Enterprise Risk Management Program have been considered. For a list of the 40 Emergency Management Ontario hazards refer to OPG-PROG-0004 – Enterprise Risk Management Appendix A (page 14) by following this link OPG-PROG-0004. 6.2 CORPORATE SAFETY CONTACT: GREG JACKSON With safety as a core value, OPG is committed to safety excellence, sustaining a strong safety culture and continuous improvement in pursuing the goal of zero injuries. The BUs are expected to program accordingly. Otherwise, there are no specific requirements for planning submissions in the area of corporate safety at this time.

6.3 FIRST NATIONS INITIATIVES CONTACT: TIM GIGLIOTTI OPG recognizes the importance of continuing to strengthen relationships with the Aboriginal Peoples in Ontario, as reflected in the First Nations and Métis Relations Policy (OPG-POL-0027) and supporting Standard and Manual found in OPG-POL-0027. All operating BUs and other line organizations that have regular contact with Aboriginal communities are required to develop programs in support of this Policy and include relevant resource requirements in their business plans. In addition, all BUs that have planned for resources related to Aboriginal communities are required to provide specific program details to the First Nations and Métis Relations group by August 21. For further guidance on the information requirements, please contact Tim Gigliotti at 400-3770.

6.4 ENVIRONMENTAL PLANNING REQUIREMENTS

CONTACT: ROB LYNG The environmental component of OPG’s business plan is centred on implementing programs to meet the requirements of the Environmental Policy (OPG-POL-0021), including the following:

Maintaining a single OPG Environmental Management System (EMS) certified to ISO 14001:2004 standard;

Effectively managing OPG’s Significant Environmental Aspects; and

Considering changes in environmental legislation. As in the prior year, environment programs or work should be identified as part of this year’s business planning and, consistent with partnering agreements, the associated budgets should reside with the group that has accountability for the work. Budgeting decisions should be made in collaboration and with mutual agreement between the BUs and CO&E – Environment. Specifically with respect to onsite biodiversity, the budget will be held by CO&E – Environment.

Filed: 2016-05-27

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Exhibit A2-2-1

Attachment 2

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Page 31

Maintaining a Single OPG Environmental Management System

BUs should not budget for maintenance of a local ISO 14001 EMS as this work is carried out by CO&E – Environment. BUs should budget for maintenance of those components of the EMS that are within their accountabilities, particularly operational control and emergency preparedness and response. Where changing local conditions may warrant additional third-party self-assessment beyond the scheduled audits for maintenance of ISO 14001 registration, BUs should identify and reach agreement with CO&E – Environment on these circumstances. The purchased service costs for these additional assessments will be included in the CO&E – Environment business plan. Significant Environmental Aspects

BUs are asked to review the applicable Environmental Programs Summary Documents, available from the Environment Intranet Site for each of OPG’s Significant Environmental Aspects, as described in the updated table below. BUs should budget to meet these program requirements. In order to ensure good management of environmental aspects, including timely receipt of any required environmental approvals, BUs are asked to identify the following in their business plans:

Any new or revised programs, projects, or activities that will result in a change in OPG’s management of a Significant Environmental Aspect or the environmental impact of a Significant Environmental Aspect. The change can be an improvement, such as reduced emissions, or reduced costs of managing the Significant Environmental Aspect; or

Any new or revised programs, projects or activities that introduce a new environmental aspect, such as a new waste stream or effluent.

Significant Environmental Aspect

Business Unit

Nuclear

Operations Refurbish-

ment HTO BAS

Carbon 14 emissions to air

Chemical emissions to water

Generation from low emission and CO2 neutral fuel sources: displacement of fossil fuels

Fish impingement/entrainment

Habitat enhancement: wildlife and biodiversity conservation

Spills

Tritium emissions

Thermal emissions to water

Water flows and level changes

Generation of low and intermediate level radioactive waste

New Environmental Legislation

The Nuclear business unit should include a work program to assess and develop a plan for 2020 compliance with more stringent contaminant concentration standards prescribed in Ontario Regulation 419/05, Air Pollution – Local Air Quality. This applies to the operation and testing of standby generators, emergency power generators and auxiliary power generators. Provincial and federal regulations to restrict greenhouse gas emissions, which are not expected to materially affect OPG's operations, will be considered in future business plans after the regulations have been finalized. No other legislative changes currently require consideration in the 2016-2018 BP.

