Exhibit 99.1

ANNUAL INFORMATION FORM
For the Year Ended December 31, 2013
March 2014
hydroOne

TABLE OF CONTENTS

TABLE OF CONTENTS

2	DEFINITIONS
7	CORPORATE STRUCTURE
9	FORWARD-LOOKING INFORMATION
15	ABOUT HYDRO ONE
15	Our Mission and Vision
15	Our Strategy
17	Corporate Awards
19	GENERAL DEVELOPMENT OF THE BUSINESS
19	Electricity Sector Landscape
19	OPA
19	OEB
19	IESO
20	Recent Industry Activity
20	Distribution Sector Consolidation
20	2013 Long-Term Energy Plan
21	Regulated Price Plan Structure
23	Procurement of New Generation
23	Recent Developments at Hydro One
23	Appointment of New Chair of Board of Directors
23	Change in Executive Officer
23	Debt Issuances
25	OVERVIEW OF HYDRO ONE
27	DESCRIPTION OF THE BUSINESS
27	Our Business Segments
27	Our Transmission Business
27	Overview
28	Transmission Planning
28	Transmission Assets
28	Transmission Stations
29	Transmission Lines
29	Network Operations
30	Telecommunications Facilities
31	Transmission Capital Expenditure Plans
32	Major Transmission Capital Development Projects
34	Transmission Projects at the Local Load Connections Level
34	Transmission Sustainment

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35	NERC/NPCC
35	NERC Critical Infrastructure Protection Standards
36	Our Distribution Business
37	Distribution Capital Expenditure Plans
37	Distribution Assets
37	Remote Communities
38	Conservation and Demand Management
39	Advanced Distribution System
40	Smart Meters
42	Our Telecommunications Business
42	Other Business Particulars
42	Employees
43	Compensation
44	Pension Plan
44	Outsourcing Arrangement with Inergi LP
45	Environmental
45	Health, Safety and Environmental Management System
45	Permits and Approvals
46	Regulation of Releases
46	Hazardous Substances
46	PCB
47	Asbestos
47	Herbicides
47	Wood Preservatives
47	Land Assessment and Remediation
48	Electric and Magnetic Fields
49	Health and Safety
50	Insurance
50	Legal Proceedings and Regulatory Actions
50	Financial
51	Cornerstone
53	REGULATION
53	The Statutory and Operating Framework
53	Federal Framework
53	Ontario Framework
54	The Ontario Regulatory Process
54	Contractual Arrangements, Codes and Licences
54	Operating Agreement with the IESO
54	Hydro One’s Relationships with Other Market Participants
55	Electricity Industry Codes
55	Electricity Industry Licences

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55	Rate Orders and Related Issues for Hydro One’s Businesses
56	Transmission
56	Current Rate Orders and Review of the Existing Transmission Rate Structure
56	Bypass
57	Competition
57	Facilities Applications
58	Distribution
58	Current Rate Orders and Distribution Rate Structure
58	Hydro One Networks Inc.
59	Hydro One Brampton Networks Inc.
59	Hydro One Remote Communities Inc.
60	Rural and Remote Rate Protection
60	Rate Protection and Determination of Direct Benefits to Accommodate Renewable Energy Generation Facilities
61	Ontario Clean Energy Benefit Act
61	Connection Cost Responsibility
63	RISK FACTORS
63	Ownership by the Province
63	Regulatory Risk
64	Risk of Natural and Other Unexpected Occurrences
65	Risk Associated with Information Technology Infrastructure
65	Risk Associated with Arranging Debt Financing
66	First Nation and Métis Claims Risk
66	Risk Associated with Outsourcing Arrangement
66	Risk Associated with Transmission Projects
66	Asset Condition
67	Work Force Demographic Risk
67	Labour Relations Risk
67	Pension Plan Risk
68	Environmental Risk
69	Market and Credit Risk
70	Risk from Transfer of Assets Located on Reserves
70	Risk from Provincial Ownership of Transmission Corridors
73	DIVIDENDS
74	DESCRIPTION OF CAPITAL STRUCTURE
75	CREDIT RATINGS OF SECURITIES AND LIQUIDITY
76	MARKET FOR SECURITIES

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77	DIRECTORS AND OFFICERS
77	Directors
77	Name and Municipality of Residence
84	Information Regarding Certain Directors
84	Executive Officers
84	Name and Municipality of Residence
85	Indebtedness of Directors and Executive Officers
86	INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS
86	Relationships with the Province and Other Parties
86	Overview
86	Transfer Orders
87	Indemnities
88	Payments in Lieu of Corporate Taxes
88	Memorandum of Agreement
90	TRUSTEES AND REGISTRARS
91	MATERIAL CONTRACTS
94	INTERESTS OF EXPERTS
95	ADDITIONAL INFORMATION
96	STATEMENT OF EXECUTIVE COMPENSATION
96	Compensation Discussion and Analysis
96	Overview
97	Governance
98	Composition of the HRC
98	Committee Members Relevant and Direct Experience
99	Compensation Policies and Practices Aligned to Risk Management
100	Independent Consultant for the HRC
101	ELEMENTS OF COMPENSATION
102	Base Salary
103	Performance-Based Compensation
103	Fund Determination
104	Fund Allocation
104	Corporate Performance Measures and Targets
106	Productivity
106	Reliability of Transmission and Distribution
107	Customer Satisfaction
107	Employee Engagement
107	Shareholder Value
107	Safety: Injury Free Workplace

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107	Overall Performance for 2013
108	Individual Performance
111	Benefits
112	Role of NEOs in Determining Executive Compensation
113	SUMMARY COMPENSATION TABLE
114	Pension Plan Benefits
114	Defined Benefit Pension Plan
117	Termination and Change of Control Benefits
118	Director Compensation
119	Director Compensation Table
120	APPOINTMENT OF AUDITOR
121	AUDIT AND FINANCE COMMITTEE INFORMATION
121	The Audit and Finance Committee’s Charter
121	Composition of the Audit and Finance Committee
121	Relevant Education and Experience
123	Audit and Finance Committee Oversight
123	Pre-Approval Policies and Procedures
123	External Auditor Service Fees
124	CORPORATE GOVERNANCE DISCLOSURE
124	Board of Directors
125	Summary of Attendance of Directors
126	Director’s Board Memberships in Other Reporting Issuers
126	Board Mandate
126	Position Descriptions
126	Committees of the Board of Directors
126	Audit and Finance Committee
127	Business Transformation Committee
127	Corporate Governance Committee
127	Health, Safety and Environment Committee
127	Human Resources Committee
128	Investment-Pension Committee
128	Regulatory and Public Policy Committee
128	Orientation and Continuing Education
128	Ethical Business Conduct
129	Board, Committee and Director Assessments
130	APPENDIX “A” AUDIT AND FINANCE COMMITTEE MANDATE
136	APPENDIX “B” HYDRO ONE INC. BOARD OF DIRECTORS MANDATE
139	APPENDIX “C” HYDRO ONE TRANSMISSION AND DISTRIBUTION LICENCES

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EXCEPT WHERE OTHERWISE INDICATED,

ALL INFORMATION PRESENTED HEREIN IS AS AT DECEMBER 31, 2013

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DEFINITIONS

For convenience, in this Annual Information Form:

“ADS” means the Advanced Distribution System;

“AIF” means this Annual Information Form;

“BES” means Bulk Electric System;

“Board” means the Board of Directors of Hydro One Inc.;

“Canadian GAAP” means Canadian Generally Accepted Accounting Principles per Part V of the Chartered Professional Accountants Canada 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;

“ESA” means an Environmental Site Assessment;

“ESR” means an Environmental Study Report;

“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 (Ontario);

“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;

“Inergi Agreement” means the outsourcing service agreement with Inergi LP;

“Intertie” means a transmission facility that physically connects adjacent transmission systems indifferent jurisdictions (e.g. provinces or countries) for the purpose of electrical power transfers;

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DEFINITIONS

“IPL” refers to an international power line;

“IPSP” means the Integrated Power System Plan developed by the OPA;

“IRM” means Incentive Regulation Mechanism;

“IT” means Information Technology;

“LDC” means a local distribution company;

“2010 LTEP” means “Ontario’s Long Term Energy Plan, Building Our Clean Energy Future”, announced by the Province on November 23, 2010;

“2013 LTEP” means “Ontario’s Long-Term Energy Plan, Achieving Balance”, announced by the Province on December 2, 2013;

“LRAM” means Lost Revenue Adjustment Mechanism;

“Micro FIT” means the micro feed-in-tariff program of the OPA;

“Ministry” or “Minister” means the Ontario Ministry of Energy or the Ontario Ministry of Energy and Infrastructure and, as applicable, its respective Minister,

“NEB” refers to the National Energy Board;

“NEB Act” means the National Energy Board Act, 1985 (Canada), as amended;

“NERC” means the North American Electric Reliability Corporation;

“NPCC” means the Northeast Power Coordinating Council Inc.;

“NYSE” means the New York Stock Exchange;

“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;

“OHSAS 18001” 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;

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DEFINITIONS

“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;

“RRFE” means the Renewed Regulatory Framework for Electricity;

“RRP” means the Renewed Regulatory Framework for Electricity Distributors and Transmitters;

“RRRP” means Rural and Remote Electricity Rate Protection;

“SEC” means the United States Securities and Exchange Commission;

“Small FIT” means the small feed-in-tariff program of the OPA;

“Smart Grid Advisory Committee” means the committee created by the OEB on June 27, 2013;

“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 transmission station;

“TSC” means the Transmission System Code;

“U.S.” means the United States of America; and

“U.S. GAAP” means United States Generally Accepted Accounting Principles.

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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, 8th Floor, South 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.

Such statements include, but are not limited to, statements about our strategy, including our strategic objectives; statements about the general development of our business, including statements about distribution sector consolidation and the 2013 Long-Term Energy Plan; statements related to the OEB’s RPP and TOU pricing, including expectations regarding the exemption of TOU pricing for rural customers and the timeline for converting those customers to TOU pricing; statements related to the FIT program; statements related to our ability to continue to prepare our financial statements in 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 regarding current and future capital expenditures and capital development projects and other investment plans including expected benefits, completion and in-service dates and our ability to recover the costs related to such projects and to obtain environmental and other regulatory approvals in connection therewith; statements regarding the reliability of our distribution and transmission systems including equipment performance; statements about our transmission and distribution capacity; expectations regarding load growth and new generation; statements about our ongoing initiatives including the expected results and their completion dates; expectations regarding

NERC/NPCC standards, expected timing of regulatory approvals, the cost impact of their adoption, and possible recovery of these costs in rates; statements about smart meters including their capabilities, costs and cost recovery; statements about CDM programs and targets; statements related to the buildout of an ADS for our distribution business, including future investments and the recoverability of those investments; statements related to the expiry of labour agreements, 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 deadlines relating to PCB regulations, potential future costs related to asbestos, herbicide and land assessment and remediation, our ability to recover such costs and the need for environmental approvals and assessments; statements relating to health and safety initiatives and opportunities; statements regarding the OEB’s plan for a renewed regulatory framework for electricity; 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 connecting the East-West Tie line; statements related to our connection assets including recovery of costs related thereto; expectations regarding developments in the

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FORWARD-LOOKING INFORMATION

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 regarding the Ontario Clean Energy Benefit Act, 2010, statements relating to our relationship with the Province, including the possibility of the Province making declarations pursuant to our memorandum of agreement with them; statements relating to IT system failures or security breaches; 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 and negotiation of rental terms; 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; continued use 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. 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;

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FORWARD-LOOKING INFORMATION

— 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;

— changes in the electricity industry requiring changes to investment needs not foreseen in long-term rate forecasting;

— 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;

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FORWARD-LOOKING INFORMATION

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

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

— the 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 or expires before a new service provider is selected;

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

— the impact of the 2010 LTEP and the 2013 LTEP on our company and the costs and expenses arising therefrom;

— the ability to negotiate appropriate collective agreements;

— no labour disputes;

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

— the inability to prepare financial statements in U.S. GAAP;

— 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 and you should review such section 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

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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 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

Our corporate strategy builds on our strong commitment to the Province and is shaped by our values. It lays out a set of objectives to position our company to achieve our mission and vision which 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 affordable 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 and ensure we remain focused on achieving our corporate goal of providing safe, reliable and affordable service to our customers, today and tomorrow, while increasing enterprise value for our shareholder.

— Creating an injury-free workplace and maintaining public safety. Health and safety must be integrated into all that we do as we continue to reinforce that nothing is more important than the health and safety of our employees. We will continue to create a passion for preventing injury, staying safe and keeping each other safe. We will invest in building a culture of accountability to continue our drive to zero injuries in the workplace. In addition, we will continue to strengthen our already strong safety culture through our Journey to Zero initiative and our successful certification to the OHSAS 18001 standard.

— Satisfying our customers. We exist to serve our customers, and serving our customers means reducing costs, improving customer service and meeting their expectations regarding reliable

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ABOUT HYDRO ONE

power supply. We will continue to focus our efforts to improve our relationship with customers and to improve our customers’ satisfaction with us. We will meet our commitments, make customers our focus in all planning discussions, communicate effectively, coordinate across our company, and maximize opportunities to improve our corporate image and every customer interaction. We will develop and deliver targeted customer segment strategies, products and delivery channels that will respond to their unique needs.

— Continuous innovation. Innovation represents one of our values and is critical to achieving our mission and vision. We have been using innovation and technology to build the foundation of our company as the utility of the future. Over the next two decades, we will continue to build on that foundation to improve the reliability and efficiency of our transmission and distribution systems and provide our customers with more capability to manage their power costs. The development of the ADS is a key element in our investment in innovation, as are the investments we have made, through our Cornerstone project, in next generation business tools to enable us to implement leading industry practices and increase productivity.

— Building and maintaining reliable, affordable 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 continuing to meet the challenge of providing reliable, affordable service to our customers in a wide range of geographical

regions and climate zones; incorporating ADS technology to provide greater visibility; and increased control and improved customer service. We will meet customer expectations regarding reliability, in part through our investment planning process, which starts with the identification of asset and customer needs.

— 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.

— Championing people and culture. We believe our primary strength is the capability of our people. In order to sustain this advantage, we will continue to address the issues of corporate culture, labour demographics, diversity, development of critical core competencies, and skill and knowledge retention. We will continue to develop a culture of accountability and trust as a key component to fostering employee engagement. Our labour strategy is to consolidate and clarify our collective agreements, increase flexibility and reduce costs and maintain a progressive relationship with our unions.

— Maintaining a commercial culture that increases value for our shareholder. For the delivery component of a customer bill, we are committed to maintaining total annual bill impacts for an average residential customer at or below the rate of inflation, and delivering income and dividends to our shareholder. We will pursue growth opportunities through LDC consolidation to increase the enterprise value of our company by leveraging our existing assets, technologies,

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ABOUT HYDRO ONE

capabilities, unparalleled experience in LDC acquisitions and our distribution and transmission footprint.

