Document:

EX-4.1

 Exhibit 4.1 

 
 

 
  
 ANNUAL
INFORMATION FORM For the Year Ended December 31, 2012 [Graphic Appears Here] 

 TABLE OF CONTENTS 

 

 TABLE OF CONTENTS 

 

			
	    2	 	         DEFINITIONS

		
	    5	 	         CORPORATE STRUCTURE

		
	    7	 	         FORWARD-LOOKING INFORMATION

		
	  13	 	         ABOUT HYDRO ONE

	  13	 	         Our Mission and Vision

	  13	 	         Our Strategy

		
	  17	 	         GENERAL DEVELOPMENT OF THE BUSINESS

	  17	 	         Electricity Sector Landscape

	  17	 	                 OPA

	  17	 	                 OEB

	  17	 	                 IESO

	  18	 	         Recent Industry Activity

	  18	 	                 Distribution Sector
Consolidation

	  18	 	                 Regulated Price Plan
Structure

	  20	 	                 Ontario Clean Energy Benefit
Act

	  20	 	                 Procurement of New
Generation

	  21	 	         Recent Developments at Hydro One

	  21	 	                 New President and Chief Executive
Officer and Organizational Realignment

	  21	 	                 Hydro One and Society Reach
Tentative Settlement

		
	  23	 	         OVERVIEW OF HYDRO ONE

		
	  25	 	         DESCRIPTION OF THE BUSINESS

	  25	 	         Our Business Segments

	  25	 	                 Our Transmission
Business

	  25	 	                 Overview

	  26	 	                 Transmission
Planning

	  26	 	                 Transmission
Assets

	  26	 	
                    Transmission
Stations

	  27	 	
                    Transmission
Lines

	  27	 	                     Network
Operations

	  28	 	
                    Telecommunications
Facilities

	  29	 	                 Transmission Capital Expenditure
Plans

	  29	 	                     Major
Transmission Capital Development Projects

	  32	 	
                    Transmission Projects at
the Local Load Connections Level

	  32	 	
                    Transmission
Sustainment

	  32	 	                 Projects Relating to
Interconnection

	  32	 	
                    
Michigan

  
 2012 ANNUAL
INFORMATION FORM  i 

 TABLE OF CONTENTS 

 

			
	  32	 	                 NERC/NPCC

	  33	 	                 NERC Critical Infrastructure
Protection Standards

	  34	 	                 Our Distribution
Business

	  34	 	                 Distribution Capital Expenditure
Plans

	  35	 	                 Distribution
Assets

	  35	 	                 Remote
Communities

	  36	 	                 Conservation and Demand
Management

	  37	 	                 Advanced Distribution
System

	  38	 	                 Smart Meters

	  39	 	                 Our Telecommunications
Business

	  39	 	                 Other Business
Particulars

	  39	 	                 Employees

	  40	 	                 Compensation

	  41	 	                 Pension Plan

	  41	 	                 Outsourcing Arrangement with
Inergi LP

	  42	 	
                Environmental

	  42	 	                     Health,
Safety and Environmental Management System

	  42	 	                     Permits
and Approvals

	  43	 	
                    Regulation of
Releases

	  43	 	                     Hazardous
Substances

	  43	 	
                        
PCB

	  44	 	
                        
Asbestos

	  44	 	
                        
Herbicides

	  44	 	
                        
Wood Preservatives

	  44	 	                 Land Assessment and
Remediation

	  45	 	                 Electric and Magnetic
Fields

	  46	 	                 Health and
Safety

	  46	 	
                Insurance

	  47	 	                 Legal Proceedings and
Regulatory Actions

	  47	 	
                Financial

	  48	 	         Developments at Hydro One

	  48	 	                 Electricity Transfer Tax
Exemption

	  48	 	                 Cornerstone

		
	  51	 	         REGULATION

	  51	 	         The Statutory and Operating Framework

	  51	 	                 General

	  52	 	         Contractual Arrangements, Codes and Licences

	  52	 	                 Operating Agreement with the
IESO

	  52	 	                 Hydro One’s Relationships
with Other Market Participants

	  52	 	                 Electricity Industry
Codes

	  52	 	                 Electricity Industry
Licences

	  53	 	         Rate Orders and Related Issues for Hydro One’s
Businesses

	  53	 	                 Transmission

  
 ii  HYDRO ONE INC.

 TABLE OF CONTENTS 

 

			
	  53	 	                     Current
Rate Orders and Review of the Existing Transmission Rate Structure

	  54	 	
                    Bypass

	  54	 	
                        
Competition

	  55	 	
                        
Facilities Applications

	  56	 	
                        
Connection Cost Responsibility and Enabler Lines

	  56	 	                 Distribution

	  56	 	                     Current
Rate Orders and Distribution Rate Structure

	  56	 	
                        
Hydro One Networks Inc.

	  57	 	
                        
Hydro One Brampton Networks Inc.

	  57	 	
                        
Hydro One Remote Communities Inc.

	  58	 	                     Rural and
Remote Rate Protection

	  58	 	                     Rate
Protection and Determination of Direct Benefits to Accommodate

	  59	 	
                    Connection Cost
Responsibility

	  59	 	
                    Distribution System Code
Exemption

		
	  61	 	         RISK FACTORS

	  61	 	         Ownership by the Province

	  61	 	         Regulatory Risk

	  62	 	         Risk Associated with Arranging Debt Financing

	  62	 	         Risk Associated with Transmission Projects

	  63	 	         Asset Condition

	  63	 	         Work Force Demographic Risk

	  63	 	         Environmental Risk

	  65	 	         Risk of Natural and Other Unexpected Occurrences

	  65	 	         Risk Associated with Information Technology
Infrastructure

	  66	 	         Pension Plan Risk

	  66	 	         Market and Credit Risk

	  67	 	         Labour Relations Risk

	  67	 	         First Nation and Métis Claims Risk

	  67	 	         Risk from Transfer of Assets Located on Reserves

	  68	 	         Risk Associated with Outsourcing Arrangement

	  68	 	         Risk from Provincial Ownership of Transmission
Corridors

		
	  69	 	         DIVIDENDS

		
	  70	 	         DESCRIPTION OF CAPITAL STRUCTURE

		
	  71	 	         CREDIT RATINGS OF SECURITIES AND LIQUIDITY

		
	  72	 	         MARKET FOR SECURITIES

		
	  73	 	         DIRECTORS AND OFFICERS

	  73	 	         Directors

	  73	 	                 Name and Municipality of
Residence

	  79	 	         Information Regarding Certain Directors

  
 2012 ANNUAL
INFORMATION FORM  iii 

 TABLE OF CONTENTS 

 

			
	  80	 	         Executive Officers

	  80	 	                 Name and Municipality of
Residence

	  84	 	         Indebtedness of Directors and Executive Officers

		
	  85	 	         INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL
TRANSACTIONS

	  85	 	         Relationships with the Province and Other Parties

	  85	 	                 Overview

	  85	 	                 Transfer
Orders

	  86	 	                 Indemnities

	  87	 	                 Operational
Matters

	  87	 	                 Payments in Lieu of Corporate
Taxes

	  87	 	                 Memorandum of
Agreement

		
	  89	 	         TRUSTEES AND REGISTRARS

		
	  90	 	         MATERIAL CONTRACTS

		
	  93	 	         INTERESTS OF EXPERTS

		
	  94	 	         ADDITIONAL INFORMATION

		
	  95	 	         STATEMENT OF EXECUTIVE COMPENSATION

	  95	 	         Compensation Discussion and Analysis

	  95	 	                 Overview

	  96	 	         Governance

	  97	 	                 Composition of the
HRC

	  97	 	                 Committee Members Relevant and
Direct Experience

	  98	 	                 Compensation Policies and
Practices Aligned to Risk Management

	  99	 	                 Independent Consultant for the
HRC

		
	100	 	         ELEMENTS OF COMPENSATION

	101	 	         Base Salary

	102	 	         Performance-Based Compensation

	102	 	                 Fund
Determination

	103	 	                 Fund
Allocation

	103	 	                     Corporate
Performance Measures and Targets

	105	 	
                        
Productivity

	105	 	
                        
Reliability of Transmission and Distribution

	106	 	
                        
Customer Satisfaction

	106	 	
                        
Employee Engagement

	106	 	
                        
Shareholder Value

	106	 	
                        
Safety: Injury Free Workplace

	106	 	                 Overall Performance for
2012

	107	 	
                    Individual
Performance

  
 iv  HYDRO ONE INC.

 TABLE OF CONTENTS 

 

			
	109	 	                 Benefits

	110	 	                 Role of NEOs in Determining
Executive Compensation

		
	111	 	         SUMMARY COMPENSATION TABLE

	113	 	         Pension Plan Benefits

	113	 	                 Defined Benefit Pension
Plan

	115	 	         Termination and Change of Control Benefits

	117	 	         Director Compensation

	117	 	                 Director Compensation
Table

		
	118	 	         APPOINTMENT OF AUDITOR

		
	119	 	         AUDIT AND FINANCE COMMITTEE INFORMATION

	119	 	         The Audit and Finance Committee’s Charter

	119	 	         Composition of the Audit and Finance Committee

	119	 	         Relevant Education and Experience

	120	 	         Audit and Finance Committee Oversight

	120	 	         Pre-Approval Policies and Procedures

	121	 	         External Auditor Service Fees

		
	122	 	         CORPORATE GOVERNANCE DISCLOSURE

	122	 	         Board of Directors

	123	 	         Summary of Attendance of Directors

	124	 	         Director’s Board Memberships in Other Reporting Issuers

	124	 	         Board Mandate

	124	 	         Position Descriptions

	124	 	         Committees of the Board of Directors

	124	 	                 Audit and Finance
Committee

	124	 	                 Business Transformation
Committee

	125	 	                 Corporate Governance
Committee

	125	 	                 Health, Safety and Environment
Committee

	125	 	                 Human Resources
Committee

	125	 	                 Investment-Pension
Committee

	125	 	                 Regulatory and Public Policy
Committee

	126	 	         Orientation and Continuing Education

	126	 	         Ethical Business Conduct

	127	 	         Board, Committee and Director Assessments

		
	128	 	         APPENDIX “A” AUDIT AND FINANCE COMMITTEE
MANDATE

		
	134	 	         APPENDIX “B” HYDRO ONE INC. BOARD OF DIRECTORS
MANDATE

		
	137	 	         APPENDIX “C” HYDRO ONE TRANSMISSION AND DISTRIBUTION
LICENCES

  
 2012 ANNUAL
INFORMATION FORM  v 

 Except where otherwise indicated, all information presented herein is as at December 31,
2012. 

  
 vi  HYDRO ONE INC.

 

 

 DEFINITIONS 
  

 For convenience, in this Annual Information Form: 

“ADS” means this Advanced Distribution System; 
 “AIF” means this Annual Information Form; 
 “Board” means the
Board of Directors of Hydro One Inc.; 
 “Canadian GAAP” means Canadian Generally Accepted Accounting Principles per Part V of
the Canadian Institute of Chartered Accountants Handbook; 
 “CDM” means conservation and demand management; 

“CDM Code” means the CDM Code for Electricity Distributors; 
 “DS” refers to a distribution station; 
 “DSC” means the
Distribution System Code; 
 “EA” means the Environmental Assessment Act (Ontario); 

“Electricity Act” means the Electricity Act, 1998, as amended; 
 “ETS” means Export Transmission Service; 
 “FERC” means
the Federal Energy Regulatory Commission; 
 “First Nation” means a band as that term is defined in the Indian Act
(Canada); 
 “FIT” means the feed-in-tariff program of the OPA; 
 “GEA” means the Green Energy and Green Economy Act, 2009; 

“GTA” means the Greater Toronto Area; 
 “Hydro One”, “our company”, “we”, “us”, “our”, and “the company” refer to Hydro One Inc. and its
subsidiaries and predecessors, except where the context requires otherwise; 
 “IESO” refers to the Independent Electricity
System Operator, previously named the Independent Electricity Market Operator; 
 “IASB” refers to the International Accounting
Standards Board; 
 “IFRS” means International Financial Reporting Standards; 

“Intertie” means a transmission facility that physically connects adjacent transmission systems in different jurisdictions (e.g.
provinces or countries) for the purpose of electrical power transfers; 
 “IPSP” means the Integrated Power System Plan
developed by the OPA; 
 “IRM” means Incentive Regulation Mechanism; 
 “IT” means Information Technology; 
 “LDC” means local
distribution company; 
 “LTEP” means “Ontario’s Long Term Energy Plan, Building Our Clean Energy Future”,
announced by the Province on November 23, 2010; 

  
 2  HYDRO ONE INC.

 DEFINITIONS 

 

 “LRAM” means Lost Revenue Adjustment Mechanism; 

“LRAMVA” means Lost Revenue Adjustment Mechanism Variance Account; 
 “Market Rules” means the rules made under Section 32 of the Electricity Act that are administered by the IESO; 
 “Micro FIT” means the micro feed-in-tariff program of the OPA; 

“Ministry” or “Minister” means the Ministry of Energy or the Ministry of Energy and Infrastructure and, as applicable,
its respective Minister; 
 “NERC” means the North American Electric Reliability Corporation; 

“NPCC” means the Northeast Power Coordinating Council Inc. 
 “OEB” refers to the Ontario Energy Board; 
 “OEB Act”
means the Ontario Energy Board Act 1998, as amended; 
 “OEFC” means the Ontario Electricity Financial Corporation;

 “OGCC” means Hydro One’s Ontario Grid Control Centre located north of Toronto, Ontario; 

“OHSAS18001” means Occupational Health and Safety Assessment Series 18001 standard; 

“Ontario” refers to the Province of Ontario as a geographical area; 
 “OM&A” means Operations, Maintenance and Administration; 

“OPA” refers to the Ontario Power Authority; 
 “OPG” refers to Ontario Power Generation Inc.; 
 “Open Access”
refers to the opening of Ontario’s wholesale and retail electricity markets to competition which officially occurred on May 1, 2002; 

“OSC” means the Ontario Securities Commission; 
 “PCB” means polychlorinated biphenyls; 
 “Province” refers to
the Government of the Province of Ontario; 
 “PWU” refers to the Power Workers’ Union; 

“Reserve” means a “reserve” as that term is defined in the Indian Act (Canada); 

“ROE” refers to return on equity; 
 “RPP” refers to the regulated price plan structure for the cost of electricity supplied to low volume and designated customers; 
 “Society” refers to the Society of Energy Professionals; 
 “SS”
refers to a switching station; 
 “TOU” refers to “time-of-use” rates; 

“TS” refers to a transformer station; and 
 “U.S. GAAP” means United States Generally Accepted Accounting Principles. 

  

 CORPORATE STRUCTURE 

 
 

 

  
 4  HYDRO ONE INC.

 CORPORATE STRUCTURE 

 

 CORPORATE STRUCTURE 
 Hydro One Inc. was incorporated as Ontario Hydro Services Company Inc. by Articles of Incorporation dated December 1, 1998 under the Business Corporations Act (Ontario). On May 1, 2000,
we changed our name to Hydro One Inc. 
 Our registered office and head office is located at 483 Bay Street, 15th Floor, North Tower, Toronto,
Ontario, M5G 2P5. 
 The following are our principal subsidiaries, each of which is wholly-owned by us and is incorporated under the laws of
Ontario: 
  

	•	 	 Hydro One Networks Inc. – carries on all business relating to our ownership, operation and management of electricity transmission and
distribution systems and facilities; 

  

	•	 	 Hydro One Brampton Networks Inc. – carries on the business relating to our ownership, operation and management of electricity distribution
systems and facilities in Brampton, Ontario; 

  

	•	 	 Hydro One Remote Communities Inc. – carries on all business relating to our ownership, operation, maintenance and construction of
generation and distribution assets used in the supply of electricity to remote communities throughout Northern Ontario; and 

  

	•	 	 Hydro One Telecom Inc. – carries on all of our business relating to leasing dark fibre and providing lit telecommunications capacity to
other telecommunication carriers, large corporations, government, healthcare, and education institutions. 

  
 2012 ANNUAL
INFORMATION FORM  5 

 FORWARD-LOOKING INFORMATION 
  
 

 

  
 6  HYDRO ONE INC.

 FORWARD-LOOKING INFORMATION 
  

 FORWARD-LOOKING INFORMATION 
 This AIF contains, and Hydro One’s oral and written public communications often contain, forward-looking statements that are based on current expectations, estimates, forecasts and projections about
the business of Hydro One and the industry in which Hydro One operates and includes beliefs and assumptions made by the management of our company. 
 This AIF contains, and Hydro One’s oral and written public communications often contain, forward-looking statements that are based on current expectations, estimates, forecasts and projections about
the business of Hydro One and the industry in which Hydro One operates and includes beliefs and assumptions made by the management of our company. Such statements include, but are not limited to, statements about the general development of our
business; statements about distribution sector consolidation; statements related to the OEB’s RPP and TOU pricing; expectations regarding the exemption of TOU pricing for rural customers and the timeline for converting those customers to TOU
pricing; statements related to the GEA and our Green Energy Plan, the Ontario Clean Energy Benefit Act, the IPSP and the Ministry’s LTEP and Supply Mix Directive including the additional investments arising therefrom, and our ability to recover
the costs of such investments; statements related to the FIT program; statements about smart meters including their capabilities, costs and cost recovery; statements related to the buildout of an ADS for our distribution business, including future
investments and the recoverability of those investments; expectations regarding the Cornerstone project; the expected impact of CDM programs and targets including funding expectations and the impact of LRAM; statements related to U.S. GAAP and our
adoption of U.S. GAAP; expectations regarding connections of new generation to our transmission and distribution systems, including their cost and impact on our systems; expectations regarding future renewable energy generation, including the
possibility of incurring capital expenditures related thereto; statements about our strategy, including our strategic objectives; statements regarding future capital expenditures and our capital development and other investment plans; statements
regarding the reliability of our distribution and transmission systems including equipment performance; statements about our transmission capacity; expectations regarding load growth and new generation; statements regarding our current and future
capital projects including expected benefits, completion dates and our ability to recover the costs related to such projects and to obtain environmental and other regulatory approvals in connection therewith; statements about our ongoing initiatives
including the expected results and their completion dates; expectations regarding NERC standards, the cost impact of their adoption, and possible recovery of these costs in rates; statements related to the attraction and retention of staff and the
maintenance and development of the skills and competence of existing employees; statements about our outsourcing arrangement with Inergi LP; expectations regarding environmental expenditures and other environmental matters including the expected
work and costs of compliance with PCB regulations, potential future costs related to asbestos, herbicide and land assessment and remediation, our ability to recover 

  
 2012 ANNUAL
INFORMATION FORM  7 

 FORWARD-LOOKING INFORMATION 

 

 
such costs and the need for environmental approvals and assessments; statements regarding the OEB’s plan for a renewed regulatory framework for electricity; statements related to revenue
decoupling; expectations regarding our operating agreement with the IESO; statements regarding our transmission and distribution rates and customer bills resulting from our rate applications; statements related to the East-West Tie Line project;
statements related to our connection assets including recovery of costs related thereto; expectations regarding developments in the statutory and operating framework for electricity distribution and transmission in Ontario including changes to
rates, rate orders, cost recovery, rates of return and rate structures in both our transmission and distribution businesses; expectations regarding the recoverability of our expenditures in future rates and the effects it may have; statements
related to the filing and status of our applications to the OEB and the timing of decisions from the OEB; statements relating to our relationship with the Province, including the possibility of the Province making declarations pursuant to our
memorandum of agreement with them; expectations regarding workforce demographics; statements regarding our borrowing requirements; the estimated impact of changes in the forecasted long-term Government of Canada bond yield (used in determining our
regulated rate of return) on our net income; expectations regarding anticipated expenditures associated with transferring assets located on Reserves; statements regarding provincial ownership of our transmission corridors; statements regarding
future pension contributions and our pension plan; our expectation regarding our need for the OEFC indemnity associated with the original transfer orders; expectations regarding implementation of health and safety programs; statements regarding
labour relations; and legal proceedings in which we are currently involved. Words such as “aim”, “could”, “would”, “expect,” “anticipate,” “intend,” “attempt,” “may,”
“plan,” “will,” “believe,” “seek,” “estimate,” and variations of such words and similar expressions are intended to identify such forward-looking statements. These statements are not guarantees of
future performance and involve assumptions and risks and uncertainties that are difficult to predict. Therefore, actual outcomes and results may differ materially from what is expressed, implied or forecasted in such forward-looking statements.
Hydro One does not intend, and Hydro One disclaims any obligation to update any forward-looking statements, except as required by law. 
 These
forward-looking statements are based on a variety of factors and assumptions including, but not limited to: no unforeseen changes in the legislative and operating framework for Ontario’s electricity market; favourable decisions from the OEB and
other regulatory bodies concerning outstanding rate and other applications; no delays in obtaining the required approvals; no unforeseen changes in rate orders or rate structures for our distribution and transmission businesses; no unfavourable
changes in environmental regulation; satisfactory resolution of the issue of rate regulated accounting by adoption and application of U.S. GAAP; a stable regulatory environment; and no significant event occurring outside the ordinary course of
business. These assumptions are based on information currently available to Hydro One including information obtained by Hydro One from third-party sources. Actual results may differ materially from those predicted by such forward-looking statements.
While Hydro One does not know what impact any of these differences may have, its business, results of operations, financial condition and its credit stability may be materially adversely affected. 

  
 8  HYDRO ONE INC.

 FORWARD-LOOKING INFORMATION 
  

 Factors that could cause actual results or outcomes to differ materially from the results expressed or
implied by forward-looking statements include, among other things: 
  

	•	 	 the risks associated with being controlled by the Province including the possibility that the Province may make declarations pursuant to our memorandum
of agreement with it, as well as potential conflicts of interest that may arise between us, the Province and related parties; 

  

	•	 	 opposition to and delays or denials of the requisite approvals and accommodations for projects necessary to increase transmission and distribution
capacity; 

  

	•	 	 the risk that previously granted regulatory approvals may be subsequently challenged, appealed or overturned; 

 

	•	 	 the risk that unexpected capital expenditures may be needed to support renewable generation or resolve unforeseen technical issues;

  

	•	 	 the risks related to our work force demographic and our potential inability to attract and retain qualified personnel; 

 

	•	 	 the risks associated with the execution of our capital and maintenance programs necessary to maintain the performance of our aging asset base;

  

	•	 	 the risk that we will be unable to source the materials necessary to support our work programs; 

 

	•	 	 the risks associated with being subject to extensive regulation including risks associated with OEB action or inaction; 

 

	•	 	 the timing and results of regulatory decisions regarding our revenue requirements, cost recovery and rates; 

 

	•	 	 the risk that load or consumption could fall below projected levels; 

 

	•	 	 unanticipated changes in our costs; 

  

	•	 	 the risks of counter-party default on our outstanding derivative contracts; 

 

	•	 	 the risks associated with changes in interest rates or discount rates; 

 

	•	 	 the risks associated with changes in the forecast long-term Government of Canada bond yield; 

 

	•	 	 the risk that we are not able to arrange sufficient cost effective financing to repay maturing debt and to fund capital expenditures and other
obligations; 

  

	•	 	 the potential impact of not being able to recover our pension costs; 

 

	•	 	 future interest rates, investment returns, changes in benefits and changes in actuarial assumptions; 

 

	•	 	 the risk to our facilities posed by severe weather conditions, natural disasters or catastrophic events and our limited insurance coverage for losses
resulting from these events; 

  

	•	 	 the risk that we may incur significant costs associated with transferring assets located on Reserves; 

 

	•	 	 the risks associated with information system security, with maintaining a complex information technology system infrastructure, and with transitioning
most of our financial and business processes to an integrated business and financial reporting system; 

  

	•	 	 the potential for substantial and currently undetermined or underestimated environmental costs and liabilities; 

 

	•	 	 the risk that assumptions that form the basis of our recorded environmental liabilities and related regulatory assets may change;

  

	•	 	 the risk that the presence or release of hazardous or harmful substances could lead to claims by third parties and/or governmental orders;

  

	•	 	 the risk that future environmental expenditures is not recoverable in future electricity rates; 

 

	•	 	 the risk that it may be determined that exposure to electric and magnetic fields emanating from power lines and other electric sources may

  
 2012 ANNUAL
INFORMATION FORM  9 

 FORWARD-LOOKING INFORMATION 

 

	 	 
cause health problems; 

  

	•	 	 the potential that we may incur significant expenses to replace some or all of the functions currently outsourced if our agreement with Inergi LP is
terminated; 

  

	•	 	 the impact of the ownership by the Province of lands underlying our transmission system; 

 

	•	 	 the impact of the GEA and the LTEP on our company and the costs and expenses arising therefrom; 

 

	•	 	 the ability to negotiate collective agreements consistent with rate orders; 

 

	•	 	 the ability to maintain compliance with our licence requirements in the event of a labour dispute; 

 

	•	 	 actions taken by the Province resulting from the review of Ontario’s electricity sector by the Ontario Distribution Sector Review Panel; and

  

	•	 	 the impact of increased competition on our transmission business. 

 Hydro One cautions you that the above list of factors is not exclusive. Some of these and other factors are discussed in more detail under “Risk Factors” in this AIF. You should review the
section entitled “Risk Factors” in detail. 
 In addition, Hydro One cautions you that forward-looking information provided in this
AIF concerning potential future expenditures is provided in order to provide context to the nature of some of our future plans and may not be appropriate for other purposes. 

  
 10  HYDRO ONE INC.

 FORWARD-LOOKING INFORMATION 
  

 Simplified Illustration of an Electric Power System 

 
 

 

  
 2012 ANNUAL
INFORMATION FORM  11 

 ABOUT HYDRO ONE 

 
 

 

  
 12  HYDRO ONE INC.

 ABOUT HYDRO ONE 

 

 ABOUT HYDRO ONE 
 Hydro One is wholly owned by the Province and our transmission and distribution businesses are regulated by the OEB. Our industry, including our company, is governed within the broad legislative framework
of the Electricity Act and the OEB Act. 
 Our AIF provides material information about us and our business in the context of historical
and future development. Our AIF describes our company and our operations, risks and other factors that impact our business. 
 Our Mission
and Vision 
 Our mission and vision are driven by our core values: health and safety, excellence, stewardship and innovation. We live our
values every day in everything we do and they represent what is most important to us. 
 As stewards of the Province’s electricity grid,
our core role is to provide safe, reliable and cost-effective electricity transmission and distribution and to connect clean and renewable sources of generation to Ontario’s electricity grid. 

Our Strategy 
 Hydro One’s corporate
strategy is based on our mission and vision and our values. Our mission and vision is to be an innovative and trusted company delivering electricity safely, reliably and efficiently to create value for our customers. Our values represent our core
beliefs: 
  

	•	 	 Health and Safety – Nothing is more important than the health and safety of our employees, those who work on our property, and the public

  

	•	 	 Excellence – We achieve excellence through continuous training, ensuring we are prepared and equipped to deliver high quality and
cost-effective service, with integrity 

  

	•	 	 Stewardship – We invest in our assets and people to build a safe, environmentally sustainable electricity network in a commercial manner

  

	•	 	 Innovation – We innovate through new processes, people and technology to allow us to find better ways to meet the needs of our customers

 We have eight strategic objectives that are inextricably linked. They drive the fulfillment of our mission and vision.

  

	•	 	 Creating an injury-free workplace and maintaining public safety. Health and safety must be integrated into all that we do. We must
continue to create a passion for preventing injury. We will strengthen our already strong safety culture through our Journey to Zero initiative and achieve world-class results. We will implement the internationally recognized health and safety
management system, ISO 18001, to identify health and safety risks, priorities and mitigation in order to further drive our safety culture. We will continue to reinforce that nothing is more important than the health and safety of our employees.

  

	•	 	 Satisfying our customers. We will meet our commitments, make customers our focus in our planning, communicate effectively, coordinate
across lines of business, and maximize opportunities to improve our corporate image. We will develop and deliver targeted customer segment strategies, products and delivery channels that will respond to their unique needs and behaviours.

  
 2012 ANNUAL
INFORMATION FORM  13 

 ABOUT HYDRO ONE 

 

	•	 	 Continuous innovation. Innovation represents one of our core values and is critical to achieving our mission and vision. Over the
next two decades, we will install innovative solutions that improve the reliability and efficiency of the transmission and distribution systems and provide our customers with more capability to manage their power costs. ADS is a key element in our
investment in innovation and will improve the operation of our distribution assets and deliver further value to our customers. 

  

	•	 	 Building and maintaining reliable, cost-effective transmission and distribution systems. Our transmission strategy is to provide a robust
and reliable provincial grid that accommodates Ontario’s emerging generation profile, manages an aging asset base and meets demand requirements through prudent expansion and effective maintenance. Our distribution strategy is focused on:
incorporating ADS technology to provide greater visibility, increasing control and improving customer service, supporting the connection of renewable energy sources, seeking efficiencies through leveraging technology and operational experience from
our transmission system, providing reliable and cost-effective service over a diverse geography, and pursuing commercial arrangements that are anticipated to arise from the rationalization of Ontario’s distribution sector.

  

	•	 	 Protecting and sustaining the environment for future generations. Consistent with our value of stewardship, we play a central role in
reducing Ontario’s carbon footprint through the delivery of clean and renewable energy and through measures that allow our customers to manage and reduce their energy use. We will engage our customers further regarding how we can manage our
sustainability obligations and activities on their behalf. 

  

	•	 	 Employee engagement. We believe our primary strength is the capability of our people. In order to sustain this advantage, we must address
the issues of corporate culture, labour demographics, diversity, development of critical core competencies and skill and knowledge retention. Our labour strategy should enable us to make significant gains in the areas of labour flexibility,
productivity improvement and cost reduction. 

  

	•	 	 Maintaining a commercial culture that increases value for our shareholder. We are committed to keeping rates as low as possible for our
customers, and delivering income and dividends to our shareholder. This is possible through our focus on reducing costs, managing our assets effectively and increasing productivity. We will explore and pursue opportunities to increase the
revenue-earning potential of the Company by leveraging existing assets, technologies, capabilities and the geographic presence of our company. 

  

	•	 	 Achieving productivity improvements and cost-effectiveness. To achieve our mission and vision, we must constantly strive for productivity
through efficiency and effective management of costs. Productivity is key to meeting our other strategic objectives and, in particular, to achieving value for our customers and our shareholder. 

We recognize the pivotal role innovation will play in building a smart electricity grid that supports a clean environment for Ontario. We are committed
to becoming the industry leader in putting innovative solutions to work for the well-being of Ontario’s economy and its residents. 

  
 14  HYDRO ONE INC.

 ABOUT HYDRO ONE 

 

 As an award winning company, in 2012, we were ranked one of the Best Corporate Citizens, and the top
ranked utility, by Corporate Knights Magazine. This ranking survey indicates that we successfully managed specific environmental, social and governance performance. Also in 2012, our Chief Information Officer was awarded the 2012 KITE Award for CIO
of the Year, Large Utility Company, and we received the Outage Cup Award in 2013 by OPG. Finally, in 2012 Laura Formusa, our President and Chief Executive Officer, was awarded the OEA Leader of the Year Award, which honours individuals who have
demonstrated exceptional vision, innovation, success, ethics and accountability. In 2013, we were awarded one of the Edison Electric Institute’s 2012 Emergency Assistance Awards for supporting the recovery efforts from the June 2012
Mid-Atlantic and Midwest derecho and Hurricane Sandy. 
  
 

 
  
 

 

  
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INFORMATION FORM  15 

 GENERAL DEVELOPMENT OF THE BUSINESS 
  
 

 

  
 16  HYDRO ONE INC.

 GENERAL DEVELOPMENT OF THE BUSINESS 

 

 GENERAL DEVELOPMENT OF THE BUSINESS 
 The following is a description of our company’s business and how it has developed, with a particular emphasis on the past three years. In this section, we will describe the electricity sector
landscape, as well as recent industry activity, and recent developments. 
 Electricity Sector Landscape 

 

			
	As a participant in the Ontario electricity sector, our company is affected by the following key parties in the electricity sector in Ontario.	  	
	  
 OPA

 
 The OPA was created in 2004 by virtue of an amendment to the Electricity Act,
and its objects are defined in Part II.1 of the Electricity Act. It is a non-profit corporation without share capital, and it is licensed and regulated by the OEB. The OPA’s mandate is to ensure the adequacy and efficiency of electricity
supply in Ontario through planning of electricity supply and demand. The OPA’s mission is to ensure that electricity needs are met for the benefit of Ontario now and in the future. The OPA plans and procures electricity supply from diverse
resources and facilitates the measures needed to achieve conservation targets.
	  	

	  
 OEB

 
 The OEB is the principal regulator of Ontario’s electricity industry. It is an
independent adjudicative tribunal that regulates Ontario’s electricity sector in the public interest, and ensures an adequate level of consumer protection in the energy market. The OEB licenses all participants in the electricity sector,
including the IESO, generators, transmitters, distributors, wholesalers and retailers. The OEB’s mandate and authority come from the OEB Act, the Electricity Act, and a number of other provincial statutes.
	  	

	  
 IESO

 
 The IESO is the system controller of Ontario’s electricity system. The IESO
manages the reliability of Ontario’s power system, forecasts the demand and supply of electricity and co-ordinates emergency preparedness for Ontario’s electricity system. The IESO also operates the wholesale electricity market, while
ensuring fair competition through market surveillance.
	  	

  
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INFORMATION FORM  17 

 GENERAL DEVELOPMENT OF THE BUSINESS 
  

 Recent Industry Activity 
 Distribution Sector Consolidation 
 On April 13, 2012, the Province announced it was
launching a comprehensive review of Ontario’s electricity sector to explore options to improve efficiencies, including LDC consolidation. As a result, the Province created the Ontario Distribution Sector Review Panel (“Panel”). On
December 13, 2012, the Panel released its report, Renewing Ontario’s Electricity Distribution Sector: Putting the Consumer First with recommendations for electricity sector consolidation. This report recommends that the 73 LDCs comprising
the focus of the report be consolidated into eight to 12 larger regional electricity distributors within a two-year timeframe. Specifically, it recommends there be two regional distributors in northern Ontario and between six and ten regional
distributors in southern Ontario with a minimum of 400,000 customers each. Given our company’s position as the largest LDC, the report recommends that Hydro One Networks be given unambiguous direction to lead and engage in the discussion of the
merger of distribution assets with the appropriate interested utilities on a commercial basis. At present, the Province is reviewing the report and assessing the recommendations. 
 Regulated Price Plan Structure 
 On April 1, 2005, the OEB implemented the RPP. The RPP
regulates only the commodity price of electricity and does not affect the rates charged for transmission and distribution of electricity. The RPP also introduced seasonal consumption thresholds. For residential customers, the price threshold between
the lower tier price and the upper tier price is 600 kWh per month in the summer and 1,000 kWh per month in the winter. For non-residential customers, the price threshold between the lower tier price and the upper tier price is 750 kWh per month in
both the summer and the winter. A summary of some recent prices per kWh set for RPP customers follows: 

  
 18  HYDRO ONE INC.

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 RPP Pricing (per kWh) 

 

							
	 Winter (Nov. 1, 2011 – April 30, 2012)
	  	Lower Tier Price	  	 	7.1 cents	  
			
		  	Upper Tier Price	  	 	8.3 cents	  
			
	 Summer (May 1, 2011 – Oct. 31, 2012)
	  	Lower Tier Price	  	 	7.5 cents	  
			
		  	Upper Tier Price	  	 	8.8 cents	  
			
	 Winter (Nov. 1, 2011 – April 30, 2013)
	  	Lower Tier Price	  	 	7.4 cents	 
			
		  	Upper Tier Price	  	 	8.7 cents	  

 Eligible customers will continue to pay RPP electricity prices until such time as Hydro One installs a smart meter and
the necessary systems are in place to start billing these customers for electricity on a TOU basis. Once customers are eligible to be billed on a TOU basis, regular RPP prices will no longer be available and instead they will be billed the RPP TOU
prices. 
 One of the OEB’s goals through TOU pricing is to provide an incentive for consumers to shift some consumption away from periods
of high total consumption (called “on-peak”) to periods of low demand (called “off-peak”). All eligible Hydro One distribution customers were migrated to TOU billing as of June 2011, except certain customers located in very rural
and very sparsely populated areas, for whom an exemption from the requirement to move to TOU pricing has been obtained until December 31, 2014. Below is a chart outlining the three TOU periods and the price for each. 

  
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 GENERAL DEVELOPMENT OF THE BUSINESS 
  

 RPP Pricing (per kWh) –TOU Prices 

 

							
	 Winter (Nov. 1, 2011 – April 30, 2012)
	  	Off-peak Price	  	 	6.2 cents	  
		  	7pm – 7am	  			
		  	  
 Mid-peak Price
	  	 	9.2 cents	  
		  	11am – 5pm	  			
		  	  
 On-peak Price
	  	 	10.8 cents	  
		  	7am – 11am, 5pm – 7pm	  			
			
	 Summer (May 1, 2012 – Oct. 31, 2012)
	  	Off-peak Price	  	 	6.5 cents	  
		  	7 pm – 7 am	  			
		  	  
 Mid-peak Price
	  	 	10.0 cents	  
		  	7 am – 11 am, 5 pm – 7 pm	  			
		  	  
 On-peak Price
	  	 	11.7 cents	  
		  	11 am – 5 pm	  			
			
	 Winter (Nov. 1, 2012 – April 30, 2013)
	  	Off-peak Price	  	 	6.3 cents	  
		  	7 pm – 7 am	  			
		  	  
 Mid-peak Price
	  	 	9.9 cents	  
		  	11 am – 5 pm	  			
		  	  
 On-peak Price
	  	 	11.8 cents	  
		  	7 am – 11 am, 5 pm – 7 pm	  			

 New RPP prices are computed at six-month intervals and are the result of an integrated consideration of re-basing and
true-ups. Price changes become effective at the beginning of a calendar month. 
 Ontario Clean Energy Benefit Act 

As announced in its 2010 Ontario Economic Outlook and Fiscal Review, the Province introduced the Ontario Clean Energy Benefit Act, 2010, which is
designed to assist Ontario electricity consumers through the transition to a cleaner electricity system. Under this Act, eligible residential, farm and small business consumers receive financial assistance in the amount of a 10% credit, with respect
to the total cost of electricity on their bills, including tax, effective January 1, 2011 for a five year period. This benefit is applied to their electricity costs for each billing period, and beginning September 1, 2012, the 10% rebate
only applies to the first 3,000 kWh of electricity consumed per month. 
 Procurement of New Generation 

Pursuant to a Provincial directive, the OPA set up the FIT program for renewable generation. The program is divided into large generation projects and
small generation projects. The smaller generation projects (10 kW or under) are referred to as the Micro FIT program. Pursuant to these 

  
 20  HYDRO ONE INC.

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 programs, the OPA has entered into contracts or conditional contracts with generators pursuant to which the OPA will
pay these generators a fixed rate for power produced over a specified period of time. Hydro One continues to work towards connecting those projects for which there are firm contracts and in which technical and economic assessments permit.

 The Province announced on October 31, 2011 that a review would be completed of the FIT program. As a result of this review, the
re-launch of the FIT program is underway. In August 2012, the OPA began to release approvals for Micro FIT projects to proceed and applications under the new program to Hydro One Networks Inc. have remained steady. On December 14, 2012, the
window for new small FIT program projects (for projects 10 kW and up to 500 kW) opened and the OPA accepted applications until January 18, 2013. 200 MW of capacity has been reserved for small FIT projects. The OPA has yet to announce when the
window for large FIT projects (for projects greater than 500 kW) will open, however it is anticipated in 2013. 
 Recent Developments at
Hydro One 
 New President and Chief Executive Officer and Organizational Realignment 

Our Board appointed Carmine Marcello to the role of President and Chief Executive Officer of Hydro One, effective January 1, 2013. Mr. Marcello
assumed his responsibilities following the planned retirement of outgoing President and Chief Executive Officer, Laura Formusa. Mr. Marcello has over 25 years’ experience with Hydro One as a senior executive, strategic planner and advisor
on transmission and distribution utility processes in the electric utility industry. Mr. Marcello’s direct reports are: Peter Gregg, as Chief Operating Officer; Sandy Struthers, as Chief Administration Officer and Chief Financial Officer;
Rick Stevens, Vice President of Customer Service; Judy McKellar, Vice President of People and Culture; Laura Cooke, Vice President of Corporate Relations; Joseph Agostino, General Counsel; and John Fraser, Senior Vice President, Internal Audit.

 In January 2013, the organization was realigned to help meet customers’ expectations and meet the following key priorities: 

 

	1.	improving our safety performance; 

  

	2.	improving our relationship with customers; and 

  

	3.	building a highly skilled and accountable workforce to deliver best-in-class service to our customers. 

Hydro One and Society Reach Tentative Settlement 
 On March 13, 2013, a tentative settlement for a renewal of the Society-Hydro One collective agreement was reached between our company and the Society. The settlement must be ratified by both the
Society’s members, as well as the Board of Hydro One before it becomes effective. 

  
 2012 ANNUAL
INFORMATION FORM  21 

 OVERVIEW OF HYDRO ONE 

 

 

 

  
 22  HYDRO ONE INC.

 OVERVIEW OF HYDRO ONE 
  

 OVERVIEW OF HYDRO ONE 
 We are the largest electricity transmission and distribution company in Ontario. 
 We own and
operate substantially all of Ontario’s electricity transmission system, accounting for approximately 96.8% of Ontario’s transmission capacity based on revenue approved by the OEB. 
 Based on assets, our transmission system is one of the largest in North America and our distribution system is the largest in Ontario. We have three reportable segments: (1) our transmission
business; (2) our distribution business; and (3) our other business. 
 Our transmission business, which represented approximately
$11.6 billion of our total assets of $20.8 billion as at December 31, 2012, transmits electricity through a high-voltage network from generators to our own distribution networks, to local distribution companies, and to transmission connected
companies. We also own and operate facilities that interconnect our transmission system with systems in neighbouring provinces and states. 

Our distribution business, which represented approximately $8.6 billion of our total assets of $20.8 billion as at December 31, 2012, distributes
electricity through our low-voltage distribution system to municipalities and to rural areas. Customers of our distribution business include LDCs, customers with loads exceeding 5 MW, and rural and urban customers. 

Hydro One Brampton Networks Inc. is our urban distribution company serving customers in the GTA. We also operate through our subsidiary, Hydro One Remote
Communities Inc., small, regulated generation and distribution systems in remote communities across Northern Ontario that are not connected to Ontario’s electricity grid. 
 Our other business segment is primarily represented by the operations of Hydro One Telecom Inc. This subsidiary markets dark and lit fibre-optic capacity to telecommunications carriers and commercial
customers with broadband network requirements. The assets of this segment constituted approximately $600 million of our total assets of $20.8 billion as at December 31, 2012. 

 
 

 

  
 2012 ANNUAL
INFORMATION FORM  23 

 DESCRIPTION OF THE BUSINESS 

 

 

 

  
 24  HYDRO ONE INC.

 DESCRIPTION OF THE BUSINESS 
  

 DESCRIPTION OF THE BUSINESS 
 Our Business Segments 
 Our Transmission Business 

Overview 
 Our transmission system
operates at 500 kV, 230 kV and 115 kV and transmits electricity to customers consisting of 47 LDCs, our own distribution businesses and 92 transmission-connected companies. Electricity is also delivered to utilities in other jurisdictions through
Interties. Electricity is supplied by generators, both within and outside Ontario, of which 97 in Ontario are connected directly to the transmission grid. Our transmission system serves over four million customers, directly or indirectly, and
transported approximately 141.3 TWh of energy throughout Ontario in 2012. Revenues from our transmission business accounted for approximately 26% of our total revenues in 2012 and approximately 25% and 26% of our total revenues in 2011 and 2010,
respectively. 
 Our transmission system forms an integrated transmission grid that can be divided into two components based on function. The
integrated network, or bulk system, operates primarily at 500 kV or 230 kV over relatively long distances and links major sources of generation to transmission stations and larger area load centres. The area supply system operates at 230 kV or 115
kV and links the bulk system to local generators and loads, such as LDCs, industrial customers and our own retail distribution operations. Transmission stations located near load centres step down the high voltage to the level required for retail
distribution systems or end-use customers connected directly to our transmission system. 
 Our transmission system is interconnected with the
North American eastern system that is comprised of virtually all of the electric utilities east of the Continental Divide. Our transmission business owns and operates 26 Interties at 345 kV, 230 kV, 115 kV and 69 kV levels with New York (7),
Québec (11), Michigan (4), Manitoba (3) and Minnesota (1). 
 Through these 26 Interties, we can accommodate imports of about 4,800
MW and exports of approximately 6,000 MW of electricity. In operation, the actual import and export capabilities may be restricted significantly by limitations within our or another jurisdiction’s transmission networks, unscheduled power flows
between interconnected systems and local load and generation patterns. 
 Our transmission system is relatively free of restrictions in its
ability to supply electricity to major load centres from generating sources located across Ontario, although there are certain short duration periods when the transmission constraints restrict economical utilization of generation. A 500 kV system
serves as the transmission “backbone” around the GTA with 500 kV connections to Northern Ontario, Ottawa, London and the major generating facilities in Ontario. As new generation projects are assessed in Ontario, the impact on the
transmission system is assessed and where required, transmission investment plans are initiated in a timely manner. 
 This section on our
transmission business consists of six topics: 
  

	1.	Transmission Planning 

  

	2.	Transmission Assets 

  

	3.	Transmission Capital Expenditure Plans 

  

	4.	Projects Relating to Interconnection 

  
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 DESCRIPTION OF THE BUSINESS 

 

	5.	NERC/NPCC 

  

	6.	NERC Critical Infrastructure Protection Standards 

 1. Transmission Planning 
 Hydro One develops transmission plans for new transmission
facilities and for refurbishment and replacement of existing transmission facilities, as required. The plans for new facilities identify proposed equipment, configuration, routing and resulting capacities for network, local area and
connection/transformation investments. We consult with customers to determine the need, timing and technical solutions for new connection/ transformation facilities. We also consult with affected communities, stakeholders and First Nations and
Métis as part of the project development process for new or upgraded transmission lines. 
 The need for additional network and local
area capabilities is determined in consultation with the OPA (which plans future generation and CDM programs), customers and in response to governmental policy and direction. The need for short-term and long-term solutions may also be highlighted in
the reliability reports issued by the IESO. The IESO assesses the system impact of proposed facilities based on requests by Hydro One, as required by the Market Rules. Projects involving new transmission lines longer than 2 kilometres are subject to
the OEB’s leave-to-construct approval. A “transmission line” or “transmission station” as prescribed in Ontario Regulation 116/01 made under the EA is subject to the “Environmental Screening Process”, as defined in
such Regulation, and may be subject to a class environmental or full environmental assessment approval. 
 Hydro One’s plans to maintain,
refurbish or replace existing facilities are developed on the basis of maintenance standards, asset condition assessments and end-of-life criteria specific to each type of equipment. Priorities are assigned to each type of investment based on the
risks that it mitigates. These investment plans are also included in our rate filings submitted to the OEB. 
 2. Transmission Assets

 Our transmission assets can be divided into four functional categories: 

 

	A.	transmission stations, 

  

	B.	transmission lines, 

  

	C.	network operations, and 

  

	D.	telecommunication facilities. 

  

 
 A. Transmission Stations 
 Transmission station facilities are used for the delivery of power, voltage transformation and switching, and serve as connection points for both customers and generators. 

Transmission stations can be broadly classified into two categories. The first category consists of terminal stations, including switchyards located at
generating facilities, which are used mainly for switching and voltage transformation between the 500 kV, 230 kV, and 115 kV systems. The second category consists of customer supply stations, which are transmission stations that deliver power

  
 26  HYDRO ONE INC.

 DESCRIPTION OF THE BUSINESS 
  

 
from the transmission system to wholesale customers. Currently, most transmission stations used for customer supply consist of paired circuits and step-down transformers that are meant to ensure
that the failure of any one element will not result in a permanent loss of supply. For smaller or remote loads, a simpler station design with a single transformer or a single circuit is used. 
 Our transmission system includes 287 transmission stations whose components may include high voltage power transformers, power circuit breakers, high voltage switches, capacitor and reactor banks,
protection and control systems, metering and monitoring systems together with site infrastructures such as buildings and security systems. 

B. Transmission Lines 
 Our
transmission lines are classified into bulk power transmission lines and area supply lines. Bulk power transmission lines are main lines delivering power from generating stations or interconnections to receiving terminal stations. Bulk power
transmission lines are part of the integrated transmission network and generally operate at 500 kV or 230 kV, with a few at 115 kV. Area supply lines take power from the transmission network at the receiving stations and transmit it to customer
supply transmission stations at customer load centres. The usual voltage levels of area supply lines are 230 kV or 115 kV. All of these lines are overhead except for approximately 282 circuit kilometres of underground cables in urban areas.

 The transmission system includes approximately 29,000 circuit kilometres of high voltage lines whose major components consist of cables,
conductors, wood or steel support structures, foundations, insulators, connecting hardware and grounding systems 
  

 
 C. Network Operations 
 All of our transmission assets and many of our sub-transmission assets are managed from one central location, the OGCC. As owners and operators of the largest portion of the Ontario transmission network,
we have the responsibility under the Electricity Act to ensure that our assets are operated in a safe and reliable manner which optimizes connection performance to our customers. 
 Accordingly, the OGCC is the controlling authority for our company’s transmission network and for large portions of the sub-transmission network. The OGCC is an operating centre that monitors and
controls our transmission and sub-transmission networks via the Network Management System. With this computer system, the OGCC remotely monitors and operates transmission equipment, responds to alarms and contingencies, and can restore and reroute
interrupted power. 
 The OGCC reviews, approves, performs and/or authorizes all switching and control actions on our transmission system and
sub-transmission system assets. The OGCC also provides the dispatch function across the entire company for transmission and distribution assets. The OGCC coordinates all planned transmission and
sub-

  
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 transmission equipment outages with stakeholders and customers. Additionally, the OGCC is responsible for notifying
affected customers of any planned distribution outages. For forced distribution outages, the OGCC creates outage tickets which contain all the relevant information for the outage, dispatches field crews, communicates estimated time of repair and
confirms outage restoration with the Hydro One distribution customer. 
 The OGCC is fully supported by onsite customer service, engineering,
operations technology, training, process and business planning staff. There is a fully functional back-up facility which would be staffed in the event of an evacuation of the OGCC. 
 D. Telecommunications Facilities 
 Our telecommunications requirements include
services necessary for protection and operation of the power system as well as voice and administrative data. Power system protection and control, and voice communications required for control and restoration of transmission and distribution assets
have very stringent reliability and security requirements which must continue to be met during prolonged blackout conditions. 
 These
telecommunications requirements are vital to meeting our transmission reliability compliance obligations, ensuring the protection of our assets and ensuring efficient and rapid restoration following contingencies. These requirements are met through
the use of our own facilities and services acquired from other telecommunications service providers. The reliability and availability of telecommunication services used in the protection and operation of our transmission system are vital to meeting
our interconnection obligations, ensuring the protection of our assets and ensuring the reliability of our transmission system. Historically, if telecommunications service providers were not able or willing to provide the required services at an
appropriate cost, we installed our own telecommunication facilities. These owned facilities include systems constructed using various communication technologies such as fibre optic and metallic cables, wireless transmission and power line carrier
equipment. 
 In May 2011, the Board authorized the Wide Area Network Initiative project with anticipated completion at the end of 2014. This
project was initiated to meet forecast growth in telecom bandwidth requirements in a cost-effective manner. The project was planned in four stages with a review to confirm forecast growth at the beginning of each stage. The review at the beginning
of the first stage indicates existing telecom capacity is higher than previously forecast and consequently the schedule for this project is under review. 

  
 28  HYDRO ONE INC.

 DESCRIPTION OF THE BUSINESS 
  

 3. Transmission Capital Expenditure Plans 

Transmission Capital Expenditure Plans consist of three segments: 
  

	A.	Major Transmission Capital Development Projects, 

  

	B.	Transmission Projects at the Local Load Connection Level, and 

  

	C.	Transmission Sustainment. 

 Our capital
investment plan is designed to address Ontario’s changing generation profile, accommodate load growth in areas throughout Ontario and support the expected increase in renewable energy generation in furtherance of the GEA as discussed below.
Additionally, this plan seeks to sustain or improve our transmission reliability performance, which is in the top quartile ranking in Canada for transmission systems of 230 kV and above. This plan also furthers our ongoing objective of sustaining
the performance of aging assets through refurbishment programs and end-of-life asset replacements. 
 The Minister, on February 17, 2011
issued a directive to the OEB, which in turn issued a decision and order on February 28, 2011, to amend the transmission licence of Hydro One Networks Inc. to develop and seek approval for the following projects the scope and timing of which
shall be in accordance with the recommendations of the OPA (see “Regulation – Transmission – Facilities Applications”): 
  

	1.	upgrade one or more existing transmission lines west of London (see “Major Transmission Capital Development Projects – Lambton to Longwood Transmission
Upgrade”); and 

  

	2.	build a new transmission line west of London. 

Additionally, the licence amendment requires Hydro One Networks Inc. to develop and implement the following transmission projects, the scope and timing
of which shall be in accordance with the recommendations of the OPA: 
  

	1.	one or more devices to enhance transfer capability such as series or static var compensators or other similar devices in southwestern Ontario; and

  

	2.	increase short circuit and/or transfer capacity at up to fifteen of our transmission stations during a 48-month period starting March 1, 2011 to enable the
connection of small scale renewable energy generation facilities. 

 In addition to the projects noted above, we are also pursuing
a number of additional projects as part of our company’s transmission investments. These projects, together with those noted above, will require various approvals, including, but not limited to, OEB approvals and EA approvals. 

A. Major Transmission Capital Development Projects 
 Set out below are our current major transmission capital development projects for which we have obtained or are actively seeking the requisite approvals. The major transmission system capital development
projects described below are at different stages of development and may not proceed to construction if requisite approvals are not obtained or if anticipated generation does not materialize. 

 

	•	 	 500 kV Bruce to Milton Double Circuit Transmission Line 

 The IESO’s December 2007 Ontario Reliability Outlook indicated that then existing transmission in southern Ontario could not accommodate the generation expected to come into service in the Bruce area
over the subsequent years. The Province supported this view, and the OPA determined that the preferred solution to increase the transfer capability of Hydro One Networks Inc.’s existing 

  
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 500 kV system was to build a new 500 kV double circuit transmission line between the Bruce Nuclear Station and the
Milton SS to securely incorporate all eight units from the Bruce nuclear facilities and the committed and potential wind generation in the area. The new line went in service in May 2012. 
 On June 18, 2012, our subsidiary Hydro One Networks Inc., and the Chippewas of Nawash First Nation and the Chippewas of Saugeen First Nation, collectively known as the Saugeen Ojibway Nation
(“SON”), entered into an agreement which contemplates a new Limited Partnership (“LP”) to hold only the lines and related land rights of our Bruce to Milton Transmission Reinforcement Project. The carrying value of these assets
is expected to be approximately $600 million when they are transferred to the LP in late 2013. Under the terms of our agreement, the SON will be eligible to purchase a non-controlling equity interest in the LP at fair value. The LP is anticipated to
become a rate-regulated entity under the jurisdiction of the OEB. Transfer of our assets to the LP and subsequent sale of an equity interest to the SON are both subject to the receipt of future regulatory approvals from the OEB. On December 18,
2012, the SON, Hydro One Networks Inc. and Hydro One signed a letter agreement in connection with the establishment of the LP. The letter agreement addresses, among other things, the terms of the LP Agreement to be entered into on closing and the
terms on which Hydro One Networks Inc. will operate the Bruce to Milton line on behalf of the LP. The closing is conditional on certain regulatory approvals and tax rulings. 

 

	•	 	 Northeast Transmission Reinforcement: Install Four Shunt Capacitor Banks 

All components of this OPA recommended investment to reinforce the transmission system in Northeastern Ontario were completed and placed into service as
of October 9, 2012. These near term measures will enable renewable generation in Northern Ontario as well as mitigate congestion on the interface between Northern Ontario and Southern Ontario. 

 

	•	 	 Woodstock Area Transmission Reinforcement 

 All components of this project were completed on March 26, 2012 and will provide reliable transmission capacity to customer load supplied in the Woodstock area of Southern Ontario. This project is
designed to increase transmission capacity through 11 km of new 230 kV double-circuit line on the existing 115 kV right-of-way between Ingersoll TS and a new station called Karn TS. The project also included construction of the new Karn TS. These
projects are expected to increase the transmission capacity in the Woodstock area to 290 MW in preparation for future growth. 
  

	•	 	 Toronto Midtown Transmission Reinforcement Project 

 Supply to the midtown Toronto area is currently provided by three 115 kV circuits between Leaside TS and Wiltshire TS. These circuits supply Bridgman TS and Dufferin TS from Leaside TS and also provide
load transfer capability between the 

  
 30  HYDRO ONE INC.

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 Leaside TS and Manby TS. This project will replace a section of aging cable and is expected to provide additional
capacity by adding one 115 kV circuit between Leaside TS and Bridgman TS. Hydro One Networks Inc. has obtained all the requisite approvals for this project and is currently proceeding to complete the acquisition of the required land rights.
Construction work is underway. The expected in-service date for the project was 2014, but due to a number of unforeseen delays related to project construction that date is under review. 

 

	•	 	 Rebuild Hearn SS 

The existing 115 kV Hearn switching station was identified by our company as due for major refurbishment. The OEB agreed with the need for the project,
EA approvals have been obtained and work is underway. The expected in-service date is the end of 2013. 
  

	•	 	 Upgrade 115 kV Switch Yards at Manby TS, Leaside TS, Hawthorne TS & Allanburg TS 

To allow the incorporation of new renewable generation in the Toronto, Ottawa and Niagara areas, the short circuit capability at each of Manby TS,
Leaside TS, Hawthorne TS and Allanburg TS 115 kV yards will be increased from the existing 40 kA to 50 kA by replacing the 115 kV breakers. The expected in-service date for this work is late 2013. 

 

	•	 	 Niagara Reinforcement Project 

 This project comprises the construction of 76 kilometres of 230 kV line from our Allanburg TS in the Niagara area to our Middleport TS in the Hamilton area. The Niagara Reinforcement Project is designed
to relieve transmission bottlenecks that limit transfer of Niagara area generation and imports from New York State. The Niagara Reinforcement Project status is considered substantially on time with the exception that some project work has been
delayed due to access issues created by a blockade related to aboriginal land claims on a section of the line. As a result, the OEB concluded that the project deserves special regulatory treatment and in its ruling of August 2007, the OEB determined
that interest capitalized against this project could be expensed and recovered as a period cost from January 1, 2007. It is anticipated that the project can be completed approximately two months after the successful conclusion of the land
claims matter between the Province and the Six Nations. 
  

	•	 	 Lambton to Longwood Transmission Upgrade 

 This project was identified in the LTEP and in the February 28, 2011 OEB license amendment to upgrade one or more of the existing transmission lines west of London. The upgrade involves the
reconductoring of approximately 70 kilometres of 230 kV double circuit transmission line in southwestern Ontario between Lambton TS and Longwood TS with higher capacity related conductor. The upgrade will enable the connection of approximately
300-500 MW of additional renewable generation in the area west of London. The required in-service date for this upgrade is December 2014. The project was approved for construction in November 2012. 

  
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	•	 	 Oshawa Area TS Project 

 The OPA has requested that Hydro One develop an implementation plan and initiate work on the installation of additional auto-transformer capacity at our proposed Clarington TS. Planning and environmental
studies are currently being undertaken. 
 B. Transmission Projects at the Local Load Connection Level 

In addition to our major capital development projects, we also have transmission projects at the local load connection level. At the local load connection
level, Hydro One continues to address supply needs with our customers in order to meet their load growth. For projects required to provide reliable delivery of electricity to communities, the participation and support of the affected LDCs as
partners in joint planning studies and throughout the consultation and approval processes continue to be essential. To address future needs of local load connections, we are in discussions with customers for major transmission expansions or new
transmission stations and, where necessary, line connections in locations such as Mississauga, Oshawa, Woodstock, Essex County, Ancaster and Brampton. Targeted investments in customer delivery point performance, power quality, and our 115 kV and 230
kV systems are expected to lead to improved reliability. 
 C. Transmission Sustainment 

In order to maintain our top quartile transmission reliability performance, our investment plan includes increased program expenditures for sustainment
initiatives to manage the replacement and refurbishment of our aging transmission infrastructure. Increased investment is being focused on those transmission assets that most impact reliability. Targeted component replacement programs such as air
blast circuit breakers, and transformers, as well as improved control initiatives to protect against animal contacts, have been adopted to remain in the top quartile in transmission reliability performance in North America. Also, we have continued
to move to more station refurbishments than have been undertaken historically. Given the current age of our assets and infrastructure, where these broader, integrated investments are possible, significant efficiencies can be gained. 

4. Projects Relating to Interconnection 

Michigan 
 In 1999, two of our
Interties with the State of Michigan were upgraded with the installation of two Phase Angle Regulators (“PAR”) and an autotransformer. The transmission owner in the State of Michigan also installed a PAR on one of our other Interties with
the State of Michigan at the same time. A number of technical issues were encountered with these devices over the past decade which required replacement of the devices. Permitting issues in the United States were also encountered. In the first half
of 2012, the permitting issues and residual technical issues with the equipment were resolved. On June 5, 2012, the PARs were put into operation simultaneously for the first time and have been used successfully for the remainder of 2012. This
project is now in-service. 
 5. NERC/NPCC 
 In Ontario, the Market Rules mandate that we comply with the reliability standards established by NERC and NPCC, and our transmission licence mandates that we comply with the Market Rules. A Market Rule
amendment effective July 8, 2011 caused those NERC and NPCC reliability standards that have not otherwise been stayed or revoked and referred back to the standards 

  
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authority (NERC and NPCC) for further consideration by the OEB to be declared in force in Ontario: (a) when the reliability standards are declared in force in the United States or, for NPCC
reliability criteria, when declared in force by NPCC; and (b) after the expiry of the period for initiating a review before the OEB and the conclusion of any such review. 
 On November 18, 2010, FERC, as the United States regulatory agency overseeing NERC, issued Order No. 743 directing NERC to revise the definition of “bulk electric system” to address
FERC’s technical concerns, and ensure that the definition encompasses all facilities necessary for operating an interconnected electric transmission network. FERC believes that the best way to accomplish these goals is to (a) eliminate the
regional discretion in the current definition; (b) maintain a bright-line threshold that includes all facilities operated at or above 100 kV except defined radial facilities, and (c) establish an exemption process and criteria for
excluding facilities that are not necessary for operating the interconnected transmission network. According to the FERC order, NERC was directed to file the revised definition together with an implementation plan and exemption process by
January 25, 2012. The definition, implementation plan and exemption process was approved by the NERC Board of Trustees on January 18, 2012, and was filed with FERC on January 25, 2012. The proposed definition, implementation plan and
exemption process were filed with the OEB on March 1, 2012. 
 On December 20, 2012, FERC announced the approval of this definition
which will come into effect in April 2013, with full compliance obligations within 24 months. We are working with the IESO and OPA together with other stakeholders on a “made in Ontario” exemption process and criteria that would allow the
application of the new definition in a cost-effective manner, where reliability gains can be obtained. 
 Significantly more transmission
facilities (being all facilities at or above 100 kV except defined radial facilities) will have to comply with NERC reliability standards with, in Hydro One’s assessment, little, if any, additional improved reliability of the interconnected
bulk electric system. Adopting this new approach would result in significant additional costs to the transmission facility owners, including Hydro One. We anticipate these costs would be spread over a number of years, and expect that they would be
recovered in rates. 
 6. NERC Critical Infrastructure Protection Standards 
 NERC Critical Infrastructure Protection (“Cyber Security”) standards came into effect in 2009. The standards are designed to ensure that utilities and other users, owners, and operators of the
bulk power system in North America have appropriate procedures in place to protect critical infrastructure from cyber attack. As a result, Hydro One’s physical, electronic and information security processes have been upgraded to meet more
stringent security requirements in order to meet NERC’s requirements. 
 The Cyber Security standards are currently evolving in response to
FERC Order No. 706 (May 16, 2008) directing NERC to develop modifications to Standard CIP-002-1 Cyber Security – Critical Cyber Asset Identification to address their concerns regarding the identification of critical assets to which the
standards apply. On April 19, 2012, FERC approved Version 4 of the standards and directed NERC to continue working to revise these standards addressing 

  
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matters in the FERC order that were not addressed in the filed Version 4 standards. On November 26, 2012, NERC Board of Trustees adopted Version 5 of the standards, which have been filed
with FERC for regulatory approval and with the Canadian governmental authorities. The updated and revised standards will impact Hydro One resulting in additional work, effort and associated costs. We anticipate these costs would be spread over a
number of years, and expect that they would be recovered in rates. 
 Our Distribution Business 

Our distribution systems provide customers with electricity distribution services through a low voltage distribution network. During 2012, approximately
29.2 TWh of electricity were delivered through the distribution system to approximately 1.4 million customers located in rural and urban areas (including approximately 142,000 urban retail customers located in Brampton, Ontario). The
distribution systems also serve 23 LDCs that are not connected directly to our transmission system, another 33 LDCs that are connected to our transmission system and 30 customers with loads exceeding 5 MW. The distribution system comprises
approximately 121,000 circuit kilometres of lines operating mainly at voltages of 50 kV or less, and we own 1,007 distribution and regulating stations. Our distribution systems distribute electricity from our transmission system and more than 10,300
small generators (433 generators >10 kW and approximately 9,900 <10 kW). Unlike the systems found in densely-populated areas that are designed to include built-in redundancy, our distribution systems supply mainly rural areas with low
population densities. To provide a cost-effective service to these areas, the distribution systems are configured as a largely radial system, meaning that they are configured in straight lines, rather than loops, so that an outage at any point along
the line causes all customers further down the line to lose power. As a result, component failures require immediate repair or replacement in order to restore service. Revenues from our distribution business accounted for approximately 73% of our
total revenues in 2012 and approximately 73% and 74% of our total revenues in both 2010 and 2011, respectively. 
  

 
 This section on our distribution business consists of six topics: 

 

	1.	Distribution Capital Expenditure Plans 

  

	2.	Distribution Assets 

  

	3.	Remote Communities 

  

	4.	Conservation and Demand Management 

  

	5.	Advanced Distribution System 

  

	6.	Smart Meters 

 1. Distribution Capital
Expenditure Plans 
 Capital expenditures for the distribution portion of our business for the period 2013 to 2015 are estimated to be
approximately $2 billion net overall. Consistent with our approved distribution rate application, capital expenditures for our distribution business for 2013 are expected to focus on new load connections, trouble calls and storm damage, wood pole
replacement, and system capability reinforcement. In response to the GEA and the resulting FIT program being 

  
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administered by the OPA with respect to implementing renewable energy technologies, we are also undertaking increased generation connection activity and upgrades to the distribution system to
accommodate this new generation. Across Ontario, we are continuing with the replacement of distribution assets that have reached their end-of-life, with installations that operate at higher voltage and conform to current standards. In addition, we
expect to continue to construct new lines and stations in response to system growth forecasts or high load relief requirements and the connection of new generation, and expect to continue our efforts to make the distribution system more efficient.
The budget also includes investments in the ADS. 
 In addition, we are continuing to implement initiatives to improve the reliability
performance of our distribution system through improved maintenance and line clearing practices. 
 The actual timing and expenditures is
uncertain as it is dependent upon various approvals, including OEB rate application approvals, as well as the extent to which the cost of distribution system investments made to enable the connection of renewable generation can be recovered.

 2. Distribution Assets 
 Our
electricity distribution system is made up of three system components: (i) low voltage lines connecting our transmission stations to our distribution stations and to some industrial customers, local generators and local distribution companies;
(ii) distribution and regulating stations; and (iii) our distribution lines connecting the low voltage side of the distribution stations to industrial, commercial, farm, local generation and residential customers as well as embedded local
distribution companies. These system components include equipment such as poles, conductors, transformers, reclosers, protection devices and switches. Other assets include service centres and equipment, such as our transportation fleet, computing
equipment and service and construction equipment. 
  
 

 
 3. Remote Communities 
 Through our subsidiary Hydro One Remote Communities Inc., we operate 19 regulated generation and distribution systems across Northern Ontario which serve 21 remote communities that are not connected to
Ontario’s electricity grid, the facilities of which are owned either by us or by OEFC, or in the case of Marten Falls, by the Marten Falls First Nation. These remote communities include a total of approximately 3,500 customers. Electricity used
by these remote communities is produced by 57 installed diesel generators owned or operated by us, which are supplemented by small amounts of wind or hydroelectric generation. Pursuant to Section 48.1 of the Electricity Act and Ontario
Regulation 199/02 thereunder, we are required, through one or more of our subsidiaries, to operate and maintain existing generation and distribution assets in, and supply electricity to, these remote communities. 

  
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 4. Conservation and Demand Management 
 The Province has established specific provincial targets for CDM. Hydro One’s distribution businesses’ expenditures to help meet these targets are funded through the global adjustment. The OEB
requires each distributor to file an annual report, by September 30 of each year, in respect of the results of its respective CDM program. 

The OPA annually files with the OEB proposed expenditure and revenue requirements and fees for review pursuant to subsection 25.21 of the Electricity
Act. Included in these applications is the OPA’s operating budget required to manage the implementation of CDM programs by local distribution companies such as Hydro One. 
 Section 27.2 of the OEB Act gives the Province the power to issue a directive to the OEB to take steps to establish CDM targets to be met by LDCs and other licencees. The CDM Code was created
in response to a directive dated March 31, 2010 by the Minister (the “Directive”). On November 12, 2010, the OEB issued final CDM targets. The distribution business of Hydro One Networks Inc. was assigned a peak demand reduction
target of approximately 214 MW and an energy reduction target of 1,130 GWh, and Hydro One Brampton Networks Inc. was assigned a peak demand reduction target of approximately 46 MW and an energy reduction target of 190 GWh, in each case for the
period 2011-2014, which is equivalent to about a 6% peak demand reduction and on a cumulative basis, a 5% energy reduction. 
 On April 26,
2012, the OEB issued its CDM guidelines for all electricity distributors. These guidelines provide more specific guidance on certain provisions in the CDM Code and the type of evidence that should be filed by distributors in support of an
application for OEB-Approved CDM programs. In addition, the guidelines provide details on LRAM related to CDM programs implemented under the CDM Code. LRAM is the mechanism by which LDCs are compensated for lost revenues associated with their
respective load reductions resulting from CDM programs. 
 The guidelines contain the following two key changes from the Directive: 

 

	1.	TOU savings: 

  

	 	a.	Savings associated with TOU pricing are eligible to be counted towards the CDM targets 

 

	 	b.	The evaluation of TOU savings will be conducted by the OPA for the entire province, and then allocated to distributors. 

 

	2.	LRAM: 

  

	 	a.	LRAMVA is established. 

  

	 	b.	LRAMVA is defined as the difference between: 

  

	 	i.	The level of CDM programs activities included in the LDC’s load forecast; and 

 

	 	ii.	The results of actual, verified impacts of CDM activities undertaken by distributors between 2011 to 2014 for OPA-contracted CDM programs and OEB-approved CDM programs.

  
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	 	c.	LDCs must apply for disposition of the balance in the LRAMVA at the time of their cost of service rate applications. 

 

	 	d.	LDCs may also apply for the disposition of the balance in the LRAMVA in IRM rate applications, if the balance is deemed significant by the applicant.

 On September 30, 2012, in accordance with the CDM Code, Hydro One Networks Inc. filed its 2011 Annual CDM Report with the
OEB. In the report, Hydro One Networks Inc. discussed the CDM activities and the energy and peak demand savings results achieved in 2011, as well as comments on its plan to reach its CDM targets by the end of 2014. 

Hydro One Networks Inc.’s results for 2011 were 35 MW (16.4% of the 2014 target) in peak demand savings, and 86 GWh of annual energy savings. These
energy savings will produce 336 GWh (or 29.7% of cumulative energy savings) towards the 2011-2014 target. Based on these results, Hydro One Networks Inc. expects to meet its 2014 cumulative demand and energy savings targets. The report discussed
alternatives for reaching Hydro One Networks Inc.’s target including, but not limited to: (1) realizing savings from enhanced and new OPA-contracted province wide initiatives; (2) savings from TOU rates; (3) realizing savings
from potential new OEB approved programs; and (4) leveraging other initiatives such as province-wide marketing activities. 
 On
December 21, 2012, the Minister issued a directive to the OPA to extend funding for the OPA-contracted province-wide CDM programs for one additional year, to December 31, 2015. This extension will provide an opportunity for the OPA and
LDCs to collaboratively work to strengthen the current framework. 
 As of December 31, 2012, Hydro One Networks Inc. was owed about $1.5
million by the OPA for CDM activities. 
 5. Advanced Distribution System 
 The ADS project is a long-term initiative aimed at testing, validating and implementing modern technologies to enable distributed generation integration, improve reliability and operations, and enhance
outage restoration and network planning. The ADS project is a key element of our company’s vision of continuous innovation to ensure a modern, flexible, and advanced distribution system for our customers in the future. Funding of $92 million in
capital and $20 million in OM&A were approved by the OEB as part of Hydro One Networks Inc.’s distribution rate case for the test years 2010 and 2011, to be recovered via a rate rider to be reviewed only with respect to the actual level of
spending. $15.6 million in OM&A was approved by the OEB for 2013 and it was agreed that capital costs can continue to be recorded in the variance account as long as they are consistent with the recommendations of the Smart Grid working group.
The costs recorded in the variance account are subject to a standard prudence review by the OEB at the next cost of service filing. 
 In 2011,
the ADS project completed the design phase of the initiative. In 2012, Hydro One Networks Inc. made significant progress in building out the trial area with modern technologies and installing a central control system (Distribution Management System)
at the OGCC. In 2013, the last remnants of the build phase of Release 1 of the project is expected to be completed and the end-to-end solution is expected to be validated to confirm design decisions and provide real time experience with the
components. In addition, plans are in place to further leverage smart meters to support outage detection and 

  
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restoration, theft detection, and distributed generation management. 
  

 
 6. Smart Meters 
 The Electricity Act originally provided the framework for the installation of smart meters in all homes and small businesses in Ontario by December 31, 2010. Electricity distributors are
accountable for the deployment of smart meter infrastructure and related technology for communications to meet minimum requirements as defined in the regulations. The Province has appointed the IESO to be the entity whose mandate includes the
storage of all provincial hourly data. Distributors are also accountable for the implementation of TOU pricing. 
 Hydro One Networks Inc. and
Hydro One Brampton Networks Inc. have installed approximately 1.4 million smart meters as of the end of 2012 and have completed development of systems and required integration to support TOU rates. These meters are capable of measuring and
reporting usage over predetermined periods, being read remotely, and, when combined with the systems being provided by the IESO, of providing customers with access to information about their electricity consumption on a daily basis. Smart meters are
regarded by the Province as an integral means of promoting a culture of conservation. 
 Smart meter activities continue to progress largely
according to plan. Hydro One Networks Inc. has installed approximately 1.2 million smart meters as of the end of 2012 and has commissioned the new systems, made changes to legacy systems, and completed the required integration with the
IESO’s Meter Data Management Repository, to implement TOU pricing. 
 Throughout 2012, Hydro One continued to optimize the smart meter
communication network through a number of firmware and software upgrades and continued with customer migration to TOU pricing. 
 In this
regard, Hydro One Networks Inc. has transitioned approximately 1.087 million customers to TOU pricing as of the end of 2012. Furthermore, Hydro One Brampton Networks Inc. moved approximately 139,000 customers to TOU pricing as of the end of
2012. These customers now consume power and receive bills based on RPP TOU prices and have access to their hourly usage information via the internet as soon as the day after it is consumed. 
 Hydro One Brampton Networks Inc. completed its smart meter plan at the end of 2012 and submitted an application to the OEB on December 14, 2012 for the final disposition of smart meter costs. As part
of Hydro One Brampton Networks Inc.’s application, the company requested a smart meter disposition rider and a smart meter incremental revenue requirement rider. 
 Expenditures for 2012 were $38.6 million for Hydro One Networks Inc. Planned expenditures in 2013 are expected to be approximately $48.5 million for Hydro One Networks Inc. 

  
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 In September 2012, Hydro One Networks Inc. filed an application with the OEB under Section 74 of
the OEB Act for an exemption from mandated TOU pricing impacting approximately 140,000 customers. These customers are located in very rural and sparsely populated portions of Hydro One’s service territory where additional cellular
communications equipment is required to support smart metering. On December 21, 2012, the OEB approved a two year exemption for Hydro One Networks Inc., with periodic reporting obligations. Hydro One Networks Inc. will report annually on its
progress in connecting these hard-to-reach customers. Hydro One Networks Inc. continues to investigate and assess alternative smart metering solutions that may provide a more economical means to serve these areas. 