Filed: 2016-05-27

EB-2016-0152

Exhibit A2-2-1

Attachment 2

Page 32 of 40

Security

CONFIDENTIAL

MEMORANDUM

June 23, 2015

From: Finance – Business Planning & Reporting

To: Carla Carmichael – VP Nuclear Finance

Hamant Becharbhai – Director Nuclear Controllership

Jenny Ruz – Director Controllership, Support Services

Paul Burke – VP Integrated Revenue Planning

Bill Wilbur – Director Integrated Revenue Planning

Banh Tran – Senior Manager Nuclear Liability

Re: Submission of Information for Extended Pickering Operations Option

As you are aware, OPG’s 2016-2018 Business Plan currently assumes a 2020 Pickering end-of-life

date. Under the leadership of the Pickering End of Commercial Operations (PECO) organization,

OPG is assessing the feasibility of the option to extend Pickering commercial operations beyond

2020. The current preferred alternative for assessment assumes the end of extended commercial

operations for two Pickering units in 2022 and the remaining four units in 2024.

As communicated in the 2016-2018 Business Planning Instructions, the Nuclear organization,

Support Services, and Commercial Operations and Environment (CO&E) have been asked to identify

2016-2018 resource requirements and generation impacts of the extension option that are incremental

to the base planning assumption of 2020. This memo outlines the details of the information

requirements and submission process. The requested information should be submitted to Finance –

Business Planning and Performance Reporting (BP&PR) by August 21, 2015.

Information Requirements

For the period 2016-2018, estimated incremental resources (e.g., capital, OM&A, provision,

headcount) and generation impacts necessary to extend Pickering operations should be identified.

The Nuclear organization, Support Services, and CO&E should consult with the PECO organization

for specific instructions to ensure that identified resources and generation impacts are appropriate.

Extending Pickering operations is expected to result in changes from the base case 2020 end of life

assumption that include the following:

Changes in nuclear generation (including additional outage days to perform work necessary

to achieve sufficient confidence in extended operations), and fuel expense

Incremental nuclear OM&A expenses directly necessary to enable extended operations

Additional ongoing nuclear, Support Services and CO&E OM&A expenses that may no longer

be reduced on account of the Pickering end of life in 2020

Additional project OM&A and capital investment

Staffing levels, including potential impact on mix of resources

Changes in materials & supplies and nuclear fuel inventory levels

Reductions in nuclear decommissioning provision expenditures

Changes in used fuel expenses.

Filed: 2016-05-27

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Exhibit A2-2-1

Attachment 2

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Submission of Information for Extended Pickering Operations Option

2 CONFIDENTIAL

Submission Process

The incremental changes to OM&A, capital, provision expenditures and staffing resources required

for the Pickering extension option are to be submitted through the BPC planning system (BPC) as

part of version W01. Specific “Project Numbers” for the incremental OM&A, capital and provision

expenditures will be setup in BPC. These common “Project Numbers” will be used by the Nuclear

organization, Support Services, and CO&E to identify resources incremental to the base planning

submission. The Nuclear Controller supporting the PECO organization will coordinate the process for

establishing and issuing the specific “Project Numbers” to be used. These “Project Numbers” will be

assigned to a new project group called “PECO”.

Labour supply associated with the Pickering extension option will utilize a specific “Revision Code: SP”

in BPC, which will be created for this purpose, and will be planned using the “7” series JF2 to ensure

that SAVH costs are properly mapped. To identify the incremental staff resources and impact on staff

mix, the PECO organization and the HR Business Partners should be consulted.