— 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.

Corporate Awards

In 2013, in recognition of our support in the recovery efforts from the June 2012 Mid-Atlantic and Midwest derecho and Hurricane Sandy, we were awarded one of the Edison Electric Institute’s 2012 Emergency Assistance Awards.

Additionally, we were presented with the OHSAS 18001 Standard award from the Occupational Health and Safety Assessment Series for Hydro One’s commitment to continual health and safety improvement. Further, in 2013, we won the 2013 Canadian Electricity Association Vice President’s Award for Safety Excellence at the Bronze level. This award is bestowed upon corporate utilities that are ranked within the top quartile of their grouping for both “All Injury/Illness Frequency” and “Lost Time Severity Rates” for either generation or transmission and distribution operations.

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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

In 2009, the transfer tax exemption applicable when publicly owned utilities sell electricity distribution assets to other publicly-owned utilities in Ontario was made permanent by the Province.

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 (the “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 recommended 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 recommended 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 recommended that Hydro One Networks Inc. 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. The Minister subsequently indicated he was supportive of voluntary consolidation and expects all LDCs to pursue innovative partnerships and transformative initiatives that will result in electricity ratepayer savings.

As the utility sector began to assess the impact of the Panel’s recommendations, Hydro One was an active participant in the competitive sale process of Norfolk Power Inc. (“Norfolk Power”). Norfolk

Power is a holding company that owns Norfolk Power Distribution Inc., a LDC, and Norfolk Energy Inc., a non-rate regulated energy services company. On April 2, 2013, we entered into an agreement with The Corporation of Norfolk County (“Norfolk County”) to purchase all of the outstanding shares of Norfolk Power for approximately $93 million. Pursuant to the agreement, we agreed to pay Norfolk County approximately $66 million net of Norfolk Power’s existing debt of approximately $27 million. The selection of our company as successful bidder followed a comprehensive competitive sales process initiated by Norfolk Power. An OEB decision on the acquisition and closing of the deal is anticipated in mid-2014. We intend to continue to pursue growth opportunities through LDC consolidation by leveraging our existing assets, technologies, capabilities, unparalleled experience in LDC acquisitions and our distribution footprint.

2013 Long-Term Energy Plan

On December 2, 2013, the Province released its updated Long-Term Energy Plan, the 2013 LTEP, replacing the 2010 LTEP. The 2013 LTEP sets out the Province’s plan of action for the energy sector, including strategies for mitigating increases in electricity rates; continued renewable energy procurement; nuclear refurbishment; enhanced regional planning with respect to energy infrastructure; transmission enhancements; encouraging Aboriginal participation in energy development, transmission and conservation projects; and the expansion of natural gas infrastructure. The plans are guided by the goal of balancing five core principles: cost-effectiveness, reliability, clean energy, community engagement, and CDM. Pursuant to the 2013 LTEP, the Province “will encourage OPG and Hydro One to explore new business lines and opportunities inside and outside Ontario. These opportunities will help

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GENERAL DEVELOPMENT OF THE BUSINESS

leverage existing areas of expertise and grow revenues for the benefit of Ontarians”. The government expects Hydro One to begin planning for a new Northwest Bulk transmission line, west of Thunder Bay, with the project scope to be recommended by the OPA.

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:

RPP Pricing (per kWh)
Winter (Nov. 1, 2012 – April 30, 2013)	Lower Tier Price	7.4 cents
	Upper Tier Price	8.7 cents
Summer (May 1, 2013 – Oct. 31, 2013)	Lower Tier Price	7.8 cents
	Upper Tier Price	9.1 cents
Winter (Nov. 1, 2013 – April 30, 2014)	Lower Tier Price	8.3 cents
	Upper Tier Price	9.7 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 the customers 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”). On August 4, 2010, the OEB issued its Final Determination to mandate TOU pricing for RPP customers. 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, 2012 – April 30, 2013)	Off-peak Price	6.3 cents
	7pm – 7am
	Weekdays, Weekends and Holidays
	Mid-peak Price	9.9 cents
	11am – 5pm Weekdays
	On-peak Price	11.8 cents
	7am – 11am, 5pm – 7pm
	Weekdays
Summer (May 1, 2013 – Oct. 31, 2013)	Off-peak Price	6.7 cents
	7 pm – 7 am
	Weekdays, Weekends and Holidays
	Mid-peak Price	10.4 cents
	7 am – 11 am, 5 pm – 7 pm
	Weekdays
	On-peak Price	12.4 cents
	11 am – 5 pm Weekdays
Winter (Nov. 1, 2013 – April 30, 2014)	Off-peak Price	7.2 cents
	7 pm – 7 am
	Weekdays, Weekends and Holidays
	Mid-peak Price	10.9 cents
	11 am – 5 pm Weekdays
	On-peak Price	12.9 cents
	7 am – 11 am, 5 pm – 7 pm
	Weekdays

New RPP prices are computed at six-month intervals and are the result of an integrated consideration of rebasing and true-ups. Price changes become effective at the beginning of a calendar month.

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Procurement of New Generation

Pursuant to a Provincial directive, the OPA set up the FIT program for procurement of renewable generation. The program is currently divided into three streams: Micro FIT (projects up to 10 kW), Small FIT (projects between 10 and 500 kW) and regular FIT (projects greater than 500 kW), all of which may result in connection to Hydro One Networks Inc.’s distribution system. Under the FIT program, the OPA has entered into contracts or conditional contracts with generation proponents pursuant to which the OPA will pay a fixed rate for power produced over a specified period of time. Hydro One continues to connect projects for which there are firm contracts.

The Province announced on May 30, 2013, that it would make 900 MW of new capacity available between 2013 and 2018 for the Small FIT and Micro FIT programs. The Province has set annual

procurement targets, from 2014 onwards, of 150 MW for Small FIT generation and 50 MW for Micro FIT generation. The Province is working with the OPA to develop a competitive process for renewable energy generation projects above 500 kW. The new process will replace the existing large project stream of the FIT program.

Recent Developments at Hydro One

Appointment of New Chair of Board of Directors

On March 7, 2014, the Province announced that effective April 1, 2014, Sandra Pupatello would be appointed Chair of the Board of Hydro One.

Change in Executive Officer

On February 25, 2014, Mr. Gregg submitted his resignation from Hydro One, which has been accepted, and provided three months’ notice of the termination of his employment. Mr. Gregg is taking on the position of President and Chief Executive Officer of Enersource Corporation.

Debt Issuances

On January 29, 2014, our company issued in Canada $50,000,000 aggregate principal amount of its medium term notes bearing interest at 4.29% and due 2064 pursuant to its medium term note program.

On March 21, 2014, our Company issued in Canada $125,000,000 aggregate principal amount of its medium term notes bearing a floating interest rate and due 2019 pursuant to its medium term note program.

2013 ANNUAL INFORMATION FORM    23

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 97% 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 $11.8 billion of our total assets of $21.6 billion as at December 31, 2013, transmits electricity through a high-voltage network from generators to our own distribution networks, to LDCs, 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 $8.8 billion of our total assets of $21.6 billion as at December 31, 2013, 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 five MW, and rural and urban customers.

Hydro One Brampton Networks Inc. is our urban distribution company serving customers in the City of Brampton, Ontario. 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 $1 billion of our total assets of $21.6 billion as at December 31, 2013.

2013 ANNUAL INFORMATION FORM    25

DESCRIPTION OF THE BUSINESS

26  HYDRO ONE INC.

DESCRIPTION OF THE BUSINESS

DESCRIPTION OF THE BUSINESS

Our Business Segments

Our Transmission Business

Overview

Our transmission system operates at 500 kV, 230 kV and 115 kV and transmits electricity to customers consisting of 47 LDCs, our own distribution businesses and 92 transmission-connected companies. Electricity is also delivered to utilities in other jurisdictions through Interties. Electricity is supplied by generators, both within and outside Ontario, of which 103 in Ontario are connected directly to the transmission grid. Our transmission system serves approximately five million customers, directly or indirectly, and transported approximately 140.7 TWh of energy throughout Ontario in 2013. Revenues from our transmission business accounted for approximately 25% of our total revenues in 2013 and approximately 26% and 25% of our total revenues in 2012 and 2011, 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 and 115 kV levels with New York (7), Quebec (11), Michigan (4), Manitoba (3) and Minnesota (1).

Through these 26 Interties, the IESO, in its report “Ontario Transmission System” dated November 22, 2013, estimates that, in the summer, with all transmission elements in service, the theoretical maximum capability for exports is up to 6,070 MW and for imports is up to 6,510 MW; in the winter, the theoretical maximum capability for exports is 6,270 MW and for imports is 6,390 MW respectively. 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.

2013 ANNUAL INFORMATION FORM    27

DESCRIPTION OF THE BUSINESS

This section on our transmission business consists of five topics:

1. Transmission Planning

2. Transmission Assets

3. Transmission Capital Expenditure Plans

4. NERC/NPCC

5. 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 communities 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) and 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 two kilometres are subject to the OEB’s leave-to-construct approval. The EA approval requirements for a “transmission line” or “transmission station” are prescribed in Ontario Regulation 116/01 made under the EA. Whether or not a particular project is subject to class environmental or an

individual environmental assessment approval is dependent on that particular project.

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

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DESCRIPTION OF THE BUSINESS

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 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 289 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.

2013 ANNUAL INFORMATION FORM    29

DESCRIPTION OF THE BUSINESS

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-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 forecasted 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 first stage review revealed that available telecommunications capacity was greater than originally identified and that future telecom growth was neither as large nor as imminent as previously predicted. Therefore, the project has been cancelled.

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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.

Capital expenditures for the transmission portion of our business for 2014 are estimated to be approximately $950 million net overall. 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.

Hydro One Networks Inc. has begun to upgrade the Lambton to Longwood transmission lines. This work is expected to be completed by the end of 2014. The OPA has not provided Hydro One Networks Inc. with any recommendations related to the build of 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. increase short circuit and/or transfer capacity at up to 15 of our transmission stations during a 48-month period starting March 1, 2011, to enable the connection of small scale renewable energy generation facilities; and

2. one or more devices to enhance transfer capability such as series or static var compensators or other similar devices in southwestern Ontario (recommended by the OPA in their letter dated October 3, 2011).

In a letter dated April 7, 2011, the OPA recommended the upgrade of ten transmission stations, of which seven have been completed and three have subsequently been determined to be not required. On August 9, 2013, the OPA sent Hydro One a letter cancelling the need to install a static var compensator at Hydro One’s Milton SS in southwestern Ontario.

The Minister issued a directive to the OEB dated November 27, 2013, and the OEB in turn issued a decision and order on January 9, 2014, to amend the transmission licence of Hydro One Networks Inc. to develop and seek approval for the expansion or reinforcement of its transmission system in the area west of Thunder Bay (the “Northwest Bulk Transmission Line Project”).

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DESCRIPTION OF THE BUSINESS

The scope and timing of the Northwest Bulk Transmission Line Project shall be in accordance with the recommendations of the OPA.

Hydro One is 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 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, 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 (“B2M LP”) to hold most of the transmission lines and related land rights associated with our Bruce to Milton Transmission Reinforcement Project. Under the terms of our agreement, the SON will be eligible to purchase a non-controlling equity interest in B2M LP at fair value.

On December 18, 2012, the SON, Hydro One Networks Inc. and Hydro One signed a letter agreement in connection with the establishment of the B2M LP. The letter agreement addresses, among other things, the terms of B2M 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 B2M LP. The closing is conditional on certain regulatory approvals and tax rulings.

On November 28, 2013, the OEB issued a decision and order granting B2M LP a transmission licence and granting Hydro One Networks Inc. leave to sell the relevant transmission assets to B2M LP. The latter is conditional on B2M LP obtaining favourable tax rulings.

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— 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 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 construction work is underway. The expected in-service date for the project is estimated to be late in 2015.

— Rebuild Hearn SS

The existing 115 kV Hearn SS was identified by our company as due for refurbishment. The project was placed partially in service in December 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 currently is mid-to-late 2014.

— 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 will take approximately two months to complete once a land settlement agreement has been concluded between the Province and the Six Nations.

— Lambton to Longwood Transmission Upgrade

This 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 a 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, and currently work is proceeding on schedule to meet the required in-service date.

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DESCRIPTION OF THE BUSINESS

— Clarington TS (formerly Oshawa Area TS) Project

In October 2011, the OPA requested that Hydro One develop an implementation plan and initiate work on the installation of additional auto-transformer capacity at our proposed Clarington TS. In 2012, Hydro One commenced planning and environmental studies, and a draft ESR was made available for review on November 15, 2012. On closing of the review period, multiple third party requests had been submitted to the Ministry of the Environment to escalate the EA approval from a class environmental assessment to a more comprehensive individual environmental assessment. On January 2, 2014, the Minister of Environment issued a decision on the requests and ruled that an individual environmental assessment is not required for the project and advised that Hydro One can proceed with the project, subject to certain conditions. The final ESR was submitted to the Ministry of the Environment on January 16, 2014. The planned in-service date is mid-2017.

— Guelph Area Transmission Refurbishment Project

The project includes an upgrade of 5 kilometres of existing 115 kV transmission line in south-central Guelph to 230 kV, the installation of autotransformers at Cedar TS and upgrading the existing Guelph North Junction to a new switching station. On March 8, 2012, Hydro One received a letter from the OPA, recommending that Hydro One proceed with development work for the project, including the completion of the environmental and regulatory approval processes. Following the OPA’s letter, Hydro One started the process. On September 26, 2013, the OEB issued a decision and order approving Hydro One’s section 92 application for the project. The expected in-service date is approximately mid-2016.

— Supply to Essex County Transmission Reinforcement Project

Hydro One is proceeding with this project, which comprises of a new 13 kilometre 230 kV double circuit transmission line in the Windsor-Essex region and the construction of a new TS called Leamington TS in the Municipality of Leamington. The class environmental assessment for the project has been completed and a final ESR was filed with Ministry of the Environment in July 2010. Hydro One submitted an application to the OEB under section 92 of the OEB Act for leave to construct the transmission line on January 22, 2014. The planned in-service date is mid-2016.

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 the broader local community, the participation and support of OPA and 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 specific load connection customers, we are in discussions with those customers regarding new transmission stations and lines, as well as upgrades to existing stations and lines.

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 have

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the most impact on our company’s strategic objectives, including reliability and value to our customers with targeted component replacement programs such as air blast circuit breakers and transformers, as well as improved control initiatives to protect against animal contacts. 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. 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 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 BES to address FERC’s technical concerns, and ensure that the definition encompasses all facilities above 100 kV that are necessary for operating an interconnected electric transmission network. While there has been considerable debate regarding the definition, the revised BES definition was approved by the FERC on March 20, 2014. The definition will

come into effect in July 2014 with full compliance in 2016.