 
 

 
 Our Telecommunications Business 
 Our telecommunications business, which is carried on by our subsidiary Hydro One Telecom Inc., markets dark and lit fibre optic capacity to telecommunications carriers and commercial customers with
broadband network requirements. Hydro One Telecom Inc. leverages its affiliated company’s telecommunications assets and delivers state-of-the-art, broadband telecommunications solutions to carriers, independent service providers, and large
public and private sector customers. 
 Hydro One Telecom Inc. is a CRTC-registered, non-dominant, facilities-based carrier, providing broadband
telecommunications services in Ontario with connections to Montreal, Quebec, Buffalo, New York, and Detroit, Michigan. Its fibre network spans over 5,000 kilometers. Hydro One Telecom Inc. provides telecommunication systems management and related
functions which are required for our transmission and distribution business including corporate data and voice networks. It also provides support for our smart meter and ADS operations. 
 Other Business Particulars 
 The following is a summary of material matters and issues
relating to our business. In this section we discuss the following: 
  

	1.	Employees 

  

	2.	Compensation 

  

	3.	Pension Plan 

  

	4.	Outsourcing Arrangement with Inergi LP 

  

	5.	Environmental 

  

	6.	Health and Safety 

  

	7.	Insurance 

  

	8.	Legal Proceedings and Regulatory Actions 

  

	9.	Financial 

 1. Employees 

At the end of 2012, our Hydro One Networks Inc. subsidiary had 5,456 regular (i.e., permanent) employees comprised of 642 non-represented executive and
managerial staff, 3,474 employees represented by the PWU and 1,340 employees represented by the Society. Hydro One Inc., Hydro One Remote Communities Inc. and Hydro One Telecom Inc. together have 148 employees in total. Hydro One Inc., Hydro One
Networks Inc., Hydro One Remote Communities Inc. and Hydro 

  
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 One Telecom Inc. also had 1,916 non-regular (i.e., temporary) employees comprised of 20 executive and managerial
staff, 795 employees represented by the PWU, 66 employees represented by the Society and 1,035 employees represented by a combination of the Canadian Union of Skilled Workers (an electrical trade union) and the 16 construction building trade unions
that have collective agreements with the Electrical Power Sector Construction Association. In addition, our Hydro One Brampton Networks Inc. subsidiary had 52 non-represented regular staff, 111 active employees represented by the Canadian Auto
Workers, 44 employees represented by the International Brotherhood of Electrical Workers and 10 contract staff. 
 On March 23, 2011, our
company and the PWU reached a Memorandum of Agreement for a renewal collective agreement. The term of the collective agreement is from April 1, 2011 to March 31, 2013. Also in 2011, we negotiated three-year agreements with the Canadian
Auto Workers and the International Brotherhood of Electrical Workers in Brampton, both of which expire on March 31, 2014. Finally, we negotiated a three-year agreement with the Canadian Union of Skilled Workers which expires on April 30,
2014. Our collective agreement with the Society expires on March 31, 2013. See “Risk Factors – Labour Relations Risk.” 
 We
expect to continue to focus initiatives on the attraction and retention of staff and the maintenance and development of the skills and competence of all our employees to foster a productive work environment and to manage the impacts of anticipated
retirements. A key goal of ours is to manage the demographics of our workforce, an issue which we are monitoring, as the average age of our work force is over 42 years with approximately 13 years of service. In response to this issue, a
comprehensive management development program, as well as a succession planning program, have been implemented. See “Risk Factors – Work Force Demographic Risk.” 

 
 

 
 2. Compensation 
 On May 18, 2010, the Public Sector Compensation Restraint to Protect Public Services Act, 2010, came into effect. This statute imposed a two-year freeze until March 31, 2012, on
the compensation structures of non-bargaining political and Legislative Assembly staff as well as compensation plans of non-bargaining employees in the broader public sector. This legislation applied to the non-bargaining employees of

  
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Hydro One. The legislation provides for an exception regarding employees represented by collective bargaining organizations, which include trade unions certified or recognized under the Labour
Relations Act. 
 The Strong Action for Ontario Act (Budget Measures), 2012 was passed on June 20, 2012. This statute amends the
Broader Sector Accountability Act, 2010 and implements new wage restraint measures on executive compensation which had expired on March 31, 2012. The compensation restraint measures affect defined, designated executives, primarily senior
management, at Hydro One and the restraint measures continue under this legislation until the Province proclaims that the restraint measures have expired, which cannot be before the fiscal year in which the Province no longer has a deficit. See
“Statement of Executive Compensation”. 
 3. Pension Plan 
 We established a defined benefit registered pension plan on December 31, 1999. Hydro One Inc. manages and invests the assets and liabilities of the pension fund as plan sponsor and administrator of
the plan. As of December 31, 2012, there were 5,487 active members and 7,532 pensioners and disabled and deferred members. In accordance with the requirements of the Pension Benefits Act (Ontario), an actuarial valuation prepared as at
December 31, 2011, was filed with the Financial Services Commission of Ontario in May, 2012. See “Risk Factors – Pension Plan Risk.” 
 Effective December 31, 1999, we established the Hydro One Inc. Supplementary Pension Plan to provide supplementary pension benefits. On October 30, 2001, this plan was amended to require the
establishment of a trust for the purpose of creating security for payment of the supplementary pension benefits provided for therein. This trust was constituted as a Retirement Compensation Arrangement under the provisions of the Income Tax Act
(Canada), and security was issued in the form of a letter of credit. 
 4. Outsourcing Arrangement with Inergi LP 

Through our subsidiary Hydro One Networks Inc., we entered into an outsourcing services agreement with Inergi LP (an affiliate of CapGemini Canada Inc.)
as of December 28, 2001, for services commencing March 1, 2002. Effective May 1, 2010, we utilized an option in our agreement to allow for the extension of the existing term to February 28, 2015. Under the agreement, Inergi LP
provides us with customer service operations and settlements, as well as supply management services, pay operations services, enterprise technology and finance and accounting services. 
 The agreement guarantees aggregate minimum revenue to Inergi LP of approximately $400 million over the final five years of the agreement; and provided that we purchase a minimum volume of services from
Inergi equivalent to the guaranteed revenue, we have the freedom to purchase additional volume of services elsewhere. Fees are subject to decreases based on optional external benchmarking analyses every three years. 

 
 

 

  
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 Capgemini North America, Inc. has provided a financial guarantee and Capgemini U.S. LLC has provided a
performance guarantee of the obligations of Inergi LP. The agreement provides for rights of termination for each of the parties, including, on the part of our company, rights of early termination for convenience and upon the occurrence of specified
business events. In such cases, we are obliged under the agreement to pay specified termination fees, as well as to contribute to resulting severance and other costs. See “Risk Factors – Risk Associated with Outsourcing Arrangement.”

 5. Environmental 
 Although
primarily regulated at the provincial level, jurisdiction over the environment is shared by Canadian federal, provincial and local governments. As a result, we are subject to extensive federal, provincial and local regulation relating to the
protection of the environment that governs, among other things, environmental assessments, discharges to water and land and the generation, storage, transportation, disposal and release of various hazardous substances. See “Risk Factors –
Environmental Risk.” Estimated environmental liabilities are reviewed annually or more frequently if significant changes in regulation or other relevant factors occur. Estimated changes are accounted for prospectively. 

Health, Safety and Environmental Management System 
 Hydro One has an environmental policy that in part states: We will identify, assess and manage significant environmental risks and integrate environmental considerations into our decisions. As part of our
health, safety and environmental management system, Hydro One has an environmental management system designed to realize our environmental policy by identifying and assessing the environmental effects of our operations and facilities and to aid in
the continual improvement of our environmental performance. The management system includes an annual risk assessment of significant environmental aspects such as PCBs and our land assessment and remediation program. This environment management
system has identified and assessed hazards and risks, and controls have been implemented to mitigate significant risks. We continually update our environmental management system to reflect organizational changes and progress in achieving our
environmental goals. 
 Permits and Approvals 
 We are required to obtain and maintain specified permits and approvals from federal, provincial and local authorities relating to the design, construction and operation of new and upgraded transmission
and distribution facilities. Examples include EA approvals, permits for facilities to be located in parks or other regulated areas, water crossing permits, and approvals to discharge to air and water. Although the majority of the permits and
approvals are under Provincial legislation, some projects may require environmental approvals from the federal government. Examples include Fisheries Act authorizations, Navigable Waters Protection Act authorizations and Canadian
Environmental Assessment Act approvals. Canadian Environmental Assessment Act approvals may apply to projects located on federally-regulated lands, including First Nation reserve lands and federal parks. Interties with neighbouring
utilities in other provinces and states also require federal approval and will be subject to federal regulatory review. 
 The development of
new transmission facilities and major expansions require approvals under the EA. Generally, larger projects are subject to the individual environmental assessment process. The majority of approvals fall under a class

  
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environmental assessment process which provides for more streamlined approvals. The scope, timing and cost of environmental assessments are dependent on the scale and type of project, the
location (urban versus rural), the environmental sensitivity of affected lands and the significance of potential environmental effects. 

Regulation of Releases 
 Federal,
provincial and municipal environmental legislation regulates the release of specific substances into the environment through the prohibition of discharges that will or may have an adverse effect on the environment. Spills and leaks of substances
occur in the course of our normal operations. Accordingly, we have spill, leak prevention and leak mitigation programs involving the testing, replacement, repair and installation of containment systems including re-gasketting of transformers and
sulphur-hexafluoride filled equipment. In addition, we have an emergency response capability which we believe is sufficient to minimize the environmental impact of spills and to comply with our legal obligations. 

Hazardous Substances 
 We manage a
number of hazardous substances, such as PCBs, herbicides and wood preservatives. In addition, some facilities have substances present which are designated for special treatment under occupational health and safety legislation such as asbestos, lead
and mercury. We have environmental management programs in place to deal with PCBs and herbicides. 
 PCB 

Under Environment Canada regulations introduced in 2008, all equipment and materials with PCBs in concentrations of 500 parts per million (ppm) or more,
except pole-top transformers and their pole-top auxiliary electrical equipment and light ballasts, were to be disposed of by the end of 2009. Hydro One has applied for and received a permit from Environment Canada to allow Hydro One to extend the
time within which to dispose of specific equipment in stations known or potentially contaminated with PCBs in stations with concentrations of 500 ppm or more (the latest date being December 31, 2014). PCBs in concentrations of 50 ppm or more in
pole-top transformers, pole-top auxiliary electrical equipment, light ballasts and other electrical equipment are required to be disposed of by the end of 2025. In addition, liquids with concentrations of 2 ppm or more that have been removed from
equipment cannot be reused. 
 To date, approximately 97.7% of Hydro One’s PCBs has been safely destroyed. PCB contaminated waste material
is transported to a provincially-approved destruction facility where the PCB waste is either incinerated or chemically destroyed. The remaining 2.3% is found in extremely low concentrations (typically less than 500 ppm) in small volume electrical
equipment that is geographically dispersed across Ontario. Hydro One estimates that approximately 262,000 pieces of equipment will require inspection, testing, retrofilling, replacement and/or disposal in order to comply with the current
regulations. 
 Our best consolidated estimate of Hydro One’s estimated non-capital future expenditures to comply with the final PCB
regulations introduced in 2008 is about $233 million. After consideration of our 2012 spending of $8 million, this represents a reduction of about $9 million in our estimated future expenditures to meet federal regulatory requirements with respect
to PCBs. As a result of this updated estimate of the future non-capital expenditures to comply with existing PCB regulations, we decreased our December 31, 2012, environmental liability by approximately $3 million compared to the balance as at

  
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September 30, 2012. This liability represents the present value of our estimated future non-capital expenditures. As we anticipate that these future expenditures will continue to be
recoverable in future electricity rates, an equivalent reduction of about $3 million has also been recorded to the offsetting regulatory asset, reflecting the continued probability of future recovery of these PCB expenditures from customers.

 Asbestos 
 As a result
of regulatory changes, we expect to incur future expenditures to identify, remove and dispose of asbestos-containing materials installed in some of our facilities. In 2010, the Company completed a study with the aid of an external expert consultant
to estimate the future expenditures required to remove asbestos prior to facility demolition. Based on this study, the Company has recorded a $7 million liability in respect of this obligation as at December 31, 2012, based on the net present
value of the Company’s best estimate of the total future expenditures of $18 million to complete its asbestos removal activities. We anticipate that such future expenditures will be recoverable in future electricity rates. 

Herbicides 
 We use herbicides for
the control of incompatible vegetation on transmission and distribution rights-of-way and for total vegetation control on station sites. We currently use an integrated vegetation management approach toward vegetation management using manual and
mechanical cutting, together with the use of herbicides. The Pesticides Act (Ontario) and associated Regulation 63/09 include a public works exception under which herbicide application is allowed for utility programs. We are working with both
government and external agencies to ensure we are in compliance. As indicated below, the historical use of herbicides has contaminated some of our properties and some nearby properties 
 On March 11, 2011, the Ministry of Natural Resources created an independent fact-finding panel to review the past use of 2,4,5-T herbicide in Ontario. The panel is investigating the use of 2,4,5-T by
the Province’s ministries and agencies and is examining whether exposure to 2,4,5-T herbicide may have potential health impacts. The findings of the panel will be made available to the public. Predecessors to Hydro One have in the past used
2,4,5-T for vegetation control. It is too early to identify what impact, if any, the findings of the panel will have on Hydro One. 
 Wood
Preservatives 
 Wood preservatives are used in wood poles to protect the wood against fungi and insects and thereby extend their service
lives. In the past, we have used poles which were impregnated with pentachlorophenol. We respond to contamination problems related to pentachlorophenol migration as they arise. 
 Land Assessment and Remediation 
 Hydro One Networks Inc. has a voluntary land
assessment and remediation program in place to identify and, where necessary, remediate historical contamination that has resulted from past (Ontario Hydro) operational practices and uses of certain long-lasting chemicals, at our transmission and
distribution stations and service centres. Our Hydro One Remote Communities Inc. subsidiary also has a similar program in place for generating stations it owns or operates. These programs involve the systematic identification of any contamination at
or from these facilities and, where necessary, the development of remediation plans for our properties and affected adjacent private properties. Potential contaminants include insulating oils, substances previously used for

  
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vegetation control such as arsenic trioxide, and other substances such as fuel oil, gasoline, PCBs and wood preservatives such as pentachlorophenol. Phase I Environmental Site Assessments
(“ESAs”) have been completed for most of the transmission stations, service centres and remote generating stations. Screening level Phase I ESAs were undertaken at distribution stations given their large number and similar operating
history. Site screening involving on-site soil sampling at the areas of greatest potential for contamination has been undertaken at the majority of these distribution sites. 
 Hydro One has identified approximately 1,550 suspect properties, where historical contamination may have occurred, comprised of approximately: 

 

	•	 	 281 Transmission and Switching Stations; 

  

	•	 	 57 Transmission Junctions with gravel cover; 

  

	•	 	 1005 Distribution and Regulating Stations; 

  

	•	 	 182 Real Estate Service Centres and associated pole yards; and 

 

	•	 	 25 Remote Diesel Generating Stations. 

 The number of sites where at least one soil or groundwater sample on site was found to be above the Ontario Ministry of the Environment standards (of at least one substance of concern) is approximately
943. We have completed the clean-up of 187 sites of the 290 identified priority sites. We have developed a risk-based property ranking system to assist in establishing priorities for Phase II ESA sampling. This system is supplemented with visual
inspections of the sites and nearby receptors. Remediation and/or risk management is occurring based on Phase II ESA results and discussions with affected property owners and regulatory authorities. The Ontario Ministry of the Environment (at the
local and head office level) and local health departments/medical officers of health are actively involved in the program. Further work may be required in the event we sell or decommission any of these sites. 

Future consolidated expenditures related to Hydro One Networks Inc.’s land assessment and remediation program are currently estimated at
approximately $41 million. These expenditures are expected to be spent over the period ending 2020 with most of the expenditures occurring prior to 2017. The consolidated expenditures on this program (including Hydro One Remote Communities Inc.) for
2012 were approximately $10 million. 
 Electric and Magnetic Fields 
 Electric and magnetic fields exist wherever electricity is used or transmitted, including electric power facilities such as transmission and distribution lines and substations, and within every building
in Ontario that has electrical service. National and international health agencies, including the World Health Organization, have reported that the evidence is insufficient to conclude that the low levels of these fields in our communities have
adverse effects on peoples’ health.1 Health Canada
“does not consider that any precautionary measures are needed regarding daily exposures to EMFs at ELFs. There is no conclusive evidence of any harm caused by exposures at levels found in Canadian homes and schools, including those located just
outside the boundaries of power line corridors.”2

  

	1	E.g., World Health Organization (WHO). Electromagnetic Fields and Public Health. Fact sheet N°322 June 2007; Extremely Low Frequency Fields. Environmental Health
Criteria, Vol. 238, Geneva, WHO, June 2007. 

	2	Health Canada. It’s Your Health: Electric and Magnetic Fields from Power Lines and Electrical Appliances. Updated November 2012.
http://www.hc-sc.gc.ca/hl-vs/alt_formats/pdf/iyh-vsv/environ/magnet-eng.pdf. 

  
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 We sponsor research and monitor national and international developments with respect to electric and
magnetic fields. Public exposures to electric and magnetic fields are not currently regulated by either the federal or provincial governments and we are not aware of any current plans to regulate public exposures to electric and magnetic fields by
these levels of government. 
  
 

 
 6. Health and Safety 
 Hydro One considers health and safety to be of paramount importance in the operation of its business and continues to maintain top quartile performance in key areas as well as to develop, implement and
maintain progressive programs and initiatives. We are committed to creating and maintaining an injury-free workplace and maintaining public safety, with concentrated focus on the elimination of serious injuries or “near-misses” which have
the potential to cause serious injuries. We have developed and are continuing to develop a number of programs and initiatives for accident prevention and to minimize the risk of injury to the public associated with our facilities and operations.
Policies are in place for both employee health and safety and public safety. 
 Measures are in place to monitor medical attention injuries
(including lost time injuries) as a result of workplace injuries. These indicators are monitored by management and by the Health, Safety and Environment Committee of the Board. Management compensation is tied, in part, to success in achieving annual
health and safety performance targets. An effective early and safe return to work program has allowed us to ensure that, when injuries occur, employees recover and return to the workplace as soon as possible. In 2012, we continued with the Journey
to Zero safety initiative that was started in 2009. This initiative compares our approach to health and safety management with world class companies to see where gaps might exist. Opportunities for improvement have been prioritized and
implementation continued during 2012. It is expected to continue in future years. 
 During 2012, there was a focus on the following areas:
Journey to Zero initiatives, planning for OHSAS18001 registration, skills and safety training, field coaching/mentoring, young and new worker safety and a number of employee wellness initiatives. As in previous years, we continue to focus on
specific areas of risk: electrical contacts, over-exertions and slips and trips. Through a review of incidents, we hope to understand contributing factors and prevention. 
 Hydro One has integrated the management of health and safety into a single health, safety and environment management system. Effective risk assessment and management are key elements to the successful
minimization of risk and safety performance improvement. Within the organization, hazards and risks have been identified and assessed and controls have been implemented to mitigate significant risks. 

7. Insurance 
 We maintain insurance
coverage, including liability, all risk property and boiler and 

  
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machinery insurance. We also maintain other insurance coverage that is required by provincial statute, which covers automobile liability, pesticide liability and aircraft liability. We do not
have insurance for damage to our transmission and distribution wires, poles and towers located outside our transmission and distribution stations including damage caused by severe weather, other natural disasters or catastrophic events or for
environmental remediation costs. See “Risk Factors – Risk of Natural and Other Unexpected Occurrences.” 
 8. Legal
Proceedings and Regulatory Actions 
 In connection with the reorganization of Ontario Hydro, we succeeded Ontario Hydro as a party to
various pending legal proceedings relating to the businesses, assets, real estate and employees transferred to us. We also assumed responsibility for future claims relating to the businesses, assets, real estate and employees acquired by us and
arising out of events occurring prior to, as well as after, April 1, 1999. In addition to claims assumed by us, we are, from time to time, named as a defendant in legal actions arising in the normal course of business. There are currently no
actions that are outstanding which are expected to have a material adverse effect on our company. 
 On April 4, 2012, we received a legal
claim issued in Superior Court by SouthPoint Wind asserting a claim against Hydro One Networks Inc., the OPA, three Ministries of the Province and Environment Canada for $1.2 billion. The allegations against Hydro One Networks Inc. related to
applications SouthPoint Wind had made under the Renewable Energy Standard Offer Program. The action against Hydro One Networks Inc. was dismissed on a without costs basis and with prejudice. We received a full and final release of the claim on
December 11, 2012. This case is concluded. 
 9. Financial 
 We aim to maximize the value of our company while maintaining an effective borrowing capability through stable credit quality and delivering stable financial returns to our shareholder. We remain
committed to understanding and staying abreast of best utility practices in order to execute our business in the most cost effective manner possible. 
 We believe that cost reductions and productivity improvements can be achieved through the joint management of our transmission and distribution businesses, leveraging better corporate data and use
next-generation business tools to make precision investments in capital and OM&A to obtain maximum benefit, and continuation of optimizing our outsourcing arrangement pursuant to which we outsourced non-core functions to Inergi LP and the
consolidation of our system operations functions. 
 Annual savings have been achieved in recent years as a consequence of our focus on
operational excellence, and these savings have largely been reinvested in our work programs or have offset additional rate pressures. Going forward, we are continuing to focus on capital efficiency and workplace productivity. Although additional
savings opportunities may be fewer, more complex and difficult to achieve, we will continue to pursue and examine additional opportunities. 

Prior to our adoption of U.S. GAAP as the basis for our consolidated financial reporting, we had planned to adopt IFRS effective January 1, 2012,
with comparative restatement of our 2011 results. Given uncertainty regarding the status of the IASB’s initiative to address the issue of rate-regulated accounting, Hydro One and several other major Canadian utilities began evaluating

  
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DESCRIPTION OF THE BUSINESS 
  

 
the option of adopting U.S. GAAP in lieu of IFRS in the first quarter of 2011. On July 21, 2011, the OSC approved Hydro One’s application to adopt U.S. GAAP, without becoming a
Securities and Exchange Commission registrant, for its 2012, 2013 and 2014 fiscal years. The Board approved a resolution in 2011 authorizing it to report under U.S. GAAP. As a result, Hydro One began reporting under U.S. GAAP in the first quarter of
2012, with one year of comparative restatement for 2011. Hydro One’s opening U.S. GAAP consolidated balance sheet as at January 1, 2011 was based on a retrospective application of U.S. GAAP. Any differences between Canadian GAAP and U.S.
GAAP that had an impact on our company’s consolidated financial statements were disclosed in the notes to the consolidated financial statements beginning with the first quarter of 2012. 
 In September 2012, the IASB decided to restart its previous project on rate-regulated activities with the development of a discussion paper. At its December 2012 meeting, the IASB decided to develop an
interim IFRS on rate-regulated activities that “grandfathers” existing recognition and measurement policies. An Exposure Draft on an interim IFRS for rate-regulated activities is scheduled to be completed by the IASB in the first half of
2013 and the discussion paper on the wider project scope is scheduled to be completed before the end of 2013. 
 Additionally, on
November 23, 2011, the OEB issued its decision with reasons approving the necessary adjustments to Hydro One Networks Inc.’s 2012 transmission revenue requirement and variance accounts resulting from the use of U.S. GAAP. On March 23,
2012, the OEB issued its decision with reasons approving the use of U.S. GAAP for regulatory purposes for Hydro One Networks Inc.’s distribution business. On April 3, 2012, the OEB approved the use of U.S. GAAP for regulatory purposes by
our subsidiary, Hydro One Remote Communities Inc. Our subsidiary Hydro One Brampton Networks Inc. has deferred its adoption of modified IFRS to the fiscal year beginning January 1, 2014, as allowed by the Canadian Accounting Standards Board.
Hydro One Brampton Networks Inc. will report under Canadian GAAP for the year ended December 31, 2012. 
 Developments at Hydro One

 Electricity Transfer Tax Exemption 
 In 2009, the Province made permanent the transfer tax exemption applicable when publicly-owned utilities sell electricity distribution assets to other publicly-owned utilities in Ontario. The Province has
indicated in the past that the transfer tax exemption is designed to encourage efficiencies and promote consolidation among Ontario’s publicly-owned electricity utilities. Hydro One remains open to strategic opportunities to rationalize the
distribution sector, on a voluntary and commercial basis, where they are consistent with both our mission and vision and direction from our shareholder. Our investment plan currently does not include any funding for LDC rationalization. 

Cornerstone 
 Cornerstone, a four phase
project, replaces IT systems that have reached “end-of-life”. The four phases are as follows: 
 Phase One implemented the enterprise
systems and functions to support the supply chain, asset management and work management functions and was completed in 2008. 

  
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 Phase Two extended the IT system functionality to replace legacy systems supporting the finance, reporting, payroll
and human resource functions and was completed in 2009. 
 Phase Three is focused on further optimization between 2011 and 2014, during which
time the new enterprise IT system will be expanded within business units to derive additional benefits surrounding business planning, asset analytics, supply chain optimization and field work management optimization. 

The last phase, Phase Four, is currently underway and will replace the legacy customer information and billing systems that perform the billing and
receivables for our company’s distribution customers (mass market, commercial, industrial, distribution generators). It is being undertaken between 2011 and 2013. 

  
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 REGULATION 
 The Statutory and Operating Framework 
 General 

The Electricity Act and the OEB Act, primarily establish the broad legislative framework for Ontario’s electricity market. The
Electricity Act sets out the fundamental principles of Ontario’s electricity industry, enabling open and non-discriminatory access to transmission and distribution systems. The OEB Act provides the OEB with the jurisdiction and
mandate to regulate Ontario’s electricity market. 
 The OEB provides a framework for the review of electric utilities’ distribution
and transmission revenue requirements so that rates may be established based on historical average or forecasted needs. See “Regulation – Rate Orders and Related Issues for Hydro One’s Businesses – Distribution – Current
Rate Orders and Distribution Rate Structure” Cost allocation issues are addressed on an ongoing basis by a working group established by the OEB. 
 On December 17, 2010, the OEB initiated a coordinated consultation process for the development of a renewed regulatory framework for electricity distributors and transmitters. On October 18,
2012, the OEB issued its report A Renewed Regulatory Framework for Electricity Distributors: A Performance Based Approach, marking the completion of its consultation process. The report identified three rate-setting models available to
provide choices suitable for distributors having varying capital requirements: a Fourth Generation IRM, which builds on the current Third Generation model by adding one year to the IRM period; a Custom IRM, which involves rate-setting based on a
five year forecast of a distributor’s revenue requirement and sales volume; and an Annual Incentive Rate-setting Index method, which involves annual adjustment of rates by a simple price cap index formula. The report also provided information
on performance measurement, continuous improvement and implementation of the new framework. 
 Four working groups (Asset Redefinition and
Regional Infrastructure Planning Process; Distribution Network Investment Planning; Smart Grid; and Performance, Benchmarking. and Rate Adjustment Indices) were established to provide expert assistance to review and advise the OEB’s staff on
proposals regarding certain implementation matters. Hydro One Networks is represented on all four groups. Working group meetings began in November 2012 and are scheduled through February 2013. Consultations will conclude with the issuance of filing
requirements and guidance, code amendments, and/or supplemental OEB policies in support of the new framework. The OEB is expecting that policies will be largely implemented in time for the 2014 rate year. We are currently assessing the rate-setting
methods available. 
 In 2010, the OEB initiated a consultation process to examine the revenue adjustment and cost recovery mechanism available
to electricity distributors (and natural gas distributors) to address revenue erosion resulting from unforecasted changes in volume of energy sold. These mechanisms are commonly referred to as “revenue decoupling” mechanisms as each
involves some means of disconnecting the link between the volume of energy consumed by customers and the recovery by energy distributors of their approved revenue requirement. 

  
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 On November 26, 2012, the OEB initiated a project to complete the work begun on revenue decoupling
for electricity and natural gas distributors. The OEB will examine how best to address changes in demand, including potential declines in average use. The OEB has had a limited revenue decoupling mechanism in place for both natural gas and
electricity distributors for some years. LRAM is intended to overcome any reluctance of distributors to engage in CDM activities since it reduces their revenues. This consultation will review the options for potential further revenue decoupling.

 Contractual Arrangements, Codes and Licences 
 Operating Agreement with the IESO 
 Under the Electricity Act, the IESO is required
to enter into agreements with transmitters giving it the authority to direct the operations of the transmitters’ systems. On June 8, 2001, we signed a 10-year operating agreement with the IESO, which became effective May 1, 2002,
which sets out the specific responsibilities of both parties relating to the provision of transmission service. The term of the operating agreement has been extended by two years to May 1, 2014. 

By contrast, the distribution portion of Ontario’s network is not directed by the IESO and remains subject to the operational control of local
distribution companies in accordance with the regulatory framework. 
 Hydro One’s Relationships with Other Market Participants

 Generators, local distribution companies and customers directly connected to our transmission system must enter into agreements with us to
ensure reliable connection service in conformity with the Transmission System Code established by the OEB. 
 Some market participants, such as
generators and large load customers embedded within distribution systems, are supplied from the wholesale market through lines and facilities that are defined or deemed by the OEB as “distribution” and owned by LDCs. At a minimum, under
the Electricity Act, LDCs must provide non-discriminatory access for eligible generators and customers to the wholesale markets administered by the IESO. The LDCs must advise the IESO of any conditions in their distribution system that may
affect the ability of embedded generators and loads to participate in the broader IESO administered markets. 
 Electricity Industry Codes

 The OEB has issued and in some cases amended several codes that govern the operation of OEB-licenced entities in Ontario. These codes
include the Affiliate Relationships Code for Electricity Distributors and Transmitters, the Standard Supply Service Code, the Transmission System Code, the Distribution System Code, the Retail Settlement Code, the Electricity Retailer Code of
Conduct, the Smart Sub-Metering Code and the CDM Code. These codes and requirements prescribe minimum standards of conduct and standards of service for transmitters, distributors, smart sub-metering providers and/or retailers in the electricity
market. These codes are available on the OEB website at www.ontarioenergyboard.ca. 
 Electricity Industry Licences 

Hydro One Networks Inc.’s transmission and distribution licences were issued in 2003 and 2004, respectively. The licences for all of our regulated
businesses have a 20-year term and incorporate reporting and record-keeping requirements in accordance with the OEB’s Electricity Reporting and Record Keeping Requirements. The GEA amended our licences to accommodate the connection of renewable
energy generation facilities and implementation of the ADS. 

  
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 The details of our transmission and distribution licences are found in Appendix “C”.

 Rate Orders and Related Issues for Hydro One’s Businesses 
 The OEB approves both the revenue requirements of and the rates charged by our regulated businesses. The rates are designed to permit our businesses to recover the allowed costs and to earn a
formula-based annual rate of return on our common equity by applying a specified equity risk premium to forecast interest rates on long-term bonds. 
 The term “utility rate base” refers to the investment in regulated operations, consisting of gross plant (property, plant and equipment) in service, less accumulated depreciation, plus necessary
working capital and in general excluding construction work in progress. Utility rate base is used to determine the capital structure for our regulated businesses, enabling a determination of approved financing charges and return on common equity for
them. 
 Transmission 

Current Rate Orders and Review of the Existing Transmission Rate Structure 
 Hydro One’s transmission rates are determined through Uniform Transmission Rates, which are based on the fully allocated cost associated with providing each of the following three transmission
service elements: 
  

	•	 	 Network services — the transmission network is the integrated part of our high voltage transmission system that is shared by all users and
includes all 500 kV facilities, and the 230 kV and the 115 kV facilities that can be classified as commonly used; 

  

	•	 	 Line connection services — connection facilities are the radial parts of our high voltage transmission system, which are dedicated to
serving a single customer or generator or a group of customers or generators. Transmission line connection facilities are the radial high voltage transmission lines connecting the transformer to the network; and 

 

	•	 	 Transformation connection services — the transformation connection assets consist of the high voltage transformation facilities that step
down voltages from transmission levels to distribution levels to supply customers. 

 In addition, electricity exports from
Ontario are levied an export charge for transmission of two dollars per MWh. 
 On May 19, 2010, Hydro One Networks Inc. filed its
Transmission Revenue Requirement and Rate Application for 2011 and 2012 rates and the decision was issued on December 23, 2010. The OEB also ordered Hydro One to adopt IFRS in 2012 and reflect the $200 million increase in 2012 revenue
requirement. 
 On July 15, 2011, Hydro One Networks Inc. filed its Motion to Vary the OEB’s decision on its previous transmission
rates application to determine its 2012 revenue requirement and electricity transmission rates, and to approve of the use of U.S. GAAP for regulatory accounting and reporting purposes as of January 1, 2012. The adoption of U.S. GAAP in lieu of
modified IFRS will decrease the revenue requirement in 2012 by about $200 million, which in turn will decrease the rate increase by approximately 15%. The OEB issued its decision with reasons on November 23, 2011, approving all the resulting
adjustments to the 2012 transmission base revenue requirement, capital expenditures and rate base 

  
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as identified by Hydro One Networks Inc. in its evidence. 
 On December 1, 2011,
Hydro One Networks Inc. submitted to the OEB its draft 2012 transmission revenue requirement that reflects the approved adoption of U.S. GAAP for rate setting purposes as well as the OEB directed update to 2012 cost of capital parameters. The
proposed $1,418 million 2012 revenue requirement was subsequently approved by the OEB, along with new 2012 uniform transmission rates effective January 1, 2012 reflecting an approximate 8% transmission rate increase. 

On May 28, 2012, Hydro One Networks Inc. submitted a cost of service rate application for its transmission business, with 2013 and 2014 as test
years. After the settlement conference in October of 2012, Hydro One and the intervenors reached an agreement, settling all issues but one, ETS. The settlement proposal was reviewed by the OEB and at an oral hearing on November 8, 2012, it
accepted the settlement agreement. An experts’ conference and an oral hearing are taking place in December 2012 and January 2013 on the only unsettled issue, ETS. The outcome of this hearing will have no impact on the approved 2013 Transmission
rates. 
 On November 30, 2012, Hydro One Networks Inc. submitted its draft transmission rate order, which includes revenue requirements of
approximately $1,438 million and $1,528 million for 2013 and 2014, respectively. For the transmission portion of thea customer’s bill, this represents no change from existing 2012 OEB-approved rate levels in 2013 and a 5.8% increase in 2014. On
a total bill basis, this represents increases of 0% for 2013 and 0.5% for 2014. On December 20, 2012, the OEB issued its final rate order for 2013 Ontario Uniform Transmission Rates. 
 Bypass 
 Bypass occurs when we have invested in the provision of transmission
facilities to a customer which then obtains all or part of its transmission services in another manner or takes action to avoid its use of our transmission services before the rates collected have paid for the investment. Recovery of the remaining
costs for the stranded facilities then necessitates higher transmission rates from the remaining customers. 
 In August 2005, following an
extensive consultation process, the OEB issued a revised Transmission System Code, which implements principles relating to transmission bypass, among other things. 
 Competition 
 Under the OEB Act, any licensed competitor can apply to the OEB
for approval to build transmission network facilities in Ontario. The OEB’s adoption of the Uniform Transmission Rate reduces the financial incentive for customers to seek alternative transmission. 

Customers historically had the option to build and own their own transmission connection facilities and thereby avoid paying our connection charge. Only
a few large industrial customers and LDCs chose to do so, likely because of the significant costs of construction. Under the new regulatory framework, in addition to avoiding our connection charge, LDCs that own their transmission connection
facilities can include these assets in their rate base and earn a regulated return. Customers will generally, however, continue to have the option to have their new connection facilities incorporated within our existing transmission transformation
and line pools or to build and own their new connection facility. We expect to continue to maintain and restore our existing connection assets, as well as bid on the construction and ownership of new facilities. 

  
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 Facilities Applications 
 Transmission line expansions greater than 2 kilometres in length require prior OEB approval under section 92 of the OEB Act, as well as environmental assessment, other approvals, and consultation
with First Nations and Métis communities. OEB filing requirements for transmission applications which include filing requirements for leave to construct electricity transmission projects under section 92 of the OEB Act ensure a
complete review of proposed transmission projects. Regardless of whether OEB leave to construct is received, cost recovery of approved facilities still needs a final approval from the OEB as part of a transmission rate application. 

On November 23, 2010, the Ministry posted the LTEP, which identified three priority transmission projects that the Province wished Hydro One to
carry out. The Minister requested Hydro One to proceed with the planning and development work for the three priority projects. Subsequently, by a directive to the OEB dated February 17, 2011 and by a decision and order of the OEB dated
February 28, 2011, Hydro One’s transmission licence was amended to proceed with those three projects as well as to develop and seek approvals for upgrades at up to 15 transmission stations. In April 2011, the OPA recommended a preliminary
list of 10 transmission station improvements. The upgrades at six (6) transmission stations were successfully completed in 2011 and 2012. It is projected that the work at the remaining transmission station will be completed in 2013. Alternative
solutions have been determined for the last three (3) transmission stations. 
 On August 26, 2010, the OEB released its new
policy entitled “Framework for Transmission Project Development Plans”. This policy sets out a framework for new transmission investment in Ontario by introducing competition for transmission development through an open process.

 On March 29, 2011, the Minister expressed the Province’s interest in the OEB commencing a transmitter designation process for the
East-West Tie line. The East-West Tie project is the first transmission network line expansion covered under the new competitive approach. The OPA’s proposed default route is a 400 km, 230 kV double-circuit line to run alongside an existing
Hydro One corridor along the north shore of Lake Superior between Hydro One’s Wawa TS in the east and Hydro One’s Lakehead TS in the west. The target in-service date is 2017. 
 One of the applicants registered for designation in this proceeding, EWT LP, is a limited partnership between three equal partners, Great Lakes Transmission, Bamkushwada LP (involving a number of First
Nations in the area of the East-West Tie), and Hydro One. EWT LP obtained an electricity transmission licence on May 31, 2012. Six (6) other transmitters also registered to participate in the designation process. The OEB adopted a
two-phase process for this proceeding. 
 On July 12, 2012, the OEB issued its Phase 1 decision and order, thus concluding Phase 1 of the
proceeding by finalizing various filing requirements and process issues and directing registered transmitters to file their applications for designation by January 4, 2013. 
 On January 4, 2013, the OEB had received six (6) applications for designation from the registered transmitters in the proceeding. The timeline for Phase 2, which will take the form of a written
hearing, has not been set. 

  
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 Connection Cost Responsibility 
 As discussed above, under “The Statutory and Operating Framework,” the OEB coordinated the Electricity Renewed Regulatory Framework consultation process, which identified issues relating to cost
responsibility for transmission connection assets. The OEB has concluded that a reconsideration of the Transmission System Code cost responsibility rules and a province-wide pooling of assets for rate-setting purposes is desirable to facilitate the
implementation of regional infrastructure planning and the execution of regional infrastructure plans. Hydro One is currently assisting the OEB through working group participation to implement these changes. (See “Regulation – The
Statutory and Operating Framework”) 
 Distribution 
 Current Rate Orders and Distribution Rate Structure 
 Hydro One Networks Inc.

 On July 13, 2009, Hydro One Networks Inc. filed its distribution rate application for 2010 and 2011. The OEB rendered its decision on
April 9, 2010, approving a revenue requirement of $1,146 million for 2010. On November 15, 2010, the OEB issued the cost of capital parameter updates for rates effective January 1, 2011. The new ROE value for 2011 was 9.66%. Applying
the lower ROE produced a revised revenue requirement of $1,218 million. The approved 2011 revenue requirement resulted in an average distribution rate increase of approximately 8.7% for 2011. The total bill increase for an average residential
customer consuming 800 kWh per month was approximately 3.4% or $4.28 per month. 
 On December 1, 2011, Hydro One Networks Inc. submitted
an application for approval to adopt U.S. GAAP for rate setting, regulatory accounting and regulatory reporting purposes for its distribution business as of January 1, 2012. It was estimated that the 2012 notional Hydro One distribution revenue
requirement would be $166 million higher if IFRS were utilized rather than U.S. GAAP. On March 23, 2012, the OEB approved Hydro One’s request. The 2011 approved distribution rates continued in 2012. 

On June 15, 2012, Hydro One Networks Inc. submitted its IRM application for 2013 distribution rates. In November 2012, Hydro One Networks Inc. and
the intervenors reached an agreement, settling all issues for all rate classes. On December 11, 2012, Hydro One Networks Inc. submitted its settlement proposal along with a draft distribution rate order to the OEB. On December 14, 2012,
the OEB issued its decision, accepting the agreement as filed. On December 20, 2012, the OEB issued a final rate order. A typical residential customer consuming 800 kWh per month will see a distribution rate increase of 1.3% in 2013, or 0.4%
when considering total bill impacts. In addition, the Retail Transmission Service Rates adjustment which was accepted in the settlement will bring the total bill increase in 2013 to 1.5%. 
 On July 22, 2010, the OEB issued a letter in relation to low-income energy customers informing stakeholders about the initiatives that the OEB will undertake in the areas of: (1) emergency
financial assistance; (2) targeted conservation and demand side management programs; and (3) more flexible customer service rules. On October 20, 2010, the OEB issued a letter to all distributors directing them to implement an
emergency financial assistance program targeted for a January 2011 implementation. The OEB directed each distributor 

  
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to establish an emergency financial assistance fund equal to 0.12% of total distribution revenue. Hydro One Networks Inc.’s fund was approximately $1.5 million for 2011 and 2012. 

The OEB mandated that all eligible Hydro One Networks Inc. customers be transitioned to TOU pricing by June 2011. As of June 2011, Hydro One Networks
Inc. met the target except for certain customers located in very rural and very sparsely populated areas, for whom an exemption from the requirement to move to TOU pricing has been obtained until December 31, 2014. 

Hydro One Brampton Networks Inc. 
 On
June 30, 2010, Hydro One Brampton Networks Inc. submitted a 2011 cost of service rate application, which was subsequently adjusted on September 2, 2010 to reflect the Canadian Accounting Standards Board’s decision to allow the
deferral of the adoption of IFRS implementation for rate-regulated entities to January 1, 2012. The OEB rendered its decision on April 4, 2011 approving a revenue requirement of approximately $59.5 million, the recovery of LRAM of
approximately $2.4 million over 20 months and the disposal of Group Two Regulatory Assets of approximately $960,000 over eight months. The decision had an implementation date of May 1, 2011 and an effective date of January 1, 2011. The
distribution component of the bill for a customer using an average of 800 kWh/month increased by 2.8% and the total bill increase was approximately 0.5% in 2011. 
 On September 15, 2011, Hydro One Brampton Networks Inc. applied for an adjustment to its 2012 distribution rates in accordance with the OEB’s third generation IRM. On December 22, 2011 the
OEB approved an increase of 0.78% to its 2011 approved basic rates, the disposition of regulatory liability accounts of approximately $3.8 million over one year, and the recovery of approximately $430,000 for LRAM over one year. On January 5,
2012, the OEB issued the final rate order. A typical residential customer (800 kWh per month) would have seen a $3.03 (13.21%) reduction in the distribution portion of their bill and a $1.82 (1.74%) reduction on their total bill.

 On August 3, 2012, Hydro One Brampton Networks Inc. applied for an adjustment to its 2013 distribution rates effective January 1,
2013 in accordance with the OEB’s third generation IRM. On December 6, 2012 the OEB approved Hydro One Brampton Networks Inc.’s request for an increase of 1.28% to its 2012 approved basic rates. The net adjustment reflects the
application of a price escalation factor, less productivity. The impact on the distribution component of the customer’s bill for a typical residential customer with monthly electricity consumption of 800 kWh will be an increase of $0.07 or
0.33%, with a total bill impact of $0.07 or 0.06%. 
 On December 14, 2012, Hydro One Brampton Networks Inc. submitted its Smart Meter
Final Disposition application with a request for two new rate riders effective May 1, 2013. The impact on the distribution component of a customer’s bill for a typical residential customer with monthly electricity consumption of 800 kWh
will be an increase of approximately $2.10 or 9.86%, with a total bill impact of $2.14 or 1.93%. 
 Hydro One Remote Communities Inc.

 Hydro One Remote Communities Inc.’s business is exempt from a number of sections of the Electricity Act which relate to the
competitive market. For example, Hydro One Remote Communities Inc. continues to apply bundled rates to customers in remote communities. Hydro One Remote Communities Inc.’s business is run on a break-even basis. As a result, any net income or
loss in 

  
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the year is recorded in a regulatory variance account for inclusion in the calculation of future customer rates. 
 Hydro One Remote Communities Inc. filed its IRM application for 2012 rates on November 25, 2011. The OEB’s decision of March 22, 2012 approved an increase in basic rates for the
distribution and generation of electricity of 1.08% effective May 1, 2012. 
 Consistent with the OEB’s decision on Hydro One Networks
Inc.’s transmission, a separate application to move to U.S. GAAP as the basis for regulatory accounting and reporting was filed on December 16, 2011. On April 3, 2012 the OEB issued a decision approving the use of U.S. GAAP.

 On September 17, 2012, Hydro One Remote Communities Inc. filed a cost of service application for 2013 distribution rates. The
application requested an increase of 3.45% to customer rates for generation and distribution and an increase of approximately $7 million to annual rural and remote rate protection. 
 Rural and Remote Rate Protection 
 In approving electricity rates for a distributor
which delivers electricity to rural or remote consumers, the OEB is required to provide rate protection for prescribed classes of consumers, including those who received rural rate assistance prior to April 1, 1999, by reducing the rates that
would otherwise apply. 
 Since January 1, 2003, the amount of rate reduction for our rural consumers who occupy rural residential premises
is $127 million per year less the specific amounts established for distributors in three former remote communities. 
 In 2009, the OEB approved
an annual amount of rate protection of $27.5 million for our remote customers. The amount approved for Hydro One Remote Communities Inc. in 2009 is an annual amount until changed by the OEB. The OEB calculates it each year, but only resets it when
we ask them to. 
 Hydro One Remote Communities Inc. is requesting approval to establish annual rural and remote rate protection of $35 million
(an increase of approximately $7 million from the current approved amount of $27.5 million) in its current cost of service rate application. 

Rate Protection and Determination of Direct Benefits to Accommodate Renewable Energy Generation Facilities 

On December 21, 2011, the OEB has issued a decision and order setting the charge for Rural or Remote Electricity Rate Protection (“RRRP”)
for 2012. The OEB noted that any over or under recovery of the total RRRP amount in 2012 will be tracked in a variance account held by Hydro One Networks Inc. The OEB has determined that effective January 1, 2012, the RRRP charge to be
collected by the IESO shall remain at the current level of 0.13 cents per kilowatt-hour. The OEB has further determined that effective May 1, 2012, the RRRP charge to be collected by the IESO shall be reduced to 0.11 cents per kilowatt-hour.

 On December 20, 2012, the OEB issued a decision and order setting the charge for RRRP for 2013. The OEB determined that effective
January 1, 2013, the RRRP charge to be collected by the IESO shall be increased to 0.12 cents per kilowatt-hour. The RRRP charge used by rate regulated distributors to bill their customers shall continue to be 0.11 cents per kilowatt hour
effective January 1, 2013. 

  
 58  HYDRO ONE INC.

 REGULATION 

 

 The OEB Act, as amended by the GEA, now includes a new mechanism for rate protection whereby some
or all of the OEB-approved costs incurred by a distributor to make an eligible investment for the purpose of connecting or enabling the connection of renewable energy generation to its distribution system may be recovered from all provincial
ratepayers rather than solely from ratepayers of the distributor making the investment. Accordingly, on September 25, 2009, the OEB advised all LDCs and other interested parties of its intent to initiate a consultation process to address how
the OEB should determine what constitutes direct benefits that accrue to the consumers of a distributor which has incurred costs to make an eligible investment in its distribution system to accommodate a renewable energy generation facility. The OEB
issued a staff discussion paper on December 14, 2009 seeking input from distributors and other stakeholders on the proposed mechanism for allocating costs. The OEB’s policy is largely consistent with the approach that Hydro One Networks
Inc. took in the allocation of direct benefits and as such Hydro One has not resubmitted its allocation of direct benefits at this time. In June 2010, the OEB issued a report which recognizes the need for a framework that takes into account the
significant diversity of distributors in relation to the amount of renewable energy generation to be connected and the magnitude of the associated eligible investment. 
 Connection Cost Responsibility 
 The DSC assigns cost responsibility between a
distributor and a generator for connection of renewable energy generation facilities. There are three types of distribution assets associated with the connection of renewable energy generation: 

 

	•	 	 connection assets, 

  

	•	 	 expansion assets, and 

  

	•	 	 renewable enabling improvements. 

 Connection asset costs are borne by generators. 
 Distributors are required to fund the following:

  

	•	 	 all expansion costs identified in a plan, 

  

	•	 	 other generator-requested expansion costs up to a cap of $90,000/MW per project (the generator paying the rest), and 

 

	•	 	 all renewable enabling improvements. 

 We have made commitments to connect a number of generators under the terms of various agreements executed prior to discovering certain technical problems with these connections, which we could not
reasonably have foreseen at the time we entered into those agreements. The problems have caused or will cause power quality issues for our customers. Under the DSC, the generation proponents would normally bear the costs of resolving the connection
issues; however the costs are significant and also were not foreseen by the generators. Thus, the issue for our company is cost recovery of incremental costs associated with connecting these generators. We applied to the OEB for an exemption to
allow the costs to be incurred and recovered through the rate pool. In December 2010, the OEB decided that we should incur the costs, record them in deferral accounts, and apply for recovery in future rate applications, subject to the provision of
evidence of the reasonableness of the costs incurred. 
 Distribution System Code Exemption 

On April 19, 2011, we submitted an application to the OEB for six-month exemptions from certain sections of the DSC pertaining to timelines for
processing applications for, and for connecting, micro-embedded generators. The OEB released its decision and order on October 11, 2011, granting a six-month exemption. On April 10, 2012, Hydro One Networks Inc. informed the OEB that,
despite its best efforts, it cannot comply with these rules. 

  
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 Hydro One Networks Inc. cited the large volume of applications within Hydro One Networks Inc.’s
service territory and their sporadic nature, which have made the DSC timelines unmanageable. On May 15, 2012, the OEB announced a consultation process on policy review of micro-embedded generation connection issues. The scope of the
consultation includes the “appropriateness of timelines in the DSC”. On August 3, 2012, Hydro One Networks Inc. applied for extension of the previous exemption. On November 8, 2012, the OEB granted an exemption, ending the
earlier of August 3, 2013 or six months after the OEB concludes its consultation on micro-embedded generation issues. 

  
 60  HYDRO ONE INC.

 RISK FACTORS 

 

 RISK FACTORS 
 Ownership by the Province 
 The Province owns all of our outstanding shares. Accordingly,
the Province has the power to determine the composition of our Board and appoint the Chair, and influence our major business and corporate decisions. We and the Province have entered into a memorandum of agreement relating to certain aspects of the
governance of our company. Pursuant to such agreement, in September 2008 the Province made a declaration removing certain powers from our company’s directors pertaining to the off-shoring of jobs under the outsourcing arrangement with Inergi
LP. See “Interest of Management and Others in Material Transactions – Relationships with the Province and Other Parties – Memorandum of Agreement”. In 2009, the Province required Hydro One, among other entities, to adhere to
certain accountability measures regarding consulting contracts and employee travel, meal and hospitality expenses. The Province may require us to adhere to further accountability measures or may make similar declarations in the future, some of which
may have a material adverse effect on our business. Hydro One’s credit ratings may change with the credit ratings of the Province, to the extent the credit rating agencies link the two ratings by virtue of Hydro One’s ownership by the
Province. 
 Conflicts of interest may arise between us and the Province as a result of the obligation of the Province to act in the best
interests of the residents of Ontario in a broad range of matters, including the regulation of Ontario’s electricity industry and environmental matters, any future sale or other transaction by the Province with respect to its ownership interest
in our company, including any potential outcomes arising out of the recommendations of the Ontario Distribution Sector Review Panel’s report, the Province’s ownership of OPG, and the determination of the amount of dividend or proxy tax
payments. We may not be able to resolve any potential conflict with the Province on terms satisfactory to us which could have a material adverse effect on our business. 
 Regulatory Risk 
 We are subject to regulatory risks, including the approval by the OEB of
rates for our transmission and distribution businesses that permit a reasonable opportunity to recover the estimated costs of providing safe and reliable service on a timely basis and earn the approved rates of return. 

The OEB approves our transmission and distribution rates based on projected electricity load and consumption levels. If actual load or consumption
materially falls below projected levels, our net income for either, or both, of these businesses could be materially adversely affected. Also, our current revenue requirements for these businesses are based on cost assumptions that may not
materialize. There is no assurance that the OEB would allow rate increases sufficient to offset unfavourable financial impacts from unanticipated changes in electricity demand or in our costs. 

Our load could also be negatively affected by successful CDM programs. We are also subject to risk of revenue loss from other factors, such as economic
trends and weather. 
 We expect to make investments in the coming years to connect new renewable generating stations. There is the possibility
that we could incur unexpected capital expenditures to maintain or improve our assets particularly given that new 

  
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technology is required to support renewable generation and unforeseen technical issues may be identified through implementation of projects. The risk exists that the OEB may not allow full
recovery of such investments in the future. To the extent possible, we aim to mitigate this risk by ensuring prudent expenditures, seeking from the regulator clear policy direction on cost responsibility, and pre-approval of the need for capital
expenditures. 
 While we expect all of our expenditures to be fully recoverable after OEB review, any future regulatory decision to disallow or
limit the recovery of such costs would lead to potential asset impairment and charges to our results of operations, which could have a material adverse effect on our company. 
 In Ontario, the Market Rules mandate that we comply with the reliability standards established by NERC and NPCC. As a result, we will be required to comply with FERC’s definition of “bulk
electric system” unless we are granted an exemption which will allow the application of the new definition in a cost-effective manner. We will look for recovery for costs incurred in meeting the definition in our rates; however an adverse
decision on an exemption for recovery of costs could have an adverse effect on our company. 
 Risk Associated with Arranging Debt Financing

 We expect to borrow to repay our existing indebtedness and fund a portion of capital expenditures. We have substantial amounts of existing
debt, which mature between 2013 and 2016, including $600 million maturing in 2013 and $750 million maturing in 2014. We plan to incur capital expenditures of approximately $1.6 billion in 2013 and $1.8 billion in 2014. Cash generated from
operations, after the payment of expected dividends, will not be sufficient to fund the repayment of our existing indebtedness and capital expenditures. Our ability to arrange sufficient and cost-effective debt financing could be materially
adversely affected by numerous factors, including the regulatory environment in Ontario, our results of operations and financial position, market conditions, the ratings assigned to our debt securities by credit rating agencies and general economic
conditions. Any failure or inability on our part to borrow substantial amounts of debt on satisfactory terms could impair our ability to repay maturing debt, fund capital expenditures and meet other obligations and requirements and, as a result,
could have a material adverse effect on our company. 
 Risk Associated with Transmission Projects 

The amount of power that can flow through transmission networks is constrained due to the physical characteristics of transmission lines and operating
limitations. Within Ontario, new and expected generation facility connections, including those renewable energy generation facilities connecting as a result of the FIT program stemming from the GEA, and load growth have increased such that parts of
our transmission and distribution systems are operating at or near capacity. These constraints or bottlenecks limit the ability of our network to reliably transmit power from new and existing generation sources (including expanded interconnections
with neighbouring utilities) to load centres or meet customers’ increasing loads. As a result, investments have been initiated to increase transmission capacity and enable the reliable delivery of power from existing and future generation
sources to Ontario consumers. 
 In many cases, these investments are contingent upon one or more of the following approvals and/or processes:
environmental approval(s); 

  
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receipt of OEB approvals which can include expropriation; and appropriate consultation processes with First Nations and Métis. Obtaining OEB and/or EA approvals and carrying out these
processes may also be impacted by opposition to the proposed site of transmission investments which could adversely affect transmission reliability and/or our service quality, both of which could have a material adverse effect on our company.

 With the introduction on August 26, 2010, of the OEB’s competitive transmission project development planning process, in the
absence of a government directive, all interested transmitters will be required to submit a bid to the OEB for identified enabler facilities and network enhancement projects. Historically, we would have been awarded such projects through our rates
and Section 92, Leave to Construct, applications. The facilitation of competitive transmission could impact our future work program and our ability to expand our current transmission footprint. In addition, bid costs are only recoverable by the
successful proponent. This could have a material adverse effect on our company. 
 Asset Condition 

We continually monitor the condition of our assets and maintain, refurbish or replace them to maintain equipment performance and provide reliable service
quality. Our capital programs have been increasing to maintain the performance of our aging asset base. Execution of these plans is partially dependent on external factors, such as outage planning with the IESO and transmission-connected customers,
funding approval by the OEB, and supply chain availability for equipment suppliers and consulting services. In addition, opportunities to remove equipment from service to accommodate construction and maintenance are becoming increasingly limited due
to customer and generator priorities. 
 Adjustments to accommodate these external dependencies have been made in our planning process, and we
are focused on overcoming these challenges to execute our work programs. However, if we are unable to carry out these plans in a timely and optimal manner, equipment performance will degrade which may compromise the reliability of the provincial
grid, our ability to deliver sufficient electricity and/or customer supply security and increase the costs of operating and maintaining these assets. This could have a material adverse effect on our company. 

Work Force Demographic Risk 
 By the end
of 2012, approximately 18% of our employees were eligible for retirement and by 2013 there could be up to 20% eligible to retire. Accordingly, our success will be tied to our ability to attract and retain sufficient qualified staff to replace those
retiring. This will be challenging as we expect the skilled labour market for our industry to be highly competitive in the future. In addition, many of our employees possess experience and skills that will also be highly sought after by other
organizations both inside and outside the electricity sector. We are therefore focused on earlier identification and more rapid development of staff who demonstrate management potential. Moreover, we must also continue to advance our technical
training and apprenticeship programs and succession plans to ensure that our future operational staffing needs will be met. If we are unable to attract and retain qualified personnel, it could have a material adverse effect on our business.

 Environmental Risk 
 Our
health, safety and environmental management system is designed to ensure hazards and risks are identified and assessed, and controls are implemented to mitigate significant risks. This system includes a standing committee of our Board that has
governance over environmental matters 

  
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(see “Committees of the Board of Directors – Health, Safety and Environment Committee”). Given the territory that our system encompasses and the amount of equipment that we own, we
cannot guarantee, however, that all such risks will be identified and mitigated without significant cost and expense to our company. The following are some of the areas that may have a significant impact on our operations. 

We are subject to extensive Canadian federal, provincial and municipal environmental regulation. Failure to comply could subject us to fines and other
penalties. In addition, the presence or release of hazardous or other harmful substances could lead to claims by third parties and/or governmental orders requiring us to take specific actions such as investigating, controlling and remediating the
effects of these substances. We are currently undertaking a voluntary land assessment and remediation (“LAR”) program covering most of our stations and service centres. This program involves the systematic identification of any
contamination at or from these facilities, and, where necessary, the development of remediation plans for our company and adjacent private properties. Any contamination of our properties could limit our ability to sell these assets in the future.

 We record a liability for our best estimate of the present value of the future expenditures required to comply with Environment Canada’s
PCB regulations and for the present value of the future expenditures to complete our LAR program. The future expenditures required to discharge our PCB obligation are expected to be incurred over the period ending 2025 while our LAR expenditures are
expected to be incurred over the period ending 2020. Actual future environmental expenditures may vary materially from the estimates used in the calculation of the environmental liabilities on our balance sheet. We do not have insurance coverage for
these environmental expenditures. 
 Under applicable regulations, we expect to incur future expenditures to identify, remove and dispose of
asbestos-containing materials installed in some of our facilities. We record an asset retirement obligation for the present value of the estimated future expenditures. The estimates are based on an external, expert study of the current expenditures
associated with removing such materials from our facilities. Actual future expenditures may vary materially from the estimates used for the amount of the asset retirement obligation. 
 There is also risk associated with obtaining governmental approvals, permits, or renewals of existing approvals and permits related to constructing or operating facilities. This may require environmental
assessment or result in the imposition of conditions, or both, which could result in delays and cost increases. 
 We anticipate that all of our
future environmental expenditures will continue to be recoverable in future electricity rates. However, any future regulatory decision to disallow or limit the recovery of such costs could have a material adverse effect on our company. 

Scientists and public health experts have been studying the possibility that exposure to electric and magnetic fields emanating from power lines and
other electric sources may cause health problems. If it were to be concluded that electric and magnetic fields present a health risk, or governments decide to implement exposure limits, we could face litigation, be required to take costly mitigation
measures such as relocating some of our facilities or experience difficulties in locating 

  
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 RISK FACTORS 

 

 
and building new facilities. Any of these could have a material adverse effect on our company. 
 Risk of Natural and Other Unexpected Occurrences 
 Our facilities are exposed to the effects
of severe weather conditions, natural disasters, man-made events including cyber and physical terrorist type attacks and, potentially, catastrophic events, such as a major accident or incident at a facility of a third party (such as a generating
plant) to which our transmission or distribution assets are connected. Although constructed, operated and maintained to industry standards, our facilities may not withstand occurrences of this type in all circumstances. We do not have insurance for
damage to our transmission and distribution wires, poles and towers located outside our transmission and distribution stations resulting from these events. Losses from lost revenues and repair costs could be substantial, especially for many of our
facilities that are located in remote areas. We could also be subject to claims for damages caused by our failure to transmit or distribute electricity. Our risk is partly mitigated because our transmission system is designed and operated to
withstand the loss of any major element and possesses inherent redundancy that provides alternate means to deliver large amounts of power. In the event of a large uninsured loss we would apply to the OEB for recovery of such loss; however, there can
be no assurance that the OEB would approve any such applications, in whole or in part, which could have a material adverse effect on our net income. 
 Risk Associated with Information Technology Infrastructure 
 Our ability to operate
effectively in the Ontario electricity market is in part dependent upon us developing, maintaining and managing complex information technology systems which are employed to operate our transmission and distribution facilities, financial and billing
systems, and business systems. Our increasing reliance on information systems and expanding data networks increases our exposure to information security threats. We mitigate this risk through various methods including the use of security event
management tools on our power and business systems, by separating our power system network from our business system network, by performing scans of our systems for known cyber threats and by providing company-wide awareness training to our
personnel. We also engage the services of external experts to evaluate the security of our IT infrastructure and controls. We perform vulnerability assessments on our critical cyber assets and we ensure security and privacy controls are incorporated
into new IT capabilities. Although these security and system disaster recovery controls are in place, there can be no guarantee that there will not be system failures or security breaches. Upon occurrence, the focus would shift from prevention to
isolation, remediation and recovery until the incident has been fully addressed. Any such system failures or security breaches could have a material adverse effect on our company. 
 We are currently in the process of a planned phased replacement of key enterprise IT systems. The last phase of this project is underway and will replace our existing billing and customer system with a
new Customer Information System (CIS). With projects of this size and complexity, there is risk to the Company if the resulting solution encounters performance problems or calculation errors. Any such system problems could have a material adverse
effect on our Company. To mitigate this risk, extensive testing and user training is taking place. Testing includes performance, system integration, parallel billing (comparing legacy system bill calculation to the

  
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new system), and operational/business readiness. Since this system directly impacts our end customers, stringent test exit criteria must be met prior to placing it into production. 

Pension Plan Risk 
 We have a defined
benefit registered pension plan for the majority of our employees. Contributions to the pension plan are established by actuarial valuations which are filed with the Financial Services Commission of Ontario on a triennial basis. The most recently
filed valuation was prepared as at December 31, 2011 and was filed in May 2012. Our company contributed $148 million in respect of 2011 and approximately $160 million in respect of 2012 to its pension plan to satisfy minimum funding
requirements. An additional contribution of $3.8 million was also made in 2011 to complete the funding associated with the partial plan wind-up. Contributions beyond 2012 will depend on investment returns, changes in benefits and actuarial
assumptions and may include additional voluntary contributions from time to time. Nevertheless, future contributions are expected to be significant. A determination by the OEB that some of our pension expenditures are not recoverable from customers
could have a material adverse effect on our company, and this risk may be exacerbated as the quantum of required pension contributions increase. 
 Market and Credit Risk 
 Market risk refers primarily to the risk of loss that results from
changes in commodity prices, foreign exchange rates and interest rates. We do not have commodity risk. We do have foreign exchange risk as we enter into agreements to purchase materials and equipment associated with our capital programs and projects
that are settled in foreign currencies. This foreign exchange risk is not material. We could in the future decide to issue foreign currency denominated debt which we would anticipate hedging back to Canadian dollars, consistent with our
company’s risk management policy. We are exposed to fluctuations in interest rates as our regulated rate of return is derived using a formulaic approach. The OEB-approved adjustment formula for calculating ROE will increase or decrease by 50%
of the change between the current Long Canada Bond Forecast and the risk-free rate established at 4.25% and 50% of the change in the spread in 30-year “A”-rated Canadian utility bonds over the 30-year benchmark Government of Canada bond
yield established at 1.415%. We estimate that a 1% decrease in the forecasted long-term Government of Canada bond yield used in determining our rate of return would reduce our transmission business’ net income by approximately $19 million and
our Hydro One Networks Inc. distribution business’ net income by approximately $10 million. Our net income is adversely impacted by rising interest rates as our maturing long-term debt is refinanced at market rates. We periodically utilize
interest rate swap agreements to mitigate elements of interest rate risk. 
 Financial assets create a risk that a counter-party will fail to
discharge an obligation, causing a financial loss. Derivative financial instruments result in exposure to credit risk, since there is a risk of counter-party default. We monitor and minimize credit risk through various techniques, including dealing
with highly-rated counter-parties, limiting total exposure levels with individual counter-parties, and by entering into master agreements which enable net settlement and by monitoring the financial condition of counter-parties. We do not trade in
any energy derivatives. We do, however, have interest rate 

  
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 RISK FACTORS 

 

 
swap contracts outstanding from time to time. Currently, there are no significant concentrations of credit risk with respect to any class of financial assets. We are required to procure
electricity on behalf of competitive retailers and embedded LDCs for resale to their customers. The resulting concentrations of credit risk are mitigated through the use of various security arrangements, including letters of credit, which are
incorporated into our service agreements with these retailers in accordance with the OEB’s Retail Settlements Code. The failure to properly manage these risks could have a material adverse effect on our company. 

Labour Relations Risk 
 The substantial
majority of our employees are represented by either the PWU or the Society. Over the past several years, significant effort has been expended to increase our flexibility to conduct operations in a more cost efficient manner. Although we have
achieved improved flexibility in our collective agreements, including a reduction in pension benefits for Society staff hired after November 2005 similar to a previous reduction affecting management staff, we may not be able to achieve further
improvement. The existing collective agreement with the PWU will expire on March 31, 2013 and the existing Society collective agreement will expire on March 31, 2013. We face financial risks related to our ability to negotiate collective
agreements consistent with our rate orders. In addition, in the event of a labour dispute, we could face operational risk related to continued compliance with our licence requirements of providing service to customers. Any of these could have a
material adverse effect on our company. 
 First Nation and Métis Claims Risk 

Some of our current and proposed transmission and distribution lines may traverse lands over which First Nations and Métis have aboriginal, treaty
or other legal claims. Although we have a recent history of successful negotiations and consultations with First Nations and Métis in Ontario, some communities and/or their citizens have expressed an increasing willingness to assert their
claims through the courts, tribunals, or by direct action, which in turn can affect business activities. As a result, there exists uncertainty relating to business operations and project planning which could have an adverse effect on our company.

 Risk from Transfer of Assets Located on Reserves 
 The transfer orders by which we acquired certain of Ontario Hydro’s businesses as of April 1, 1999 did not transfer title to some assets located on Reserves. See “Interest of Management and
Others in Material Transactions – Relationships with the Province and Other Parties – Transfer Orders.” Currently, OEFC holds legal title to these assets and we manage them until we have obtained necessary authorizations to complete
the title transfer. To occupy Reserves, Hydro One must have valid permits issued by Her Majesty the Queen in the Right of Canada. For each permit, we must negotiate an agreement (in the form of a Memorandum of Understanding) with the First Nation,
OEFC and any members of the First Nation who have occupancy rights. The agreement includes provisions whereby the First Nation consents to the federal Department of Aboriginal Affairs and Northern Development issuing a permit. It is difficult to
predict the aggregate amount that we may have to pay, either on an annual or one-time basis, to obtain the required agreements from First Nations. However, we anticipate that the amount will exceed the approximately $943,000 that we paid in 2012.
OEFC will continue to hold these assets until we are able to negotiate agreements with First Nations and occupants. If we cannot 

  
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reach satisfactory agreements and obtain federal permits, we may have to relocate these assets to other locations at a cost that could be substantial. In a limited number of cases, it may be
necessary to abandon a line and replace it with diesel generation facilities. The costs relating to these assets could have a material adverse effect on our net income if we are not able to recover them in future rate orders. 

Risk Associated with Outsourcing Arrangement 
 Consistent with our strategy of reducing operating costs, we amended and extended our outsourcing services agreement with Inergi LP, effectively renewing the arrangement until February 28, 2015. See
“Description of the Business –Outsourcing Arrangement with Inergi LP.” If the agreement with Inergi LP is terminated for any reason, we could be required to incur significant expenses to transfer to another service provider, which
could have a material adverse effect on our business, operating results, financial condition or prospects. 
 Risk from Provincial Ownership
of Transmission Corridors 
 Pursuant to the Reliable Energy and Consumer Protection Act, 2002, the Province acquired ownership of our
transmission corridor lands underlying our transmission system. Although we have the statutory right to use the transmission corridors, we may be limited in our ability to expand our systems. Also, other uses of the transmission corridors by third
parties in conjunction with the operation of our systems may increase safety or environmental risks, which could have an adverse effect on our company. 

  
 68  HYDRO ONE INC.

 DIVIDENDS 

 

 DIVIDENDS 
 Dividends on our common shares and Series A preferred shares are declared at the discretion of our Board, and are recommended by our management based on our results of operations, maintenance of the
deemed regulatory capital structure, financial condition, cash requirements and other relevant factors, such as industry practice and shareholder expectations. 
 Our company’s policy is to declare and pay cash dividends on our common shares on the basis of a calculation involving our regulated net income net of preferred dividends and non-regulated net
income. Any factor that adversely affects our company’s net income would likely be reflected in our dividend payments. 
 We declared and
paid to the Province annual dividends on our outstanding 100,000 common shares totalling approximately $352 million in 2012 as compared with $150 million in 2011 and $10 million in 2010. We declared and paid to the Province a total annual cumulative
dividend on our outstanding 12,920,000 series A preferred shares of approximately $18 million in each of 2012, 2011 and 2010, which was calculated at a rate of $1.375 per annum per share, as stipulated in our company’s Articles of
Incorporation. In addition, we made payments in lieu of taxes to the OEFC in 2012 in the amount of approximately $197 million, as compared to $80 million in 2011. 

  
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 DESCRIPTION OF CAPITAL STRUCTURE 

 

 DESCRIPTION OF CAPITAL STRUCTURE 
 General Description of Capital Structure 
 The authorized share capital of our company
consists of an unlimited number of common shares (the voting shares of our company) and an unlimited number of preferred shares. As at December 31, 2012, 100,000 common shares and 12,920,000 series A preferred shares were issued and
outstanding, all of which are owned directly by the Province. 
 All of our company’s voting securities are held by the Province.
Accordingly, our company is controlled by the Province. 
 The common shares are not redeemable or retractable. Holders of our common shares are
entitled to one vote per share at meetings of the shareholders of the common shares and to receive dividends if, as, and when declared by the Board of our company. Holders of common shares are also entitled to participate, pro rata to their holding
of common shares, in any distribution of the assets of our company upon its liquidation, dissolution or winding-up. The series A preferred shares, as set forth in our Articles of Incorporation, entitle our company to redeem all or any part of these
shares subject to certain terms and conditions as set forth therein. These series A preferred shares are entitled to a dividend at a rate of $1.375 per annum per share. Our company has not issued any restricted securities. 

  
 70  HYDRO ONE INC.

 CREDIT RATINGS OF SECURITIES AND LIQUIDITY 

 

 CREDIT RATINGS OF SECURITIES AND LIQUIDITY 

The credit ratings assigned to our company’s debt securities by external rating agencies are important to our ability to raise capital and funding to
support our business operations. Maintaining strong credit ratings allows our company to access capital markets on competitive terms. A material downgrade of our credit ratings would likely increase our cost of funding significantly, and our ability
to access funding and capital through the capital markets could be reduced. Our company’s corporate credit ratings from approved rating organizations are as follows: 

 

					
	Rating Agency	  	Short-term Debt	  	Long-term Debt
			
	 Standard & Poor’s Rating Services Inc. (“S&P”)
	  	A-1	  	A+
			
	 DBRS Limited (“DBRS”)
	  	R-1 (middle)	  	A (high)
			
	 Moody’s Investors Services Inc. (“Moody’s”)
	  	Prime-1	  	A1

 The following information relating to credit ratings is based on information made available to the public by the rating
agencies. 
 Credit ratings are intended to provide investors with an independent measure of the credit quality of an issue of securities. The
rating agencies rate long-term debt instruments by rating categories ranging from a high of “AAA” to a low of “D” (“C” in the case of Moody’s). Long-term debt instruments which are rated in the A category by
S&P mean the obligor has a strong capacity to meet its financial commitments and obligations but are considered somewhat more susceptible to the adverse effects of changes in circumstances and economic conditions than obligations in higher rated
categories. S&P utilizes a “+” or a “-” modifier to indicate the relative standing within the rating category. Long-term debt instruments which are rated in the A category by DBRS are considered to be of a good credit
quality, with substantial capacity for the payment of financial obligations. Entities in the “A” category, however, are considered to be more vulnerable to future events, but qualifying negative factors are considered manageable. The
“high” modifier indicates relative standing within this rating category by DBRS. Long-term debt instruments which are rated in the A category by Moody’s are considered upper medium grade and are subject to low credit risk.
Moody’s applies numerical modifiers to each generic rating classification from Aa to Caa. The modifier 1 indicates a ranking in the higher end of that generic rating category. 
 The ratings mentioned above are not a recommendation to purchase, sell or hold our company’s debt securities and do not comment as to market price or suitability for a particular investor. There can
be no assurance that the ratings will remain in effect for any given period of time or that the ratings will not be revised or withdrawn entirely by any or all of S&P, DBRS and Moody’s at any time in the future if in their judgment
circumstances so warrant. 
 Our company has made payments to S&P, DBRS and Moody’s, in connection with the assignment of ratings to
our long-term debt and will make payments to S&P, DBRS and Moody’s in connection with the confirmation of such ratings for purposes of the offering of medium term notes in the future. 

  
 2012 ANNUAL
INFORMATION FORM  71 

 MARKET FOR SECURITIES 

 

 MARKET FOR SECURITIES 
 Our Debentures (7.35%) due 2030, Series 2 Notes (6.93%) due 2032, Series 4 Notes (6.35%) due 2034, Series 5 Notes (6.59%) due 2043, Series 9 Notes (5.36%) due 2036, Series 10
Notes (4.640%) due 2016, Series 11 Notes (5.00%) due 2046, Series 12 Notes (4.89%) due 2037, Series 13 Notes (5.18%) due 2017, Series 15 Notes (5.00%) due 2013, Series 17 Notes (6.03%) due 2039, Series 18 Notes
(5.49%) due 2040, Series 19 Notes (3.13%) due 2014, Series 20 Notes (4.4%) due 2020, Series 21 Notes (2.95%) due 2015, Series 22 Notes (Floating Rate 3-month BA + 0.40%) due 2015, Series 23 Notes (4.39%) due 2041, Series 24
Notes (4.00%) due 2051, Series 25 Notes (3.20%) due 2022, Series 26 Notes (3.79%) due 2062 and Series 27 Notes (Floating Rate 3-month BA + 0.37%) due 2016 are currently outstanding and are not listed on any exchange or similar market
for securities. 
 Trading Price and Volume 
 The debt securities issued by our company are not listed on a recognized exchange or quoted on a recognized quotation and trade reporting system. 
 Prior Sales 
 Our company issued the following tranches of medium term notes in 2012:

  

													
	Note	  	Principal Amount
(million) ($)	 	  	Sale Price ($) /
$100 principal
amount	 	  	Gross Proceeds ($)	 
				
	 Series 24 (4.00%) due 2051
	  	 	125	  	  	 	100.017	  	  	$	125,021,250	  
				
	 Series 25 (3.20%) due 2022
	  	 	300	  	  	 	99.924	  	  	$	299,772,000	  
				
	 Series 25 (3.20%) due 2022
	  	 	300	  	  	 	101.385	  	  	$	304,155,000	  
				
	 Series 26 (3.79%) due 2062
	  	 	75	  	  	 	99.978	  	  	$	74,983,500	  
				
	 Series 26 (3.79%) due 2062
	  	 	235	  	  	 	99.709	  	  	$	234,316,150	  
				
	 Series 27 (Floating Rate 3 month BA + 0.37%) due 2016
	  	 	50	  	  	 	100.000	  	  	$	50,000,000	  

  
 72  HYDRO ONE INC.

 DIRECTORS AND OFFICERS 
  

 DIRECTORS AND OFFICERS 
 Directors 
 The following table sets forth the name, municipality of residence and principal
occupation of each of our directors, as of December 31, 2012. 
  