Using specific “Project Numbers” and a specific “Revision Code” to plan Pickering extension

resources will permit filtering to remove these resources, as required, allowing the business units to

view their base case business plans. Once planning for the Pickering extension option is complete,

BP&PR will copy version W01 as a separate “Pickering Extension” scenario in BPC. The BPC

Administrator will then remove all the Pickering extension specific “Project Numbers” and the specific

“Revision Code” labour from version W01.

In addition to the BPC submission, the following details should be submitted via the Finance – Business

Planning SharePoint site:

Generation plan impacts and fuel expense

Changes in capitalized interest and in-service additions, the details of which should be in line

with the requirements in section 5.1.1 of the 2016-2018 Business Planning Instructions

Materials and supplies, and fuel inventory

Nuclear decommissioning and waste management fuel expenditures

Summary of changes to the nuclear outage plan.

If you have any questions on this request, please contact myself or Vassa Chase.

_[original signed by:]______________

Alex Kogan

VP Business Planning & Reporting

cc: Beth Summers Allan Webster Andrew Barrett Anthony Melaragno

Laurie Swami Craig Halket Andy Teichman

John Mauti Connie Hergert John McIntee

John Blazanin Stephen Rogers Vassa Chase

Filed: 2016-05-27

EB-2016-0152

Exhibit A2-2-1

Attachment 2

Page 34 of 40

Security

CONFIDENTIAL

MEMORANDUM

August 13, 2015

From: Finance – Business Planning & Reporting

To: Carla Carmichael – VP Nuclear Finance

Hamant Becharbhai – Director Nuclear Controllership

Jenny Ruz – Director Controllership, Support Services

Paul Burke – VP Integrated Revenue Planning

Bill Wilbur – Director Integrated Revenue Planning

Banh Tran – Senior Manager Nuclear Liability

Charanjit Singh – VP Shared Financial Services

Re: Addendum to Memorandum Dated June 23, 2015 on Submission of Information for

Extended Pickering Operations Option

This is an addendum to the memo issued on June 23, 2015 which outlined the submission

requirements for 2016-2018 business planning information on the option to extend Pickering

commercial operations beyond the base case end of life in 2020. The addendum requests additional

information, extends the submission date for the original information request, and updates certain

planning system process steps for submitting the information.

As indicated in the June 23 memo, the current preferred alternative for assessment assumes the end

of extended commercial operations for two Pickering units in 2022 and the remaining four units in

2024. By way of this addendum, the Nuclear organization, Commercial Operations and Environment

(CO&E), Support Services, and certain Finance organizations are asked to submit longer-term

planning information for the period 2019-2021 under the Pickering extension option. In all other

respects, the 2019-2021 information should consistently reflect the base planning assumptions

communicated in the 2016-2018 Business Planning Instructions. The specific information

requirements and submission process for the 2019-2021 information are outlined below.

The initial submission of the requested information for 2019-2021 as well as the information

for 2017-2018 requested in the June 23 memo is required to Finance – Business Planning and

Reporting (BP&R) by September 23, 2015.

Summary regular headcount information for 2017-2021 must be provided to BP&R by

August 31, 2015.

The process and timelines for submitting Darlington refurbishment cost and labour resource

requirements outlined in the 2016-2018 Business Planning Instructions have been expanded to

include requirements to provide information for the 2019-2021 period, as outlined below.

Filed: 2016-05-27

EB-2016-0152

Exhibit A2-2-1

Attachment 2

Page 35 of 40

2 CONFIDENTIAL

2019-2021 Information Requirements

The 2019-2021 cost information must be submitted using the BPC planning system. The specific

information requirements and schedule are summarized in the appendices.

As the requested information may be used in the development of OPG’s future nuclear rate

applications to the OEB, the submissions (including BPC input) must be sufficient to support rate filing

requirements. Otherwise, both labour and non-labour information may be entered into BPC at a

higher level than typically used for the three-year business planning period.