Hydro One has been represented on the NERC team developing the revised BES definition to address the issues of non-jurisdictional entities and to consult with other major Canadian entities and stakeholders.

Significantly more transmission facilities (facilities at or above 100 kV except excluded by definition) will be designated BES and be required to comply with NERC reliability standards. In Hydro One’s assessment, this will add little, if any, additional improvement to the reliability of the interconnected BES. Adopting this new approach would result in significant additional costs to the transmission facility owners, including Hydro One. We anticipate these incremental costs would be spread over a number of years, and expect that they would be recovered in rates.

In Ontario, the IESO has developed a “made in Ontario” BES Exception Procedure and criteria that would allow market participants such as Hydro One to prepare an exception application for a newly designated BES element.

5. 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.

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DESCRIPTION OF THE BUSINESS

Hydro One is currently mandated to comply to Version 3 of the critical infrastructure protection standards. On November 26, 2012, NERC Board of Trustees adopted Version 5 of the standards, which was approved by FERC on November 21, 2013. 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 2013, approximately 29.8 TWh of electricity were delivered through the distribution system to approximately 1.4 million customers located in rural and urban areas (including approximately 146,000 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 32 customers with loads exceeding five MW. The distribution system comprises approximately 3,300 feeders operating at voltages less than 50 kV, that total 122,000 circuit kilometres of lines, and we own 1,017 distribution and regulating stations. Our distribution systems distribute electricity from our transmission system and more than 12,000 small generators (approximately 1,980 generators that are greater than ten kW and approximately 10,060 that are less than or equal to ten kW).

Unlike the distribution systems found in densely-populated areas that are designed to include built-in transfer capability, Hydro One Networks Inc.’s distribution systems supply mainly rural areas with low population densities and are mostly configured as a radial system. This means that

there is very limited transfer capability, as they are not designed in loops with connections to other feeders and outages at any point along the feeder will cause all customers on the feeder to lose power. As a result, fallen trees and component failures on the feeders require immediate repair or replacement in order to restore service.

Unlike the distribution systems in areas with low population density, Hydro One Brampton Networks Inc.’s systems in Brampton, which is densely-populated, are designed with a larger focus on underground distribution which is less susceptible to weather conditions. The majority of investments in the distribution system in Brampton are related to expanding the system in order to connect new customers and to support infrastructure development such as road development and road widening. In addition to the investments in the distribution system expansion for needed capacity, efforts are also directed at converting distribution systems in older sections of Brampton into present day standard designs to improve system reliability, performance and robustness.

Revenues from our distribution business accounted for approximately 74% of our total revenues in 2013 and approximately 73% and 74% of our total revenues in 2012 and 2011, respectively.

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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 2014 are estimated to be approximately $650 million net overall. Consistent with our approved distribution rate application, capital expenditures for our distribution business for 2013 were focused on new load connections, trouble calls and storm damage, wood pole replacement, and system capability reinforcement. Going forward into 2014 and 2015, we will continue with these areas of focus. In response to the GEA and the resulting FIT program being administered by the OPA to procure renewable energy generation, we continue to observe a relatively high level of generation connection activity, particularly for Micro FIT generating facilities and Small FIT generating facilities. We invest in additions and modifications to our distribution system, as required by regulations, in order to connect new generating facilities.

Across Ontario, we are continuing with the replacement of distribution assets that have reached their end-of-life. We are increasing the number of projects to renew distribution stations and are increasing wood pole replacement quantities. 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. We also intend to continue our efforts to make the distribution system more efficient and reliable, including investments in the ADS.

In addition, we are continuing to focus on line-clearing activities to maintain the reliability performance of our distribution system.

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 generally consists of: (i) M class distribution feeders that deliver power at 44 kV and 27.6 kV from our transmission stations to our distribution stations and to some industrial customers, local generators and LDCs; (ii) distribution and regulating stations; and (iii) F class distribution feeders that deliver power at 14 kV, 8 kV and 4 kV from the distribution stations to industrial, commercial, farm, local generation and residential customers as well as embedded LDCs. These feeders and stations 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

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by these remote communities is produced by 58 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.

4. Conservation and Demand Management

The Province has established specific provincial targets for CDM. Hydro One’s distribution business’ expenditures to help meet these targets are funded through the global adjustment. The global adjustment is a rate which is adjusted monthly that (a) accounts for differences between: (i) the market price for electricity generation; and (ii) the rates paid to regulated and contracted generators; and (b) CDM programs. The global adjustment can be positive or negative, depending on the level of prices in the wholesale electricity market. A lower wholesale market price is associated with a higher 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 LDCs 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 for the period 2011-2014. 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

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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. The guidelines also 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. In addition, the guidelines state that savings associated with TOU pricing are eligible to be counted towards the 2011-2014 CDM targets.

On September 30, 2013, in accordance with the CDM Code, Hydro One Networks Inc. and Hydro One Brampton Networks Inc. each filed a 2012 Annual CDM Report with the OEB. The reports discussed each company’s CDM activities, energy and peak demand savings results achieved in 2012, and plans to reach CDM targets by the end of 2014. Hydro One Networks Inc. reported that it expects to reach 100% of its demand target and 80% of its cumulative energy target by 2014. Hydro One Brampton Networks Inc. reported that it expects to reach 68% of its demand target and 100% of its cumulative energy target by 2014. The OEB has indicated that there are several LDCs that have a similar issue. The OEB is aware of our situation.

On December 21, 2012, the Minister issued a directive to the OPA to extend funding for the OPA-contracted Ontario-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, and to keep customer programs in place for 2015.

On July 16, 2013, the Ministry released a white paper entitled “Conservation First” for stakeholder consultation regarding development of CDM

framework post 2014. The white paper expressed a Renewed Vision for Energy Conservation in Ontario, and is available at the following link: http://www.energy.gov.on.ca/en/conversation-first.

Stakeholders were invited to submit comments by September 16, 2013. Hydro One Networks Inc., as a part of the Coalition of Large Distributors, submitted comments in response to the paper. The Province will take into account stakeholders’ input as they make a decision on the new CDM framework. The 2013 LTEP calls for 30 TWh of energy savings by 2032, and 2,400 MW of demand response by 2025.

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. As part of Hydro One Networks Inc.’s distribution rate case for the test years 2010 and 2011, funding of $92 million in capital and $20 million

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in OM&A were approved by the OEB. The approved funding for 2010 and 2011 was to be recovered via a rate rider to be reviewed only with respect to the actual level of spending. We did not seek any additional funding in 2012. $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 Advisory Committee. In 2013, as part of Hydro One’s 2014 funding request, the OEB agreed with the prudence of ADS related expenditures to the end of 2013 and approved additional 2014 funding of $29 million in capital and $15.8 million in OM&A. Recovery of costs in the variance account is being sought in the current Hydro One distribution rate application, for 2015 to 2019 rates.

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 majority of the build phase was completed, with the remainder planned for completion in 2014. End-to-end solution validation, to confirm design decisions and provide real time experience with the components, is underway.

Work is also underway on pilot projects, which involve leveraging the Distribution Management System solution to support voltage optimization, utilizing the Smart Meter Advanced Meter Infrastructure network capabilities to support outage detection and restoration, as well as theft detection. These initiatives will continue in 2014 and will be augmented with additional pilot projects that build on ADS work to date.

On June 27, 2013, the OEB announced the creation of the Smart Grid Advisory Committee to provide it with on-going assistance on emerging ADS issues as it proceeds with facilitating the development and implementation of ADS in Ontario. Hydro One is a member of the Smart Grid Advisory Committee.

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.

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Hydro One Networks Inc. and Hydro One Brampton Networks Inc. have installed approximately 1.4 million smart meters as of the end of 2013 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 2013 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 2013, Hydro One continued to optimize the smart meter communication network through a number of firmware and software upgrades and communication network equipment optimization to enhance network performance levels.

In this regard, Hydro One Networks Inc. has transitioned approximately 1.1 million customers to TOU pricing as of the end of 2013. Hydro One Brampton Networks Inc. completed its transition to TOU pricing in 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.

On April 25, 2013, Hydro One Brampton Networks Inc. received approval from the OEB for the final disposition of the smart meter deferral accounts. Hydro One Brampton Networks Inc. received approval for two rate riders; the first rider is for a final disposition amount of approximately $1.9 million. The second rate rider relates to the incremental revenue requirement associated with 2013 (8 months) and 2014 (full year) and is estimated at $1 million and $1.5 million respectively.

Smart meter expenditures for 2013 were $21.4 million for Hydro One Networks Inc. Planned expenditures in 2014 are expected to be approximately $19.3 million for Hydro One Networks Inc.

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 for certain customers in our service area. 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. Hydro One Networks Inc. received an exemption from the OEB, effective until December 31, 2014, from implementing mandatory TOU pricing for customers that are currently out of reach of our smart meter telecommunications infrastructure. Hydro One

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Networks Inc. continues to 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.

Hydro One Networks Inc. is recalling and replacing a certain type of installed commercial/industrial grade smart meter as approximately 0.27% of this class of meter have malfunctioned in a manner causing physical damage to the meter. Approximately 16,000 meters will be replaced.

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 registered with the Canadian Radio-television and Telecommunications Commission as a 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 6,000 kilometres. 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 and smart meter and ADS operations. In addition, it has recently assumed accountability for telecom engineering design services which will allow it to optimize its delivered services.

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

10. Cornerstone

1. Employees

At the end of 2013, our Hydro One Networks Inc. subsidiary had 5,205 regular (i.e., permanent) employees comprised of 611 non-represented executive and managerial staff, 3,328 employees represented by the PWU and 1,266 employees represented by the Society. Hydro One Inc., Hydro One Remote Communities Inc. and Hydro One Telecom Inc. together have 225 employees in total. Hydro One Inc., Hydro One Networks Inc.,

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Hydro One Remote Communities Inc. and Hydro One Telecom Inc. also had 2,086 non-regular (i.e., temporary) employees comprised of 27 executive and managerial staff, 225 employees represented by the PWU, 48 employees represented by the Society, 630 employees covered by Appendix “A” of the PWU agreement (PWU Hiring Hall) and 1,156 employees represented by a combination of the Canadian Union of Skilled Workers (an electrical trade union) and the construction building trade unions which are of relevance to Hydro One because they have collective agreements with the Electrical Power Sector Construction Association (“EPSCA”). Hydro One maintains membership in EPSCA, an employers’ association that bargains collective agreements on behalf of its membership. Hydro One’s membership in EPSCA is ongoing. In addition, our Hydro One Brampton Networks Inc. subsidiary had 55 non-represented regular staff, 112 active employees represented by UNIFOR (previously the Canadian Auto Workers), 44 employees represented by the International Brotherhood of Electrical Workers and 23 contract staff.

On May 16, 2013, 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, 2013, to

March 31, 2015. Also in 2013, we negotiated a three-year agreement with the Society. This agreement expires on March 31, 2016. The collective agreement with the Canadian Union of Skilled Workers expires on April 30, 2014. The Hydro One Brampton Networks Inc. agreements with UNIFOR and the International Brotherhood of Electrical Workers expire on March 31, 2014. 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 12 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

The Strong Action for Ontario Act (Budget Measures), 2012 was passed on June 20, 2012. This statute amends the Broader Public Sector Accountability Act, 2010 and implements new wage restraint measures on executive compensation. 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”.

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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, 2013, there were 5,379 active members and 7,637 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 source to pay services, pay operations services, information technology and finance and accounting services.

The Inergi 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 LP 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. 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 Inergi 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. See “Risk Factors – Risk Associated with Outsourcing Arrangement”.

Effective September 30, 2013, pursuant to section 108 of the Business Corporations Act (Ontario), the Province made a declaration regarding the outsourcing of services covered by the Inergi Agreement. See “Interest of Management and Others in Material Transactions – Relationships with the Province and Other Parties – Memorandum of Agreement”.

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A request for proposal was issued November 7, 2013 to pre-qualified proponents, seeking a supplier or suppliers to deliver the services on expiration of the Inergi Agreement. Responses were initially due from pre-qualified entities on February 18, 2014. However, the closing date has now been deferred.

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 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.

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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 two ppm or more that have been removed from equipment cannot be reused.

On June 22, 2013, the Government of Canada issued a proposed amendment to its existing PCB regulations. The proposed amendment would extend our end-of-use deadline for concentrations, equal to or greater than 500 ppm in our stations, from December 31, 2014 (based on our existing approved end-of-use extension) to December 31, 2025.

To date, approximately 97.7% of Hydro One’s PCBs have 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 258,000 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 remaining non-capital future expenditures to comply with the final PCB regulations introduced in 2008 is about $237 million. After consideration of our 2013 spending of $2 million, this represents an increase of about $4 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 environmental liability by approximately

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$3 million in 2013. This liability represents the present value of our estimated future non-capital expenditures. We anticipate that these future expenditures will 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 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, 2013, 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.

Herbicide

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 investigated the use of 2,4,5-T by the Province’s ministries and agencies and examined whether exposure to 2,4,5-T herbicide may have potential health impacts. The findings of the panel were released to the public on June 13, 2013. The Ministry of Natural Resources is reviewing the report and has not yet decided whether changes or procedures are needed to be taken to address the findings. 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 Preservative

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,

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where necessary, the development of remediation plans for our properties and affected adjacent private properties. Potential contaminants include insulating oils, substances previously used for vegetation control such as arsenic trioxide, and other substances such as fuel oil, gasoline, PCBs and wood preservatives such as pentachlorophenol. Phase I 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 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 192 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 $54 million. These expenditures are expected to be spent over the period ending 2022 with most of the expenditures occurring prior to 2020. The consolidated expenditures on this program (including Hydro One Remote Communities Inc.) for 2013 were approximately $14 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’ health¹. Health Canada “does not consider that any precautionary measures are needed regarding daily exposures to electric and magnetic fields at extremely low frequency. There is no conclusive evidence of any harm caused by exposures at levels found in Canadian homes and

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.

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schools, including those located just outside the boundaries of power line corridors.”² 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 2013, 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 2013. It is expected to continue in future years.

During 2013, there was a focus on the following areas: Journey to Zero initiatives (including a safety culture assessment by DuPont, which included a survey, site assessment, leadership interviews and focus groups), obtaining OHSAS 18001 registration, skills and safety training, field coaching/mentoring, young and new worker safety and a number of employee health and 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. The successful OHSAS 18001 registration of the Health and Safety and Environment Management System will allow us to enhance our health & safety

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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performance through a structured approach that drives continual improvement. 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 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.

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 of next-generation business tools to make precision investments in capital and OM&A to obtain maximum benefit, 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.

