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

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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

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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

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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

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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.

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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;

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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

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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.

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FORWARD-LOOKING INFORMATION

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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

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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.

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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

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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.

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FORWARD-LOOKING INFORMATION

Simplified Illustration of an Electric Power System

2012 ANNUAL INFORMATION FORM  11

ABOUT HYDRO ONE

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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.

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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.

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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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GENERAL DEVELOPMENT OF THE BUSINESS

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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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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:

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GENERAL DEVELOPMENT OF THE BUSINESS

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

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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

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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

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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

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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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DESCRIPTION OF THE BUSINESS

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.

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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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DESCRIPTION OF THE BUSINESS

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

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DESCRIPTION OF THE BUSINESS

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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DESCRIPTION OF THE BUSINESS

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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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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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.

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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.

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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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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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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.

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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.

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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.

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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

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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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DIRECTORS AND OFFICERS

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

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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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	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.

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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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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

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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

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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.

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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.

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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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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.

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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

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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	$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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MATERIAL CONTRACTS

$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.

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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.

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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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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;

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• 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

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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.

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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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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

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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.

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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

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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.

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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

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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

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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,

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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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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.

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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

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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.

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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

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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

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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

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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

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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.

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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.

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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

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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.

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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.

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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

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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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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.

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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.

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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.

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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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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

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(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.

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(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”

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.

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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

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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.

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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

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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.

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