Submissions must separately identify estimated incremental resources (e.g., capital, OM&A,

provision, headcount) and generation impacts for 2019-2021 necessary to extend Pickering

operations. The PECO organization should be consulted for specific instructions to ensure that

identified resources and generation impacts are appropriate.

As previously communicated, impacts of extending Pickering operations beyond the base case end-

of-life assumption are expected to include the following:

Changes in nuclear generation (including additional outage days to perform work necessary

to achieve sufficient confidence in extended operations), and fuel expense

Incremental nuclear OM&A expenses directly necessary to enable extended operations

Additional ongoing nuclear, Support Services and CO&E OM&A expenses that may no longer

be reduced on account of the Pickering end of life in 2020

Additional project OM&A and capital investment

Staffing levels, including potential impact on mix of resources

Changes in materials & supplies and nuclear fuel inventory levels

Reductions in nuclear decommissioning provision expenditures

Changes in used fuel expenses

Darlington Refurbishment

Consistent with the 2016-2018 Business Planning Instructions (section 1.7), the September 23

submission will reflect Darlington refurbishment cost and labour resource requirements for 2019-2021

based on the information presented to the OPG Board of Directors in November 2014. As

communicated in the instructions, information on the final budget and schedule for the Darlington

refurbishment is expected to be submitted to BP&R, Nuclear Finance – Business Planning &

Benchmarking, and Support Services Controllership on October 5, 2015. This information should

cover the period to the end of 2021 and will include updated information on the refurbishment costs

and labour resources that are budgeted by Support Services and CO&E. The September 23 BPC

data load for 2019-2021 must be subsequently updated for the final Darlington refurbishment budget

and schedule.

Costing Assumptions

Labour costs for 2019-2021 will reflect standard labour rates, including payroll burdens, to be loaded

by BP&R into the “Pickering Extension” version of BPC (discussed below). If there is a subsequent

need to change payroll burdens as a result of updated pension and other post-employment benefit

cost projections, the changes will either be incorporated into the detailed labour rates or included at

the BU-leader level. BP&R will communicate further information on any such changes.

Filed: 2016-05-27

EB-2016-0152

Exhibit A2-2-1

Attachment 2

Page 36 of 40

3 CONFIDENTIAL

Full-time equivalent calculations for regular labour costing must use the half-year rule if a regular

headcount is added or removed during the year, unless credible information is available to support a

different assumption.

Non-labour costs for 2019-2021 should reflect known or expected agreements, requirements or

commitments. Where a specific basis is not available, non-labour escalation should be assumed at

2.0% per year for 2019-2021.

Planning assumptions for capitalized interest rates for 2019-2021 are the same as for 2016-2018.

Submission Process for 2017-2021

All 2017-2021 information will be submitted through a separate “Pickering Extension” BPC version,

which will contain planning for years 2017-2021 and include updated standard labour rates for 2019-

2021 as discussed above. (The same labour rates as in BPC version W01 for 2017 and 2018 will

also be reflected in this version.) BPC version W01 will therefore be used only for the 2016

budget.

On August 19, the BPC administrator will copy the existing 2017 and 2018 information from version

W01 to the “Pickering Extension” version. No data should be input for years 2017-2020 in version

W01 after August 18. Once the “Pickering Extension” version is created, all planning for 2017

and 2018 must continue in that version rather than version W01. The BPC administrator will

advise business unit planners when the “Pickering Extension” version is available for planning, which

is currently expected by August 21.

As outlined in the June 23 memo, business units are to use separate “Project Numbers” and

“Revision Code: SP” to identify expenditures and headcounts for 2017-2021 that are incremental to

the base planning assumption of a 2020 Pickering end of life. There have been a few process

updates to the June 23 memo in this regard, namely the requirement to use the “7” series JF2 for

labour no longer applies and a new project group PEXT, instead of PECO, contains the “Project

Numbers” for the incremental OM&A, capital and provision expenditures. Questions regarding the

PEXT project group should be directed to George Turner at 701-4942.