					
	Name and Municipality of Residence	 	 	 	Principle Occupation
			
	James Arnett (2)	 		 	
	Toronto, Ontario	 		 	Chair of the Board of Directors of Hydro One Inc.
	Canada	 		 
	(Director and Chair from March 31, 2008 to December 8, 2008, and Director and Chair from February 17, 2009 to present)	 		 	
			
	Kathryn A. Bouey (1) (5) 
(6)	 		 	President,
	Toronto, Ontario	 		 	TBG Strategic Services Inc.
	Canada	 		 	Corporate Director
	(Director since March 30, 2007)	 		 	
			
	George Cooke (1) (4) 
(7)	 		 	Chief Executive Officer,
	Toronto, Ontario	 		 	The Dominion of Canada
	Canada	 		 	General Insurance Company
	(Director since January 25, 2010)	 		 	(Until December 31, 2012)
			
		 		 	Executive Vice President,
		 		 	E-L Financial Corporation Limited
		 		 	(Until June 30, 2012)
			
	Laura Formusa	 		 	 President and Chief Executive Officer,
 Hydro One Inc.
 (Until December 31, 2012)

	Toronto, Ontario	 		 
	Canada	 		 
	(Director since March 30, 2007, until December 31, 2012)	 		 
			
	Janet Holder (4) (5) 
(7)	 		 	Executive Vice President,
	Prince George, British Columbia	 		 	Western Access,
	Canada	 		 	Enbridge Inc.
	(Director since July 1, 2010)	 		 	

  
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	Don MacKinnon (4) (5)	  	President,
	Chatsworth, Ontario	  	Power Workers’ Union
	Canada	  	
	(Director since June 11, 2002)	  	
		
	Michael J. Mueller (1) (2) 
(6)	  	
	Tecumseh, Ontario	  	Corporate Director
	Canada	  	
	(Director since March 30, 2007)	  	
		
	Walter Murray (1) (3) 
(7)	  	
	Bracebridge, Ontario	  	Corporate Director
	Canada	  	
	(Director since November 10, 2005)	  	
		
	Robert L. Pace (2) (3) 
(7)	  	
	Glen Margaret, Nova Scotia	  	President and Chief Executive Officer,
	Canada	  	The Pace Group Ltd.
	(Director since March 30, 2007)	  	
		
	Yezdi Pavri (1) (6)	  	Corporate Director
	North York, Ontario	  	
	Canada	  	
	(Director since December 6, 2012)	  	
		
	Gale Rubenstein (2) (3) 
(4)	  	Partner, Goodmans LLP
	Toronto, Ontario	  	
	Canada	  	
	(Director since March 30, 2007)	  	
		
	Douglas E. Speers (3) (5) 
(6)	  	Corporate Director
	Coldwater, Ontario	  	
	Canada	  	
	(Director since November 10, 2005, Chair from December 8, 2008 to February 17, 2009)	  	

  

	(1)	Member of the Audit and Finance Committee 

	(2)	Member of the Corporate Governance Committee 

	(3)	Member of the Human Resources Committee 

	(4)	Member of the Regulatory and Public Policy Committee 

	(5)	Member of the Health, Safety and Environment Committee 

	(6)	Member of the Business Transformation Committee 

	(7)	Member of the Investment – Pension Committee 

  
 74  HYDRO ONE INC.

 DIRECTORS AND OFFICERS 
  

			
	 

 JAMES ARNETT
 Chair of the Board of Directors
 Hydro One
Inc.
	  	James Arnett was appointed Chair of Hydro One Inc. on March 31, 2008. Mr. Arnett has had a distinguished career as a senior executive, corporate director and lawyer.
Prior to his appointment as Chair of Hydro One Inc., during 2007 Mr. Arnett’s principal occupation was Counsel to Fraser Milner Casgrain LLP from which he retired on January 31, 2010. Mr. Arnett chaired the Province of Ontario’s 2007
Agency Review Panel that reviewed the way compensation is set for senior executives in Ontario’s electricity sector agencies, and how those agencies could work together more efficiently. He was special advisor to the Premier of Ontario on the
steel industry from 2004-2006 and on the automobile industry from 2008-2009. Mr. Arnett is a former president and CEO of Molson Inc. and between 1997 and 2000, he led Molson’s transformation from a diversified holding company to a focused
brewing company. Prior to that, he was a senior partner in a major Canadian law firm as the Toronto Corporate/Commercial Head and as resident partner in the firm’s Washington, D.C. office. He is a Past Chair of the Toronto East General
Hospital. Mr. Arnett holds a Bachelor of Arts degree and an LL.B from the University of Manitoba and an LL.M from the Harvard Law School.
		
	 

 KATHRYN A. BOUEY
 Director
	  	Kathryn A. Bouey is President of TBG Strategic Services Inc., a management consulting firm. From 2001 to 2005, Ms. Bouey was the Deputy Minister of the Management Board
Secretariat, Province of Ontario and previously held other senior management positions with the Province, including: Deputy Minister of Intergovernmental Affairs (1999-2001); and Assistant Deputy Minister, Corporate Services Group, Ministry of
Health and Long-Term Care (1997-1999). She is currently a Director of St. Joseph’s Health Centre. Previously, she held the position of Chair of the Ontario Civil Service Commission and has served on the boards of the Canadian Comprehensive
Auditing Foundation, Ontario Power Generation, the Ontario Financing Authority, the Ontario Pension Board, and Sheridan College Institute of Technology and Applied Learning. Ms. Bouey obtained a Master of Arts (Economics) from Carleton University in
1981 and was certified by the Institute of Corporate Directors in 2006. She has been a Director of our company since March 30, 2007.
		
	 

 GEORGE COOKE
 Director
	  	George L. Cooke is the former President and CEO, The Dominion of Canada General Insurance Company (“The Dominion”), a position he held from 1992 when he joined the
company to August 2012. In August 2012, Mr. Cooke retired from his role as President of the Dominion and continued to hold the position of Chief Executive Officer of the company until December 31, 2012. Prior to his appointment with The
Dominion, Mr. Cooke was Vice President (Ontario Division), S.A. Murray Consulting Inc. (a government relations consulting firm) between 1990 and 1992. His previous experience also includes Special Advisor, Policy to the Ontario Deputy Premier and
Treasurer (1989-1990), General Manager, Ontario Automobile Insurance Board (1988-1989), and positions with the OEB (1980-1988). Mr. Cooke obtained a Bachelor of Arts

  
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 DIRECTORS AND OFFICERS 

 

			
		  	degree (Hons.) in Political Studies (1975) and a Masters of Business Administration degree (1977) from Queen’s University, Kingston, Ontario. He also holds an Honorary Doctor
of Laws degree (1999) from Assumption University in Windsor. He is currently a member of the Board of Directors of: The Dominion of Canada General Insurance Company and Insurance Bureau of Canada. Mr. Cooke is also an Executive Vice President with
E-L Financial Corporation Limited, a position he will hold until June 30, 2013. Mr. Cooke has been a Director of our company since January 26, 2010.
		
	 

 LAURA FORMUSA
 President and Chief Executive Officer
 Hydro One Inc.

Director
	  	Laura Formusa was appointed President and Chief Executive Officer, Hydro One Inc., on November 23, 2007 and held the position until her recent retirement from the company on
December 31, 2012. Previously, Ms. Formusa served as the company’s acting President and Chief Executive Officer from December 8, 2006 until her appointment in November 2007. Ms. Formusa’s career spans more than 30 years at Ontario Hydro
and Hydro One Inc. She practised law in the areas of corporate/commercial, regulatory and environment and held various senior positions within the company until being appointed Hydro One’s General Counsel in 2003. Ms. Formusa earned her
Bachelor of Laws degree at Osgoode Hall Law School and was admitted to the Law Society of Upper Canada in 1980, following her call to the Bar of Ontario. Ms. Formusa was a Trustee to the Banting Research Foundation and a member of the Board of
Directors of DHX Media Ltd. until October, 2012 and Plug’nDrive Ontario until December, 2012. Ms. Formusa was also certified by the Institute of Corporate Directors in 2010 and has been a Director of our company since March 30, 2007. Ms.
Formusa retired on December 31, 2012.
		
	 

 JANET HOLDER
 Director
	  	Janet Holder was appointed Executive Vice President, Western Access, Enbridge Inc. on September 1, 2011 and is responsible for the overall leadership of the
Corporation’s Northern Gateway Pipelines Project. Previously, Ms. Holder was President, Gas Distribution of Enbridge Inc., a role she held since January 2008. She has spent much of her career in Gas Distribution and also held senior roles with
Enbridge in Corporate and Liquids Pipelines. She has held a number of executive positions with Enbridge’s various businesses since 1992 including: Vice President, Support Services, Enbridge Pipelines Inc. (2006-2008); and Vice President, Market
Services, Enbridge Inc. (2004-2006). Ms. Holder obtained a Bachelor of Science degree (Chemical Engineering) from the University of New Brunswick (1979) and a Master of Business Administration degree (1982) from McMaster University, Hamilton,
Ontario. She is currently a member of the Board of Directors of the Saint Elizabeth Health Care Foundation (Chair and Director) and Saint Elizabeth Health Care Governance Board. Ms. Holder is a former member of the Board of Enbridge Gas Distribution
Inc. She is also the 2011 United Way Toronto Campaign Chair. Ms. Holder also holds a Chartered Director’s designation (McMaster University) and has been a Director of our company since July 1,
2010.

  
 76  HYDRO ONE INC.

 DIRECTORS AND OFFICERS 
  

			
	 

 DON MACKINNON
 Director
	  	Don MacKinnon has been President of the PWU, an electricity industry workers union, since May 2000 and a lineman by trade since 1971. He was Vice-President of the Union for
11 years prior to being elected President. In 2000, Mr. MacKinnon was appointed by the Minister of Energy, Science and Technology to the Electricity Transition Committee. He was a member of the Board of Directors of the Electrical and Utilities
Safety Association and the Retail Management Board of Ontario Hydro. In 2003, Mr. MacKinnon was appointed by the Minister of Energy to the government’s Electricity Conservation and Supply Task Force. In 2005, Mr. MacKinnon became a member of
the Canadian Nuclear Association’s Board of Directors. In 2007, he became a member of the National Round Table on the Environment and the Economy, and in October 2011 became a member of the Advisory Committee of the Centre for Labour Management
Relations at Ryerson University. Most recently, Mr. MacKinnon joined the Board of Plug’nDrive Ontario and became a member of the Board Advisory Council of the Waterloo Institute for Sustainable Energy (WISE), University of Waterloo. Mr.
MacKinnon has been a Director of our company since June 11, 2002.
		
	 

 MICHAEL J. MUELLER Director
	  	Michael J. Mueller is a former Global leader of PricewaterhouseCoopers’ (PwC) Private Company Services/Middle Market Practice and a former member of PwC’s Global
Audit Leadership Team, Global Advisory Leadership Team and the Global Markets Council. Prior to his retirement from PwC in July 2007, his previous positions with the firm also included National Managing Partner for Canada and Senior Relationship
Partner for a number of the firm’s most significant clients. He is also a Chartered Accountant, and a Chartered Business Valuator. Until 2009, he was a Certified Insolvency Practitioner. In December 2008, Mr. Mueller was appointed to the
Ontario Economic Advisory Panel by the Minister of Finance of Ontario and in July 2010 was appointed as a member of the Board of Directors of SMART Technologies Inc. Mr. Mueller’s past community involvement includes: member of the Board of
Governors of the Stratford Shakespearean Festival of Canada; President of the Windsor Symphony Society; President, Better Business Bureau of Windsor and Essex Counties; and is a current Director of the Windsor-Essex Economic Development Commission,
Chair of the Odette School of Business – Advisory Board, University of Windsor and a member of Caesars Windsor, Compliance Committee. He has been a Director of our company since March 30, 2007.
		
	 

 WALTER MURRAY
 Director
	  	Walter Murray is a former Vice-Chairman and member of the Executive Committee of RBC Capital Markets, an international corporate and investment bank. Prior to his retirement
from the RBC Royal Bank in April 2005, his 38-year career included Senior Executive Investment Banking responsibility for overseeing and directing all financial and advisory activity with a portfolio of major Canadian and International accounts;
Executive head of Corporate Banking activities across Canada, and several other Executive postings, including serving as Regional Executive for RBC’s Midwestern USA Corporate Banking operations. Mr. Murray has been a Director of our company
since November 10, 2005. 

  
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 DIRECTORS AND OFFICERS 

 

			
	 

 ROBERT L. PACE
 Director
	  	Robert L. Pace Pace is the President and Chief Executive Officer of The Pace Group Ltd. The Pace Group owns and operates a number of companies across Atlantic Canada,
including: Maritime Broadcasting System Ltd., a 24 radio station group; MBS Realty Ltd.; and Shredder’s. He began his professional career with the Halifax law firm Chandler Moore, where he practiced family and commercial law. Between 1981 and
1984, Mr. Pace served as Atlantic Advisor to the Prime Minister of Canada. Mr. Pace is currently a member of the Board of Directors of Canadian National Railway Company; Canadian Health Care Consulting Services Ltd.; High Liner Foods Incorporated;
the Atlantic Salmon Federation; the Public Gardens Restoration Committee (Halifax); and the Walter and Duncan Gordon Foundation. Mr. Pace was called to the Nova Scotia Bar in 1981 following the completion of his Bachelor of Laws degree at Dalhousie
University, where he also completed an MBA in 1977. He has been a Director of our company since March 30, 2007.
		
	 

 YEZDI PAVRI
 Director
	  	Yezdi Pavri is a Chartered Accountant, a former Vice-Chairman (June 2010 – June 2012), and a former Toronto Managing Partner (June 2004 – May 2010) of Deloitte
Canada, a leading professional services firm for audit, tax, consulting and financial advisory services. Mr. Pavri’s experience with Deloitte Canada has included overall responsibility for a number of the firm’s key clients in the
financial, retail and governmental sectors. Between 1990-2004, Mr. Pavri was National Managing Partner for Deloitte Canada’s Enterprise Risk Services group. Mr. Pavri holds a B. Technology from the Indian Institute of Technology (Aeronautical
Engineering) 1972; a M.Sc. from the Imperial College, London University (Thermal Power Engineering) 1974; and obtained his Chartered Accountant accreditation in 1979 while he was an accountant with Binder Hamlyn, Chartered Accountants, London, UK
(1974-1979). In 1979, Mr. Pavri joined Touche Ross in Toronto as an accountant. He is a Fellow of the Institute of Chartered Accountants in England and Wales, and is also a Fellow of the Institute of Chartered Accountants of Ontario. Mr. Pavri is
currently the Chair of the Board of Trustees of the United Way of Toronto. He has also served as the Treasurer of the Board of the Toronto Region Immigrant Employment Council, and was a member of the Board of the Canada – India Business Council
and the Canadian Paralympic Foundation. He has been a Director of our company since December 6, 2012.
		
	 

 GALE RUBENSTEIN Director
	  	Gale Rubenstein is a partner of the law firm Goodmans LLP and a member of the firm’s Executive Committee. She practices law primarily in the areas of commercial
insolvency and restructuring with emphasis on financial institutions, both domestic and international, and on pension restructurings. Ms. Rubenstein was senior counsel to the liquidators of numerous financial institutions and has been counsel to the
Superintendent of Financial Institutions (Canada) and the Superintendent of Financial Services (Ontario). She has authored numerous papers on the insolvency of insurance companies and banks, and is update author of LexisNexis Canada’s
Insurance

  
 78  HYDRO ONE INC.

 DIRECTORS AND OFFICERS 
  

			
		  	Companies Act: Legislation and Commentary. She obtained her Bachelor of Law degree from Osgoode Hall Law School and is a current Director of the Insolvency Institute of Canada; a
member of Insol International; and a Director of Osgoode Hall Alumni Association. She has been a Director of our company since March 30, 2007.
		
	 

 DOUGLAS E. SPEERS Director
	  	Douglas E. Speers is the former Chairman and Director of Emco Corporation, a leading Canadian distributor of building materials for the residential, commercial and industrial
construction markets. Prior to his appointment as Chairman of Emco Corporation, Mr. Speers was Emco’s President and CEO from 1997 – 2004. Between 1971 and 1988, he held several senior positions with Imperial Oil Ltd. in Canada and Exxon
International in New York City. Mr. Speers is a Professional Engineer –Province of Ontario, a member of the Advisory Board of the Richard Ivey School of Business, and past Chair and Director of the Ivey Management Services Company. He is a
member of a board of a privately-held company and has been a Director of our company since November 10, 2005.

 Each director is elected annually to serve for one year or until his or her successor is elected or appointed.

 Information Regarding Certain Directors 
 Walter Murray was a director of Ivernia Inc. (“Ivernia”) when it was the subject of a temporary “management and insider cease trade order” issued by the OSC on May 22, 2003 as a
result of a delay in filing audited annual consolidated financial statements for the 2002 financial year and certain other disclosure documents within the periods required by Canadian securities laws. The required filings were delayed as a result of
continuing negotiations regarding a joint venture and the obtaining of financing for Ivernia, the outcome of which would impact the presentation of Ivernia’s financial statements. All outstanding disclosure filings were completed and the cease
trade order expired on July 23, 2003. 

  
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 Executive Officers 
 The following table sets forth the name, municipality of residence and position of each of our executive officers as of December 31, 2011. 

 

			
	Name and Municipality of Residence	  	Position With Our Company
		
	James Arnett	  	Chair of the Board of Directors of Hydro One Inc.
	Toronto, Ontario	  
	Canada	  	
		
	Laura Formusa	  	President and Chief Executive Officer
	Toronto, Ontario	  	
	Canada	  	
		
	Sandy Struthers	  	Executive Vice President and Chief Financial Officer
	Toronto, Ontario	  
	Canada	  	
		
	Joseph Agostino	  	General Counsel
	Toronto, Ontario	  	
	Canada	  	
		
	Myles D’Arcey	  	Senior Vice President,
	Toronto, Ontario	  	Customer Operations
	Canada	  	
		
	Nairn McQueen	  	Senior Vice President,
	Dundas, Ontario	  	Engineering & Construction Services
	Canada	  	
		
	Carmine Marcello	  	Executive Vice President, Strategy
	Thornhill, Ontario	  	
	Canada	  	
		
	Wayne Smith	  	Senior Vice President, Grid Operations
	Toronto, Ontario	  	
	Canada	  	
		
	Peter Gregg	  	Executive Vice President, Operations
	Oakville, Ontario	  	
	Canada	  	

  
 80  HYDRO ONE INC.

 DIRECTORS AND OFFICERS 
  

			
	John Fraser	  	Senior Vice President,
	Mississauga, Ontario	  	Internal Audit & Chief Risk Officer
	Canada	  	
		
	John Macnamara	  	Vice President,
	Waterdown, Ontario	  	Health, Safety & Environment
	Canada	  	
		
	Robert Cultraro	  	Senior Vice President,
	Pickering, Ontario	  	Chief Investment & Pension Officer
	Canada	  	

  

							
	

	  	 James Arnett’s

biographical information is presented above under “Directors”.
	  	

	  	 Laura Formusa’s

biographical information is presented above under “Directors”.

	JAMES ARNETT	  		  	LAURA FORMUSA	  	
	Chair of the Board of Directors Hydro One Inc.	  		  	President and Chief Executive Officer	  	

  

			
	 

 SANDY STRUTHERS
 Executive Vice President

and Chief Financial Officer
	 	Sandy Struthers was appointed as Executive Vice President and Chief Financial Officer effective November 1, 2010. Prior to this, Mr. Struthers was Senior
Vice President and Chief Financial Officer. Mr. Struthers joined Hydro One in 2000 as a Director in the Finance area and has held a number of senior positions in Finance, including Director, Financial Strategy and Director, Merger & Acquisitions
Finance. In 2005, he was appointed to the position of Chief Information Officer where he implemented a number of significant advancements in our company’s IT infrastructure. Prior to joining Hydro One, Mr. Struthers was a partner in a national
accounting firm.
	 
		
	 

 JOSEPH AGOSTINO
 General Counsel
	 	Joseph Agostino was appointed as General Counsel on December 13, 2007, after having served as Acting General Counsel since December 8, 2006. On November 24, 2011, Mr.
Agostino was appointed as the Chief Compliance Officer for Hydro One and its subsidiaries. He joined Ontario Hydro in 1995 and has previously held the position of Assistant General Counsel of Hydro One Networks
Inc.

  
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 MYLES D’ARCEY
 Senior Vice President
 Customer Operations
	 	Myles D’Arcey was appointed as Senior Vice President, Customer Operations of Hydro One Networks Inc. on May 1, 2005. Mr. D’Arcey is also President and Chief
Executive Officer of Hydro One Remote Communities Inc. He joined Ontario Hydro in 1978 and has held the position of Vice President, Station Services of Hydro One Networks Inc.
		
	 

 NAIRN MCQUEEN
 Senior Vice President Engineering & Construction Services
	 	Nairn McQueen was appointed as Senior Vice President, Engineering & Construction Services effective April 15, 2009 after serving as Vice President, Engineering &
Construction Services of Hydro One Networks Inc. from August 28, 2002. Prior to joining Hydro One Network Services Inc. in 2000 as Director of Engineering, Mr. McQueen was V.P., Engineering and Project Management Services for Agra
Monenco.
		
	 

 CARMINE MARCELLO
 Executive Vice President
 Strategy
	 	Carmine Marcello was appointed as Executive Vice President, Strategy, effective November 1, 2010. Prior to this, Mr. Marcello was Senior Vice President, Asset Management and
Corporate Projects of Hydro One Networks Inc. effective April 15, 2009 after serving as Vice President, Asset Management from March 6, 2009 and Vice President, Corporate Projects of Hydro One Networks Inc. from March 21, 2007. Mr. Marcello joined
Ontario Hydro in 1987 and has held a number of senior positions including Director, System Investment and Director, Ontario Grid Control Centre Transformation.
		
	 

 WAYNE SMITH
 Senior Vice President
 Grid Operations
	 	Wayne Smith was appointed Senior Vice President, Grid Operations of Hydro One Networks Inc. effective April 15, 2009 after serving as Vice President, Grid Operations of Hydro
One Networks Inc. from January 1, 2005. He joined Ontario Hydro in 1980 and has held the position of Director of Investment Planning in Asset Management of Hydro One Networks Inc.

  
 82  HYDRO ONE INC.

 DIRECTORS AND OFFICERS 
  

			
	 

 PETER GREGG
 Executive Vice President Operations
	 	Peter Gregg was appointed Executive Vice President, Operations, effective November 1, 2010. Prior to this, he was Senior Vice President, Corporate & Regulatory
Affairs of Hydro One Networks Inc. on April 1, 2009. Mr. Gregg joined Hydro One Networks Inc. in 2004 as Vice President, Corporate Affairs and was appointed as Vice President, Executive Office in 2005 and then Vice President, Corporate and
Regulatory Affairs in early 2007. Prior to joining Hydro One Networks, Mr. Gregg was responsible for Corporate Affairs and Communications at the Greater Toronto Airport Authority.
		
	 

 JOHN FRASER
 Senior Vice President

Internal Audit & Chief Risk Officer
	 	John Fraser was appointed Vice President, Internal Audit & Chief Risk Officer on May 1, 2003. Prior to joining Hydro One Networks Inc. on May 12, 1999, he was Senior
Vice President, Quality Assurance, Newcourt Credit Group Inc. He has previously held the positions of General Auditor of Ontario Hydro Services Company Inc., General Auditor and Chief Risk Officer of Ontario Hydro Services Company Inc., and General
Auditor and Chief Risk Officer of Hydro One Networks Inc.
		
	 

 JOHN MACNAMARA
 Vice President
 Health, Safety & Environment
	 	John Macnamara was appointed Vice President, Health, Safety & Environment on May 4, 2009. Prior to joining Hydro One Networks Inc. in 2009 as Vice President, Health,
Safety & Environment, Mr. Macnamara was Global Vice President, Health and Safety and Co-chair of Global Joint Health and Safety Committee at Arcelor Mittal.
		
	 

 ROBERT CULTRARO
 Senior Vice President

Chief Investment & Pension Officer
	 	Robert Cultraro was appointed Senior Vice President and Chief Investment & Pension Officer effective June 1, 2011. Prior to this, Mr. Cultraro was Hydro One’s
acting Vice President, Pension Fund. Mr. Cultraro joined Hydro One on January 2, 2006 as Director, Pension Fund.

  
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 For a discussion of the restructuring of our company effective January 1, 2013, please see
“General Development of the Business – Recent Developments at Hydro One”. 
 There is no family relationship between any director
or executive officer and any other director or executive officer. 
 Indebtedness of Directors and Executive Officers 

No director, executive officer, employee, former director, former executive officer or former employee or associate of any director or executive officer
of Hydro One or any of its subsidiaries had any outstanding indebtedness to Hydro One or any of its subsidiaries except routine indebtedness or had any indebtedness that was the subject of a guarantee, support agreement, letter of credit or other
similar arrangement or understanding provided by Hydro One or any of its subsidiaries. 

  
 84  HYDRO ONE INC.

 INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS 

 

 INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS 

Relationships with the Province and Other Parties 
 Overview 
 The Province owns all of our outstanding shares. As a result, the Province has
the power to control all governance decisions affecting us, including the composition of our Board. Accordingly, the Province exercises control over our policies, the acquisition or disposition of assets, the incurrence of further debt and the
payment of dividends to holders of our common and preferred shares. 
 The OEB is the principal regulator of Ontario’s electricity
industry. The Province appoints the board members of the OEB and fills any vacancies on the OEB. The OEB is obligated to implement approved directives of the Province concerning general policy and objectives to be pursued by the OEB and other
directives aimed at addressing existing or potential abuses of market power by industry participants. The IESO directs the operation of our transmission system. The Board of Directors of the IESO, other than its Chief Executive Officer, is appointed
by the Province in accordance with the regulations in effect from time to time under the Electricity Act. 
 The OPA is mandated to
forecast supply and demand of electricity over the medium and long term and to conduct planning and implement measures to meet the supply and demand needs. Its Board of Directors is appointed by the Province. 

Transfer Orders 
 The transfer orders
pursuant to which we acquired Ontario Hydro’s electricity transmission, distribution and energy services businesses as of April 1, 1999 did not transfer any asset, right, liability or obligation where the transfer would constitute a breach
of the terms of any such asset, right, liability or obligation or a breach of any law or order. The transfer orders also did not transfer title to some assets located on Reserves. The transfer of title to these assets did not occur because
authorizations originally granted by the Canadian Minister of Indian and Northern Affairs for the construction and operation of these assets could not be transferred without the consent of such Minister and the relevant First Nation or, in several
cases, because the authorizations had either expired or had never been properly issued. These assets consist primarily of approximately 70 km of transmission lines and distribution lines used to deliver electricity on Reserves (of which 14 km of
lines are used solely for serving customers off the Reserves). OEFC holds these assets. 
 We are obligated under the transfer orders to manage
both the assets held in trust until we have obtained all consents necessary to complete the transfer of title to these assets to us and the assets otherwise retained by OEFC that relate to our businesses. We have entered into an agreement with OEFC
under which we are obligated, in managing the assets, to take instructions from OEFC if our actions could have a material adverse effect on it. OEFC has retained the right to take control of and manage the assets, although it must notify and consult
with us before doing so and must exercise its powers relating to the assets in a manner that will facilitate the operation of our businesses. The consent of OEFC is also required prior to any disposition of these assets. 

The Province also transferred officers, employees, assets, liabilities, rights and obligations of Ontario

  
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Hydro in a similar manner to its other successor corporations. These transfer orders include a dispute resolution mechanism to resolve any disagreement among the various transferees with respect
to the transfer of specific assets, liabilities, rights or obligations. 
 The transfer orders do not contain any representations or warranties
from the Province or OEFC with respect to the transferred officers, employees, assets, liabilities, rights and obligations. Furthermore, under the Electricity Act, OEFC was released from liability in respect of all assets and liabilities
transferred by the transfer orders, except for liability under our indemnity from OEFC as discussed below. By the terms of the transfer orders, each transferee indemnifies OEFC with respect to any assets and liabilities not effectively transferred,
and is obligated to take all reasonable measures to complete the transfers where the transfers were not effective. 
 Indemnities

 OEFC indemnified us with respect to the failure of the transfer orders to transfer any asset, right or thing or any interest therein
related to our business to us and some of our subsidiaries, some adverse claims or interests of third parties or based on title deficiencies arising from the transfer orders, except for some claims and rights of the Crown, and claims related to any
equity account previously referred to in the financial statements of Ontario Hydro including amounts relating to any judgment, settlement or payment in connection with litigation initiated by some utilities commissions. The Province has
unconditionally and irrevocably guaranteed to us and our subsidiaries the payment of all amounts owing by OEFC under its indemnity. 
 The
indemnity specifically excludes any matter for which we have agreed or are required to indemnify OEFC pursuant to or in connection with any transfer order. It also excludes any claim related to any aboriginal title or rights or the absence of a
permit, right-of-way, easement or similar right in respect of Reserves. It also excludes any payment made, or loss, expense or liability incurred by us as a result of the failure of a transfer order to transfer any asset of Ontario Hydro described
in the provisions of the transfer order relating to ineffective transfers. 
 The indemnity does not cover the first $10,000 in value of each
claim and only applies to the amount by which the total of all claims exceeds $10 million. We are obliged to pay OEFC a fee for the indemnity of $5 million per year until such time as the parties agree that the indemnity should be terminated. We
anticipate that we will require the indemnity until all indemnifiable claims have been identified and finally determined by a non-appealable court order. The indemnity ceases to be available to any of our subsidiary corporations if we cease to
control them unless the cessation of ownership results from the sale of the shares of a subsidiary in connection with the enforcement of security on such shares by an arm’s-length creditor of Hydro One. The indemnity can be assigned under some
conditions with the consent of the Minister of Finance. 
 The Province has also agreed to indemnify the directors of Hydro One for any
liabilities reasonably incurred by them in respect of any civil, criminal or administrative action or proceeding to which they are made a party to the extent that these liabilities result from a claim or determination that their approval of the
indemnity by OEFC constituted a breach of their duty to exercise the care, diligence or skill that a reasonably prudent person would exercise in comparable circumstances. 

  
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 INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS 

 

 We have indemnified OEFC in respect of the damages, losses, obligations, liabilities, claims,
encumbrances, penalties, interest, deficiencies, costs and expenses arising from matters relating to our business and any failure by us to comply with our obligations to OEFC under agreements dated as of April 1, 1999. These obligations include
obligations to employ the employees transferred to us under the transfer orders, make and remit employee source deductions, i.e., tax withholding amounts, and employer contributions, manage the real and personal properties which OEFC continues to
hold in trust or otherwise and take any necessary action to transfer all of these properties to us, to pay realty taxes and other costs, provide access to books and records and to assume other responsibilities in respect of the assets held by OEFC
in trust for us. 
 Operational Matters 
 Hydro One receives its revenues, which are in part collected by the IESO from customers, in accordance with the rules established under the Electricity Act and the OEB Act from time to time.

 Hydro One and the IESO have entered into an operating agreement, which took effect in May 2002, setting out the specific responsibilities of
both parties relating to the provision of transmission service. Hydro One also purchases power from the IESO administered spot market. 
 Hydro
One has service agreements with OPG. These services include field, engineering, logistics and telecommunications. 
 Payments in Lieu of
Corporate Taxes 
 We and our subsidiaries are exempt from taxes under the Income Tax Act (Canada) and the Corporations Tax Act
(Ontario) and the Taxation Act, 2007 (Ontario) because we are wholly-owned by the Province, and each of our subsidiaries is, in turn, wholly owned (directly or indirectly) by us. However, pursuant to the Electricity Act, we and
each of our subsidiaries are required to pay amounts to OEFC, which are referred to as payments in lieu of corporate taxes or proxy taxes, in respect of each taxation year, generally equal to the amount of tax that we would be liable to pay under
the Income Tax Act (Canada) and for the taxation years ending prior to January 1, 2009, the Corporations Tax Act (Ontario) and the Taxation Act, 2007 (Ontario) thereafter if we were not exempt from taxes thereunder.

 Memorandum of Agreement 
 We
entered into a memorandum of agreement with the Province in March 2008 relating to our mandate, responsibilities, performance expectations and executive compensation. Under this agreement, we must prepare investment plans for new transmission and
distribution projects and prioritize investments in transmission and distribution capacity to support projects necessary to maintain ongoing grid security and reliability. This agreement also requires that we undertake special initiatives
communicated from time to time by the Province by way of unanimous shareholder agreement or declaration in accordance with the provisions of the Business Corporations Act (Ontario). Additionally, this agreement requires that we obtain
approval from the Province in advance of any proposal to issue or transfer shares in Hydro One or its subsidiaries, any major transaction, including the sale of assets, which would potentially have a material effect on the financial interest of the
Province or our ability to make payments to OEFC or payments in lieu of corporate taxes (proxy taxes) under the Electricity Act. 

Effective September 24, 2008, the Province made a declaration pursuant to the memorandum of

  
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agreement and Section 108 of the Business Corporations Act (Ontario) (the “Shareholder Directive”) pertaining to off-shoring of jobs under the outsourcing arrangement with
Inergi LP (the “Inergi Agreement”). The declaration allows the Province to assume all decision-making power in respect of the off-shoring of jobs under the Inergi Agreement and removes these powers from the Board. The directors and
officers of Hydro One are charged with performing that which is necessary to carry out the intention of the Shareholder Directive. 
 Effective
April 19, 2011, the Province made a declaration preventing our company from seeking cost recovery through the regulatory process for the upgrades from either Micro FIT or small-scale FIT generators, whether directly or indirectly, for costs
related to investment and expenditures made, or required to be made in order to appropriately fund the upgrades at up to 15 transmission stations pursuant to the February 28, 2011 licence condition amendments made to Hydro One Networks
Inc.’s transmission licence. 
 Copies of the memorandum of agreement and the shareholder directives have been filed with the securities
regulatory authorities in each province of Canada and are available at www.sedar.com. 

  
 88  HYDRO ONE INC.

 TRUSTEES AND REGISTRARS 
  

 TRUSTEES AND REGISTRARS 
 The trustee and registrar for our company’s debt securities is Computershare Trust Company of Canada, located in Toronto, Ontario. 
 The U.S. trustee and registrar for certain of our company’s debt securities is Bank of Nova Scotia Trust Company of New York located in New York, New York. 

  
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 MATERIAL CONTRACTS 
 The following are the only material contracts that we have entered into since January 1, 2002 that remain in effect, other than contracts entered into by us in the ordinary course of business:

  

			
	(a) (i)	  	a third supplemental trust indenture dated as of January 31, 2003 relating to the issuance of Series 4 Notes in the aggregate principal amount of $1,000,000,000, of which
$200,000,000 was drawn down on January 31, 2003, $120,000,000 was drawn down on June 25, 2004 and $65,000,000 was drawn down on August 24, 2004, pursuant to the Trust Indenture dated as of June 4, 2001 between Hydro One and
Computershare Trust Company of Canada (the “Trust Indenture”);
		
	(ii)	  	a fourth supplemental trust indenture dated as of April 22, 2003 relating to the issuance of Series 5 Notes in the aggregate principal amount of $1,000,000,000, of which
$250,000,000 was drawn down on April 22, 2003 and $65,000,000 was drawn down on August 20, 2004, pursuant to the Trust Indenture;
		
	(iii)	  	an eighth supplemental indenture dated as of May 19, 2005 relating to the issuance of Series 9 Notes in the aggregate principal amount of $1,000,000,000, of which $350,000,000
was drawn down on May 19, 2005 and $250,000,000 was drawn down on April 24, 2006, pursuant to the Trust Indenture;
		
	(iv)	  	a ninth supplemental trust indenture dated as of March 3, 2006 relating to the issuance of Series 10 Notes in the aggregate principal amount of $1,000,000,000, of which
$300,000,000 was drawn down on March 3, 2006 and $150,000,000 was drawn down on August 22, 2006, pursuant to the Trust Indenture;
		
	(v)	  	a tenth supplemental trust indenture dated as of October 19, 2006 relating to the issuance of Series 11 Notes in the aggregate principal amount of $1,000,000,000, of which
$75,000,000 was drawn down on October 19, 2006, and $250,000,000 was drawn down on September 13, 2010, pursuant to the Trust Indenture;
		
	(vi)	  	an eleventh supplemental trust indenture dated as of March 13, 2007 relating to the issuance of Series 12 Notes in the aggregate principal amount of $1,000,000,000, of which
$400,000,000 was drawn on March 13, 2007, pursuant to the Trust Indenture;
		
	(vii)	  	a twelfth supplemental trust indenture dated as of October 18, 2007 relating to the issuance of Series 13 Notes in the aggregate principal amount of $1,000,000,000, of which
$300,000,000 was drawn down on October 18, 2007 and $300,000,000 was drawn down on March 3, 2008, pursuant to the Trust Indenture;
		
	(viii)	  	a fourteenth supplemental trust indenture dated as of November 10, 2008 relating to the issuance of Series 15 Notes in the aggregate principal amount of $1,000,000,000, of
which $400,000,000 was drawn down on November 10, 2008 and $200,000,000 was drawn down on January 14, 2009, pursuant to the Trust Indenture;
		
	(ix)	  	a sixteenth supplemental trust indenture dated as of March 3, 2009 relating to the issuance of Series 17 Notes in the aggregate principal amount of

  
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 MATERIAL CONTRACTS 

 

			
		  	$1,000,000,000, of which $300,000,000 was drawn down on March 3, 2009, pursuant to the Trust Indenture;
		
	(x)	  	a seventeenth supplemental trust indenture dated as of July 16, 2009 relating to the issuance of Series 18 Notes in the aggregate principal amount of $1,000,000,000, of which
$300,000,000 was drawn down on July 16, 2009 and $200,000,000 was drawn on March 15, 2010, pursuant to the Trust Indenture;
		
	(xi)	  	an eighteenth supplemental trust indenture dated as of November 19, 2009 relating to the issuance of Series 19 Notes in the aggregate principal amount of $1,000,000,000, of
which $250,000,000 was drawn down on November 19, 2009, and $500,000,000 was drawn down on January 22, 2010 pursuant to the Trust Indenture;
		
	(xii)	  	a nineteenth supplemental trust indenture dated as of March 15, 2010 relating to the issuance of Series 20 Notes in the aggregate principal amount of $1,000,000,000, of which
$300,000,000 was drawn down on March 15, 2010, pursuant to the Trust Indenture;
		
	(xiii)	  	a twentieth supplemental trust indenture dated as of September 13, 2010 relating to the issuance of Series 21 Notes in the aggregate principal amount of $1,000,000,000, of
which $250,000,000 was drawn down on September 13, 2010, and $250,000,000 was drawn down on January 19, 2011, pursuant to the Trust Indenture;
		
	(xiv)	  	a twenty-first supplemental trust indenture dated as of January 24, 2011 relating to the issuance of Series 22 Notes in the aggregate principal amount of $1,000,000,000, of
which $50,000,000 was drawn down on January 24, 2011, pursuant to the Trust Indenture;
		
	(xv)	  	a twenty-second supplemental trust indenture dated as of July 29, 2011 amending the definition of “Canadian GAAP” in the Trust Indenture;
		
	(xvi)	  	a twenty-third supplemental trust indenture dated as of September 26, 2011 relating to the issuance of Series 23 Notes in the aggregate principal amount of $1,000,000,000, of
which $300,000,000 was drawn down on September 26, 2011, pursuant to the Trust Indenture;
		
	(xvii)	  	a twenty-fourth supplemental trust indenture dated as of December 22, 2011 relating to the issuance of Series 24 Notes in the aggregate principal amount of $1,000,000,000, of
which $100,000,000 was drawn down on December 22, 2011, and $125,000,000 was drawn down on May 22, 2012, pursuant to the Trust Indenture;
		
	(xviii)	  	a twenty-fifth supplemental trust indenture dated as of January 13, 2012 relating to the issuance of Series 25 Notes in the aggregate principal amount of $1,000,000,000, of
which $300,000,000 was drawn down on January 13, 2012, and $300,000,000 was drawn down on May 22, 2012, pursuant to the Trust Indenture
		
	(xix)	  	a twenty-sixth supplemental trust indenture dated as of July 31, 2012 relating to the issuance of Series 26 Notes in the aggregate principal amount of $1,000,000,000, of which
$75,000,000 was drawn down on July 31, 2012, and $235,000,000 was drawn down on August 16, 2012, pursuant to the Trust Indenture; and
		
	(xx)	  	a twenty-seventh supplemental trust indenture dated as of December 3, 2012 relating to the issuance of Series 27 Notes in the aggregate principal amount of

  
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		  	$1,000,000,000, of which $50,000,000 was drawn down on December 3, 2012, pursuant to the Trust Indenture.

 Each of these supplemental trust indentures supplement the terms of the Trust Indenture, which contains customary
covenants and representations by our company for the public issuance of debt securities in the Canadian market. 
  

	(b)	a Dealer Agreement dated August 23, 2011 between our company and BMO Nesbitt Burns Inc., Casgrain & Company Limited, CIBC World Markets Inc., Desjardins
Securities Inc., HSBC Securities (Canada) Inc., Laurentian Bank Securities Inc., Merrill Lynch Canada Inc., National Bank Financial Inc., RBC Dominion Securities Inc., Scotia Capital Inc. and TD Securities Inc. (collectively, the
“Dealers”), relating to the public offering of unsecured medium term notes of Hydro One in a maximum aggregate principal amount of up to $3,000,000,000. The Dealer Agreement, as amended, provides for the appointment of the Dealers as
non-exclusive agents of Hydro One to solicit, from time to time, offers to purchase its medium term notes in Canada and, in certain circumstances, the United States. 

 Copies of these documents are available on www.sedar.com. 

  
 92  HYDRO ONE INC.

 INTEREST OF EXPERTS 

 

 INTERESTS OF EXPERTS 
 For the year ended December 31, 2012, KPMG LLP provided the following services to our company: 
  

	(a)	quarterly review of our company’s consolidated interim financial statements; 

 

	(b)	annual audit of our company’s consolidated financial statements; 

  

	(c)	annual audit of Hydro One Networks Inc.’s transmission and distribution businesses, Hydro One Remote Communities Inc.’s and Hydro One Brampton Networks
Inc.’s financial statements; and 

  

	(d)	annual audit of our company’s pension fund and the following companies which hold our alternative asset investments: HOPF-HFG Investments Ltd., HOPF- HFM
Investments Ltd., HOPF-PEJ Investments Ltd. and HOPF-PEP Investments Ltd. 

 KPMG LLP is independent in Canada in accordance with
its rules of professional conduct. 
 Mercer Human Resource Consulting LLC provides the following services to our company: 

 

	(a)	annual accounting actuarial valuation (valuation report prepared) for registered and unregistered pension and other post- employment and post-retirement plans;

  

	(b)	tri-annual funding actuarial valuation (last valuation completed as of December 31, 2011, next valuation scheduled for 2014); and 

 

	(c)	annual accounting actuarial valuation for supplementary pension plan for purposes of letters of credit (valuation report prepared). 

  
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 ADDITIONAL INFORMATION 

 

 ADDITIONAL INFORMATION 
 Additional Information about Hydro One is available on SEDAR (“System for Electronic Document Analysis and Retrieval”) at www.sedar.com. 
 As our sole shareholder is the Province, we are not required to prepare an information circular. Additional financial information is contained in our audited consolidated financial statements, together
with the auditors’ report thereon, and our Management’s Discussion and Analysis for our most recently completed fiscal year, each of which may be found on SEDAR at www.sedar.com. 

  
 94  HYDRO ONE INC.

 STATEMENT OF EXECUTIVE COMPENSATION 

 

 STATEMENT OF EXECUTIVE COMPENSATION 
 Compensation Discussion and Analysis 
 Overview 

This discussion and analysis outlines Hydro One’s approach to executive compensation, the elements of management compensation and the compensation
paid to its Named Executive Officers (“NEOs”). 
 Hydro One’s executive compensation program is designed: 

 

	•	 	 to attract, motivate and retain executives with the skills necessary to sustain and develop a safe, reliable and efficient electricity delivery system,
and 

  

	•	 	 to establish pay levels, based on performance, which are competitive with Canadian utility and energy companies and other comparable companies, both
publicly and privately owned. 

 Given the competitiveness of the market for skilled employees in the electricity sector and
the challenges confronting Hydro One and others in the electricity sector with respect to employee demographics, Hydro One seeks to attract, retain and compensate sufficient qualified staff to replace those retiring as well as to position the
company for its future work and infrastructure program. 
 The company’s overall compensation methodology for current and new management
employees, including current and new executives and senior management, is to target total compensation (base salary, incentive plan values, pension and benefits) at the 50th percentile of total compensation (i.e. salary, target bonus, annualized net
present value of long term incentive, benefits, and pension) of the 50/50 blend of public and private sector entities that form our comparator group, which is discussed below. 
 Our compensation program in terms of Total Cash Compensation is comprised of a base pay and an “at-risk” performance driven variable pay component. These elements are designed to complement each
other and reward achievement of short and long term corporate objectives. Annual incentive pay (the “Incentive Plan”) is linked to achievement of the corporate scorecard which measures management’s performance in accordance with and
against the strategic plan and approved business plan in each year. Linking compensation to the corporate scorecard is an effective way of driving management and corporate performance towards achieving specific strategic and business outcomes.

 For 2012, Hydro One’s compensation practices were applied consistent with the two statutes that impose restraint measures on the
compensation plans at Hydro One. The first statute is the Public Sector Compensation Restraint to Protect Public Services Act, 2010 (the “Restraint Act”) which imposed restraint measures from March 24, 2010 until March 31,
2012 on compensation plans (including base pay and incentive plan provisions of compensation plans) of non-bargaining employees in the broader public sector, including the NEOs of Hydro One. The second statute is the Broader Public Sector
Accountability Act, 2010, (the “BPSAA”), which was amended by the Strong Action for Ontario Act (Budget Measures) 2012 passed on June 20, 2012 to include and continue compensation restraint for defined designated executives
only from March 31, 2012 until such time as the Province proclaims that the restraint measures have expired, which cannot be before the fiscal year in which the Province no longer has a deficit. Management employees who do not qualify as
defined designated executives were not covered by the BPSAA. The BPSAA applies to the NEOs of Hydro One. 

  
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 The NEOs of Hydro One for 2012 are: 

 

			
	Name	 	Title
		
	Laura Formusa	 	President and Chief Executive Officer
		
	Sandy Struthers	 	Executive Vice President Corporate Support and Chief Financial Officer
		
	Myles D’Arcey	 	Senior Vice President, Customer Operations and President and Chief Executive Officer Hydro One Remote Communities Inc.
		
	Carmine Marcello	 	Executive Vice President, Strategy
		
	Peter Gregg	 	Executive Vice President, Operations

 Governance 
 The Human Resources Committee of the Hydro One Board of Directors (the “HRC”) is entirely independent within the meaning of Canadian securities laws. It is responsible for Board oversight of
human resources issues including compensation. Its mandate with respect to its advisory functions on executive compensation is to annually review and recommend to the Board for approval: 

 

	•	 	 all management salary ranges; 

  

	•	 	 Hydro One’s total compensation practices for all employees; 

 

	•	 	 any adjustment to the President and Chief Executive Officer’s base salary; 

 

	•	 	 the aggregate amount of the short term incentive fund; 

 

	•	 	 the amount of any short term incentive payout to be made to the President and Chief Executive Officer; 

 

	•	 	 the terms of the performance agreement to be entered into with the President and Chief Executive Officer for the following year;

  

	•	 	 the corporate performance measures for Hydro One; and 

 

	•	 	 Hydro One’s performance against its corporate performance measures. 

 Also, the HRC annually reviews and approves: 
  

	•	 	 the amount of any base salary adjustments for the President and Chief Executive Officer’s direct reports, and informs the Board of the
Committee’s decision; 

  

	•	 	 the amount of any short term incentive payouts to be made to the direct reports of the President and Chief Executive Officer, and informs the Board of
the Committee’s decision; 

  

	•	 	 the amount of any adjustments to management base salaries (in the aggregate) and informs the Board of the Committee’s decision; and

  

	•	 	 the amount of any management short term incentive results (in aggregate) and informs the Board of the Committee’s decision.

  
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 As well, the HRC: 
  

	•	 	 annually reviews the benefits provided under the pension and benefits plans for active and non-active employees; and 

 

	•	 	 annually considers the implications of risks associated with Hydro One’s compensation policies and practices. 

Composition of the HRC 
 As at
December 31, 2012, the members of our HRC were Douglas E. Speers, Walter Murray, Robert Pace and Gale Rubenstein. Members of the HRC have been selected and appointed to the HRC on the basis of their knowledge, experience and background in
executive compensation and risk management related to compensation practices and policies. Each has experience in these areas as senior members of public and private corporations or business entities. Members of the HRC are appointed by the Board of
Directors, upon recommendation of the Chair, and management has no role in the selection of the committee members. 
 Committee Members
Relevant and Direct Experience 
 Douglas E. Speers has been a member of the Board of Directors of Hydro One since November 10, 2005 and
has been a member of the HRC since April 5, 2007 when he was also appointed Chair of the HRC. He is fully conversant with the compensation policies and practices of Hydro One. Mr. Speers is the former President and Chief Executive Officer
of Emco Corporation, a publicly traded corporation which distributes building materials, and in his capacity had responsibility for all compensation including base pay, long and short term incentives, benefits and pensions. As well, Mr. Speers
was the President of Building Products of Canada with responsibility for, among other things, compensation and benefits for a unionized and non-unionized workforce. He was later appointed Chairman of Emco Corporation with continued responsibility in
all areas of compensation, and appointed Chair of Building Products of Canada with continued responsibility for compensation and benefits for a unionized and non-unionized workforce. Further Mr. Speers has chaired and sat on various pension
committees. 
 Walter Murray has been a member of the Board of Directors of Hydro One since November 10, 2005 and has been a member of the
HRC since December 15, 2005. As well, Mr. Murray is the Chair of our Investment Pension Committee, which has oversight of the Hydro One Pension Plan on behalf of the Board, and is accordingly familiar with all pension matters related to
compensation at Hydro One. Mr. Murray was the past Chair of our Audit and Finance Committee and continues to be a member of that committee. Mr. Murray is fully knowledgeable regarding the compensation policies and practices of Hydro One.
Mr. Murray was a board member of Ivernia Inc. from 2000 to 2009 and a member of its Human Resources Committee which has responsibility for oversight of its compensation practices. 
 Robert Pace has been a member of the Board of Directors of Hydro One since March 30, 2007 and has been a member of the HRC since April 5, 2007. As well, Mr. Pace is a member of our
Investment Pension Committee, which maintains oversight of the Hydro One Pension Plan and is accordingly familiar with pension matters related to our compensation practices. Mr. Pace is the President and Chief Executive Officer of the Pace
Group Ltd., which owns and operates a number of companies in Atlantic Canada and in this role he has responsibility and familiarity with compensation practices for his companies. Additionally, he is a member of the Board of Directors of Canadian
National Railway Company and has been the chair of its Human Resources 

  
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 STATEMENT OF EXECUTIVE COMPENSATION 
  

 
and Compensation Committee for the past five years. Further, Mr. Pace has been a director of High Liner Foods Incorporated for fourteen years and a member of its Human Resources Committee
since 2011. Additionally, Mr. Pace attended an executive education session on executive compensation in November 2011 at the Harvard Business School. Mr. Pace is cognizant of compensation policies and practices at Hydro One. 

Gale Rubenstein has been a member of the Board of Directors of Hydro One since March 30, 2007 and has been a member of the HRC since
December 9, 2010. Ms. Rubenstein is a partner at the law firm of Goodmans LLP and a member of its executive and compensation committees. She is familiar with the compensation practices and policies of Hydro One. Ms. Rubenstein’s
practice area is in insolvency law. As counsel in insolvency matters she has hands on experience regarding compensation issues and the claims for compensation that have to be determined and approved by the court in cases of insolvency and corporate
reorganization transactions. 
 Compensation Policies and Practices Aligned to Risk Management 

The Board of Directors is responsible for reviewing the major risks to the company’s strategic business objectives and is also responsible for
approving the company’s enterprise risk management policy and framework. The HRC, in relation to compensation matters, is charged with considering the implications of risks associated with the company’s compensation policies and practices.
Hydro One has a disciplined approach to identifying and assessing risk in relation to factors that may adversely affect the company and the HRC takes this into account in determining compensation. This approach and oversight is designed to mitigate
excessive risk taking by management. 
 The following elements of risk management have been built in to our compensation practices: 

 

	•	 	 we have a formal Enterprise Risk Management Policy and Framework; 

 

	•	 	 the Board has continual oversight of risk management issues affecting the company; 

 

	•	 	 the Board annually sets the multi-year strategic plan for Hydro One in which its strategic objectives are clarified and risks considered;

  

	•	 	 the strategic objectives form the basis of a corporate scorecard against which corporate performance is measured and incentive compensation is
determined; 

  

	•	 	 the measures and targets in the corporate scorecard are based on objective and industry standard factors with the targets vetted, established and
approved by the HRC; 

  

	•	 	 the overall annual assessment by the HRC of performance against the measures and targets in the corporate scorecard determines the aggregate amount of
the short term incentive payout; 

  

	•	 	 the measures and targets in the corporate scorecard are reviewed and considered by specific Board committees in addition to the HRC during the course
of the year to monitor and assess performance throughout the year; 

  

	•	 	 the Senior Vice President, Internal Audit and Chief Risk Officer audits the achievement of the targets in the corporate scorecard to ensure the targets
achieved are accurately represented and reports accordingly to the HRC, prior to the review and assessment by the HRC; 

  

	•	 	 achievement of the performance targets in the corporate scorecard is based on corporate wide performance and not NEO performance;

  

	•	 	 only a portion of the total compensation is based on Incentive Plan payments; 

  
 98  HYDRO ONE INC.

 STATEMENT OF EXECUTIVE COMPENSATION 

 

	•	 	 Incentive Plan payments for the NEOs are at-risk and not guaranteed; performance of the NEOs is reviewed and assessed by the HRC to determine the
Incentive Plan payments to the NEOs; 

  

	•	 	 there are maximum limits on incentive pay and for the NEOs, other than the President and Chief Executive Officer, the maximum payout is 60% of base
pay; for the President and Chief Executive Officer the maximum payout for 2012 is 25% of base pay; 

  

	•	 	 Hydro One does not grant to management, including the NEOs, any options, warrants or other rights to purchase its stock, including stock appreciation
rights; 

  

	•	 	 there is no area of compensation that encourages senior management to take excessive risks to directly increase their compensation;

  

	•	 	 as noted below, the HRC has retained, since 2008, an independent expert to provide it with advice on compensation matters and such advice includes the
identification of any risks related to our compensation practices related to management and the NEOs; 

  

	•	 	 the HRC deliberates, over several meetings, on matters of material importance related to compensation in order to reach an informed decision; and

  

	•	 	 the HRC holds in camera meetings on a regular basis and in particular does so to reach independent decisions. 

Independent Consultant for the HRC 
 In
December 2008, the HRC, in accordance with its powers to obtain independent expert advice, engaged the services of Hugessen Consulting Inc., an independent consulting firm that provides advice to boards and compensation committees on executive
compensation, to provide the HRC with advice on the competitiveness and effectiveness of the company’s compensation programs, including all elements of management compensation at Hydro One. Hugessen Consulting Inc. attended the HRC meetings,
when required, in 2012 and provided its independent views to the HRC and in particular its views on matters of compensation. Additionally, Hugessen Consulting Inc. provided services for the HRC in the design of the corporate scorecard for 2012.
Hugessen Consulting Inc. continues to provide its services to the HRC. Other than in respect of its compensation related services described above, Hugessen Counseling Inc. does not provide any other services to Hydro One. The table below is a
summary of the fees billed by Hugessen Consulting Inc. to Hydro One for each of the two last fiscal years in respect of the compensation services it has provided. 
  

									
	 	  	Executive Compensation
Related Fees	 	  	All Other Fees	 
	 2012
	  	$	93,046.62	  	  	$	0	  
			
	 2011
	  	$	170,402.05	  	  	$	0	  

  
 2012 ANNUAL
INFORMATION FORM  99 

 ELEMENTS OF COMPENSATION 

 

 ELEMENTS OF COMPENSATION 
 Compensation for executive officers consists of a base salary, performance-based pay through the Incentive Plan, pension and health and dental benefits, each of which is described in more detail below.

 Each of the NEOs, namely, Ms. Formusa, Mr. Struthers, Mr. D’Arcey, Mr. Marcello and Mr. Gregg was entitled
under their respective employment agreements to these elements of compensation. Hydro One does not provide its senior management with personal club memberships, car allowances or entertainment accounts. The Province issued a Perquisites Directive,
effective June 1, 2011, which applies to Hydro One. The Perquisites Directive provides that, subject to exceptions stated therein, no perquisites are permitted in ministries, classified agencies and prescribed organizations. Hydro One complies
with the Perquisites Directive. 
 The Total Cash Compensation (“TCC”) component of the program is comprised of base salary plus the
Incentive Plan. The TCC is set relative to the Total Direct Compensation (“TDC”) of the comparator group (base salary, short term incentive, and long term incentive) in aggregate. For all management employees, the maximum amount payable
for the Incentive Plan payment is a percentage of base pay fixed according to the band and salary range level of the employee. For the NEOs, other than the President and Chief Executive Officer, the maximum amount payable for the Incentive Plan
payment is 60% of the base salary of the NEO. For all the NEOs, the maximum achievable TCC amount is the base salary and the full award under the Incentive Plan. The value of the Incentive Plan component of TCC reflects short term incentives in the
comparator group. Hydro One does not have a long term incentive plan. 
 The HRC approved a comparator group submitted by management with the
assistance of management’s external compensation advisors, the Hay Group Limited. The company’s management engaged the services of the Hay Group Limited to provide advice and counsel on compensation matters, including executive
compensation. These services are distinct from those provided directly to the HRC by Hugessen Consulting Inc., referred to above. During 2012, the Hay Group Limited was paid $18,272.11 for its advice and services which included consultations,
evaluations and job ratings for management and executive positions. 
 The comparator group consists of 30 Canadian-based entities (15 public
and 15 private). Six of these entities are not reportable segments of their reporting parent and therefore financial information was not available. However, these six companies do form part of the Hay Group Limited compensation information
pool. Of the 24 entities in the comparator group with publicly available financial information, approximately 70% are smaller in size when compared to Hydro One, based on both revenues and assets, according to their most recent publicly available
annual financial statements. 

  
 100  HYDRO ONE INC.

 ELEMENTS OF COMPENSATION 
  

 The list of comparator group companies is as follows: 

 

			
	Public Sector	  	Private Sector
		
	British Columbia Hydro and Power Authority	  	ArcelorMittal Dofasco Inc.
		
	Business Development Bank of Canada	  	Barrick Gold Corporation
		
	Canadian Standards Association/CSA Group	  	Bruce Power
		
	Canada Mortgage and Housing Corporation	  	Canadian National Railway Company
		
	Canada Post Corporation	  	Canadian Pacific Railway
		
	Enersource Hydro Mississauga	  	Enbridge Gas Distribution Inc.
		
	Farm Credit Canada	  	Fortis Inc
		
	Government of Ontario	  	Newfoundland Power Inc.
		
	Ontario Power Authority	  	Nova Chemicals Corporation
		
	Ontario Power Generation	  	Nova Scotia Power Inc.
		
	PowerStream Inc.	  	Siemens Canada Limited
		
	SaskEnergy Incorporated	  	Suncor Energy Inc.
		
	Sask Power	  	Ultamar Ltee
		
	Sask Tel	  	Vale Inco Limited
		
	Toronto Hydro Corporation	  	Xstrata Nickel Canada
		
	Total 15	  	Total 15

 (1) Base Salary 
 Base (annual) salary is intended to compensate the NEOs for day-to-day, ongoing performance. The Hydro One Board of Directors determines a range of base compensation for each NEO based on comparisons to
comparable roles in the comparator group. 
 The actual level of base salary, within the approved range for each executive officer, including
the NEOs, is determined on the basis of job function and the individual’s performance and experience. Prior to the Restraint Act and the BPSAA, the President and Chief Executive Officer annually submitted a base salary recommendation to the HRC
for each of her direct reports and the HRC would set the base salary of such executives and then report its decision to the Board of Directors. The HRC would bring a base salary recommendation for the President and Chief Executive Officer to the
Board of Directors for approval. Until March 31, 2012, base salary increases were subject to the restraint measures in the Restraint Act. From and after March 31, 2012, base salary increases are subject to the restraint measures in the
BPSAA for designated executives, 

  
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INFORMATION FORM  101 

 ELEMENTS OF COMPENSATION 

 

 
which include the direct reports of the President and Chief Executive Officer. In compliance with the Restraint Act and the BPSAA, there were no base salary increases for the NEOs in 2012.

 The positioning of the NEO within the range is based on the level of performance relative to the requirements of the position. The Hydro One
Board of Directors establishes a base salary increase fund based on market comparisons. Performance is assessed on day-to-day performance in the role, both in terms of results and behaviours, and is often related to the level of experience in the
role. Hydro One does not provide across-the-board or economic increases to its NEOs. An NEO’s base salary may increase annually, but it may not. As a result of the Restraint Act and the BPSAA, base salary for the NEOs did not increase in 2012.

 (2) Performance-Based Compensation 
 Our company does not grant to its executive officers any options, warrants or other rights to purchase its stock, including stock appreciation rights. Performance-based compensation, outside of base
salary, is restricted to the Incentive Plan. 
 Hydro One’s Incentive Plan is a mechanism used by the company to drive performance, and is
separate and distinct from base salary adjustments. The Incentive Plan is designed to establish a strong correlation between corporate performance, individual performance and at-risk compensation. Hydro One’s Incentive Plan provides an
opportunity for participants, including the NEOs, to earn an annual cash incentive payment based on two elements. The first element is the achievement of corporate performance targets set by the Board of Directors. The second element is the
participant’s contributions to these targets. 
 For the purposes of determining the amount of short term incentive payable to the
President and Chief Executive Officer, specific weightings and levels of achievement are established by the HRC and are assigned to each corporate performance measure incorporated in her performance contract as well as to specific qualitative and
leadership goals. The assessment of the President and Chief Executive Officer is conducted by the HRC and approved by the Hydro One Board of Directors. 
 For management employees, the maximum allowable short term incentive is established for each salary band (i.e. range of rates of pay) of management employees and is fixed as a percentage of base pay for
that particular band. For each of the NEOs, potential awards range between 0% and a maximum of 60% of base salary. For the year ended December 31, 2012, the potential award ranges for the NEOs were as follows: between 0% and 25% of base salary
for Ms. Formusa, and between 0% and 60% of base salary for each of Mr. Struthers, Mr. D’Arcey, Mr. Marcello and Mr. Gregg. The range for Ms. Formusa was set by the HRC and approved by the Board in 2007 and it has
not changed since then. The range for the NEOs other than the President and Chief Executive Officer was established by the HRC and approved by the Board in 2006 and they have not changed since then. 

There are two components to performance-based compensation for NEOs: fund determination and fund allocation. These components will be described
separately. 
 Fund Determination: The maximum percentage for funding is at the discretion of the Hydro One Board of Directors, based on
a recommendation by the HRC. The funds available 

  
 102  HYDRO ONE INC.

 ELEMENTS OF COMPENSATION 
  

 
for the NEOs are a percentage of the total payout which would be payable assuming each individual earned his or her maximum allowable short term incentive. In 2012, the maximum percentage of
funds available for the NEOs was set at 65% of this total potential payout. This determination was made by the HRC, and recommended to, and approved by, the Board of Directors, by measuring the company’s performance at the end of the year
against various corporate performance targets and measures set at the beginning of the year. 
 Fund Allocation: The fund is allocated
among individual executives on the basis of performance. It is not an across the board allocation. NEOs are assessed against their performance agreement and against the other direct reports of the President and Chief Executive Officer, based on
objective and subjective assessments. These assessments of the NEOs, other than the President and Chief Executive Officer and other than Mr. D’Arcey, are conducted by the President and Chief Executive Officer, and approved by the HRC. The
assessment of Mr. D’Arcey is conducted by the Executive Vice President, Operations and approved by the President and Chief Executive Officer. No direct report is allowed to receive above his maximum allowable short term incentive. A
further discussion on the evaluation of performance of the NEOs is set out below in the section dealing with individual performance. 

(a) Corporate Performance Measures and Targets 
 The HRC, together with input from senior management, develops Hydro One’s corporate performance measures and targets annually at the end of each year for the following year through the use of a
balanced scorecard. A balanced scorecard is designed to measure corporate performance broadly, covering all key aspects of corporate performance. Measures included in the scorecard are designed to ensure that the corporate strategy is achieved.

 In the fall of each year, Hydro One’s management identifies the key measures and targets which it believes will drive corporate
performance during the course of the following year and presents these recommended measures and targets to the HRC. For 2012, the corporate performance measures were tied to Hydro One’s corporate strategy which was updated in 2012. See
“About Hydro One – Our Strategy” for additional information. Management and the HRC reviewed, considered and assessed the measures and targets to ensure they covered all key aspects of corporate performance and were robust enough to
drive superior performance and corporate strategy implementation. For 2012, the HRC determined that Hydro One should focus on six strategic objectives and nine performance measures and targets as compared to eight strategic objectives and seventeen
performance measures and targets in 2011. The HRC then recommended the measures and targets to the full Board of Directors for approval. These measures and targets are based on Hydro One’s key strategic goals in the areas of productivity,
reliability, satisfying our customer, employee engagement, shareholder value and safety. 
 The following table sets out Hydro One’s
corporate performance measures for 2012, which were aligned to its strategic objectives, and the targets for each of those measures. In 2012, the Board of Directors determined that, with respect to the targets, Hydro One met or exceeded 5 of the
targets and 4 were not met but 2 of those were within 5% of the target. The context of those targets is described in more detail under each strategic objective heading below. 

  
 2012 ANNUAL
INFORMATION FORM  103 

 ELEMENTS OF COMPENSATION 

 

													
	 Strategic Objective
	  	 Performance Measure
	  	Year-End	 
	  	  	Actual	 	  	Target	 
	 Productivity
	  	Transmission Unit Costs (Capital and OM&A costs per Asset) %	  	

 	  	 	8.6	  	  	 	10.1	  
		  	Distribution Unit Costs (Capital and OM&A costs per km of line) $’000/km	  	

 	  	 	10.0	  	  	 	11.0	  
	 Reliability
	  	Duration of Customer Unplanned Interruptions on 115/230kV Network Transmission System per delivery point Φ (minutes/delivery point)	  	

 	  	 	6.8	  	  	 	10.0	  
		  	Duration of Customer Interruptions on the Distribution System (hours per customer)	  	

 	  	 	7.0	  	  	 	6.7	  
	 Satisfying Our Customers
	  	Customer Satisfaction (Transmission Customers) (% satisfied / Results available in May & October)	  	

 	  	 	76	  	  	 	90	  
		  	Customer Satisfaction (Distribution Customers) (% satisfied)	  	

 	  	 	86	  	  	 	86	  
	 Employee Engagement
	  	Employee Survey (Grand Mean)	  	

 	  	 	3.92	  	  	 	4.06	  
	 Shareholder Value
	  	Net Income After Tax + ($M)	  	

 	  	 	745	  	  	 	643	  
	 Injury-free Workplace
	  	Medical Attentions † (# of medical attentions per 200,000 hours worked)	  	

 	  	 	2.3	  	  	 	2.2	  

 Legend 

 Better than plan (35%) 

 On Plan 

 Below Plan 
  

	Φ	All multi-circuit supplied delivery points. 

	+	Results are for Hydro One Inc. which includes all subsidiaries. 

	†	Subset of WSIB reportable Injuries 

  
 104  HYDRO ONE INC.

 ELEMENTS OF COMPENSATION 
  

 The 2012 scorecard is not weighted. Each measure is key to driving corporate performance, and all of the
measures are interrelated. In terms of assessing performance, the HRC is required to exercise judgment in weighing the results for each measure and determining whether overall corporate performance, as reflected through scorecard performance, is
met. If, on balance, scorecard performance is met or exceeded, the short term incentive fund may be funded to a percentage of the maximum short term incentive payout, up to 100%, based on the recommendation of the HRC, but subject to the ultimate
discretion of the Board of Directors. If, on balance, scorecard performance is not met, the HRC will determine and recommend a funding level, also subject to the ultimate discretion of the Board of Directors. Since 2003, the Board of Directors
determined that the funding level would be set at 75% of the maximum short term incentive fund if on balance the targets were met or exceeded. In 2012, the Board of Directors considered the corporate scorecard results and the key accomplishments of
the Company throughout the year and determined, while several targets were not met, many were and on balance and in the exercise of its discretion, the funding level should be set at 65% of the maximum short term incentive fund. In accordance with
the BPSAA, the funding envelope for the short term incentive for 2012 cannot exceed the amount that was paid in aggregate in the performance pay cycle for 2011 and Hydro One has complied with this requirement. 

1. Productivity 
 One of our strategic
objectives is to increase productivity through efficiency improvements and effective management of costs. The measures for this objective for 2012 were: transmission unit cost and distribution unit cost. 

For 2012, Hydro One measured for transmission unit cost the capital expenditures and OM&A costs per dollar of gross in-service assets (expressed as a
percentage). For distribution unit cost, the measure is capital expenditures and OM&A costs per kilometre of line ($’000/km) due to the length of line required to connect our rural customers. Our objective with our ongoing work and
investment program is to maintain and improve our assets and monitor our productivity year-over-year. Our transmission unit cost target was set at 10.1% and Hydro One met this target. The distribution unit cost target was set at $11,000 per
kilometre of line and Hydro One also met this target. 
 2. Reliability of Transmission and Distribution 

Hydro One continues to build and retain public confidence and trust in its operations, as stewards of Ontario’s electricity grid. In 2012, Hydro One
continued its focus on this strategic priority by investing in the key assets of the electricity delivery system and by operating the existing system for customers in a safe, reliable and efficient fashion. Hydro One is conscious that commercial
customers of all sizes require reliable service to allow them to deliver their products and services and that customers’ expectations are for a reasonably limited duration when interruptions occur. Transmission and distribution reliability is
measured through the duration of customer interruptions. 
 For the duration of unplanned customer interruptions within our transmission
business, the target for 2012 was 10 minutes per delivery point. We more than met this target. 
 For the Hydro One Networks distribution
business, the target for 2012 for the duration of customer interruptions was set at 6.7 hours per customer. We did not meet this target. 

  
 2012 ANNUAL
INFORMATION FORM  105 

 ELEMENTS OF COMPENSATION 

 

 3. Customer Satisfaction 
 Customer satisfaction measures the degree to which our transmission and distribution customers are satisfied with the service they receive from our company. Customer satisfaction is based on the results
of customer surveys conducted on Hydro One’s behalf by independent third parties. In 2012, for transmission customers we targeted a customer satisfaction rate of 90%, but did not meet this target. For our distribution customers, we targeted a
satisfaction rate of 86%, and we met this target. 
 4. Employee Engagement 
 Hydro One continues to focus efforts on increasing employee engagement throughout the company. An engaged workforce is one in which employees embrace the corporate values of safety, stewardship,
excellence and innovation. The process of measuring and improving such engagement began in 2008 by means of an employee engagement survey administered by an independent third party expert. Our goal is to improve the grand mean score year-over-year.
The target of improving the grand mean score to 4.06 (out of 5) in 2012 was not met. 
 5. Shareholder Value 

Achievement of strong financial performance is measured by a performance measure of targeted level of net income after tax. Our target was $643 million
net income after tax and we exceeded our target. 
 6. Safety: Injury Free Workplace 

The safety of our employees is paramount. In 2012, Hydro One used medical attentions, defined as injuries that require treatment by a medical practitioner
(beyond first aid), as the performance measure for this strategic objective. The medical attentions measure reflects incidents that are reported to the Workplace Safety Insurance Board and is calculated as the number of attentions per 200,000 hours
worked. In 2012, Hydro One set a target of no higher than 2.2 attentions per 200,000 hours worked. In an effort to achieve this target, Hydro One engaged in a number of activities, such as: continued emphasis on improving health and safety through
face-to-face sessions; continuation of its Journey to Zero initiative; better monitoring of mandatory skills and safety training; an enhanced driver training/evaluation program; and field coaching to increase the expectations from supervisors and
staff. The number of attentions in 2012 improved by 35% compared to the number in 2011 but was still slightly higher than the target for 2012. 

Overall Performance for 2012 
 For 2012,
the HRC determined that of the 9 targets, 5 were met or exceeded the target, 2 were not met but within 5% of the target and 2 were not met and that, taking into consideration the key accomplishments of the Company throughout the year, on balance,
the payout funding at 65% of the maximum short term incentive payout would be recommended to the Board. In considering the 2012 results, the HRC noted that while the safety target was missed, there has been substantial improvement over 2011 results
indicating continued focus on improvements in management systems and on prevention. The HRC also noted that with respect to the Distribution Duration of Customer Interruptions target, it was missed due to January storms and that for the balance of
the year the target was either met or exceeded. The HRC found the Company had performed very well regarding the Bruce to Milton high-voltage transmission project which came in well ahead of schedule. Other key transmission projects also were
completed and placed in service in 2012. Additionally, the Company continued to positively move forward towards the completion of a limited partnership with the 

  
 106  HYDRO ONE INC.

 ELEMENTS OF COMPENSATION 
  

 
Saugeen Ojibway First Nation for the new Bruce to Milton transmission project. The Board of Directors considered the HRC’s recommendation and decided that, in its assessment of the results
of the corporate scorecard, on balance, and in consideration of the other accomplishments of the Company, to approve the payout funding at 65% of the maximum short term incentive payout. Accordingly, the funding at 65% of the maximum short term
incentive payout was the available amount for distribution to management employees, including the NEOs. 
 (b) Individual Performance

 The second component of determining the amount of short term incentive payments to be made to NEOs pursuant to the Incentive Plan is
their individual performance. Individual target performance criteria are outlined in individual performance agreements which include both broad corporate and individual specific targets. NEOs are expected to align their efforts with and advance the
Corporate Performance Measures and Targets discussed above. The NEOs were required to provide visible leadership to develop and maintain a safe and healthy workplace in support of the “Journey to Zero” initiatives designed to achieve world
class health and safety at Hydro One over the foreseeable future. In addition, the NEOs, as organizational leaders are held to certain defined accountabilities, pursuant to an enhanced managerial framework for Hydro One called “Craft of
Management”. Performance agreements are entered into annually between the President and Chief Executive Officer and her direct reports. The Board of Directors, in turn, annually approves the performance agreement entered into between the
President and Chief Executive Officer and the Chair of the Board. 
 Potential awards for NEOs are expressed as a percentage of base salary as
described above. 
 The potential award for each NEO was based on his or her relative achievement of specific individual performance targets. As
noted earlier, these targets may be objective, numeric-based targets or more subjective targets. These targets are linked to some or all of the corporate performance measures, to measures related to the NEO’s business unit and were designed to
enable our company to promote and achieve its strategic plan. The evaluation of performance against the targets is important. Hydro One does not take a mechanistic approach to assessment. Each NEO is assessed objectively against his/her specific
individual targets. Once this assessment has been completed, a second assessment comparing relative achievement across the NEOs is also conducted. This approach requires judgment on the part of the President and Chief Executive Officer and HRC with
respect to the NEOs other than the President and Chief Executive Officer and the HRC with respect to the President and Chief Executive Officer, but provides a better assessment of performance since it considers both absolute performance (against a
set of targets) and relative performance against the other NEOs (other than the President and Chief Executive Officer). Using this approach means an NEO could meet all of his/her targets but receive less than his/her incentive maximum if other NEOs
performed better against their targets. 
 Ms. Formusa’s targets were weighted and comprised both quantitative and qualitative
targets. The quantitative factors (overall total 70%) were as follows: productivity (17.5%), reliable transmission and distribution (17.5%), satisfying our customers (14%), employee engagement (10.5%), and shareholder value (10.5%). With respect to
these quantitative targets, they were the same as and tied to achieving the Corporate Performance Measures and targets described above. The qualitative factors (30%), each 

  
 2012 ANNUAL
INFORMATION FORM  107 

 ELEMENTS OF COMPENSATION 

 

 
carrying a sub-weighting, were: strategic planning and key priorities (10.5%), leadership and culture (7.5%), relationship management – Board and shareholder (7.5%), and relationship
management – other stakeholders (4.5%). 
 Mr. Struthers, as Executive Vice President Corporate Support and Chief Financial
Officer accountable for Corporate Finance, and Regulatory Affairs, had targets with a number of financial components including: raising the budgeted capital funding in a cost effective manner; working with the Company’s credit analysts;
managing towards meeting the net income target; providing, supporting and completing the 2012 business plan; and determining and implementing a strategy applicable to maintaining financial reporting in US GAAP as it applies to the Ontario
Securities Commission IFRS reporting exemption expiring in 2014. As well, Mr. Struthers targets included ensuring the transmission and distribution rate filings were filed in 2012 and properly supported; the continued support of the rollout of
the Craft of Management within his reporting group; driving better employee engagement within his reporting group; working with key internal business groups to address the changing landscape in pensions; providing guidance with respect to the
outsourcing strategy and the operations of the outsourcing contract; and supporting and overseeing key business development activities with external parties, such as the East-West Tie project. Additionally, Mr. Struthers had targets to enhance
relations with, and to keep informed, stakeholders and industry counterparts to enable them to better understand Hydro One’s business. 