Hydro One began reporting under U.S. GAAP in the first quarter of 2012 with one year of comparative restatement for 2011, in accordance with an OSC exemption, which is effective for the financial years ended 2012, 2013 and 2014. Hydro One’s opening U.S. GAAP consolidated

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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 annual and quarterly 2012 consolidated financial statements.

The OEB approved the use of U.S. GAAP for regulatory purposes by Hydro One Networks Inc.’s transmission and distribution businesses, as well as by our subsidiary, Hydro One Remote Communities Inc., beginning with the year 2012. Our subsidiary Hydro One Brampton Networks Inc. has deferred its adoption of modified IFRS to the year beginning January 1, 2015, as allowed by the Canadian Accounting Standards Board. Hydro One Brampton Networks Inc. will report under Canadian GAAP for the year ended December 31, 2013.

Registration of Securities in the United States – Securities and Exchange Registration

In October 2013, Hydro One became a reporting company under the U.S. Securities Exchange Act of 1934, as amended (the “Exchange Act”), thus a Securities and Exchange Commission (“SEC”) registrant, and listed its 2.78% Medium Term Notes due 2018 and 4.59% Medium Term Notes due 2043 on the “NYSE”. As permitted by Canadian securities laws, Hydro One intends to prepare its financial statements in U.S. GAAP so long as the notes remain listed on the NYSE or Hydro One otherwise continues to be subject to U.S. reporting obligations.

10. Cornerstone

Cornerstone is a four-phased project, which 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.

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 to drive additional business value, improve end-to-end process efficiency and improve asset lifecycle management analytics/decisions. Cornerstone Phase Three is comprised of engineering design transformation, asset analytics, business planning, human resources expansion, planning and scheduling, meter management, supply chain expansion and business intelligence expansion.

The last phase, Phase Four replaced 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). This phase was completed in 2013.

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REGULATION

Hydro One’s transmission and distribution businesses are primarily regulated by the OEB and the NEB. In this section, we discuss the regulatory impact on our transmission and distribution businesses. We provide a general overview of the federal and provincial framework to which we are subject and a brief introduction to the regulatory process in Ontario.

As a regulated company, we are subject to various contractual arrangements, codes and licences which we describe in more detail in this section. As the OEB approves both the revenue requirements of and the rates charged by our regulated businesses, we discuss our current rate orders and rate structures for both our transmission and distribution businesses.

The Statutory and Operating Framework

Federal Framework

While most electricity power lines and facilities in Canada fall within provincial jurisdiction, the NEB has jurisdiction over the construction and operation of international power lines (IPLs) and interprovincial lines that are designated as being under federal jurisdiction (no interprovincial lines currently fall under NEB jurisdiction). Hydro One Networks Inc. owns and operates IPLs with New York, Michigan and Minnesota, and is subject to several NEB-issued certificates and permits. According to the NEB Act, any modifications to an IPL require NEB approval.

On December 6, 2012, the NEB issued a general order and five amending orders for mandatory electricity reliability standards for certain IPLs in Canada. The orders (i) require Hydro One Networks Inc., as the owner of such lines, to comply with specified NERC and NPCC reliability

standards, (ii) mandate certain reporting requirements, and (iii) contain provisions for IPL owners to seek exemptions. On March 6, 2013, Hydro One Networks Inc. submitted to the NEB a declaration of compliance and a request for indefinite exemptions from a list of standards that do not apply to Hydro One Networks Inc. or to the IPLs it owns. On November 13, 2013, the NEB granted Hydro One Networks Inc.’s exemption requests, with some minor exceptions.

Ontario Framework

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.

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The Ontario Regulatory Process

The major participants in the regulatory process are as follows: the regulated entity, namely Hydro One Networks Inc., Hydro One Brampton Networks Inc., or Hydro One Remote Communities Inc.; Ontario Energy Board staff; and intervenors. Intervenors are parties interested in the outcome of a rate case, such as consumer groups and other electric utilities.

A review process begins when the regulated entity files an application to request a change in rates or when the regulator determines on its own initiative to review the regulated entity’s rates. A hearing is announced, and the regulated entity makes its submission by filing what is known as “prefiled evidence”. Intervenors and the regulator’s staff may also file evidence. Any party to the hearing may then pose interrogatories (requests for information) to other parties who have filed evidence.

The next step may be an “issues day” to articulate the items that are at issue in the hearing, and there may also be a motion to the regulator to determine the scope of the hearing, if scope is an issue. After the preceding steps, the parties may attempt to negotiate a settlement or partial settlement. The issues that have not settled go to a hearing, which may be either written or oral. After the completion of the hearing, the regulator has up to 60 days to issue a decision with reasons. The decision often requires the applicant to submit a draft rate order that is based on the regulator’s decision. The regulator then issues its final rate order by either approving the draft rates or making revisions to them.

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. Our operating agreement with the IESO, which sets out the specific responsibilities of both parties relating to the provision of transmission service, extends until 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 LDCs in accordance with the regulatory framework.

Hydro One’s Relationships with Other Market Participants

Generators, LDCs and customers directly connected to our transmission system must enter into agreements with us to ensure reliable connection service in conformity with the TSC 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.

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Electricity Industry Codes

The OEB has issued and in some cases amended several codes that govern the operation of OEB-licensed entities in Ontario. These codes include the Affiliate Relationships Code for Electricity Distributors and Transmitters, the Standard Supply Service Code, the TSC, the DSC, the Retail Settlement Code, the Electricity Retailer Code of Conduct, the Smart Sub-Metering Code and the CDM Code.

On August 26, 2013, the OEB issued amendments to the TSC and the DSC. These amendments support the recommendation of the Planning Process Working Group, of which Hydro One Networks Inc. is a member, for the move to a more structured approach to regional infrastructure planning, leading to the execution of regional infrastructure plans. The OEB, at the same time, also issued supplementary proposed amendments to the TSC to clarify certain cost responsibility matters raised by Hydro One Networks Inc., specifically, the ability of transmitters to pool-fund some connection costs. On October 21, 2013, the OEB also amended the OPA’s licence to support the new regional planning process. Hydro One Networks Inc. expects the TSC and the DSC amendments will further promote cost-effective development of electricity infrastructure (process and methodology) through coordinated regional planning and clearer definitions of cost responsibilities.

In May 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”. In June 2013, the OEB issued its final amendments to the DSC for micro-embedded generation. The DSC changes, effective as of June 13, 2013, included

clarifications regarding timelines, which grant more time to process indirect connections that require a site visit. The OEB agreed with Hydro One’s suggestion to fully mirror micro-embedded generator connection timelines with those for load customers. Hydro One has now achieved compliance with the requirements of the DSC regarding micro-embedded generator connectors.

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.

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.

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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.

A. Transmission

Current Rate Orders and Review of the Existing Transmission Rate Structure

Hydro One Networks Inc.’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.

In November 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. In December 2012, the OEB issued its final rate order for 2013 Ontario Uniform Transmission Rates approving Hydro One Networks Inc.’s transmission 2013 revenue requirement of $1,438 million. The approved 2013 transmission rates did not change from the 2012 OEB-approved rate levels. Primarily due to changes in the cost of capital parameters for 2014 released by the OEB in November 2013, the 2014 revenue requirement has been increased to $1,535 million from the originally-approved revenue requirement of $1,528 million. In January 2014, the OEB approved Hydro One Networks Inc.’s draft rate order as filed. In total, the approved 2014 revenue requirement represents a transmission rate increase of 6.3% in 2014, or 0.5% when considering total bill impact.

In May 2012, Hydro One Networks Inc. submitted a cost of service rate application for its transmission business, with 2013 and 2014 as test years. An agreement was reached between Hydro One Networks Inc. and the intervenors to this application, settling all issues but one, being ETS. The settlement proposal was reviewed and accepted by the OEB. In June 2013, the OEB issued its decision and order with respect to ETS and ordered that Hydro One Networks Inc.’s ETS rate remain at two dollars per MWh.

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

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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 TSC, 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.

On August 26, 2010, the OEB released its 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.

In March 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 target in-service date is 2017. Hydro One participated in the designation process as one of three equal partners, including Great Lakes Transmission and Bamkushwada LP (involving a number of First Nations in the area of the East-West Tie). In August 2013, the OEB issued a decision and order declaring Upper Canada Transmission Inc., a competitor to the Hydro One consortium, to be the designated transmitter for the development phase of the proposed East-West Tie line. Hydro One is in discussions with the designated transmitter regarding the details of the connection of the line to our stations.

Facilities Applications

Transmission line expansions greater than two 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.

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On November 23, 2010, the Ministry posted the 2010 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 improvements for ten transmission stations. The upgrades at six transmission stations were successfully completed in 2011 and 2012. Alternative solutions to upgrades were determined for three transmission stations. The upgrades at the tenth transmission station were completed in June 2013.

B. Distribution

In December 2010, the OEB initiated a coordinated consultation process for the development of a RRFE. On October 18, 2012, the OEB issued its report, “A Renewed Regulatory Framework for Electricity Distributors: A Performance Based Approach”. The report identified three rate-setting models available to provide choices suitable for distributors having varying capital requirements: a fourth generation IRM; a custom rate setting; and an annual incentive rate-setting index method. The report also provided information on performance measurement, continuous improvement and implementation of the new framework.

In late 2013, the OEB issued its “Report of the Board on Rate Setting Parameters and Benchmarking under the Renewed Regulatory Framework for Ontario’s Electricity Distributors”.

This report sets out the OEB’s policies and approaches to the rate adjustment parameters for incentive rate setting for electricity distributors and the benchmarking of electricity distributor total cost performance. It also includes the OEB’s determination on rate adjustment parameter values for 2014 incentive rate setting, which were used to adjust Hydro One Networks Inc.’s 2014 distribution rates.

Current Rate Orders and Distribution Rate Structure

a) Hydro One Networks Inc.

In December 2012, the OEB issued a final rate order relating to Hydro One Networks Inc.’s IRM application for 2013 distribution rates. A typical residential customer consuming 800 kWh per month saw 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 brought the total bill increase in 2013 to 1.5%.

In April 2013, Hydro One Networks Inc. filed a distribution rate application under the OEB’s IRM, for rates effective January 1, 2014. In December 2013, the OEB issued its final decision on the IRM application. The distribution rate for a typical residential customer consuming 800 kWh per month will increase by approximately 2.4% in 2014. The total bill impact will be an increase of approximately 0.85%.

In December 2013, Hydro One Networks Inc. filed its 2015-2019 distribution custom rate application with the OEB, for rates effective January 1 of each test year. This application is a five-year custom application which is being submitted under the OEB’s RRF. It has been customized to fit Hydro One Networks Inc.’s specific circumstances, which necessitate

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significant and necessary multi-year investments. The submitted evidence includes the overall business plan, revenue requirements, and rate information necessary to support the issuance of a notice by the OEB. If the application is approved as filed, the resulting change to the distribution portion of the average customer bill will be approximately 1.3 % decrease in 2015, 4.2% increase in 2016, 2.6% increase in 2017, 1.9% increase in 2018 and 2.9% increase in 2019, for a typical residential customer consuming 800 kWh per month. When considering total bill impact, the resulting change will be approximately 1.1% decrease in 2015, 1.5% increase in 2016, 0.9% increase in 2017, 0.7% increase in 2018 and 1.1% increase in 2019.

b) Hydro One Brampton Networks Inc.

In August 2012, Hydro One Brampton Networks Inc. applied for an adjustment to its 2013 distribution rates effective January 1, 2013. In December 2012, the OEB approved Hydro One Brampton Networks Inc.’s request for an increase of 1.28% to its 2012 approved basic rates. The impact on the distribution component of the customer’s bill for a typical residential customer with monthly electricity consumption of 800 kWh was an increase of seven cents or 0.33%, with an increase on the total bill of seven cents or 0.06%.

In December 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. In April 2013, Hydro One Brampton Networks Inc. received approval from the OEB for the final disposition of the smart meter deferral accounts. The company received approval for two rate riders; the first rider is for a final disposition amount of approximately $1.9 million to be recovered over 20 months; and the second rate rider relates to the incremental revenue requirement associated with 2013 (eight

months) and 2014 (full year) and is estimated at $1 million and $1.5 million, respectively. In addition, a common rate rider for the residential and general service < 50 kW classes was replaced by a separate rate rider for each class. Based on the approved rate riders, 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 55 cents or 2.53%, with a total bill impact of approximately 55 cents or 0.5%.

In August 2013, Hydro One Brampton Networks Inc. filed its 2014 third generation IRM electricity distribution rate application requesting new distribution rates effective January 1, 2014. On December 5, 2013, the OEB approved Hydro One Brampton Networks Inc.’s request for an increase of 1.4% to its 2013 approved basic distribution rates, adjustments to transmission rates, new rate riders for the disposition of deferral and variance accounts, a shared tax savings amount, and an adjustment to the GEA funding adder. The new rate riders that the OEB approved relate to Group 1 deferral and variance account balances of approximately $8.3 million to the end of 2012 including projected carrying charges to December 31, 2013. The OEB also approved Hydro One Brampton Networks Inc.’s request for a two-year disposition period for these riders. 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 a decrease of approximately 59 cents or 2.32%, and a decrease of approximately 60 cents or 0.5% on the total bill.

c) 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

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example, Hydro One Remote Communities Inc. continues to apply bundled rates to customers in remote communities. Hydro One Remote Communities Inc.’s business is operated on a break-even basis. As a result, any net income or loss in the year is recorded in a regulatory variance account for inclusion in the calculation of future customer rates.

In September 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. In September 2013, the OEB approved the proposed rate increase and annual rate protection of approximately $32.3 million.

In October 2013, Hydro One Remote Communities Inc. filed an application for 2014 distribution rates under the OEB’s IRM. The final rate increase will be adjusted by the OEB’s updated rate adjustment parameters and Hydro One Remote Communities’ IRM stretch factor, which is currently under review by the OEB. The OEB approved Hydro One Remote Communities Inc.’s application, and effective May 1, 2014, the rates will increase by 1.7%.

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 2013, the OEB approved an annual amount of rate protection of $32.3 million for our remote customers. The amount approved for Hydro One Remote Communities Inc. in 2013 is an annual amount until changed by the OEB. The OEB calculates it each year, but only resets it when requested to do so.

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

On December 21, 2011, the OEB issued a decision and order setting the charge for 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 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 kWh. The OEB further determined that effective May 1, 2012, the RRRP charge to be collected by the IESO shall be reduced to 0.11 cents per kWh.

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 be increased to 0.12 cents per kWh. The RRRP charge used by rate regulated distributors to bill their customers continued to be 0.11 cents per kWh effective January 1, 2013. On April 2, 2013, the OEB issued a decision and order, increasing the RRRP charge used by rate distributors to bill their customers to 0.12 cents per kWh effective May 1, 2013.