The final BPC load for 2017-2021, reflecting the final submissions of the Pickering extension

option information and the final Darlington refurbishment budget and schedule, must be

completed by late October 2015. The 2017 and 2018 information must be loaded in BPC at a

level of detail in line with the requirements outlined in the 2016-2018 Business Planning

Instructions.

Information requirements outlined in Appendix 1 that are outside of BPC should be submitted via the

Finance – Business Planning SharePoint site, using the same process and format as for the 2016-

2018 planning information. The impact of the Pickering extension option on that information should

be separately identified.

Filed: 2016-05-27

EB-2016-0152

Exhibit A2-2-1

Attachment 2

Page 37 of 40

4 CONFIDENTIAL

Generation Plan

CO&E – Integrated Revenue Planning is responsible for submitting to BP&R the initial 2017-2021

nuclear energy production and revenue plan under the Pickering extension option by

September 23, 2015. The impact of extending Pickering operations should be separately identified.

CO&E – Integrated Revenue Planning may contact business units directly with their information

requirements.

For greater clarity, submission dates, requirements and processes for 2016 budget information are

not affected by this memorandum.

If you have any questions on this request, please contact myself or Vassa Chase.

_[original signed by:]______________

Alex Kogan

VP Business Planning & Reporting

cc: Beth Summers Allan Webster Andrew Barrett Anthony Melaragno

Laurie Swami Craig Halket Andy Teichman Don Brazier/George Turner

John Mauti Connie Hergert John McIntee Colin Anderson

John Blazanin Stephen Rogers Vassa Chase Xin Wang

Filed: 2016-05-27

EB-2016-0152

Exhibit A2-2-1

Attachment 2

Page 38 of 40

5 CONFIDENTIAL

Appendix 1

2019-2021 Information Submission Requirements and Accountabilities

Nuclear Generation Revenue and Gross Margin (including a summary nuclear outage plan by facility)

CO&E – Integrated Revenue Planning

Nuclear Non-Generation Revenue & Cost of Goods Sold (isotope sales, heavy water sales, detritiation services, Bruce lease rent and L&ILW services)

CO&E – Commercial Contracts & Power Marketing

Nuclear Non-Generation Revenue & Cost of Goods Sold (e.g., engineering services, investment recovery)

Nuclear

Headcount and OM&A Expenses

(by base, project, outage and by site/plant/organization;

regular and non-regular headcount and costs separated)

Operating Business Units and Support Services

Capital Expenditures (including MFA)

Capitalized interest shown separately

In-Service Additions and Retirements/Write-Offs

Quarterly information for all years, where available

Monthly detail required where a single in-service

addition/retirement is at least $50M

Operating Business Units and Support Services for sustaining capital and projects in execution phase Corporate Business Development for new projects and projects not yet in execution

Darlington Refurbishment Cost Flows (Capital

and OM&A) and In-Service Additions

Monthly detail for all in-service additions

Nuclear

Nuclear Waste and Nuclear Decommissioning

Provision Drawdowns

(by program from p. 18 of 2016-2018 Business Planning

Instructions, and per section 5.1 of those instructions)

Operating Business Units and Support Services

Balance Sheet – Materials & Supplies Inventory Nuclear

Balance Sheet – Nuclear Fuel Inventory Finance – Support Services Controllership to coordinate with BAS – Supply Chain

Legal, Environmental and Other Provisions –

Expenses and Cash Payments Operating Business Units, Support Services, and Finance – Shared Financial Services

Insurance Finance – Support Services Controllership to coordinate with Finance – Treasury

Property Taxes Finance – BP&R to coordinate with BAS – Real Estate & Services

Stakeholder Return Program Costs P&C – Total Rewards & Solutions Centre

Vacation Accrual & Fiscal Calendar Adjustment Finance – Shared Financial Services

Depreciation & Amortization

(based on current net book values and asset class/station

lives, adjusted for changes expected from this year’s DRC)