Mr. D’Arcey, as Senior Vice President Customer Operations and President and Chief Executive Officer of Hydro One Remote Communities Inc.
was assigned targets which focused on the customer operations area and specifically on overseeing and guiding the Customer Information System Replacement project through the build and cutover phases on schedule and budget, while minimizing the
impact to customers as a result of the improved system; improving customer satisfaction in the distribution customer segment of our business to help meet corporate targets; providing visible leadership and support in employee engagement to achieve
the corporate targets for the customer operations group; transitioning the smart meter program from project mode to sustainment and stabilize systems as Hydro One moves to the Customer Information System implementation stage; managing the connection
process for the FIT and Micro FIT projects to achieve regulatory compliance and reduce costs; delivering on the development and implementation of the CDM programs to achieve OEB targets on conservation and load reductions, and managing the policies,
procedures and field execution of the meter to bank process to support corporate revenue requirements, enhance customer experience and ensure regulatory compliance. 
 Mr. Marcello, as Executive Vice President, Strategy, accountable for Asset Management, External Affairs, Corporate Communications, Human Resources, First Nations and Métis Relations,
Hydro One Brampton, Information Solutions (information technology), Corporate Security, Strategy Alignment, Hydro One Telecom and Transmission Projects Development, was assigned targets which included alignment of the regulatory, human resources,
labour, business development and asset strategies with the overall corporate strategy; developing the asset investment plan to support the transmission and distribution rate filings; lead major strategic projects (which include our new Customer
Information System, Advanced Distribution System, 

  
 108  HYDRO ONE INC.

 ELEMENTS OF COMPENSATION 
  

 
Smart Meters, Time of Use Implementation, business development with external parties [e.g. East-West Tie project], transmission planning for nuclear incorporation, improved area supply and
interconnection capability); incorporating renewable energy generation into the distribution system; enhancing and improving stakeholder relations (e.g. government, First Nations and Métis peoples) to enhance Hydro One’s reputation,
manage risk and obtain timely decisions and to achieve productivity targets identified in Hydro One’s business plan. 

Mr. Gregg, as Executive Vice President, Operations accountable for Customer Operations, Engineering Project Delivery, Facilities and Real
Estate, Grid Operations, Health Safety and Environment, Organizational Alignment and Supply Chain and Shared Services, was given these key objectives: bring the Bruce to Milton project in-service ahead of the original schedule; improve the overall
grand mean score for the employee engagement survey; establish an Operations Health and Safety Forum to align all health and safety initiatives across the Operating groups; develop, provide and track monthly reports of the Operations group to track
budget, work accomplishments and medical attentions statistics at the work group level; help deliver the new Customer Information System; deliver Operations work programs cost-effectively and productively for the continued operation and maintenance
of the transmission and distribution systems; deliver the work programs without increasing the work force budget; deliver costs savings and productivity improvements; continue and support the rollout of the Craft of Management initiative; and manage
the succession process within his group for the orderly transfer of knowledge and skills. 
 In 2012, based on an assessment, by the HRC and the
Board, of the NEOs respective performance and their performance compared to other executives, other than Mr. D’Arcey who was assessed by the Executive Vice President, Operations, the NEOs received Incentive payments ranging from 86% to 70%
of their maximum potential award. 
 The determination of Incentive Plan amounts for the NEOs is independent from the assessment of base salary
adjustments. However, the final dollar amount of an annual Incentive Plan payment is impacted by any changes to base salary since it is a percentage of base salary. 
 (3) Benefits 
 In addition to the Base Salary and Incentive Plan compensation, as part of
their compensation package, the NEOs also participate in the Hydro One registered pension plan and supplementary pension plan and participate in a flexible benefits plan, which is available to all other management employees. The flexible benefits
plan provides various benefits, including life insurance, vacation and health care benefits. Hydro One provides to each executive and management employee certain core benefits, which include basic life insurance, accidental insurance, extended
health benefits, out of country medical, dental, sick leave and long term disability, pension and basic vacation. The flexible benefit plan provides for credits for life insurance and vacation calculated each plan year on the individual’s base
annual earnings in effect at the time of enrolment in the plan. Those flexible benefit plan credits may then be allocated by each executive and management employee to purchase additional life insurance, up to allowed additional vacation days, and a
health care account. Unallocated credits are paid out at year end, subject to withholding tax, to the employee. 

  
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INFORMATION FORM  109 

 ELEMENTS OF COMPENSATION 

 

 
Benefits provided to NEOs, other than Mr. Gregg, are the same as those provided to all other management employees and could be higher or lower than bargaining unit represented staff,
depending on the specific benefit. Benefits are relatively independent of base salary and Incentive Plan payments, although some are a percentage of base pay. Many health-related benefits are a flat rate and not related to base salary or Incentive
Plan levels. 
 Pension benefits for NEOs, other than Mr. Gregg, are identical to those of all other executive and management staff in our
company with the same start date, and are calculated in a similar manner identical to all employees in our company. See “Pension Plan Benefits” below. 
 Mr. Gregg’s benefits and pension benefits differ from those of the other NEOs as Mr. Gregg became an employee of Hydro One after January 1, 2004 and his benefits and pension benefits are in
accordance with the reduced benefits for management employees who became employees of Hydro One after January 1, 2004. 
 Role of NEOs
in Determining Executive Compensation 
 An NEO does not play any part in determining his or her own compensation. The Executive Vice
President Strategy, working with the Vice President, Human Resources and Hay Group Limited, is responsible for providing recommendations regarding compensation (other than that of the Executive Vice President Strategy) to the HRC consistent with the
Board approved compensation strategy. The HRC must then review, discuss, and ultimately approve the base salary, Incentive Plan payment and benefits for all the NEOs (other than the President and Chief Executive Officer) based on a recommendation by
the President and Chief Executive Officer. With respect to the compensation payable to the President and Chief Executive Officer, the HRC reviews, discusses and makes a recommendation to the Board of Directors, who must consider, discuss and
ultimately approve the final compensation level for the President and Chief Executive Officer. In 2012, in addition to the above recommendations, the HRC and the Board of Directors considered the requirements of the Restraint Act and the BPSAA in
determining the base salary and Incentive Plan payments for all the NEOs for 2012. Base salary for the NEOs did not increase in 2012. 

  
 110  HYDRO ONE INC.

 SUMMARY COMPENSATION TABLE 
  

 SUMMARY COMPENSATION TABLE 
 The following table summarizes the compensation paid to each of the Chief Executive Officer, Chief Financial Officer and to each of the three other most highly paid officers in 2012, 2011 and 2010.

  

																																	
	 Name and Principal Position
	  	Year	 	  	Salary ($)	 	  	Non-equity incentive plan	 	  	Total
Direct
Compensation
($)	 	  	Pension
Value 5
($)	 	 	All
Other
Compensation
($)	 	  	Total
Compensation
($)
	 
	  	  	  	compensation ($)	 	  	  	 	  
	  	  	  	Annual	 	  	Long-term	 	  	  	 	  
	  	  	  	incentive	 	  	incentive	 	  	  	 	  
	  	  	  	plans 1	 	  	plans	 	  	  	 	  
	 L. Formusa
President & CEO
	  	 	2012	  	  	$	735,875	  	  	$	159,000	  	  	$	0	  	  	$	894,875	  	  	$	24,000	  	 	$	0	  	  	$	918,875	  
	  	 	2011	  	  	$	735,875	  	  	$	177,000	  	  	$	0	  	  	$	912,875	  	  	$	42,000	  	 	$	0	  	  	$	954,875	  
	  	 	2010	  	  	$	735,875	  	  	$	157,477	  	  	$	0	  	  	$	893,352	  	  	$	58,000	  	 	$	0	  	  	$	951,352	  
									
	 S. Struthers 2
Executive Vice President and CFO
	  	 	2012	  	  	$	325,000	  	  	$	169,000	  	  	$	0	  	  	$	494,000	  	  	$	38,000	  	 	$	0	  	  	$	532,000	  
	  	 	2011	  	  	$	325,000	  	  	$	177,000	  	  	$	0	  	  	$	502,000	  	  	$	36,000	  	 	$	0	  	  	$	538,000	  
	  	 	2010	  	  	$	325,000	  	  	$	178,750	  	  	$	0	  	  	$	503,750	  	  	$	60,000	  	 	$	0	  	  	$	563,750	  
									
	 M. D’Arcey
Senior Vice President, Customer Operations
	  	 	2012	  	  	$	339,010	  	  	$	130,000	  	  	$	0	  	  	$	469,010	  	  	($	53,000	) 	 	$	0	  	  	$	416,010	  
	  	 	2011	  	  	$	339,010	  	  	$	150,000	  	  	$	0	  	  	$	489,010	  	  	($	37,000	) 	 	$	0	  	  	$	452,010	  
	  	 	2010	  	  	$	339,010	  	  	$	154,000	  	  	$	0	  	  	$	493,010	  	  	($	2,000	) 	 	$	0	  	  	$	491,010	  
									
	 C. Marcello 3
Executive Vice President Strategy
	  	 	2012	  	  	$	300,000	  	  	$	156,000	  	  	$	0	  	  	$	456,000	  	  	($	13,000	) 	 	$	0	  	  	$	443,000	  
	  	 	2011	  	  	$	300,000	  	  	$	177,000	  	  	$	0	  	  	$	477,000	  	  	($	9,000	) 	 	$	0	  	  	$	468,000	  
	  	 	2010	  	  	$	300,000	  	  	$	165,000	  	  	$	0	  	  	$	465,000	  	  	$	51,000	  	 	$	0	  	  	$	516,000	  
									
	 Peter Gregg 4
Executive Vice President Operations
	  	 	2012	  	  	$	295,000	  	  	$	153,400	  	  	$	0	  	  	$	448,400	  	  	$	38,000	  	 	$	0	  	  	$	486,400	  
	  	 	2011	  	  	$	295,000	  	  	$	177,000	  	  	$	0	  	  	$	472,000	  	  	$	34,000	  	 	$	0	  	  	$	506,000	  
	  	 	2010	  	  	$	295,000	  	  	$	162,250	  	  	$	0	  	  	$	457,250	  	  	$	35,000	  	 	$	0	  	  	$	492,250	  

  
 2012 ANNUAL
INFORMATION FORM  111 

 SUMMARY COMPENSATION TABLE 

 

	1 	 Information in the Summary Compensation Table is based on the year the incentive was earned. The incentive is generally earned in one year and paid in
the following year. Therefore, the information provided in the Summary Compensation Table above differs from that published under the Public Sector Salary Disclosure Act (Ontario). 

	2 	 Mr. Struthers became the CFO effective February 12, 2009, upon the resignation of B. Summers, the former CFO. Mr. Struthers became an
Executive Vice President and CFO effective November 1, 2010. In his new role, Mr. Struthers continued with his responsibilities as CFO and added responsibilities for Regulatory Affairs. Effective January 1, 2013, as part of an
organizational realignment to better deliver on key priorities of the Company, Mr. Struthers was appointed Chief Administration Officer and Chief Financial Officer, which positions will bring together under Mr. Struthers’ oversight
and direction of the shared services of the Company. As a result of this realignment and added responsibilities, Mr. Struthers compensation has been increased commensurate with the position and increased responsibilities, effective January 1,
2013. 

	3 	 Mr. Marcello was appointed on March 9, 2009 as Senior Vice President – Asset Management. On November 1, 2010, he was appointed
Executive Vice President Strategy and continued to retain his responsibilities for Asset Management. He had additional responsibilities for Human Resources, Hydro One Telecom, First Nations and Metis Relations, Hydro One Brampton, Information
Solutions Division, Strategy Alignment, and Transmission Projects Development. Effective January 1, 2013, Mr. Marcello was appointed the President and Chief Executive Officer of Hydro One to succeed Ms. Formusa following her
retirement. Mr. Marcello also became a director of Hydro One as well as the other subsidiary corporations within the Hydro One group of companies. As a result of his appointment, Mr. Marcello’s compensation has been increased
commensurate with his new position and its increased responsibilities, effective January 1, 2013. The overall compensation will be less than the amount paid for this position in prior years. 

	4 	 Mr. Gregg was formerly the Senior Vice President, Corporate and Regulatory Affairs until November 1, 2010 when he was appointed Executive
Vice President Operations. In his role as Executive Vice President Operations, Mr. Gregg was accountable for Customer Operations, Engineering and Project Delivery, Facilities and Real Estate, Grid Operations, Health Safety and Environment,
Organizational Alignment, and Supply Chain and Shared Services. Effective January 1, 2013, as part of an organizational realignment to better deliver on key priorities of the Company, Mr. Gregg was appointed Chief Operating Officer, which
position will have accountability for all aspects of planning, engineering, designing/building and all operations of our transmission and distribution systems as well as other key accountabilities for telecom, technology infrastructure, health and
safety and labour relations. As a result of this realignment and added responsibilities, Mr. Gregg’s compensation has been increased and commensurate with his new position and increased responsibilities, effective January 1, 2013.

	5 	 The pension value includes a combination of annual current service cost as well as the past service impact of other compensating amounts as described
in footnotes 2 and 3 to the defined benefit pension plan table in the next section. 

  
 112  HYDRO ONE INC.

 SUMMARY COMPENSATION TABLE 
  

 None of Ms. Formusa, Mr. Struthers, Mr. D’Arcey, Mr. Marcello or Mr. Gregg
are entitled to other benefits or perquisites in the aggregate amount that exceeds $50,000 or 10% of his or her annual salary. 

Ms. Formusa did not receive any additional compensation for her services as a director of Hydro One. Mr. Marcello will not receive any
additional compensation for his services as a director of Hydro One. 
 Pension Plan Benefits 

Defined Benefit Pension Plan 
 Hydro One
provides a defined benefit pension plan to its employees. Each of the NEOs participates in the Hydro One Pension Plan (consisting of the Hydro One registered pension plan and the supplementary pension plan). The benefits for these individuals are
calculated in a consistent manner with all other Hydro One employees, as described below. 
 For each year of credited service under the Hydro
One Pension Plan, to a maximum of 35 years, the benefit provided for each of the employees who participate in the plan is equal to 2% of the member’s average base annual earnings during the 36 consecutive months (60 consecutive months for
management employees hired on or after January 1, 2004 and for employees represented by the Society of Energy Professionals hired on or after November 17, 2005) when his or her base annual earnings were highest. Base annual earnings are
comprised of the member’s salary and 50% of his or her short term incentive. 
 The approximate projected credited years of service that
each NEO will have if he or she works until the age of 65 is as follows: Ms. Formusa – 35 years; Mr. Struthers – 24 years; Mr. D’Arcey – 35 years; Mr. Marcello – 35 years and Mr. Gregg – 28
years. This pension is reduced by 0.625% of the member’s average base annual earnings up to the year’s maximum pensionable earnings during the 36 consecutive months (60 consecutive months for management employees hired after
January 1, 2004 and for employees represented by the Society of Energy Professionals who were hired after November 17, 2005) when his or her base earnings were highest (the reduction is 0.500% for employees represented by the Society of
Energy Professionals who were hired prior to November 17, 2005 and for all employees represented by the Power Workers’ Union). The reduction is intended to offset Canada Pension Plan (“CPP”) benefits. 

The plan terms also include a bridge pension which is payable from the date of retirement to age 65 for all members except for management employees hired
on or after January 1, 2004 and employees represented by the Society of Energy Professionals hired on or after November 17, 2005. The Hydro One Pension Plan provides for early retirement with an unreduced pension at the earlier of age 65
and the attainment of years of age plus continuous employment totalling 82 or more (years of age plus credited service totalling 85 for management employees hired on or after January 1, 2004 and for employees represented by the Society of
Energy Professionals hired on or after November 17, 2005). A plan member who is not eligible for an unreduced pension can retire with a reduced pension any time after attaining age 55. 
 Pension benefits payable to pensioners, beneficiaries and terminated employees with deferred pensions are increased annually effective January 1 of each year equal to 100% of the increase in the
Ontario consumer price index for the 12 month period ending in June of the previous 

  
 2012 ANNUAL
INFORMATION FORM  113 

 SUMMARY COMPENSATION TABLE 

 

 
year (75% for management employees hired on or after January 1, 2004 and for employees represented by the Society of Energy Professionals hired on or after November 17, 2005). The
normal form of pension for a member who does not have a spouse at retirement is a pension payable for life and guaranteed for five years, payable to an estate if not paid to the retiree. The normal form of pension for a member who has a spouse at
retirement is a pension payable for the life of the member, and continuing after the member’s death to his or her spouse at the rate of 66 2/3% of the amount the member was receiving. 
 Benefits payable under Hydro One’s registered pension plan, similar to other entities, are restricted by the Income Tax Act (Canada). This limit on benefits affects members whose average
annual earnings exceed approximately $148,000 in 2012. Participants whose pensions would otherwise be restricted by the Income Tax Act (Canada) participate in an unregistered supplementary pension plan that provides benefits equal to the
difference between the Income Tax Act (Canada) maximum pension benefits and the benefits determined in accordance with the formula set out in Hydro One’s registered pension plan. The supplementary pension plan is unfunded and the
additional retirement income is paid from general revenues. Hydro One’s obligations to participants under the supplementary pension plan are secured by a letter of credit. 
 The table below shows the following information for each NEO participating in the company’s defined benefit pension arrangements: 

 

	•	 	 Years of credited service as at December 31, 2012; 

 

	•	 	 Estimated annual lifetime benefit payable for service up to December 31, 2012 and up to the normal retirement age of 65; and

  

	•	 	 A reconciliation of the present value of the defined benefit obligation from December 31, 2011 to December 31, 2012. The present value of the
defined benefit obligations reflect the impact of the annual bonus earned in the year even though it is paid in the following year. 

  

																																	
	 	  	 Number of
years

credited
service at
	 	  	Annual benefits payable
($)	 	  	 Opening
present value

of
defined
benefit
obligation 1
	 	  	Compensatory change
($)	 	 	Non-
compensatory
present value	 	  	 Closing

of defined
benefit
	 
	  	  	  	  	Service	 	  	 	 	 	  
	 Name
	  	year end (#)	 	  	At year end	 	  	At age 65	 	  	($)	 	  	Cost 2	 	  	Other 3	 	 	change 4
($)	 	  	obligation 5
($)	 
	 L. Formusa
	  	 	31.9 yrs	  	  	$	511,500	  	  	$	511,500	  	  	$	8,328,000	  	  	$	233,000	  	  	($	209,000	) 	 	$	3,029,000	  	  	$	11,381,000	  
	 S. Struthers
	  	 	12.9 yrs	  	  	$	101,500	  	  	$	188,500	  	  	$	1,293,000	  	  	$	88,000	  	  	($	50,000	) 	 	$	420,000	  	  	$	1,751,000	  
	 M. D’Arcey
	  	 	34.2 yrs	  	  	$	271,000	  	  	$	277,600	  	  	$	4,632,000	  	  	$	113,000	  	  	($	166,000	) 	 	$	949,000	  	  	$	5,528,000	  
	 C. Marcello
	  	 	25.1 yrs	  	  	$	184,700	  	  	$	257,700	  	  	$	2,845,000	  	  	$	97,000	  	  	($	110,000	) 	 	$	896,000	  	  	$	3,728,000	  
	 P. Gregg
	  	 	8.5 yrs	  	  	$	59,700	  	  	$	197,400	  	  	$	651,000	  	  	$	66,000	  	  	($	28,000	) 	 	$	308,000	  	  	$	997,000	  

  
 114  HYDRO ONE INC.

 SUMMARY COMPENSATION TABLE 
  

	1 	 The opening present value of the defined benefit obligation is the value of the projected pension earned for service to December 31, 2011. The
values have been determined using the same actuarial assumptions used for determining the pension plan obligations at December 31, 2011 as disclosed in the notes to the 2011 consolidated financial statements, based on the actual earnings for
2011 and adjusted to reflect expected increases in pensionable earnings. 

	2 	 The values shown under the column headed Service Cost under Compensatory Change is the value of the projected pension earned for service in the current
fiscal year (reduced by the NEOs own contributions). 

	3 	 The values shown under the column headed Other under Compensatory Change is the value of the increase or decrease in the present value of the defined
benefit obligation that relates to service prior to the current fiscal year due to the differences between actual compensation for the year and the actuarial assumption for the year assumed at the end of the prior year. 

	4 	 The values shown under the column headed Non-Compensatory Change include the impact of amounts attributable to interest accruing on the
beginning-of-year obligation, changes in the actuarial assumptions, the NEOs own contributions and any other experience gains and losses. 

	5 	 The closing present value of the defined benefit obligation is the value of the projected pension earned for service to December 31, 2012. The
values have been determined using the same actuarial assumptions used for determining the pension plan obligations at December 31, 2012 as disclosed in the notes to the 2012 consolidated financial statements, based on the actual earnings for
2012 and adjusted to reflect expected increases in pensionable earnings. The closing present value of the defined benefit obligation for Ms. Formusa reflects her final pension entitlement following her retirement effective December 31,
2012. 

 Notes: 
  

	•	 	 All members are currently vested in their pension entitlements earned to December 31, 2012. 

 

	•	 	 In accordance with Canadian generally accepted accounting principles, the amounts above make no allowance for the different tax treatment of the
portion of pension not paid from the registered or qualified pension plans. 

  

	•	 	 All amounts shown above are estimated based on assumptions and represent contractual entitlements that may change over time.

  

	•	 	 The method and assumptions used to determine estimated amounts will not be identical to the method and assumptions used by other issuers and, as a
result, the figures may not be directly comparable to other issuers. 

 Termination and Change of Control Benefits

 Each of Mr. Struthers, Mr. D’Arcey, Mr. Marcello and Mr. Gregg is a party to an employment agreement with Hydro
One governing the terms of their employment. None of the NEOs have any rights or receive benefits on a change of control of the company. With respect to Mr. Struthers, Mr. D’Arcey, Mr. Marcello and Mr. Gregg, if their
employment is terminated by Hydro One without cause, each of Mr. Struthers, Mr. D’Arcey, Mr. Marcello and Mr. Gregg is entitled to receive an amount equal to her or his base salary at the date of termination in equal monthly
instalments for a period of 24 months (18 months in the case of Mr. Gregg as of December 31, 2012) and to receive benefits over the same period (including Incentive Plan payments equal to the average of

  
 2012 ANNUAL
INFORMATION FORM  115 

 SUMMARY COMPENSATION TABLE 

 

 
the three previous Incentive Plan payments). Each of Mr. Struthers, Mr. D’Arcey, Mr. Marcello and Mr. Gregg would continue to earn credited service under the Hydro One
Pension Plan during such 24-month period (18-month period in the case of Mr. Gregg as of December 31, 2012). Continuation of benefits will also continue until expiry of the severance period. For Mr. Gregg, effective January 1,
2013, the values above change from 18 months to 24 months. The amount of salary and incentive plan benefits expected to be paid if Mr. Struthers, Mr. D’Arcey, Mr. Marcello and Mr. Gregg were terminated on December 31,
2012 is summarized in the following table. 
  

													
	Name	  	Base Salary	 	  	3 year average
Incentive Payment	 	  	Total Payment	 
				
	 S. Struthers
	  	$	650,000	  	  	$	330,500	  	  	$	980,500	  
				
	 M. D’Arcey
	  	$	678,020	  	  	$	305,666	  	  	$	983,686	  
				
	 C. Marcello
	  	$	600,000	  	  	$	332,000	  	  	$	932,000	  
				
	 P. Gregg
	  	$	442,500	  	  	$	248,124	  	  	$	690,624	  

 The following information summarizes the amount by which each NEO’s annual pension would increase due to inclusion
of such 24-months (18 months in the case of Mr. Gregg) of additional credited service and any corresponding increase in average annual earnings calculated at the end of such 24-month period (18 months in the case of Mr. Gregg). 

Mr. Struthers’s annual pension accrued at December 31, 2011 would be expected to increase by $16,100 

Mr. D’Arcey’s annual pension accrued at December 31, 2011 would be expected to increase by $6,100 

Mr. Marcello’s annual pension accrued at December 31, 2011 would be expected to increase by $15,300 

Mr. Gregg’s annual pension accrued at December 31, 2011 would be expected to increase by $12,500 

The payment levels have been determined based on standard factors considered in termination situations, such as age, length of service, proximity to
retirement and job level. 
 Mr. Struthers, Mr. D’Arcey, Mr. Marcello and Mr. Gregg are not entitled to receive any
payment in the event of termination for cause or voluntary termination. 
 Upon retirement, all NEOs are entitled to benefits, which include
core health and dental coverage and life insurance applicable to all management employees employed at Hydro One. These benefits are identical to the retirement benefits provided to other management employees in the company. No benefits are provided
in the event of a termination of employment for any other reason in the NEO’s employment contract. 
 Ms. Formusa retired effective
December 31, 2012 and receives a pension in accordance with the amounts described in the pension table described above. Other than described above, Ms. Formusa is entitled to no other payments, or benefits, from the Company, as a result of
her retirement. 
 For the NEOs, there are no significant conditions or obligations that apply to receiving any of these

  
 116  HYDRO ONE INC.

 SUMMARY COMPENSATION TABLE 
  

 
benefits or payments other than a standard company confidentiality agreement. 

Director Compensation 
 The by-laws of
Hydro One provide that directors may receive reasonable remuneration for their services, commensurate with their duties, together with reimbursement for all reasonable expenses incurred in fulfilment of their duties, including travel expenses. The
amount of such remuneration is determined by the Board from time to time. The following remuneration is currently paid to directors: 

Retainer for directors $25,000 per annum 

Retainer for Committee Chairs $3,000 per annum 
 Participation in Board and Committee Meetings $900 per meeting 
 The fees are reviewed
periodically but have not been revised since 2001. The President and Chief Executive Officer is not entitled to these fees. Directors who travel large distances to attend Board and Committee meetings also receive an allowance of $900 for each
meeting or series of meetings. Directors are also reimbursed for travel and other expenses incurred for attendance at Board and Committee meetings. Directors’ fees, less statutory deductions, are paid quarterly by direct deposit or cheque as
requested. 
 Mr. James Arnett was appointed Chair of the Board on March 31, 2008. The Chair receives annual remuneration of $150,000
per annum and does not receive any additional fees for serving as a director. 
 The following table summarizes the compensation earned in 2012
by the directors of Hydro One. 
 Director Compensation Table 

 

													
	Name	  	Fees Earned	 	  	All other compensation1	 	  	Total	 
				
	 James Arnett, Chair
	  	$	150,000.00	  	  	$	0	  	  	$	150,000.00	  
				
	 Sami Bébawi
	  	$	8,502.74	  	  	$	900.00	  	  	$	9,402.74	  
				
	 Kathryn Bouey
	  	$	52,376.72	  	  	$	0	  	  	$	52,376.72	  
				
	 George Cooke
	  	$	47,568.50	  	  	$	0	  	  	$	47,568.50	  
				
	 Janet Holder
	  	$	43,068.50	  	  	$	5,400.00	  	  	$	48,468.50	  
				
	 Don MacKinnon
	  	$	43,376.72	  	  	$	0	  	  	$	43,376.72	  
				
	 Michael Mueller
	  	$	55,076.72	  	  	$	8,100.00	  	  	$	63,176.72	  
				
	 Walter Murray
	  	$	58,676.72	  	  	$	9,900.00	  	  	$	68,576.72	  
				
	 Robert Pace
	  	$	55,076.72	  	  	$	7,200.00	  	  	$	62,276.72	  
				
	 Yezdi Pavri
	  	$	4,480.82	  	  	$	0	  	  	$	4,480.82	  
				
	 Gale Rubenstein
	  	$	64,076.72	  	  	$	0	  	  	$	64,076.72	  
				
	 Douglas Speers
	  	$	63,176.72	  	  	$	11,700.00	  	  	$	74,876.72	  
				
	 TOTAL
	  	$	645,457.60	  	  	$	43,200.00	  	  	$	688,657.60	  

  

	1.	All other compensation is the cumulative travel allowance, described above, for attendance at meetings or series of meetings. 

  
 2012 ANNUAL
INFORMATION FORM  117 

 APPOINTMENT OF AUDITOR 

 

 APPOINTMENT OF AUDITOR 
 On December 13, 2007, the Board recommended to our sole shareholder that KPMG LLP be appointed as the auditor of our company for the fiscal year ended December 31, 2008. This appointment was
confirmed by our sole shareholder on December 19, 2007. In 2012, KPMG LLP was re-appointed as the auditor of our company for the fiscal year ended December 31, 2012, which appointment was confirmed by our sole shareholder. 

  
 118  HYDRO ONE INC.

 AUDIT AND FINANCE COMMITTEE INFORMATION 

 

 AUDIT AND FINANCE COMMITTEE INFORMATION 
 The Audit and Finance Committee’s Charter 
 Our Audit and Finance Committee’s
mandate is attached hereto as Appendix “A”, which Appendix is hereby incorporated by reference. The Audit and Finance Committee mandate was last reviewed on December 13, 2012. 
 Composition of the Audit and Finance Committee 
 As at December 31, 2012, the members
of our Audit and Finance Committee were Michael Mueller (Chair), Kathryn Bouey, George Cooke, Walter Murray and Yezdi Pavri. All members are independent, and all members are financially literate as such terms are defined under applicable Canadian
securities legislation. 
 Relevant Education and Experience 
 In addition to each member’s general business experience, the education and experience of each Audit and Finance Committee member who was serving as a member of the Audit and Finance Committee on
December 31, 2012 that is relevant to the performance of his or her responsibilities as an Audit and Finance Committee member is described below. 
 Mr. Mueller is a former Global Leader of PricewaterhouseCoopers’ (PwC) Private Company Services/Middle Market Practice and a former member of PwC’s Global Audit Leadership Team, Global
Advisory Leadership Team and the Global Markets Council. From 1996 to 2005, Mr. Mueller held the position of COO and National Managing Partner of PwC Canada. Mr. Mueller is a Chartered Accountant, and a Chartered Business Valuator. Until
2009, he was a Certified Insolvency Practitioner. Since July 2010, Mr. Mueller is a Director and Chair of the Audit and Finance Committee for SMART Technologies Inc. 
 Ms. Bouey is President of TBG Strategic Services Inc., a management consulting firm. From 2001 to 2005, Ms. Bouey was the Deputy Minister of the Management Board Secretariat, Province of Ontario
and previously held other senior management positions with the Province, including: Deputy Minister of Intergovernmental Affairs (1999-2001); and Assistant Deputy Minister, Corporate Services Group, Ministry of Health and Long-Term Care (1997-1999).
Previously, she held the position of Chair of the Ontario Civil Service Commission and has served on the boards of the Canadian Comprehensive Auditing Foundation, Ontario Power Generation, the Ontario Financing Authority, the Ontario Pension Board
and Sheridan College of Technology and Applied Learning. Ms. Bouey obtained a Master of Arts (Economics) from Carleton University in 1981 and was certified by the Institute of Corporate Directors in 2006. She also completed the Rotman/Institute
of Corporate Directors course on Financial Literacy for Directors and Executives in 2005. 
 Mr. Cooke is the former President and CEO, The
Dominion of Canada General Insurance Company (“The Dominion”), a position he held from 1992 when he joined the company to August 2012. In August 2012, Mr. Cooke retired from his role as President of The Dominion and continued to hold
the position of Chief Executive Officer of the company until December 31, 2012. Prior to his appointment with The Dominion, Mr. Cooke was Vice President (Ontario Division), S.A. Murray Consulting Inc. (a government relations consulting

  
 2012 ANNUAL
INFORMATION FORM  119 

 AUDIT AND FINANCE COMMITTEE INFORMATION 
  

 
firm) between 1990 and 1992. His previous experience also includes Special Advisor, Policy to the Ontario Deputy Premier and Treasurer (1989-1990), General Manager, Ontario Automobile Insurance
Board (1988-1989), and positions with the OEB (1980-1988). Mr. Cooke was a member of the Board of Directors of Atomic Energy Canada Limited (1995 to 1999) and a member of the Audit Committee. He obtained a Bachelor of Arts degree (Hons.) in
Political Studies (1975) and a Master’s of Business Administration degree (1977) from Queen’s University, Kingston, Ontario. He also holds an Honorary Doctor of Laws degree (1999) from Assumption University in Windsor. He is
currently a member of the Board of Directors of: The Dominion of Canada General Insurance Company, and the Insurance Bureau of Canada. Mr. Cooke is also an Executive Vice President with E-L Financial Corporation Limited, a position he will hold
until June 30, 2013. 
 Mr. Murray is the former Vice-Chairman and member of the Executive Committee of RBC Capital Markets, an
international corporate and investment bank. His 38 year career at the RBC Royal Bank included Senior Executive Investment Banking responsibility, Executive head of corporate banking activities for Canada and Regional Executive for RBC’s
Midwestern USA Corporate Banking operations. Mr. Murray is a former director of Ivernia Inc.’s Board of Directors and past Chair of its audit committee. Mr. Murray holds a Bachelor of Commerce degree from Concordia University majoring
in Accounting and Business Administration. He is also a graduate of the Executive Development Program at the Tuck School of Business, Dartmouth College, New Hampshire. 
 Mr. Pavri is a Chartered Accountant, a former Vice-Chairman (June 2010 – June 2012), and a former Toronto Managing Partner (June 2004-May 2010) of Deloitte Canada, a leading professional
services firm for audit, tax, consulting and financial advisory services. Mr. Pavri’s experience with Deloitte Canada has included overall responsibility for a number of the firm’s key clients in the financial, retail and governmental
sectors. Between 1990-2004, Mr. Pavri was National Managing Partner for Deloitte Canada’s Enterprise Risk Services group. Mr. Pavri holds a B. Technology from the Indian Institute of Technology (Aeronautical Engineering) 1972; a M.Sc.
from the Imperial College, London University (Thermal Power Engineering) 1974; and obtained his Chartered Accountant accreditation in 1979 while he was an accountant with Binder Hamlyn, Chartered Accountants, London, UK (1974-1979). In 1979,
Mr. Pavri joined Touche Ross in Toronto as an accountant. He is a Fellow of the Institute of Chartered Accountants in England and Wales, and is also a Fellow of the Institute of Chartered Accountants of Ontario. 

Audit and Finance Committee Oversight 

There have been no recommendations of our Audit and Finance Committee to nominate or compensate an external auditor which have not been adopted by our
Board. 
 Pre-Approval Policies and Procedures 
 In accordance with the provisions of its mandate, the Audit and Finance Committee ratifies all non-audit services, as pre-approved by the Committee Chair, to be provided to our company by its external
auditor. 

  
 120  HYDRO ONE INC.

 AUDIT AND FINANCE COMMITTEE INFORMATION 

 

 External Auditor Service Fees 

 

	(a)	Audit Fees 

 The
audit fees to be billed by KPMG LLP for fiscal 2012 are estimated to be approximately $806,000. The audit fees billed by KPMG LLP for fiscal 2011 were $695,140. 
  

	(b)	Audit-Related Fees 

The total audit-related fees billed by KPMG LLP for fiscal 2012 are estimated to be approximately $180,000. The total audit related fees
billed by KPMG LLP for fiscal 2011 were $292,113. The nature of services rendered in both years were: audit of the Hydro One Pension Plan, audit of the Hydro One Employees’ and Pensioners’ Charity Trust, French translations and executive
expense reviews. 
  

	(c)	Tax Fees 

 There
were no tax fees billed by KPMG LLP for fiscal 2012 or fiscal 2011 as KPMG LLP did not provide any professional services in respect of tax compliance, tax advice or tax planning. 

 

	(d)	All Other Fees 

There were no other fees billed by KPMG LLP for fiscal 2012 or fiscal 2011. 

  
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 CORPORATE GOVERNANCE DISCLOSURE 

 

 CORPORATE GOVERNANCE DISCLOSURE 
 Board of Directors 
 The Board has undertaken an independence assessment and determined
that, except as noted below, all of Hydro One’s current directors are “independent” within the meaning of the rules adopted by the Canadian Securities Administrators (the “CSA”). Ms. Laura Formusa, who was the President
and Chief Executive Officer of our company and a member of the Board until her retirement on December 31, 2012, is not independent as she is an executive officer of our company. Mr. Marcello, who succeeded Ms. Formusa effective
January 1, 2013 as President and Chief Executive Officer as a member of the Board, is also not independent as he is an executive officer of our company. In addition, Mr. James Arnett, the Chair of our Board, is also not considered
independent as he acts as our Chair and accordingly is considered an executive officer of our company. 
 The Board has separated the roles of
Chair and Chief Executive Officer. The prime responsibility of the Chair of the Board is to provide leadership to the Board and to enhance Board effectiveness. The Chair, as the presiding member of the Board, also ensures that the relationships
between the Board, management, the shareholder and other stakeholders are effective, efficient and further the best interests of our company. The Chair also encourages input and significant participation of independent directors in the leadership of
our company. 
 Directors hold regularly scheduled meetings at which members of management are not in attendance. During 2012, nine such
sessions without management were held at Board of Directors’ meetings. Each Committee of the Board also holds regular in camera sessions without management present. As well, the Audit and Finance Committee regularly holds such sessions with the
external auditors and with the internal auditor. The Chair of the Audit and Finance Committee meets four times a year with the internal auditor. These sessions encourage open and candid discussion among the directors including amongst independent
directors. 

  
 122  HYDRO ONE INC.

 CORPORATE GOVERNANCE DISCLOSURE 
  

 Summary of Attendance of Directors 
 The following table summarizes the attendance of individual directors at meetings of the Board of Directors held for the 12-month period ending December 31, 2012. 

 

			
	Director	 	Board Meetings Attended
		
	James Arnett	 	9 of 9
		
	Sami Bébawi1	 	1 of 2
		
	Kathryn Bouey	 	9 of 9
		
	George Cooke	 	9 of 9
		
	Janet Holder	 	8 of 9
		
	Laura Formusa2	 	8 of 8
		
	Don MacKinnon	 	8 of 9
		
	Michael Mueller	 	9 of 9
		
	Walter Murray	 	9 of 9
		
	Robert Pace	 	9 of 9
		
	Yezdi Pavri3	 	1 of 1
		
	Gale Rubenstein	 	8 of 9
		
	Douglas Speers	 	9 of 9

  

	1 	 Mr. Bébawi resigned from the Board on April 21, 2012 and only two meetings of the Board were held prior to that time.

	2 	 Ms. Formusa was not in attendance at one meeting of the Board of Directors because this meeting was an in camera meeting of the Board for external
Directors that solely addressed Ms. Formusa’s successor as President and CEO of the company. 

	3 	 Mr. Pavri was elected to the Board on December 6, 2012 and only one meeting of the Board was held since his election to the Board.

  
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 Directors’ Board Memberships in Other Reporting Issuers 

 

			
	Director	 	Reporting Issuer
		
	Robert Pace	 	 Canadian National Railway Company,
 High Liner Foods Incorporated

		
	Michael Mueller	 	Smart Technologies Inc.

 Board Mandate 
 The Board is responsible for the stewardship of our company and the supervision of management of the business and affairs of our company. The Board’s accountabilities and responsibilities include
development of our company’s approach to corporate governance, the adoption of a strategic plan and oversight of risk management, as well as oversight of the company’s pension plan. The Board has adopted a written mandate, the text of
which is set out as Appendix “B” and which is hereby incorporated by reference. 
 Position Descriptions 

The Board has adopted formal position descriptions for the Chair of the Board and the Board Committee Chairs. The position descriptions of each Committee
Chair are set out in the Committees’ mandates. In general, Committee Chairs are responsible for the leadership of their Committee as well as reporting to the Board on behalf of the Committee. The Board has also adopted a position description
for the President and Chief Executive Officer, which sets out the key roles and responsibilities for that position. 
 Committees of the
Board of Directors 
 The Board has established seven standing committees of the Board and delegates certain of its enumerated
responsibilities to each of the Committees. Notwithstanding this delegation, the Board retains its oversight function and ultimate responsibility for all matters delegated to committees. 
 The seven standing committees of the Board are the Audit and Finance Committee, the Business Transformation Committee, the Corporate Governance Committee, the Health, Safety and Environment Committee, the
Human Resources Committee, the Investment-Pension Committee, and the Regulatory and Public Policy Committee. The roles and responsibilities of each Committee are set out in formal written mandates. These mandates are reviewed at least annually to
ensure that they reflect best practices as well as applicable regulatory requirements. In 2010, the Committee structure was revised to support the efficient operation of the Committees and the Board’s oversight of the business of the company. A
brief summary of each of the Committees’ responsibilities follows. 
 Audit and Finance Committee 

The Audit and Finance Committee is composed entirely of independent directors or directors who are exempt from such independence requirements as required
by the CSA rules (for more information, see the mandate of the Audit and Finance Committee which is attached and the discussion concerning the composition of the Audit and Finance Committee above). The Audit and Finance Committee oversees the
integrity of accounting policies and financial reporting, internal controls, internal audit, financial risk exposures, financial compliance and ethics policies. In 2011, the mandate of the Audit and Finance Committee was amended to reflect that
oversight responsibility for corporate risk management resides with the Board 

  
 124  HYDRO ONE INC.

 CORPORATE GOVERNANCE DISCLOSURE 
  

 Business Transformation Committee 
 The Business Transformation Committee is composed entirely of independent directors and was first established as an ad hoc advisory Committee of the Board specifically to assist the Board in its oversight
responsibility on matters related to our company’s Cornerstone project. 
 In May 2009, the Committee’s mandate was amended to include
oversight responsibility for all matters related to the “ADS and Continuous Innovation Strategy”. In 2010, the Committee’s mandate was further amended to include oversight responsibility for all matters related to the planning,
development and implementation of major transmission system or distribution projects including the projects described in the Corporation’s Green Energy Implementation Plan. 
 Corporate Governance Committee 
 The Corporate Governance Committee is composed
entirely of independent directors with the exception of Mr. Arnett. The Corporate Governance Committee acts as the nominating committee of the Board and recommends director candidates, committee assignments, director compensation, and corporate
governance policy for committees and the board as a whole. The Corporate Governance Committee reviews the general and specific criteria applicable to candidates to be considered for nomination to the Board. The objective of this review is to
maintain the composition of the Board in a way that provides the best mix of skills and experience to guide the long-term strategy and ongoing business operations of our company. In addition, the Corporate Governance Committee leads an annual
evaluation of the Board and makes recommendations on modifications of the evaluation process. 
 Health, Safety and Environment Committee

 The Health, Safety and Environment Committee advises the Board on health, safety and environment policies and standards, oversees
compliance with health, safety and environment regulations at our company, and reviews and reports to the Board on our company’s emergency preparedness. 
 Human Resources Committee 
 The Human Resources Committee (the “HR
Committee”) is composed entirely of independent directors. The HR Committee recommends compensation policy for senior managers, leads the performance review of the President and Chief Executive Officer, and recommends bargaining strategy with
respect to the unions. In this regard, the Committee also reviews succession planning and the recommendations for the appointment of persons to senior executive positions. The HR Committee also engaged Hugessen Consulting Inc. to advise the
Committee and the Board on the competitiveness and effectiveness of the company’s compensation programs. For additional information relating to the compensation of our company’s senior executives, see “Statement of Executive
Compensation.” 
 Investment-Pension Committee 
 The Investment-Pension Committee’s primary function is to assist the Board in fulfilling its oversight responsibilities in all matters related to the Hydro One Pension Plan including the Hydro One
Pension Fund. 
 Regulatory and Public Policy Committee 
 The Regulatory and Public Policy Committee monitors our company’s compliance with regulatory requirements and related risk, reviews related policies and generally oversees processes and procedures
related to regulatory compliance at our company. The Regulatory and Public Policy 

  
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 CORPORATE GOVERNANCE DISCLOSURE 

 

 
Committee also advises the Board on public policy matters and corporate social responsibility issues. 
 Orientation and Continuing Education 
 Hydro One’s “The Director Orientation and
Continuing Education Program” was established in accordance with the principles set out in the Business Corporations Act (Ontario), National Policy 58-201: Corporate Governance Guidelines, the mandate of the Board and the mandates
of the Corporate Governance and Audit and Finance Committees. The Director Orientation and Continuing Education Program consists of two elements: the New Director Orientation Program and the Continuing Director Education Program. The New Director
Orientation Program consists of a Hydro One Directors’ Guide, which is given to all new directors upon joining the Board to provide them with an overview of the key organizational, financial, regulatory, and operational aspects of our company.
The Directors Guide also contains information on the structure of the Board and its committees, committee mandates and general information on a director’s obligations. In addition, new directors receive orientation sessions with the Chair, the
President and Chief Executive Officer and members of the senior management team as well as tours of our company’s facilities. The orientation sessions familiarize directors with Hydro One’s strategic plans, its significant financial,
accounting and risk management issues, its compliance programs, its Pension Plan and the directors’ obligations as plan fiduciaries, and its Code of Business Conduct. 
 The Continuing Director Education Program includes, on an ongoing basis, as part of regular Board meetings, information briefings, presentations and updates from senior management on relevant topics
related to our company’s business. These information items are either suggested by management or may be requested by members of the Board. As well, directors receive information from management in response to any actions arising at a Board
meeting or otherwise. The Continuing Director Education Program also includes articles and other information from relevant publications, which are forwarded to directors, visits to Hydro One facilities, and, attendance at industry events and
conferences and seminars which are relevant external education opportunities or general courses of interest. 
 Ethical Business Conduct

 The Board has adopted a written Code of Business Conduct (the “Code”). The Code sets out a comprehensive set of principles and
expectations relating to ethical conduct, conflicts of interest and compliance with laws. The Code is part of Hydro One’s internal control framework and applies to all of Hydro One’s directors, officers and employees. The Code also applies
to Hydro One’s agents, consultants, contractors and business partners, to the extent feasible. The Code is posted on the corporate intranet site and on the external corporate website at www.HydroOne.com. 

Our company has a Corporate Ethics Officer who is accountable for making sure that the appropriate actions are taken to investigate and resolve known or
suspected violations of the Code, and for ensuring the tracking and reporting of all violations. The Board monitors compliance with the Code through the Human Resources Committee and the Audit and Finance Committee, to whom the Corporate Ethics
Officer reports. The President and Chief Executive Officer is ultimately responsible for our company’s compliance with the Code. Further, the Board abides by a conflict of interest policy which requires directors to exercise independent
judgment when considering transactions and contracts in respect of which a director has a material interest. 

  
 126  HYDRO ONE INC.

 CORPORATE GOVERNANCE DISCLOSURE 
  

 In 2008, the Code was updated to reflect changes in Hydro One’s organizational structure, corporate
accountabilities, and the Company’s business strategy. The revised Code reflects current best governance and ethics practices, including the introduction of a third-party hotline for the anonymous reporting of any accounting, internal
accounting controls or auditing matters. The document can be found at: http://www.HydroOne.com/Careers/Pages/ CodeofConduct.aspx. 
 Board,
Committee and Director Assessments 
 A process is in place for evaluating the effectiveness of the Board and its Committees. The process
consists of a long-form and short-form evaluation process. The long-form Board evaluation process consists of three written questionnaires: Board, Individual Director, and Committee Assessments of the Board. The Board Assessment addresses the areas
of Board responsibility, operation and effectiveness. The Individual Director Assessment allows each director to identify areas for improved individual development and performance. The Committee Assessment addresses areas of committee operations and
allows each Committee member to identify areas for improved performance. 
 In alternate years, a short-form Board evaluation process consisting
of a one-page questionnaire in which Board members provide comments on any issues that may be of concern to them, is completed. 
 In addition
to the written questionnaires, the Chair of the Board also meets annually with each director about individual performance and the effectiveness of the Board and Committees. 
 The responses to each questionnaire are compiled in summary reports, which are reviewed by the Corporate Governance Committee to determine what, if any, actions may need to be taken. The Chair of the
Corporate Governance Committee provides a report on the summary reports to the Board. 

  
 2012 ANNUAL
INFORMATION FORM  127 

 APPENDIX “A” 

 

 APPENDIX “A” 
 AUDIT AND FINANCE COMMITTEE 
 Mandate 

 

	1.	Pursuant to By-Law No. 1 of Hydro One Inc. (the “Corporation”), a committee of the directors to be known as the “Audit and Finance Committee”
(hereinafter referred to as the “Committee”) is hereby established. 

  

	2.	The Committee shall be composed of a minimum of four directors, and have membership attributes consistent with applicable requirements under the Securities Act
(Ontario) and regulations there under including: 

  

	 	•	 	 Independence. The Committee shall be comprised of directors who shall meet the independence and audit committee composition requirements set
forth by applicable securities regulatory authorities, or any governmental or regulatory body exercising authority over the Corporation, as in effect from time to time. A member cannot accept consulting, advisory or compensatory fees, other than
compensation for directors’ fees and expenses, from the Corporation. 

  

	 	•	 	 Financial Literacy. All members are to be financially literate (or shall become financially literate within a reasonable period of time after
appointment to the Committee). A member is financially literate if he or she has the ability to read and understand a set of financial statements that present a breadth and level of complexity of accounting issues that are generally comparable to
the breadth and complexity of issues that can reasonably be expected to be raised by the Corporation’s financial statements. 

  

	3.	The members of the Committee shall be appointed or re-appointed at the Organizational Meeting of the Board of Directors (the “Board”) immediately following
each annual meeting of the Shareholder of the Corporation. Each member of the Committee shall continue to be a member thereof until his or her successor is appointed, unless such member shall resign or be removed by the Board or shall cease to be a
director of the Corporation. Where a vacancy occurs at any time in the membership of the Committee, it may be filled by the Board and shall be filled by the Board if the membership of the Committee is less than four directors as a result of the
vacancy. Whenever there is a vacancy on the Committee, the remaining members may exercise all of the powers of the Committee as long as a quorum remains in office. 

 

	4.	The Board or, in the event of its failure to do so, the members of the Committee, shall appoint a Chair from amongst their number. If the Chair of the Committee is not
present at any meeting of the Committee, the Chair of the meeting shall be chosen by the Committee from among the members present. The Committee Chair shall be responsible for the leadership of the Committee, including the preparation of the agenda,
presiding over meetings and determining Committee assignments. The Chair presiding at any meeting of the Committee shall have a casting vote in case of deadlock. The Committee shall also appoint a Secretary who need not be a director.

  
 128  HYDRO ONE INC.

 APPENDIX “A” 
  

	5.	The time and place of meetings of the Committee and the procedure at such meetings shall be determined from time to time by the members thereof provided that:

 (a) a quorum for meetings shall be three members, present in person or by telephone or other telecommunication
device that permit all persons participating in the meeting to speak and hear each other; 
 (b) the Committee shall meet at
least quarterly; and 
 (c) notice of the time and place of every meeting shall be given in writing by facsimile communication or
electronic mail to each member of the Committee, the internal auditors and the external auditors of the Corporation at least 24 hours prior to the time fixed for such meeting, provided, however, that a member may in any manner waive a notice of a
meeting; and attendance of a member at a meeting is a waiver of notice of the meeting, except where a member attends a meeting for the express purpose of objecting to the transaction of any business on the grounds that the meeting is not lawfully
called. The Committee may request the external auditors to attend a meeting or meetings of the Committee, the expense of which shall be paid by the Corporation and included within the external auditors’ annual fee. A meeting of the Committee
may be called by the Secretary of the Committee on the direction of the Chair or Chief Executive Officer of the Corporation, by any member of the Committee, the external auditors or internal auditors. Notwithstanding the provisions of this
paragraph, the Committee shall at all times have the right to determine who shall and shall not be present at any part of the meeting of the Committee. 
  

	6.	The Committee Chair is responsible for reporting to the Board on behalf of the Committee on matters considered by the Committee, its activities and compliance with this
mandate. 

  

	7.	For purposes of this Section, the term “Corporation” shall include Hydro One Inc. and its subsidiary entities, as defined by Multilateral Instrument 52-110
Audit Committees. 

 The Committee shall: 
 (1) in connection with its advisory functions: 
 (a) review the internal audit
procedures of the Corporation and advise the Board on its auditing practices and procedures and obtain adequate assurance that internal controls are adequate; 
 (b) meet separately with the external auditors and internal auditors; 
 (c)
recommend to the Board and shareholder the retention and, if appropriate, the removal of external auditors, evaluating and remunerating them, and monitoring their qualifications, performance and independence; 

(d) review periodically, reports on the nature and extent of compliance with requirements regarding statutory deductions and remittances,
including deductions and 

  
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 APPENDIX “A” 

 

 
remittances under the Income Tax Act (Canada), the Excise Tax Act (Canada), the Employment Insurance Act (Canada), and the Canada Pension Plan Act, each Act as amended
from time to time, the nature and extent of non-compliance together with the reasons therefore and the plan and timetable to correct deficiencies and report to the Board on the status of such matters; 

 

	(e)	review and reassess the Committee’s mandate at least annually and report to the Board results of the review, including any recommended changes to the mandate;

  

	(f)	the Committee shall meet with management to review and assess the process and systems in place for the review of public disclosure documents that contain audited and
unaudited financial information and their effectiveness; 

  

	(g)	describe in the annual information form all information about the Committee as required by applicable securities regulatory authorities; and 

 

	(h)	review and assess with management and recommend to the Board for approval any material transaction, contract or other matter involving the Corporation and a
shareholder, or other person, which owns directly or indirectly voting securities of the Corporation. For this purpose, “material” means any transaction, contract or matter that significantly affects, or would reasonably be expected to
have a significant effect on, the financial position of the Corporation or the market price or value of its securities. 

  

	(2)	In connection with the exercise of its powers: (a) review and recommend to the Board for approval: 

(i) the audited annual financial statements of the Corporation, the annual management discussion and analysis (“MD&A”) and
any required annual MD&A supplement and related press releases before the Corporation publicly discloses this information; 

(ii) the Corporation’s interim (quarterly) financial statements, interim MD&A and any required interim MD&A supplement and
related press releases before the Corporation publicly discloses this information, unless the Board delegates to the Committee such approval authority as provided in paragraph (b) below; 

(iii) all financial statements in prospectuses and other offering memoranda, and financial statements required by securities regulatory
authorities; 
 (iv) the annual information form of the Corporation and any other similar disclosure required to be filed by
securities regulatory authorities; 
 (v) any prospectus, offering memorandum of the Corporation, or any amendments thereto. For
the purpose of this mandate, reference to “prospectus” includes a preliminary prospectus, a prospectus, or an amendment thereto, but excludes a pricing supplement; 
 (vi) the annual financing plans and objectives of the Corporation including, foreign currency risk and interest rate risk strategies; and 

  
 130  HYDRO ONE INC.

 APPENDIX “A” 
  

 (vii) the Corporation’s annual Budget and Outlook, and annual Business Plan, and
any amendments thereof. 
 (b) subject to the authority delegated by the Board, review and approve the Corporation’s interim
financial statements, interim MD&A and any interim MD&A supplement, and review and approve the related press releases; 

(c) discuss with the external auditors results of their review of the interim financial statements and interim MD&A, including any
matters external auditors may raise with audit committees under generally accepted accounting principles and auditing standards in compliance with applicable securities laws and regulations; 

(d) review the issuance under a shelf prospectus of the Corporation of debentures, notes and/or other unsecured and secured evidences of
indebtedness of the Corporation, in accordance with the authority delegated by the Board and the filing with securities regulatory authorities of any prospectus supplement relating thereto; 

(e) review and oversee the audit plans of the internal auditors and review, pre-approve and directly be responsible for overseeing the
work of the external auditors of the Corporation engaged for the purpose of preparing or issuing an auditor’s report or performing other audit, review or attest services for the Corporation, including the resolution of any disagreements between
management and the external auditors regarding financial reporting. The Committee has the authority to communicate directly with the internal and external auditors. 
 The Committee shall also review the degree of co-ordination between the audit plans of the internal auditors and the external auditors and will inquire as to the extent the planned audit scope can be
relied upon to detect weaknesses in internal control, fraud or other illegal acts. Any significant recommendations made by the auditors for the strengthening of internal controls will be reviewed; 

(f) pre-approve all audit and non-audit services to be provided to the Corporation by its external auditors. In connection with non-audit
services, the Committee shall adopt specific policies and procedures for the engagement of non-audit services ensuring that the non-audit service is not prohibited or restricted by securities regulatory authorities. The Committee may also delegate
to one or more of its members the authority to pre-approve audit and non-audit services, in which event the pre-approval of audit and non-audit services by any such member must be presented to and ratified by the Committee at its first scheduled
meeting following such pre-approval; 
 (g) review the internal control procedures and management’s annual internal control
report to ensure compliance with the law and avoidance of conflicts of interest including, without limitation, a review of policies and practices concerning officers’ expenses and perquisites, including the use of the Corporation’s assets;

 (h) review the duties and responsibilities of internal audit staff respecting controls, procedures and accounting practices of
the Corporation; 

  
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 (i) review management programs and policies regarding the adequacy and effectiveness of
internal controls over the accounting and financial reporting systems within the Corporation and, in particular, the Committee will review management’s response to the internal control recommendations of the internal and external auditors;

 (j) receive and review regular reports from the internal and external auditors on the appropriateness of the
Corporation’s significant accounting and disclosure policies and practices and changes thereto, including any areas of management judgment and estimates that have a material effect upon the financial statements, alternative accounting
treatments and their ramifications, disagreements between management and the internal and external auditors and include in the review a discussion with the external auditors of the quality, not just acceptability, of accounting principles, the
reasonableness of significant judgments, and the clarity and completeness of disclosure; 
 (k) review with management, the
external auditors and, if necessary, with legal counsel, any litigation, claim or other contingency, including tax assessments, that could have a material effect upon the financial position or operating results of the Corporation, and the manner in
which these matters have been disclosed in the financial statements; 
 (l) review, at least annually, the Corporation’s
corporate insurance program; 
 (m) annually discuss with external auditors and report to the Board the auditors’
independence from management and the Corporation, and in connection, request their written confirmation of independence and disclosure of relationships they have with the Corporation that may be thought to bear on independence, including non-audit
related services and fees and their impact; 
 (n) review the minutes of any audit committee meetings of subsidiary entities of
the Corporation and any significant issues and auditor recommendations concerning such subsidiary entities; 
 (o) review the
basis and amount of the external auditor’s fees in light of the number and nature of reports issued by the auditors, the quality of the internal controls, the size, complexity and financial condition of the Corporation and the extent of
internal audit and other support provided by the Corporation to the external auditors and review all other non-audit fees of the auditors or other accounting firms; 
 (p) review management’s retention of consulting and professional services, including external legal services, on an annual basis; 

(q) review and appropriately address any complaints regarding accounting, internal accounting controls, or auditing matters received since
the Committee’s last meeting, including complaints confidentially submitted by those wishing to remain anonymous; and 
 (r)
receive and review any reports of evidence of a material violation of securities laws or breaches of fiduciary duty tabled by the Corporation’s legal counsel as a result of an inappropriate response from management. 

  
 132  HYDRO ONE INC.

 APPENDIX “A” 
  

 (3) review and approve the Corporation’s hiring policies regarding partners,
employees and former partners and employees of the current and former external auditor of the Corporation. 
 (4) review, at
least on an annual basis: 
 (a) for information purposes: 

(i) overall financing of risk, including the purchase of insurance; 

(ii) loss prevention policies and insurance risk management programs; 

(b) and recommend to the Board for approval financial risk management strategies, including foreign currency and interest rate risk
strategies. 
 (5) With respect to the Corporation’s Pension Plan and Fund, review and recommend to the Board for approval
the Hydro One Pension Plan and Fund Annual Report and Audited Financial Statements. 
  

	8.	The Committee is responsible for monitoring the Strategic Objectives contained in the annual Corporate Scorecard applicable to it, as determined from time-to-time by
the Corporate Governance Committee of the Board. 

  

	9.	In instances where members of the Committee believe that in order to properly discharge their fiduciary obligations to the Corporation it is necessary to obtain the
advice of independent counsel and other expert advisers, the Committee shall have authority to engage and compensate the appropriate experts. The Board shall be kept apprised of both the selection of the experts and the expert’s findings
through the Committee’s regular reports to the Board. 

  
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 APPENDIX “B” 

 

 APPENDIX “B” 
 HYDRO ONE INC. BOARD OF DIRECTORS 
 Mandate 

Duties of the Board of Directors 
  

	1.	The Board of Directors of Hydro One Inc. (the “Board”) is responsible for the stewardship of, and has the duty to supervise the management of, the business
and affairs of the Corporation including its Subsidiaries, as defined in the Business Corporations Act (Ontario). 

  

	2.	The Board is elected by the sole Shareholder, the Province of Ontario, as represented by the Minister of Energy and Infrastructure (the “Shareholder”). The
Board is responsible for seeking and recommending suitable Board candidates to the Shareholder. 

 Accountabilities and
Responsibilities 
 The Board shall have the accountabilities and responsibilities set out below. In addition, the Board shall perform such
duties as may be required under, and act in accordance with the Business Corporations Act (Ontario), the Corporation’s by-laws, the Memorandum of Agreement with the Shareholder, dated March 27, 2008 (the “Shareholder
Agreement”), as may be amended from time to time, and all applicable laws. 
  

	1.	Corporate Governance 

  

	a.	The Board is responsible for developing the Corporation’s approach to corporate governance, including developing appropriate policies and procedures and delegating
such other matters as it sees fit to the Corporate Governance Committee for its review and consideration. 

  

	b.	The Board is responsible for the Corporation’s approach to its governance relationship with its sole Shareholder. 

 

	2.	Strategic Planning 

 The Board is
responsible for: 
  

	a.	adopting a strategic planning process and approving, on at least an annual basis, a strategic plan which lays out the strategic direction of the Corporation in the
context of the opportunities and risks of the business and the business and commercial environment in which it operates; 

  

	b.	reviewing and approving the business, financial, strategic and other plans proposed by management to enable the Corporation to execute its strategy;

  

	c.	adopting processes for monitoring the Corporation’s progress toward its strategic and operational goals, and to revising and altering its directions to management
in light of changing circumstances affecting the Corporation; 

  

	d.	taking action when corporate performance falls short of its performance targets or other special circumstances warrant; 

 

	e.	approving the audited financial statements, interim financial statements and the notes and management’s discussion and analysis accompanying such financial
statements and the Corporation’s Annual Information Form; 

  

	f.	reviewing and approving material transactions outside the ordinary course of business, subject to the Shareholder Agreement; and 

 

	g.	overseeing the Corporation’s Pension Plan and Fund. 

  
 134  HYDRO ONE INC.

 APPENDIX “B” 
  

	3.	Risk Management 

 The Board is responsible
for: 
  

	a.	identifying the principal risks of the Corporation’s business and ensuring the implementation of appropriate systems to effectively monitor and manage such risks
with a view to the long-term viability of the Corporation; 

  

	b.	reviewing the major risks to the Corporation’s business objectives (Corporate Risk Profile); 

 

	c.	reviewing the risk retention philosophy and risk tolerance guidelines; 

  

	d.	reviewing and approving the Corporation’s enterprise risk management policy and framework; 

 

	e.	overseeing the integrity of the Corporation’s internal control and management information systems; 

 

	f.	approving and monitoring compliance with, all significant policies and procedures by which the Corporation is operated; and 

 

	g.	approving policies and procedures designed to ensure that the Corporation operates at all times within applicable laws and regulations. 

 

	4.	Human Resources Management 

  

	a.	The Board is responsible for approving the appointment of the President and CEO. The Board is also responsible for approving the compensation of the President and CEO
and the performance agreement of the President and CEO following a review of the recommendations of the Human Resources Committee. 

  

	b.	The Board will, to the extent feasible, satisfy itself as to the integrity of the President and CEO and other executive officers, and that the President and CEO and
other executive officers create a culture of integrity throughout the organization. 

  

	c.	The Board is responsible for ensuring that succession planning programs are in place, including programs to train, develop, monitor and retain senior management,
including the President and CEO. 

  

	5.	Communications and Reporting 

  

	a.	The Board is responsible for approving and revising from time to time, a disclosure policy to address accurate and timely communications with the Shareholder,
bondholders, employees, financial analysts, governments and regulatory authorities, the media and the public. 

  

	b.	The Board is responsible for overseeing the Corporation’s reporting to the Shareholder, responses to requests for information and other reporting obligations as
set out in the Shareholder Agreement, and for ensuring open and transparent communication with the Shareholder. 

  

	6.	Board Meetings and Materials 

  

	a.	The Chair, in consultation with the President and CEO and the General Counsel and Secretary, shall develop the agenda for each Board meeting. 

 

	b.	Meeting materials shall be provided to directors before each Board meeting in sufficient time to ensure adequate opportunity for review. 

 

	c.	Independent directors (as defined under applicable securities legislation) shall hold regularly scheduled meetings at which non- independent directors including members
of management are not present. 

  

	7.	Committees of the Board 

  

	a.	 The Board discharges its responsibilities both directly and through its committees: the Audit and Finance Committee, the Business Transformation
Committee, the Corporate Governance Committee, the Human Resources Committee, the Health, Safety and 

  
 2012 ANNUAL
INFORMATION FORM  135 

 APPENDIX “B” 

 

	 	
Environment Committee, the Investment-Pension Committee and the Regulatory and Public Policy Committee. In addition to these standing Committees, the Board may from time to time appoint ad hoc
Committees to address certain issues of a more short-term nature. 

  

	b.	The Board is responsible for approving the mandates for each Board Committee. 

 

	c.	To facilitate communication between the Board and each Board Committee, each Committee Chair is responsible for providing a report to the Board on material matters
considered by the Committee at the first Board meeting after the Committee’s meeting. 

 Director Development and
Evaluation 
  

	1.	Each new director shall participate in Hydro One’s Director Education Program and any continuing director development programs. 

 

	2.	Annually, with the assistance of the Corporate Governance Committee, the Board shall evaluate and review the performance of the Board, each of its Committees, each of
the directors and the adequacy of this mandate. 

  
 136  HYDRO ONE INC.

 APPENDIX “C” 
  

 APPENDIX “C” 
 HYDRO ONE TRANSMISSION AND DISTRIBUTION LICENCES 
 Transmission Licence 

The following are the key conditions of our transmission licence: 
  

	•	 	 Obligation to Enter into Agreement with the IESO – We are required to enter into the operating agreement with the IESO, providing for the
IESO’s direction of the operation of our transmission system. On June 8, 2001, we signed an operating agreement with the IESO. See “Regulation – Contractual Arrangements, Codes and Licences – Operating Agreement with the
IESO.” 

  

	•	 	 Non-discriminatory Access – If a generator, distributor, retailer, wholesaler or customer requests that we convey electricity using our
transmission system, subject to capacity constraints, we must make an offer to convey electricity on behalf of the applicant consistent with the applicable Market Rules and the Transmission System Code. 

 

	•	 	 Obligation to Connect and Priority Connection Access – We will not refuse to make an offer to connect to our transmission system which has
been made in accordance with the terms of our transmission rate order, the Market Rules and the Transmission System Code unless we are permitted to do so by the OEB, the legislation or any codes, standards or rules with which we are obligated to
comply as a condition of our licence. The connection procedures of our licence outline the respective responsibilities of Hydro One and of the connecting customer. We are required to provide priority connection access to the transmission system for
qualified renewable energy generation facilities, i.e. those facilities that meet the requirements prescribed by Provincial regulations. 

  

	•	 	 Obligation to Maintain System Integrity – We must maintain our transmission system to the standards established in our agreement with the
IESO, the Market Rules and any other recognized industry operating or planning standard which has been specified by the OEB. 

  

	•	 	 Transmission Rates – We may not impose charges for the transmission of electricity or connection to our transmission system except in
accordance with our transmission rate order. 

  

	•	 	 Preparation of Plans – We are required to prepare plans for approval by the OEB in the manner and at the times mandated by the OEB or as
prescribed by regulation, that identify expansion or reinforcement of the transmission system required to accommodate the connection of renewable energy generation facilities and to prepare plans for the development and implementation of the ADS in
relation to the transmission system. 

  

	•	 	 Separation of Business Activity – Our transmission business must separate its financial records from those of any other business of Hydro
One. 

  

	•	 	 Expansion of the Transmission System – Construction, expansion or reinforcement of our transmission system is subject to legislation,
regulatory approvals, licences, codes and the Market Rules. Either the IESO or the OEB may require us to expand or reinforce our transmission system if it determines that doing so is necessary for the maintenance of security, reliability or
integrity 

  
 2012 ANNUAL
INFORMATION FORM  137 

 APPENDIX “C” 

 

	 	 
of the system. See “Description of the Business – Our Transmission Business – Projects Relating to Interconnection Capacity.” 

 

	•	 	 Information Disclosure – We are required to maintain records, provide the OEB with information it may require from time to time and inform
the OEB of any material change in circumstances no more than 20 days after the date of occurrence. 

  

	•	 	 Restrictions on Provision of Information – We are restricted in our use and disclosure of information pertaining to consumers, retailers,
wholesalers and generators. We must obtain consent for disclosure of such information, except in certain specified situations and inform such parties of the conditions under which their information may be disclosed without their consent.

 Distribution Licences 
 The terms and conditions of our three distribution licences (Hydro One Networks Inc., Hydro One Brampton Networks Inc. and Hydro One Remote Communities Inc.) are similar to the terms and conditions of our
transmission licence described above. In addition, these licences: 
  

	•	 	 Separation of Business Activity – require the distribution business to keep its financial records separate from those of the transmission
business. 

  

	•	 	 Distribution Rates – create an obligation to charge rates in accordance with an order of the OEB and in accordance with the methods or
techniques set out in the Electricity Distribution Rate Handbook, the Distribution System Code, the Standard Supply Service Code and the Retail Settlement Code. 

 

	•	 	 Code Compliance – require compliance with the Retail Settlement Code and the Affiliate Relationships Code for Electricity Distributors and
Transmitters. 

  

	•	 	 Commodity Rebates – prescribe the manner by which we must pass through any rebates from OPG to customers. 

 

	•	 	 Obligation to Connect and Serve and Priority Connection Access – impose the obligation on our distribution business to connect a building
to our distribution system under prescribed circumstances, and to sell electricity or ensure electricity is supplied to every person connected to our distribution system, in accordance with our distribution rate orders and the Standard Supply
Service Code, and to sell electricity to consumers consistent with the terms and conditions of these instruments. We are also required to provide priority connection access to the distribution system for qualified renewable energy generation
facilities, i.e. those facilities that meet the requirements prescribed by Provincial regulations. 

  

	•	 	 Preparation of Plans – We are required to prepare plans for approval by the OEB, in the manner and at the times mandated by the OEB or as
prescribed by regulation, that identify expansion or reinforcement of the distribution system required to accommodate the connection of renewable energy generation facilities and to prepare plans for the development and implementation of the ADS in
relation to the distribution system. 

 Hydro One Networks Inc. holds an interim distribution licence to serve the community
of Cat Lake in Northwestern Ontario. The interim licence was first issued in July 2006 and has been renewed regularly for sequential terms of three months each. 

  
 138  HYDRO ONE INC.EX-4.2

Table of Contents

 Exhibit 4.2 
 HYDRO ONE INC. 
 ANNUAL CONSOLIDATED FINANCIAL STATEMENTS

  

					
	 	  	Page	 
	 Management’s Discussion and Analysis
	  	 	2	  
	 Management’s Report
	  	 	38	  
	 Independent Auditors’ Report
	  	 	39	  
	 Consolidated Statements of Operations and Comprehensive Income
	  	 	40	  
	 Consolidated Balance Sheets
	  	 	41	  
	 Consolidated Statements of Changes in Shareholder’s Equity
	  	 	43	  
	 Consolidated Statements of Cash Flows
	  	 	44	  
	 Notes to Consolidated Financial Statements
	  	 	45	  
	 Five-Year Summary of Financial and Operating Statistics
	  	 	92	  

  

					
		  		  	

Table of Contents

 HYDRO ONE INC. 
 MANAGEMENT’S DISCUSSION AND ANALYSIS 
 On January 1,
2012, Hydro One Inc. (Hydro One) adopted United States (US) Generally Accepted Accounting Principles (GAAP) as its approved basis for accounting and financial reporting. Comparative 2011 information is presented under US GAAP, unless otherwise
noted. All amounts are in Canadian dollars. 
 The following discussion is based on our Consolidated Financial Statements for the years ended
December 31, 2012 and 2011. 
 EXECUTIVE SUMMARY 
 We are wholly owned by the Province of Ontario (Province), and our transmission and distribution businesses are regulated by the Ontario Energy Board (OEB). Our mission and vision has been refined to
recognize the unique role we play in the economy of the province and as a provider of critical infrastructure to all our customers. We strive to be an innovative and trusted company, delivering electricity safely, reliably and efficiently to create
value for our customers. We operate as a commercial enterprise with an independent Board of Directors. Our strategic plan is driven by our values: health and safety; excellence; stewardship; and innovation. Safety is of utmost importance to us
because we work in an environment that can be hazardous. We take our responsibility as stewards of critical provincial assets seriously. We demonstrate sound stewardship by managing our assets in a manner that is commercial, transparent and which
values our customers. We strive for excellence by being trained, prepared and equipped to deliver high-quality service. We value innovation because it allows us to increase our productivity and develop enhanced methods to meet the needs of our
customers. In 2012, we continued to focus on our core businesses and our commitment to our customers and made important contributions to the rebuilding of Ontario’s core infrastructure while continuing to meet the requirements of the Green
Energy Act (GEA). 
 We manage our business using the following framework: 

 
 

 
 Core Business and Strategy 
 Our corporate strategy is based on our mission and vision and our values. Our strategic goals, which are discussed in the section “Our Strategy,” encompass the core values that drive our
business. Our strategy touches every part of our core business: health and safety; our customers; innovation; the reliability and efficiency of our systems; the environment; our workforce; shareholder value; and productivity. 

Key Performance Drivers 

Performance drivers have been identified that relate to achieving certain of our company’s strategic goals. We establish specific performance targets
for each driver aimed at measuring the achievement of our strategic goals over time. For example, we track the duration of unplanned customer interruptions per delivery point as an indication of our commitment to provide a reliable transmission
system for our customers. We measure transmission and distribution unit costs as an indication of our commitment to increasing productivity. These and other key performance drivers are included in our discussion of our performance measures in the
section “Performance Measures and Targets.” 
 Capability to Deliver Results 

We continue to use a balanced scorecard approach as we strive to manage our performance and deliver results each and every year. In 2012, we set nine
stretch targets and we met or exceeded five of them. In 2011, we met or exceeded 13 of 17 stretch targets. We exceeded our target for minimizing the duration of unplanned customer interruptions within our Transmission Business. Our performance with
respect to productivity was on target in our subsidiary Hydro One Networks Inc.’s (Hydro One Networks) transmission and distribution businesses. Our ability to deliver results in each of our strategic areas is limited by risks inherent in our
regulatory environment, our business, our workforce and in the economic environment. These risks, as well as our strategies to mitigate them, are discussed in the section “Risk Management and Risk Factors.” 

  

					
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Table of Contents

 HYDRO ONE INC. 
 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) 
  

 Results and Outlook 
 During 2012, our financial fundamentals remained strong with current year net income of $745 million. Our OEB-approved revenue requirement for our transmission business for 2012 was $1,418 million. Our
2011 distribution rates for Hydro One Networks continued unchanged throughout 2012, and its approved revenue requirement for 2011 was $1,218 million. Approved rates support the work programs required to sustain our critical infrastructure and invest
in a sustainable electricity system that supports renewable and cleaner generation. We successfully issued $1,085 million in debt financing in 2012, the proceeds of which were used to fund the retirement of $600 million of debt maturing in the year
and to fund a portion of our capital expenditures and other corporate requirements. A full discussion of our results of operations and financing activities can be found in the sections “Results of Operations” and “Liquidity and
Capital Resources.” 
 In 2012, we invested more than $1.4 billion in capital expenditures to improve system reliability and performance,
address our aging power system, facilitate new generation and improve service to our customers. Capital expenditures for the next few years will include those required to build critical infrastructure identified in the Long-Term Energy Plan (LTEP),
which is based on recommendations from the Ontario Power Authority (OPA), and expenditures to address aging infrastructure. Our future capital expenditures are more fully described in the section “Future Capital Expenditures.” 

OVERVIEW 
 Transmission

  

			
	Substantially all of Ontario’s electricity transmission system is owned and operated by our subsidiary Hydro One Networks. Our transmission system forms an integrated
transmission grid that is monitored, controlled and managed centrally from our Ontario Grid Control Centre. Our system operates over relatively long distances and links major sources of generation to transmission stations and larger area load
centres. In 2012, we earned total transmission revenues of $1,482 million, primarily by transmitting approximately 141 TWh of electricity, directly or indirectly, to substantially all consumers of electricity in Ontario. Our transmission system is
one of the largest in North America, and it is linked to five adjoining jurisdictions through 26 interconnections, through which we can accommodate imports of about 4,800 MW and exports of approximately 6,000 MW of electricity. In terms of assets,
our Transmission Business is our largest business segment, representing approximately 56% of our total assets at December 31, 2012.	  	

			
	  
 Distribution

 
	  	
	

	  	Our consolidated distribution system is the largest in Ontario and it spans roughly 75% of the province. We serve approximately 1.4 million rural and urban customers and 440
large user customers. Our subsidiary Hydro One Remote Communities Inc. (Hydro One Remote Communities) operates small, regulated generation and distribution systems in a number of remote communities across northern Ontario that are not connected to
Ontario’s electricity grid. In 2012, we earned total distribution revenues of $4,184 million. As illustrated in the accompanying chart, over half of our distribution revenues were earned from our residential customers. At December 31,
2012, our Distribution Business assets represented approximately 41% of our total assets.

 Other 

In 2012, our Other business segment contributed revenues of $62 million, and had assets of $604 million at December 31, 2012, representing 3% of our
total assets. This segment primarily represents the operations of our wholly-owned subsidiary, Hydro One Telecom Inc., which markets fibre-optic capacity to telecommunications carriers and commercial customers with broadband network requirements,
including a dedicated optical network providing secure, high-capacity connectivity across numerous health care locations in Ontario. 