On December 19, 2013, the OEB issued a

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decision and order setting the charge for RRRP for 2014. The OEB determined that the RRRP charge to be collected by the IESO will remain at 0.12 cents per kWh from January 1 to April 30, 2014, but the charge will increase to 0.13 cents per kWh effective May 1, 2014. The RRRP charge used by rate regulated distributors to bill their customers will remain at 0.12 cents per kWh effective January 1, 2014 and will increase to 0.13 cents per kWh effective May 1, 2014.

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.

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, modern 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 applies only to the first 3,000 kWh of electricity consumed per month.

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.

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REGULATION

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. Hydro One is currently seeking a prudence review of the costs and disposition of the deferral accounts associated with connecting these generators in its 2015-2019 custom rate application.

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RISK FACTORS

RISK FACTORS

Ownership by the Province

The Province owns all of our outstanding shares. Accordingly, the Province has the power to determine the composition of our Board, 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 Inergi Agreement. In 2011, the Province made a declaration preventing our company from seeking cost recovery through the regulatory process for the cost of upgrades required for either Micro FIT or Small FIT generators for costs related to investment and expenditures made. Effective September 30, 2013, the Province made a declaration regarding the outsourcing of services covered by the Inergi Agreement. 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

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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.

The OEB’s new RRF requires that the term of a custom rate application (distribution business) is a five-year period. There are risks associated with forecasting over a longer period. Changes in the industry may alter the investment needs or require changes to rate setting that could result in a significant impact on Hydro One’s capability to execute its plan.

To mitigate the risk of externally driven factors that may impact its plan, Hydro One Networks Inc. proposed a number of adjustment mechanisms in the design of its recent custom application to reflect plan changes outside the normal course of business in order for the company to avoid a regulatory review by the OEB during the five-year custom application period. Hydro One Networks Inc. also proposed a set of outcome measures to track its performance and delivery of the plan. There can be no assurance that the OEB will accept these mechanisms or that they will be sufficient to protect Hydro One from unforeseen changes to its plan.

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 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 BES unless we are granted an exception which will allow the application of the new definition in a cost-effective manner. Hydro One plans to submit exception applications and will look for recovery for costs incurred in meeting the definition in our rates; however, an adverse decision on an exception or recovery of costs could have an 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

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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.

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, including $750 million maturing in 2014 and $550 million maturing in 2015. We plan to incur capital expenditures of approximately $1.6 billion in each 2014 and 2015. 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.

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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 communities 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 Associated with Outsourcing Arrangement

Consistent with our strategy of reducing operating costs, we amended and extended the Inergi Agreement, effectively renewing the arrangement until February 28, 2015. See “Description of the Business – Outsourcing Arrangement with Inergi LP”. If the Inergi Agreement is terminated for any reason or expires before a new supplier is selected, 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 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: EA approval(s); receipt of OEB approvals which can include expropriation; and appropriate consultation processes with First Nations and Métis communities. 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 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 recoverable only by the successful proponent. This could have a material adverse effect on our company.

Asset Condition

We continually monitor the condition of our assets

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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 2013, approximately 16% of our employees were eligible for retirement and by the end of 2014 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.

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 and increased pension contributions for PWU and Society staff, we may not be able to achieve further improvement. The existing collective agreement with the PWU will expire on March 31, 2015, and the existing Society collective agreement will expire on March 31, 2016. 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.

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 minimally required to be filed with the Financial Services Commission of Ontario on a triennial basis. The

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most recently filed valuation was prepared as at December 31, 2011, and was filed in May 2012. Our company contributed approximately $160 million in respect of 2012 and approximately $160 million in respect of 2013 to its pension plan to satisfy minimum funding requirements. Contributions beyond 2013 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.

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 (see “Committees of the Board of Directors – Health, Safety and Environment Committee”). However, given the territory that our system encompasses and the amount of equipment that we own, we cannot guarantee 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 2022. 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.

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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 and building new facilities. Any of these could have a material adverse effect on our company.

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 price 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 in a deemed regulatory capital structure of 40% common equity and 60% debt 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’ 2014 net income by approximately $20 million and our Hydro One Networks Inc. distribution business’ 2014 net income by approximately $10 million. Our net income is adversely impacted by rising interest rates as our maturing long-term debt is refinanced at market rates. We periodically utilize interest rate swap agreements to mitigate elements of interest rate risk.

Financial assets create a risk that a counterparty will fail to discharge an obligation, causing a financial loss. Derivative financial instruments result in exposure to credit risk, since there is a risk of counterparty default. We monitor and minimize credit risk through various techniques, including dealing with highly-rated counterparties, limiting total exposure levels with individual counterparties, and by entering into master agreements which enable net settlement and by monitoring the financial condition of counterparties. We do not trade in any energy derivatives. We do, however, have interest rate swap contracts outstanding from time to time. Currently, there are no significant concentrations of credit risk with respect to any class of financial

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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 Settlement Code. The failure to properly manage these risks could have a material 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. Where the agreement and permit are for transmission assets, Hydro One must

negotiate rental terms. 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. In 2013, we paid approximately $2 million to First Nations in respect of these agreements. OEFC will continue to hold these assets until we are able to negotiate agreements with First Nations and occupants. If we cannot reach satisfactory agreements and obtain federal permits, we may have to relocate these assets to other locations at a cost that could be substantial. In a limited number of cases, it may be necessary to abandon a line and replace it with diesel generation facilities. In either case, 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 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

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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 $200 million in 2013 as compared with $352 million in 2012

and $150 million in 2011. 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 2013, 2012 and 2011, 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 2013 in the amount of approximately $138 million, as compared to $197 million in 2012.

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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, 2013, 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 designated 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 adverse 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 on 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. We have not made any payment to S&P, DBRS or Moody’s in respect of any other services during the last two years.

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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 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, Series 27 Notes (Floating Rate 3-month BA + 0.37%) due 2016, Series 28 Notes (2.78%) due 2018, Series 29 Notes (4.59%) due 2043, Series 30 Notes (4.29%) due 2064 and Series 31 Notes (Floating Rate 3-month BA + 0.35%) due 2019 are currently outstanding and, except for the Series 28 Notes and Series 29 Notes, are not listed on any exchange or similar market for securities. Our Series 28 Notes and Series 29 Notes are listed for trading on the NYSE.

Prior Sales

Our company issued the following tranches of medium term notes in 2013; both tranches were listed on the NYSE:

Note	Principal Amount   (million) ($)	Sale Price ($) /   $100 principal amount	Gross Proceeds ($)
Series 28 (2.78%) due 2018	750	99.995	$749,962,500
Series 29 (4.59%) due 2043	435	99.984	$434,930,400

Trading Price and Volume

Our Series 28 Notes (2.78%) due 2018 are listed on the NYSE under the symbol “HYDO18”. Our Series 29 Notes (4.59%) due 2043 are listed on the NYSE under the symbol “HYDO43”. In the period from their date of issuance to December 31, 2013, there have been no reported trades of the Series 28 Notes or the Series 29 Notes on the NYSE.

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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, 2013.

Name and Municipality of Residence	Principal Occupation
James Arnett (2)	Chair of the Board of
Toronto, Ontario	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 (5) (6) (7)	President,
Toronto, Ontario	TBG Strategic Services Inc.
Canada	Corporate Director
(Director since March 30, 2007)
George Cooke (1) (4) (7)	President,
Toronto, Ontario	Martello Associates Consulting
Canada
(Director since January 25, 2010)	Chair of the Board of Directors of
	OMERS Administration Corporation
Catherine Karakatsanis (5) (6)	Chief Operating Officer,
Toronto, Ontario	Morrison Hershfield Group Inc.
Canada
(Director since November 27, 2013)
Don MacKinnon (4) (5)	President,
Chatsworth, Ontario	Power Workers’ Union
Canada
(Director since June 11, 2002)
Carmine Marcello	President and Chief Executive Officer,
Thornhill, Ontario	Hydro One Inc.
Canada
(Director since January 1, 2013)
Michael J. Mueller (1) (2) (6)	Corporate Director
Tecumseh, Ontario
Canada
(Director since March 30, 2007)

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DIRECTORS AND OFFICERS

Walter Murray (1) (3) (7)	Corporate Director
Bracebridge, Ontario
Canada
(Director since November 10, 2005)
Robert L. Pace (2) (3) (7)	President and Chief Executive Officer,
Seabright, Nova Scotia	The Pace Group Ltd.
Canada
(Director since March 30, 2007)
Yezdi Pavri (1) (6)	Corporate Director
Toronto, Ontario
Canada
(Director since December 6, 2012)
Sandra Pupatello (1) (4) Windsor, Ontario Canada (Director since November 20, 2013)	Director, Business Development and Global Markets,
	PricewaterhouseCoopers
	Chief Executive Officer,
	WindsorEssex Economic Development
	Corporation
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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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 at the law firm of Stikeman Elliott 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 SPRINT Senior Care. 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, Sheridan College Institute of Technology and Applied Learning, and St. Joseph’s Health Care. 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 President, Martello Associates Consulting, a business strategy consulting firm, and on October 1, 2013 he was appointed as Chair of the Board of Directors of the OMERS Administration Corporation. OMERS is one of Canada’s largest pension funds and the OMERS Administration Corporation is responsible for pension services and administration, investments, and plan valuation. 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

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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 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. Mr. Cooke was a member of the Board of Directors of The Dominion of Canada General Insurance Company and Insurance Bureau of Canada and was also an Executive Vice President with E-L Financial Corporation Limited. He is also currently the Chair of the Board of Directors of CANATICS (Canadian National Insurance Crime Services). Mr. Cooke has been a Director of our company since January 26, 2010.
CATHERINE KARAKATSANIS Director	Catherine Karakatsanis is the Chief Operating Officer of Morrison Hershfield Group Inc. and also serves as Director and Secretary of the Toronto-based consulting engineering firm. Ms. Karakatsanis joined Morrison Hershfield in 1989, serving in a variety of engineering and senior management positions before becoming COO in 2012. Ms. Karakatsanis’ leadership volunteer activities include serving as the Director, Board of Directors, Engineers Without Borders; Immediate Past President and Chair, Board of Directors, Engineers Canada; Director, Board of Directors for the Canadian Engineering Memorial Foundation and Fellow of The Canadian Academy of Engineering. She is a member of a number of professional organizations, including The Ontario Society of Professional Engineers, Consulting Engineers Ontario and The Association
of Professional Engineers, Geologists and Geophysicists of Alberta. Ms. Karakatsanis obtained her Bachelor of Engineering Science and Masters of Engineering Science at The University of Western Ontario. Ms. Karakatsanis has been a Director of our company since November 27, 2013.
DON MACKINNON Director	Don MacKinnon has been President of the Power Workers’ Union, an electricity industry workers union, since May 2000 and a lineman by trade since 1971. He was Vice-President of the Power Workers’ 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’n Drive 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.

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CARMINE MARCELLO President and Chief Executive Officer	Carmine Marcello was appointed President and Chief Executive Officer of Hydro One Inc. in January 2013. He joined Ontario Hydro in 1987 and has over 25 years’ experience in the electric utility industry and has held many senior management positions at Ontario Hydro and then Hydro One Inc. In 2007, he was appointed Vice President, Corporate Projects and in 2009 he was appointed Senior Vice President, Asset Management and was responsible for the life cycle management of Hydro One’s transmission and distribution assets including Hydro One’s Smart Grid Initiative. In 2010 he was appointed Executive Vice President, Strategy and was responsible for transmission and distribution asset management, transmission and distribution development, business and power systems, IT, Telecom and the operations of the Hydro One subsidiaries, Hydro One Brampton Networks Inc. and Hydro One Telecom Inc. Mr. Marcello
currently serves as the Chair of the Hydro One Brampton Networks Inc. Board of Directors. He is a member of the Canadian Electricity Association (CEA), Ontario Energy Association (OEA) and Plug’n Drive’s Board of Directors. Mr. Marcello is also a member of the Electricity Sub-Sector Coordinating Council’s Executive Committee, holds a position on the Electric Power Research Institute’s Research and Advisory Committee and on the Canadian Council of Chief Executives Advisory Committee on Cyber-Security. Mr. Marcello previously served on the North American Transmission Forum Board of Directors and the NERC Member Representatives Committee (MRC). He has held previous positions on the OEN Board of Directors and is the past Chair of the CEA Transmission Council. Mr. Marcello holds a Master of Business Administration from York University, a Bachelor of Applied Science in Electrical Engineering from the University of Toronto and holds an ICD.D designation from the Institute of Corporate Directors. Mr. Marcello has been a Director of our company since January 1, 2013.
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.

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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.
ROBERT L. PACE Director	Robert L. 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 Vice-Chairman of the Board of Directors of Canadian National Railway Company and is a member of the Board of Directors of 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.

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SANDRA PUPATELLO Director	Sandra Pupatello is the Director of Business Development and Global Markets at PricewaterhouseCoopers Canada, a position she has held since 2012. PwC provides audit and assurance, consulting, deals and tax services for public, private and government clients. In May 2013, she was appointed as the Chief Executive Officer of the WindsorEssex Economic Development Corporation. Ms. Pupatello was first elected into the Ontario legislature in 1995 and appointed to Cabinet in 2003. Between 2003 and 2011, she held several portfolios, including Minister of Community and Social Services, Minister of Education, Minister of Economic Development and Trade and Minister of International Trade and Development. Ms. Pupatello’s past positions include Executive Director of the Essex County
Kidney Foundation of Canada, General Manager of the Rotary Club of Windsor and Board Member of the Windsor Regional Hospital and Windsor Regional Children’s Centre. She holds a Bachelor of Arts and honourary Doctor of Law degree from the University of Windsor. Ms. Pupatello has been a Director of our company since November 20, 2013.
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 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 and is an Emeritus Member of the Advisory Board of the Ivey Business School at Western University. He is Past Chair and Director of the Ivey Services Company and Past Chair of the Ivey Business School Alumni Association. He is also Past Chair of the Executive Board of the Canadian Industry Program for
Energy Conservation (a joint Industry-Federal Government Initiative). Mr. Speers is a member of the Board of Directors of Ceres Global Ag Corporation and serves as Lead Director. He has been a Director of our company since November 10, 2005.

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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.

Executive Officers

The following table sets forth the name, municipality of residence and position of each of our executive officers as of December 31, 2013.

Name and Municipality of Residence	Position With Our Company
James Arnett	Chair of the Board of Directors of
Toronto, Ontario	Hydro One Inc.
Canada
Carmine Marcello	President and Chief Executive Officer
Thornhill, Ontario
Canada
Sandy Struthers	Chief Administration Officer and
Toronto, Ontario	Chief Financial Officer
Canada
Peter Gregg	Chief Operating Officer
Oakville, Ontario
Canada

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  JAMES ARNETT   Chair of the Board of Directors Hydro One Inc. James Arnett’s biographical information is presented above under “Directors”.   CARMINE MARCELLO President and   Chief Executive Officer Carmine Marcello’s biographical information is presented above under “Directors”.