Finance – Shared Financial Services

Nuclear Segregated Fund and Liability Inputs,

and ONFA Guarantee Fee Finance – BP&R

Pension and OPEB Information, and Pension

Guarantee Fee Finance – BP&R

Filed: 2016-05-27

EB-2016-0152

Exhibit A2-2-1

Attachment 2

Page 39 of 40

6 CONFIDENTIAL

Appendix 2 Summary Schedule

DATE ACTIVITY

August 18 Last day to input data for years 2017-2020 into version W01 of the BPC planning system

August 19 BPC administrator creates “Pickering Extension” version in BPC

August 31 Regular headcount under the Pickering extension option is provided to Finance – BP&R, at a summary level, for the Nuclear organization, CO&E and Support Services

September 23 Initial submission of 2017-2021 information provided to BP&R through BPC and Finance – Business Planning SharePoint site

October 5 Submission of 2017-2021 planning information on the updated Darlington refurbishment budget and schedule to BP&R, Nuclear Finance – Business Planning & Benchmarking, and Support Services Controllership

Late October Final BPC submission for 2017-2021, reflecting the final submission of the Pickering Extension option and the final Darlington refurbishment budget and schedule, is completed

Filed: 2016-05-27

EB-2016-0152

Exhibit A2-2-1

Attachment 2

Page 40 of 40

Filed: 2016-05-27 EB-2016-0152

Exhibit A2 Tab 2

Schedule 1 Attachment 3

Page 1 of 3

BUSINESS PLANNING AND BUDGETING 1

PROCESS OVERVIEW 2

3

OPG’s business planning and budgeting process is largely unchanged from that filed in EB-4

2013-0321. 5

6

OPG’s business planning and budgeting process is a decentralized annual process 7

undertaken within a consistent, corporately-developed, top-down framework of strategic 8

objectives, resource guidelines, and costing assumptions. The key elements of this corporate 9

framework are formally identified to the business units through business planning instructions 10

provided by Finance. Within this framework, the individual business units develop their 11

specific strategic and performance objectives, and then identify and plan the work required to 12

achieve these objectives. 13

14

Throughout the business planning process, business planning communications are delivered 15

primarily through the business planning instructions issued in the second quarter. The key 16

elements of the business planning process are outlined below. 17

18

Communication of the strategic planning context, resource targets and asset/ project 19

strategy. 20

The identification of key operating, economic and other planning assumptions to be 21

used in development and costing of plans, including: 22

o Forecast rates for labour costing 23

o Interest rate forecasts 24

o Schedules and assumptions regarding major generation development projects 25

o Establishment and communication of information submission requirements and 26

business planning schedules including key timelines, milestones and activities 27

o Development of a consolidated revenue, sales and production forecast by 28

OPG’s Integrated Revenue Planning Group. This forecast incorporates key 29

Filed: 2016-05-27 EB-2016-0152 Exhibit A2 Tab 2 Schedule 1 Attachment 3 Page 2 of 3

production and reliability parameters from the nuclear and hydroelectric 1

business units. 2

o Development of business plans by individual business units using staff levels, 3

OM&A and capital expenditures as primary financial planning metrics. Each 4

business unit also identifies key risks to forecast results, and mitigation 5

initiatives. 6

The preparation of a consolidated financial outlook by Finance, based on inputs 7

received from across the organization. Business units provide their planned OM&A, 8

capital and provision-funded expenditures. Finance develops a comprehensive 9

financial outlook by supplementing this information with other elements including: 10

o A forecast depreciation expense based on existing assets and forecasts of new 11

additions to the asset base 12

o A forecast of regulatory variance and deferral accounts and their amortization 13

o A forecast of borrowing requirements and associated financing costs. 14

o A forecast of impacts of nuclear waste management and decommissioning 15

liabilities and associated segregated funds 16

o Income taxes payable. 17

Depending on the operational and/or financial issues facing OPG at the time, 18

alternative planning scenarios may be identified and modelled once the base case 19

forecast has been established.1 20

Individual business unit plans are reviewed with the President and Chief Executive 21