  

					
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Table of Contents

 HYDRO ONE INC. 
 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) 
  

 Our Strategy 
 Our corporate strategy is based on our mission and vision and our values. Our mission and vision is to be an innovative and trusted company delivering electricity safely, reliably and efficiently to
create value for our customers. Our values represent our core beliefs: 
 Health and safety: Nothing is more important than the
health and safety of our employees, those who work on our property, and the public. 
 Excellence: We achieve excellence through
continuous training, ensuring we are prepared and equipped to deliver high-quality and cost-effective service, with integrity. 

Stewardship: We invest in our assets and people to build a safe, environmentally sustainable electricity network in a commercial manner.

 Innovation: We innovate through new processes, people and technology to allow us to find better ways to meet the needs of our
customers. 
 We have eight strategic objectives that are inextricably linked. They drive the fulfillment of our mission and vision. 

Creating an injury-free workplace and maintaining public safety. Health and safety must be integrated into all that we do. We must continue
to create a passion for preventing injury. We will strengthen our already strong safety culture through our Journey to Zero initiative and achieve world-class results. We will implement the internationally recognized health and safety management
system, ISO 18001, to identify health and safety risks, priorities and mitigation in order to further drive our safety culture. We will continue to reinforce that nothing is more important than the health and safety of our employees. 

Satisfying our customers. We will meet our commitments, make customers our focus in our planning, communicate effectively, coordinate
across lines of business, and maximize opportunities to improve our corporate image. We will develop and deliver targeted customer segment strategies, products and delivery channels that will respond to their unique needs and behaviours. 

Continuous innovation. Innovation represents one of our core values and is critical to achieving our mission and vision. Over the next two
decades, we will install innovative solutions that improve the reliability and efficiency of the transmission and distribution systems and provide our customers with more capability to manage their power costs. The Advanced Distribution System (ADS)
is a key element in our investment in innovation and will improve operation of our distribution assets and deliver further value to our customers. 
 Building and maintaining reliable, cost-effective transmission and distribution systems. Our transmission strategy is to provide a robust and reliable provincial grid that accommodates
Ontario’s emerging generation profile, manages an aging asset base and meets demand requirements through prudent expansion and effective maintenance. Our distribution strategy is focused on: incorporating ADS technology to provide greater
visibility; increasing control and improving customer service; supporting the connection of renewable energy sources; seeking efficiencies through leveraging technology and operational experience from our transmission system; providing reliable and
cost-effective service over a diverse geography; and pursuing commercial arrangements that are anticipated to arise from the rationalization of Ontario’s distribution sector. 
 Protecting and sustaining the environment for future generations. Consistent with our value of stewardship, we play a central role in reducing Ontario’s carbon footprint through the
delivery of clean and renewable energy and through measures that allow our customers to manage and reduce their energy use. We will engage our customers further regarding how we manage our sustainability obligations and activities on their behalf.

 Employee engagement. We believe our primary strength is the capability of our people. In order to sustain this advantage, we
must address the issues of corporate culture, labour demographics, diversity, development of critical core competencies and skill and knowledge retention. Our labour strategy should enable us to make significant gains in the areas of labour
flexibility, productivity improvement and cost reduction. 

  

					
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Table of Contents

 HYDRO ONE INC. 
 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) 
  

 Maintaining a commercial culture that increases value for our shareholder. We are
committed to keeping rates as low as possible for our customers, and delivering income and dividends to our shareholder. This is possible through our focus on reducing costs, managing our assets effectively and increasing productivity. We will
explore and pursue opportunities to increase the revenue-earning potential of our company by leveraging existing assets, technologies, capabilities and the geographic presence of our company. 
 Achieving productivity improvements and cost-effectiveness. To achieve our mission and vision, we must constantly strive for productivity through efficiency and effective management of
costs. Productivity is key to meeting our other strategic objectives and, in particular, to achieving value for our customers and our shareholder. 
 We recognize the pivotal role innovation will play in building a smart electricity grid that supports a clean environment for Ontario. We are committed to becoming the industry leader in putting
innovative solutions to work for the well-being of Ontario’s economy and its residents. 
 Performance Measures and Targets

 We target and measure our performance by using a balanced scorecard approach. Key performance drivers are closely monitored throughout the
year to ensure that we maintain a focus on our strategic objectives and take mitigating actions as required. In 2012, we met or exceeded five of nine stretch targets. Overall, we are making progress towards achieving many of our strategic
goals. 
 Achieving productivity improvements and cost-effectiveness 
 One of our strategic objectives is to increase productivity through efficiency improvements and effective management of costs. The measures for this objective for 2012 were transmission unit cost and
distribution unit cost. 
 For 2012, we measured for transmission unit cost the capital expenditures and operation, maintenance and
administration costs per dollar of gross in-service assets (expressed as a percentage). For distribution unit cost, the measure is capital expenditures and operation, maintenance and administration costs per kilometre of line ($’000/km) due to
the length of line required to connect our rural customers. Our objective with our ongoing work and investment program is to maintain and improve our assets and monitor our productivity year-over-year. Our transmission unit cost target was set at
10.1% and we met this target. The distribution unit cost target was set at $11,000 per kilometre of line and we also met this target. 

Building and maintaining reliable, cost-effective transmission and distribution systems 

We continue to build and retain public confidence and trust in our operations, as stewards of Ontario’s electricity grid. In 2012, we continued our
focus on this strategic priority by investing in the key assets of the electricity delivery system and by operating the existing system for customers in a safe, reliable and efficient fashion. We are conscious that commercial customers of all sizes
require reliable service to allow them to deliver their products and services and that customers’ expectations are for a reasonably limited duration when interruptions occur. Transmission and distribution reliability is measured through the
duration of customer interruptions. 
 For the duration of unplanned customer interruptions within our Transmission Business, the target for
2012 was 10 minutes per delivery point. We more than met this target. 
 For the Hydro One Networks distribution business, the target for 2012
for the duration of customer interruptions was set at 6.7 hours per customer. We did not meet this target. 
 Satisfying our customers

 Customer satisfaction measures the degree to which our transmission and distribution customers are satisfied with the service they
receive from our company. Customer satisfaction is based on the results of customer surveys conducted on our behalf by independent third parties. In 2012, for transmission customers we targeted a customer satisfaction rate of 90%, but did not meet
this target. For our distribution customers, we targeted a satisfaction rate of 86%, and we met this target. 

  

					
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Table of Contents

 HYDRO ONE INC. 
 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) 
  

 Employee engagement 
 We continue to focus efforts on increasing employee engagement throughout the company. An engaged workforce is one in which employees embrace the corporate values of safety, stewardship, excellence and
innovation. The process of measuring and improving such engagement began in 2008 by means of an employee engagement survey administered by an independent third-party expert. Our goal is to improve the grand mean score year-over-year. The target of
improving the grand mean score to 4.06 (out of 5) in 2012 was not met. 
 Maintaining a commercial culture that increases value for our
shareholder 
 Achievement of strong financial performance is measured by a performance measure of targeted level of net income after
tax. Our target was $643 million net income after tax and we exceeded our target. 
 Creating an injury-free workplace and maintaining
public safety 
 The safety of our employees is paramount. In 2012, we used medical attentions, defined as injuries that require
treatment by a medical practitioner (beyond first aid), as the performance measure for this strategic objective. The medical attentions measure reflects incidents that are reported to the Workplace Safety and Insurance Board and is calculated as the
number of attentions per 200,000 hours worked. In 2012, Hydro One set a target of no higher than 2.2 attentions per 200,000 hours worked. In an effort to achieve this target, we engaged in a number of activities, such as: continued emphasis on
improving health and safety through face-to-face sessions; continuation of our Journey to Zero initiative; better monitoring of mandatory skills and safety training; an enhanced driver training/evaluation program; and field coaching to increase the
expectations from supervisors and staff. The number of attentions in 2012 improved by 35% compared to the number in 2011 but was still slightly higher than our target for 2012. 
 REGULATION 
 Our electricity transmission and distribution businesses are licenced and
regulated by the OEB. The OEB sets rates following oral or written public hearings. Our transmission revenues primarily include our transmission tariff, which is based on the province-wide uniform transmission rates (UTRs) approved by the OEB for
all transmitters across Ontario. Our distribution revenues primarily include our distribution tariff, which is also based on OEB-approved rates, and the recovery of the cost of purchased power used by our customers. Consequently, our Distribution
Business does not have commodity price risk. Transmission and distribution tariff rates are set based on an approved revenue requirement that provides for cost recovery and a return on deemed common equity. In addition, the OEB approves rate riders
to allow for the recovery or disposition of specific regulatory accounts over specified timeframes. 
 Electricity Rates

 Under the current market structure, low-volume and designated consumers pay electricity rates established through the Regulated Price
Plan (RPP) and wholesale electricity consumers pay a blend of regulated, contract and wholesale spot market prices. The OEB sets prices for RPP customers based on both a two-tiered electricity pricing structure, with seasonal consumption thresholds,
and a three-tiered electricity pricing structure with Time of Use (TOU) thresholds. The majority of our RPP customers are now on TOU billing. Unexpected shortfalls or overpayments associated with the RPP are temporarily financed by the OPA. Prices
are reviewed by the OEB every six months and may change based on an updated OEB forecast and any accumulated differences between the amount that customers paid for electricity and the amount paid to generators in the previous period. 

We started migrating our customers to TOU rates in 2010 and the majority of our customers were transitioned to TOU rates by the end of 2011. We received
an exemption from the OEB, effective until December 31, 2014, from implementing mandatory TOU pricing for approximately 120,000 customers that are currently out of reach of our smart meter telecommunications infrastructure. 

Customers who are not eligible for the RPP and wholesale customers pay the market price for electricity, adjusted for the difference between market
prices and prices paid to generators by the Independent Electricity System Operator (IESO) under the Electricity Act, 1998. The IESO is responsible for overseeing and operating the wholesale market as well as ensuring the reliability of the
integrated power system. 

  

					
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Table of Contents

 HYDRO ONE INC. 
 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) 
  

 Transmission Rates 
 The IESO facilitates payments to us based on the Ontario UTRs approved by the OEB for all transmitters across Ontario. 
 On May 19, 2010, we submitted our application for 2011 and 2012 transmission rates in continued support of our aging critical infrastructure and supply mix objectives for generation, including
off-coal initiatives and initiation of investments in support of the GEA. This application sought the approval of revenue requirements of approximately $1,446 million for 2011 and $1,547 million for 2012, which represented estimated rate increases
of 15.7% and 9.8%, respectively, or 1.2% and 0.7% on an average customer’s monthly bill. 
 On December 23, 2010, the OEB issued its
decision, which resulted in a revenue requirement effective January 1, 2011 of $1,346 million for 2011 and $1,658 million for 2012, reflecting transmission rate changes of approximately 7% in 2011 and 26% in 2012, or 0.5% and 2%, respectively,
on an average customer’s total bill. Our 2012 revenue requirement was impacted by the OEB directing us to adopt a cost capitalization policy consistent with International Financial Reporting Standards (IFRS). This specific accounting revision
resulted in an increased revenue requirement of about $200 million for 2012. 
 Consistent with an approval from the Ontario Securities
Commission (OSC) to adopt US GAAP for our external financial reporting and securities filings, on July 15, 2011 we filed a Motion to Vary the OEB’s 2012 rate decision. Our application sought approval to adopt US GAAP as a basis
for regulatory accounting and rate setting in place of the OEB’s approved modified IFRS basis. On November 23, 2011, the OEB approved the use of US GAAP by our Transmission Business, which resulted in the reversal of the $200 million
adjustment that was made by the OEB in its December 2010 rate decision. 
 On December 1, 2011, we submitted to the OEB a draft 2012
transmission revenue requirement that reflects the approved adoption of US GAAP for rate-setting purposes as well as the OEB-directed update to 2012 cost-of-capital parameters. On December 20, 2011, the proposed $1,418 million 2012 revenue
requirement was approved by the OEB along with new 2012 UTRs effective January 1, 2012. The new rates resulted in an approximate 8% transmission rate increase, or 0.6% on an average customer’s total bill. The adoption of US GAAP in
lieu of modified IFRS as a basis for rate setting decreased the approved rates by about 15%. 
 To achieve the necessary funding in support of
aging critical infrastructure and investments, we submitted a cost-of-service rate application to the OEB for our 2013 and 2014 transmission rates on May 28, 2012. The application sought OEB approval for revenue requirement increases of
approximately 0.6% and 9.1% in 2013 and 2014, respectively, or estimated increases of 0% in 2013 and 0.7% in 2014, on an average customer’s total bill. A settlement conference was held in October 2012, where Hydro One Networks and the
intervenors reached an agreement, settling all issues apart from Export Transmission Service. This is anticipated to be settled in early 2013 but is not expected to affect our company’s results of operations. The settlement agreement was
reviewed and approved by the OEB on November 8, 2012. On November 30, 2012, we submitted a draft rate order, which includes revenue requirements of approximately $1,438 million and $1,528 million for 2013 and 2014, respectively. For the
transmission portion of the bill, this represents no change from existing 2012 OEB-approved rate levels in 2013 and a 5.8% increase in 2014. On an average customer total bill basis, this represents increases of nil for 2013 and 0.5% for 2014. On
December 20, 2012, the OEB issued a final Rate Order, approving Hydro One Networks’ 2013 transmission revenue requirement for use in setting the 2013 Ontario UTRs. 
 Distribution Rates 
 As a distributor, we are responsible for delivering electricity and
billing our customers for our approved distribution rates, purchased power costs and other approved regulatory charges. Substantially all of our purchased power costs and other approved regulatory charges are settled through the IESO, which
facilitates payments to other parties such as generators, the Ontario Electricity Financial Corporation (OEFC) and itself. 
 In 2006, the OEB
established a multi-year electricity distribution rate-setting plan whereby a distributor’s rates are set via a cost-of-service rebasing application followed by an Incentive Regulation Mechanism (IRM) that uses a formulaic approach to establish
rates for the next three years. In 2012, the OEB issued a new regulatory framework that included three rate-setting methods available to distributors (see “Renewed Regulatory Framework”). 

  

					
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Table of Contents

 HYDRO ONE INC. 
 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) 
  

 Hydro One Networks 
 On July 13, 2009, our subsidiary Hydro One Networks filed a cost-of-service application with the OEB for 2010 and 2011 distribution rates. 
 On April 9, 2010, the OEB released its decision approving revenue requirements of $1,146 million for 2010 and $1,236 million for 2011 to support the necessary work programs, the implementation of the
GEA and the installation of smart meters. 
 On November 15, 2010, the OEB issued its cost-of-capital parameter updates for rates effective
January 1, 2011. The lowering of the return on equity (ROE) produced a revised revenue requirement of $1,218 million. The approved 2011 revenue requirement resulted in an average distribution rate increase of approximately 8.7% for 2011, or
3.4% on an average (i.e. consuming 800 kWh per month) customer’s total bill. 
 On March 23, 2012, the OEB approved our request for
Hydro One Networks’ distribution business to adopt US GAAP for rate setting and regulatory accounting and reporting. Hydro One Networks did not seek a distribution cost-of-service rate adjustment for 2012 and rates continued unchanged at
2011 levels. 
 On June 15, 2012, Hydro One Networks filed evidence in support of its application for 2013 distribution rates on the basis
of the OEB’s 3rd Generation IRM process. Hydro One Networks and intervenors subsequently reached a settlement and submitted a settlement agreement to the OEB. On December 14, 2012, the OEB issued its decision accepting the agreement as
filed. On December 20, 2012, the OEB issued a final Rate Order. The distribution rate of an average residential customer will increase by approximately 1.3% in 2013, or by 0.4% when considering total bill impacts. In addition, the Retail
Transmission Service Rates adjustment, which was accepted in the Settlement, will bring the total bill increase in 2013 to approximately 1.5%. 

Hydro One Brampton Networks 
 On
June 30, 2010, our subsidiary Hydro One Brampton Networks submitted its 2011 cost-of-service application, which was subsequently adjusted in September to reflect the optional deferral of the adoption of modified IFRS until January 1, 2012,
consistent with a decision by the Canadian Accounting Standards Board (AcSB). The AcSB later extended the optional deferral to January 1, 2014 and Hydro One Brampton Networks has decided to exercise this option. 

Following another adjustment to the application in November 2010, the revenue requirement was approximately $63 million. On April 4, 2011, the OEB
issued a decision that approved a revenue requirement of $59.5 million for 2011. The revised rates were approved with an effective date of January 1, 2011 and an implementation date of May 1, 2011. Included in the rates is an amount of
$1.52 per month per metered customer for smart meters and approval of a GEA funding adder of $0.02 per month per metered customer. The new rates result in a total bill increase for an average customer (i.e. consuming 800 kWh per month) of
approximately 0.5%. 
 On September 15, 2011, Hydro One Brampton Networks filed an application for 2012 rates on the basis of the
OEB’s 3rd Generation IRM process. On December 22, 2011, the OEB issued its decision and on December 31, 2011, the OEB declared Hydro One Brampton Networks’ existing rates interim as of January 1, 2011. On January 5,
2012, the OEB released a decision that resulted in a reduction in rates of approximately 13.2%, or a 1.7% reduction on the average customer’s total bill in the year. These rate reductions were primarily due to OEB-approved adjustments to
depreciation rates. 
 On August 3, 2012, Hydro One Brampton Networks filed an application for 2013 rates on the basis of the OEB’s
3rd Generation IRM process, requesting new distribution rates effective January 1, 2013. Hydro One Brampton Networks subsequently amended its rate application and on December 6, 2012, the OEB approved the amended application. The rate
impact on the distribution component associated with a typical residential customer was an increase of approximately 0.3%, or less than 0.1% on the customer’s total bill. 
 Hydro One Remote Communities 
 On October 15, 2010, Hydro One Remote Communities
filed an application for 2011 distribution rates on the basis of the OEB’s 3rd Generation IRM. The application sought approval for an increase of approximately 0.4% to basic rates for the distribution and generation of electricity effective
May 1, 2011. On March 28, 2011, the OEB approved the application. The overall impact of the new rates on an average (i.e. consuming 800 kWh per month) residential customer’s total bill was marginal. 

  

					
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Table of Contents

 HYDRO ONE INC. 
 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) 
  

 On November 25, 2011, Hydro One Remote Communities filed its application for 2012 distribution
rates on the basis of the OEB’s 3rd Generation IRM. On March 22, 2012, the OEB issued its decision approving a rate increase of 1.08% effective May 1, 2012, representing an increase of about $1 on an average residential
customer’s monthly bill. 
 Consistent with the OEB’s decision affirming the use of US GAAP for rate-setting purposes by Hydro
One Networks’ transmission and distribution businesses, we made a similar request to use US GAAP for Hydro One Remote Communities. On April 3, 2012, the OEB approved the request to use US GAAP as the basis for rate setting within
Hydro One Remote Communities effective January 1, 2012. 
 On September 17, 2012, Hydro One Remote Communities filed a cost-of-service
application for 2013 rates to be effective May 1, 2013. If approved as filed, the electricity rate of an average customer will increase by 3.5% in 2013. In its rate application, Hydro One Remote Communities also requested approval to establish
a Rural and Remote Rate Protection of $35 million in 2013. The OEB Hearing and decision are anticipated to occur in the first quarter of 2013. 

Recent Industry Developments 

Long-Term Energy Plan 
 On
November 23, 2010, the Ministry of Energy released Ontario’s LTEP, which sets out the province’s expected electricity needs until 2030 and supports the continued procurement of new, cleaner generation. The LTEP addresses seven key
areas: demand; supply; conservation; transmission; aboriginal communities; capital investments; and electricity prices. On February 17, 2011, the Province issued a Supply Mix Directive that required the OPA to prepare a 20-year Integrated Power
System Plan (IPSP) to meet the goals set out in the LTEP. On May 9, 2011, the OPA announced that it was beginning consultations to update Ontario’s IPSP and issued the IPSP Planning and Consultation Overview document. On
June 17, 2011, we submitted our comments on the IPSP, as requested of stakeholders by the OPA. Stakeholder comments will form part of the evidence when the OPA submits the revised IPSP to the OEB for its review. 

On February 28, 2011, the OEB issued a decision amending Hydro One Networks’ transmission licence in accordance with a directive from the
Minister of Energy to the OEB. The licencee amendment requires Hydro One Networks to develop and either seek approvals for, or implement, specified transmission projects and upgrades to safely and reliably accommodate additional renewable energy in
accordance with recommendations from the OPA. In a letter dated April 7, 2011, the OPA provided the scope and timing to increase short circuit and/or transformer capacity at ten of 15 transformer stations noted in the licence to accommodate
small-scale renewable generation. Six of these upgrades have been completed and we are currently anticipating that one additional station upgrade will be placed in service in 2013. Alternative solutions have been identified for the other three
upgrades. In accordance with the Memorandum of Agreement between Her Majesty the Queen in Right of the Province of Ontario as represented by the Minister of Energy (Shareholder) and our company, the Shareholder made a declaration, dated
April 19, 2011, pursuant to subsection 108 (3) of the Business Corporations Act (Ontario) pertaining to the cost recovery of the expenditures related to the February 28, 2011 licence condition amendment. As a result, the
recovery of the seven station upgrades was restricted. We charged $17 million to operation, maintenance and administration expense in 2012 and charged $19 million to operation, maintenance and administration expense in 2011, in respect of these
projects. 
 In June 2011, the OPA recommended the scope and timing of the project to re-conductor two circuits between Sarnia and London, our
West of London Transmission Upgrade Project, with a required in-service date of December 2014. This project is needed to satisfy government policy relating to the incorporation of 10,700 MW of non-hydroelectric renewable generation resources by
2018. On November 8, 2012, the OEB issued a decision approving our Section 92, Leave to Construct, application for this project. In October 2011, the OPA recommended the scope and timing of the Southwestern Ontario Reactive Compensation
Priority Project, recommending that we install a Static Var Compensator (SVC) at our Milton Switching Station to increase the capability of our Bruce to Milton Line. An OPA recommendation regarding the construction of a new transmission line west of
the City of London is not expected in the foreseeable future. 

  

					
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 HYDRO ONE INC. 
 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) 
  

 Framework for Transmission Development Plans 

On August 26, 2010, the OEB released its new policy entitled Framework for Transmission Project Development Plans. This policy sets out a
framework for new transmission investment in Ontario by introducing competition for transmission development through an open process. On March 29, 2011, the Minister of Energy expressed the Province’s interest in the OEB commencing a
transmitter designation process for the East-West Tie Line. The East-West Tie Project is the first transmission network line expansion covered under the new competitive approach. The proposed route is a 400 km, 230 kV double-circuit line between its
transformer stations at Wawa in the east and Lakehead in the west. The target in-service date, set by the OPA in its report issued June 30, 2011, is 2017. The East-West Tie LP, an equally-shared partnership of three entities including our
company, obtained a transmission licence on May 31, 2012, and is participating in the East-West Tie Project bid process. 
 The OEB adopted
a two-phase process for the East-West Tie proceeding. On July 12, 2012, the OEB issued its Phase 1 decision and order, thus concluding Phase 1 of the proceeding by finalizing various filing requirements and process issues and directing
registered transmitters to file their applications for designation by January 4, 2013. The proceeding is now in Phase 2 and the OEB received six applications for designation from the registered transmitters in the proceeding, including one from
the East-West Tie LP. The timeline for Phase 2, which will take the form of a written hearing, has not yet been set. 
 Renewed Regulatory
Framework 
 On December 17, 2010, the OEB initiated a coordinated consultation process for the development of a renewed regulatory
framework for electricity distributors and transmitters. On October 18, 2012, the OEB issued its report A Renewed Regulatory Framework for Electricity Distributors: A Performance-Based Approach, marking the completion of its consultation
process. The report identified three rate-setting models available to provide choices suitable for distributors having varying capital requirements: a 4th Generation IRM, which builds on the current 3rd Generation model by adding one year to the IRM
period; a Custom IRM, which involves rate setting based on a five-year forecast of a distributor’s revenue requirement and sales volume; and an Annual Incentive Rate-setting Index method, which involves annual adjustment of rates by a simple
price cap index formula. The report also provided information on performance measurement, continuous improvement and implementation of the new framework. 
 Four working groups were established to provide expert assistance to review and advise the OEB’s staff on proposals regarding certain implementation matters: Asset Redefinition and Regional
Infrastructure Planning Process; Distribution Network Investment Planning; Performance, Benchmarking, and Rate Adjustment Indices; and Smart Grid. Hydro One Networks is represented on all four groups. Working group meetings began in November 2012
and are scheduled through February 2013. Consultations will conclude with the issuance of filing requirements and guidance, code amendments, and/or supplemental Board policies in support of the new framework. The OEB is expecting that policies will
be largely implemented in time for the 2014 rate year. We are currently assessing the rate-setting methods available. 
 OEB Transmission
and Distribution System Codes 
 Under the Transmission System Code, the transmitter covers the initial pooling of the costs of enabler
lines, with generators paying their pro-rata share when ready to connect, based on generator capacity. 
 Under the Distribution System Code
(DSC), there are three classes of distribution assets associated with the connection of renewable energy generation: connection assets, expansion assets, and renewable enabling improvements. Generators that connect directly to a distributor’s
system pay the costs of connection assets, while distributors fund: all expansion costs identified in a plan; other generator-requested expansion costs up to a cap of $90,000/MW per project (generator pays the rest); and all renewable enabling
improvements. 
 In 2011, the OEB granted us an exemption from mandatory DSC timelines for the connection of micro-embedded generation
facilities. The OEB decision increased the timeline for processing indirect connections that require a site assessment and approved amendments to the conditions that must be met before we are required to connect micro-embedded generation facilities
to our distribution system. On August 3, 2012, Hydro One Networks applied to the OEB for an extension of the exemption and on November 8, 2012, the OEB granted the extension for a period ending August 3, 2013, or six months after the
conclusion of its consultation on micro-embedded generation issues, whichever is earlier. 

  

					
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 HYDRO ONE INC. 
 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) 
  

 Ontario Clean Energy Benefit 
 Effective January 1, 2011, the Province introduced the Ontario Clean Energy Benefit Act, 2010, which is designed to assist Ontario electricity consumers through the transition to a cleaner
electricity system. Under this Act, eligible residential, farm and small business consumers receive a 10% benefit with respect to the total cost of electricity on their bills, including tax, for a five-year period. This benefit is applied to
customers’ electricity costs for each billing period. Effective September 1, 2012, the 10% rebate is applied only to the first 3,000 kWh of electricity consumed per month. 
 Revenue Decoupling for Distributors 
 In 2010, the OEB initiated a consultation
process to examine the revenue adjustment and cost recovery mechanisms available to electricity and natural gas distributors to address revenue erosion resulting from unforecasted changes in volume of energy sold. These mechanisms are commonly
referred to as “revenue decoupling” mechanisms as each involves some means of disconnecting the link between the volume of energy consumed by customers and the recovery by energy distributors of their approved revenue requirement.

 On November 26, 2012, the OEB initiated a project to complete the work begun on revenue decoupling for electricity and natural gas
distributors. The OEB will coordinate its consideration of revenue decoupling with the new rate-setting policies proposed in the renewed regulatory framework for electricity. The OEB will examine how best to address changes in demand, including
potential declines in average use. This consultation will review the options for potential revenue decoupling in addition to the existing lost revenue decoupling mechanism (i.e. the Lost Revenue Adjustment Mechanism or LRAM). The OEB expects to
release a draft policy in early 2013. The OEB will solicit stakeholder comments in writing before finalizing the policy. 
 Distribution
Sector Consolidation 
 On April 13, 2012, the Province announced it was launching a comprehensive review of Ontario’s
electricity sector to explore options to improve efficiencies, including local distribution companies (LDCs) consolidation. As a result, the Province created the Ontario Distribution Sector Review Panel (Panel). On December 13, 2012, the Panel
released its report, Renewing Ontario’s Electricity Distribution Sector: Putting the Consumer First, with recommendations for electricity sector consolidation. This report recommends that the 73 LDCs comprising the focus of the report be
consolidated into eight to 12 larger regional electricity distributors within a two-year timeframe. Specifically, it recommends there be two regional distributors in northern Ontario and between six and ten regional distributors in southern Ontario
with a minimum of 400,000 customers each. Given our company’s position as the largest LDC, the report recommends that Hydro One Networks be given unambiguous direction to lead and engage in the discussion of the merger of distribution assets
with the appropriate interested utilities on a commercial basis. At present, the Province is reviewing the report and assessing the recommendations. 
 FIT and microFIT 
 On October 1, 2009, the OPA launched its Feed-in Tariff (FIT)
Program which is designed to procure energy from a wide range of renewable energy sources, including wind, solar, photovoltaic, bio-energy and waterpower up to 50 MW. 
 On March 22, 2012, the Province announced the results of its two-year FIT Program Review, including recommended changes to reflect input received from stakeholders. The OPA implemented these
recommendations and re-launched its microFIT program on July 12, 2012. The revised program encourages greater community and aboriginal participation and the protection of agricultural lands. In August 2012, the OPA began to release approvals
allowing microFIT projects to proceed. On December 14, 2012, the OPA announced that it will award up to 200 MW of Small FIT applications, received between December 14, 2012 and January 18, 2013, for renewable energy projects with a
proposed capacity between ten and 500 kilowatts. The OPA is not accepting Large FIT applications at this time. The timing for the Large FIT project application window will be communicated once details are finalized. 

Conservation and Demand Management (CDM) 
 The OPA continues to be responsible for coordinating the delivery and funding of Ontario’s CDM programs. Our CDM programs funded through the OPA in 2012 amounted to approximately $25 million,
compared to $15 million in 2011. These programs included: the Peaksaver Program; the Low Income Home Assistance Program; Appliance Retirement and Exchange Events; and the Process and System Upgrade Incentive Program. 

  

					
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 HYDRO ONE INC. 
 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) 
  

 The Ontario Energy Board Act, 1998, as amended by the GEA, provides direction to the OEB
to take steps to establish CDM targets to be met by LDCs and other licencees. A province-wide CDM target for Ontario’s LDCs was set in 2010. The two key CDM targets for LDCs over the four-year period beginning January 1, 2011 were to
collectively reduce 1,330 MW of provincial summer peak demand and to provide 6,000 GWh of cumulative energy savings. The OEB issued its CDM Code for Electricity Distributors (CDM Code) on September 16, 2010 and on November 12, 2010, it
issued final CDM targets to each LDC. Our company was allocated a 259 MW reduction of provincial peak demand and a 1,320 GWh reduction of electricity consumption, representing, respectively, 19.5% and 22.0% of the total target savings established
for all LDCs. The CDM Code also set out the conditions and rules that LDCs are required to follow if they choose to use OEB-approved CDM programs to meet their CDM targets. 
 On April 26, 2012, the OEB issued its CDM guidelines for all electricity distributors. One key change is that savings associated with TOU pricing are eligible to be counted towards the CDM targets.
Savings will be evaluated by the OPA for the entire province and then allocated to each distributor. The other key change is the establishment of the LRAM variance account, which captures the variance between the level of CDM included in a
distributor’s load forecast and the verifiable results of impacts of CDM activities undertaken between 2011 and 2014 for both OPA-contracted and OEB-approved CDM programs. 
 On September 28, 2012 and September 30, 2012, in accordance with the CDM Code, Hydro One Brampton Networks and Hydro One Networks, respectively, filed their 2011 Annual CDM Reports with the OEB.
Our combined results for 2011 were 40 MW in peak demand savings, representing 15.6% of our target, and 99 GWh of annual energy savings. These energy savings will produce 388 GWh towards our target, representing 29.4% of our cumulative target. We
anticipate meeting our 2014 cumulative demand and energy savings targets. 
 On December 21, 2012, the Minister of Energy issued a
directive to the OPA to extend funding for its CDM programs for one additional year, to December 31, 2015. This extension aims to provide added stability, support the momentum of province-wide programs and ensure that projects with longer
completion times can continue to participate in key conservation initiatives. This extension will also provide an opportunity for the OPA and LDCs to collaboratively work to strengthen the current framework and deliver innovative programs that
support Ontario families and businesses. The OPA will be reaching out to distributors to further solicit insight and advice on the implementation of this extension. 
 Advanced Distribution System 
 The Energy Conservation Responsibility Act, 2006
further broadened the objectives of CDM by providing the framework for the installation of smart meters in all homes and small businesses in Ontario. In 2007, the Province appointed the IESO as the interim smart meter entity that would oversee
the collection and management of data from installed smart meters. LDCs, including our distribution businesses, are accountable for the deployment of smart meter infrastructure and related communications technology to meet minimum regulatory
requirements, as well as the implementation of TOU rates. 
 In 2011, we carried out a number of studies on advanced distribution technologies
and initiated the Smart Zone Pilot Project in the Owen Sound area. The Smart Zone Pilot consists of testing and demonstrating power system equipment, IT systems and communication systems that will be required to help facilitate the connection of a
large number of Distributed Generation (DG) connections to our distribution system. In 2012, we successfully completed the deployment of the Distribution Management System (DMS) within the Owen Sound pilot area. This integrates the Network
Management System, the Outage Response Management System and field devices. Further releases of the ADS will look at optimizing outage response through more effective dispatch, automation to isolate faults where needed and the dynamic regulation of
voltage to reduce losses. All releases leverage a core infrastructure and build on each other, and as pilot elements are proven, business cases will be developed for the provincial roll out which will ultimately comprise the ADS. 

  

					
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 HYDRO ONE INC. 
 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) 
  

 RESULTS OF OPERATIONS 
 Revenues 
  

																	
	 Year ended December 31 (millions of dollars)
	  	2012	 	  	2011	 	  	$ Change	 	 	% Change	 
	 Transmission
	  	 	1,482	  	  	 	1,389	  	  	 	93	  	 	 	7	  
	 Distribution
	  	 	4,184	  	  	 	4,019	  	  	 	165	  	 	 	4	  
	 Other
	  	 	62	  	  	 	63	  	  	 	(1	) 	 	 	(2	) 
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 
		  	 	5,728	  	  	 	5,471	  	  	 	257	  	 	 	5	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 
	 Average annual Ontario 60-minute peak demand (MW)1
	  	 	21,132	  	  	 	21,166	  	  	 	(34	) 	 	 	—  	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 
	 Distribution – units distributed to customers (TWh)1
	  	 	29.2	  	  	 	29.2	  	  	 	—  	  	 	 	—  	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 

  

	1	 System-related
statistics are preliminary. 

 Transmission 
 Transmission revenues primarily consist of our transmission tariff, which is based on the monthly peak electricity demand across our high-voltage network. The tariff is designed to recover revenues
necessary to support a transmission system with sufficient capacity to accommodate the maximum expected demand. Demand is primarily influenced by weather and economic conditions. Transmission revenues also include export revenues associated with
transmitting excess generation to surrounding markets and ancillary revenues which are mostly attributable to maintenance services provided primarily to generators and secondary use of our land rights. 

Our transmission revenues were higher by $93 million, or 7%, compared to 2011. On December 23, 2010, the OEB rendered its decision on our 2011 and
2012 transmission rate application. On December 20, 2011, the OEB approved new transmission tariff rates, effective January 1, 2012, which reflected higher in-service assets and the use of US GAAP as our basis for rate setting. The
decisions resulted in higher transmission revenues of $106 million for the year ended December 31, 2012, and the average peak demand for 2012 resulted in a slight increase of $3 million, compared to the prior year. 

Increases were partially offset by a $9 million reduction in revenue following the completion of recovery of a transmission regulatory account effective
December 31, 2011, a $6 million reduction in transmission-related external revenues and a $1 million reduction associated with other OEB-approved regulatory accounts. 
 Distribution 
 Our consolidated Distribution Business consists of the separate
distribution businesses of our subsidiaries Hydro One Networks, Hydro One Brampton Networks, and Hydro One Remote Communities. Distribution revenues include our distribution tariff and amounts to recover the cost of purchased power used by the
customers of our consolidated Distribution Business. Accordingly, our distribution revenues are influenced by the amount of electricity we distribute, the cost of purchased power and our distribution tariff rates. Distribution revenues also include
minor ancillary distribution services revenues, such as fees related to the joint use of our distribution poles by the telecommunications and cable television industries as well as miscellaneous charges, such as those for late payments. 

Our 2012 distribution revenues were higher by $165 million, or 4%, compared to 2011. The increase was primarily due to the recovery of higher purchased
power costs of $146 million, as described below under “Purchased Power.” Our distribution revenues were also higher by $18 million due to our placement of new ADS and smart meter investments in service. Given that these investments relate
to new technologies, they are currently recovered through separate rate mechanisms. 
 Distribution revenues for the year reflect additional
external revenues of $7 million, an increase in Hydro One Remote Communities’ revenues of $2 million and a $1 million increase associated with OEB-approved regulatory accounts. These increases were partially offset by a $7 million reduction due
to lower energy consumption, resulting primarily from the milder winter we experienced in 2012 compared to 2011, and by a decrease of $2 million in Hydro One Brampton Networks’ distribution tariff revenues. 

  

					
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 HYDRO ONE INC. 
 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) 
  

 Purchased Power 
 Purchased power costs are incurred by our Distribution Business and represent the cost of electricity delivered to customers within our distribution service territories. These costs comprise the wholesale
commodity cost of energy, the IESO’s wholesale market service charges, and transmission charges levied by the IESO. The commodity cost of energy for certain low-volume and designated customers is based on the OEB’s RPP, which consists of a
two-tiered pricing structure with threshold amounts and a separate pricing structure for RPP customers on TOU billing, both of which are adjusted twice annually. We began transitioning our RPP customers to TOU billing in May 2010, and a large
majority of our RPP customers are now on TOU billing. Customers who are not eligible for the RPP pay the market price for electricity, adjusted for the difference between market prices and the prices paid to generators under the Electricity
Restructuring Act, 2004. 
 A summary of the RPP for the reporting and comparative periods is provided below. 

 

																	
	 RPP
	  	Tier Threshold (kWh/month)	 	  	Tier Rates (cents/kWh)	 
	 Effective Date
	  	Residential	 	  	Non-Residential	 	  	First Tier	 	  	Second Tier	 
	 November 1, 2010
	  	 	1,000	  	  	 	750	  	  	 	6.4	  	  	 	7.4	  
	 May 1, 2011
	  	 	600	  	  	 	750	  	  	 	6.8	  	  	 	7.9	  
	 November 1, 2011
	  	 	1,000	  	  	 	750	  	  	 	7.1	  	  	 	8.3	  
	 May 1, 2012
	  	 	600	  	  	 	750	  	  	 	7.5	  	  	 	8.8	  
	 November 1, 2012
	  	 	1,000	  	  	 	750	  	  	 	7.4	  	  	 	8.7	  

  

													
	 RPP TOU
	  	Rates (cents/kWh)	 
	 Effective Date
	  	On Peak	 	  	Mid Peak	 	  	Off Peak	 
	 November 1, 2010
	  	 	9.9	  	  	 	8.1	  	  	 	5.1	  
	 May 1, 2011
	  	 	10.7	  	  	 	8.9	  	  	 	5.9	  
	 November 1, 2011
	  	 	10.8	  	  	 	9.2	  	  	 	6.2	  
	 May 1, 2012
	  	 	11.7	  	  	 	10.0	  	  	 	6.5	  
	 November 1, 2012
	  	 	11.8	  	  	 	9.9	  	  	 	6.3	  

 Purchased power costs increased by $146 million, or 6%, to $2,774 million for the year, compared to 2011. The increase in
our purchased power costs was primarily due to an increase of $118 million resulting from the impact of changes in the OEB’s RPP rates for residential and other eligible customers, a $33 million increase resulting from the OEB transmission rate
decision effective January 1, 2012 that affected the transmission charges levied by the IESO, and a $7 million increase related to higher electricity demand. The effect of these increases was partially offset by an $11 million reduction
compared to 2011 in wholesale market service charges levied by the IESO, which include certain costs for operating the transmission grid, and a $1 million decrease resulting from lower purchased power costs for customers who are not eligible for the
RPP. 
 Operation, Maintenance and Administration 
 Our operation, maintenance and administration costs consist of labour, material, equipment and purchased services which support the operation and maintenance of the transmission and distribution systems.
Also included in these costs are property taxes and payments in lieu thereof related to certain of our transmission and distribution facilities. 
 Operation, maintenance and administration costs for each of our three business segments were as follows: 
  

																	
	 Year ended December 31 (millions of dollars)
	  	2012	 	  	2011	 	  	$ Change	 	 	% Change	 
	 Transmission
	  	 	402	  	  	 	422	  	  	 	(20	) 	 	 	(5	) 
	 Distribution
	  	 	608	  	  	 	609	  	  	 	(1	) 	 	 	—  	  
	 Other
	  	 	61	  	  	 	61	  	  	 	—  	  	 	 	—  	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 
		  	 	1,071	  	  	 	1,092	  	  	 	(21	) 	 	 	(2	) 
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 

 Our company continues to focus on managing its costs, resulting in a decrease in total operation, maintenance and
administration expenditures in 2012, compared to 2011, while continuing to substantially complete the planned work programs for both our transmission and distribution businesses. 

  

					
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 HYDRO ONE INC. 
 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) 
  

 Transmission 
 Operation, maintenance and administration expenditures incurred to sustain our high-voltage transmission stations, lines and rights-of-way decreased by $20 million, or 5%, in 2012 compared to last year.
Within our work programs, we continued to invest in the safe and reliable operation of our transmission system that spans Ontario. Our work program requirements were lower by $33 million compared to last year mainly due to: lower demand for
station-related corrective maintenance, particularly for power equipment; lower demand for underground cable corrective maintenance; and reduced autotransformer remediation work. We also incurred lower expenditures compared to last year related to
the OPA’s recommendation to increase short circuit and/or transformer capacity at a number of our transmission stations to enable the connection of small renewable projects, for which recovery is restricted (see “Regulation –
Long-Term Energy Plan”). Most of this work has now been completed. Expenditures in support of our transmission system increased by $13 million, compared to 2011, due to a redirection of resources from our Distribution Business, partially offset
by management cost reduction initiatives. 
 Distribution 
 Operation, maintenance and administration expenditures required to maintain our low-voltage distribution system decreased slightly by $1 million compared to last year. Our work program expenditures
decreased by $5 million mainly due to decreased power restoration expenditures resulting from overall lower storm activity in Ontario in 2012 compared to 2011. Reductions also resulted from lower lines maintenance requirements, partially offset by
increased requirements within our forestry program resulting from higher tree densities experienced this year. Our expenditures in support of our distribution system increased by $4 million mainly due to spending in support of the Customer
Information System (CIS) phase of our entity-wide information system replacement and improvement project. The impact of this increase was partially offset by cost reduction initiatives and a redirection of resources in support of our Transmission
Business. 
 Depreciation and Amortization 
 Depreciation and amortization expense increased by $43 million, or 7%, in 2012, compared to 2011. This increase was attributable to higher depreciation expense of $40 million, when compared to 2011,
primarily related to our placement of new assets in service consistent with our ongoing capital work program. Slightly higher asset removal costs of $3 million contributed the remainder of the variance from the prior year. 

Financing Charges 
 Financing charges
increased by $14 million, or 4%, to $358 million for 2012 compared to 2011. Higher financing costs were mainly due to an increased average level of debt and partially offset by a lower average effective interest rate. 

Provision for Payments in Lieu of Corporate Income Taxes (PILs) 
 The provision for PILs decreased by $29 million, or 19%, to $121 million in 2012, compared to 2011. This decrease primarily resulted from a reduction in the statutory tax rate from 28.25% to 26.50%,
changes in net temporary differences, and an increase in research and development tax credits related to our ADS project. This reduction was partially offset by the impact of higher levels of pre-tax income compared to 2011. 

Net Income 
 Net income of $745 million
was higher by $104 million, or 16%, than our comparable 2011 results. Higher revenues reflect the recovery of prior year investments which are now in service and which will improve the province’s electricity system. Our net income was also
positively impacted by lower operation, maintenance and administration expenditures resulting from cost-effectively managing the work program within our Transmission Business and by lower PILs resulting from a lower combined federal and provincial
statutory income tax rate compared to 2011. In addition, our 2012 net income reflects higher depreciation expense resulting from our placement of new assets in service, consistent with our increased capital work program, and increased financing
charges reflecting our higher average level of debt. 

  

					
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 HYDRO ONE INC. 
 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) 
  

 QUARTERLY RESULTS OF OPERATIONS 
 The following table sets forth unaudited quarterly information for each of the eight quarters, from the quarter ended March 31, 2011 through December 31, 2012. This information has been derived
from our unaudited interim Consolidated Financial Statements and our audited annual Consolidated Financial Statements which include all adjustments, consisting only of normal recurring adjustments, necessary for fair presentation of our financial
position and results of operations for those periods. These operating results are not necessarily indicative of results for any future period and should not be relied upon to predict our future performance. 

 

																																	
	 (millions of dollars)
	  	2012	 	  	2011	 
	 Quarter ended
	  	Dec. 31	 	  	Sept. 30	 	  	Jun. 30	 	  	Mar. 31	 	  	Dec. 31	 	  	Sept. 30	 	  	Jun. 30	 	  	Mar. 31	 
	 Total revenue
	  	 	1,435	  	  	 	1,466	  	  	 	1,359	  	  	 	1,468	  	  	 	1,359	  	  	 	1,384	  	  	 	1,268	  	  	 	1,460	  
	 Net income
	  	 	165	  	  	 	201	  	  	 	169	  	  	 	210	  	  	 	120	  	  	 	167	  	  	 	142	  	  	 	212	  
	 Net income to common shareholder
	  	 	160	  	  	 	197	  	  	 	164	  	  	 	206	  	  	 	115	  	  	 	163	  	  	 	137	  	  	 	208	  

 Electricity demand generally follows normal weather-related variations, and consequently, our electricity-related
revenues and profit, all other things being equal, would tend to be higher in the first and third quarters than in the second and fourth quarters. 
 LIQUIDITY AND CAPITAL RESOURCES 
 Our primary sources of liquidity and capital resources are
funds generated from our operations, debt capital market borrowings and bank financing. These resources will be used to satisfy our capital resource requirements, which continue to include our capital expenditures, servicing and repayment of our
debt, and dividends. 
 Summary of Sources and Uses of Cash 

 

									
	 Year ended December 31 (millions of dollars)
	  	2012	 	 	2011	 
	 Operating activities
	  	 	1,285	  	 	 	1,407	  
	 Financing activities
	  				 			
	 Long-term debt issued
	  	 	1,085	  	 	 	700	  
	 Long-term debt retired
	  	 	(600	) 	 	 	(500	) 
	 Dividends paid
	  	 	(370	) 	 	 	(168	) 
	 Investing activities
	  				 			
	 Capital expenditures
	  	 	(1,454	) 	 	 	(1,447	) 
	 Other financing and investing activities
	  	 	21	  	 	 	64	  
		  	  
	  
	 	 	  
	  
	 
	 Net change in cash and cash equivalents
	  	 	(33	) 	 	 	56	  
		  	  
	  
	 	 	  
	  
	 

 Operating Activities 
 Net cash from operating activities decreased by $122 million to $1,285 million in 2012, compared to 2011. The decrease was primarily due to changes in accrued liabilities related to customer prepayments,
and a reduction in taxes payable, resulting from a tax payment made in the first quarter of 2012 related to the 2011 taxation year, as well as the timing of tax installment payments in 2012, compared to 2011. The decrease was partly offset by higher
2012 net income, compared to 2011. 
 Financing Activities 
 Short-term liquidity is provided through funds from operations, our Commercial Paper Program, under which we are authorized to issue up to $1,000 million in short-term notes with a term to maturity of
less than 365 days, our revolving credit facility, and through our holding of Province of Ontario Floating-Rate Notes. 
 Our Commercial Paper
Program is supported by a total of $1,500 million in liquidity facilities comprised of our $1,250 million committed revolving credit facility with a syndicate of banks, which matures in June 2017, and a long-term investment in Province of Ontario
Floating-Rate Notes of $250 million (with a fair value of $251 million at December 31, 2012). The short-term liquidity under this program and anticipated levels of funds from operations should be sufficient to fund our normal operating
requirements. 

  

					
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Table of Contents

 HYDRO ONE INC. 
 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) 
  

 At December 31, 2012, we had $8,460 million in long-term debt outstanding, including the current
portion. Our notes and debentures mature between 2013 and 2062. Long-term financing is provided by our access to the debt markets, primarily through our Medium-Term Note (MTN) Program. The maximum authorized principal amount of medium-term notes
issuable under this program is $3,000 million. At December 31, 2012, $1,515 million remained available until September 2013. 
  

					
	  	  	Rating
	 Rating Agency
	  	Short-term Debt	 	Long-term Debt
	 DBRS Limited
	  	R-1 (middle)	 	A (high)
	 Moody’s Investors Service Inc.1
	  	Prime-1	 	A1
	 Standard & Poor’s (S&P)2
	  	A-1	 	A+

  

	1	 On April 27,
2012, Moody’s Investors Service Inc. downgraded our senior unsecured rating to A1 from Aa3. 

	2	 On April 25,
2012, S&P revised their outlook on our company to negative from stable. 

 We have the customary covenants normally
associated with long-term debt. Among other things, our long-term debt covenants limit our permissible debt as a percentage of our total capitalization, limit our ability to sell assets, and impose a negative pledge provision, subject to customary
exceptions. The credit agreements related to our credit facilities have no material adverse change clauses that could trigger default. However, the credit agreements require that we provide notice to the lenders of any material adverse change within
three business days of the occurrence. The agreements also provide limitations that debt cannot exceed 75% of total capitalization and that third-party debt issued by our subsidiaries cannot exceed 10% of the total book value of our assets. We were
in compliance with all these covenants and limitations at December 31, 2012. 
 In 2012, we successfully issued $1,085 million in
cost-effective long-term debt under our MTN Program, consisting of $300 million issued in the first quarter, $425 million issued in the second quarter, $310 million issued in the third quarter, and $50 million issued in the fourth quarter of 2012.
In the third quarter of 2012, we also called and redeemed $600 million of our long-term debt, prior to its maturity date of November 15, 2012. 
 In 2011, we issued $700 million in long-term debt under our MTN Program, consisting of $300 million issued in the first quarter, $300 million issued in the third quarter, and $100 million issued in the
fourth quarter of 2011. In 2011, we also repaid $500 million in maturing long-term debt, $250 million in the first quarter and $250 million in the fourth quarter. 
 We had no short-term notes outstanding as at December 31, 2012 or December 31, 2011. 

Common dividends are declared at the sole discretion of our Board of Directors, and are recommended by management based on results of operations,
maintenance of the deemed regulatory capital structure, financial condition, cash requirements, and other relevant factors such as industry practice and shareholder expectations. Common dividends pertaining to our quarterly financial results are
generally declared and paid in the immediately following quarter. 
 In 2012, we paid dividends to the Province in the amount of $370 million,
consisting of $352 million in common dividends and $18 million in preferred dividends. In 2011, we paid dividends in the amount of $168 million, consisting of $150 million in common dividends and $18 million in preferred dividends. 

In 2012, cash dividends per common share were $3,523, compared to $1,500 per common share in 2011. Cash dividends per preferred share were $1.375 in each
of 2012 and 2011. 
 Our objectives with respect to our capital structure are to maintain effective access to capital on a long-term basis at
reasonable rates and to deliver appropriate financial returns to our shareholder. 

  

					
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Table of Contents

 HYDRO ONE INC. 
 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) 
  

 Investing Activities 
 Cash used for investing activities, primarily representing capital expenditures to enhance and reinforce our transmission and distribution infrastructure in the public interest, was as follows:

  

																	
	 Year ended December 31 (millions of dollars)
	  	2012	 	  	2011	 	  	$ Change	 	 	% Change	 
	 Transmission
	  	 	776	  	  	 	810	  	  	 	(34	) 	 	 	(4	) 
	 Distribution
	  	 	671	  	  	 	628	  	  	 	43	  	 	 	7	  
	 Other
	  	 	7	  	  	 	9	  	  	 	(2	) 	 	 	(22	) 
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 
		  	 	1,454	  	  	 	1,447	  	  	 	7	  	 	 	—  	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 

 Transmission 
 Transmission capital expenditures decreased by $34 million, or 4%, to $776 million in 2012, compared to 2011. Investments to expand and reinforce our transmission system were $313 million, representing a
decrease of $103 million from last year. The majority of our expenditures were made on inter-area network projects to support the Province’s supply mix objectives for generation, although we continue to make significant investments in load
customer connection and local area supply projects to address growing loads. The 2012 decrease in our expenditures results from the completion of several large projects in 2011. Major inter-area network projects completed and put into service in
2011 included the installation of SVCs at our Nanticoke, Detweiler, Porcupine and Kirkland Lake transformer stations. Also contributing to the reduction in expenditures were lower expenditures in 2012 related to our Woodstock Area Transmission
Reinforcement Project to increase capacity and ensure supply reliability in the Woodstock area, and our Bruce to Milton Transmission Reinforcement Project connecting refurbished nuclear and new wind generation sources in the Huron-Grey-Bruce area.
These projects were successfully put into service in March and May of this year, respectively. The impact of the reductions in expenditures in both periods was partially offset by increases in our expenditures resulting from load customer connection
and local area supply projects progressing into their build phases, and investments in our transformer stations related to the ADS Project, which supports clean DG connected to our distribution system consistent with the GEA. 

On June 18, 2012, our subsidiary Hydro One Networks entered into an agreement with the Chippewas of Nawash First Nation and the Chippewas of Saugeen
First Nation, collectively known as the Saugeen Ojibway Nation (SON). The agreement contemplates a new Limited Partnership (LP) to hold only the lines and related land rights of our Bruce to Milton Transmission Reinforcement Project. The carrying
value of these assets is expected to be approximately $600 million when they are transferred to the LP in late 2013. Under the terms of our agreement, the SON will be eligible to purchase a non-controlling equity interest in the LP at fair value.
The LP is anticipated to become a rate-regulated entity under the jurisdiction of the OEB. Transfer of our assets to the LP and subsequent sale of an equity interest to the SON are both subject to the receipt of future regulatory approvals from the
OEB. On December 18, 2012, the SON, Hydro One Networks and Hydro One signed a Letter Agreement in connection with the establishment of the LP. The Letter Agreement addresses, among other things, the terms of the LP Agreement to be entered into
on closing and the terms on which Hydro One Networks will operate the Bruce to Milton Line on behalf of the LP. The closing is conditional on certain regulatory approvals and tax rulings. 
 Our local area supply project expenditures include investments in our Switchyard Reconstruction Project at our Burlington Transformer Station, which will address aging infrastructure to increase the load
supply capacity and to ensure reliability of supply to customers in the area. The project successfully went into service on December 21, 2012. We continue to invest in our Midtown Electricity Infrastructure Renewal Project to replace aging
cable and overhead line facilities and to provide additional supply capability to meet future load growth in midtown Toronto as well as areas to the west. Work is progressing at our Hearn Switching Station to rebuild an existing switchyard that has
reached its end-of-life. This project will also increase short circuit capability to accommodate future connection of renewable generation in central and downtown Toronto. 
 Significant expenditures within our load customer connection projects include investments to build our Commerce Way Transformer Station, a new load supply station in the City of Woodstock that was
partially put into service on December 19, 2012. This project will provide additional transformation and line capacity to address load growth issues in the Woodstock area. 

  

					
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Table of Contents

 HYDRO ONE INC. 
 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) 
  

 Expenditures to sustain our existing transmission system were $392 million in 2012, representing an
increase of $57 million compared to 2011. During the year, we made significant investments in the refurbishment and replacement of end-of-life equipment, including end-of-life oil circuit breakers, switches, insulators and protections at our Abitibi
Canyon switching station, and deteriorated autotransformers at our Trafalgar and Claireville transformer stations. Of these projects, the autotransformer at our Trafalgar transformer station and one of two at our Claireville transformer station were
successfully put into service this year. During the year, we also experienced an increase in replacements for end-of-life protection and control equipment. 
 Our other transmission capital expenditures were $71 million in 2012, representing an increase of $12 million compared to 2011. The majority of these increased expenditures were related to fleet
acquisitions and to information technology (IT) investments. 
 Distribution 

Our distribution capital expenditures increased by $43 million, or 7%, to $671 million in 2012, compared to 2011. Capital investments to expand and
reinforce our distribution network were $284 million in 2012, representing an increase of $15 million compared to 2011. We experienced increases in 2012 related to our continued investments in our ADS Project, a multi-year initiative to identify,
deploy, analyze and assess equipment and applications to modernize our distribution system. The ADS Project will protect distributed generators from power interruption and is anticipated to improve outage restoration, reduce construction and ongoing
maintenance costs, and reduce power loss as it flows across the electricity grid. Increased capital expenditures in 2012 were also due to investments related to our other distribution projects and upgrades to safely and reliably accommodate
additional renewable energy, and to higher volumes of new customer connections and upgrades, partially offset by reduced expenditures within our Smart Meter Project as it nears completion. 
 Expenditures to sustain our distribution system network were $245 million in 2012, representing an increase of $5 million compared to 2011. The increase in our sustainment program was primarily impacted
by increased work accomplished within our lines and distribution station refurbishment programs, as well as higher expenditures related to the strategic purchase of power transformers compared to the prior year. These impacts were partially offset
by lower storm restoration work given lower storm activity in 2012 compared to two major storms in Ontario in 2011. 
 Other distribution
capital expenditures were $142 million in 2012, representing an increase of $23 million, compared to 2011. The majority of these expenditures were related to the CIS phase of our enterprise-wide information system replacement and improvement
project. In addition to replacing end-of-life systems, this implementation will result in process improvements that are expected to provide many benefits, including enhancements to customer satisfaction through reduced call times and first call
resolution of issues given faster availability of information. Productivity savings are anticipated to result from performance improvements, consolidation of systems, and decommissioning of over a dozen legacy systems. 

Future Capital Expenditures 
  

			
	Our capital expenditures for 2013 are budgeted at approximately $1,600 million. Our 2013 capital budgets for our transmission and distribution businesses are about $1,000 million
and $600 million, respectively. Consolidated capital expenditures are expected to be approximately $1,750 million in 2014 and $1,650 million in 2015. These expenditure levels reflect meeting the sustainment requirements of our aging infrastructure.
Our sustainment program is expected to be approximately $800 million in 2013, $950 million in 2014 and $1,000 million in 2015. Our development projects include the ADS, inter-area network upgrades that reflect supply mix policies, local area supply
requirements, and requirements to enable DG. Our development expenditures are expected to be approximately $600 million in 2013, $600 million in 2014, and $450 million in 2015. These development investments also reflect customer demand work. Other
capital expenditures are expected to be approximately $200 million in each of 2013, 2014 and 2015. These expenditures include investments to replace our end-of-life customer billing system and smaller projects related to the continued realization of
increased productivity from our enterprise-wide SAP information system.	  	  
 

  

					
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Table of Contents

 HYDRO ONE INC. 
 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) 
  

 Transmission 
 Transmission capital expenditures include significant investments to manage the replacement and refurbishment of our aging transmission infrastructure in order to ensure a continued reliable supply of
energy to customers throughout the province. Our investment plan includes sustainment investments to replace end-of-life air blast circuit breakers and switchgear, high-voltage underground cable, and aging power transformers and to comply with North
American Electricity Reliability Corporation cyber security requirements. These sustaining investments are necessary to ensure that we continue to meet all regulatory, compliance, safety and environmental objectives. 

Major capital investments include our Oshawa Area Transformer Station Project to install additional auto-transformer capacity at our proposed Clarington
Transformer Station, for which the OPA has requested that Hydro One develop an implementation plan and initiate work. Planning and environmental studies are currently being undertaken for this project. Investments also include our Midtown
Electricity Infrastructure Renewal Project that will provide additional supply capability to meet future load growth in midtown Toronto as well as areas to the west, our SVC installation to be completed at our Milton station, and our project to
rebuild the switching station at our Hearn Transformer Station, which is expected to be completed by 2014. Transmission investments for ADS and requirements to enable DG are also included in the investment plan. The Hearn Transformer Station
Project, when combined with four other transformer station upgrades, will collectively enable up to 600 MW of new transmission capacity. 
 On
December 22, 2010, we received a letter from the Minister of Energy requesting us to proceed with the necessary planning and development work for specified transmission projects and upgrades to safely and reliably accommodate additional
renewable energy. On April 7, 2011, the OPA provided the scope and timing to increase short circuit and/or transformer capacity at ten of 15 transformer stations. These upgrades are substantially complete. Expenditures for these upgrades have
been recorded within operation, maintenance and administration (see “Regulation – Long-Term Energy Plan”). Two of the three priority specified transmission projects are reflected in our budgeted capital expenditures. The West of
London Transmission Upgrade Project generally requires restringing conductor on existing towers along an existing right-of-way and will enable the connection of additional renewable generation in the west of London area. The Southwestern Ontario
Reactive Compensation Priority Project will increase the transmission capability of the Bruce transmission system. We are awaiting direction on the third priority project from the OPA (see “Regulation – Long-Term Energy Plan”).

 In August 2010, the OEB introduced a framework for competitive designation for the development of eligible transmission projects. As a
result, we did not include in our budgeted capital expenditures any projects that could meet the definition of expansions under the OEB’s competitive framework. We do not plan to undertake large capital expenditures without a reasonable
expectation of recovering them in our rates. 
 The actual timing and expenditures of many development projects are uncertain as they are
dependent upon: various approvals including OEB leave to construct approvals and environmental assessment approvals; negotiations with customers, neighbouring utilities and other stakeholders; and consultations with First Nations and Métis
communities. Projects are also dependent on the timing and level of generator contributions for enabling facilities. 
 Distribution

 Distribution capital expenditures include investments to support the sustainment of our capital infrastructure. Our core work will
continue to focus on the performance of our aging distribution asset base in order to improve system reliability. There are continuing investments to replace end-of-life equipment and components, implement ADS as part of this renewal and a focus on
wood pole replacements to maintain reliability. In addition, we will continue to address customer demand projects through connectivity for DG, the demand for new load connections, trouble calls, storm restoration and system capability reinforcement.

 Distribution development expenditures over the period are primarily related to the development of an ADS system and related grid
modernization standards, customer demand work such as connections and upgrades, work to facilitate DG connections, including station upgrades, protection and control, new lines and some contestable work for which we receive capital contributions.
During the 2013 and 2014 periods, we expect to manage a significant number of projects throughout the province to address load growth and the stress on our system components. 

  

					
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Table of Contents

 HYDRO ONE INC. 
 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) 
  

 DG expenditures are based on our estimate of the number of anticipated connections, which have been
reduced based on the experience gained since 2009 and changes that have occurred to the FIT Program. The budget only reflects expenditures for projects with FIT and microFIT Program contracts from the OPA that are expected to connect to our
distribution system. 
 In 2013, the ADS Project will look at optimizing outage response through more effective dispatch, automation to isolate
faults where needed and the dynamic regulation of voltage to reduce losses. 
 Summary of Contractual Obligations and Other Commercial
Commitments 
 There are no off-balance-sheet arrangements that have, or are reasonably likely to have, a material current or future effect
on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources. 
 The following table presents a summary of our debt and other major contractual obligations, as well as other major commercial commitments. 

 

																					
	 December 31, 2012 (millions of dollars)
	  	Total	 	  	2013	 	  	2014/2015	 	  	2016/2017	 	  	After 2017	 
	 Contractual Obligations (due by year)
	  				  				  				  				  			
	 Long-term debt – principal repayments
	  	 	8,460	  	  	 	600	  	  	 	1,300	  	  	 	1,100	  	  	 	5,460	  
	 Long-term debt – interest payments
	  	 	7,336	  	  	 	410	  	  	 	735	  	  	 	651	  	  	 	5,540	  
	 Pension1
	  	 	330	  	  	 	158	  	  	 	172	  	  	 	—  	  	  	 	—  	  
	 Environmental and asset retirement obligations2
	  	 	313	  	  	 	30	  	  	 	73	  	  	 	40	  	  	 	170	  
	 Inergi LP (Inergi) outsourcing agreement3
	  	 	287	  	  	 	136	  	  	 	151	  	  	 	—  	  	  	 	—  	  
	 Operating lease commitments
	  	 	53	  	  	 	10	  	  	 	15	  	  	 	14	  	  	 	14	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Total Contractual Obligations4
	  	 	16,779	  	  	 	1,344	  	  	 	2,446	  	  	 	1,805	  	  	 	11,184	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Other Commercial Commitments (by year of expiry)
	  				  				  				  				  			
	 Bank line5
	  	 	1,250	  	  	 	—  	  	  	 	—  	  	  	 	1,250	  	  	 	—  	  
	 Letters of credit6
	  	 	150	  	  	 	150	  	  	 	—  	  	  	 	—  	  	  	 	—  	  
	 Guarantees6
	  	 	326	  	  	 	326	  	  	 	—  	  	  	 	—  	  	  	 	—  	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Total Other Commercial Commitments
	  	 	1,726	  	  	 	476	  	  	 	—  	  	  	 	1,250	  	  	 	—  	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 

  

	1 	 Contributions to the Hydro One Pension Fund are generally made one month in arrears. The 2013 and 2014 minimum contributions are based on an actuarial
valuation filed in May 2012 and effective December 31, 2011. Based on expected levels of 2012 pensionable earnings, our total 2012 annual pension contributions were approximately $160 million. Future minimum contributions beyond 2014 will be
based on an actuarial valuation effective no later than December 31, 2014, and will depend on future investment returns, changes in benefits or actuarial assumptions. Pension contributions beyond 2014 are not estimable at this time.

	2 	 We record a liability for the estimated future expenditures associated with the phase-out and destruction of polychlorinated biphenyl
(PCB)-contaminated insulating oil from electrical equipment and for the assessment and remediation of contaminated lands, as well as asset retirement obligations for the removal of asbestos-contaminated materials from our facilities and the
decommissioning and removal of certain switching stations. The expenditure pattern reflects our planned work programs for the periods. 

	3 	 On March 1, 2002, Inergi began providing a range of services to us for a ten-year period, including IT, customer care, supply chain and certain
human resources and finance services. On May 1, 2010, consistent with the terms of the contract, our company extended the Master Services Agreement with Inergi for a further three-year period, to expire on February 28, 2015. Given the
complexities involved, we have begun developing a plan of action for end-of-term and anticipate working towards a request for proposal in 2013. The amounts disclosed include an estimated annual inflation adjustment in the range of 1.8% to 3.0%.

	4 	 In addition, our company has entered into various agreements to purchase goods or services in support of our work programs that are enforceable and
legally binding. None of these agreements is considered individually material, and the majority do not extend beyond December 31, 2013. 

	5 	 In support of our liquidity requirements, we have a $1,250 million revolving standby credit facility with a syndicate of banks that matures in June
2017. 

	6 	 We currently have outstanding bank letters of credit of $127 million relating to retirement compensation arrangements. On April 27, 2012, our
highest credit rating declined from the “Aa” category to the “A” category. Based on this credit rating category, we began providing prudential support to the IESO in the form of letters of credit, the amount of which is
calculated based on forecasted monthly power consumption. As at December 31, 2012, we provided letters of credit to the IESO in the amount of $22 million to meet our current prudential requirement. The other $1 million pertains to operating
letters of credit. We have also provided prudential support to the IESO on behalf of our subsidiaries as required by the IESO’s Market Rules, using parental guarantees of up to a maximum of $325 million, and on behalf of two distributors using
guarantees of up to a maximum of $0.7 million. 

  

					
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Table of Contents

 HYDRO ONE INC. 
 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) 
  

 The amounts in the above table under long-term debt – principal repayments are not charged to our
results of operations, but are reflected on our Consolidated Balance Sheets and Consolidated Statements of Cash Flows. Interest associated with this debt is recorded under financing charges on our Consolidated Statements of Operations and
Comprehensive Income or as a cost of our capital programs. Payments in respect of operating leases and our outsourcing agreement with Inergi are recorded under operation, maintenance and administration expense on our Consolidated Statements of
Operations and Comprehensive Income or as a cost of our capital programs. 
 RELATED PARTY TRANSACTIONS 

Related party transactions primarily consist of our transmission revenues received from, and our power purchase payments made to the IESO, which is a
related party by virtue of its status as an agency of the Province. The year-over-year changes related to these amounts are described more fully in the discussion of our transmission revenues and purchased power costs. Other significant related
party transactions include our dividends, which are paid to the Province, and our PILs and some of our property taxes, which are paid or payable to the OEFC. In January 2010, we purchased $250 million of Province of Ontario Floating-Rate Notes,
maturing on November 19, 2014, as a form of alternate liquidity to supplement our bank credit facilities. 
 CONSIDERATIONS OF CURRENT
ECONOMIC CONDITIONS 
 Effect of Load on Revenue 
 Our load, based on normal weather patterns, is expected to marginally decline in 2013 due to the impact of CDM and embedded generation, partially offset by load growth associated with economic growth in
all sectors of the Ontario economy. Overall load growth due to the economy alone is forecasted to be approximately 1.3%, with the commercial and industrial sectors slightly outperforming the residential sector. The load impacts of CDM and embedded
generation are expected to have a negative impact on load growth of approximately 1.1% and 0.3%, respectively. On the whole, our load is expected to decline by about 0.1% in 2013. Our approved revenue requirement for 2013 has taken the expected load
decline into account. A reduction in load, beyond our load forecast included in our approved revenue requirement, would negatively impact our financial results. 
 Effect of Interest Rates 
 Changes in interest rates will impact the calculation of the
revenue requirements upon which our rates are based. The first component impacted by interest rates is our ROE. The OEB-approved adjustment formula for calculating ROE will increase or decrease by 50% of the change between the current Long Canada
Bond Forecast and the risk-free rate established at 4.25% and 50% of the change in the spread in 30-year “A”-rated Canadian utility bonds over the 30-year benchmark Government of Canada bond yield established at 1.415%. All other things
being equal, we estimate that a 1% decrease in the forecasted long-term Government of Canada bond yield used in determining our ROE would reduce Hydro One Networks’ transmission and distribution businesses’ results of operations by
approximately $19 million and $10 million, respectively. As interest rates decline, there is more risk of a decline in our net income. The second component of revenue requirement that would be impacted by interest rates is the return on debt. The
difference between actual interest rates on new debt issuances and those approved for return by the OEB would impact our results of operations. 

Input Costs and Commodity Pricing 
 In
support of our ongoing work programs, we are required to procure materials, supplies and services. To manage our total costs, we regularly establish security of supply, strategic material and services contracts, general outline agreements, and
vendor alliances and we also manage a stock of commonly used items. Such arrangements are for a defined period of time and are monitored. Where advantageous, we develop long-term contractual relationships with suppliers to optimize the cost of goods
and services and to ensure the availability and timely supply of critical items. As a result of our strategic sourcing practices, we do not foresee any adverse impacts on our business from current economic conditions in respect of adequacy and
timing of supply and credit risk of our counterparties. Further, we have been able to realize significant savings through our strategic sourcing initiatives. 

  

					
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Table of Contents

 HYDRO ONE INC. 
 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) 
  

 Debt Financing 
 Cash generated from operations, after the payment of expected dividends, will not be sufficient to fund capital expenditures or meet debt maturity repayments and other liquidity requirements (see
“Risk Management and Risk Factors – Risk Associated with Arranging Debt Financing”). We rely on debt financing through our MTN Program and Commercial Paper Program. Our Commercial Paper Program is supported by a total of $1,500
million in liquidity facilities as at December 31, 2012, which is comprised of a $1,250 million syndicated bank line of credit and the holding of $250 million of Province of Ontario Floating-Rate Notes. In 2012, we continued issuing sufficient
cost-effective debt financing through the MTN Program in the Canadian capital markets and we arranged sufficient available liquidity. Economic conditions were challenging in 2012 and we expect they will remain challenging in 2013. 

Pension 
 In 2012, we contributed
approximately $160 million to our pension plan and incurred $207 million in net periodic pension benefit cost. An actuarial valuation filed in May 2012 and effective December 31, 2011 did not result in significant changes to our 2012 required
contributions or our 2012 net periodic benefit cost. Actuarial valuations are minimally required to be filed every three years. We currently estimate our total annual pension contributions to be approximately $160 million for 2013 and 2014, based on
the projected level of pensionable earnings and the same actuarial valuation effective December 31, 2011. Future minimum contributions beyond 2014 will be based on the actuarial valuation effective no later than December 31, 2014. Our
pension plan experienced positive returns of about 9.19% in 2012. Our pension obligation is impacted by interest rates. The 1% decrease in the discount rate, from 5.25% at December 31, 2011 to 4.25% at December 31, 2012, resulted in an
increase in the pension obligation of $862 million and an increase to our post-retirement and post-employment benefit obligation of $241 million. No new benefits were introduced and over the last number of years benefits have been reduced through
re-negotiations with certain of our unions as well as our management employees. 
 RISK MANAGEMENT AND RISK FACTORS 

We have an Enterprise Risk Management (ERM) Program that aims at balancing business risks and returns. An enterprise-wide approach enables regulatory,
strategic, operational and financial risks to be managed and aligned with our strategic goals. Our ERM program helps us to better understand uncertainty and its potential impact on our strategic goals. It sets out the uniform principles, processes
and criteria for identifying, assessing, evaluating, treating, monitoring and communicating risks across all lines of business. It supports our Board of Directors’ corporate governance needs and the due diligence responsibilities of senior
management. 
 While our philosophy is that risk management is the responsibility of all employees, the Board of Directors annually reviews our
company’s risk tolerances, risk management policies, processes and accountabilities. Twice per year, the Board of Directors reviews our risk profile, which is the list of key risks prepared by senior management, that represents the greatest
threats to meeting our strategic objectives. The Audit and Finance Committee of our Board of Directors annually reviews the status of our internal control framework. 
 Our President and Chief Executive Officer (CEO) has ultimate accountability for risk management. Our Leadership Team provides senior management oversight of our risk portfolio and our risk management
processes. The leadership team provides direction on the evolution of these processes and identifies priority areas of focus for risk assessment and mitigation planning. 
 Our Chief Administration Officer and Chief Financial Officer (CAO and CFO) is responsible for ensuring that the risk management program is an integral part of our business strategy, planning and objective
setting. The CAO and CFO has specific accountability for ensuring that enterprise risk management processes are established, properly documented and maintained by our company. 
 Our senior managers, line and functional managers are responsible for managing risks within the scope of their authority and accountability. Risk acceptance or mitigation decisions are made within the
risk tolerances specified by the head of the subsidiary or function. 

  

					
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 HYDRO ONE INC. 
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 The CAO and CFO provides support to the Audit and Finance Committee of our Board of Directors, the
President and CEO, the senior management team and key managers within our company. This support includes developing risk management frameworks, policies and processes, introducing and promoting new techniques, establishing risk tolerances, preparing
annual corporate risk profiles, maintaining a registry of key business risks and facilitating risk assessments across our company. Our internal audit staff is responsible for performing independent reviews of the effectiveness of risk management
policies, processes and systems. Starting in 2013, our Board of Directors has taken on an enhanced role in our governance structure. Each committee of the Board of Directors will take accountability for reviewing specific risks of our company.

 Key elements of our ERM Program enable us to identify, assess and monitor our risks effectively. These include having an ERM policy and
framework which communicates our philosophy and process for risk management across our company. A discussion of risks is an integral part of each line of business’ planning documents on an annual basis. Risk identification is also considered as
part of each business case for investments. Finally, discrete risk assessments and workshops are performed for specific lines of business, key projects and various profiles, such as customer relationships and regulatory compliance. In order to drive
consistency throughout our risk identification and risk management processes, we use a standard list of risk sources known as our risk universe. These sources are maintained in a single database that provides a consistent basis for risk
identification and classification and serves as a repository for our risk assessments. All risk assessments in our company start with this risk universe. We also use standard risk criteria, which establish the metrics and terminology used for
assessing and communicating on risks, and help ensure a consistent basis for our risk assessments and risk evaluations across all lines of business. Risk criteria include formally established risk tolerances and standard scales for assessing the
probability of a risk materializing and the strength of controls in place to mitigate them. 
 Ownership by the Province 

The Province owns all of our outstanding shares. Accordingly, the Province has the power to determine the composition of our Board of Directors and
appoint the Chair, and influence our major business and corporate decisions. We and the Province have entered into a memorandum of agreement relating to certain aspects of the governance of our company. Pursuant to such agreement, in September 2008,
the Province made a declaration removing certain powers from our company’s Directors pertaining to the off-shoring of jobs under the outsourcing arrangement with Inergi. In 2009, the Province required our company, among other entities, to
adhere to certain accountability measures regarding consulting contracts and employee travel, meal and hospitality expenses. The Province may require us to adhere to further accountability measures or may make similar declarations in the future,
some of which may have a material adverse effect on our business. Our credit ratings may change with the credit ratings of the Province, to the extent the credit rating agencies link the two ratings by virtue of Hydro One’s ownership by the
Province. 
 Conflicts of interest may arise between us and the Province as a result of the obligation of the Province to act in the best
interests of the residents of Ontario in a broad range of matters, including the regulation of Ontario’s electricity industry and environmental matters, any future sale or other transaction by the Province with respect to its ownership interest
in our company, including any potential outcomes arising out of the recommendations of the Ontario Distribution Sector Review Panel’s report, the Province’s ownership of Ontario Power Generation Inc., and the determination of the amount of
dividend or proxy tax payments. We may not be able to resolve any potential conflict with the Province on terms satisfactory to us which could have a material adverse effect on our business. 
 Regulatory Risk 
 We are subject to regulatory risks, including the approval by the OEB of
rates for our transmission and distribution businesses that permit a reasonable opportunity to recover the estimated costs of providing safe and reliable service on a timely basis and earn the approved rates of return. 