SANDY STRUTHERS Chief Administration Officer and Chief Financial Officer

Sandy Struthers was appointed as Chief Administration Officer and Chief Financial Officer effective January 1, 2013. Prior to this, Mr. Struthers was Executive Vice President and Chief Financial Officer. Mr. Struthers joined Hydro One in 2000 as a Director in the Finance area, was appointed as Chief Information Officer in 2005 and then was appointed as Senior Vice President and Chief Financial Officer in 2009. Prior to joining Hydro One, Mr. Struthers was a partner in a national accounting firm.

PETER GREGG Chief Operating Officer

Peter Gregg was appointed Chief Operating Officer effective January 1, 2013. Prior to this, he was Executive Vice President, Operations. Mr. Gregg joined Hydro One Networks Inc. in 2004 as Vice President, Corporate Affairs and was appointed as Vice President, Executive Office in 2005, Vice President, Corporate and Regulatory Affairs in 2007 and Senior Vice President, Corporate and Regulatory Affairs in 2009. Prior to joining Hydro One Networks, Mr. Gregg was responsible for Corporate Affairs and Communications at the Greater Toronto Airport Authority. Mr. Gregg submitted his resignation, which was accepted, on February 25, 2014.

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 kilometres of transmission lines and distribution lines used to deliver electricity on Reserves (of which 14 kilometres 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.

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 agreement and section 108 of the Business Corporations Act (Ontario) pertaining to off-shoring of jobs under 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 this declaration.

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 FIT generators, whether directly or indirectly, for costs related to investment and expenditures made, or

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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.

Effective September 30, 2013, the Province made a declaration pursuant to the memorandum of agreement and section 108 of the Business Corporations Act (Ontario) regarding the outsourcing of services (the “Outsourced Services”) covered by the Inergi Agreement. Pursuant to the declaration and the concurrent shareholder resolution, the Province restricted the discretion and powers of our Board to manage or supervise the management of the business and affairs of our company as they pertain to whether or not one or more procurements for the provision

of the Outsourced Services on the expiration of the Inergi Agreement (the “New Procurements”) should include a requirement (the “Ontario Requirement”) that all Outsourced Services be performed by persons who are: (i) employed in Ontario to perform those Outsourced Services, and (ii) physically located in Ontario at the time they perform those Outsourced Services (the “Restricted Powers”). The Province exercised the Restricted Powers such that all New Procurements shall include the Ontario Requirement. The directors and officers of our company are charged with carrying out the intention of this declaration.

Copies of the memorandum of agreement and the shareholder declarations 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

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 Computershare Trust Company, N.A., located in New York, New York.

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MATERIAL CONTRACTS

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

(a) (i)	a third supplemental trust indenture dated as of January 31, 2003 relating to the issuance of Series 4 Notes in the aggregate principal amount of $1,000,000,000, of which $200,000,000 was drawn down on January 31, 2003, $120,000,000 was drawn down on June 25, 2004 and $65,000,000 was drawn down on August 24, 2004, pursuant to the Trust Indenture dated as of June 4, 2001 between Hydro One and Computershare Trust Company of Canada (the “Trust Indenture”);
(ii)	a fourth supplemental trust indenture dated as of April 22, 2003 relating to the issuance of Series 5 Notes in the aggregate principal amount of $1,000,000,000, of which $250,000,000 was drawn down on April 22, 2003 and $65,000,000 was drawn down on August 20, 2004, pursuant to the Trust Indenture;
(iii)	an eighth supplemental indenture dated as of May 19, 2005 relating to the issuance of Series 9 Notes in the aggregate principal amount of $1,000,000,000, of which $350,000,000 was drawn down on May 19, 2005 and $250,000,000 was drawn down on April 24, 2006, pursuant to the Trust Indenture;
(iv)	a ninth supplemental trust indenture dated as of March 3, 2006 relating to the issuance of Series 10 Notes in the aggregate principal amount of $1,000,000,000, of which $300,000,000 was drawn down on March 3, 2006 and $150,000,000 was drawn down on August 22, 2006, pursuant to the Trust Indenture;

(v)	a tenth supplemental trust indenture dated as of October 19, 2006 relating to the issuance of Series 11 Notes in the aggregate principal amount of $1,000,000,000, of which $75,000,000 was drawn down on October 19, 2006, and $250,000,000 was drawn down on September 13, 2010, pursuant to the Trust Indenture;
(vi)	an eleventh supplemental trust indenture dated as of March 13, 2007 relating to the issuance of Series 12 Notes in the aggregate principal amount of $1,000,000,000, of which $400,000,000 was drawn on March 13, 2007, pursuant to the Trust Indenture;
(vii)	a twelfth supplemental trust indenture dated as of October 18, 2007 relating to the issuance of Series 13 Notes in the aggregate principal amount of $1,000,000,000, of which $300,000,000 was drawn down on October 18, 2007 and $300,000,000 was drawn down on March 3, 2008, pursuant to the Trust Indenture;
(viii)	a sixteenth supplemental trust indenture dated as of March 3, 2009 relating to the issuance of Series 17 Notes in the aggregate principal amount of $1,000,000,000, of which $300,000,000 was drawn down on March 3, 2009, pursuant to the Trust Indenture;
(ix)	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

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	was drawn down on July 16, 2009 and $200,000,000 was drawn on March 15, 2010, pursuant to the Trust Indenture;
(x)	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;
(xi)	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;
(xii)	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;
(xiii)	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;
(xiv)	a twenty-second supplemental trust indenture dated as of July 29, 2011 amending the definition of “Canadian GAAP” in the Trust Indenture;
(xv)	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;
(xvi)	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;
(xvii)	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;
(xviii)	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;
(xix)	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 $1,000,000,000, of which $50,000,000 was drawn down on December 3, 2012, pursuant to the Trust Indenture;
(xx)	a twenty-eighth supplemental trust indenture dated as of October 9, 2013 relating to the issuance of Series 28 Notes in the aggregate principal amount of $1,000,000,000, of which $750,000,000

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MATERIAL CONTRACTS

	was drawn down on October 9, 2013, pursuant to the Trust Indenture;
(xxi)	a twenty-ninth supplemental trust indenture dated as of October 9, 2013 relating to the issuance of Series 29 Notes in the aggregate principal amount of $1,000,000,000, of which $435,000,000 was drawn down on October 9, 2013, pursuant to the Trust Indenture;
(xxii)	a thirtieth supplemental trust indenture dated as of January 29, 2014 relating to the issuance of Series 30 Notes in the aggregate principal amount of $1,000,000,000, of which $50,000,000 was drawn down on January 29, 2014, pursuant to the Trust Indenture; and
(xxiii)	a thirty-first supplemental trust indenture dated as of March 21, 2014 relating to the issuance of Series 31 Notes in the aggregate principal amount of $1,000,000,000 of which $125,000,000 was drawn down on March 21, 2014, 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 September 4, 2013 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., 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 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, the United States and, in certain circumstances, other jurisdictions.

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

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INTEREST OF EXPERTS

INTERESTS OF EXPERTS

KPMG LLP

For the year ended December 31, 2013, KPMG LLP provided the following services to our company:

(a) quarterly reviews 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-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

For the year ended December 31, 2013, Mercer Human Resource Consulting LLC provided 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) annual accounting actuarial valuation for supplementary pension plan for purposes of letters of credit (valuation report prepared).

Mercer Human Resource Consulting LLC’s engagement with our company ended on February 24, 2014.

Towers Watson

In December 2013, Towers Watson commenced performing the following services for our company relating to the December 31, 2013 year end:

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

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

Towers Watson will also be providing the tri- annual funding actuarial valuations (next valuation will be performed no later than December 31, 2014).

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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 affordable service to our customers, today and tomorrow, 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 plan, 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 short term incentive pay (the “Incentive Plan”), the variable pay component of the compensation program, is linked to achievement of our corporate scorecard which measures management’s performance in accordance with and against our 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 2013, Hydro One’s compensation practices were applied consistent with the Broader Public Sector Accountability Act, 2010, (the “BPSAA”), as amended by the Strong Action for Ontario Act (Budget Measures) 2012, which imposes compensation restraint measures on the compensation plans of defined designated executives 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 are not covered by the BPSAA. The BPSAA applies to the NEOs of Hydro One.

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The NEOs of Hydro One for 2013 were:

Name	Title
Carmine Marcello	President and Chief Executive Officer
Sandy Struthers	Chief Administration Officer
	and Chief Financial Officer
Peter Gregg	Chief Operating Officer
Michael Winters	Senior Vice President,
	Engineering and Technology
Wayne Smith	Senior Vice President,
	Planning and Operating

Governance

The Human Resources Committee of the Hydro One Board of Directors (the “HRC”) is comprised entirely of independent directors 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 Incentive Plan fund;

— the amount of any Incentive Plan 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 HRC’s decision;

— the amount of any Incentive Plan payouts to be made to the direct reports of the President and Chief Executive Officer, and informs the Board of the HRC’s decision;

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

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

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.

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Composition of the HRC

As at December 31, 2013, 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, 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. Mr. Speers is a member of the Board of Directors of Ceres Global

Ag Corporation and is a member of that Board’s Compensation and Governance Committee.

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 had 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 Vice-Chairman of the Board of Directors of Canadian National Railway Company and was the chair of its Human Resources and Compensation Committee for several years. Further, Mr. Pace is a director of High Liner Foods Incorporated and a member of its Human Resources Committee since 2011. Additionally, Mr. Pace attended an executive

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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, located in Toronto, Ontario, 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, but 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:

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

— compensation is aligned with Hydro One’s strategic objectives - the Board annually sets the multi-year strategic plan for Hydro One in which its strategic objectives are clarified and risks considered. These strategic objectives then form the basis of a corporate scorecard against which corporate performance is measured and incentive compensation is determined. The specific 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;

— annual incentive funding is determined on a collective basis – the HRC assesses the overall annual performance against the measures and targets in the corporate scorecard and determines its recommendation to the Board of Directors of the aggregate amount of the short term incentive payout. Determining aggregate funding in this manner ensures all employees have an incentive to achieve all corporate measures and targets;

— performance against the measures and targets in the corporate scorecard is reviewed and considered by specific Board committees in addition to the HRC during the course of the year;

— Actual performance against the measures and targets in the corporate scorecard is audited by the Senior Vice President, Internal Audit to ensure the targets achieved are accurately represented and the results of such audit are reported to the HRC, prior to the review and assessment by the HRC;

— Hydro One takes a balanced approach to the level of compensation which is “at risk” - only a portion of the total compensation is based on Incentive Plan payments;

— actual payment of Incentive Plan amounts is based on an assessment of individual performance, both on an absolute basis and relative to other individuals. Incentive Plan

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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. This assessment allows for consideration of the individual’s contribution to corporate performance and the application of judgment to exclude the impact of fortuitous or unfortunate circumstances that were largely outside the control of the individual;

— there are maximum limits on incentive pay; for the NEOs, other than the President and Chief Executive Officer, the maximum payout is 60% of base pay and for the President and Chief Executive Officer the maximum payout is 65% 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;

— senior management is not encouraged to take excessive risks to directly increase their compensation;

— the HRC may retain, when it considers advisable, 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 to reach an informed decision including the risk of existing legislated restraint measures on attracting and retaining individuals with the experience and expertise needed to enable Hydro One to manage its business and discharge its mandate properly and its ability to tailor its compensation program to align with the company’s strategies; 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 several HRC meetings in 2013 and provided its independent views to the HRC and in particular its views on matters of compensation. Other than in respect of its compensation-related services described above, Hugessen Consulting Inc. did not provide any other services to Hydro One. The HRC determined in 2013 to terminate its agreement with Hugessen Consulting Inc. effective December 31, 2013. However, in February 2014, the HRC retained Hugessen Consulting Inc. for the limited purpose of providing consulting services to support the creation and approval of Hydro One’s corporate scorecard. 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
2013	$25,917.41	$0
2012	$93,046.62	$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 was entitled 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 Hydro One compensation 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 the President and Chief Executive Officer, the maximum amount payable for the Incentive Plan payment is 65% of his base salary. 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.

In 2013, 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.

The comparator group consists of 30 Canadian-based entities (15 public and 15 private). The selection criteria for the comparator group includes size of the organization and its revenue, engineering and technology positions, unionized workforce, a pay-for-performance culture and the existence of variable pay programs. 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 62.5% 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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ELEMENTS OF COMPENSATION

The list of comparator group companies is as follows:

Public Sector	Private Sector
Atomic Energy of Canada Limited	ArcelorMittal Canada
Business Development Bank of Canada	Barrick Gold Corporation
Canada Mortgage and Housing Corporation	Bombardier Transportation Canada Inc.
Canadian Standards Association/CSA Group	Bruce Power LP
Enersource Hydro Mississauga Inc.	Canadian National Railway Company
Farm Credit Canada	Fortis Inc.
Government of Ontario	FortisBC Energy Inc.
Hydro Ottawa Limited	Goldcorp Inc.
NB Power Holding Corporation	Newfoundland Power Inc.
Ontario Power Authority	Siemens Canada Limited
Ontario Power Generation	SNC-Lavalin Group Inc.
Royal Canadian Mint	Suncor Energy Inc.
SaskEnergy Incorporated	Vale Canada Ltd.
Sask Power	Valero Energy Inc.
Sask Tel	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. The positioning of the NEO within the approved 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. Since 2012, however, base salary increases for designated executives have been subject to compensation restraint measures imposed by the BPSAA. In 2013 the roles, accountabilities and responsibilities of certain of the NEOs were increased due to an

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organizational realignment and adjustments were made to their base salaries to reflect such increased responsibilities. Base salaries were otherwise not increased for any of the NEOs in 2012 or 2013.

(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 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 (in total) and levels of achievement are established by the HRC and are assigned to the corporate performance measures incorporated in his performance contract as well as to his individual 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 the year ended December 31, 2013, the potential award ranges for the NEOs were as follows: between 0% and 65% of base salary for Mr. Marcello, and between 0% and 60% of base salary for each of Mr. Struthers, Mr. Gregg, Mr. Winters and Mr. Smith. The range for Mr. Marcello was set by the HRC and approved by the Board in December 2012. 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 it has 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 for all management employees and 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 2013, the maximum percentage of funds available for allocation for all management employees (including the NEOs) was set at 60% 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.