Officer (“CEO”) and the Chief Financial Officer (“CFO”) through a series of briefings 22

and presentations, typically in the fall.2 Business units incorporate feedback and 23

redirection from these sessions into updated submissions. 24

1 As discussed in Ex. A2-2-1, with the continued analysis of the prospect for pursuing Pickering

Extended Operations, this scenario was maintained in detail during the 2016-2018 business planning cycle until the decision was made to consider Extended Operations as the planning base case. 2 Due to the timing of the Pickering Extended Operations approval, by OPG’s Board of Directors in

November 2015 and as announced by the Province in January 2016, these reviews took place throughout the fall of 2015 and into early 2016 as part of the 2016-2018 business planning cycle.

Filed: 2016-05-27 EB-2016-0152

Exhibit A2 Tab 2

Schedule 1 Attachment 3

Page 3 of 3

The draft consolidated business plan, based on the updated submissions, is reviewed 1

by OPG’s CEO, CFO and other members of the executive-level Enterprise Leadership 2

Team. The plan is also reviewed with shareholder’s representatives. 3

The final consolidated plan is submitted for approval to OPG’s Board of Directors.3 4

Formal concurrence with the OPG Board-approved plan is required from the Province 5

in accordance with the Memorandum of Agreement. 6

3 Final Board of Directors’ approval of the 2016-2018 Business Plan took place in May 2016

Filed: 2016-05-27 EB-2016-0152

Exhibit A2 Tab 2

Schedule 1 Attachment 4

Page 1 of 4

ASSET MANAGEMENT AND PROJECT REVIEW PROCESSES 1

2

OPG’s asset management and project review processes are largely unchanged from EB-3

2013-0321. Their description is provided for reference. 4

5

1.0 ASSET MANAGEMENT 6

OPG’s investments and initiatives are targeted at programs that will result in increased 7

generating capacity, extended service lives, improved performance, and reduced long-term 8

operations and maintenance costs. 9

10

In addition to improving performance of its existing assets, OPG also evaluates development 11

initiatives with respect to its regulated facilities which can include plant life extensions, plant 12

redevelopments or new supply developments. These development initiatives are typically 13

larger in size, have higher risk profiles and longer time horizons than the projects held within 14

the business unit portfolios. These potential investments are subject to more rigorous internal 15

evaluations and scrutiny during the approval process. 16

17

2.0 PROJECT PORTFOLIOS AND SUPPORTING DOCUMENTATION 18

As part of the business planning process, business units submit project lists that have been 19

prioritized to maximize value and address regulatory requirements while considering risks, 20

corporate business objectives, asset management processes, and funding guidelines. All 21

known projects necessary to meet work program requirements and having cash flows within 22

the business plan time horizon are listed, with the total cost of the projects being consistent 23

with the funding guidelines. 24

25

The project list is a snapshot of the project work intended to be done over the business plan 26

horizon. As time progresses, priorities may be re-set and the project list may change as 27

dictated by the needs of the business. Details regarding the prioritization process are provided 28

later in this schedule. 29

30

Filed: 2016-05-27 EB-2016-0152 Exhibit A2 Tab 2 Schedule 1 Attachment 4 Page 2 of 4

2.1 Planning Business Cases 1

“Planning” business cases, or project screening forms in nuclear, are produced for qualifying 2

projects that are planned for release within the plan period. Inclusion of a project in the 3

business plan does not constitute approval to proceed with the project. Request for project 4

approval and release of funds to commence work on a project is a separate process and 5

requires a more comprehensive business case summary (“BCS”). Business case 6

requirements for project release are discussed later in this schedule. Planning business cases 7

are a preliminary and usually more condensed version of the full BCS. 8

9

2.2 Project Categorization 10

Investments must also be categorized according to the type of benefit they are expected to 11

produce. Investments fall within the following three categories established by OPG: 12