The OEB approves our transmission and distribution rates based on projected electricity load and consumption levels. If actual load or consumption
materially falls below projected levels, our net income for either, or both, of these businesses could be materially adversely affected. Also, our current revenue requirements for these businesses are based on cost assumptions that may not
materialize. There is no assurance that the OEB would allow rate increases sufficient to offset unfavourable financial impacts from unanticipated changes in electricity demand or in our costs. 

Our load could also be negatively affected by successful CDM programs. We are also subject to risk of revenue loss from other factors, such as economic
trends and weather. 

  

					
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 HYDRO ONE INC. 
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 We expect to make investments in the coming years to connect new renewable generating stations. There is
the possibility that we could incur unexpected capital expenditures to maintain or improve our assets, particularly given that new technology is required to support renewable generation and unforeseen technical issues may be identified through
implementation of projects. The risk exists that the OEB may not allow full recovery of such investments in the future. To the extent possible, we aim to mitigate this risk by ensuring prudent expenditures, seeking from the regulator clear policy
direction on cost responsibility, and pre-approval of the need for capital expenditures. 
 While we expect all of our expenditures to be fully
recoverable after OEB review, any future regulatory decision to disallow or limit the recovery of such costs would lead to potential asset impairment and charges to our results of operations, which could have a material adverse effect on our
company. 
 In Ontario, the Market Rules mandate that we comply with the reliability standards established by North American Electric
Reliability Corporation and Northeast Power Coordinating Council Inc. As a result, we will be required to comply with the Federal Energy Regulatory Commission’s definition of “bulk electric system” unless we are granted an exemption
which will allow the application of the new definition in a cost-effective manner. We will look for recovery for costs incurred in meeting the definition in our rates; however an adverse decision on an exemption for recovery of costs could have an
adverse effect on our company. 
 Risk Associated with Arranging Debt Financing 
 We expect to borrow to repay our existing indebtedness and fund a portion of capital expenditures. We have substantial amounts of existing debt which mature between 2013 and 2016, including $600 million
maturing in 2013 and $750 million maturing in 2014. We plan to incur capital expenditures of approximately $1.6 billion in 2013 and $1.8 billion in 2014. Cash generated from operations, after the payment of expected dividends, will not be sufficient
to fund the repayment of our existing indebtedness and capital expenditures. Our ability to arrange sufficient and cost-effective debt financing could be materially adversely affected by numerous factors, including the regulatory environment in
Ontario, our results of operations and financial position, market conditions, the ratings assigned to our debt securities by credit rating agencies and general economic conditions. Any failure or inability on our part to borrow substantial amounts
of debt on satisfactory terms could impair our ability to repay maturing debt, fund capital expenditures and meet other obligations and requirements and, as a result, could have a material adverse effect on our company. 

Risk Associated with Transmission Projects 
 The amount of power that can flow through transmission networks is constrained due to the physical characteristics of transmission lines and operating limitations. Within Ontario, new and expected
generation facility connections, including those renewable energy generation facilities connecting as a result of the FIT program stemming from the GEA, and load growth have increased such that parts of our transmission and distribution systems are
operating at or near capacity. These constraints or bottlenecks limit the ability of our network to reliably transmit power from new and existing generation sources (including expanded interconnections with neighbouring utilities) to load centres or
meet customers’ increasing loads. As a result, investments have been initiated to increase transmission capacity and enable the reliable delivery of power from existing and future generation sources to Ontario consumers. 

In many cases, these investments are contingent upon one or more of the following approvals and/or processes: environmental approval(s); receipt of OEB
approvals which can include expropriation; and appropriate consultation processes with First Nations and Métis. Obtaining OEB and/or environmental assessment approvals and carrying out these processes may also be impacted by opposition to the
proposed site of transmission investments which could adversely affect transmission reliability and/or our service quality, both of which could have a material adverse effect on our company. 
 With the introduction on August 26, 2010 of the OEB’s competitive transmission project development planning process, in the absence of a government directive, all interested transmitters will be
required to submit a bid to the OEB for identified enabler facilities and network enhancement projects. Historically, we would have been awarded such projects through our rates and Section 92, Leave to Construct, applications. The facilitation
of competitive transmission could impact our future work program and our ability to expand our current transmission footprint. In addition, bid costs are only recoverable by the successful proponent. This could have a material adverse effect on our
company. 

  

					
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 HYDRO ONE INC. 
 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) 
  

 Asset Condition 
 We continually monitor the condition of our assets and maintain, refurbish or replace them to maintain equipment performance and provide reliable service quality. Our capital programs have been increasing
to maintain the performance of our aging asset base. Execution of these plans is partially dependent on external factors, such as outage planning with the IESO and transmission-connected customers, funding approval by the OEB, and supply chain
availability for equipment suppliers and consulting services. In addition, opportunities to remove equipment from service to accommodate construction and maintenance are becoming increasingly limited due to customer and generator priorities.

 Adjustments to accommodate these external dependencies have been made in our planning process, and we are focused on overcoming these
challenges to execute our work programs. However, if we are unable to carry out these plans in a timely and optimal manner, equipment performance will degrade which may compromise the reliability of the provincial grid, our ability to deliver
sufficient electricity and/or customer supply security and increase the costs of operating and maintaining these assets. This could have a material adverse effect on our company. 
 Workforce Demographic Risk 
 By the end of 2012, approximately 18% of our employees were
eligible for retirement and by 2013 there could be up to 20% eligible to retire. Accordingly, our success will be tied to our ability to attract and retain sufficient qualified staff to replace those retiring. This will be challenging as we expect
the skilled labour market for our industry to be highly competitive in the future. In addition, many of our employees possess experience and skills that will also be highly sought after by other organizations both inside and outside the electricity
sector. We are therefore focused on earlier identification and more rapid development of staff who demonstrate management potential. Moreover, we must also continue to advance our technical training and apprenticeship programs and succession plans
to ensure that our future operational staffing needs will be met. If we are unable to attract and retain qualified personnel, it could have a material adverse effect on our business. 
 Environmental Risk 
 Our health, safety and environmental management system is designed to
ensure hazards and risks are identified and assessed, and controls are implemented to mitigate significant risks. This system includes a standing committee of our Board of Directors that has governance over environmental matters. Given the territory
that our system encompasses and the amount of equipment that we own, we cannot guarantee, however, that all such risks will be identified and mitigated without significant cost and expense to our company. The following are some of the areas that may
have a significant impact on our operations. 
 We are subject to extensive Canadian federal, provincial and municipal environmental regulation.
Failure to comply could subject us to fines and other penalties. In addition, the presence or release of hazardous or other harmful substances could lead to claims by third parties and/or governmental orders requiring us to take specific actions
such as investigating, controlling and remediating the effects of these substances. We are currently undertaking a voluntary land assessment and remediation (LAR) program covering most of our stations and service centres. This program involves the
systematic identification of any contamination at or from these facilities, and, where necessary, the development of remediation plans for our company and adjacent private properties. Any contamination of our properties could limit our ability to
sell these assets in the future. 
 We record a liability for our best estimate of the present value of the future expenditures required to
comply with Environment Canada’s PCB regulations and for the present value of the future expenditures to complete our LAR program. The future expenditures required to discharge our PCB obligation are expected to be incurred over the period
ending 2025, while our LAR expenditures are expected to be incurred over the period ending 2020. Actual future environmental expenditures may vary materially from the estimates used in the calculation of the environmental liabilities on our balance
sheet. We do not have insurance coverage for these environmental expenditures. 
 Under applicable regulations, we expect to incur future
expenditures to identify, remove and dispose of asbestos-containing materials installed in some of our facilities. We record an asset retirement obligation for the present value of the estimated future expenditures. The estimates are based on an
external, expert study of the current expenditures associated with removing such materials from our facilities. Actual future expenditures may vary materially from the estimates used for the amount of the asset retirement obligation. 

There is also risk associated with obtaining governmental approvals, permits, or renewals of existing approvals and permits related to constructing or
operating facilities. This may require environmental assessment or result in the imposition of conditions, or both, which could result in delays and cost increases. 

  

					
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 HYDRO ONE INC. 
 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) 
  

 We anticipate that all of our future environmental expenditures will continue to be recoverable in
future electricity rates. However, any future regulatory decision to disallow or limit the recovery of such costs could have a material adverse effect on our company. 
 Scientists and public health experts have been studying the possibility that exposure to electric and magnetic fields emanating from power lines and other electric sources may cause health problems. If it
were to be concluded that electric and magnetic fields present a health risk, or governments decide to implement exposure limits, we could face litigation, be required to take costly mitigation measures such as relocating some of our facilities or
experience difficulties in locating and building new facilities. Any of these could have a material adverse effect on our company. 
 Risk of
Natural and Other Unexpected Occurrences 
 Our facilities are exposed to the effects of severe weather conditions, natural disasters,
man-made events including cyber and physical terrorist type attacks and, potentially, catastrophic events, such as a major accident or incident at a facility of a third party (such as a generating plant) to which our transmission or distribution
assets are connected. Although constructed, operated and maintained to industry standards, our facilities may not withstand occurrences of this type in all circumstances. We do not have insurance for damage to our transmission and distribution
wires, poles and towers located outside our transmission and distribution stations resulting from these events. Losses from lost revenues and repair costs could be substantial, especially for many of our facilities that are located in remote areas.
We could also be subject to claims for damages caused by our failure to transmit or distribute electricity. Our risk is partly mitigated because our transmission system is designed and operated to withstand the loss of any major element and
possesses inherent redundancy that provides alternate means to deliver large amounts of power. In the event of a large uninsured loss we would apply to the OEB for recovery of such loss; however, there can be no assurance that the OEB would approve
any such applications, in whole or in part, which could have a material adverse effect on our net income. 
 Risk Associated with Information
Technology Infrastructure 
 Our ability to operate effectively in the Ontario electricity market is in part dependent upon us developing,
maintaining and managing complex IT systems which are employed to operate our transmission and distribution facilities, financial and billing systems, and business systems. Our increasing reliance on information systems and expanding data networks
increases our exposure to information security threats. We mitigate this risk through various methods including the use of security event management tools on our power and business systems, by separating our power system network from our business
system network, by performing scans of our systems for known cyber threats and by providing company-wide awareness training to our personnel. We also engage the services of external experts to evaluate the security of our IT infrastructure and
controls. We perform vulnerability assessments on our critical cyber assets and we ensure security and privacy controls are incorporated into new IT capabilities. Although these security and system disaster recovery controls are in place, there can
be no guarantee that there will not be system failures or security breaches. Upon occurrence, the focus would shift from prevention to isolation, remediation and recovery until the incident has been fully addressed. Any such system failures or
security breaches could have a material adverse effect on our company. 
 We are currently in the process of a planned phased replacement of key
enterprise IT systems. The last phase of this project is underway and will replace our existing billing and customer system with a new CIS. With projects of this size and complexity, there is risk to the Company if the resulting solution encounters
performance problems or calculation errors. Any such system problems could have a material adverse effect on our company. To mitigate this risk, extensive testing and user training is taking place. Testing includes performance, system integration,
parallel billing (comparing legacy system bill calculation to the new system), and operational/business readiness. Since this system directly impacts our end customers, stringent test exit criteria must be met prior to placing it into production.

 Pension Plan Risk 
 We have a
defined benefit registered pension plan for the majority of our employees. Contributions to the pension plan are established by actuarial valuations which are filed with the Financial Services Commission of Ontario on a triennial basis. The most
recently filed valuation was prepared as at December 31, 2011 and was filed in May 2012. Our company contributed $148 million in respect of 2011 and approximately $160 million in respect of 2012 to its pension plan to satisfy minimum funding
requirements. An additional contribution of $3.8 million was also made in 2011 to complete the funding associated with the partial plan wind-up. Contributions beyond 2012 will depend on investment returns, changes in benefits and actuarial
assumptions and may include additional voluntary contributions from time to time. Nevertheless, future 

  

					
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contributions are expected to be significant. A determination by the OEB that some of our pension expenditures are not recoverable from customers could have a material adverse effect on our
company, and this risk may be exacerbated as the quantum of required pension contributions increase. 
 Market and Credit Risk

 Market risk refers primarily to the risk of loss that results from changes in commodity prices, foreign exchange rates and interest rates.
We do not have commodity risk. We do have foreign exchange risk as we enter into agreements to purchase materials and equipment associated with our capital programs and projects that are settled in foreign currencies. This foreign exchange risk is
not material. We could in the future decide to issue foreign currency-denominated debt which we would anticipate hedging back to Canadian dollars, consistent with our company’s risk management policy. We are exposed to fluctuations in interest
rates as our regulated rate of return is derived using a formulaic approach. The OEB-approved adjustment formula for calculating ROE will increase or decrease by 50% of the change between the current Long Canada Bond Forecast and the risk-free rate
established at 4.25% and 50% of the change in the spread in 30-year “A”-rated Canadian utility bonds over the 30-year benchmark Government of Canada bond yield established at 1.415%. We estimate that a 1% decrease in the forecasted
long-term Government of Canada bond yield used in determining our rate of return would reduce our Transmission Business’ net income by approximately $19 million and our Hydro One Networks’ Distribution Business’ net income by
approximately $10 million. Our net income is adversely impacted by rising interest rates as our maturing long-term debt is refinanced at market rates. We periodically utilize interest-rate swap agreements to mitigate elements of interest-rate risk.

 Financial assets create a risk that a counterparty will fail to discharge an obligation, causing a financial loss. Derivative financial
instruments result in exposure to credit risk, since there is a risk of counterparty default. We monitor and minimize credit risk through various techniques, including dealing with highly-rated counterparties, limiting total exposure levels with
individual counterparties, and by entering into master agreements which enable net settlement and by monitoring the financial condition of counterparties. We do not trade in any energy derivatives. We do, however, have interest-rate swap contracts
outstanding from time to time. Currently, there are no significant concentrations of credit risk with respect to any class of financial assets. We are required to procure electricity on behalf of competitive retailers and embedded LDCs for resale to
their customers. The resulting concentrations of credit risk are mitigated through the use of various security arrangements, including letters of credit, which are incorporated into our service agreements with these retailers in accordance with the
OEB’s Retail Settlements Code. The failure to properly manage these risks could have a material adverse effect on our company. 
 Labour
Relations Risk 
 The substantial majority of our employees are represented by either the Power Workers’ Union (PWU) or the Society of
Energy Professionals. Over the past several years, significant effort has been expended to increase our flexibility to conduct operations in a more cost-efficient manner. Although we have achieved improved flexibility in our collective agreements,
including a reduction in pension benefits for Society staff hired after November 2005 similar to a previous reduction affecting management staff, we may not be able to achieve further improvement. The existing collective agreement with the PWU will
expire on March 31, 2013 and the existing Society collective agreement will expire on March 31, 2013. We face financial risks related to our ability to negotiate collective agreements consistent with our rate orders. In addition, in the
event of a labour dispute, we could face operational risk related to continued compliance with our licence requirements of providing service to customers. Any of these could have a material adverse effect on our company. 

First Nation and Métis Claims Risk 

Some of our current and proposed transmission and distribution lines may traverse lands over which First Nations and Métis have aboriginal, treaty
or other legal claims. Although we have a recent history of successful negotiations and consultations with First Nations and Métis in Ontario, some communities and/or their citizens have expressed an increasing willingness to assert their
claims through the courts, tribunals, or by direct action, which in turn can affect business activities. As a result, there exists uncertainty relating to business operations and project planning which could have an adverse effect on our company.

  

					
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 HYDRO ONE INC. 
 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) 
  

 Risk from Transfer of Assets Located on Reserves 

The transfer orders by which we acquired certain of Ontario Hydro’s businesses as of April 1, 1999 did not transfer title to some assets located
on Reserves. Currently, OEFC holds legal title to these assets and we manage them until we have obtained necessary authorizations to complete the title transfer. To occupy Reserves, we must have valid permits issued by Her Majesty the Queen in the
Right of Canada. For each permit, we must negotiate an agreement (in the form of a Memorandum of Understanding) with the First Nation, OEFC and any members of the First Nation who have occupancy rights. The agreement includes provisions whereby the
First Nation consents to the federal Department of Aboriginal Affairs and Northern Development issuing a permit. It is difficult to predict the aggregate amount that we may have to pay, either on an annual or one-time basis, to obtain the required
agreements from First Nations. However, we anticipate that the amount will exceed the approximately $943,000 that we paid in 2012. OEFC will continue to hold these assets until we are able to negotiate agreements with First Nations and occupants. If
we cannot reach satisfactory agreements and obtain federal permits, we may have to relocate these assets to other locations at a cost that could be substantial. In a limited number of cases, it may be necessary to abandon a line and replace it with
diesel generation facilities. The costs relating to these assets could have a material adverse effect on our net income if we are not able to recover them in future rate orders. 
 Risk Associated with Outsourcing Arrangement 
 Consistent with our strategy of reducing
operating costs, we amended and extended our outsourcing services agreement with Inergi, effectively renewing the arrangement until February 28, 2015. If the agreement with Inergi is terminated for any reason, we could be required to incur
significant expenses to transfer to another service provider, which could have a material adverse effect on our business, operating results, financial condition or prospects. 
 Risk from Provincial Ownership of Transmission Corridors 
 Pursuant to the Reliable
Energy and Consumer Protection Act, 2002, the Province acquired ownership of our transmission corridor lands underlying our transmission system. Although we have the statutory right to use the transmission corridors, we may be limited in
our ability to expand our systems. Also, other uses of the transmission corridors by third parties in conjunction with the operation of our systems may increase safety or environmental risks, which could have an adverse effect on our company.

 CRITICAL ACCOUNTING ESTIMATES 

The preparation of our Consolidated Financial Statements requires us to make estimates and judgements that affect the reported amounts of assets,
liabilities, revenues and costs, and related disclosures of contingencies. We base our estimates and judgements on historical experience, current conditions and various other assumptions that are believed to be reasonable under the circumstances,
the results of which form the basis for making judgements about the carrying values of assets and liabilities as well as identifying and assessing our accounting treatment with respect to commitments and contingencies. Actual results may differ from
these estimates and judgements under different assumptions or conditions. 
 We believe the following critical accounting estimates involve the
more significant estimates and judgements used in the preparation of our Consolidated Financial Statements: 
 Regulatory Assets and
Liabilities 
 At December 31, 2012, regulatory assets amounted to $3,127 million and these amounts principally relate to regulatory
offsets to pension, deferred income tax, post-retirement and post-employment benefits and environmental liabilities, which are anticipated to be recovered through rates over time. We have also recorded regulatory liabilities amounting to $221
million as at December 31, 2012. These amounts pertain primarily to OEB deferral and variance accounts. These assets and liabilities can be recognized for rate-setting and financial reporting purposes only if the relevant amounts have been
approved for inclusion in the rate-setting process by the OEB or if such approval is judged to be probable by management. If management judges that it is no longer probable that the OEB will include a regulatory item in the setting of future rates,
the relevant regulatory asset or liability would be charged or credited to results of operations in the period in which that judgement is made. 

  

					
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 Environmental Liabilities 
 We record liabilities and related regulatory assets based on the present value of the estimated future expenditures to be made to satisfy obligations related to legacy environmental contamination
inherited upon our de-merger from Ontario Hydro in 1999. These liabilities fall into two main categories: the management of assets contaminated with PCB-laden mineral oils and the assessment and remediation of contaminated lands. In determining the
amounts to be recorded as environmental liabilities, we estimate the current cost of completing mitigation work now and make assumptions for when the future expenditures will actually be incurred in order to generate future cash flow information. A
long-term inflation assumption of 2% is used to express our current cost estimates as estimated future expenditures. Future estimated LAR expenditures are expected to be incurred over the period ending 2020 and are discounted using factors ranging
from 3.57% to 4.87%, depending on the appropriate rate for the period when the particular obligation was recorded. Consistent with the current requirements of Environment Canada’s PCB regulations, estimated future PCB remediation expenditures
are expected to be incurred over the period ending 2025 and are discounted using factors ranging from 5.14% to 6.25%, depending on the appropriate rate in effect in the period when each obligation was originally recorded. 

Recording a liability for such long-term future expenditures requires that many other assumptions be made, such as the number of contaminated properties
and the extent of contamination; the number of assets to be inspected, tested and mitigated; oil volumes; contamination levels of equipment that may have PCBs; and the timing of work. All factors used in deriving our environmental liabilities
represent management’s best estimates based on our planned approach of meeting current legislative and regulatory requirements. These requirements include Environment Canada’s regulations governing the management, storage and disposal of
PCBs. However, it is reasonably possible that numbers or volumes of contaminated assets, current cost estimates, inflation estimates and the actual pattern of annual future cash flows may differ significantly from our current assumptions. Estimated
environmental liabilities are reviewed annually or more frequently if significant changes in regulation or other relevant facts occur. Regulatory changes are reflected when enacted. Estimate changes are accounted for prospectively. 

Employee Future Benefits 
 We provide
future benefits to our current and retired employees, including pension, group life insurance, health care and long-term disability. 
 In
accordance with our rate orders, we record pension costs when employer contributions are paid to the pension fund (the Fund) in accordance with the Pension Benefits Act (Ontario). Our annual pension contributions in respect of 2012 were
approximately $160 million, based on an actuarial valuation effective December 31, 2011. Contributions after 2014 will be based on an actuarial valuation effective no later than December 31, 2014, and will depend on investment returns,
changes in benefits or actuarial assumptions. Pension costs are also disclosed in the notes to the Consolidated Financial Statements on an accrual basis. The discount rate used to calculate the accrued benefit obligation, on an accrual accounting
basis, is calculated differently from what would be used to determine the funding requirement, and is determined each year end by referring to the most recently available market interest rates based on AA corporate bond yields reflecting the
duration of the applicable employee future benefit plan. The discount rates at December 31, 2012 declined to 4.25% from 5.25% used at December 31, 2011, in conjunction with decreases in bond yields over this period. The decrease in
discount rates has resulted in a corresponding increase in liabilities for accounting purposes. We also record employee future benefit costs other than pension on an accrual accounting basis. The accrual costs are determined by independent actuaries
using the projected benefit method prorated on service and based on assumptions that reflect management’s best estimates. The assumptions were determined by management recognizing the recommendations of our actuaries. There were no changes in
benefits afforded to employees. 
 The assumed return on pension plan assets of 6.25% per annum is based on expectations of long-term rates
of return at the beginning of the fiscal year and reflects a pension asset mix consistent with the Fund’s investment policy. During the year the Fund’s target asset mix was 60% equities, 35% fixed income and 5% in alternative assets
consisting of real estate and infrastructure. Returns on the respective portfolios are determined with reference to published Canadian and U.S. stock indices and long-term bond and treasury bill indices. The assumed rate of return on pension plan
assets reflects our long-term expectations. We believe that this assumption is reasonable because, with the Fund’s balanced investment approach, the higher volatility of equity investment returns is intended to be offset by the greater
stability of fixed-income and short-term investment returns. The net result, on a long-term basis, is a somewhat lower return than might be expected by investing in equities alone. In the short term, the plan can experience aberrations in actual
return. In 2012, the return on pension plan assets of 9.19% was higher than this long-term assumption and was higher than in 2011. 

  

					
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 HYDRO ONE INC. 
 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) 
  

 Yields on AA corporate bonds declined by approximately 80-100 basis points between December 31,
2011 and December 31, 2012. Based on the duration of the plan’s liabilities, discount rates would be 4.25% per annum for each of the pension plan, the post-retirement benefit plan and the post-employment plan. The overall discount
rate applied to all plans for liability accounting purposes as at December 31, 2012 was 4.25%. 
 Further, based on differences between
long-term Government of Canada nominal bonds and real return bonds, the implied inflation rate has decreased from 2.0% per annum as at December 31, 2011 to approximately 1.90% per annum as at December 31, 2012. Given the Bank of
Canada’s commitment to keep long-term inflation between 1.00% and 3.00%, management believes that the current implied rate is reasonable to use as a long-term assumption and as such, has used a 2.0% per annum inflation rate for liability
valuation purposes as at December 31, 2012. 
 The costs of employee future benefits other than pension are determined at the beginning of
the year. The costs are based on assumptions for expected claims experience and future health care cost inflation. A 1% increase in the health care cost trends would result in an increase in service cost and interest cost of about $17 million per
year and an increase in the year-end obligation of about $246 million. 
 Employee future benefits are included in labour costs that are either
charged to results of operations or capitalized as part of the cost of fixed and intangible assets. Changes in assumptions will affect the accrued benefit obligation of the employee future benefits and the future years’ amounts that will be
charged to our results of operations or capitalized as part of the cost of fixed and intangible assets. 
 Asset Impairment 

Within our regulated businesses, carrying costs of our other assets are recovered in our revenue requirements and are included in rate base, where they
earn a return. Such assets would need to be tested for impairment only in the event that the OEB disallowed recovery or if such a disallowance was judged to be probable. We periodically monitor the assets of our unregulated Telecom Business for
indications of impairment. No asset impairments have been recorded to date within any of our businesses. 
 TRANSITION TO US GAAP

 Accounting Framework for External Reporting 
 In 2011, the OSC and our Board of Directors approved our application to adopt US GAAP as the basis for our accounting, external financial reporting and periodic securities filings, without becoming a
Securities and Exchange Commission (SEC) registrant, for our 2012, 2013 and 2014 fiscal years. As a result, our Consolidated Financial Statements and accompanying notes as at, and for the year ended, December 31, 2012 have been prepared in
accordance with US GAAP. These are our first US GAAP annual Consolidated Financial Statements. Our first US GAAP unaudited interim Consolidated Financial Statements were as at, and for the three months ended, March 31, 2012.

 Our company’s Consolidated Financial Statements were prepared in accordance with Part V of the Canadian Institute of Chartered
Accountants (CICA) Handbook until December 31, 2011. Canadian GAAP differs in some areas from US GAAP as disclosed in the reconciliation to US GAAP included in Note 24 to the annual Consolidated Financial Statements as at, and for the
year ended, December 31, 2012. Descriptions of the effect of the transition from Canadian GAAP to US GAAP on our financial position, financial performance and cash flows as at, and for the year ended, December 31, 2011 are also
provided in Note 24 to our annual Consolidated Financial Statements for the year ended December 31, 2012. The accounting policies set out in the annual Consolidated Financial Statements for the year ended December 31, 2012 have been
consistently applied to all the periods presented. The comparative figures in respect of 2011 were retrospectively restated effective January 1, 2011 to reflect our adoption of US GAAP. 
 Accounting Framework for Rate Setting 
 Consistent with the OSC’s decision to
approve our adoption of US GAAP, two of our subsidiaries, Hydro One Networks and Hydro One Remote Communities requested that the OEB approve the adoption of US GAAP as the basis for future rate setting and regulatory accounting and
reporting in place of its standard modified IFRS basis. The OEB approved Hydro One Networks’ request to adopt US GAAP for its regulated transmission and distribution businesses, and approved Hydro One 

  

					
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 HYDRO ONE INC. 
 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) 
  

 Remote Communities’ request to adopt US GAAP as its approved basis for rate setting, all
effective January 1, 2012. We did not make a request to adopt US GAAP for rate-setting purposes on behalf of our subsidiary, Hydro One Brampton Networks. Our subsidiary Hydro One Brampton Networks has deferred its adoption of modified IFRS
until the fiscal year beginning January 1, 2014, as allowed by the Canadian Accounting Standards Board. Currently, Hydro One Brampton Networks will continue to have its rates set based on Part V of the CICA Handbook until it begins reporting
under modified IFRS. 
 Debt Covenants 
 None of our financial covenants were impacted by our conversion to US GAAP. 
 Internal
Controls over Financial Reporting and Disclosure Controls and Procedures 
 Our transition to US GAAP did not result in any
significant revisions to our internal controls over financial reporting and disclosure controls and procedures. 
 Financial Reporting
Expertise 
 Given the similarities between US GAAP and Canadian GAAP for our company, there has also been no significant impact
from the transition to US GAAP with respect to financial reporting expertise. Our US GAAP training efforts have been focused on specific areas of difference between the two accounting frameworks and these efforts have been targeted to
specific finance staff, senior executive management and the Audit and Finance Committee of our Board of Directors. We continue to provide additional training to our other finance and operational staff, concentrating on communicating the key
differences between Canadian and US GAAP at a level of detail that is appropriate to meet their respective needs. During 2013, we will continue to focus our US GAAP training on new accounting and reporting developments and on emerging
issues. 
 Information Systems 
 Given the similarities between US GAAP and Canadian GAAP, we did not experience any significant impacts from the transition to US GAAP with respect to our information systems. 

IFRS 
 Prior to our adoption of
US GAAP as the basis for our accounting, external financial reporting and periodic securities filings, we had planned to adopt IFRS effective January 1, 2012, with comparative restatement of our 2011 results. Accordingly, by mid-2011, we
had substantively completed our four-phase IFRS Conversion Project, which included separate diagnostic, design and planning, solution development, and implementation phases. Our IFRS conversion project involved, among other initiatives, a detailed
assessment of the effects of IFRS on our financial statements, a review and upgrade of our information systems to meet IFRS requirements, an assessment of our internal controls over financial reporting and disclosure controls and processes, as well
as training of our key finance and operational staff. 
 As a result of our 2011 decision to adopt US GAAP, our IFRS Conversion Project
efforts were effectively halted. However, our IFRS conversion work has been, and will continue to be, managed in such a way that it can effectively be restarted if a future transition to IFRS is required. We continue to monitor major accounting
developments arising from initiatives of the international standard setter, particularly as several major projects are joint efforts with the US Financial Accounting Standards Board. 
 Training of our key finance and operational staff commenced in 2007, and continues on a reduced but ongoing basis, as we have certain subsidiaries that are required to prepare their own separate financial
statements in accordance with IFRS. IFRS training was also previously provided to our Audit and Finance Committee and senior executive management. In 2013, we will continue to monitor new IFRS accounting and reporting developments and emerging
issues and will provide IFRS training to specific staff as applicable. 
 Our company has the customary financial covenants normally associated
with long-term debt. Among other things, our long-term debt covenants limit our permissible debt as a percentage of our total capitalization. Depending on the outcome of various international standard setting initiatives, including the International
Accounting Standards Board’s (IASB) Rate 

  

					
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 HYDRO ONE INC. 
 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) 
  

 Regulated Accounting Project, a potential future adoption of IFRS could result in changes to our
financial position and increased volatility in our results of operations that could impact our debt covenants. We continue to monitor the potential impact that an IFRS conversion could have under various scenarios. 

As part of a company-wide information systems improvement project, many of our major financial systems were replaced in 2008 and 2009. Our new financial
systems were designed with maximum flexibility given the uncertainty of the outcome of certain impactive IASB projects. Our financial systems have the ability and capacity to handle current accounting and reporting processes in accordance with IFRS,
should that be required in the future. 
 DISCLOSURE CONTROLS AND INTERNAL CONTROLS OVER FINANCIAL REPORTING (ICFR) 

To optimize our customer service operations, we have started the final major phase of our planned SAP enterprise-wide information system by initiating our
CIS Project. This new system will increase productivity by replacing multiple legacy applications currently providing service to our distribution customers and key constituents for billing, customer contacts, field services, settlements and customer
choice administration. With the design phase complete, the CIS Project is currently in the system integration phase. Internal controls have been documented and will be tested for adequacy and effectiveness with any remediation effort to be completed
prior to the go-live date in 2013. In addition to the benefits associated with our CIS, we continue to leverage our other SAP enterprise systems to gain other productivity improvements. 
 In compliance with the requirements of National Instrument 52-109, Certification of Disclosure in Issuers’ Annual and Interim Filings, our Certifying Officers have reviewed and certified the
Consolidated Financial Statements for the year ended December 31, 2012, together with other financial information included in our annual securities filings. Our Certifying Officers have also certified that disclosure controls and procedures
(DC&P) have been designed to provide reasonable assurance that material information relating to our company is made known within our company. Based on the evaluation of the design and operation of our DC&P, our Certifying Officers concluded
that our DC&P was effective as at December 31, 2012. Further, our Certifying Officers have also certified that our ICFRs have been designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation
of Consolidated Financial Statements. Based on the evaluation of the design and operating effectiveness of our company’s ICFR, our Certifying Officers concluded that our ICFR was effective as at December 31, 2012. 

SELECTED ANNUAL INFORMATION 
 The
following table sets forth audited annual information for each of the three years ended December 31, 2012, 2011 and 2010. This information has been derived from our audited annual Consolidated Financial Statements. 

 

													
	Consolidated Statements of Operations	  	 	 	  	 	 	  	 	 
	 Year ended December 31 (millions of dollars, except amounts per share)
	  	2012	 	  	2011	 	  	20101	 
	 Revenues
	  	 	5,728	  	  	 	5,471	  	  	 	5,124	  
	 Net income
	  	 	745	  	  	 	641	  	  	 	591	  
	 Basic and fully diluted earnings per common share
	  	 	7,280	  	  	 	6,228	  	  	 	5,727	  
	 Cash dividends per common share
	  	 	3,523	  	  	 	1,500	  	  	 	100	  
	 Cash dividends per preferred share
	  	 	1.375	  	  	 	1.375	  	  	 	1.375	  
				
	Consolidated Balance Sheets	  	 	 	  	 	 	  	 	 
	 December 31 (millions of dollars)
	  	2012	 	  	2011	 	  	2010	 
	 Total assets
	  	 	20,811	  	  	 	18,836	  	  	 	17,344	  
	 Total long-term debt
	  	 	8,479	  	  	 	8,008	  	  	 	7,783	  

  

	1	 Based on Canadian
GAAP. US GAAP results would not differ significantly. 

  

					
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 HYDRO ONE INC. 
 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) 
  

 OUTLOOK 
 To achieve our mission and vision to be an innovative and trusted company delivering electricity safely, reliably and efficiently to create value for our customers, we will continue to concentrate on our
strategic objectives of safety, customer satisfaction, continuous innovation, reliability, protection of the environment, employee engagement, shareholder value and productivity and cost-effectiveness. Given the nature of the work undertaken by our
employees and contractors, safety remains our top priority. We will continue to focus on creating an injury-free workplace and maintaining public safety through several health and safety initiatives. 

We will continue to focus our efforts to improve our customers’ satisfaction by meeting the unique needs of our diverse customer base through
dialogue to understand their needs. We will install innovative solutions that improve the reliability and efficiency of the transmission and distribution systems and provide our customers more capability to manage their own costs. Most importantly,
we are focused on becoming the customer’s trusted advisor by providing access to specialized energy conservation teams to discuss the customer’s opportunities to lower consumption, and through the use of a special team of agents to handle
distributed generator inquiries and requirements. 
 Our assets are in the midst of a demographic change with an increasing proportion of assets
reaching end-of-life and an increasing average asset age. Our focus is to address aging infrastructure, and to make needed asset replacement and maintenance investments, to maintain current and future system reliability for customers, within the
policy set by the OEB. We will invest in technology that will provide us with real time asset condition and performance data giving us the visibility to make asset optimization life-cycle decisions, and opportunities through planning and scheduling
data to improve materials procurement and to deploy work crews to better manage work programs to meet customer needs. 
 It is expected that the
implementation of new asset management tools, such as Asset Analytics and Asset Investment Planning, will enhance risk-based investment planning, which considers such factors as asset condition, safety, performance, system function, customer impact,
and statutory requirements allowing for targeted investment. 
 We will also continue to strive for productivity through efficiency and
effective management of costs, which is key to achieving value for our customers and our shareholder. 
 Over the last four years, we have
replaced most of our core information technology systems with an enterprise-wide IT system. We will leverage this investment as a platform for further effectiveness and efficiency gains, including enhancements in strategic sourcing. Further
development of the existing IT platform will provide tools which are being developed to allow our company to effectively plan and reprioritize work and integrate customers’ needs into multi-year investment plans. The outcomes are consistent
with the OEB’s direction in its new Outcomes-Based Approach to regulation. 
 We will be implementing the new CIS in 2013 that will improve
customer service and corporate productivity by allowing the earlier investments in SAP to operate as an integrated platform. In addition, the first elements of the next generation of work delivery to be introduced through the Workflow of the Future
Program in 2013 and 2014, and the use of information within the SAP systems, are expected to improve field-level productivity. 
 We are
planning significant investments in transmission and distribution infrastructure and we will continue to focus on the operating and economic performance of our core utility operations in the provision of safe, cost-effective and reliable electricity
delivery services to our customers, and in providing increasing enterprise value to the people of the province of Ontario. Productivity, value for money and improved employee and customer communications will be key areas of focus. We will continue
to connect and support DG and investments made consistent with the LTEP. 
 Significant opportunity resides with smart meters and the
proliferation of an ADS, including energy efficiency, demand response and distributed-resources technologies. We will invest in the development of an ADS and related grid modernization standards, customer demand work (connections and upgrades),
smart meters, DG connections, including station upgrades, protection and control, new lines and some contestable work, for which the Company will receive capital contributions. There is little flexibility to reduce this work as most of it is
customer demand driven. 
 As part of our new ADS, a new DMS will provide a monitoring and centralized control capability similar to that which
already exists in the transmission system, and in selected areas of the distribution system. The new DMS was introduced in the Owen Sound pilot area and it will be expanded over time, as warranted. Future enhancements will also integrate the Outage
Response Management System with the Advanced Meter Infrastructure (i.e. smart meters) and with the DMS, to reduce System Average Interruption Duration Index and System Average Interruption Frequency Index. 

  

					
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 HYDRO ONE INC. 
 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) 
  

 The actual timing and expenditures in our business plan are predicated on obtaining various approvals
including: OEB approvals and environmental assessment approvals; successful negotiations with customers, neighbouring utilities and other stakeholders; and consultations with First Nations and Métis communities. 

As stewards of significant electricity assets, we are committed to the protection and sustainment of the environment for future generations. We are
working towards being an environmental leader in our industry, by distributing clean and renewable energy, by upgrading our electricity grid, by minimizing the impacts of our own operations, and by ensuring that environmental factors are considered
in making our business decisions. 
 Key enablers of the successful implementation of our work programs are our human and material resourcing
strategies. Our human resource strategy is focused on hiring through our apprenticeship program and our association with universities, colleges and our unions, as well as skills development and retention, including earlier identification and more
rapid development of staff who demonstrate management potential. Effective use of human resources and ensuring correct skills will be critical to attaining the balance between meeting the asset needs and mitigating rate impact on the customer.
Although our work program is assumed to grow moderately over the 2013 and 2014 years, no increase in regular staff numbers is anticipated over that period. With regard to materials, we are seeing a need for increasing lead times and costs as market
shortages emerge globally. Consequently, materials sourcing strategies continue to be developed and implemented to ensure the availability of materials to support our work programs. 
 We remain committed to a prudent and measured approach to distribution rationalization. We have considered and will continue to consider and respond to opportunities for acquisitions or divestitures, on a
voluntary and commercial basis. Our plan does not include funding for LDC acquisitions or assume any disposition of our service territory. These opportunities will be managed as they arise. Our plan also does not incorporate any projects related to
competitive transmission. However, as leaders in the sector, we plan to bid on key projects. The OEB notes in its Framework for Transmission Project Development Plans that where projects are otherwise equivalent or close in other factors,
information such as socio-economic benefits, including First Nations involvement, could prove decisive in a competitive bid. As such, First Nations involvement in competitive bids is likely to become more prevalent. 

APPOINTMENT OF CARMINE MARCELLO 
 On
November 14, 2012, our Board of Directors appointed Carmine Marcello to the role of President and Chief Executive Officer, effective January 1, 2013. Mr. Marcello assumes his responsibilities following the planned retirement of
outgoing President and Chief Executive Officer, Laura Formusa. Mr. Marcello has over 25 years’ experience with our company as a senior executive, strategic planner and advisor on transmission and distribution utility processes in the
electric utility industry. 
 APPOINTMENT OF YEZDI PAVRI 
 On December 6, 2012, Yezdi Pavri was appointed to our Board of Directors. Mr. Pavri is a Chartered Accountant and a former Vice-Chairman of Deloitte Canada. Mr. Pavri currently holds the
position of Chair of the Board of Trustees of the United Way of Toronto. 
 FORWARD-LOOKING STATEMENTS AND INFORMATION 

Our oral and written public communications, including this document, often contain forward-looking statements that are based on current expectations,
estimates, forecasts and projections about our business and the industry in which we operate, and include beliefs and assumptions made by the management of our company. Such statements include, but are not limited to: statements about our strategy,
including our strategic objectives; statements regarding our transmission and distribution rates; statements regarding load changes and associated impacts; statements regarding CDM programs and targets; the estimated impact of changes in the
forecasted long-term Government of Canada bond yield (used in determining our regulated rate of return) on our results of operations; statements related to economic conditions; expectations regarding

  

					
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 HYDRO ONE INC. 
 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) 
  

 
energy-related revenues and profit and their trend; statements related to the GEA, the IPSP and the Ministry’s LTEP and Supply Mix Directive, including additional investments arising
therefrom and the timing and content of OPA recommendations; statements regarding our liquidity and capital resources and operational requirements; statements about our standby credit facility; expectations regarding our financing activities;
statements regarding our maturing debt; statements regarding our ongoing and planned projects and/or initiatives including the expected results of these projects and/or initiatives and their completion dates; expectations regarding the
recoverability of large capital expenditures; statements regarding expected future capital and development expenditures, the timing of these expenditures and our investment plans; statements regarding contractual obligations and other commercial
commitments; statements related to the OEB, including the renewed regulatory framework and revenue decoupling; statements regarding future pension contributions, our pension plan and actuarial valuation; statements about our outsourcing arrangement
with Inergi; statements relating to US GAAP and our adoption of US GAAP; statements regarding accounting-related international standard setting initiatives, including the potential future adoption of IFRS and its associated impacts as well as
our training and conversion plans; statements related to our agreement with the SON; statements related to our outlook including statements regarding our approach to distribution rationalization; and statements related to the FIT program. Words such
as “expect”, “anticipate”, “intend”, “attempt”, “may”, “plan”, “will”, “believe”, “seek”, “estimate”, “goal”, “aim”,
“target”, and variations of such words and similar expressions are intended to identify such forward-looking statements. These statements are not guarantees of future performance and involve assumptions and risks and uncertainties that are
difficult to predict. Therefore, actual outcomes and results may differ materially from what is expressed, implied or forecasted in such forward-looking statements. We do not intend, and we disclaim any obligation, to update any forward-looking
statements, except as required by law. 
 These forward-looking statements are based on a variety of factors and assumptions including, but not
limited to the following: no unforeseen changes in the legislative and operating framework for Ontario’s electricity market; favourable decisions from the OEB and other regulatory bodies concerning outstanding rate and other applications; no
delays in obtaining required approvals; no unforeseen changes in rate orders or rate structures for our Distribution and Transmission businesses; a stable regulatory environment; no unfavourable changes in environmental regulation; and no
significant event occurring outside the ordinary course of business. These assumptions are based on information currently available to us, including information obtained from third-party sources. Actual results may differ materially from those
predicted by such forward-looking statements. While we do not know what impact any of these differences may have, our business, results of operations, financial condition and our credit stability may be materially adversely affected. Factors that
could cause actual results or outcomes to differ materially from the results expressed or implied by forward-looking statements include, among other things: 
  

	 	•	 	 the impact of the GEA and the Province’s Long-Term Energy Plan, including unexpected expenditures arising therefrom; 

 

	 	•	 	 the risk that unexpected capital expenditures may be needed to support renewable generation or resolve unforeseen technical issues;

  

	 	•	 	 the risks associated with the impending expiry of our collective agreements with both the Society and the PWU; 

 

	 	•	 	 the risk that previously granted regulatory approvals may be subsequently challenged, appealed or overturned; 

 

	 	•	 	 the risks associated with the OEB’s competitive transmission project development planning process; 

 

	 	•	 	 public opposition to and delays or denials of the requisite approvals and accommodations for our planned projects; 

 

	 	•	 	 the risks associated with being controlled by the Province including the possibility that the Province may make declarations pursuant to the memorandum
of agreement, as well as potential conflicts of interest that may arise between us, the Province and related parties; 

  

	 	•	 	 the risks associated with being subject to extensive regulation including risks associated with OEB action or inaction; 

 

	 	•	 	 unanticipated changes in electricity demand or in our costs; 

 

	 	•	 	 the risk that we are not able to arrange sufficient cost-effective financing to repay maturing debt and to fund capital expenditures and other
obligations; 

  

	 	•	 	 the risks associated with the execution of our capital and operation, maintenance and administration programs necessary to maintain the performance of
our aging asset base; 

  

	 	•	 	 the result of regulatory decisions regarding our revenue requirements, cost recovery and rates; 

  

					
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 HYDRO ONE INC. 
 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) 
  

	 	•	 	 the risk to our facilities posed by severe weather conditions, natural disasters or catastrophic events and our limited insurance coverage for losses
resulting from these events; 

  

	 	•	 	 future interest rates, future investment returns, inflation, and changes in benefits and actuarial assumptions; 

 

	 	•	 	 the risks related to our workforce demographic and our potential inability to attract and retain qualified personnel; 

 

	 	•	 	 the risks associated with information system security, with maintaining a complex information technology system infrastructure, and with transitioning
key enterprise IT systems; 

  

	 	•	 	 the risk that the presence or release of hazardous or harmful substances could lead to claims by third parties and/or governmental orders;

  

	 	•	 	 the risk that future environmental expenditures are not recoverable in future electricity rates; 

 

	 	•	 	 the risk that it may be determined that exposure to electric and magnetic fields emanating from power lines and other electric sources may cause health
problems; 

  

	 	•	 	 the risks associated with changes in interest rates; 

  

	 	•	 	 the risks of counterparty default on our outstanding derivative contracts; 

 

	 	•	 	 the risks associated with current economic uncertainty and financial market volatility; 

 

	 	•	 	 the risk that our long-term credit rating would deteriorate; 

 

	 	•	 	 the risk that we may incur significant costs associated with transferring assets located on Indian lands; 

 

	 	•	 	 the risks associated with the fact that some of our current and proposed transmission and distribution lines may traverse lands which First Nations and
Métis have aboriginal, treaty or other legal claims; 

  

	 	•	 	 the potential that we may incur significant expenses to replace some or all of the functions currently outsourced if our agreement with Inergi is
terminated; and 

  

	 	•	 	 the impact of the ownership by the Province of lands underlying our transmission system. 

We caution the reader that the above list of factors is not exhaustive. Some of these and other factors are discussed in more detail in the section
“Risk Management and Risk Factors” in this Management’s Discussion and Analysis (MD&A). You should review this section in detail. 
 In addition, we caution the reader that information provided in this MD&A regarding our outlook on certain matters, including future expenditures, is provided in order to give context to the nature of
some of our future plans and may not be appropriate for other purposes. 
 This MD&A is dated as at February 14, 2013. Additional
information about our company, including our Annual Information Form, is available on SEDAR at www.sedar.com. 

  

					
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 HYDRO ONE INC. 
 MANAGEMENT’S REPORT 
 The Consolidated Financial Statements,
Management’s Discussion and Analysis (MD&A) and related financial information presented in this Annual Report have been prepared by the management of Hydro One Inc. (Hydro One or the Company). Management is responsible for the integrity,
consistency and reliability of all such information presented. The Consolidated Financial Statements have been prepared in accordance with United States Generally Accepted Accounting Principles and applicable securities legislation. The MD&A has
been prepared in accordance with National Instrument 51-102, Part 5. 
 The preparation of the Consolidated Financial Statements and information
in the MD&A involves the use of estimates and assumptions based on management’s judgement, particularly when transactions affecting the current accounting period cannot be finalized with certainty until future periods. Estimates and
assumptions are based on historical experience, current conditions and various other assumptions believed to be reasonable in the circumstances, with critical analysis of the significant accounting policies followed by the Company as described in
Note 2 to the Consolidated Financial Statements. The preparation of the Consolidated Financial Statements and the MD&A includes information regarding the estimated impact of future events and transactions. The MD&A also includes information
regarding sources of liquidity and capital resources, operating trends, risks and uncertainties. Actual results in the future may differ materially from the present assessment of this information because future events and circumstances may not occur
as expected. The Consolidated Financial Statements and MD&A have been properly prepared within reasonable limits of materiality and in light of information up to February 14, 2013. 
 In meeting its responsibility for the reliability of financial information, management maintains and relies on a comprehensive system of internal control and internal audit. The system of internal control
includes a written corporate conduct policy; implementation of a risk management framework; effective segregation of duties and delegation of authorities; and sound and conservative accounting policies that are regularly reviewed. This structure is
designed to provide reasonable assurance that assets are safeguarded and that reliable information is available on a timely basis. In addition, internal and disclosure controls have been documented, evaluated, tested and identified consistent with
National Instrument 52-109 (Bill 198). The effectiveness of these internal controls is evaluated and findings are reported to management and the Audit and Finance Committee of the Hydro One Board of Directors, as required. 

The Consolidated Financial Statements have been examined by KPMG LLP, independent external auditors appointed by the Hydro One Board of Directors. The
external auditors’ responsibility is to express their opinion on whether the Consolidated Financial Statements are fairly presented in accordance with United States Generally Accepted Accounting Principles. The Independent Auditors’ Report
outlines the scope of their examination and their opinion. 
 The Hydro One Board of Directors, through its Audit and Finance Committee, is
responsible for ensuring that management fulfills its responsibilities for financial reporting and internal controls. The Audit and Finance Committee of Hydro One met periodically with management, the internal auditors and the external auditors to
satisfy itself that each group had properly discharged its respective responsibility and to review the Consolidated Financial Statements before recommending approval by the Board of Directors. The external auditors had direct and full access to the
Audit and Finance Committee, with and without the presence of management, to discuss their audit and their findings as to the integrity of the financial reporting and the effectiveness of the system of internal controls. 

The Company’s President and Chief Executive Officer and Executive Vice-President and Chief Financial Officer have certified Hydro One’s annual
Consolidated Financial Statements and annual MD&A filed under provincial securities legislation, related disclosure controls and procedures and the design and effectiveness of related internal controls over financial reporting pursuant to
National Instrument 52-109. 
 On behalf of Hydro One Inc.’s management: 

 

			
	

	  	

		
	Carmine Marcello	  	Sandy Struthers
	President and Chief Executive Officer	  	Chief Administration Officer and Chief Financial Officer

  

					
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 HYDRO ONE INC. 
 INDEPENDENT AUDITORS’ REPORT 
 To the Shareholder of Hydro
One Inc. 
 We have audited the accompanying consolidated financial statements of Hydro One Inc., which comprise the consolidated balance sheets
as at December 31, 2012 and December 31, 2011, the consolidated statements of operations and comprehensive income, changes in shareholder’s equity and cash flows for the years ended December 31, 2012 and December 31, 2011,
and notes, comprising a summary of significant accounting policies and other explanatory information. 
 Management’s Responsibility for
the Consolidated Financial Statements 
 Management is responsible for the preparation and fair presentation of these consolidated financial
statements in accordance with United States Generally Accepted Accounting Principles, and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material
misstatement, whether due to fraud or error. 
 Auditors’ Responsibility 
 Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards. Those
standards require that we comply with ethical requirements and plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement. 

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The
procedures selected depend on our judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, we consider internal control
relevant to the entity’s preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the
effectiveness of the entity’s internal control. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation
of the consolidated financial statements. 
 We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to
provide a basis for our audit opinion. 
 Opinion 
 In our opinion, the consolidated financial statements present fairly, in all material respects, the consolidated financial position of Hydro One Inc. as at December 31, 2012 and December 31,
2011, and its consolidated statements of operations and comprehensive income, changes in shareholder’s equity and cash flows for the years ended December 31, 2012 and December 31, 2011 in accordance with United States Generally
Accepted Accounting Principles. 
  
 

 
 Chartered Accountants, Licensed Public Accountants 
 Toronto, Canada 
 February 14, 2013 

  

					
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 HYDRO ONE INC. 
 CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME 
  

									
	 Year ended December 31 (millions of dollars, except per share amounts)
	  	2012	 	  	2011	 
	 	  	 	 	  	(Note 24)	 
	 Revenues
	  				  			
	 Distribution (includes $155 related party revenues; 2011 – $155) (Note 19)
	  	 	4,184	  	  	 	4,019	  
	 Transmission (includes $1,482 related party revenues; 2011 – $1,372) (Note 19)
	  	 	1,482	  	  	 	1,389	  
	 Other
	  	 	62	  	  	 	63	  
		  	  
	  
	 	  	  
	  
	 
		  	 	5,728	  	  	 	5,471	  
		  	  
	  
	 	  	  
	  
	 
	 Costs
	  				  			
	 Purchased power (includes $2,409 related party costs; 2011 – $2,427) (Note 19)
	  	 	2,774	  	  	 	2,628	  
	 Operation, maintenance and administration (Note 19)
	  	 	1,071	  	  	 	1,092	  
	 Depreciation and amortization (Note 4)
	  	 	659	  	  	 	616	  
		  	  
	  
	 	  	  
	  
	 
		  	 	4,504	  	  	 	4,336	  
		  	  
	  
	 	  	  
	  
	 
	 Income before financing charges and provision for payments in lieu of corporate income taxes
	  	 	1,224	  	  	 	1,135	  
	 Financing charges (Note 5)
	  	 	358	  	  	 	344	  
		  	  
	  
	 	  	  
	  
	 
	 Income before provision for payments in lieu of corporate income taxes
	  	 	866	  	  	 	791	  
	 Provision for payments in lieu of corporate income taxes (Notes 6, 19)
	  	 	121	  	  	 	150	  
		  	  
	  
	 	  	  
	  
	 
	 Net income
	  	 	745	  	  	 	641	  
	 Other comprehensive income
	  	 	1	  	  	 	—  	  
		  	  
	  
	 	  	  
	  
	 
	 Comprehensive income
	  	 	746	  	  	 	641	  
		  	  
	  
	 	  	  
	  
	 
	 Basic and fully diluted earnings per common share (dollars) (Note 17)
	  	 	7,280	  	  	 	6,228	  
		  	  
	  
	 	  	  
	  
	 
	 Dividends per common share declared (dollars) (Note 18)
	  	 	3,523	  	  	 	1,500	  
		  	  
	  
	 	  	  
	  
	 

 See accompanying notes to Consolidated Financial Statements. 

  

					
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 HYDRO ONE INC. 
 CONSOLIDATED BALANCE SHEETS 
  

									
	 December 31 (millions of dollars)
	  	2012	 	  	2011	 
	 	  	 	 	  	(Note 24)	 
	 Assets
	  				  			
	 Current assets:
	  				  			
	 Short-term investments (Note 12)
	  	 	195	  	  	 	228	  
	 Accounts receivable (net of allowance for doubtful accounts – $23; 2011 – $18) (Note 7)
	  	 	845	  	  	 	805	  
	 Due from related parties (Note 19)
	  	 	154	  	  	 	156	  
	 Regulatory assets (Note 10)
	  	 	29	  	  	 	24	  
	 Materials and supplies
	  	 	23	  	  	 	25	  
	 Deferred income tax assets (Note 6)
	  	 	18	  	  	 	19	  
	 Derivative instruments (Note 12)
	  	 	—  	  	  	 	1	  
	 Other
	  	 	22	  	  	 	19	  
		  	  
	  
	 	  	  
	  
	 
		  	 	1,286	  	  	 	1,277	  
		  	  
	  
	 	  	  
	  
	 
	 Property, plant and equipment (Note 8):
	  				  			
	 Property, plant and equipment in service
	  	 	22,650	  	  	 	21,008	  
	 Less: accumulated depreciation
	  	 	8,145	  	  	 	7,679	  
		  	  
	  
	 	  	  
	  
	 
		  	 	14,505	  	  	 	13,329	  
	 Construction in progress
	  	 	1,055	  	  	 	1,436	  
	 Future use land, components and spares
	  	 	147	  	  	 	138	  
		  	  
	  
	 	  	  
	  
	 
		  	 	15,707	  	  	 	14,903	  
		  	  
	  
	 	  	  
	  
	 
	 Other long-term assets:
	  				  			
	 Regulatory assets (Note 10)
	  	 	3,098	  	  	 	1,966	  
	 Long-term investment (Notes 11, 12, 19)
	  	 	251	  	  	 	250	  
	 Intangible assets (net of accumulated amortization – $305; 2011 – $257) (Note 9)
	  	 	267	  	  	 	224	  
	 Goodwill
	  	 	133	  	  	 	133	  
	 Deferred debt costs
	  	 	34	  	  	 	32	  
	 Derivative instruments (Note 12)
	  	 	19	  	  	 	33	  
	 Deferred income tax assets (Note 6)
	  	 	14	  	  	 	17	  
	 Other
	  	 	2	  	  	 	1	  
		  	  
	  
	 	  	  
	  
	 
		  	 	3,818	  	  	 	2,656	  
		  	  
	  
	 	  	  
	  
	 
	 Total assets
	  	 	20,811	  	  	 	18,836	  
		  	  
	  
	 	  	  
	  
	 

 See accompanying notes to Consolidated Financial Statements. 

  

					
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 HYDRO ONE INC. 
 CONSOLIDATED BALANCE SHEETS (continued) 
  

									
	 December 31 (millions of dollars, except number of shares)
	  	2012	 	 	2011	 
	 	  	 	 	 	(Note 24)	 
	 Liabilities
	  				 			
	 Current liabilities:
	  				 			
	 Bank indebtedness (Note 12)
	  	 	42	  	 	 	39	  
	 Accounts payable
	  	 	140	  	 	 	154	  
	 Accrued liabilities (Notes 6, 14, 15)
	  	 	582	  	 	 	575	  
	 Due to related parties (Note 19)
	  	 	257	  	 	 	342	  
	 Accrued interest
	  	 	95	  	 	 	85	  
	 Regulatory liabilities (Note 10)
	  	 	40	  	 	 	25	  
	 Long-term debt payable within one year (Notes 11, 12)
	  	 	600	  	 	 	600	  
		  	  
	  
	 	 	  
	  
	 
		  	 	1,756	  	 	 	1,820	  
		  	  
	  
	 	 	  
	  
	 
	 Long-term debt (includes $769 measured at fair value;
2011 – $783) (Notes 11, 12)
	  	 	7,879	  	 	 	7,408	  
		  	  
	  
	 	 	  
	  
	 
	 Other long-term liabilities:
	  				 			
	 Post-retirement and post-employment benefit liability (Note 14)
	  	 	1,416	  	 	 	1,163	  
	 Deferred income tax liabilities (Note 6)
	  	 	944	  	 	 	758	  
	 Pension benefit liability (Note 14)
	  	 	1,515	  	 	 	779	  
	 Environmental liabilities (Note 15)
	  	 	227	  	 	 	235	  
	 Regulatory liabilities (Note 10)
	  	 	181	  	 	 	169	  
	 Net unamortized debt premiums
	  	 	23	  	 	 	23	  
	 Asset retirement obligations (Note 16)
	  	 	15	  	 	 	15	  
	 Long-term accounts payable and other liabilities
	  	 	25	  	 	 	12	  
		  	  
	  
	 	 	  
	  
	 
		  	 	4,346	  	 	 	3,154	  
		  	  
	  
	 	 	  
	  
	 
	 Total liabilities
	  	 	13,981	  	 	 	12,382	  
		  	  
	  
	 	 	  
	  
	 
	 Contingencies and commitments (Notes 21, 22)
	  				 			
	 Preferred shares (authorized: unlimited; issued: 12,920,000) (Notes 17, 18)
	  	 	323	  	 	 	323	  
	 Shareholder’s Equity
	  				 			
	 Common shares (authorized: unlimited; issued: 100,000) (Notes 17, 18)
	  	 	3,314	  	 	 	3,314	  
	 Retained earnings
	  	 	3,202	  	 	 	2,827	  
	 Accumulated other comprehensive loss
	  	 	(9	) 	 	 	(10	) 
		  	  
	  
	 	 	  
	  
	 
	 Total shareholder’s equity
	  	 	6,507	  	 	 	6,131	  
		  	  
	  
	 	 	  
	  
	 
	 Total liabilities, preferred shares and shareholder’s equity
	  	 	20,811	  	 	 	18,836	  
		  	  
	  
	 	 	  
	  
	 

 See accompanying notes to Consolidated Financial Statements. 

On behalf of the Board of Directors: 
  

							
		 	

	  	

	  	
		 	James Arnett	  	Michael J. Mueller	  	
		 	Chair	  	Chair, Audit and Finance Committee	  	

  

					
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 HYDRO ONE INC. 
 CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDER’S EQUITY 
  

																	
	 Year ended December 31, 2012

(millions of dollars)
	  	Common Shares	 	  	Retained
Earnings	 	 	Accumulated Other
Comprehensive
Loss	 	 	Total
Shareholder’s
Equity	 
	 January 1, 2012
	  	 	3,314	  	  	 	2,827	  	 	 	(10	) 	 	 	6,131	  
	 Net income
	  	 	—  	  	  	 	745	  	 	 	—  	  	 	 	745	  
	 Other comprehensive income
	  	 	—  	  	  	 	—  	  	 	 	1	  	 	 	1	  
	 Dividends on preferred shares
	  	 	—  	  	  	 	(18	) 	 	 	—  	  	 	 	(18	) 
	 Dividends on common shares
	  	 	—  	  	  	 	(352	) 	 	 	—  	  	 	 	(352	) 
		  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 December 31, 2012
	  	 	3,314	  	  	 	3,202	  	 	 	(9	) 	 	 	6,507	  
		  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	 	  
	  
	 
					
	 Year ended December 31, 2011
 (millions of dollars)
 (Note
24)
	  	Common Shares	 	  	Retained
Earnings	 	 	Accumulated Other
Comprehensive
Loss	 	 	Total
Shareholder’s
Equity	 
	 January 1, 2011
	  	 	3,314	  	  	 	2,354	  	 	 	(10	) 	 	 	5,658	  
	 Net income
	  	 	—  	  	  	 	641	  	 	 	—  	  	 	 	641	  
	 Other comprehensive income
	  	 	—  	  	  	 	—  	  	 	 	—  	  	 	 	—  	  
	 Dividends on preferred shares
	  	 	—  	  	  	 	(18	) 	 	 	—  	  	 	 	(18	) 
	 Dividends on common shares
	  	 	—  	  	  	 	(150	) 	 	 	—  	  	 	 	(150	) 
		  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 December 31, 2011
	  	 	3,314	  	  	 	2,827	  	 	 	(10	) 	 	 	6,131	  
		  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	 	  
	  
	 

 See accompanying notes to Consolidated Financial Statements. 

  

					
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 HYDRO ONE INC. 
 CONSOLIDATED STATEMENTS OF CASH FLOWS 
  

									
	 Year ended December 31 (millions of dollars)
	  	2012	 	 	2011	 
	 	  	 	 	 	(Note 24)	 
	 Operating activities
	  				 			
	 Net income
	  	 	745	  	 	 	641	  
	 Environmental expenditures
	  	 	(18	) 	 	 	(16	) 
	 Adjustments for non-cash items:
	  				 			
	 Depreciation and amortization (excluding removal costs)
	  	 	589	  	 	 	550	  
	 Regulatory assets and liabilities
	  	 	12	  	 	 	47	  
	 Deferred income taxes
	  	 	(9	) 	 	 	(12	) 
	 Asset retirement obligations
	  	 	—  	  	 	 	4	  
	 Other
	  	 	6	  	 	 	9	  
	 Changes in non-cash balances related to operations (Note 20)
	  	 	(40	) 	 	 	184	  
		  	  
	  
	 	 	  
	  
	 
	 Net cash from operating activities
	  	 	1,285	  	 	 	1,407	  
		  	  
	  
	 	 	  
	  
	 
	 Financing activities
	  				 			
	 Long-term debt issued
	  	 	1,085	  	 	 	700	  
	 Long-term debt retired
	  	 	(600	) 	 	 	(500	) 
	 Dividends paid
	  	 	(370	) 	 	 	(168	) 
	 Change in bank indebtedness
	  	 	3	  	 	 	39	  
	 Other
	  	 	(1	) 	 	 	(4	) 
		  	  
	  
	 	 	  
	  
	 
	 Net cash from (used in) financing activities
	  	 	117	  	 	 	67	  
		  	  
	  
	 	 	  
	  
	 
	 Investing activities
	  				 			
	 Capital expenditures
	  				 			
	 Property, plant and equipment
	  	 	(1,363	) 	 	 	(1,371	) 
	 Intangible assets
	  	 	(91	) 	 	 	(76	) 
	 Other
	  	 	19	  	 	 	29	  
		  	  
	  
	 	 	  
	  
	 
	 Net cash used in investing activities
	  	 	(1,435	) 	 	 	(1,418	) 
		  	  
	  
	 	 	  
	  
	 
	 Net change in cash and cash equivalents
	  	 	(33	) 	 	 	56	  
	 Cash and cash equivalents, beginning of year
	  	 	228	  	 	 	172	  
		  	  
	  
	 	 	  
	  
	 
	 Cash and cash equivalents, end of year
	  	 	195	  	 	 	228	  
		  	  
	  
	 	 	  
	  
	 

 See accompanying notes to Consolidated Financial Statements. 

  

					
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 HYDRO ONE INC. 
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
 1. DESCRIPTION OF
THE BUSINESS 
 Hydro One Inc. (Hydro One or the Company) was incorporated on December 1, 1998, under the Business Corporations Act
(Ontario) and is wholly owned by the Province of Ontario (Province). The principal businesses of Hydro One are the transmission and distribution of electricity to customers within Ontario. These businesses are regulated by the Ontario Energy
Board (OEB). 
 2. SIGNIFICANT ACCOUNTING POLICIES 
 Basis of Consolidation 
 These Consolidated Financial Statements include the accounts
of the Company and its wholly-owned subsidiaries: Hydro One Networks Inc. (Hydro One Networks), Hydro One Remote Communities Inc. (Hydro One Remote Communities), Hydro One Brampton Networks Inc. (Hydro One Brampton Networks), Hydro One Telecom Inc.
(Hydro One Telecom), Hydro One Lake Erie Link Management Inc., and Hydro One Lake Erie Link Company Inc. 
 Intercompany transactions and
balances have been eliminated. 
 Basis of Accounting 
 These Consolidated Financial Statements are prepared and presented in accordance with United States (US) Generally Accepted Accounting Principles (GAAP) and in Canadian dollars. These statements are to be
read in conjunction with Note 24 – Transition to US GAAP, which discloses information on the Canadian GAAP per Part V of the CICA Handbook (Canadian GAAP) to US GAAP transition and related reconciliations from Canadian GAAP to US
GAAP. The results of operations for the year ended December 31, 2011 and the Consolidated Balance Sheet at December 31, 2011 have been restated under US GAAP for comparative purposes. The Company’s Consolidated Financial
Statements were previously prepared using Canadian GAAP. 
 Hydro One performed an evaluation of subsequent events for the accompanying
Consolidated Financial Statements and notes through to February 14, 2013, the date these Consolidated Financial Statements were issued, to determine whether the circumstances warranted recognition and disclosure of any events or transactions.
No such events or transactions were identified. 
 Use of Management Estimates 

The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities
at the date of the financial statements and the reported amounts of revenues, expenses, gains and losses during the reporting periods. Management evaluates these estimates on an ongoing basis based upon: historical experience; current conditions;
and assumptions believed to be reasonable at the time the assumptions are made with any adjustments being recognized in results of operations in the period they arise. Significant estimates relate to regulatory assets and regulatory liabilities,
environmental liabilities, pension benefits, post-retirement and post-employment benefits, asset retirement obligations (AROs), goodwill and asset impairments, contingencies, unbilled revenues, allowance for doubtful accounts, derivative
instruments, and deferred income tax assets and liabilities. Actual results may differ significantly from these estimates, which may be impacted by future decisions made by the OEB or the Province. 

Rate Setting 
 The Company’s
consolidated Distribution Business includes the separately regulated distribution businesses of Hydro One Networks, Hydro One Brampton Networks, and Hydro One Remote Communities. The OEB has approved US GAAP as the basis for rate setting for
Hydro One Networks’ Transmission and Distribution businesses and by Hydro One Remote Communities all effective January 1, 2012. Hydro One Brampton Networks’ rates are currently set under Canadian GAAP, and are expected to be set under
the OEB’s modified International Financial Reporting Standards (IFRS) framework commencing in 2015, once its current Incentive Regulation Mechanism (IRM) period is complete. 

  

					
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Table of Contents

 HYDRO ONE INC. 
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) 
  

 Transmission 
 In May 2010, Hydro One Networks filed a cost-of-service application for 2011 and 2012 transmission rates in continued support of the Company’s aging critical infrastructure and the supply mix
objectives for generation, including off-coal initiatives and initiation of investments in support of the Green Energy Act (GEA). This application sought the approval of revenue requirements of approximately $1,446 million for 2011 and $1,547
million for 2012. 
 In December 2010, the OEB approved revenue requirements of $1,346 million for 2011 and $1,658 million for 2012. The
approved 2012 revenue requirement was higher than that applied for, reflecting OEB direction to Hydro One to adopt a cost capitalization policy based on modified IFRS. This adjustment was subsequently reversed, when the OEB approved the use of
US GAAP for transmission rate-setting purposes beginning January 1, 2012. Consequently, the OEB approved a revenue requirement of $1,418 million for 2012, along with new 2012 uniform transmission rates, with an effective date of
January 1, 2012. 
 Distribution 
 In 2009, Hydro One Networks filed a cost-of-service application with the OEB for 2011 distribution rates, seeking approval for a revenue requirement of approximately $1,264 million. The application
reflected the Company’s plan to invest in its network assets to meet objectives regarding public and employee safety, regulatory and legislative compliance, maintenance of system security and reliability of system growth requirements, and to
make investments required by the GEA. In April 2010, the OEB approved a revenue requirement of $1,236 million for 2011. The OEB also approved certain distribution regulatory account balances sought by Hydro One Networks in its application, including
retail settlement variance accounts, retail cost variance accounts and smart meters. In November 2010, the OEB issued its cost-of-capital parameter updates for rates effective January 1, 2011. A lowering of the return on equity produced a
revised revenue requirement of $1,218 million. The approved 2011 revenue requirement resulted in an average distribution rate increase of approximately 8.7% for 2011. Hydro One Networks elected to retain the same distribution rates for 2012 as
approved by the OEB for the 2011 rate year. 
 In 2010, Hydro One Brampton Networks filed a cost-of-service application with the OEB for 2011
distribution rates, seeking approval for a revenue requirement of approximately $63 million. In 2011, the OEB approved a revenue requirement of approximately $60 million for 2011, with an effective date of January 1, 2011. The reduced approved
revenue requirement included a reduction to approved operation, maintenance and administration costs. In September 2011, Hydro One Brampton Networks filed an IRM application with the OEB for 2012 distribution rates, with an effective date of
January 1, 2012. In January 2012, the OEB released a decision that resulted in a reduction in distribution rates of approximately 13.2% for 2012. These rate reductions were primarily due to OEB-approved adjustments to depreciation rates.

 In October 2010, Hydro One Remote Communities filed an IRM application with the OEB for 2011 rates. In March 2011, the OEB approved an
increase of approximately 0.4% to basic rates for the distribution and generation of electricity, with an effective date of May 1, 2011. In November 2011, Hydro One Remote Communities filed an IRM application with the OEB for 2012 rates. In
March 2012, the OEB approved an increase of approximately 1.1% to basic rates for the distribution and generation of electricity, with an effective date of May 1, 2012. 
 Regulatory Accounting 
 The OEB has the general power to include or exclude revenues,
costs, gains or losses in the rates of a specific period, resulting in a change in the timing of accounting recognition from that which would have applied in an unregulated company. Such change in timing involves the application of rate-regulated
accounting, giving rise to the recognition of regulatory assets and liabilities. The Company’s regulatory assets represent certain amounts receivable from future customers and costs that have been deferred for accounting purposes because it is
probable that they will be recovered in future rates. In addition, the Company has recorded regulatory liabilities that generally represent amounts that are refundable to future electricity customers. The Company continually assesses the likelihood
of recovery of each of its regulatory assets and continues to believe that it is probable that the OEB will factor its regulatory assets and liabilities into the setting of future rates. If, at some future date, the Company judges that it is no
longer probable that the OEB will include a regulatory asset or liability in setting future rates, the appropriate carrying amount will be reflected in results of operations in the period that the assessment is made. 

  

					
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 HYDRO ONE INC. 
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) 
  

 Cash and Cash Equivalents 
 Cash and cash equivalents include cash and short-term investments. Short-term investments have an original maturity of three months or less. 
 Revenue Recognition 
 Transmission revenues are collected through OEB-approved rates,
which are based on an approved revenue requirement that includes a rate of return. Such revenue is recognized as electricity is transmitted and delivered to customers. 
 Distribution revenues are recognized on an accrual basis and include billed and unbilled revenues. Distribution revenues attributable to the delivery of electricity are based on OEB-approved distribution
rates and are recognized as electricity is delivered to customers. The Company estimates monthly revenue for a period based on wholesale electricity purchases because customer meters are not generally read at the end of each month. At the end of
each month, the electricity delivered to customers, but not billed, is estimated and revenue is recognized. The unbilled revenue estimate is affected by energy demand, weather, line losses and changes in the composition of customer classes.

 Distribution revenue also includes an amount relating to rate protection for rural, residential and remote customers, which is received from
the Independent Electricity System Operator (IESO) based on a standardized customer rate that is approved by the OEB. Current legislation provides rate protection for prescribed classes of rural, residential and remote consumers by reducing the
electricity rates that would otherwise apply. 
 Revenues also include amounts related to sales of other services and equipment. Such revenue is
recognized as services are rendered or as equipment is delivered. 
 Revenues are recorded net of indirect taxes. 

Accounts Receivable and Allowance for Doubtful Accounts 
 Accounts receivable are recorded at the invoiced amount or net realizable value, if unbilled. Overdue amounts related to regulated billings bear interest at OEB-approved rates. The allowance for doubtful
accounts reflects the Company’s best estimate of losses on accounts receivable balances. The allowance is based on accounts receivable aging, historical experience and other currently available information. The Company estimates the allowance
for doubtful accounts on customer receivables by applying internally developed loss rates to the outstanding receivable balances by risk segment. Risk segments represent groups of customers with similar credit quality indicators and are computed
based on various attributes, including number of days receivables are past due, delinquency of balances and payment history. Loss rates applied to the accounts receivable balances are based on historical average write-offs as a percentage of
accounts receivable in each risk segment. An account is considered delinquent if the amount billed is not received within 120 days of the invoiced date. Accounts receivable are written off against the allowance when they are deemed uncollectible.
The existing allowance for uncollectible accounts will continue to be affected by changes in volume, prices and economic conditions. 

Corporate Income Taxes 
 Under the
Electricity Act, 1998, Hydro One is required to make payments in lieu of corporate income taxes (PILs) to the Ontario Electricity Financial Corporation (OEFC). These payments are calculated in accordance with the rules for computing income
and other relevant amounts contained in the Income Tax Act (Canada) and the Taxation Act, 2007 (Ontario) as modified by the Electricity Act, 1998 and related regulations. 
 Current and deferred income taxes are computed based on the tax rates and tax laws enacted at the balance sheet date. Tax benefits associated with income tax positions taken, or expected to be taken, in a
tax return are recorded only when the “more-likely-than-not” recognition threshold is satisfied and are measured at the largest amount of benefit that has a greater than 50% likelihood of being realized upon settlement. Management
evaluates each position based solely on the technical merits and facts and circumstances of the position, assuming the position will be examined by a taxing authority having full knowledge of all relevant information. Significant management
judgement is required to determine recognition thresholds and the related amount of tax benefits to be recognized in the Consolidated Financial Statements. Management re-evaluates tax positions each period in which new information about recognition
or measurement becomes available. 

  

					
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 HYDRO ONE INC. 
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) 
  

 Current Income Taxes 
 The provision for current taxes and the assets and liabilities recognized for the current and prior periods are measured at the amounts receivable from, or payable to, the OEFC. 

Deferred Income Taxes 
 Deferred income
taxes are provided for using the liability method. Deferred income taxes are recognized based on the estimated future tax consequences attributable to temporary differences between the carrying amount of assets and liabilities in the Consolidated
Financial Statements and their corresponding tax bases. 
 Deferred income tax liabilities are generally recognized on all taxable temporary
differences. Deferred tax assets are recognized to the extent that it is more-likely-than-not that these assets will be realized from taxable income available against which deductible temporary differences can be utilized. 

Deferred income taxes are calculated at the tax rates that are expected to apply in the period when the liability is settled or the asset is realized,
based on the tax rates and tax laws that have been enacted at the balance sheet date. Deferred income taxes that are not included in the rate-setting process are charged or credited to the Consolidated Statements of Operations and Comprehensive
Income. 
 If management determines that it is more-likely-than-not that some or all of a deferred income tax asset will not be realized, a
valuation allowance is recorded against the tax asset to report the net balance at the amount expected to be realized. Previously unrecognized deferred income tax assets are reassessed at each balance sheet date and are recognized to the extent that
it has become more-likely-than-not that the tax benefit will be realized. 
 The Company records regulatory assets and liabilities associated
with deferred income taxes that will be included in the rate-setting process. 
 The Company uses the flow-through method to account for
investment tax credits (ITCs) earned on eligible scientific research and experimental development expenditures, and apprenticeship job creation. Under this method, only the ITCs are recognized as a reduction to income tax expense. 

Materials and Supplies 
 Materials
and supplies represent consumables, small spare parts and construction materials held for internal construction and maintenance of property, plant and equipment. These assets are carried at average cost less any impairments recorded. 