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Fund Allocation: The fund is allocated among individual executives on the basis of individual performance. It is not an across the board allocation. NEOs are assessed against their performance agreement based on objective and subjective assessments. The HRC conducted and approved the assessments of the President and Chief Executive Officer, Chief Administration Officer and Chief Financial Officer and the Chief Operating Officer. The Chief Operating Officer assessed the Senior Vice President, Engineering and Technology and the Senior Vice President Planning and Operating and those assessments were approved by the President and Chief Executive Officer. No NEO or management employee is allowed to receive above his or her 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.

For 2013, the corporate performance measures were tied to Hydro One’s corporate strategy which was updated in 2013. 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 2013, the HRC determined that Hydro One should focus on six strategic objectives and nine performance measures and targets. The HRC then recommended the measures and targets to the full Board of Directors for approval. These measures and targets were 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 2013, which were aligned to its strategic objectives and the targets for each of those measures. In 2013, 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. 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) %	l	7.8	9.8
	Distribution Unit Costs (Capital and OM&A costs per km of line) $’000/km		10.6	9.8
Reliability	Tx Duration of Customer Unplanned Interruptions on 115/230 kV Network Transmission System per delivery point (minutes/delivery point)		12.9	9.0
	Dx Duration of Customer Interruptions (hours per customer)		6.9	6.7
Satisfying Our Customers	Tx Customer Satisfaction (% satisfied)		81	82
	Dx Customer Satisfaction (% satisfied)	l	87	86
Employee Engagement	Employee Survey (Grand Mean)		3.93	4.06
Shareholder Value	Net Income After Tax+ ($M)	«	803	702
Injury-free Workplace	Medical Attentions † (# of medical attentions per 200,000 hours worked)		2.5	1.9

 Legend    «Better than plan (³5%)    l On Plan       Below Plan

      All multi-circuit supplied delivery points.

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

   †  Subset of WSIB reportable.

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The 2013 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. The scores against these measures and the overall corporate score are not absolute determinants. The Board retains the right to assess the overall result by taking into consideration major accomplishments that may not be reflected in the scorecard and in doing so may exercise its discretion to make adjustments to the score and the determination of the Incentive Plan fund. If, on balance, scorecard performance is met or exceeded, the Incentive Plan 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. In 2013, the Board of Directors considered the corporate scorecard results, as noted above, and the key accomplishments of the Company throughout the year and determined, on balance and in the exercise of its discretion, the funding level should be set at 60% of the maximum short term incentive fund. In accordance with the BPSAA, the funding envelope for the short term incentive for 2013 cannot exceed the amount that was paid in aggregate in the performance pay cycle for 2011. In setting the funding level at 60% for 2013, 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 2013 were: transmission unit cost and distribution unit cost.

For 2013, for transmission unit cost, Hydro One measured the capital expenditures and OM&A costs per dollar of gross in-service assets (expressed as a percentage). For distribution unit cost, Hydro One measured 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 9.8% and Hydro One met this target. The distribution unit cost target was set at $9,800 per kilometre of line. Hydro One did not meet 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 2013, 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 2013 was 9 minutes per delivery point. We did not meet this target.

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For the Hydro One Networks distribution business, the target for 2013 for the duration of customer interruptions was set at 6.7 hours per customer. While we did not meet this target, the Board noted that the impact of storms in January and February of 2013 would require the Company to change work practices and alter resource levels to simply meet the target and that the cost to do so would be prohibitive and not in the best interests of the ratepayer. Considering the storm impacts and the positive results over the balance of the year, the Board, in the exercise of its discretion, determined that this target was met.

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 2013, for transmission customers we targeted a customer satisfaction rate of 82%. The survey is given to three major groups of transmission customers. The Board determined that there was significant improvement in two of the three groups which comprise the survey members and accordingly, in the exercise of its discretion, considered this target met. 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 our corporate values of safety, stewardship, excellence and innovation. The employee engagement survey is 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 2013 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 $702 million net income after tax and we exceeded our target.

6. Safety: Injury Free Workplace

The safety of our employees is paramount. In 2013, 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 2013, Hydro One set a target of no higher than 1.9 attentions per 200,000 hours worked. Hydro One did not meet this target.

Overall Performance for 2013

For 2013, the HRC determined that of the 9 targets, 5 were met or exceeded and 4 were not met. Taking into consideration the key accomplishments of the Company throughout the year, coupled with these results on the targets, the HRC determined that, on balance, the payout funding at 60% of the maximum short term incentive payout would be recommended to the Board. In considering some of the key accomplishments in 2013, the HRC noted that the Company transitioned to its new Customer Information System in May of 2013, customer satisfaction results were improving, the Company responded exceedingly well to numerous storms and power outages throughout the year (in particular the July flash flood and the December

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ice storm both of which affected the Toronto area), the Company made progress in the consolidation of local distribution companies, and the Company successfully completed its SEC registration in the United States and its global bond launch in October. 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 60% of the maximum short term incentive payout.

Accordingly, the funding at 60% 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. As well, the NEOs were to provide leadership in improving customer relationships. 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 his 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 actual 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 managerial accountability, and 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.

Mr. Marcello’s targets were quantitative and qualitative, with overall target weightings attributed to these factors. The quantitative factors (overall total 70%) were: productivity, reliable transmission and distribution, satisfying our customers,, employee engagement, shareholder value and safety. These quantitative targets were

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the same as and tied to achieving the Corporate Performance Measures and targets described above. The qualitative factors (overall total 30%) focused on strategies and plans to increase shareholder value, drive a culture of safety and performance, improve service to Hydro One customers and improve corporate reputation. The key elements and summaries of the specific objectives of these factors were: strategy (to develop and implement a corporate strategy), risk (to ensure the Board is aware of known and emerging risks in order to apply appropriate mitigation), corporate reputation (to advance to Company’s objectives and maintain effective and strategic relationships in the electricity sector and the broader public sector), succession planning (to develop succession plans for all executive positions), cultural transformation (to lead a cultural transformation that entrenches measurement, accountability and performance), customer (to improve customer relationships), and major projects (to implement the Customer Information System).

Mr. Struthers, as Chief Administration Officer and Chief Financial Officer accountable for Business Planning and Support, Corporate Finance, Facilities and Real Estate, Outsourcing Services, Pension Fund, Regulatory Affairs, Supply Chain Services, Taxation, Transport and Work Equipment and Treasury and Risk, had targets comprised of quantitative and qualitative factors. The quantitative factors (overall total 70%) were as follows: productivity, reliable transmission and distribution, satisfying our customers, employee engagement, shareholder value and safety. The qualitative factors (overall total 30%) were comprised of two key responsibilities: (i) strategic planning and key priorities and (ii) service function objectives, each having specific strategic and individual objectives. With respect to strategic planning and key priorities, Mr. Struthers’

specific strategic and individual objectives were: increase shareholder value; drive a culture of safety and performance; improve service to internal customers, including supporting the delivery of the Customer Information System; and improve corporate reputation. Regarding the service function objectives, Mr. Struthers’ specific strategic and individual objectives related to the following key business functions or areas of oversight: treasury and risk (complete the renewed debt financing program and global bond issuance); financial reporting (complete the SEC filing and US GAAP reporting requirements); pension (provide oversight on the plan’s performance); regulatory (develop and implement the multi-year rate filings); business plan (manage and introduce the multi-year business plan); outsourcing (oversee the outsourcing process); fleet (develop a strategy to manage fleet costs and better use of resources); and real estate (oversee the process to obtain external providers for our facilities management).

Mr. Gregg, as Chief Operating Officer accountable for Operations and Maintenance, Health and Safety, Planning and Operating, Remote Communities and Technology, Engineering and Construction and for part of the year Labour Relations matters in which he oversaw the successful negotiation of PWU and Society collective agreements, had targets which focused on health and safety, customers, management practices and specific matters related to the cost effective delivery of the work program, productivity improvements and ensuring succession plans are in place for key management roles. Mr. Gregg’s goals included providing visible leadership in health and safety with a focus on the successful implementation of the OHSAS 18001 certification and continued implementation of the Journey to Zero initiative, all with a view to continued safety performance. Additionally, with

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respect to the customer focus area he provided operations support on the Customer Information System project to ensure it was delivered on time and on budget. As well, Mr. Gregg set goals to reinforce the Craft of Management principles throughout the field level organization and in particular at the supervisory level. Regarding the work program, his objective was to deliver the work program cost effectively to maintain the electricity network and deliver service to our customers coupled with productivity initiatives to address cost savings.

Mr. Winters, is the Senior Vice President, Engineering and Technology. He is accountable for Detailed Engineering, Project Management, Construction, the Chief Information Officer Organization and Hydro One Telecom Inc. His targets focused on health and safety, customer, management practices and matters related to his specific work programs. Mr. Winters’ goals include providing visible leadership to improve overall safety performance and maintain a safe and healthy workplace. Regarding the customer focus area, his target included the delivery of a new Customer Information System and associated processes on time and on budget. With respect to management practices and effectiveness, Mr. Winters targeted aligning Technology, Engineering and Construction on corporate goals and priorities through improved employee engagement, management capability and integration across all project stakeholders. In his focus area on work programs, Mr. Winters target was to cost effectively deliver the programs and projects necessary to maintain and enhance the core service Hydro One provides to its customers across the province. His mandate also included designing and constructing using standard and repeatable methods that lead to safe, reliable and cost effective operations of power system assets, improving the overall governance of telecom

assets and capabilities, delivering productivity and cost savings and delivering engineering design technology improvements to standardize designs and facilitate commissioning of projects.

Mr. Smith, is the Senior Vice President of Planning and Operating. He is accountable for all work planning activities including asset management, operations planning and control, conceptual design, and for network operating and network development. His targets focused on health and safety, customer, management practices and matters related to setting Hydro One Network’s work programs and operating the provincial grid. Regarding health and safety, his goal focussed on our Safety by Design initiative which relates to the design of goods or equipment or assets to ensure that they meet or exceed applicable safety standards and requirements. As well, he focussed on administering the Work Protection Code in a safe manner to reduce the number of Work Protection Code incidents. With respect to customers, he addressed the effective coordination of outages to reflect the needs of our customers and Hydro One. As well, his focus included reflecting the needs of our customer commitments in our work program. On the management practices goal, his initiatives included improving the efficiency and consistency of risk related to investment decisions, consolidate reporting and performance management, discontinue low value work, collate information on lessons learned from equipment failures to facilitate making better decisions and ensure robust succession plans are in place for management in his areas of accountability. The goals for Mr. Smith in his work program were to develop a process and resource it for regional planning as directed by the OEB, provide assistance with the transmission and distribution rate filings, and develop and implement a two year transformation of planning for Hydro One.

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In 2013, the HRC and the Board assessed the respective performances of Mr. Marcello, Mr. Struthers and Mr. Gregg. In making their assessments, the HRC and the Board paid particular attention to the corporate scorecard results and their assessments of these results, the personal performance and contributions of each these three NEOs to Hydro One throughout the year and certain negative prolonged billing and related service issues concerning the Customer Information System. With respect to Mr. Marcello, the HRC and the Board considered the results of the scorecard targets but gave significant weight to his strong personal performance and leadership overall in the year and factored that in to its assessment in making its award. However, the Board also gave significant weight to his overall responsibility for such negative issues related to the Customer Information System. In its assessment of Mr. Struthers, the HRC and Board noted: net income significantly exceeded the target; the SEC filing was accomplished; the impressive debt issuance and listing on the New York Stock Exchange; the strong pension plan performance; the favourable real estate tax ruling and its financial benefit; and his use of Hydro One management practices and principles to support the Hydro One cultural transformation. Regarding Mr. Gregg, the HRC and Board noted in its assessment of his performance the generally strong operational results, the exceptional storm response in respect of the Toronto flash flood and December ice storm, his focus on promoting the Hydro One management practices and principles to his organization to foster the cultural transformation, all tempered by the safety results and not achieving in-service capital.

Mr. Winters was assessed by Mr. Gregg as Mr. Winters reports to him directly. In his assessment, Mr. Gregg noted Mr. Winters’ leadership in his new position, the performance improvement in work completed in 2013, the completion of a Hydro One Telecom Inc. service delivery initiative and streamlined work processes, his oversight of the successful

completion of the Asset Analytics, Asset Investment Planning and Business Planning Consolidation Projects to ensure consistent quality data and more efficient processes, and the enhanced ability to award external Engineering, Procurement and Construct to ensure cost-effective completion of projects.

Mr. Gregg also completed the assessment of Mr. Smith, another direct report, and in his assessment noted Mr. Smith took on a new role combining existing functions and groups into the Planning and Operating Division where he revamped established work processes making them more efficient and effective. As well, Mr. Smith delivered the annual Investment Plan, 5 months earlier than previously delivered to align the plan with the 5-year business plan regulatory submissions. Mr. Gregg also noted Mr. Smith’s coordination of the operational response to the flooding of two critical Toronto area transformer stations in July which ensured safe and efficient restoration of power to parts of Toronto following record rainfall. Mr. Smith continued to achieve high customer satisfaction rating through advanced planning and communication of planned transmission outages for large customers.

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

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and health care benefits. Hydro One provides to each executive and management employee certain core benefits, which include basic life insurance, accident 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, take additional vacation days (up to a cap), and/or contribute to a health care account. Unallocated credits are paid out at year end, subject to withholding tax, to the employee.

Benefits provided to NEOs, other than Mr. Gregg and Mr. Winters, are the same as those provided to all other management employees whose start date is pre-2004 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 and Mr. Winters, are identical to those of all other executive and management staff in our company whose start date is pre-2004, and are calculated in a similar manner identical to all employees in our company. See “Pension Plan Benefits” below.

Mr. Gregg’s and Mr. Winters’ benefits and pension benefits differ from those of the other NEOs as Mr. Gregg and Mr. Winters became employees of Hydro One after January 1, 2004 and their 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 Vice- President, People and Culture, working with the Hay Group Limited, is responsible for providing recommendations regarding compensation 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 2013, in addition to the above recommendations, the HRC and the Board of Directors considered the requirements of the BPSAA in determining the base salary and Incentive Plan payments for all the NEOs for 2013.

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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 2013, 2012 and 2011.