Value Enhancing – Discretionary investments that promise value creation or strategic 13

opportunities, such as added revenues, reduced costs, increased efficiencies, or new 14

business opportunities. 15

Regulatory – Expenditures required to satisfy environmental, safety or other 16

requirements in law or regulation to allow the continued operation of existing facilities. 17

Sustaining – Required to maintain existing infrastructure and facilities at their current 18

performance level. 19

20

2.3 Project Prioritization Process 21

As the business units compile their project lists, the total cost of all initially identified work may 22

exceed funding guidelines and/or the business unit’s capacity to undertake the work during 23

the planning period. Prioritization processes are then applied to assist with the selection of the 24

highest priority projects while remaining within the funding guidelines and resource 25

capabilities. Since business units manage different assets, prioritization approaches are also 26

unique to each business unit. However, business unit prioritization approaches have common 27

elements such as value, consideration of risks, and regulatory compliance. The approach for 28

nuclear projects is presented in Ex. D2-1-1. 29

30

Filed: 2016-05-27 EB-2016-0152

Exhibit A2 Tab 2

Schedule 1 Attachment 4

Page 3 of 4

3.0 BUSINESS CASE REQUIREMENTS FOR PROJECT RELEASE 1

Approval is required for the release of funds to undertake project work. The documentation for 2

seeking approval is a BCS, which provides an explanation of the need and the business 3

opportunity, along with an analysis of feasible alternatives for meeting this need and the 4

rationale for the recommended alternative. 5

6

Requests for releases of funds are approved in accordance with the OPG Organizational 7

Authority Register (“OAR”). The OAR sets out delegated authorities within OPG, and defines 8

approval limits for decisions made on behalf of the corporation. Approval requirements are 9

based on the cumulative amount of funds being released, with more restrictive requirements 10

for projects of a strategic nature or unplanned work (projects not identified in the project 11

portfolio during business planning). The OAR also specifies authorities for approval of over-12

variances for previously released projects, and for superseding releases where projects must 13

be reconsidered due to significant scope, schedule or cost changes. 14

15

Functional reviews of BCSs are also carried out to ensure that they meet the criteria for the 16

quality and completeness of the information required to enable an informed decision on 17

approval of the project release. The functional review is required where there is a significant 18

impact on the function or its deliverables. For example: 19

Projects with substantial IT requirements are reviewed by the relevant IT Department. 20

Projects with significant legal or contractual issues are reviewed by Law Division. 21

Projects involving real estate transactions or leasing of office spaces are reviewed by 22

Real Estate Services. 23

Projects with significant labour relations or health and safety issues are reviewed by 24

People and Culture. 25

26

4.0 POST IMPLEMENTATION REVIEW PROCESS 27

The post implementation review (“PIR”) process is used by OPG to assess achievements 28

following completion of projects. Specifically, a PIR is an appraisal process designed to 29

evaluate whether planned results of a given investment have been met following project 30

Filed: 2016-05-27 EB-2016-0152 Exhibit A2 Tab 2 Schedule 1 Attachment 4 Page 4 of 4

completion. The two main objectives of the PIR process are to verify whether the benefits 1

stated in the project business case were realized, and to capture the lessons learned from 2

each project so that they can be applied to improve future projects and investment decisions. 3

4

Post implementation reviews follow a simplified or comprehensive format depending on the 5

size and scope of the investment involved. All projects must have a PIR completed as 6

specified in the PIR plan, ideally within twelve months of the project being completed. 7

8

OPG selects a number of complex or high value projects to undergo a comprehensive PIR 9

within each business planning period. A comprehensive PIR is an independent and broad 10

review of a completed project. It is an intensive exercise requiring a multi-disciplinary team, 11

ideally independent from the project team, to review all phases of a project. It provides 12

detailed feedback on how the project was developed, planned, and executed to help gather 13

lessons for future investments. It is only performed on a small number of projects due to the 14

high resource requirements. 15