Property, Plant and Equipment 

Property, plant and equipment is recorded at original cost, net of customer contributions received in aid of construction and any accumulated impairment
losses. The cost of additions, including betterments and replacement asset components, is included on the Consolidated Balance Sheets as property, plant and equipment. 
 The original cost of property, plant and equipment includes direct materials, direct labour (including employee benefits), contracted services, attributable capitalized financing costs, asset retirement
costs, and direct and indirect overheads that are related to the capital project or program. Indirect overheads include a portion of corporate costs such as finance, treasury, human resources, information technology and executive costs. Overhead
costs, including corporate functions and field services costs, are capitalized on a fully allocated basis, consistent with an OEB-approved methodology. 
 Property, plant and equipment in service consists of transmission, distribution, communication, administration and service assets and land easements. Property, plant and equipment also includes future use
assets, such as land, major components and spare parts, and capitalized project development costs associated with deferred capital projects. 

  

					
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 HYDRO ONE INC. 
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) 
  

 Transmission 
 Transmission assets include assets used for the transmission of high-voltage electricity, such as transmission lines, support structures, foundations, insulators, connecting hardware and grounding
systems, and assets used to step up the voltage of electricity from generating stations for transmission and to step down voltages for distribution, including transformers, circuit breakers and switches. 

Distribution 
 Distribution assets
include assets related to the distribution of low-voltage electricity, including lines, poles, switches, transformers, protective devices and metering systems. 
 Communication 
 Communication assets include the fibre-optic and microwave radio system,
optical ground wire, towers, telephone equipment and associated buildings. 
 Administration and Service 

Administration and service assets include administrative buildings, personal computers, transport and work equipment, tools and other minor assets.

 Easements 
 Easements include
statutory rights of use for transmission corridors and abutting lands granted under the Reliable Energy and Consumer Protection Act, 2002, as well as other land access rights. 
 Intangible Assets 
 Intangible assets separately acquired or internally developed are
measured on initial recognition at cost, which comprises purchased software, direct labour (including employee benefits), consulting, engineering, overheads and attributable capitalized financing charges. Following initial recognition, intangible
assets are carried at cost, net of any accumulated amortization and accumulated impairment losses. The Company’s intangible assets primarily represent major administrative computer applications. 

Capitalized Financing Costs 

Capitalized financing costs represent interest costs attributable to the construction of property, plant and equipment or development of intangible
assets. The financing cost of attributable borrowed funds is capitalized as part of the acquisition cost of such assets. The capitalized portion of financing costs is a reduction to financing charges recognized in the Consolidated Statements of
Operations and Comprehensive Income. Capitalized financing costs are calculated using the Company’s weighted average effective cost of debt. 
 Construction and Development in Progress 
 Construction and development in progress
consists of the capitalized cost of constructed assets that are not yet complete and which have not yet been placed in service. 

Depreciation and Amortization 

The cost of property, plant and equipment and intangible assets is depreciated or amortized on a straight-line basis based on the estimated remaining
service life of each asset category, except for transport and work equipment, which is depreciated on a declining balance basis. 
 The Company
periodically initiates an external independent review of its property, plant and equipment and intangible asset depreciation and amortization rates, as required by the OEB. Any changes arising from OEB approval of such a review are implemented on a
remaining service life basis, consistent with their inclusion in electricity rates. The last review resulted in changes to rates effective January 1, 2007. 

  

					
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 HYDRO ONE INC. 
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) 
  

 A summary of average service lives and depreciation and amortization rates for the various classes of
assets is included below: 
  

													
	 	  	Average	 	  	Rate (%)	 
	 	  	Service Life	 	  	Range	 	 	Average	 
	 Transmission
	  	 	56 years	  	  	 	1% - 3	% 	 	 	2	% 
	 Distribution
	  	 	42 years	  	  	 	1% - 13	% 	 	 	2	% 
	 Communication
	  	 	19 years	  	  	 	1% - 13	% 	 	 	5	% 
	 Administration and service
	  	 	15 years	  	  	 	1% -20	% 	 	 	8	% 

 The cost of intangible assets is included primarily within the administration and service classification above.
Amortization rates for computer applications software and other intangible assets range from 9% to 11%. 
 In accordance with group depreciation
practices, the original cost of property, plant and equipment, or major components thereof, and intangible assets that are normally retired, is charged to accumulated depreciation, with no gain or loss being reflected in results of operations. Where
a disposition of property, plant and equipment occurs through sale, a gain or loss is calculated based on proceeds and such gain or loss is included in depreciation expense. Depreciation expense also includes the costs incurred to remove property,
plant and equipment where no ARO has been recorded. 
 Goodwill 
 Goodwill represents the cost of acquired local distribution companies that is in excess of the fair value of the net identifiable assets acquired at the acquisition date. Goodwill is not included in rate
base. 
 Goodwill is evaluated for impairment on an annual basis, or more frequently if circumstances require. Per Accounting Standards Update
(ASU) 2011-08, Intangibles – Goodwill and Other (Topic 350), Testing Goodwill for Impairment, issued by the Financial Accounting Standards Board (FASB) in September 2011, the Company performs a qualitative assessment to determine whether it is
more-likely-than-not that the fair value of the applicable reporting unit is less than its carrying amount. If the Company determines, as a result of its qualitative assessment, that it is not more-likely-than-not that the fair value of the
applicable reporting unit is less than its carrying amount, no further testing is required. If the Company determines, as a result of its qualitative assessment, that it is more-likely-than-not that the fair value of the applicable reporting unit is
less than its carrying amount, a goodwill impairment assessment is performed using a two-step, fair value-based test. The first step compares the fair value of the applicable reporting unit to its carrying amount, including goodwill. If the carrying
amount of the applicable reporting unit exceeds its fair value, a second step is performed. The second step requires an allocation of fair value to the individual assets and liabilities using purchase price allocation in order to determine the
implied fair value of goodwill. If the implied fair value of goodwill is less than the carrying amount, an impairment loss is recorded as a reduction to goodwill and as a charge to results of operations. 

For the year ended December 31, 2012, based on the qualitative assessment performed, the Company has determined that it is not more-likely-than-not
that the fair value of each applicable reporting unit assessed is less than its carrying amount. As a result, no further testing was performed, and the Company has concluded that goodwill was not impaired at December 31, 2012. 

Long-Lived Asset Impairment 
 When
circumstances indicate the carrying value of long-lived assets may not be recoverable, the Company evaluates whether the carrying value of such assets, excluding goodwill, has been impaired. For such long-lived assets, impairment exists when the
carrying value exceeds the sum of the future estimated undiscounted cash flows expected to result from the use and eventual disposition of the asset. When alternative courses of action to recover the carrying amount of a long-lived asset are under
consideration, a probability-weighted approach is used to develop estimates of future undiscounted cash flows. If the carrying value of the long-lived asset is not recoverable based on the estimated future undiscounted cash flows, an impairment loss
is recorded, measured as the excess of the carrying value of the asset over its fair value. As a result, the asset’s carrying value is adjusted to its estimated fair value. 

  

					
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 HYDRO ONE INC. 
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) 
  

 Within its regulated business, the carrying costs of most of Hydro One’s long-lived assets are
included in rate base where they earn an OEB-approved rate of return. Asset carrying values and the related return are recovered through approved rates. As a result, such assets are only tested for impairment in the event that the OEB disallows
recovery, in whole or in part, or if such a disallowance is judged to be probable. 
 Hydro One regularly monitors the assets of its unregulated
Hydro One Telecom subsidiary for indications of impairment. Management assesses the fair value of such long-lived assets using commonly accepted techniques, and may use more than one. Techniques used to determine fair value include, but are not
limited to, the use of recent third party comparable sales for reference and internally developed discounted cash flow analysis. Significant changes in market conditions, changes to the condition of an asset, or a change in management’s intent
to utilize the asset are generally viewed by management as triggering events to reassess the cash flows related to these long-lived assets. As at December 31, 2012, no asset impairment had been recorded for assets within either the
Company’s regulated or unregulated businesses. 
 Costs of Arranging Debt Financing 

For financial liabilities classified as other than held-for-trading, the Company defers the external transaction costs related to obtaining debt financing
and presents such amounts as deferred debt costs on the Consolidated Balance Sheets. Deferred debt costs are amortized over the contractual life of the related debt on an effective-interest basis and the amortization is included within financing
charges in the Consolidated Statements of Operations and Comprehensive Income. Transaction costs for items classified as held-for-trading are expensed immediately. 
 Comprehensive Income 
 Comprehensive income is comprised of net income and other
comprehensive income (OCI). OCI includes the amortization of net unamortized hedging losses on the Company’s discounted cash flow hedges, and the change in fair value on the existing cash flow hedges to the extent that the hedge is effective.
The Company amortizes its unamortized hedging losses on discontinued cash flow hedges to financing charges using the effective-interest method over the term of the allocated hedged debt. Hydro One presents net income and OCI in a single continuous
Consolidated Statement of Operations and Comprehensive Income. 
 Financial Assets and Liabilities 

All financial assets and liabilities are classified into one of the following five categories: held-to-maturity; loans and receivables; held-for-trading;
other liabilities; or available-for-sale. Financial assets and liabilities classified as held-for-trading are measured at fair value. All other financial assets and liabilities are measured at amortized cost, except accounts receivable and amounts
due from related parties, which are measured at the lower of cost or fair value. Accounts receivable and amounts due from related parties are classified as loans and receivables. The Company considers the carrying amounts of accounts receivable and
amounts due from related parties to be reasonable estimates of fair value because of the short time to maturity of these instruments. Provisions for impaired accounts receivable are recognized as adjustments to the allowance for doubtful accounts
and are recognized when there is objective evidence that the Company will not be able to collect amounts according to the original terms. 

Derivative instruments are measured at fair value. Gains and losses from fair valuation are included within financing charges in the period in which they
arise. The Company determines the classification of its financial assets and liabilities at the date of initial recognition. The Company designates certain of its financial assets and liabilities to be held at fair value, when it is consistent with
the Company’s risk management policy disclosed in Note 12 – Fair Value of Financial Instruments and Risk Management. 
 Short-term
investments have an original maturity of three months or less and are generally classified as held-to-maturity. However, the Company may classify pools of short-term investments as held-for-trading where there is no intention to hold a pool of
assets to maturity. Documentation of the short-term investment classification is made on inception. As at December 31, 2012 and 2011, all short-term investments were classified as held-to-maturity. 

  

					
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 HYDRO ONE INC. 
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) 
  

 The Company’s long-term investment in Province of Ontario Floating-Rate Notes, which is held as an
alternate form of liquidity to supplement the bank credit facilities, is classified as held-for-trading and is measured at fair value. 
 All
financial instrument transactions are recorded at trade date. 
 Derivative Instruments and Hedge Accounting 

The Company closely monitors the risks associated with changes in interest rates on its operations and, where appropriate, uses various instruments to
hedge these risks. Certain of these derivative instruments qualify for hedge accounting and are designated as accounting hedges, while others either do not qualify as hedges or have not been designated as hedges (hereinafter referred to as
undesignated contracts) as they are part of economic hedging relationships. 
 The accounting guidance for derivative instruments requires the
recognition of all derivative instruments not identified as meeting the normal purchase and sale exemption as either assets or liabilities recorded at fair value on the Consolidated Balance Sheets. For derivative instruments that qualify for hedge
accounting, the Company may elect to designate such derivative instruments as either cash flow hedges or fair value hedges. The Company offsets fair value amounts recognized in its Consolidated Balance Sheets related to derivative instruments
executed with the same counterparty under the same master netting agreement. 
 For derivative instruments that qualify for hedge accounting and
which are designated as cash flow hedges, the effective portion of any gain or loss, net of tax, is reported as a component of accumulated OCI (AOCI) and is reclassified to results of operations in the same period or periods during which the hedged
transaction affects results of operations. Any gains or losses on the derivative instrument that represent either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in results of operations. For
fair value hedges, changes in fair value of both the derivative instrument and the underlying hedged exposure are recognized in the Consolidated Statement of Operations and Comprehensive Income in the current period. The gain or loss on the
derivative instrument is included in the same line item as the offsetting gain or loss on the hedged item in the Consolidated Statements of Operations and Comprehensive Income. Additionally, the Company enters into derivative agreements that are
economic hedges that either do not qualify for hedge accounting or have not been designated as hedges. The changes in fair value of these undesignated derivative instruments are reflected in results of operations. 

Embedded derivative instruments are separated from their host contracts and carried at fair value on the Consolidated Balance Sheets when: (a) the
economic characteristics and risks of the embedded derivative are not clearly and closely related to the economic characteristics and risks of the host contract; (b) the hybrid instrument is not measured at fair value, with changes in fair
value recognized in results of operations each period; and (c) the embedded derivative itself meets the definition of a derivative. The Company does not engage in derivative trading or speculative activities and had no embedded derivatives at
December 31, 2012. 
 Hydro One periodically develops hedging strategies taking into account risk management objectives. At the inception
of a hedging relationship where the Company has elected to apply hedge accounting, Hydro One formally documents the relationship between the hedged item and the hedging instrument, the related risk management objective, the nature of the specific
risk exposure being hedged, and the method for assessing the effectiveness of the hedging relationship. The Company also assesses, both at the inception of the hedge and on a quarterly basis, whether the hedging instruments are effective in
offsetting changes in fair values or cash flows of the hedged items. 
 Employee Future Benefits 

Employee future benefits provided by Hydro One include pension, post-retirement and post-employment benefits. The costs of the Company’s pension,
post-retirement and post-employment benefit plans are recorded over the periods during which employees render service. 
 The Company recognizes
the funded status of its pension, post-retirement and post-employment plans on its Consolidated Balance Sheets and subsequently recognizes the changes in funded status at the end of each reporting year. Pension, post-retirement and post-employment
plans are considered to be underfunded when the projected benefit obligation exceeds the fair value of the plan assets. Liabilities are recognized in the Consolidated Balance Sheets for any net underfunded projected benefit obligation. The net
underfunded projected benefit obligation may be disclosed as a current liability, long-term 

  

					
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 HYDRO ONE INC. 
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liability, or both. The current portion is the amount by which the actuarial present value of benefits included in the benefit obligation payable in the next 12 months exceeds the fair value of
plan assets. If the fair value of plan assets exceeds the projected benefit obligation of the plan, an asset is recognized equal to the net overfunded projected benefit obligation. The net asset for an overfunded plan is classified as a long-term
asset in the Consolidated Balance Sheets. The post-retirement and post-employment benefit plans are unfunded because there are no related plan assets. 
 Pension benefits 
 Hydro One records a regulatory asset equal to the net underfunded
projected benefit obligation for its pension plan. The regulatory asset for the net underfunded projected benefit obligation for the pension plan, in the absence of regulatory accounting, would be recognized in AOCI. A regulatory asset is recognized
because management considers it to be probable that pension benefit costs will be recovered in the future through the rate-setting process. The pension regulatory assets are remeasured at the end of each year based on the current status of the
pension plan. 
 In accordance with the OEB’s rate orders, pension costs are recorded on a cash basis as employer contributions are paid to
the pension fund in accordance with the Pension Benefits Act (Ontario). Pension costs are also calculated on an accrual basis for financial reporting purposes. Pension costs are actuarially determined using the projected benefit method
prorated on service and are based on assumptions that reflect management’s best estimate of the effect of future events, including future compensation increases. Past service costs from plan amendments and all actuarial gains and losses are
amortized on a straight-line basis over the expected average remaining service period of active employees in the plan, and over the estimated remaining life expectancy of inactive employees in the plan. Pension plan assets, consisting primarily of
listed equity securities as well as corporate and government debt securities, are fair valued at the end of each year. 
 All future pension
benefit costs are attributed to labour and are either charged to results of operations or capitalized as part of the cost of property, plant and equipment and intangible assets. 
 Post-retirement and post-employment benefits 
 Hydro One records a regulatory asset equal to
the incremental net unfunded projected benefit obligation for post-retirement and post-employment plans recorded on transition to US GAAP and at each year end based on annual actuarial reports. The regulatory asset for the incremental net
unfunded projected benefit obligation for post-retirement and post-employment plans, in the absence of regulatory accounting, would be recognized in AOCI. A regulatory asset is recognized because management considers it to be probable that
post-retirement and post-employment benefit costs will be recovered in the future through the rate-setting process. 
 Post-retirement and
post-employment benefits are recorded and included in rates on an accrual basis. Costs are determined by independent actuaries using the projected benefit method prorated on service and based on assumptions that reflect management’s best
estimates. Past service costs from plan amendments are amortized to results of operations based on the expected average remaining service period. 
 For post-retirement benefits, all actuarial gains or losses are deferred using the “corridor” approach. The amount calculated above the “corridor” is amortized to results of operations
on a straight-line basis over the expected average remaining service life of active employees in the plan and over the remaining life expectancy of inactive employees in the plan. The post-retirement benefit obligation is remeasured to its fair
value at each year end based on an annual actuarial report, with an offset to the associated regulatory asset, to the extent of the remeasurement adjustment. 
 For post-employment obligations, the associated regulatory liabilities representing actuarial gains on transition to US GAAP are amortized to results of operations based on the “corridor”
approach. Post transition, the actuarial gains and losses on post-employment obligations that are incurred during the year are recognized immediately to results of operations. The post-employment benefit obligation is remeasured to its fair value at
each year end based on an annual actuarial report, with an offset to associated regulatory asset, to the extent of the remeasurement adjustment. 
 All post-retirement and post-employment future benefit costs are attributed to labour and are either charged to results of operations or capitalized as part of the cost of property, plant and equipment
and intangible assets. 

  

					
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 HYDRO ONE INC. 
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) 
  

 Multiemployer Pension Plan 
 Employees of Hydro One Brampton Networks participate in the Ontario Municipal Employees Retirement System Fund (OMERS), a multiemployer, contributory, defined benefit public sector pension fund. OMERS
provides retirement pension payments based on members’ length of service and salary. Both participating employers and members are required to make plan contributions. The OMERS plan assets are pooled together to provide benefits to all plan
participants and the plan assets are not segregated by member entity. OMERS is registered with the Financial Services Commission of Ontario under Registration #0345983. 
 The OMERS plan is accounted for as a defined contribution plan by Hydro One because it is not practicable to determine the present value of the Company’s obligation, the fair value of plan assets or
the related current service cost applicable to Hydro One Brampton Networks’ employees. Hydro One recognizes its contributions to the OMERS plan as pension expense, with a portion being capitalized. The expensed amount is included in operation,
maintenance and administration costs in the Consolidated Statements of Operations and Comprehensive Income. 
 At December 31, 2011, OMERS
had approximately 419,000 members, with approximately 277 members being current employees of Hydro One Brampton Networks. 
 Loss
Contingencies 
 Hydro One is involved in certain legal and environmental matters that arise in the normal course of business. In the
preparation of its Consolidated Financial Statements, management makes judgements regarding the future outcome of contingent events and records a loss for a contingency based on its best estimate when it is determined that such loss is probable and
the amount of the loss can be reasonably estimated. Where the loss amount is recoverable in future rates, a regulatory asset is also recorded. When a range estimate for the probable loss exists and no amount within the range is a better estimate
than any other amount, the Company records a loss at the minimum amount within the range. 
 Management regularly reviews current information
available to determine whether recorded provisions should be adjusted and whether new provisions are required. Estimating probable losses may require analysis of multiple forecasts and scenarios that often depend on judgements about potential
actions by third parties, such as federal, provincial and local courts or regulators. Contingent liabilities are often resolved over long periods of time. Amounts recorded in the Consolidated Financial Statements may differ from the actual outcome
once the contingency is resolved. Such differences could have a material impact on future results of operations, financial position and cash flows of the Company. 
 Provisions are based upon current estimates and are subject to greater uncertainty where the projection period is lengthy. A significant upward or downward trend in the number of claims filed, the nature
of the alleged injuries, and the average cost of resolving each claim could change the estimated provision, as could any substantial adverse or favourable verdict at trial. A federal or provincial legislative outcome or structured settlement could
also change the estimated liability. Unless otherwise required by GAAP, legal fees are expensed as incurred. 
 Environmental Liabilities

 Environmental liabilities are recorded in respect of past contamination when it is determined that future environmental remediation
expenditures are probable under existing statute or regulation and the amount of the future expenditures can be reasonably estimated. Hydro One records a liability for the estimated future expenditures associated with the contaminated land
assessment and remediation (LAR) and for the phase-out and destruction of polychlorinated biphenyl (PCB)-contaminated mineral oil removed from electrical equipment, based on the present value of these estimated future expenditures. The Company
determines the present value with a discount rate equal to its credit-adjusted risk-free interest rate on financial instruments with comparable maturities to the pattern of future environmental expenditures. As the Company anticipates that the
future expenditures will continue to be recoverable in future rates, an offsetting regulatory asset has been recorded to reflect the future recovery of these environmental expenditures from customers. Hydro One reviews its estimates of future
environmental expenditures annually, or more frequently if there are indications that circumstances have changed. 

  

					
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 HYDRO ONE INC. 
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) 
  

 Asset Retirement Obligations 
 AROs are recorded for legal obligations associated with the future removal and disposal of long-lived assets. Such obligations may result from the acquisition, construction, development and/or normal use
of the asset. Conditional AROs are recorded when there is a legal obligation to perform a future asset retirement activity but where the timing and/or method of settlement are conditional on a future event that may or may not be within the control
of the Company. In such a case, the obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and/or method of settlement. 
 When recording an ARO, the present value of the estimated future expenditures required to complete the asset retirement activity is recorded in the period in which the obligation is incurred, if a
reasonable estimate can be made. In general, the present value of the estimated future expenditures is added to the carrying amount of the associated asset and the resulting asset retirement cost is depreciated over the estimated useful life of the
asset. Where an asset is no longer in service when an ARO is recorded, the asset retirement cost is recorded in results of operations. 
 Some
of the Company’s transmission and distribution assets, particularly those located on unowned easements and rights-of-way, may have AROs, conditional or otherwise. The majority of the Company’s easements and rights-of-way are either of
perpetual duration or are automatically renewed annually. Land rights with finite terms are generally subject to extension or renewal. As the Company expects to use the majority of its facilities in perpetuity, no ARO currently exists for these
assets. If, at some future date, a particular facility is shown not to meet the perpetuity assumption, it will be reviewed to determine whether an estimable ARO exists. In such a case, an ARO would be recorded at that time. 

The Company’s AROs recorded to date relate to estimated future expenditures associated with the removal and disposal of asbestos-containing
materials installed in some of its facilities and with the decommissioning of specific switching stations located on unowned sites. 
 3. NEW
ACCOUNTING PRONOUNCEMENTS 
 Recently Adopted Accounting Pronouncements 

In September 2011, the FASB issued ASU 2011-09, Disclosures About an Employer’s Participation in a Multiemployer Benefit Plan. This ASU requires an
employer to provide quantitative and qualitative disclosures about its participation in significant multiemployer plans that offer pension, post-retirement and post-employment benefits. The ASU’s objective is to enhance the transparency of
disclosures about the significant multiemployer plans in which an employer participates, the level of the employer’s participation in those plans, the financial health of the plans, and the nature of the employer’s commitments to the
plans. An employer that is not able to provide some of the quantitative information required by this ASU must disclose what information has been omitted and why it could not obtain the information. This ASU does not change the recognition and
measurement guidance for an employer’s participation in a multiemployer plan. As this ASU only requires enhanced disclosures, the adoption of this ASU did not have a significant impact on the Company’s Consolidated Financial Statements.

 In September 2011, the FASB issued ASU 2011-08, Intangibles – Goodwill and Other (Topic 350), Testing Goodwill for Impairment. This ASU
is intended to reduce the cost and complexity of the annual goodwill impairment test by providing entities an option to perform a qualitative assessment to determine whether further impairment testing is necessary. An entity has the option to first
assess qualitative factors to determine whether it is necessary to perform the current two-step test. If an entity believes, as a result of its qualitative assessment, that it is more-likely-than-not that the fair value of a reporting unit is less
than its carrying amount, the quantitative impairment test is required. Otherwise, no further testing is required. An entity can choose to perform the qualitative assessment on none, some or all of its reporting units. Moreover, an entity can bypass
the qualitative assessment for any reporting unit in any period and proceed directly to step one of the impairment test, and then resume performing the qualitative assessment in any subsequent period. The adoption of this ASU did not have a
significant impact on the Company’s Consolidated Financial Statements. 
 In June 2011, the FASB issued ASU 2011-05, Presentation of
Comprehensive Income to clarify that an entity has the option to present the total of comprehensive income, the components of net income, and the components of OCI either in a single continuous statement of comprehensive income or in two separate
but consecutive statements. In both choices, an entity is 

  

					
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 HYDRO ONE INC. 
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) 
  

 required to present each component of net income along with total net income, each component of OCI
along with a total for OCI, and a total amount for comprehensive income. This update eliminates the option to present the components of OCI as part of the statement of changes in shareholder’s equity. The amendments in this ASU do not change
the items that must be reported in OCI or when an item of OCI must be reclassified to net income. Hydro One has elected to present OCI and net income in a single continuous Consolidated Statement of Operations and Comprehensive Income. 

In May 2011, the FASB issued ASU 2011-04, Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure
Requirements in U.S. GAAP and IFRSs. This ASU is the result of joint efforts by the FASB and the International Accounting Standards Board to develop common, converged fair value guidance on how to measure fair value and on what disclosures to
provide about fair value measurements. This ASU is largely consistent with existing US GAAP fair value measurement principles under Accounting Standards Codification 820. However, this ASU expands the existing disclosure requirements for fair
value measurements, particularly of Level 3 inputs, and requires categorization by level of the fair value hierarchy for items that are not measured at fair value on the Consolidated Balance Sheets but for which the fair value is required to be
disclosed. Required disclosures have been included in Note 12 – Fair Value of Financial Instruments and Risk Management. As this ASU only requires enhanced disclosures, the adoption of this ASU did not have a significant impact on the
Company’s Consolidated Financial Statements. 
 Recent Accounting Guidance Not Yet Adopted 

In December 2011, the FASB issued ASU 2011-11, Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities. This ASU requires an entity
to disclose both gross and net information about financial instruments and transactions eligible for offset on the Consolidated Balance Sheets as well as financial instruments and transactions executed under a master netting or similar arrangement.
The ASU was issued to enable users of financial statements to understand the effects or potential effects of those arrangements on an entity’s financial position. This ASU is required to be applied retrospectively and is effective for fiscal
years, and interim periods within those years, beginning on or after January 1, 2013. As this ASU only requires enhanced disclosures, the adoption of this ASU is not anticipated to have a significant impact on the Company’s Consolidated
Financial Statements. 
 4. DEPRECIATION AND AMORTIZATION 

 

									
	 Year ended December 31 (millions of dollars)
	  	2012	 	  	2011	 
	 Depreciation of property, plant and equipment
	  	 	522	  	  	 	485	  
	 Amortization of intangible assets
	  	 	48	  	  	 	45	  
	 Asset removal costs
	  	 	70	  	  	 	66	  
	 Amortization of regulatory assets
	  	 	19	  	  	 	20	  
		  	  
	  
	 	  	  
	  
	 
		  	 	659	  	  	 	616	  
		  	  
	  
	 	  	  
	  
	 

 5. FINANCING CHARGES 
  

									
	 Year ended December 31 (millions of dollars)
	  	2012	 	 	2011	 
	 Interest on long-term debt
	  	 	421	  	 	 	412	  
	 Other
	  	 	12	  	 	 	5	  
	 Less: Interest capitalized on construction and development in progress
	  	 	(59	) 	 	 	(58	) 
	 Gain on interest-rate swap agreements
	  	 	(12	) 	 	 	(12	) 
	 Interest earned on investments
	  	 	(4	) 	 	 	(3	) 
		  	  
	  
	 	 	  
	  
	 
		  	 	358	  	 	 	344	  
		  	  
	  
	 	 	  
	  
	 

  

					
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 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) 
  

 6. PROVISION FOR PAYMENTS IN LIEU OF CORPORATE INCOME TAXES 

The major components of income tax expense are as follows: 
  

									
	 Year ended December 31 (millions of dollars)
	  	2012	 	 	2011	 
	 Current provision for PILs
	  	 	130	  	 	 	162	  
	 Deferred recovery of PILs
	  	 	(9	) 	 	 	(12	) 
		  	  
	  
	 	 	  
	  
	 
	 Provision for PILs
	  	 	121	  	 	 	150	  
		  	  
	  
	 	 	  
	  
	 

 The provision for PILs differs from the amount that would have been recorded using the combined Canadian Federal and
Ontario statutory income tax rate. The reconciliation between the statutory and the effective tax rates is provided as follows: 
  

									
	 Year ended December 31 (millions of dollars)
	  	2012	 	 	2011	 
	 Income before provision for PILs
	  	 	866	  	 	 	791	  
	 Canadian Federal and Ontario statutory income tax rate
	  	 	26.50	% 	 	 	28.25	% 
		  	  
	  
	 	 	  
	  
	 
	 Provision for PILs at statutory rate
	  	 	230	  	 	 	223	  
		  	  
	  
	 	 	  
	  
	 
	 Increase (decrease) resulting from:
	  				 			
	 Net temporary differences included in amounts charged to customers:
	  				 			
	 Capital cost allowance in excess of depreciation and amortization
	  	 	(42	) 	 	 	(34	) 
	 Pension contributions in excess of pension expense
	  	 	(23	) 	 	 	(17	) 
	 Interest capitalized for accounting but deducted for tax purposes
	  	 	(15	) 	 	 	(16	) 
	 Overheads capitalized for accounting but deducted for tax purposes
	  	 	(14	) 	 	 	(12	) 
	 Non-refundable investment tax credits
	  	 	(8	) 	 	 	—  	  
	 Environmental expenditures
	  	 	(5	) 	 	 	(4	) 
	 Post-retirement and post-employment benefit expense in excess of cash payments
	  	 	—  	  	 	 	5	  
	 Other
	  	 	(3	) 	 	 	3	  
		  	  
	  
	 	 	  
	  
	 
	 Net temporary differences
	  	 	(110	) 	 	 	(75	) 
	 Net permanent differences
	  	 	1	  	 	 	2	  
		  	  
	  
	 	 	  
	  
	 
	 Total provision for PILs
	  	 	121	  	 	 	150	  
		  	  
	  
	 	 	  
	  
	 
	 Current provision for PILs
	  	 	130	  	 	 	162	  
	 Deferred recovery of PILs
	  	 	(9	) 	 	 	(12	) 
		  	  
	  
	 	 	  
	  
	 
	 Total provision for PILs
	  	 	121	  	 	 	150	  
		  	  
	  
	 	 	  
	  
	 
	 Effective income tax rate
	  	 	13.96	% 	 	 	18.96	% 
		  	  
	  
	 	 	  
	  
	 

 The current provision for PILs of $130 million represents the amount paid or payable to the OEFC with respect to current
year income. The outstanding balance due to the OEFC at December 31, 2012 was $10 million (2011 – $85 million). 
 The total provision
for PILs includes deferred recovery of PILs of $9 million that is not included in the rate-setting process, using the balance sheet liability method of accounting. Deferred PILs balances expected to be included in the rate-setting process are offset
by regulatory assets and liabilities to reflect the anticipated recovery or disposition of these balances within future electricity rates. 

Deferred Income Tax Assets and Liabilities 
 Deferred income tax assets and liabilities arise from differences between the carrying amounts and tax bases of the Company’s assets and liabilities. At December 31, deferred income tax assets
and liabilities consisted of the following: 

  

					
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 HYDRO ONE INC. 
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) 
  

									
	  
 December 31 (millions of
dollars)
	  	2012	 	 	2011	 
	 Deferred income tax assets
	  				 			
	 Depreciation and amortization in excess of capital cost allowance
	  	 	3	  	 	 	6	  
	 Post-retirement and post-employment benefits expense in excess of cash payments
	  	 	7	  	 	 	5	  
	 Environmental expenditures
	  	 	4	  	 	 	5	  
	 Other
	  	 	—  	  	 	 	1	  
		  	  
	  
	 	 	  
	  
	 
	 Total deferred income tax assets
	  	 	14	  	 	 	17	  
	 Less: current portion
	  	 	—  	  	 	 	—  	  
		  	  
	  
	 	 	  
	  
	 
		  	 	14	  	 	 	17	  
		  	  
	  
	 	 	  
	  
	 
			
	 December 31 (millions of dollars)
	  	2012	 	 	2011	 
	 Deferred income tax liabilities
	  				 			
	 Capital cost allowance in excess of depreciation and amortization
	  	 	(1,344	) 	 	 	(1,106	) 
	 Post-retirement and post-employment benefits expense in excess of cash payments
	  	 	519	  	 	 	356	  
	 Environmental expenditures
	  	 	62	  	 	 	61	  
	 Regulatory amounts receivable that are not recognized for tax purposes
	  	 	(147	) 	 	 	(36	) 
	 Goodwill
	  	 	(19	) 	 	 	(18	) 
	 Other
	  	 	3	  	 	 	4	  
		  	  
	  
	 	 	  
	  
	 
	 Total deferred income tax liabilities
	  	 	(926	) 	 	 	(739	) 
	 Less: current portion
	  	 	18	  	 	 	19	  
		  	  
	  
	 	 	  
	  
	 
		  	 	(944	) 	 	 	(758	) 
		  	  
	  
	 	 	  
	  
	 

 During 2012, the deferred tax liability increased by $60 million as a result of the change in the rate applicable to
future taxes. At December 31, 2012, unused tax losses carried forward were less than $1 million (2011 – less than $1 million). 

7. ACCOUNTS RECEIVABLE 
  

									
	 December 31 (millions of dollars)
	  	2012	 	 	2011	 
	 Accounts receivable – billed
	  	 	224	  	 	 	235	  
	 Accounts receivable – unbilled
	  	 	644	  	 	 	588	  
		  	  
	  
	 	 	  
	  
	 
	 Accounts receivable, gross
	  	 	868	  	 	 	823	  
	 Allowance for doubtful accounts
	  	 	(23	) 	 	 	(18	) 
		  	  
	  
	 	 	  
	  
	 
	 Accounts receivable, net
	  	 	845	  	 	 	805	  
		  	  
	  
	 	 	  
	  
	 

 The following table shows the movements in the allowance for doubtful accounts for the years ended December 31, 2012
and 2011. 
  

									
	 Year ended December 31 (millions of dollars)
	  	2012	 	 	2011	 
	 Allowance for doubtful accounts – January 1
	  	 	(18	) 	 	 	(25	) 
	 Write-offs
	  	 	17	  	 	 	30	  
	 Additions to allowance for doubtful accounts
	  	 	(22	) 	 	 	(23	) 
		  	  
	  
	 	 	  
	  
	 
	 Allowance for doubtful accounts – December 31
	  	 	(23	) 	 	 	(18	) 
		  	  
	  
	 	 	  
	  
	 

  

					
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Table of Contents

 HYDRO ONE INC. 
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) 
  

 8. PROPERTY, PLANT AND EQUIPMENT 

 

																	
	 December 31 (millions of dollars)
	  	Property, Plant
and Equipment	 	  	Accumulated
Depreciation	 	  	Construction
in Progress	 	  	Total	 
	 2012
	  				  				  				  			
	 Transmission
	  	 	11,840	  	  	 	3,990	  	  	 	641	  	  	 	8,491	  
	 Distribution
	  	 	8,005	  	  	 	2,879	  	  	 	234	  	  	 	5,360	  
	 Communication
	  	 	1,024	  	  	 	516	  	  	 	57	  	  	 	565	  
	 Administration and Service
	  	 	1,314	  	  	 	668	  	  	 	123	  	  	 	769	  
	 Easements
	  	 	614	  	  	 	92	  	  	 	—  	  	  	 	522	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
		  	 	22,797	  	  	 	8,145	  	  	 	1,055	  	  	 	15,707	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 2011
	  				  				  				  			
	 Transmission
	  	 	10,906	  	  	 	3,810	  	  	 	1,079	  	  	 	8,175	  
	 Distribution
	  	 	7,596	  	  	 	2,706	  	  	 	253	  	  	 	5,143	  
	 Communication
	  	 	919	  	  	 	468	  	  	 	43	  	  	 	494	  
	 Administration and Service
	  	 	1,232	  	  	 	607	  	  	 	61	  	  	 	686	  
	 Easements
	  	 	493	  	  	 	88	  	  	 	—  	  	  	 	405	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
		  	 	21,146	  	  	 	7,679	  	  	 	1,436	  	  	 	14,903	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 

 Financing charges capitalized on property, plant and equipment under construction were $56 million in 2012 (2011 –
$57 million). 
 9. INTANGIBLE ASSETS 
  

																	
	 December 31 (millions of dollars)
	  	Intangible
Assets	 	  	Accumulated
Amortization	 	  	Development
in Progress	 	  	Total	 
	 2012
	  				  				  				  			
	 Computer applications software
	  	 	451	  	  	 	301	  	  	 	116	  	  	 	266	  
	 Other
	  	 	5	  	  	 	4	  	  	 	—  	  	  	 	1	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
		  	 	456	  	  	 	305	  	  	 	116	  	  	 	267	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 2011
	  				  				  				  			
	 Computer applications software
	  	 	427	  	  	 	254	  	  	 	49	  	  	 	222	  
	 Other
	  	 	5	  	  	 	3	  	  	 	—  	  	  	 	2	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
		  	 	432	  	  	 	257	  	  	 	49	  	  	 	224	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 

 Financing charges capitalized on intangible assets under development were $3 million in 2012 (2011 – $1 million).
The estimated annual amortization expense for intangible assets for each of the next five years is $42 million. 

  

					
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 HYDRO ONE INC. 
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) 
  

 10. REGULATORY ASSETS AND LIABILITIES 
 Regulatory assets and liabilities arise as a result of the rate-setting process. Hydro One has recorded the following regulatory assets and liabilities: 

 

									
	 December 31 (millions of dollars)
	  	2012	 	  	2011	 
	 Regulatory assets:
	  				  			
	 Pension benefit regulatory asset
	  	 	1,515	  	  	 	779	  
	 Deferred income tax regulatory asset
	  	 	954	  	  	 	763	  
	 Post-retirement and post-employment benefits
	  	 	320	  	  	 	123	  
	 Environmental
	  	 	249	  	  	 	257	  
	 Pension cost variance
	  	 	61	  	  	 	42	  
	 Rider 2
	  	 	10	  	  	 	11	  
	 Long-term project development costs
	  	 	5	  	  	 	5	  
	 Other
	  	 	13	  	  	 	10	  
		  	  
	  
	 	  	  
	  
	 
	 Total regulatory assets
	  	 	3,127	  	  	 	1,990	  
	 Less: current portion
	  	 	29	  	  	 	24	  
		  	  
	  
	 	  	  
	  
	 
		  	 	3,098	  	  	 	1,966	  
		  	  
	  
	 	  	  
	  
	 
	 Regulatory liabilities:
	  				  			
	 External revenue variance
	  	 	61	  	  	 	39	  
	 Retail settlement variance accounts
	  	 	54	  	  	 	39	  
	 Rider 8
	  	 	45	  	  	 	41	  
	 Deferred income tax regulatory liability
	  	 	16	  	  	 	25	  
	 PST savings deferral
	  	 	13	  	  	 	8	  
	 Rider 3
	  	 	9	  	  	 	9	  
	 Rural and remote rate protection variance
	  	 	6	  	  	 	8	  
	 Hydro One Brampton Networks rider
	  	 	—  	  	  	 	2	  
	 Other
	  	 	17	  	  	 	23	  
		  	  
	  
	 	  	  
	  
	 
	 Total regulatory liabilities
	  	 	221	  	  	 	194	  
	 Less: current portion
	  	 	40	  	  	 	25	  
		  	  
	  
	 	  	  
	  
	 
		  	 	181	  	  	 	169	  
		  	  
	  
	 	  	  
	  
	 

 Pension Benefit Regulatory Asset 
 The Company recognizes the net unfunded status of pension obligations on the Consolidated Balance Sheets with an offset to the associated regulatory asset. A regulatory asset is recognized because
management considers it to be probable that pension benefit costs will be recovered in the future through the rate-setting process. The pension benefit obligation is remeasured to its fair value at each year end based on an annual actuarial report,
with an offset to the associated regulatory asset, to the extent of the remeasurement adjustment. In the absence of rate-regulated accounting, 2012 OCI would have been lower by $736 million (2011 – higher by $482 million). 

Deferred Income Tax Regulatory Asset and Liability 
 Deferred income taxes are recognized on temporary differences between the carrying amount of assets and liabilities in the financial statements and the corresponding tax bases used in the computation of
taxable profit. The Company has recognized regulatory assets and liabilities that correspond to deferred income taxes that flow through the rate-setting process. In the absence of rate-regulated accounting, the Company’s provision for PILs
would have been recognized using the liability method and there would be no regulatory accounts established for taxes to be recovered through future rates. As a result, the 2012 provision for PILs would have been higher by approximately $136 million
(2011 – $70 million), including the impact of a change in enacted tax rates. 

  

					
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 HYDRO ONE INC. 
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) 
  

 Post-Retirement and Post-Employment Benefits 

The Company recognizes the net unfunded status of post-retirement and post-employment obligations on the Consolidated Balance Sheets with an incremental
offset to the associated regulatory assets. A regulatory asset is recognized because management considers it to be probable that post-retirement and post-employment benefit costs will be recovered in the future through the rate-setting process. The
post-retirement and post-employment benefit obligation is remeasured to its fair value at each year end based on an annual actuarial report, with an offset to the associated regulatory asset, to the extent of the remeasurement adjustment. In the
absence of rate-regulated accounting, 2012 OCI would have been lower by $197 million (2011 – higher by $30 million). 
 Environmental

 Hydro One records a liability for the estimated future expenditures required to remediate past environmental contamination (see Note 15
– Environmental Liabilities). Because such expenditures are expected to be recoverable in future rates, the Company has recorded an equivalent amount as a regulatory asset. In 2012, this regulatory asset decreased by $3 million (2011 – $55
million) to reflect related changes in the Company’s PCB liability, and increased by $2 million (2011 – $5 million) due to changes in the LAR liability. The environmental regulatory asset is amortized to results of operations based on the
pattern of actual expenditures incurred and charged to environmental liabilities. The OEB has the discretion to examine and assess the prudency and the timing of recovery of all of Hydro One’s actual environmental expenditures. In the absence
of rate-regulated accounting, 2012 operation, maintenance and administration expenses would have been lower by $1 million (2011 – $50 million). In addition, 2012 amortization expense would have been lower by $18 million (2011 – $16
million), and 2012 financing charges would have been higher by $11 million (2011 – $14 million). 
 Pension Cost Variance

 A pension cost variance account was established for each of Hydro One Networks’ Transmission and Distribution businesses to track the
difference between the actual pension expense incurred and estimated pension costs approved by the OEB. The balance in this account reflects the excess of pension costs paid as compared to OEB-approved amounts. In December 2010, the OEB approved the
December 31, 2009 balance, including accrued interest, to be recovered over a one-year period from January 1, 2011 to December 31, 2011. In the absence of rate-regulated accounting, 2012 revenue would have been lower by $18 million
(2011 – $14 million). 
 Rider 2 
 In April 2006, the OEB announced its decision regarding the Company’s rate application in respect of the Distribution Business of Hydro One Networks. As part of this decision, the OEB also approved
the distribution-related deferral account balances sought by Hydro One. The Rider 2 regulatory asset includes retail settlement and cost variance amounts and distribution low-voltage service amounts, plus accrued interest. 

Long-Term Project Development Costs 
 In
May 2009, the OEB approved the creation of a deferral account to record Hydro One Networks’ costs of preliminary work to advance certain transmission projects identified in the Company’s 2009 and 2010 transmission rate applications. In
March 2010, the OEB issued a decision amending the scope of the account to include the 20 major transmission projects identified in the September 2009 request from the Ministry of Energy and Infrastructure. In December 2010, the OEB approved the
recovery of the December 31, 2009 balance, including accrued interest, to be recovered over a one-year period from January 1, 2011 to December 31, 2011. In the absence of rate-regulated accounting, 2011 operation, maintenance and
administration expenses would have been lower by $2 million. 
 External Revenue Variance 

In May 2009, the OEB approved forecasted amounts related to export service revenue, external revenue from secondary land use, and external revenue from
station maintenance and engineering and construction work. These revenue sources are taken into account in structuring the Company’s revenue requirement and as such, the OEB requested the establishment of new variance accounts to capture any
difference between the approved forecasted external revenue amounts used in establishing the revenue requirement and actual external revenues. The external revenue variance account balance reflects the excess of actual external revenue compared to
the OEB-approved forecasted amounts. In December 2010, the OEB approved the disposition of the December 31, 2009 balance, including accrued interest, to be disposed over a one-year period from January 1, 2011 to December 31, 2011.

  

					
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 HYDRO ONE INC. 
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) 
  

 Retail Settlement Variance Accounts (RSVAs) 

Hydro One has deferred certain retail settlement variance amounts under the provisions of Article 490 of the OEB’s Accounting Procedures Handbook. In
April 2010, the OEB approved the disposition of the total RSVA balance accumulated from May 2008 to December 2009, including accrued interest, to be disposed over a 20-month period from May 1, 2010 to December 31, 2011. Hydro One has
continued to accumulate a net liability in its RSVA accounts since December 31, 2009. 
 Rider 8 

In April 2010, the OEB requested the establishment of deferral accounts which capture the difference between the revenue recorded on the basis of Green
Energy Plan expenditures incurred and the actual recoveries received. 
 PST Savings Deferral Account 

The provincial sales tax (PST) and goods and services tax (GST) were harmonized in July 2010. Unlike the GST, the PST was included in operation,
maintenance and administrative expenses or capital expenditures for past revenue requirements approved during a full cost of service hearing. Under the harmonized sales tax (HST) regime, the HST included in operation, maintenance and administrative
expenses or capital expenditures is not a cost ultimately borne by the Company and as such, a refund of the prior PST element in the approved revenue requirement is applicable and calculations for tracking and refund were requested by the OEB. For
the Hydro One Networks Transmission revenue requirement, PST was included between July 1, 2010 and December 31, 2010 and recorded in a deferral account per direction from the OEB. For the Hydro One Networks Distribution revenue
requirement, PST was included between July 1, 2010 and December 31, 2012 and recorded in a deferral account per direction from the OEB. 
 Rider 3 
 In December 2008, the OEB approved certain distribution-related deferral account
balances sought by Hydro One, including RSVA amounts, deferred tax changes, OEB costs and smart meters. The OEB approved the disposition of the Rider 3 balance accumulated up to April 2008, including accrued interest, to be disposed over a 27-month
period from February 1, 2009 to April 30, 2011. 
 Rural and Remote Rate Protection Variance (RRRP) 

Hydro One receives rural rate protection amounts from the IESO. A portion of these amounts is provided to retail customers of Hydro One Networks who are
eligible for rate protection. The OEB has approved a mechanism to collect the RRRP through the Wholesale Market Service Charge. Variances between the amounts remitted by the IESO to Hydro One and the fixed entitlements defined in the regulation, and
subsequent OEB utility rate decisions, are tracked by the Company in the RRRP variance account. 
 Hydro One Brampton Networks Rider

 In April 2010, the OEB issued a decision regarding the 2010 distribution rates of Hydro One Brampton Networks. Included in the OEB’s
decision was the approval of certain deferral account balances, primarily RSVAs, sought by Hydro One Brampton Networks in its application. The OEB ordered that the approved balances be aggregated into a single regulatory account and disposed of
through a rate rider over a two-year period from May 1, 2010 to April 30, 2012. 

  

					
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 HYDRO ONE INC. 
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) 
  

 11. DEBT AND CREDIT AGREEMENTS 
 Short-Term Notes 
 Hydro One meets its short-term liquidity requirements in part through the
issuance of commercial paper under its Commercial Paper Program with a maximum amount of $1,000 million. These short-term notes are denominated in Canadian dollars with varying maturities not exceeding 365 days. Hydro One had no commercial paper
borrowings outstanding as at December 31, 2012 and 2011. 
 The Commercial Paper Program is supported by a total of $1,500 million in
liquidity facilities comprised of a $1,250 million committed revolving standby credit facility with a syndicate of banks and a long-term investment in Province of Ontario Floating-Rate Notes with a fair value of $251 million at December 31,
2012. 
 Long-Term Debt 
 The
Company issues notes for long-term financing under its Medium-Term Note (MTN) Program. The maximum authorized principal amount of notes issuable under this program is $3,000 million. At December 31, 2012, $1,515 million remained available until
September 2013. 
 The following table presents the outstanding long-term debt at December 31, 2012 and 2011: 

 

									
	 December 31 (millions of dollars)
	  	2012	 	 	2011	 
	 5.77% Series 3 notes due 2012
	  	 	—  	  	 	 	600	  
	 5.00% Series 15 notes due 2013
	  	 	600	  	 	 	600	  
	 3.13% Series 19 notes due 20141
	  	 	750	  	 	 	750	  
	 2.95% Series 21 notes due 20151
	  	 	500	  	 	 	500	  
	 Floating-rate Series 22 notes due 20152
	  	 	50	  	 	 	50	  
	 4.64% Series 10 notes due 2016
	  	 	450	  	 	 	450	  
	 Floating-rate Series 27 notes due 20162
	  	 	50	  	 	 	—  	  
	 5.18% Series 13 notes due 2017
	  	 	600	  	 	 	600	  
	 4.40% Series 20 notes due 2020
	  	 	300	  	 	 	300	  
	 3.20% Series 25 notes due 2022
	  	 	600	  	 	 	—  	  
	 7.35% debentures due 2030
	  	 	400	  	 	 	400	  
	 6.93% Series 2 notes due 2032
	  	 	500	  	 	 	500	  
	 6.35% Series 4 notes due 2034
	  	 	385	  	 	 	385	  
	 5.36% Series 9 notes due 2036
	  	 	600	  	 	 	600	  
	 4.89% Series 12 notes due 2037
	  	 	400	  	 	 	400	  
	 6.03% Series 17 notes due 2039
	  	 	300	  	 	 	300	  
	 5.49% Series 18 notes due 2040
	  	 	500	  	 	 	500	  
	 4.39% Series 23 notes due 2041
	  	 	300	  	 	 	300	  
	 6.59% Series 5 notes due 2043
	  	 	315	  	 	 	315	  
	 5.00% Series 11 notes due 2046
	  	 	325	  	 	 	325	  
	 4.00% Series 24 notes due 2051
	  	 	225	  	 	 	100	  
	 3.79% Series 26 notes due 2062
	  	 	310	  	 	 	—  	  
		  	  
	  
	 	 	  
	  
	 
		  	 	8,460	  	 	 	7,975	  
	 Add: Unrealized marked-to-market loss1
	  	 	19	  	 	 	33	  
	 Less: Long-term debt payable within one year
	  	 	(600	) 	 	 	(600	) 
		  	  
	  
	 	 	  
	  
	 
	 Long-term debt
	  	 	7,879	  	 	 	7,408	  
		  	  
	  
	 	 	  
	  
	 

  

	1 	 The unrealized marked-to-market loss relates to $500 million of the Series 19 notes due 2014, and $250 million of the Series 21 notes due 2015. The
unrealized marked-to-market loss is offset by a $19 million (2011 – $33 million) unrealized marked-to-market gain on the related fixed-to-floating interest-rate swap agreements, which are accounted for as fair value hedges. See Note 12 –
Fair Value of Financial Instruments and Risk Management for details of fair value hedges. 

	2 	 The interest rates of the floating-rate notes are referenced to the 3-month Canadian dollar bankers’ acceptance rate, plus a margin.

  

					
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 HYDRO ONE INC. 
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) 
  

 In 2012, Hydro One issued $1,085 million of long-term debt under the MTN Program, consisting of $300
million issued in the first quarter, $425 million issued in the second quarter, $310 million issued in the third quarter, and $50 million issued in the fourth quarter of 2012. In September 2012, the Company also redeemed the $600 million MTN Series
3 notes. 
 The long-term debt is unsecured and denominated in Canadian dollars. The long-term debt is summarized by the number of years to
maturity in Note 12 – Fair Value of Financial Instruments and Risk Management. 
 Credit Agreements 

Hydro One has a $1,250 million committed and unused revolving standby credit facility with a syndicate of banks, maturing in June 2017. If used, interest
on the facility would apply based on Canadian benchmark rates. This credit facility supports the Company’s Commercial Paper Program. 
 The
Company may use the credit facility for general corporate purposes, including meeting short-term funding requirements. The obligation of each lender to make any credit extension to the Company under its credit facility is subject to various
conditions including, among other things, that no event of default has occurred or would result from such credit extension. 
 12. FAIR VALUE
OF FINANCIAL INSTRUMENTS AND RISK MANAGEMENT 
 Fair value is considered to be the exchange price in an orderly transaction between market
participants to sell an asset or transfer a liability at the measurement date. The fair value definition focuses on an exit price, which is the price that would be received in the sale of an asset or the amount that would be paid to transfer a
liability. 
 Hydro One classifies its fair value measurements based on the following hierarchy, as prescribed by the accounting guidance for
fair value, which prioritizes the inputs to valuation techniques used to measure fair value into three levels: 
 Level 1 inputs are unadjusted
quoted prices in active markets for identical assets or liabilities that Hydro One has the ability to access. An active market for the asset or liability is one in which transactions for the asset or liability occur with sufficient frequency and
volume to provide ongoing pricing information. 
 Level 2 inputs are those other than quoted market prices that are observable, either directly
or indirectly, for an asset or liability. Level 2 inputs include, but are not limited to, quoted prices for similar assets or liabilities in an active market, quoted prices for identical or similar assets or liabilities in markets that are not
active and inputs other than quoted market prices that are observable for the asset or liability, such as interest rate curves and yield curves observable at commonly quoted intervals, volatilities, credit risk and default rates. A Level 2
measurement cannot have more than an insignificant portion of the valuation based on unobservable inputs. 
 Level 3 inputs are any fair value
measurements that include unobservable inputs for the asset or liability for more than an insignificant portion of the valuation. A Level 3 measurement may be based primarily on Level 2 inputs. 

Non-Derivative Financial Assets and Liabilities 
 At December 31, 2012 and 2011, the Company’s carrying amounts of accounts receivable, due from related parties, short-term investments, bank indebtedness, accounts payable, accrued liabilities,
and due to related parties are representative of fair value because of the short-term nature of these instruments. 

  

					
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 HYDRO ONE INC. 
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) 
  

 Fair Value Measurements of Long-Term Debt 

The fair values and carrying values of the Company’s long-term debt at December 31, 2012 and 2011 are as follows: 

 

																	
	 December 31 (millions of dollars)
	  	2012
Carrying Value	 	  	2012
Fair Value	 	  	2011
Carrying Value	 	  	2011
Fair Value	 
	 Long-term debt
	  				  				  				  			
	 $ 500 million of MTN Series 19 notes1
	  	 	512	  	  	 	512	  	  	 	521	  	  	 	521	  
	 $ 250 million of MTN Series 21 notes2
	  	 	257	  	  	 	257	  	  	 	262	  	  	 	262	  
	 Other notes and debentures3
	  	 	7,710	  	  	 	9,188	  	  	 	7,225	  	  	 	8,615	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
		  	 	8,479	  	  	 	9,957	  	  	 	8,008	  	  	 	9,398	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 

  

	1 	 The fair value of $500 million of the MTN Series 19 notes subject to hedging is primarily based on changes in the present value of future cash flows
due to a change in the yield in the swap market for the related swap (hedged risk). 

	2 	 The fair value of $250 million of the MTN Series 21 notes subject to hedging is primarily based on changes in the present value of future cash flows
due to a change in the yield in the swap market for the related swap (hedged risk). 

	3 	 The fair value of other notes and debentures, and the portions of the MTN Series 19 notes and the MTN Series 21 notes that are not subject to hedging,
represents the market value of the notes and debentures and is based on unadjusted period-end market prices for the same or similar debt of the same remaining maturities. 

 Fair Value Measurements of Derivative Instruments 
 At December 31, 2012, the Company
had interest-rate swaps totaling $750 million (2011 – $750 million) that were used to convert fixed-rate debt to floating-rate debt. These swaps are classified as fair value hedges. The Company’s fair value hedge exposure was equal to
about 9% (2011 – 9%) of its total long-term debt of $8,479 million (2011 – $8,008 million). At December 31, 2102, the Company had the following interest-rate swaps designated as fair value hedges: 

 

	 	(a)	two $250 million fixed-to-floating interest-rate swap agreements to convert $500 million of the $750 million MTN Series 19 notes maturing November 19, 2014 into
three-month variable rate debt; and 

  

	 	(b)	two $125 million fixed-to-floating interest-rate swap agreements to convert $250 million of the $500 million MTN Series 21 notes maturing September 11, 2015 into
three-month variable rate debt. 

 At December 31, 2012, the Company also had interest-rate swaps with a total notional value
of $900 million classified as undesignated contracts. The undesignated contracts consist of the following interest-rate swaps: 
  

	 	(c)	three $250 million floating-to-fixed interest-rate swap agreements that lock in the floating rate the Company pays on a portion of the above fixed-to-floating
interest-rate swaps from December 11, 2012 to December 11, 2013, from February 21, 2012 to February 19, 2013, and from February 19, 2013 to February 19, 2014, respectively; 

 

	 	(d)	two $50 million floating-to-fixed interest-rate swap agreements that lock in the floating rate the Company pays on the $50 million floating-rate MTN Series 22 notes
from January 24, 2012 to January 24, 2013, and from January 24, 2013 to January 24, 2014; and 

  

	 	(e)	a $50 million floating-to-fixed interest-rate swap agreement that locks in the floating rate the Company pays on the $50 million floating-rate MTN Series 27 notes from
March 4, 2013 to December 3, 2013. 

 At December 31, 2012 and 2011, the Company’s carrying amounts of
derivative instruments were representative of fair value. 

  

					
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 HYDRO ONE INC. 
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) 
  

 Fair Value Hierarchy 
 The fair value hierarchy of financial assets and liabilities at December 31, 2012 and 2011 is as follows: 
  

																					
	 December 31, 2012 (millions of dollars)
	  	Carrying
Value	 	  	Fair
Value	 	  	Level 1	 	  	Level 2	 	  	Level 3	 
	 Assets:
	  				  				  				  				  			
	 Short-term investments
	  	 	195	  	  	 	195	  	  	 	—  	  	  	 	195	  	  	 	—  	  
	 Long-term investment
	  	 	251	  	  	 	251	  	  	 	—  	  	  	 	251	  	  	 	—  	  
	 Derivative instruments
	  				  				  				  				  			
	 Fair value hedges – interest-rate swaps
	  	 	19	  	  	 	19	  	  	 	—  	  	  	 	19	  	  	 	—  	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
		  	 	465	  	  	 	465	  	  	 	—  	  	  	 	465	  	  	 	—  	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Liabilities:
	  				  				  				  				  			
	 Bank indebtedness
	  	 	42	  	  	 	42	  	  	 	42	  	  	 	—  	  	  	 	—  	  
	 Long-term debt
	  	 	8,479	  	  	 	9,957	  	  	 	—  	  	  	 	9,957	  	  	 	—  	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
		  	 	8,521	  	  	 	9,999	  	  	 	42	  	  	 	9,957	  	  	 	—  	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
						
	 December 31, 2011 (millions of dollars)
	  	Carrying
Value	 	  	Fair
Value	 	  	Level 1	 	  	Level 2	 	  	Level 3	 
	 Assets:
	  				  				  				  				  			
	 Short-term investments
	  	 	228	  	  	 	228	  	  	 	—  	  	  	 	228	  	  	 	—  	  
	 Long-term investment
	  	 	250	  	  	 	250	  	  	 	—  	  	  	 	250	  	  	 	—  	  
	 Derivative instruments
	  				  				  				  				  			
	 Fair value hedges – interest-rate swaps
	  	 	33	  	  	 	33	  	  	 	—  	  	  	 	33	  	  	 	—  	  
	 Undesignated contracts – interest-rate swaps
	  	 	1	  	  	 	1	  	  	 	—  	  	  	 	1	  	  	 	—  	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
		  	 	512	  	  	 	512	  	  	 	—  	  	  	 	512	  	  	 	—  	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Liabilities:
	  				  				  				  				  			
	 Bank indebtedness
	  	 	39	  	  	 	39	  	  	 	39	  	  	 	—  	  	  	 	—  	  
	 Long-term debt
	  	 	8,008	  	  	 	9,398	  	  	 	—  	  	  	 	9,398	  	  	 	—  	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
		  	 	8,047	  	  	 	9,437	  	  	 	39	  	  	 	9,398	  	  	 	—  	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 

 The short-term investments represent investments with an original maturity of three months or less. The fair value of the
short-term investments is determined using inputs other than quoted prices that are observable for the assets. The Company obtains quotes for the fair value of the short-term investments from an independent third party. 

The long-term investment represents the Province of Ontario Floating-Rate Notes. The fair value of the long-term investment is determined using inputs
other than quoted prices that are observable for the asset, with unrecognized gains or losses recognized in financing charges. The Company obtains quotes from an independent third party for the fair value of the long-term investment, who uses the
market price of similar securities adjusted for changes in observable inputs such as maturity dates and interest rates. 
 The fair value of the
derivative instruments is determined using other than quoted prices that are observable for these assets. The fair value is primarily based on the present value of future cash flows using a swap yield curve to determine the assumptions for interest
rates. 
 The fair value of the hedged portion of the long-term debt is primarily based on the present value of future cash flows using a swap
yield curve to determine the assumption for interest rates. The fair value of the unhedged portion of the long-term debt is based on unadjusted period-end market prices for the same or similar debt of the same remaining maturities. 

There were no significant transfers between any of the levels during the years ended December 31, 2012 and 2011. 

See Note 14 – Pension and Post-Retirement and Post-Employment Benefits for further information regarding the fair value and related valuation
techniques for pension plan assets. 

  

					
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Table of Contents

 HYDRO ONE INC. 
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) 
  

 Risk Management 
 Exposure to market risk, credit risk and liquidity risk arises in the normal course of the Company’s business. 
 Market Risk 
 Market risk refers primarily to the risk of loss that results from
changes in commodity prices, foreign exchange rates and interest rates. The Company does not have commodity risk. The Company does have foreign exchange risk as it enters into agreements to purchase materials and equipment associated with capital
programs and projects that are settled in foreign currencies. This foreign exchange risk is not material, although the Company could in the future decide to issue foreign currency-denominated debt which would be hedged back to Canadian dollars
consistent with its risk management policy. Hydro One is exposed to fluctuations in interest rates as the regulated rate of return for the Company’s transmission and distribution businesses is derived using a formulaic approach that is based on
the forecast for long-term Government of Canada bond yields and the spread in 30-year “A”-rated Canadian utility bonds over the 30-year benchmark Government of Canada bond yield. The Company estimates that a 1% decrease in the forecasted
long-term Government of Canada bond yield or the “A”-rated Canadian utility spread used in determining the Company’s rate of return would reduce the Transmission Business’ results of operations by approximately $18 million (2011
– $18 million) and Hydro One Networks’ Distribution Business’ results of operations by approximately $10 million (2011 – $10 million). 
 The Company uses a combination of fixed and variable-rate debt to manage the mix of its debt portfolio. The Company also uses derivative financial instruments to manage interest-rate risk. The Company
utilizes interest-rate swaps, which are typically designated as fair value hedges, as a means to manage its interest rate exposure to achieve a lower cost of debt. In addition, the Company may utilize interest-rate derivative instruments to lock in
interest rate levels in anticipation of future financing. Hydro One may also enter into derivative agreements such as forward-starting pay fixed-interest-rate swap agreements to hedge against the effect of future interest rate movements on long-term
fixed-rate borrowing requirements. Such arrangements are typically designated as cash flow hedges. No cash flow hedge agreements were outstanding as at December 31, 2012 or 2011. 
 A hypothetical 10% increase in the interest rates associated with variable-rate debt would not have resulted in a significant decrease in Hydro One’s results of operations for the years ended
December 31, 2012 or 2011. 
 Fair Value Hedges 
 For derivative instruments that are designated and qualify as fair value hedges, the gain or loss on the derivative as well as the offsetting loss or gain on the hedged item attributable to the hedged
risk are recognized in the Consolidated Statements of Operations and Comprehensive Income. The net unrealized loss (gain) on the hedged debt and the related interest rate swaps for the years ended December 31, 2012 and 2011 are included in
financing charges as follows: 
  

									
	 Year ended December 31 (millions of dollars)
	  	2012	 	 	2011	 
	 Unrealized loss (gain) on hedged debt
	  	 	(14	) 	 	 	25	  
	 Unrealized loss (gain) on fair value interest-rate swaps
	  	 	14	  	 	 	(25	) 
		  	  
	  
	 	 	  
	  
	 
	 Net unrealized loss (gain)
	  	 	—  	 	 	 	—  	 
		  	  
	  
	 	 	  
	  
	 

 At December 31, 2012, Hydro One had $750 million (2011 – $750 million) of notional amounts of fair value hedges
outstanding related to interest-rate swaps, with assets at fair value of $19 million (2011 – $33 million). During the years ended December 31, 2012 and 2011, there was no significant impact on the results of operations as a result of any
ineffectiveness attributable to fair value hedges. 
 Credit Risk 
 Financial assets create a risk that a counterparty will fail to discharge an obligation, causing a financial loss. At December 31, 2012 and 2011, there were no significant concentrations of credit
risk with respect to any class of financial assets. The Company’s revenue is earned from a broad base of customers. As a result, Hydro One did not earn a significant amount of revenue from any individual customer. At December 31, 2012 and
2011, there was no significant accounts receivable balance due from any single customer. 

  

					
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Table of Contents

 HYDRO ONE INC. 
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) 
  

 At December 31, 2012, the Company’s provision for bad debts was $23 million (2011 – $18
million). Adjustments and write-offs were determined on the basis of a review of overdue accounts, taking into consideration historical experience. At December 31, 2012, approximately 3% of the Company’s accounts receivable were aged more
than 60 days (2011 – 3%). 
 Hydro One manages its counterparty credit risk through various techniques including: entering into
transactions with highly-rated counterparties; limiting total exposure levels with individual counterparties consistent with the Company’s Board-approved Credit Risk Policy; entering into master agreements which enable net settlement and the
contractual right of offset; and monitoring the financial condition of counterparties. In addition to payment netting language in master agreements, the Company establishes credit limits, margining thresholds and collateral requirements for each
counterparty. Counterparty credit limits are based on an internal credit review that considers a variety of factors, including the results of a scoring model, leverage, liquidity, profitability, credit ratings and risk management capabilities. The
determination of credit exposure for a particular counterparty is the sum of current exposure plus the potential future exposure with that counterparty. The current exposure is calculated as the sum of the principal value of money market exposures
and the market value of all contracts that have a positive mark-to-market position on the measurement date. The Company would only offset the positive market values against negative values with the same counterparty where permitted by the existence
of a legal netting agreement such as an International Swap Dealers Association master agreement. The potential future exposure represents a safety margin to protect against future fluctuations of interest rates, currencies, equities, and
commodities. It is calculated based on factors developed by the Bank of International Settlements, following extensive historical analysis of random fluctuations of interest rates and currencies. To the extent that a counterparty’s margining
thresholds are exceeded, the counterparty is required to post collateral with the Company as specified in each agreement. The Company monitors current and forward credit exposure to counterparties both on an individual and an aggregate basis. The
Company’s credit risk for accounts receivable is limited to the carrying amounts on the Consolidated Balance Sheets. 
 Derivative
financial instruments result in exposure to credit risk since there is a risk of counterparty default. The credit exposure of derivative contracts, before collateral, is represented by the fair value of contracts at the reporting date. At
December 31, 2012, the counterparty credit risk exposure on the fair value of these interest-rate swap contracts was $22 million (2011 – $36 million). At December 31, 2012, Hydro One’s credit exposure for all derivative
instruments, and applicable payables and receivables, had a credit rating of investment grade, with four financial institutions as the counterparties. The credit exposure of each of the four counterparties accounted for more than 10% of the total
credit exposure. 
 Liquidity Risk 
 Liquidity risk refers to the Company’s ability to meet its financial obligations as they come due. Hydro One meets its short-term liquidity requirements using cash and cash equivalents on hand, funds
from operations, the issuance of commercial paper, the revolving standby credit facility, and by holding Province of Ontario Floating-Rate Notes. The Commercial Paper Program is supported by a total of $1,500 million in liquidity facilities
comprised of a $1,250 million committed revolving credit facility with a syndicate of banks maturing in June 2017 and the Province of Ontario Floating-Rate Notes with a fair value of $251 million. The short-term liquidity under this program and
anticipated levels of funds from operations should be sufficient to fund normal operating requirements. 
 At December 31, 2012, accounts
payable and accrued liabilities in the amount of $722 million are expected to be settled in cash at their carrying amounts within the next year. 
 At December 31, 2012, Hydro One had issued long-term debt in the notional amount of $8,460 million (2011 – $7,975 million). Long-term debt maturing during the next year is $600 million (2011
– $600 million). Interest payments for the next 12 months on the Company’s outstanding long-term debt amount to $410 million (2011 – $408 million). Principal outstanding, interest payments and related weighted average interest rates
are summarized by the number of years to maturity in the following table. 

  

					
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 HYDRO ONE INC. 
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) 
  

													
	 Years to Maturity
	  	Principal Outstanding
on Long-term Debt
(millions of
dollars)	 	  	Interest 
Payments1
(millions of dollars)	 	  	Weighted Average
Interest Rate1
(%)	 
	 1 year
	  	 	600	  	  	 	410	  	  	 	5.0	  
	 2 years
	  	 	750	  	  	 	379	  	  	 	3.1	  
	 3 years
	  	 	550	  	  	 	356	  	  	 	2.8	  
	 4 years
	  	 	500	  	  	 	331	  	  	 	4.3	  
	 5 years
	  	 	600	  	  	 	320	  	  	 	5.2	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
		  	 	3,000	  	  	 	1,796	  	  	 	4.1	  
	 6 – 10 years
	  	 	900	  	  	 	1,403	  	  	 	3.6	  
	 Over 10 years
	  	 	4,560	  	  	 	4,138	  	  	 	5.6	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
		  	 	8,460	  	  	 	7,337	  	  	 	4.9	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 

  

	1 	 Interest payments and weighted average interest rates beyond 1 year exclude the impact of the $50 million floating-rate Series 22 notes due 2015 and
the $50 million floating-rate Series 27 notes due 2016. 

 13. CAPITAL MANAGEMENT 

The Company’s objectives with respect to its capital structure are to maintain effective access to capital on a long-term basis at reasonable rates,
and to deliver appropriate financial returns. In order to ensure ongoing effective access to capital, the Company targets to maintain an “A” category long-term credit rating. 
 The Company considers its capital structure to consist of shareholder’s equity, preferred shares, long-term debt, and cash and cash equivalents. At December 31, 2012 and 2011, the Company’s
capital structure was as follows: 
  

									
	 December 31 (millions of dollars)
	  	2012	 	  	2011	 
	 Long-term debt payable within one year
	  	 	600	  	  	 	600	  
	 Less: Cash and cash equivalents
	  	 	195	  	  	 	228	  
		  	  
	  
	 	  	  
	  
	 
		  	 	405	  	  	 	372	  
		  	  
	  
	 	  	  
	  
	 
	 Long-term debt
	  	 	7,879	  	  	 	7,408	  
	 Preferred shares
	  	 	323	  	  	 	323	  
	 Common shares
	  	 	3,314	  	  	 	3,314	  
	 Retained earnings
	  	 	3,202	  	  	 	2,827	  
		  	  
	  
	 	  	  
	  
	 
		  	 	6,516	  	  	 	6,141	  
		  	  
	  
	 	  	  
	  
	 
	 Total capital
	  	 	15,123	  	  	 	14,244	  
		  	  
	  
	 	  	  
	  
	 

 The Company has customary covenants typically associated with long-term debt. Among other things, Hydro One’s
long-term debt and credit facility covenants limit the permissible debt to 75% of the Company’s total capitalization, limit the ability to sell assets and impose a negative pledge provision, subject to customary exceptions. At December 31,
2012 and 2011, Hydro One was in compliance with all of these covenants and limitations. 
 14. PENSION AND POST-RETIREMENT AND
POST-EMPLOYMENT BENEFITS 
 Hydro One has a defined benefit pension plan, a supplementary pension plan, and post-retirement and
post-employment benefit plans. The defined benefit pension plan (Pension Plan) is contributory and covers all regular employees of Hydro One and its subsidiaries, except Hydro One Brampton Networks. Employees of Hydro One Brampton Networks
participate in the OMERS plan, a multiemployer public sector pension fund. The supplementary pension plan provides members of the Pension Plan with benefits that would have been earned and payable under the Pension Plan but for the limitations
imposed by the Income Tax Act (Canada). The supplementary pension plan obligation is included with other post-retirement and post-employment benefit obligations on the Consolidated Balance Sheets. 

  

					
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 HYDRO ONE INC. 
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) 
  

 The OMERS Plan 
 Hydro One contributions to the OMERS plan for the year ended December 31, 2012 were $2 million (2011 – $1 million). Company contributions payable at December 31, 2012 and included in
accrued liabilities on the Consolidated Balance Sheets were $0.2 million (2011 – $0.2 million). Hydro One contributions do not represent more than 5% of total contributions to the OMERS plan, as indicated in OMERS’s most recently available
annual report for the year ended December 31, 2011. 
 At December 31, 2011, the OMERS plan was 88.7% funded, with an unfunded
liability of $7,290 million. This unfunded liability will likely result in future payments by participating employers and members. Hydro One future contributions could be increased substantially if other entities withdraw from the plan. 

Pension Plan, Post-Retirement and Post-Employment Plans 
 The Pension Plan provides benefits based on highest three-year average pensionable earnings. For new management employees who commenced employment on or after January 1, 2004, and for new Society of
Energy Professionals-represented staff hired after November 17, 2005, benefits are based on highest five-year average pensionable earnings. After retirement, pensions are indexed to inflation. 

Company and employees’ contributions to the Pension Plan are based on actuarial valuations performed at least every three years. Annual Pension Plan
contributions for 2012 of $163 million (2011 – $152 million) were based on an actuarial valuation effective December 31, 2011 and the level of 2012 pensionable earnings. Estimated annual Pension Plan contributions for 2013 are $162
million, based on the December 31, 2011 valuation and the projected level of pensionable earnings. 
 Hydro One recognizes the overfunded
or underfunded status of the Pension Plan, and post-retirement and post-employment plans (Plans) as an asset or liability on its Consolidated Balance Sheets, with offsetting regulatory assets and liabilities as appropriate. The underfunded benefit
obligations for the Plans, in the absence of regulatory accounting, would be recognized in AOCI. The impact of changes in assumptions used to measure pension, post-retirement and post-employment benefit obligations is generally recognized over the
expected average remaining service period of the employees. For the year ended December 31, 2012, the measurement date for the Plans was December 31. 
  

																	
	 	  	 	 	 	 	 	 	Post-Retirement and Post-	 
	 	  	Pension Benefits	 	 	Employment Benefits	 
	 Year ended December 31 (millions of dollars)
	  	2012	 	 	2011	 	 	2012	 	 	2011	 
	 Change in projected benefit obligation
	  				 				 				 			
	 Projected benefit obligation, beginning of year
	  	 	5,461	  	 	 	4,996	  	 	 	1,206	  	 	 	1,178	  
	 Current service cost
	  	 	123	  	 	 	108	  	 	 	29	  	 	 	30	  
	 Interest cost
	  	 	285	  	 	 	286	  	 	 	63	  	 	 	68	  
	 Reciprocal transfers
	  	 	1	  	 	 	4	  	 	 	—  	  	 	 	—  	  
	 Benefits paid
	  	 	(291	) 	 	 	(289	) 	 	 	(42	) 	 	 	(42	) 
	 Net actuarial loss (gain)
	  	 	928	  	 	 	356	  	 	 	203	  	 	 	(28	) 
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Projected benefit obligation, end of year
	  	 	6,507	  	 	 	5,461	  	 	 	1,459	  	 	 	1,206	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Change in plan assets
	  				 				 				 			
	 Fair value of plan assets, beginning of year
	  	 	4,682	  	 	 	4,699	  	 	 	—  	  	 	 	—  	  
	 Actual return on plan assets
	  	 	425	  	 	 	102	  	 	 	—  	  	 	 	—  	  
	 Reciprocal transfers
	  	 	1	  	 	 	4	  	 	 	—  	  	 	 	—  	  
	 Benefits paid
	  	 	(291	) 	 	 	(289	) 	 	 	—  	  	 	 	—  	  
	 Employer’s contributions
	  	 	163	  	 	 	153	  	 	 	—  	  	 	 	—  	  
	 Employees’ contributions
	  	 	27	  	 	 	27	  	 	 	—  	  	 	 	—  	  
	 Administrative expenses
	  	 	(15	) 	 	 	(14	) 	 	 	—  	  	 	 	—  	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Fair value of plan assets, end of year
	  	 	4,992	  	 	 	4,682	  	 	 	—  	  	 	 	—  	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Unfunded status
	  	 	1,515	  	 	 	779	  	 	 	1,459	  	 	 	1,206	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 

  

					
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 HYDRO ONE INC. 
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) 
  

 Hydro One presents its benefit obligations and plan assets net on its Consolidated Balance Sheets within
the following line items: 
  

																	
	 	  	 	 	  	 	 	  	Post-Retirement and Post-	 
	 	  	Pension Benefits	 	  	Employment Benefits	 
	 December 31 (millions of dollars)
	  	2012	 	  	2011	 	  	2012	 	  	2011	 
	 Accrued liabilities
	  	 	—  	  	  	 	—  	  	  	 	43	  	  	 	43	  
	 Pension benefit liability
	  	 	1,515	  	  	 	779	  	  	 	—  	  	  	 	—  	  
	 Post-retirement and post-employment benefit liability
	  	 	—  	  	  	 	—  	  	  	 	1,416	  	  	 	1,163	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Unfunded status
	  	 	1,515	  	  	 	779	  	  	 	1,459	  	  	 	1,206	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 

 The funded/unfunded status of the pension, post-retirement and post-employment benefit plans refers to the difference
between the fair value of plan assets and the projected benefit obligations for the Plans. The funded/unfunded status changes over time due to several factors, including contribution levels, assumed discount rates and actual returns on plan assets.