Name and Principal Position	Year		Salary  ($)		Non-equity incentive plan compensation ($)			Pension Value 7 ($)		All Other Compensation  ($)	Total Compensation ($)
					Annual incentive plans1		Long-term  incentive plans
C. Marcello2 President & CEO		2013		$525,000		$170,625	$0		$2,889,000	$0	$3,584,625
		2012		$300,000		$156,000	$0		($13,000)	$0	$443,000
		2011		$300,000		$177,000	$0		($9,000)	$0	$468,000
S. Struthers2 Chief Administration Officer and CFO3		2013		$375,000		$135,000	$0		$324,000	$0	$834,000
		2012		$325,000		$169,000	$0		$38,000	$0	$532,000
		2011		$325,000		$177,000	$0		$36,000	$0	$538,000
Peter Gregg4 Chief Operating Officer		2013		$395,000		$142,200	$0		$420,000	$0	$957,200
		2012		$295,000		$153,400	$0		$38,000	$0	$486,400
		2011		$295,000		$177,000	$0		$34,000	$0	$506,000
Mike Winters5 Senior Vice President Technology, Engineering and Construction		2013		$280,000		$135,000	$0		$85,000	$0	$500,000
		2012		$270,000		$140,000	$0		$38,000	$0	$448,000
		2011		$270,000		$110,000	$0		$81,000	$0	$461,000
Wayne Smith6 Senior Vice President of Planning and Operating		2013		$274,050		$125,000	$0		($6,000)	$0	$393,050
		2012		$274,050		$150,000	$0		$16,000	$0	$440,050
		2011		$274,050		$152,000	$0		$7,000	$0	$433,050

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  Effective January 1, 2013, Mr. Marcello was appointed the President and Chief Executive Officer of Hydro One. 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 increased commensurate with his new position and its increased responsibilities.

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³  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 increased commensurate with the position and increased responsibilities, effective January 1, 2013.

⁴  Effective January 1, 2013, Mr. Gregg was appointed Chief Operating Officer as a result of an organizational realignment. With added responsibilities in this new position, including the accountability for our Remote Communities subsidiary as its President and Chief Executive Officer, Mr. Gregg’s compensation increased commensurate with his new position and increased responsibilities. On February 25, 2014, Mr. Gregg submitted his resignation from Hydro One, which has been accepted, and provided three months’ notice of the termination of his employment. Mr. Gregg is taking on the position of President and Chief Executive Officer of Enersource Corporation.

⁵  Effective January 1, 2013, as part of the organizational realignment to better deliver on key priorities of the Company, Mr. Winters as appointed in 2013 as Senior Vice President, Engineering and Technology. As a result of this realignment and added responsibilities, Mr. Winters’ compensation increased commensurate with his new position and increased responsibilities.

⁶  Effective January 1, 2013, Mr. Smith, as part of the organizational realignment became the Senior Vice President, Planning and Operation.

⁷  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. The pension plan provides a benefit, in respect of all years of service, which is based on each plan member’s highest average earnings at the time of his or her termination or retirement. The increase in Mr. Marcello’s pension obligation in 2013 includes a one-time increase to reflect the additional value of his future pension resulting from his increased compensation upon promotion to President and Chief Executive Officer.

None of Mr. Marcello, Mr. Struthers, Mr. Gregg, Mr. Winters and Mr. Smith are entitled to other benefits or perquisites in the aggregate amount that exceeds $50,000 or 10% of his annual salary.

Mr. Marcello did 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

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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: Mr. Marcello – 35 years; Mr. Struthers – 24 years; Mr. Gregg – 28 years; Mr. Winters – 30 years; Mr. Smith – 35 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 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 $151,000 in 2013. 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

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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, 2013;

— Estimated annual lifetime benefit payable for service up to December 31, 2013 and up to the normal retirement age of 65; and

— A reconciliation of the present value of the defined benefit obligation from December 31, 2012 to December 31, 2013. 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.

Name	Number of years credited service at year end (#)		Annual benefits payable ($)				Opening present value of defined benefit obligation1 ($)		Compensatory change ($)				Non- compensatory change4 ($)		Closing present value of defined benefit obligation5 ($)
			At year end		At age 65				Service Cost2		Other3
C. Marcello		26.1 yrs		$231,000		$309,900		$3,728,000		$237,000		$2,652,000		($62,000)	$6,555,000
S. Struthers		13.9 yrs		$115,200		$198,600		$1,751,000		$133,000		$191,000		$31,000	$2,106,000
P. Gregg		9.5 yrs		$72,100		$213,200		$997,000		$134,000		$286,000		($35,000)	$1,382,000
M. Winters		7.7 yrs		$43,800		$172,200		$723,000		$91,000		($6,000)		($24,000)	$784,000
W. Smith		33.2 yrs		$217,200		$229,200		$4,326,000		$107,000		($113,000)		($92,000)	$4,228,000

¹  The opening 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.

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.

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⁵  The closing present value of the defined benefit obligation is the value of the projected pension earned for service to December 31, 2013. The values have been determined using the same actuarial assumptions used for determining the pension plan obligations at December 31, 2013 as disclosed in the notes to the 2013 consolidated financial statements, based on the actual earnings for 2013 and adjusted to reflect expected increases in pensionable earnings.

Notes:

— All members are currently vested in their pension entitlements earned to December 31, 2013.

— 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. Marcello, Mr. Struthers, 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. Marcello, Mr. Struthers, and Mr. Gregg, if their employment is terminated by Hydro One without cause, each of Mr. Marcello, Mr. Struthers, 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 and to receive benefits over the same period (including Incentive Plan payments equal to the average of the three previous Incentive Plan payments, payable in monthly instalments). Each of Mr. Marcello, Mr. Struthers, and Mr. Gregg would continue to earn credited service under the Hydro One Pension Plan during such 24-month period. Continuation of benefits will also continue until expiry of the severance period, except for disability insurance and accrual of vacation. The amount of salary and incentive plan benefits expected to be paid if Mr. Marcello, Mr. Struthers, and Mr. Gregg were terminated on December 31, 2013 is summarized in the following table.

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SUMMARY COMPENSATION TABLE

Name	Base Salary		3 year average   Incentive Payment	Total Payment
C. Marcello		$1,050,000	$332,000	$1,382,000
S. Struthers		$750,000	$349,834	$1,099,834
P. Gregg		$790,000	$328,434	$1,118.434

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

Mr. Marcello’s annual pension accrued at December 31, 2013 would be expected to increase by $100,600

Mr. Struthers’s annual pension accrued at December 31, 2013 would be expected to increase by $24,600

Mr. Gregg’s annual pension accrued at December 31, 2013 would be expected to increase by $24,700

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. Marcello, Mr. Struthers, 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.

For the NEOs, there are no significant conditions or obligations that apply to receiving any of these 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

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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 2013 by the directors of Hydro One.

Director Compensation Table

Name	Fees Earned		All other compensation1		Total
James Arnett		$150,000.00		$0		$150,000.00
Kathryn Bouey		$57,700.00		$0		$57,700.00
George Cooke		$51,100.00		$0		$51,100.00
Janet Holder		$30,642.47		$3,600.00		$34,242.47
Catherine Karakatsanis		$3,297.26		$0		$3,297.26
Don MacKinnon		$41,500.00		$0		$41,500.00
Michael Mueller		$68,500.00		$7,200.00		$75,700.00
Walter Murray		$65,800.00		$9,000.00		$74,800.00
Robert Pace		$60,400.00		$5,400.00		$65,800.00
Yezdi Pavri		$55,600.00		$0		$55,600.00
Sandra Pupatello		$5,576.71		$0		$5,576.71
Gale Rubenstein		$57,700.00		$0		$57,700.00
Douglas Speers		$73,000.00		$10,800.00		$83,800.00
TOTAL		$720,816.44		$36,000.00		$756,816.44

(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

The auditor of our company is KPMG LLP.

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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 August 9, 2013.

Composition of the Audit and Finance Committee

As at December 31, 2013, the members of our Audit and Finance Committee were Michael Mueller (Chair), George Cooke, Walter Murray, Yezdi Pavri and Sandra Pupatello. Ms. Pupatello was appointed as a member of the Audit and Finance Committee on December 12, 2013 in place of Ms. Kathryn Bouey, who served on the Committee from August 12, 2010 until December 12, 2013. All members are independent, and all members are financially literate as such terms are defined under applicable Canadian securities legislation. In respect of the current members of the Audit and Finance Committee, the board determined that at least one of the members, being the current Chair of the Audit and Finance Committee, Mr. Mike Mueller, is qualified as an “audit committee financial expert”, and that all members of the Audit and Finance Committee are independent under the Exchange Act and the listing standards of the NYSE.

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, 2013 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.

Mr. Cooke is President, Martello Associates Consulting, a business strategy consulting firm, and on October 1, 2013 he was appointed as the Chair of the Board of Directors of OMERS Administration Corporation. OMERS is one of Canada’s largest pension funds and the OMERS Administration Corporation is responsible for pension services and administration, investments, and plan valuation. 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 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

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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. Mr. Cooke was a member of the Board of Directors of The Dominion of Canada General Insurance Company and the Insurance Bureau of Canada and was also an Executive Vice President with E-L Financial Corporation Limited.

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.

Ms. Pupatello is the Director of Business Development and Global Markets at PricewaterhouseCoopers Canada, a position she has held since 2012. PwC provides audit and assurance, consulting, deals and tax services for public, private and government clients. In May 2013, she was appointed as the Chief Executive Officer of the WindsorEssex Economic Development Corporation. Ms. Pupatello was first elected into the Ontario legislature in 1995 and appointed to Cabinet in 2003. Between 2003 and 2011, she held several portfolios, including Minister of Community and Social Services, Minister of Education, Minister of Economic Development and Trade and Minister of International Trade and Development. She holds a Bachelor of Arts and honourary Doctor of Law degree from the University of Windsor.

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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.

External Auditor Service Fees

	Fiscal 2013				Fiscal 2012
Type of Fees	Fees		% of Total		Fees		% of Total
Audit Fees		$807,176		77.2%		$806,146		81.7%
Audit-Related Fees		204,083(1)		20.6%		180,235(2)		18.3%
Tax Fees		—		—  %		—		—  %
All Other Fees(3)		21,714		2.2		—		—  %
Total		$1,032,973		100%		$986,381		100%

(1) The nature of services rendered were: audit of the Hydro One Pension Plan, audit of the Hydro One Employees’ and Pensioners’ Charity Trust, audit of the Apprenticeship Enhancement Fund Audit, French translations, incremental procedures performed over implementation of the Customer Information System, and executive expense reviews.

(2) The nature of services rendered were: audit of the Hydro One Pension Plan, audit of the Hydro One Employees’ and Pensioners’ Charity Trust, audit of the Apprenticeship Enhancement Fund Audit, French translations, procedures performed related to U.S. GAAP, and executive expense reviews.

(3) These fees were related to a review of the sufficiency of Hydro One’s documentation of the controls and procedures identified as addressing certain additional laws and regulations as a result of becoming an SEC registrant.

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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”). Mr. Carmine Marcello, who is the President and Chief Executive Officer of our company and a member of the Board, is 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 2013, seven 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 among 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 held during the 12-month period ending December 31, 2013.

Director	Board Meetings Attended
James Arnett	14 of 14
Kathryn Bouey	13 of 14
George Cooke1	11 of 13
Janet Holder2	7 of 9
Catherine Karakatsanis3	1 of 2
Don MacKinnon4	7 of 10
Carmine Marcello	14 of 14
Michael Mueller	14 of 14
Walter Murray	14 of 14
Robert Pace	13 of 14
Yezdi Pavri	14 of 14
Sandra Pupatello5	2 of 2
Gale Rubenstein	13 of 14
Douglas Speers	13 of 14

(1) Mr. Cooke was not in attendance for one Board meeting due to a conflict of interest.

(2) Ms. Holder resigned from the Board on August 12, 2013, and nine meetings of the Board were held prior to that time.

(3) Ms. Karakatsanis was elected to the Board on November 27, 2013 and only two meetings of the Board were held since her election to the Board.

(4) Mr. MacKinnon was not in attendance for four meetings of the Board because these meetings solely addressed labour relations matters and, as President of the PWU, there was a conflict of interest.

(5) Ms. Pupatello was elected to the Board on November 20, 2013 and only two meetings of the Board were held since her 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.
Douglas Speers	Ceres Global Ag Corporation

Board Mandate

The Board is responsible for the stewardship of our company and the supervision of the 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 and U.S. 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

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accounting policies and financial reporting, internal controls, internal audit, financial risk exposures, financial compliance and ethics policies. Concurrent with our company’s SEC registration in 2013, the mandate of the Audit and Finance Committee was updated to ensure compliance with U.S. securities legislation.

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 HR 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 HR Committee and the Board on the competitiveness and effectiveness of the company’s compensation programs. The HR Committee determined in 2013 to terminate its agreement with Hugessen Consulting Inc. effective December 31, 2013. However, in February 2014, the HR Committee retained Hugessen Consulting Inc. for the limited purpose of providing consulting services to support the creation and approval of Hydro One’s corporate scorecard. For additional information relating to the compensation of our company’s senior executives, see “Statement of Executive Compensation”.

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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 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 provides 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 and Committee meetings, information briefings, presentations and updates from senior management and external speakers 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.

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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.

Concurrent with our company’s SEC registration in 2013, the Code was updated to ensure compliance with U.S. securities legislation, to reflect changes in Hydro One’s organizational structure, and to represent advancements in current best corporate governance and ethics practices. The revised Code reflects current best governance and ethics practices, including the availability of a third-party hotline for the anonymous reporting of suspected violations of the Code including any accounting, internal accounting controls or auditing matters. The document can be found at: http://www.hydroone.com/Careers/

Documents/Code_of_Business_

Conduct.pdf

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 Canadian securities laws, U.S. federal securities laws and the rules of any stock exchange on which the Corporation’s securities are listed, 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, stock exchanges or any governmental or regulatory body exercising authority over the Corporation, as in effect from time to time. Without limiting the generality of the foregoing, 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.

— Audit Committee Financial Expert.

At least one member of the Committee shall be an “audit committee financial expert” within the meaning of applicable U.S. federal securities laws.

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

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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.

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 National 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

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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 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 or other document required to be filed pursuant to applicable securities laws (including any annual report on Form 40-F or Form 20-F filed pursuant to applicable United States securities laws) all information about the Committee as required to be described in such documents pursuant to applicable securities laws; 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, registration statements 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 document (including any annual report on Form 40-F or Form 20-F filed pursuant to applicable United States securities laws) required to be filed pursuant to applicable securities laws;

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(v)   any prospectus, registration statement, 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 prospectus supplement or pricing supplement and “registration statement” includes any preliminary prospectus, prospectus or amendments thereto forming a part thereof, but excludes any prospectus supplement or pricing supplement forming a part thereof;

(vi)  the annual financing plans and objectives of the Corporation including, foreign currency risk and interest rate risk strategies; and

(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 or registration statement 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 accordance with the requirements of applicable securities laws. 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 applicable securities laws or the auditor independence requirements of any securities regulatory authority. The Committee may also delegate to one or more of its members the authority to

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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;

(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 therewith, 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

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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.

(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. The Committee shall have authority to engage independent counsel and other advisers, as it determines necessary to carry out its duties, and to compensate such persons. 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 TSC.

— 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 TSC 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 of the system.

— Information Disclosure – We are required to maintain records, provide the OEB with

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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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Mailing Address

Hydro One Inc.

483 Bay Street

8th Floor, South Tower

Toronto, Ontario

M5G 2P5