 The following table provides the projected benefit obligation (PBO), accumulated benefit obligation (ABO) and fair value of plan assets for
the Pension Plan. 
  

									
	 December 31 (millions of dollars)
	  	2012	 	  	2011	 
	 PBO
	  	 	6,507	  	  	 	5,461	  
	 ABO
	  	 	6,074	  	  	 	5,038	  
	 Fair value of plan assets
	  	 	4,992	  	  	 	4,682	  

 On an ABO basis, the plans were funded at 82% at December 31, 2012 (2011 – 93%). On a PBO basis, the plans were
funded at 77% at December 31, 2012 (2011 – 86%). The ABO differs from the PBO in that the ABO includes no assumption about future compensation levels. 
 Components of Net Periodic Benefit Costs 
 The following table provides the components of
the net periodic benefit costs for the years ended December 31, 2012 and 2011 for all plans: 
  

																	
	 	  	 	 	 	 	 	 	Post-Retirement and Post-	 
	 	  	Pension Benefits	 	 	Employment Benefits	 
	 Year ended December 31 (millions of dollars)
	  	2012	 	 	2011	 	 	2012	 	  	2011	 
	 Current service cost, net of employee contributions
	  	 	96	  	 	 	81	  	 	 	30	  	  	 	30	  
	 Interest cost
	  	 	285	  	 	 	286	  	 	 	63	  	  	 	67	  
	 Expected return on plan assets net of expenses
	  	 	(289	) 	 	 	(291	) 	 	 	—  	  	  	 	—  	  
	 Actuarial loss amortization
	  	 	112	  	 	 	68	  	 	 	8	  	  	 	7	  
	 Prior service cost amortization
	  	 	3	  	 	 	4	  	 	 	3	  	  	 	4	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	  	  
	  
	 
	 Net Periodic Benefit Cost
	  	 	207	  	 	 	148	  	 	 	104	  	  	 	108	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	  	  
	  
	 
	 Charged to results of operations1
	  	 	76	  	 	 	93	  	 	 	48	  	  	 	61	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	  	  
	  
	 

  

	1 	 The Company follows the cash basis of accounting consistent with the inclusion of pension costs in OEB-approved rates. During the year ended
December 31, 2012, pension costs of $163 million (2011 – $153 million) were attributed to labour, of which $76 million (2011 – $93 million) was charged to operations and $87 million (2011 – $60 million) was capitalized as part of
the cost of property, plant and equipment and intangible assets. 

 Assumptions 

The measurement of the obligations of the Plans and costs of providing benefits under Plans involves various factors, including the development of
valuation assumptions and accounting policy elections. When developing the required assumptions, the Company considers historical information as well as future expectations. The measurement of benefit obligations and costs is impacted by several
assumptions including the discount rate applied to benefit obligations, the long-term expected rate of return on plan assets, Hydro One’s expected level of contributions to the Plans, the incidence of mortality, the expected remaining service
period of plan participants, the level of compensation and rate of compensation increases, employee age, length of service, and the anticipated rate of increase of health care costs, among other factors. The impact of changes in assumptions used to
measure the obligations of the Plans is generally recognized over the expected 

  

					
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 HYDRO ONE INC. 
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) 
  

 
average remaining service period of the plan participants. In selecting the expected rate of return on plan assets, Hydro One considers historical economic indicators (including inflation and GDP
growth) that impact asset returns, as well as expectations regarding future long-term capital market performance, weighted by target asset class allocations. In general, equity securities, real estate and private equity investments are forecasted to
have higher returns than fixed income securities. 
 The following weighted average assumptions were used to determine the benefit obligations
and benefit expense at December 31, 2012 and 2011. Assumptions used to determine current year-end benefit obligations are the assumptions used to estimate the subsequent year’s net periodic benefit costs. 

 

																	
	 	  	 	 	 	 	 	 	Post-Retirement and Post-	 
	 	  	Pension Benefits	 	 	Employment Benefits	 
	 Year ended December 31
	  	2012	 	 	2011	 	 	2012	 	 	2011	 
	 Significant assumptions:
	  				 				 				 			
	 For net periodic benefit cost, year ended December 31:
	  				 				 				 			
	 Weighted average expected rate of return on plan assets
	  	 	6.25	% 	 	 	6.25	% 	 	 	—  	  	 	 	—  	  
	 Weighted average discount rate
	  	 	5.25	% 	 	 	5.75	% 	 	 	5.25	% 	 	 	5.75	% 
	 Rate of compensation scale escalation (without merit)
	  	 	2.50	% 	 	 	2.50	% 	 	 	2.50	% 	 	 	2.50	% 
	 Rate of cost of living increase
	  	 	2.00	% 	 	 	2.00	% 	 	 	2.00	% 	 	 	2.00	% 
	 Average remaining service life of employees (years)
	  	 	11	  	 	 	11	  	 	 	11	  	 	 	11	  
	 Rate of increase in health care cost trends1
	  	 	—  	  	 	 	—  	  	 	 	4.41	% 	 	 	4.91	% 
	 For projected benefit obligation, at December 31:
	  				 				 				 			
	 Weighted average discount rate
	  	 	4.25	% 	 	 	5.25	% 	 	 	4.25	% 	 	 	5.25	% 
	 Rate of compensation scale escalation (without merit)
	  	 	2.50	% 	 	 	2.50	% 	 	 	2.50	% 	 	 	2.50	% 
	 Rate of cost of living increase
	  	 	2.00	% 	 	 	2.00	% 	 	 	2.00	% 	 	 	2.00	% 
	 Rate of increase in health care cost trends2
	  	 	—  	  	 	 	—  	  	 	 	4.39	% 	 	 	4.41	% 

  

	1 	 7.03% per annum in 2012, grading down to 4.41% per annum in and after 2031 (2011 – 7.56% in 2011, grading down to 4.91% per annum
in and after 2029) 

	2 	 6.91% per annum in 2013, grading down to 4.39% per annum in and after 2031 (2011 – 7.03% in 2012, grading down to 4.41% per annum
in and after 2031) 

 The discount rate used to determine the current year pension obligation and the subsequent year’s
net periodic benefit costs is based on a yield curve approach. Under the yield curve approach, expected future benefit payments for each plan are discounted by a rate on a third party bond yield curve corresponding to each duration. The yield curve
is based on AA long-term corporate bonds. A single discount rate is calculated that would yield the same present value as the sum of the discounted cash flows. 
 The effect of 1% change in health care cost trends on the post-retirement and post-employment benefits is as follows: 
  

									
	 Year ended December 31 (millions of dollars)
	  	2012	 	 	2011	 
	 Effect of 1% increase in health care cost trends on:
	  				 			
	 Projected benefit obligation at December 31
	  	 	246	  	 	 	174	  
	 Service cost and interest cost
	  	 	17	  	 	 	20	  
	 Effect of 1% decrease in health care cost trends on:
	  				 			
	 Projected benefit obligation at December 31
	  	 	(191	) 	 	 	(138	) 
	 Service cost and interest cost
	  	 	(13	) 	 	 	(14	) 

  

					
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 HYDRO ONE INC. 
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) 
  

 Estimated Future Benefit Payments 
 At December 31, 2012, estimated future benefit payments by the Company to Plan participants were: 
  

									
	 	  	 	 	  	Post-Retirement and Post-	 
	 (millions of dollars)
	  	Pension Benefits	 	  	Employment Benefits	 
	 2013
	  	 	299	  	  	 	51	  
	 2014
	  	 	306	  	  	 	54	  
	 2015
	  	 	313	  	  	 	57	  
	 2016
	  	 	318	  	  	 	61	  
	 2017
	  	 	324	  	  	 	64	  
	 2018 through to 2022
	  	 	1,690	  	  	 	374	  
		  	  
	  
	 	  	  
	  
	 
	 Total estimated future benefit payments through to 2022
	  	 	3,250	  	  	 	661	  
		  	  
	  
	 	  	  
	  
	 

 Components of Regulatory Assets 
 A portion of actuarial gains and losses and prior service costs is recorded within regulatory assets on Hydro One’s Consolidated Balance Sheets to reflect the expected regulatory inclusion of these
amounts in future rates, which would otherwise be recorded in OCI. The following table provides the actuarial gains and losses and prior service costs recorded within regulatory assets: 

 

																	
	 	  	 	 	 	 	 	 	Post-Retirement and Post-	 
	 	  	Pension Benefits	 	 	Employment Benefits	 
	 Year ended December 31 (millions of dollars)
	  	2012	 	 	2011	 	 	2012	 	 	2011	 
	 Actuarial loss (gain) for the year
	  	 	807	  	 	 	558	  	 	 	203	  	 	 	(27	) 
	 Actuarial loss amortization
	  	 	(112	) 	 	 	(68	) 	 	 	(8	) 	 	 	(7	) 
	 Prior service cost amortization
	  	 	(3	) 	 	 	(4	) 	 	 	(3	) 	 	 	(3	) 
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
		  	 	   692	  	 	 	486	  	 	 	192	  	 	 	(37	) 
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 

 The following table provides the components of regulatory assets that have not been recognized as components of net
periodic benefit costs for the years ended December 31, 2012 and 2011: 
  

																	
	 	  	Pension Benefits	 	  	 Post-Retirement and Post-

Employment Benefits
	 
	 Year ended December 31 (millions of dollars)
	  	2012	 	  	2011	 	  	2012	 	  	2011	 
	 Prior service cost
	  	 	5	  	  	 	7	  	  	 	5	  	  	 	7	  
	 Actuarial loss
	  	 	1,510	  	  	 	772	  	  	 	315	  	  	 	116	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
		  	 	1,515	  	  	 	779	  	  	 	320	  	  	 	123	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 

 The following table provides the components of regulatory assets at December 31 that are expected to be amortized as
components of net periodic benefit costs in the following year: 
  

																	
	 	  	 	 	  	 	 	  	Post-Retirement and Post-	 
	 	  	Pension Benefits	 	  	Employment Benefits	 
	 Year ended December 31 (millions of dollars)
	  	2012	 	  	2011	 	  	2012	 	  	2011	 
	 Prior service cost
	  	 	2	  	  	 	3	  	  	 	3	  	  	 	3	  
	 Actuarial loss
	  	 	175	  	  	 	112	  	  	 	17	  	  	 	4	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
		  	 	   177	  	  	 	115	  	  	 	20	  	  	 	  7	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 

  

					
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 HYDRO ONE INC. 
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) 
  

 Pension Plan Assets 
 Investment Strategy 
 On a regular basis, Hydro One evaluates its investment strategy
to ensure that plan assets will be sufficient to pay Pension Plan benefits when due. As part of this ongoing evaluation, Hydro One may make changes to its targeted asset allocation and investment strategy. The Pension Plan is managed at a net asset
level. The main objective of the Pension Plan is to sustain a certain level of net assets in order to meet the pension obligations of the Company. The Pension Plan fulfills its primary objective by adhering to specific investment policies outlined
in its Summary of Investment Policies and Procedures (SIPP), which is reviewed and approved by the Investment-Pension Committee of Hydro One’s Board of Directors. The Company manages net assets by engaging knowledgeable external investment
managers who are charged with the responsibility of investing existing funds and new funds (current year’s employee and employer contributions) in accordance with the approved SIPP. The performance of the managers is monitored through a
governance structure. Increases in net assets are a direct result of investment income generated by investments held by the Pension Plan and contributions to the Pension Plan by eligible employees and by the Company. The main use of net assets is
for benefit payments to eligible Pension Plan members. 
 Pension Plan Asset Mix 

At December 31, 2012, the Pension Plan target asset allocations and weighted average asset allocations were as follows: 

 

									
	 December 31, 2012
	  	Target Allocation (%)	 	  	Pension Plan Assets (%)	 
	 Equity securities
	  	 	60.0	  	  	 	64.1	  
	 Debt securities
	  	 	35.0	  	  	 	35.8	  
	 Other 1
	  	 	5.0	  	  	 	0.1	  
		  	  
	  
	 	  	  
	  
	 
		  	 	100.0	  	  	 	100.0	  
		  	  
	  
	 	  	  
	  
	 

  

	1	 Other investments
include real estate and infrastructure investments. 

 At December 31, 2012, the Pension Plan held $20 million of Hydro
One corporate bonds (2011 – $27 million) and $243 million of debt securities of the Province (2011 – $214 million). 

Concentrations of Credit Risk 

Hydro One evaluated its Pension Plan’s asset portfolio for the existence of significant concentrations of credit risk as at December 31, 2012
and 2011. Concentrations that were evaluated include, but are not limited to, investment concentrations in a single entity, concentrations in a type of industry, and concentrations in individual funds. At December 31, 2012 and 2011, there were
no significant concentrations (defined as greater than 10% of plan assets) of risk in the Pension Plan’s assets. 
 The Pension Plan
manages its counterparty credit risk with respect to bonds by investing in investment-grade and government bonds and with respect to derivative instruments by transacting only with financial institutions rated at least “AA” by S&P or
“Aa2” by Moody’s Investors Service Inc. and also by utilizing exposure limits to each counterparty. The risk of default on transactions in listed securities is considered minimal, as the trade will fail if either party to the
transaction does not meet its obligation. 

  

					
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 HYDRO ONE INC. 
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) 
  

 Fair Value Measurements 
 The following table presents the Pension Plan assets measured and recorded at fair value on a recurring basis and their level within the fair value hierarchy at December 31, 2012 and 2011:

  

																	
	 December 31, 2012 (millions of dollars)
	  	Level 1	 	  	Level 2	 	  	Level 3	 	  	Total	 
	 Pooled funds
	  	 	2	  	  	 	15	  	  	 	104	  	  	 	121	  
	 Cash and cash equivalents
	  	 	125	  	  	 	—  	  	  	 	—  	  	  	 	125	  
	 Short-term securities
	  	 	—  	  	  	 	100	  	  	 	—  	  	  	 	100	  
	 Real estate
	  	 	—  	  	  	 	—  	  	  	 	2	  	  	 	2	  
	 Corporate shares – Canadian
	  	 	920	  	  	 	—  	  	  	 	—  	  	  	 	920	  
	 Corporate shares – Foreign
	  	 	2,077	  	  	 	—  	  	  	 	—  	  	  	 	2,077	  
	 Bonds and debentures – Canadian
	  	 	—  	  	  	 	1,643	  	  	 	—  	  	  	 	1,643	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Total fair value of plan assets1
	  	 	3,124	  	  	 	1,758	  	  	 	106	  	  	 	4,988	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 

  

	1 	 At December 31, 2012, the total fair value of Pension Plan assets excludes $16 million of interest and dividends receivable, $4 million relating to
accruals for pending sales transactions and $8 million relating to accruals for pension administration expense. 

  

																	
	 December 31, 2011 (millions of dollars)
	  	Level 1	 	  	Level 2	 	  	Level 3	 	  	Total	 
	 Pooled funds
	  	 	3	  	  	 	15	  	  	 	165	  	  	 	183	  
	 Cash and cash equivalents
	  	 	128	  	  	 	—  	  	  	 	—  	  	  	 	128	  
	 Short-term securities
	  	 	—  	  	  	 	38	  	  	 	—  	  	  	 	38	  
	 Real estate
	  	 	—  	  	  	 	—  	  	  	 	2	  	  	 	2	  
	 Corporate shares – Canadian
	  	 	820	  	  	 	—  	  	  	 	—  	  	  	 	820	  
	 Corporate shares – Foreign
	  	 	1,820	  	  	 	—  	  	  	 	—  	  	  	 	1,820	  
	 Bonds and debentures – Canadian
	  	 	—  	  	  	 	1,675	  	  	 	—  	  	  	 	1,675	  
	 Bonds and debentures – Foreign
	  	 	—  	  	  	 	1	  	  	 	—  	  	  	 	1	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Total fair value of plan assets1
	  	 	2,771	  	  	 	1,729	  	  	 	167	  	  	 	4,667	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 

  

	1 	 At December 31, 2011, the total fair value of Pension Plan assets excludes $17 million of interest and dividends receivable, $8 million of receivables
relating to pending sales transactions, and $10 million relating to accruals for pension administration expense. 

 See Note
12 – Fair Value of Financial Instruments and Risk Management for a description of levels within the fair value hierarchy. 
 Changes
in the Fair Value of Financial Instruments Classified in Level 3 
 The following table summarizes the changes in fair value of financial
instruments classified in Level 3 for the years ended December 31, 2012 and 2011. The Pension Plan classifies financial instruments as Level 3 when the fair value is measured based on at least one significant input that is not observable in the
markets or due to lack of liquidity in certain markets. The gains and losses presented in the table below may include changes in fair value based on both observable and unobservable inputs. 

 

									
	 Year ended December 31 (millions of dollars)
	  	2012	 	 	2011	 
	 Fair value, beginning of year
	  	 	167	  	 	 	167	  
	 Realized and unrealized gains
	  	 	5	  	 	 	18	  
	 Purchases
	  	 	6	  	 	 	9	  
	 Sales and disbursements
	  	 	(72	) 	 	 	(27	) 
		  	  
	  
	 	 	  
	  
	 
	 Fair value, end of year
	  	 	106	  	 	 	167	  
		  	  
	  
	 	 	  
	  
	 

 There have been no material transfers into or out of Level 3 of the fair value hierarchy. 

The Company performs sensitivity analysis for fair value measurements classified in Level 3, substituting the unobservable inputs with one or more
reasonably possible alternative assumptions. These sensitivity analyses resulted in negligible changes in the fair value of financial instruments classified in this level. 

  

					
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 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) 
  

 Valuation Techniques Used to Determine Fair Value 

Pooled Funds 
 The pooled fund category
mainly consists of private equity investments. Private equity investments represent private equity funds that invest in operating companies that are not publicly traded on a stock exchange. Investment strategies in private equity include limited
partnerships in businesses that are characterized by high internal growth and operational efficiencies, venture capital, leveraged buyouts and special situations such as distressed investments. Private equity valuations are reported by the fund
manager and are based on the valuation of the underlying investments which includes inputs such as cost, operating results, discounted future cash flows and market-based comparable data. Since these valuation inputs are not highly observable,
private equity investments have been categorized as Level 3 within pooled funds. 
 Cash Equivalents 

Demand cash deposits held with banks and cash held by the investment managers are considered cash equivalents and are included in the fair value
measurements hierarchy as Level 1. 
 Short-Term Securities 
 Short-term securities are valued at cost plus accrued interest, which approximates fair value due to their short-term nature. Short-term securities have been categorized as Level 2. 

Real Estate 
 Real estate investments
represent private equity investments in holding companies that invest in real estate properties. The investments in the holding companies are valued using net asset values reported by the fund manager. Real estate investments are categorized as
Level 3. 
 Corporate Shares 

Corporate shares are valued based on quoted prices in active markets and are categorized as Level 1. Investments denominated in foreign currencies are
translated into Canadian currency at year-end rates of exchange. 
 Bonds and Debentures 

Bonds and debentures are presented at published closing trade quotations, and are categorized as Level 2. 

15. ENVIRONMENTALLIABILITIES 
 The
Company has accrued the following discounted amounts for environmental liabilities on the Consolidated Balance Sheets at December 31, 2012 and 2011: 
  

													
	 December 31 (millions of dollars)
	  	PCB	 	 	LAR	 	 	Total	 
	 2012
	  				 				 			
	 Environmental liabilities, January 1
	  	 	199	  	 	 	58	  	 	 	257	  
	 Interest accretion
	  	 	9	  	 	 	2	  	 	 	11	  
	 Expenditures
	  	 	(8	) 	 	 	(10	) 	 	 	(18	) 
	 Revaluation adjustment
	  	 	(3	) 	 	 	2	  	 	 	(1	) 
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Environmental liabilities, December 31
	  	 	197	  	 	 	52	  	 	 	249	  
	 Less: current portion
	  	 	(13	) 	 	 	(9	) 	 	 	(22	) 
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 
		  	 	184	  	 	 	43	  	 	 	227	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 

  

					
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	 December 31 (millions of dollars)
	  	PCB	 	 	LAR	 	 	Total	 
	 2011
	  				 				 			
	 Environmental liabilities, January 1
	  	 	251	  	 	 	58	  	 	 	309	  
	 Interest accretion
	  	 	12	  	 	 	2	  	 	 	14	  
	 Expenditures
	  	 	(9	) 	 	 	(7	) 	 	 	(16	) 
	 Revaluation adjustment
	  	 	(55	) 	 	 	5	  	 	 	(50	) 
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Environmental liabilities, December 31
	  	 	199	  	 	 	58	  	 	 	257	  
	 Less: current portion
	  	 	(13	) 	 	 	(9	) 	 	 	(22	) 
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 
		  	 	186	  	 	 	49	  	 	 	235	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 

 The following table illustrates the reconciliation between the undiscounted basis of the environmental liabilities and
the amount recognized in the Consolidated Balance Sheets after factoring in the discount rate: 
  

													
	 December 31 (millions of dollars)
	  	PCB	 	 	LAR	 	 	Total	 
	 2012
	  				 				 			
	 Undiscounted environmental liabilities, December 31
	  	 	233	  	 	 	54	  	 	 	287	  
	 Less: discounting accumulated liabilities to present value
	  	 	(36	) 	 	 	(2	) 	 	 	(38	) 
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Discounted environmental liabilities, December 31
	  	 	197	  	 	 	52	  	 	 	249	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 

  

													
	 December 31 (millions of dollars)
	  	PCB	 	 	LAR	 	 	Total	 
	 2011
	  				 				 			
	 Undiscounted environmental liabilities, December 31
	  	 	242	  	 	 	61	  	 	 	303	  
	 Less: discounting accumulated liabilities to present value
	  	 	(43	) 	 	 	(3	) 	 	 	(46	) 
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Discounted environmental liabilities, December 31
	  	 	199	  	 	 	58	  	 	 	257	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 

 Estimated future environmental expenditures for each of the five years subsequent to December 31, 2012 and in total
thereafter are as follows: 2013 – $22 million; 2014 – $38 million; 2015 – $36 million; 2016 – $22 million; 2017 – $17 million; and thereafter – $152 million. At December 31, 2012, of the total estimated future
environmental expenditures, $233 million relate to PCB (2011 – $242 million) and $54 million relate to LAR (2011 – $61 million). 

Consistent with its accounting policy for environmental costs, Hydro One records a liability for the estimated mandatory future expenditures associated
with the removal and destruction of PCB-contaminated insulating oils and related electrical equipment and for the assessment and remediation of chemically-contaminated lands. 
 There are uncertainties in estimating future environmental costs due to potential external events such as changes in legislation or regulations and advances in remediation technologies. All factors used
in estimating the Company’s environmental liabilities represent management’s best estimates of the present value of the cost required to meet existing legislation or regulations. However, it is reasonably possible that numbers or volumes
of contaminated assets, cost estimates to perform work, inflation assumptions and the assumed pattern of annual cash flows may differ significantly from the Company’s current assumptions. In addition, with respect to the PCB environmental
liability, the availability of critical resources such as skilled labour and replacement assets and the ability to take maintenance outages in critical facilities may influence the timing of expenditures. Estimated environmental liabilities are
reviewed annually or more frequently if significant changes in regulation or other relevant factors occur. Estimate changes are accounted for prospectively. The Company records a regulatory asset reflecting its expectation that future environmental
costs will be recoverable in rates. 
 In determining the amounts to be recorded as environmental liabilities, the Company estimates the current
cost of completing required work and makes assumptions as to when the future expenditures will actually be incurred, in order to generate future cash flow information. A long-term inflation assumption of approximately 2% has been used to express
these current cost estimates as estimated future expenditures. Future environmental expenditures have been discounted using factors ranging from 3.75% to 6.25%, depending on the appropriate rate for the period when increases in the obligations were
first recorded. 

  

					
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 HYDRO ONE INC. 
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) 
  

 PCBs 
 In September 2008, Environment Canada published its final regulations governing the management, storage and disposal of PCBs. These regulations were enacted under the Canadian Environmental Protection
Act, 1999. These regulations impose timelines for disposal of PCBs based on certain criteria, including type of equipment, in-use status and PCB-contamination thresholds. All PCBs in concentrations of 500 parts per million (ppm) or more, except
for specified equipment, had to be disposed of by the end of 2009, with the exception of specifically exempted equipment. Under the regulations, PCBs in equipment in concentrations greater than 50 ppm and less than 500 ppm, or greater than 50 ppm
for pole-top transformers, pole-top auxiliary electrical equipment and light ballasts must be disposed of by the end of 2025. 
 Management
judges that the Company currently has very few PCB-contaminated assets in excess of 500 ppm. Assets to be disposed of by 2025 primarily consist of pole-mounted distribution line transformers and light ballasts. Contaminated distribution and
transmission station equipment will generally be replaced or will be decontaminated by removing PCB-contaminated insulating oil and retro filling with replacement oil that contains PCBs in concentrations of less than 2 ppm. 

The Company’s best estimate of the total estimated future expenditures to comply with current PCB regulations is approximately $233 million. These
expenditures are expected to be incurred over the period from 2013 to 2025. As a result of its most recent cost estimate to comply with current PCB regulations, the Company recorded a revaluation adjustment to reduce the PCB environmental liability
by approximately $3 million (2011 – $55 million). 
 LAR 
 The Company’s best estimate of the total estimated future expenditures to complete its LAR program is approximately $54 million. These expenditures are expected to be incurred over the period from
2013 to 2020. As part of its annual review of environmental liabilities, the Company also reviewed its liability for LAR. As a result of this review, the Company recorded a revaluation adjustment to increase the LAR environmental liability by
approximately $2 million (2011 – $5 million). 
 16. ASSET RETIREMENT OBLIGATIONS 

AROs, which represent legal obligations associated with the retirement of certain tangible long-lived assets, are computed as the present value of the
projected expenditures for the future retirement of specific assets and are recognized in the period in which the liability is incurred, if a reasonable estimate of fair value can be made. If the asset remains in service at the recognition date, the
present value of the liability is added to the carrying amount of the associated asset in the period the liability is incurred and this additional carrying amount is depreciated over the remaining life of the asset. If an ARO is recorded in respect
of an out-of-service asset, the asset retirement cost is charged to results of operations. Subsequent to the initial recognition, the liability is adjusted for any revisions to the estimated future cash flows associated with the ARO (with
corresponding adjustments to property, plant and equipment), which can occur due to a number of factors including, but not limited to, cost escalation, changes in technology applicable to the assets to be retired and changes in federal, state or
local regulations, as well as for accretion of the liability due to the passage of time until the obligation is settled. Depreciation expense is adjusted prospectively for any increases or decreases to the carrying amount of the associated asset.

 All factors used in estimating the Company’s AROs represent management’s best estimates of the costs required to meet existing
legislation or regulations. However, it is reasonably possible that numbers or volumes of contaminated assets, cost estimates to perform work, inflation assumptions and the assumed pattern of annual cash flows may differ significantly from the
Company’s current assumptions. AROs are reviewed annually or more frequently if significant changes in regulation or other relevant factors occur. Estimate changes are accounted for prospectively. 

In determining the amounts to be recorded as AROs, the Company estimates the current fair value for completing required removal and remediation work and
makes assumptions as to when the future expenditures will actually be incurred, in order to generate future cash flow information. A long-term inflation assumption of approximately 2% has been used to express these current cost estimates as
estimated future expenditures. Future expenditures have been discounted using factors ranging from approximately 3% to 5%, depending on the appropriate rate for the period when expenditures are expected to be incurred. 

At December 31, 2012, Hydro One had recorded AROs of $15 million (2011 – $15 million), consisting of $7 million (2011 – $7 million)
related to the estimated future expenditures associated with the removal and disposal of asbestos-containing materials installed in some of its facilities, as well as $8 million (2011 – $8 million) related to the future decommissioning and
removal of two of its switching stations. 

  

					
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 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) 
  

 The Company’s liability for the estimated future expenditures associated with the removal and
disposal of asbestos-containing materials installed in some of its facilities is based on management’s best estimate of the present value of the estimated future expenditures to comply with current regulations. In 2010, the Company completed a
study with the aid of an expert external consultant to estimate the future expenditures required to remove asbestos prior to facility demolition. The amount of interest recorded is nominal and there have been no expenditures associated with these
obligations to date. 
 In 2011, Hydro One recorded an ARO of $4 million related to the future decommissioning and removal of one of its
switching stations, in addition to the ARO of $4 million recorded in a prior year related to the future decommissioning and removal of another switching station. The amount of interest recorded is nominal and there have been no expenditures
associated with these obligations to date. 
 17. SHARE CAPITAL 
 Preferred Shares 
 The Company has 12,920,000 issued and outstanding 5.5% cumulative
preferred shares with a redemption value of $25 per share or $323 million total value. The Company is authorized to issue an unlimited number of preferred shares. 
 The Company’s preferred shares are entitled to an annual cumulative dividend of $18 million, or $1.375 per share, which is payable on a quarterly basis. The preferred shares are not subject to
mandatory redemption (except on liquidation) but are redeemable in certain circumstances. The shares are redeemable at the option of the Province at the redemption value, plus any accrued and unpaid dividends, if the Province sells a number of the
common shares which it owns to the public such that the Province’s holdings are reduced to less than 50% of the common shares of the Company. Hydro One may elect, without condition, to pay all or part of the redemption price by issuing
additional common shares to the Province. If the Province does not exercise its redemption right, the Company would have the ability to adjust the dividend on the preferred shares to produce a yield that is 0.50% less than the then-current dividend
market yield for similarly rated preferred shares. The preferred shares do not carry voting rights, except in limited circumstances, and would rank in priority over the common shares upon liquidation. 

These preferred shares have conditions for their redemption that are outside the control of the Company because the Province can exercise its right to
redeem in the event of change in ownership without approval of the Company’s Board of Directors. Because the conditional redemption feature is outside the control of the Company, the preferred shares are classified outside of Shareholder’s
Equity on the Consolidated Balance Sheets. Management believes that it is not probable that the preferred shares will become redeemable. No adjustment to the carrying value of the preferred shares has been recognized at December 31, 2012. If it
becomes probable in the future that the preferred shares will be redeemed, the redemption value would be adjusted. 
 Common Shares

 The Company has 100,000 issued and outstanding common shares. The Company is authorized to issue an unlimited number of common shares.

 Common share dividends are declared at the sole discretion of the Hydro One Board of Directors, and are recommended by management based on
results of operations, maintenance of the deemed regulatory capital structure, financial conditions, cash requirements, and other relevant factors, such as industry practice and shareholder expectations. 

Earnings per Share 
 Earnings per share
is calculated as net income for the year, after cumulative preferred dividends, divided by the weighted average number of common shares outstanding during the year. 

  

					
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 18. DIVIDENDS 
 In 2012, preferred share dividends in the amount of $18 million (2011 – $18 million) and common share dividends in the amount of $352 million (2011 – $150 million) were declared. 

19. RELATED PARTY TRANSACTIONS 
 Hydro
One is owned by the Province. The OEFC, IESO, Ontario Power Authority (OPA), Ontario Power Generation Inc. (OPG) and the OEB are related parties to Hydro One because they are controlled or significantly influenced by the Province. Transactions
between these parties and Hydro One were as follows: 
 Hydro One received revenue for transmission services from the IESO, based on uniform
transmission rates approved by the OEB. Transmission revenues include $1,474 million (2011 – $1,366 million) related to these services. Hydro One receives amounts for rural rate protection from the IESO. Distribution revenues include $127
million (2011 – $127 million) related to this program. In 2012, Hydro One also received revenue related to the supply of electricity to remote northern communities from the IESO. Distribution revenues include $28 million (2011 – $28
million) related to these services. 
 In 2012, Hydro One purchased power in the amount of $2,392 million (2011 – $2,401 million) from the
IESO-administered electricity market; $10 million (2011 – $16 million) from OPG; and $7 million (2011 – $10 million) from the OEFC. 

Under the Ontario Energy Board Act, 1998, the OEB is required to recover all of its annual operating costs from gas and electricity distributors
and transmitters. In 2012, Hydro One incurred $11 million (2011 – $11 million) in OEB fees. 
 Hydro One has service level agreements with
OPG. These services include field, engineering, logistics and telecommunications services. In 2012, revenues related to the provision of construction and equipment maintenance services with respect to these service level agreements were $10 million
(2011 – $7 million), primarily for the Transmission Business. Operation, maintenance and administration costs related to the purchase of services with respect to these service level agreements were $2 million in 2012 (2011 – $2 million).

 The OPA funds substantially all of the Company’s Conservation and Demand Management (CDM) programs. The funding includes program costs,
incentives, and management fees. In 2012, Hydro One received $39 million (2011 – $39 million) from the OPA related to the CDM programs. 

The provision for PILs and payments in lieu of property taxes were paid or payable to the OEFC, and dividends were paid or payable to the Province.

 Sales to and purchases from related parties occur at normal market prices or at a proxy for fair value based on the requirements of the
OEB’s Affiliate Relationships Code. Outstanding balances at period end are unsecured, interest free and settled in cash. At December 31, 2012, the Company held Province of Ontario Floating-Rate Notes with a fair value of $251 million (2011
– $250 million). 
 The amounts due to and from related parties as a result of the transactions referred to above are as follows:

  

									
	 December 31 (millions of dollars)
	  	2012	 	 	2011	 
	 Due from related parties
	  	 	154	  	 	 	156	  
	 Due to related parties1
	  	 	(257	) 	 	 	(342	) 
	 Long-term investment
	  	 	251	  	 	 	250	  

  

	1 	 Included in due to related parties at December 31, 2012 are amounts owing to the IESO in respect of power purchases of $199 million (2011 – $209
million). 

  

					
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 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) 
  

 20. CONSOLIDATED STATEMENTS OF CASH FLOWS 

The changes in non-cash balances related to operations consist of the following: 

 

									
	 Year ended December 31 (millions of dollars)
	  	2012	 	 	2011	 
	 Accounts receivable
	  	 	(30	) 	 	 	(18	) 
	 Due from related parties
	  	 	2	  	 	 	(32	) 
	 Materials and supplies
	  	 	2	  	 	 	(4	) 
	 Other assets
	  	 	(4	) 	 	 	(11	) 
	 Accounts payable
	  	 	(14	) 	 	 	29	  
	 Accrued liabilities
	  	 	10	  	 	 	98	  
	 Due to related parties
	  	 	(85	) 	 	 	61	  
	 Accrued interest
	  	 	10	  	 	 	1	  
	 Long-term accounts payable and other liabilities
	  	 	13	  	 	 	—  	  
	 Post-retirement and post-employment benefit liability
	  	 	56	  	 	 	60	  
		  	  
	  
	 	 	  
	  
	 
		  	 	(40	) 	 	 	184	  
		  	  
	  
	 	 	  
	  
	 
	 Supplementary information:
	  				 			
	 Net interest paid
	  	 	411	  	 	 	410	  
	 Payments in lieu of corporate income taxes
	  	 	197	  	 	 	80	  

 21. CONTINGENCIES 
 Legal Proceedings 
 Hydro One is involved in various lawsuits, claims and regulatory
proceedings in the normal course of business. In the opinion of management, the outcome of such matters will not have a material adverse effect on the Company’s consolidated financial position, results of operations or cash flows. 

Transfer of Assets 
 The transfer
orders by which the Company acquired certain of Ontario Hydro’s businesses as of April 1, 1999 did not transfer title to some assets located on Reserves (as defined in the Indian Act (Canada)). Currently, the OEFC holds these
assets. Under the terms of the transfer orders, the Company is required to manage these assets until it has obtained all consents necessary to complete the transfer of title of these assets to itself. The Company cannot predict the aggregate amount
that it may have to pay, either on an annual or one-time basis, to obtain the required consents. However, the Company anticipates having to pay more than the $1 million that it paid in 2012. If the Company cannot obtain the required consents, the
OEFC will continue to hold these assets for an indefinite period of time. If the Company cannot reach a satisfactory settlement, it may have to relocate these assets to other locations at a cost that could be substantial or, in a limited number of
cases, to abandon a line and replace it with diesel-generation facilities. The costs relating to these assets could have a material adverse effect on the Company’s results of operations if the Company is not able to recover them in future rate
orders. 
 22. COMMITMENTS 

Agreement with Inergi LP (Inergi) 

Effective March 1, 2002, Inergi, a wholly-owned subsidiary of Cap Gemini Canada Inc., began providing services to Hydro One. On May 1, 2010,
consistent with the terms of the contract, the Company extended the Master Services Agreement with Inergi for a further three-year period. This agreement will expire on February 28, 2015. As a result of this agreement, Hydro One receives from
Inergi a range of services including business processing and information technology outsourcing services, as well as core system support related primarily to SAP implementation and optimization. Inergi billings for these services have ranged between
$93 million and $130 million per year and are subject to external benchmarking every three years to ensure Hydro One is receiving a defined, competitive and continuously improved price. 

  

					
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 At December 31, 2012, the annual commitments under the Inergi agreement are as follows: 2013 –
$136 million; 2014 – $130 million; 2015 – $21 million; 2016 and thereafter – nil. 
 Prudential Support 

Purchasers of electricity in Ontario, through the IESO, are required to provide security to mitigate the risk of their default based on their expected
activity in the market. As at December 31, 2012, the Company provided prudential support to the IESO on behalf of Hydro One Networks and Hydro One Brampton Networks using parental guarantees of $325 million (2011 – $325 million), and on
behalf of two distributors using guarantees of $0.7 million (2011 – $0.7 million). On April 27, 2012, Hydro One’s highest credit rating declined from the “Aa” category to the “A” category. Based on the new credit
rating category, the Company has provided letters of credit in the amount of $22 million to the IESO. The IESO could draw on these guarantees and/or letters of credit if these subsidiaries or distributors fail to make a payment required by a default
notice issued by the IESO. The maximum potential payment is the face value of any letters of credit plus the nominal amount of the parental guarantees. 
 Retirement Compensation Arrangements 
 Bank letters of credit have been issued to
provide security for the Company’s liability under the terms of a trust fund established pursuant to the supplementary pension plan for the employees of Hydro One and its subsidiaries. The supplementary pension plan trustee is required to draw
upon these letters of credit if Hydro One is in default of its obligations under the terms of this plan. Such obligations include the requirement to provide the trustee with an annual actuarial report as well as letters of credit sufficient to
secure the Company’s liability under the plan, to pay benefits payable under the plan and to pay the letter of credit fee. The maximum potential payment is the face value of the letters of credit. At December 31, 2012, Hydro One had
letters of credit of $127 million (2011 – $124 million) outstanding relating to retirement compensation arrangements. 
 Operating
Leases 
 Hydro One is committed as lessee to irrevocable operating lease contracts for buildings used in administrative and service
related functions and storing telecommunication equipment. These leases have an average life of between one and five years with renewal options for periods ranging from one to 10 years included in some of the contracts. All leases include a clause
to enable upward revision of the rental charge on an annual basis or on renewal according to prevailing market conditions. There are no restrictions placed upon Hydro One by entering into these leases. Hydro One Networks and Hydro One Telecom are
the principal entities concerned. 
 At December 31, 2012, the future minimum lease payments under non-cancellable operating leases were as
follows: 
  

									
	 December 31 (millions of dollars)
	  	2012	 	  	2011	 
	 Within one year
	  	 	10	  	  	 	8	  
	 After one year but not more than five years
	  	 	29	  	  	 	26	  
	 More than five years
	  	 	14	  	  	 	20	  
		  	  
	  
	 	  	  
	  
	 
		  	 	53	  	  	 	54	  
		  	  
	  
	 	  	  
	  
	 

 During the year ended December 31, 2012, the Company made lease payments totaling $9 million (2011 – $6
million). 

  

					
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 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) 
  

 23. SEGMENTED REPORTING 
 Hydro One has three reportable segments: 
  

	•	 	 The Transmission Business, which comprises the core business of providing electricity transportation and connection services, is responsible for
transmitting electricity throughout the Ontario electricity grid; 

  

	•	 	 The Distribution Business, which comprises the core business of delivering and selling electricity to customers; and 

 

	•	 	 Other, the operations of which primarily consist of those of the telecommunications business. 

The designation of segments has been based on a combination of regulatory status and the nature of the products and services provided. Operating segments
for the Company are determined based on information used by the chief operating decision maker in deciding how to allocate resources and evaluate the performance at each of the segments. The Company evaluates segment performance based on income
before financing charges and provision for PILs from continuing operations (excluding certain allocated corporate governance costs). 
 The
accounting policies followed by the segments are the same as those described in the summary of significant accounting policies (see Note 2 – Significant Accounting Policies). Segment information on the above basis is as follows: 

 

																	
	 Year ended December 31, 2012 (millions of dollars)
	  	Transmission	 	  	Distribution	 	  	Other	 	 	Consolidated	 
	 Segment profit
	  				  				  				 			
	 Revenues
	  	 	1,482	  	  	 	4,184	  	  	 	62	  	 	 	5,728	  
	 Purchased power
	  	 	—  	  	  	 	2,774	  	  	 	—  	  	 	 	2,774	  
	 Operation, maintenance and administration
	  	 	402	  	  	 	608	  	  	 	61	  	 	 	1,071	  
	 Depreciation and amortization
	  	 	320	  	  	 	329	  	  	 	10	  	 	 	659	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 
	 Income (loss) before financing charges and provision for PILs
	  	 	760	  	  	 	473	  	  	 	(9	) 	 	 	1,224	  
	 Financing charges
	  				  				  				 	 	358	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 
	 Income before provision for PILs
	  				  				  				 	 	866	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 
	 Capital expenditures
	  	 	776	  	  	 	671	  	  	 	7	  	 	 	1,454	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 

  

																	
	 Year ended December 31, 2011 (millions of dollars)
	  	Transmission	 	  	Distribution	 	  	Other	 	 	Consolidated	 
	 Segment profit
	  				  				  				 			
	 Revenues
	  	 	1,389	  	  	 	4,019	  	  	 	63	  	 	 	5,471	  
	 Purchased power
	  	 	—  	  	  	 	2,628	  	  	 	—  	  	 	 	2,628	  
	 Operation, maintenance and administration
	  	 	422	  	  	 	609	  	  	 	61	  	 	 	1,092	  
	 Depreciation and amortization
	  	 	302	  	  	 	304	  	  	 	10	  	 	 	616	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 
	 Income (loss) before financing charges and provision for PILs
	  	 	665	  	  	 	478	  	  	 	(8	) 	 	 	1,135	  
	 Financing charges
	  				  				  				 	 	344	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 
	 Income before provision for PILs
	  				  				  				 	 	791	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 
	 Capital expenditures
	  	 	810	  	  	 	628	  	  	 	9	  	 	 	1,447	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 

  

									
	 December 31 (millions of dollars)
	  	2012	 	  	2011	 
	 Total assets
	  				  			
	 Transmission
	  	 	11,586	  	  	 	10,589	  
	 Distribution
	  	 	8,621	  	  	 	7,594	  
	 Other
	  	 	604	  	  	 	653	  
		  	  
	  
	 	  	  
	  
	 
		  	 	20,811	  	  	 	18,836	  
		  	  
	  
	 	  	  
	  
	 

 All revenues, costs and assets, as the case may be, are earned, incurred or held in Canada. 

  

					
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 24. TRANSITION TO US GAAP 
 The adoption of US GAAP has been made on a retrospective basis with restatement of comparative information to reflect US GAAP requirements in effect at that time. The Company’s transition
date to US GAAP is January 1, 2011, which is the commencement of the 2011 comparative period to the Company’s 2012 Consolidated Financial Statements. 
 Measurement and classification differences resulting from Hydro One’s adoption of US GAAP are presented below. With respect to measurement and classification differences, the tables under the
heading US GAAP Differences represent quantitative reconciliations of the Consolidated Balance Sheets and the Consolidated Statements of Changes in Shareholder’s Equity, previously presented in accordance with Canadian GAAP, to the
respective amounts and classifications under US GAAP, together with descriptions of the various significant measurement and classification differences arising from the adoption of US GAAP. Consolidated Balance Sheets and Consolidated Statements
of Changes in Shareholder’s Equity reconciliations are presented as at January 1, 2011 and December 31, 2011, representing the commencement and ending dates of the comparative financial year to 2012. There were no measurement or
classification differences resulting from Hydro One’s adoption of US GAAP on the Consolidated Statements of Operations and Comprehensive Income. 
 Except as otherwise disclosed in this note, the change in basis of accounting from Canadian GAAP to US GAAP did not materially impact accounting policies or disclosures. Reference should be made to
the previously filed Canadian GAAP Consolidated Financial Statements as at and for the year ended December 31, 2011 for additional information on Canadian GAAP accounting policies and practices. 

The following table summarizes the increases (decreases) to total assets: 

 

													
	 (millions of dollars)
	  	Notes	 	  	January 1, 2011	 	 	December 31, 2011	 
	 Total assets – Canadian GAAP
	  				  	 	17,322	  	 	 	18,368	  
	 Deferred debt costs
	  	 	A	  	  	 	32	  	 	 	32	  
	 Deferred pension asset
	  	 	B	  	  	 	(460	) 	 	 	(466	) 
	 Regulatory assets
	  	 	B	  	  	 	450	  	 	 	902	  
		  				  	  
	  
	 	 	  
	  
	 
	 Total assets – US GAAP
	  				  	 	17,344	  	 	 	18,836	  
		  				  	  
	  
	 	 	  
	  
	 

 The following table summarizes the increases (decreases) to total liabilities: 

 

													
	 (millions of dollars)
	  	Notes	 	  	January 1, 2011	 	 	December 31, 2011	 
	 Total liabilities – Canadian GAAP
	  				  	 	11,341	  	 	 	11,914	  
	 Long-term debt
	  	 	A	  	  	 	5	  	 	 	9	  
	 Net unamortized debt premiums
	  	 	A	  	  	 	27	  	 	 	23	  
	 Pension benefit liability
	  	 	B	  	  	 	297	  	 	 	779	  
	 Post-retirement and post-employment benefit liability
	  	 	B	  	  	 	153	  	 	 	123	  
	 Regulatory liabilities
	  	 	B	  	  	 	(460	) 	 	 	(466	) 
		  				  	  
	  
	 	 	  
	  
	 
	 Total liabilities – US GAAP
	  				  	 	11,363	  	 	 	12,382	  
		  				  	  
	  
	 	 	  
	  
	 

  

					
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 US GAAP Differences 
 The reconciliations of the January 1, 2011 and December 31, 2011 Consolidated Balance Sheets from Canadian GAAP to US GAAP are as follows: 

 

																	
	 January 1, 2011 (millions of dollars)
	  	Notes	 	  	Canadian
GAAP	 	  	Effect of
transition to
US GAAP	 	 	US GAAP	 
	 Assets
	  				  				  				 			
	 Current assets:
	  				  				  				 			
	 Cash
	  				  	 	33	  	  	 	—  	  	 	 	33	  
	 Short-term investments
	  				  	 	139	  	  	 	—  	  	 	 	139	  
	 Accounts receivable
	  	 	F	  	  	 	911	  	  	 	(124	) 	 	 	787	  
	 Due from related parties
	  	 	F	  	  	 	—  	  	  	 	124	  	 	 	124	  
	 Regulatory assets
	  				  	 	42	  	  	 	—  	  	 	 	42	  
	 Materials and supplies
	  				  	 	21	  	  	 	—  	  	 	 	21	  
	 Deferred income tax assets
	  				  	 	35	  	  	 	—  	  	 	 	35	  
	 Derivative instruments
	  	 	C	  	  	 	—  	  	  	 	1	  	 	 	1	  
	 Other
	  	 	C	  	  	 	8	  	  	 	(1	) 	 	 	7	  
		  				  	  
	  
	 	  	  
	  
	 	 	  
	  
	 
		  				  	 	1,189	  	  	 	—  	  	 	 	1,189	  
		  				  	  
	  
	 	  	  
	  
	 	 	  
	  
	 
	 Property, plant and equipment:
	  				  				  				 			
	 Property, plant and equipment in service
(net of accumulated depreciation)
	  				  	 	12,520	  	  	 	—  	  	 	 	12,520	  
	 Construction in progress
	  				  	 	1,402	  	  	 	—  	  	 	 	1,402	  
	 Future use land, components and spares
	  				  	 	139	  	  	 	—  	  	 	 	139	  
		  				  	  
	  
	 	  	  
	  
	 	 	  
	  
	 
		  				  	 	14,061	  	  	 	—  	  	 	 	14,061	  
		  				  	  
	  
	 	  	  
	  
	 	 	  
	  
	 
	 Other long-term assets:
	  				  				  				 			
	 Regulatory assets
	  	 	B	  	  	 	1,013	  	  	 	450	  	 	 	1,463	  
	 Deferred pension asset
	  	 	B	  	  	 	460	  	  	 	(460	) 	 	 	—  	  
	 Long-term investment
	  				  	 	249	  	  	 	—  	  	 	 	249	  
	 Intangible assets (net of accumulated amortization)
	  				  	 	189	  	  	 	—  	  	 	 	189	  
	 Goodwill
	  				  	 	133	  	  	 	—  	  	 	 	133	  
	 Deferred debt costs
	  	 	A	  	  	 	—  	  	  	 	32	  	 	 	32	  
	 Derivative instruments
	  	 	C	  	  	 	—  	  	  	 	7	  	 	 	7	  
	 Deferred income tax assets
	  				  	 	19	  	  	 	—  	  	 	 	19	  
	 Other
	  	 	C	  	  	 	9	  	  	 	(7	) 	 	 	2	  
		  				  	  
	  
	 	  	  
	  
	 	 	  
	  
	 
		  				  	 	2,072	  	  	 	22	  	 	 	2,094	  
		  				  	  
	  
	 	  	  
	  
	 	 	  
	  
	 
	 Total assets
	  				  	 	17,322	  	  	 	22	  	 	 	17,344	  
		  				  	  
	  
	 	  	  
	  
	 	 	  
	  
	 

  

					
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	 January 1, 2011 (millions of dollars)
	  	Notes	 	  	Canadian
GAAP	 	 	Effect of

transition to
US GAAP	 	 	US GAAP	 
	 Liabilities
	  				  				 				 			
	 Current liabilities:
	  				  				 				 			
	 Accounts payable and accrued charges
	  	 	D, F	  	  	 	884	  	 	 	(884	) 	 	 	—  	  
	 Accounts payable
	  	 	D	  	  	 	—  	  	 	 	125	  	 	 	125	  
	 Accrued liabilities
	  	 	D	  	  	 	—  	  	 	 	478	  	 	 	478	  
	 Due to related parties
	  	 	F	  	  	 	—  	  	 	 	281	  	 	 	281	  
	 Accrued interest
	  				  	 	84	  	 	 	—  	  	 	 	84	  
	 Regulatory liabilities
	  				  	 	72	  	 	 	—  	  	 	 	72	  
	 Long-term debt payable within one year
	  				  	 	500	  	 	 	—  	  	 	 	500	  
		  				  	  
	  
	 	 	  
	  
	 	 	  
	  
	 
		  				  	 	1,540	  	 	 	—  	  	 	 	1,540	  
		  				  	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Long-term debt
	  	 	A	  	  	 	7,278	  	 	 	5	  	 	 	7,283	  
		  				  	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Other long-term liabilities:
	  				  				 				 			
	 Post-retirement and post-employment benefit liability
	  	 	B	  	  	 	980	  	 	 	153	  	 	 	1,133	  
	 Deferred income tax liabilities
	  				  	 	693	  	 	 	—  	  	 	 	693	  
	 Pension benefit liability
	  	 	B	  	  	 	—  	  	 	 	297	  	 	 	297	  
	 Environmental liabilities
	  				  	 	287	  	 	 	—  	  	 	 	287	  
	 Regulatory liabilities
	  	 	B	  	  	 	540	  	 	 	(460	) 	 	 	80	  
	 Net unamortized debt premiums
	  	 	A	  	  	 	—  	  	 	 	27	  	 	 	27	  
	 Asset retirement obligations
	  				  	 	11	  	 	 	—  	  	 	 	11	  
	 Long-term accounts payable and other liabilities
	  				  	 	12	  	 	 	—  	  	 	 	12	  
		  				  	  
	  
	 	 	  
	  
	 	 	  
	  
	 
		  				  	 	2,523	  	 	 	17	  	 	 	2,540	  
		  				  	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Total liabilities
	  				  	 	11,341	  	 	 	22	  	 	 	11,363	  
		  				  	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Preferred shares
	  	 	E	  	  	 	—  	  	 	 	323	  	 	 	323	  
	 Shareholder’s equity
	  				  				 				 			
	 Preferred shares
	  	 	E	  	  	 	323	  	 	 	(323	) 	 	 	—  	  
	 Common shares
	  				  	 	3,314	  	 	 	—  	  	 	 	3,314	  
	 Retained earnings
	  				  	 	2,354	  	 	 	—  	  	 	 	2,354	  
	 Accumulated other comprehensive loss
	  				  	 	(10	) 	 	 	—  	  	 	 	(10	) 
		  				  	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Total shareholder’s equity
	  				  	 	5,981	  	 	 	(323	) 	 	 	5,658	  
		  				  	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Total liabilities, preferred shares and shareholder’s equity
	  				  	 	17,322	  	 	 	22	  	 	 	17,344	  
		  				  	  
	  
	 	 	  
	  
	 	 	  
	  
	 

  

					
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 HYDRO ONE INC. 
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) 
  

																	
	 December 31, 2011 (millions of dollars)
	  	Notes	 	  	Canadian
GAAP	 	  	Effect of
transition to
US GAAP	 	 	US GAAP	 
	 Assets
	  				  				  				 			
	 Current assets:
	  				  				  				 			
	 Short-term investments
	  				  	 	228	  	  	 	—  	  	 	 	228	  
	 Accounts receivable
	  	 	F	  	  	 	961	  	  	 	(156	) 	 	 	805	  
	 Due from related parties
	  	 	F	  	  	 	—  	  	  	 	156	  	 	 	156	  
	 Regulatory assets
	  				  	 	24	  	  	 	—  	  	 	 	24	  
	 Materials and supplies
	  				  	 	25	  	  	 	—  	  	 	 	25	  
	 Deferred income tax assets
	  				  	 	19	  	  	 	—  	  	 	 	19	  
	 Derivative instruments
	  	 	C	  	  	 	—  	  	  	 	1	  	 	 	1	  
	 Other
	  	 	C	  	  	 	20	  	  	 	(1	) 	 	 	19	  
		  				  	  
	  
	 	  	  
	  
	 	 	  
	  
	 
		  				  	 	1,277	  	  	 	—  	  	 	 	1,277	  
		  				  	  
	  
	 	  	  
	  
	 	 	  
	  
	 
	 Property, plant and equipment:
	  				  				  				 			
	 Property, plant and equipment in service
(net of accumulated depreciation)
	  				  	 	13,329	  	  	 	—  	  	 	 	13,329	  
	 Construction in progress
	  				  	 	1,436	  	  	 	—  	  	 	 	1,436	  
	 Future use land, components and spares
	  				  	 	138	  	  	 	—  	  	 	 	138	  
		  				  	  
	  
	 	  	  
	  
	 	 	  
	  
	 
		  				  	 	14,903	  	  	 	—  	  	 	 	14,903	  
		  				  	  
	  
	 	  	  
	  
	 	 	  
	  
	 
	 Other long-term assets:
	  				  				  				 			
	 Regulatory assets
	  	 	B	  	  	 	1,064	  	  	 	902	  	 	 	1,966	  
	 Deferred pension asset
	  	 	B	  	  	 	466	  	  	 	(466	) 	 	 	—  	  
	 Long-term investment
	  				  	 	250	  	  	 	—  	  	 	 	250	  
	 Intangible assets (net of accumulated amortization)
	  				  	 	224	  	  	 	—  	  	 	 	224	  
	 Goodwill
	  				  	 	133	  	  	 	—  	  	 	 	133	  
	 Deferred debt costs
	  	 	A	  	  	 	—  	  	  	 	32	  	 	 	32	  
	 Derivative instruments
	  	 	C	  	  	 	—  	  	  	 	33	  	 	 	33	  
	 Deferred income tax assets
	  				  	 	17	  	  	 	—  	  	 	 	17	  
	 Other
	  	 	C	  	  	 	34	  	  	 	(33	) 	 	 	1	  
		  				  	  
	  
	 	  	  
	  
	 	 	  
	  
	 
		  				  	 	2,188	  	  	 	468	  	 	 	2,656	  
		  				  	  
	  
	 	  	  
	  
	 	 	  
	  
	 
	 Total assets
	  				  	 	18,368	  	  	 	468	  	 	 	18,836	  
		  				  	  
	  
	 	  	  
	  
	 	 	  
	  
	 

  

					
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 HYDRO ONE INC. 
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) 
  

																	
	 December 31, 2011 (millions of dollars)
	  	Notes	 	  	Canadian
GAAP	 	 	Effect of
transition to
US GAAP	 	 	US GAAP	 
	 Liabilities
	  				  				 				 			
	 Current liabilities:
	  				  				 				 			
	 Bank indebtedness
	  				  	 	39	  	 	 	—  	  	 	 	39	  
	 Accounts payable and accrued charges
	  	 	D, F	  	  	 	1,071	  	 	 	(1,071	) 	 	 	—  	  
	 Accounts payable
	  	 	D	  	  	 	—  	  	 	 	154	  	 	 	154	  
	 Accrued liabilities
	  	 	D	  	  	 	—  	  	 	 	575	  	 	 	575	  
	 Due to related parties
	  	 	F	  	  	 	—  	  	 	 	342	  	 	 	342	  
	 Accrued interest
	  				  	 	85	  	 	 	—  	  	 	 	85	  
	 Regulatory liabilities
	  				  	 	25	  	 	 	—  	  	 	 	25	  
	 Long-term debt payable within one year
	  				  	 	600	  	 	 	—  	  	 	 	600	  
		  				  	  
	  
	 	 	  
	  
	 	 	  
	  
	 
		  				  	 	1,820	  	 	 	—  	  	 	 	1,820	  
		  				  	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Long-term debt
	  	 	A	  	  	 	7,399	  	 	 	9	  	 	 	7,408	  
		  				  	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Other long-term liabilities:
	  				  				 				 			
	 Post-retirement and post-employment benefit liability
	  	 	B	  	  	 	1,040	  	 	 	123	  	 	 	1,163	  
	 Deferred income tax liabilities
	  				  	 	758	  	 	 	—  	  	 	 	758	  
	 Pension benefit liability
	  	 	B	  	  	 	—  	  	 	 	779	  	 	 	779	  
	 Environmental liabilities
	  				  	 	235	  	 	 	—  	  	 	 	235	  
	 Regulatory liabilities
	  	 	B	  	  	 	635	  	 	 	(466	) 	 	 	169	  
	 Net unamortized debt premiums
	  	 	A	  	  	 	—  	  	 	 	23	  	 	 	23	  
	 Asset retirement obligations
	  				  	 	15	  	 	 	—  	  	 	 	15	  
	 Long-term accounts payable and other liabilities
	  				  	 	12	  	 	 	—  	  	 	 	12	  
		  				  	  
	  
	 	 	  
	  
	 	 	  
	  
	 
		  				  	 	2,695	  	 	 	459	  	 	 	3,154	  
		  				  	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Total liabilities
	  				  	 	11,914	  	 	 	468	  	 	 	12,382	  
		  				  	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Preferred shares
	  	 	E	  	  	 	—  	  	 	 	323	  	 	 	323	  
	 Shareholder’s equity
	  				  				 				 			
	 Preferred shares
	  	 	E	  	  	 	323	  	 	 	(323	) 	 	 	—  	  
	 Common shares
	  				  	 	3,314	  	 	 	—  	  	 	 	3,314	  
	 Retained earnings
	  				  	 	2,827	  	 	 	—  	  	 	 	2,827	  
	 Accumulated other comprehensive loss
	  				  	 	(10	) 	 	 	—  	  	 	 	(10	) 
		  				  	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Total shareholder’s equity
	  				  	 	6,454	  	 	 	(323	) 	 	 	6,131	  
		  				  	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Total liabilities, preferred shares and shareholder’s equity
	  				  	 	18,368	  	 	 	468	  	 	 	18,836	  
		  				  	  
	  
	 	 	  
	  
	 	 	  
	  
	 

 The adjustments to the January 1, 2011 and December 31, 2011 equity from Canadian GAAP to US GAAP are as
follows: 
  

																					
	 January 1, 2011
 (millions of dollars)
	  	Common Shares	 	  	Preferred Shares	 	 	Accumulated Other
Comprehensive
Income (Loss)	 	 	Retained
Earnings	 	  	Total
Shareholder’s
Equity	 
	 Canadian GAAP
	  	 	3,314	  	  	 	323	  	 	 	(10	) 	 	 	2,354	  	  	 	5,981	  
	 Other comprehensive income
	  	 	—  	  	  	 	—  	  	 	 	—  	  	 	 	—  	  	  	 	—  	  
	 Preferred shares reclassified outside shareholder’s equity
	  	 	—  	  	  	 	(323	) 	 	 	—  	  	 	 	—  	  	  	 	(323	) 
		  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	  	  
	  
	 
	 US GAAP
	  	 	3,314	  	  	 	—  	  	 	 	(10	) 	 	 	2,354	  	  	 	5,658	  
		  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	  	  
	  
	 

  

					
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 HYDRO ONE INC. 
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) 
  

																					
	 December 31, 2011

(millions of dollars)
	  	Common Shares	 	  	Preferred Shares	 	 	Accumulated Other
Comprehensive
Income (Loss)	 	 	Retained
Earnings	 	  	Total
Shareholder’s
Equity	 
	 Canadian GAAP
	  	 	3,314	  	  	 	323	  	 	 	(10	) 	 	 	2,827	  	  	 	6,454	  
	 Other comprehensive income
	  	 	—  	  	  	 	—  	  	 	 	—  	  	 	 	—  	  	  	 	—  	  
	 Preferred shares reclassified outside shareholder’s equity
	  	 	—  	  	  	 	(323	) 	 	 	—  	  	 	 	—  	  	  	 	(323	) 
		  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	  	  
	  
	 
	 US GAAP
	  	 	3,314	  	  	 	—  	  	 	 	(10	) 	 	 	2,827	  	  	 	6,131	  
		  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	  	  
	  
	 

 Notes to the Transitional Adjustments 
 Under US GAAP, the Company (i) measures certain assets and liabilities differently than it had under Canadian GAAP (see details on each measurement change below); and (ii) discloses certain
assets, liabilities and equity on different lines in the Consolidated Financial Statements than it had under Canadian GAAP (see details on each classification change below). 
 A. Debt Issuance Costs (classification change) 
 Under Canadian GAAP, costs of arranging
debt financing, premiums and discounts were netted against long-term debt. Under US GAAP, costs of arranging debt financing are included in “Deferred debt costs” as part of “Other long-term assets”, and net unamortized
premiums are included in “Net unamortized debt premiums” as part of “Other long-term liabilities”. 
 At January 1,
2011 and December 31, 2011, the effect on the Consolidated Balance Sheets is reflected by the following increases: 
  

									
	 (millions of dollars)
	  	January 1, 2011	 	  	December 31, 2011	 
	 Other long-term assets:
	  				  			
	 Deferred debt costs
	  	 	32	  	  	 	32	  
	 Other long-term liabilities:
	  				  			
	 Net unamortized debt premiums
	  	 	27	  	  	 	23	  
	 Long-term debt
	  	 	5	  	  	 	9	  

 B. Pension, Post-Retirement and Post-Employment Benefits (measurement change) 

Under Canadian GAAP, the Company disclosed, but was not required to recognize, the net unfunded status of pension, post-retirement and post-employment
benefit obligations on the Consolidated Balance Sheets. Under US GAAP, the Company recognized the unfunded status of pension, post-retirement and post-employment benefit obligations on the Consolidated Balance Sheets with an offset to
associated regulatory assets for the transitional fair value adjustments as the incremental obligations are expected to be recovered through future rates charged to customers. The deferred tax assets and liabilities arising on recognition of
incremental pension, post-retirement and post-employment benefit obligations and the associated regulatory assets offset each other, with no material impact on the Consolidated Statements of Operations and Comprehensive Income. In the absence of
regulatory accounting, the related tax impact on the opening transitional adjustments would result in the recognition of deferred tax assets of $113 million on January 1, 2011 and $224 million on December 31, 2011. 

At January 1, 2011 and December 31, 2011, the effect on the Consolidated Balance Sheets is reflected by the following increases (decreases):

  

					
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 HYDRO ONE INC. 
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) 
  

									
	 (millions of dollars)
	  	January 1, 2011	 	 	December 31, 2011	 
	 Other long-term assets:
	  				 			
	 Deferred pension asset
	  	 	(460	) 	 	 	(466	) 
	 Regulatory assets1
	  	 	450	  	 	 	902	  
	 Other long-term liabilities:
	  				 			
	 Pension benefit liability
	  	 	297	  	 	 	779	  
	 Post-retirement and post-employment benefit liability
	  	 	153	  	 	 	123	  
	 Regulatory liabilities2
	  	 	(460	) 	 	 	(466	) 

  

	1	 Represents
offsetting regulatory assets for incremental obligations for pension and non-pension obligations of $297 million and $153 million on January 1, 2011, and $779 million and $123 million on December 31, 2011, respectively.

	2 	 Represents write-off of deferred pension asset regulatory liability under Canadian GAAP. 

C. Derivative Instruments (classification change) 
 Under Canadian GAAP, the Company classified its derivative instruments in designated hedging relationships and in economic hedging relationships under the category of “Other assets” on the
Consolidated Balance Sheets. Under US GAAP, the Company has included these balances in “Derivative instruments”. 
 At
January 1, 2011 and December 31, 2011, the effect on the Consolidated Balance Sheets is reflected by the following increases (decreases): 
  

									
	 (millions of dollars)
	  	January 1, 2011	 	 	December 31, 2011	 
	 Current assets:
	  				 			
	 Derivative instruments
	  	 	1	  	 	 	1	  
	 Other
	  	 	(1	) 	 	 	(1	) 
	 Other long-term assets:
	  				 			
	 Derivative instruments
	  	 	7	  	 	 	33	  
	 Other
	  	 	(7	) 	 	 	(33	) 

 D. Accounts Payable (classification change) 
 Under Canadian GAAP, trade and non-trade payables were disclosed as “Accounts payable and accrued charges”. Under US GAAP, trade payables are recognized in “Accounts payable” and
non-trade payables are recognized in “Accrued liabilities”. 
 At January 1, 2011 and December 31, 2011, the effect on the
Consolidated Balance Sheets is reflected by the following increases (decreases): 
  

									
	 (millions of dollars)
	  	January 1, 2011	 	 	December 31, 2011	 
	 Current liabilities:
	  				 			
	 Accounts payable
	  	 	125	  	 	 	154	  
	 Accrued liabilities
	  	 	478	  	 	 	575	  
	 Accounts payable and accrued charges
	  	 	(603	) 	 	 	(729	) 

 E. Preferred Shares (classification change) 
 Under Canadian GAAP, Hydro One’s preferred shares were classified as equity, and preferred dividends were deducted from retained earnings and accrued as declared. Under US GAAP, the preferred
shares are classified outside shareholder’s equity because of conditional redemption features in the preferred share agreement. Under US GAAP, the preferred dividends continue to be deducted from retained earnings and accrued as declared
(see Note 17 – Share Capital). 
 At January 1, 2011 and December 31, 2011, the effect on the Consolidated Balance Sheets is
reflected by the following increases (decreases): 

  

					
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 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) 
  

									
	 (millions of dollars)
	  	January 1, 2011	 	 	December 31, 2011	 
	 Preferred shares
	  	 	323	  	 	 	323	  
	 Shareholder’s equity:
	  				 			
	 Preferred shares
	  	 	(323	) 	 	 	(323	) 

 F. Related Party Balances (classification change) 
 Under Canadian GAAP, receivables from related parties and payables to related parties were disclosed as “Accounts receivable” and “Accounts payable and accrued charges”, respectively.
Under US GAAP, receivables from related parties are recognized in “Due from related parties” and payables to related parties are recognized in “Due to related parties”. 

At January 1, 2011 and December 31, 2011, the effect on the Consolidated Balance Sheets is reflected by the following increases (decreases):

  

									
	 (millions of dollars)
	  	January 1, 2011	 	 	December 31, 2011	 
	 Current assets:
	  				 			
	 Due from related parties
	  	 	124	  	 	 	156	  
	 Accounts receivable
	  	 	(124	) 	 	 	(156	) 
	 Current liabilities:
	  				 			
	 Due to related parties
	  	 	281	  	 	 	342	  
	 Accounts payable and accrued charges
	  	 	(281	) 	 	 	(342	) 

 25. COMPARATIVE FIGURES 
 The comparative Consolidated Financial Statements have been reclassified from statements previously presented to conform to the presentation of the December 31, 2012 Consolidated Financial
Statements. 

  

					
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 HYDRO ONE INC. 
 FIVE-YEAR SUMMARY OF FINANCIAL AND OPERATING STATISTICS 
  

																					
	 Statements of Operations Data

Year ended December 31 (millions of dollars)
	  	20121	 	 	20111	 	 	20102	 	 	20092	 	 	20082	 
	 Revenues
	  				 				 				 				 			
	 Distribution
	  	 	4,184	  	 	 	4,019	  	 	 	3,754	  	 	 	3,534	  	 	 	3,334	  
	 Transmission
	  	 	1,482	  	 	 	1,389	  	 	 	1,307	  	 	 	1,147	  	 	 	1,212	  
	 Other
	  	 	62	  	 	 	63	  	 	 	63	  	 	 	63	  	 	 	51	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
		  	 	5,728	  	 	 	5,471	  	 	 	5,124	  	 	 	4,744	  	 	 	4,597	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Costs
	  				 				 				 				 			
	 Purchased power
	  	 	2,774	  	 	 	2,628	  	 	 	2,474	  	 	 	2,326	  	 	 	2,181	  
	 Operation, maintenance and administration
	  	 	1,071	  	 	 	1,092	  	 	 	1,078	  	 	 	1,057	  	 	 	965	  
	 Depreciation and amortization
	  	 	659	  	 	 	616	  	 	 	583	  	 	 	537	  	 	 	548	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
		  	 	4,504	  	 	 	4,336	  	 	 	4,135	  	 	 	3,920	  	 	 	3,694	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Income before financing charges and provision for payments in lieu of corporate income taxes
	  	 	1,224	  	 	 	1,135	  	 	 	989	  	 	 	824	  	 	 	903	  
	 Financing charges
	  	 	358	  	 	 	344	  	 	 	342	  	 	 	308	  	 	 	292	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Income before provision for payments in lieu of corporate income taxes
	  	 	866	  	 	 	791	  	 	 	647	  	 	 	516	  	 	 	611	  
	 Provision for payments in lieu of corporate income taxes
	  	 	121	  	 	 	150	  	 	 	56	  	 	 	46	  	 	 	113	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Net income
	  	 	745	  	 	 	641	  	 	 	591	  	 	 	470	  	 	 	498	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Basic and fully diluted earnings per common share (dollars)
	  	 	7,280	  	 	 	6,228	  	 	 	5,727	  	 	 	4,528	  	 	 	4,797	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Dividends per common share declared (dollars)
	  	 	3,523	  	 	 	1,500	  	 	 	100	  	 	 	1,700	  	 	 	2,410	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
						
	 Balance Sheets Data
 December 31 (millions of dollars)
	  	20121	 	 	20111	 	 	20101	 	 	20092	 	 	20082	 
	 Assets
	  				 				 				 				 			
	 Distribution
	  	 	8,621	  	 	 	7,594	  	 	 	6,915	  	 	 	6,481	  	 	 	5,873	  
	 Transmission
	  	 	11,586	  	 	 	10,589	  	 	 	9,820	  	 	 	8,993	  	 	 	7,877	  
	 Other
	  	 	604	  	 	 	653	  	 	 	609	  	 	 	161	  	 	 	128	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Total Assets
	  	 	20,811	  	 	 	18,836	  	 	 	17,344	  	 	 	15,635	  	 	 	13,878	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Liabilities
	  				 				 				 				 			
	 Current liabilities (including current portion of long-term debt)
	  	 	1,756	  	 	 	1,820	  	 	 	1,540	  	 	 	1,655	  	 	 	1,300	  
	 Long-term debt
	  	 	7,879	  	 	 	7,408	  	 	 	7,283	  	 	 	6,281	  	 	 	5,733	  
	 Other long-term liabilities
	  	 	4,346	  	 	 	3,154	  	 	 	2,540	  	 	 	2,281	  	 	 	1,721	  
	 Preferred shares
	  	 	323	  	 	 	323	  	 	 	323	  	 	 	—  	  	 	 	—  	  
	 Shareholder’s equity
	  				 				 				 				 			
	 Preferred shares
	  	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	323	  	 	 	323	  
	 Common shares
	  	 	3,314	  	 	 	3,314	  	 	 	3,314	  	 	 	3,314	  	 	 	3,314	  
	 Retained earnings
	  	 	3,202	  	 	 	2,827	  	 	 	2,354	  	 	 	1,791	  	 	 	1,497	  
	 Accumulated other comprehensive income
	  	 	(9	) 	 	 	(10	) 	 	 	(10	) 	 	 	(10	) 	 	 	(10	) 
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Total liabilities, preferred shares and shareholder’s equity
	  	 	20,811	  	 	 	18,836	  	 	 	17,344	  	 	 	15,635	  	 	 	13,878	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 

  

	1	 Based on
US GAAP 

	2	 Based on Canadian
GAAP 

  

					
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Table of Contents

 HYDRO ONE INC. 
 FIVE-YEAR SUMMARY OF FINANCIAL AND OPERATING STATISTICS (continued) 
  

  

																					
	 Other Financial Data
 Year ended December 31
	  	2012	 	  	2011	 	  	2010	 	  	2009	 	  	2008	 
	 Capital expenditures (millions of dollars)
	  				  				  				  				  			
	 Distribution
	  	 	671	  	  	 	628	  	  	 	629	  	  	 	643	  	  	 	570	  
	 Transmission
	  	 	776	  	  	 	810	  	  	 	936	  	  	 	918	  	  	 	704	  
	 Other
	  	 	7	  	  	 	9	  	  	 	5	  	  	 	5	  	  	 	10	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Total capital expenditures
	  	 	1,454	  	  	 	1,447	  	  	 	1,570	  	  	 	1,566	  	  	 	1,284	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Ratios
	  				  				  				  				  			
	 Net asset coverage on long-term debt ratio1
	  	 	1.81	  	  	 	1.81	  	  	 	1.77	  	  	 	1.79	  	  	 	1.84	  
	 Earnings coverage ratio2
	  	 	2.83	  	  	 	2.71	  	  	 	2.39	  	  	 	2.15	  	  	 	2.63	  
	 Operating statistics
	  				  				  				  				  			
	 Transmission
	  				  				  				  				  			
	 Units transmitted (TWh)3
	  	 	141.3	  	  	 	141.5	  	  	 	142.2	  	  	 	139.2	  	  	 	148.7	  
	 Ontario 20-minute system peak demand (MW)3
	  	 	24,768	  	  	 	25,505	  	  	 	25,145	  	  	 	24,477	  	  	 	24,231	  
	 Ontario 60-minute system peak demand (MW)3
	  	 	24,636	  	  	 	25,450	  	  	 	25,075	  	  	 	24,380	  	  	 	24,195	  
	 Total transmission lines (circuit-kilometres)
	  	 	29,327	  	  	 	28,942	  	  	 	28,951	  	  	 	28,924	  	  	 	29,039	  
	 Distribution
	  				  				  				  				  			
	 Units distributed to Hydro One customers (TWh)3
	  	 	29.2	  	  	 	29.2	  	  	 	29.1	  	  	 	28.9	  	  	 	29.9	  
	 Units distributed through Hydro One lines (TWh)3,4
	  	 	42.4	  	  	 	42.5	  	  	 	42.5	  	  	 	43.5	  	  	 	44.7	  
	 Total distribution lines (circuit-kilometres)
	  	 	121,525	  	  	 	120,514	  	  	 	123,552	  	  	 	123,528	  	  	 	123,260	  
	 Customers
	  	 	1,381,926	  	  	 	1,365,379	  	  	 	1,345,177	  	  	 	1,333,920	  	  	 	1,325,745	  
	 Total regular employees
	  	 	5,811	  	  	 	5,781	  	  	 	5,717	  	  	 	5,427	  	  	 	5,032	  

  

	1 	 The net asset coverage on long-term debt ratio is calculated as total assets minus total liabilities excluding long-term debt (including current
portion) divided by long-term debt (including current portion). 

	2 	 The earnings coverage ratio has been calculated as the sum of net income, financing charges and provision for payments in lieu of corporate income
taxes divided by the sum of financing charges, capitalized interest and cumulative preferred dividends. 

	3 	 System-related statistics include preliminary figures for December. 

	4 	 Units distributed through Hydro One lines represent total distribution system requirements and include electricity distributed to consumers who
purchased power directly from the IESO. 

  

					
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