40-F

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 40-F

¨ REGISTRATION STATEMENT PURSUANT TO SECTION 12 OF THE SECURITIES EXCHANGE ACT OF 1934

OR

x ANNUAL REPORT PURSUANT TO SECTION 13(a) OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2014 Commission File Number 001-36115

Hydro One Inc.

(Exact name of Registrant as specified in its charter)

Ontario, Canada	4911	Not Applicable
(Province or other jurisdiction of incorporation or organization)	(Primary Standard Industrial Classification Code Number)	(I.R.S. Employer Identification Number)

483 Bay Street

South Tower, 8th Floor

Toronto Ontario M5G 2P5

Canada

(416) 345-6301

(Address and telephone number of Registrant’s principal executive offices)

CT Corporation System

111 Eighth Avenue, 13^th Floor, New York, NY 10011

(212) 894-8700

(Name, address, (including zip code) and telephone number (including area code)

of agent for service in the United States)

Securities registered or to be registered pursuant to Section 12(b) of the Act:

2.78% Medium-Term Notes due 2018

4.59% Medium-Term Notes due 2043

Title of Class: Medium Term Notes

Name of Exchange where Securities are listed: New York Stock Exchange, Inc.

Securities registered or to be registered pursuant to Section 12(g) of the Act: Not applicable

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act:

Not applicable

Information filed with this Form:

x  Annual Information Form x  Audited annual financial statements

Number of outstanding shares of each of the issuer’s classes of

capital or common stock as of December 31, 2014:

100,000 Common Shares outstanding

12,920,000 Series A Preferred Shares

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

x  Yes ¨  No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the Registrant was required to submit and post such files).

x  Yes ¨  No

CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

The United States Securities and Exchange Commission (the “Commission”) defines “disclosure controls and procedures” as controls and other procedures of an issuer that are designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the U.S. Securities Exchange Act of 1934, as amended (the “Exchange Act”) is recorded, processed, summarized and reported, within the time periods specified in the Commission’s rules and forms.

After evaluation of the effectiveness of the Registrant’s disclosure controls and procedures as of the end of the fiscal year covered by this report, the Registrant’s Chief Executive Officer and its Chief Financial Officer have concluded that the Registrant’s disclosure controls and procedures were effective as of end of the fiscal year covered by this report.

Management’s annual report on internal control over financial reporting and attestation report of the registered public accounting firm.

The Company’s management is responsible for establishing and maintaining internal control over financial reporting. The Company’s management assessed the effectiveness of the Company’s internal control over financial reporting as at December 31, 2014. The Company’s management used the Internal Control – Integrated Framework (2013) as issued by the Committee of Sponsoring Organizations (COSO) of the Treadway Commission to evaluate the effectiveness of the Company’s internal control over financial reporting. Based on management’s assessment, the Company’s internal control over financial reporting is effective as at December 31, 2014.

This annual report does not include an attestation report of the Registrant’s registered public accounting firm regarding internal control over financial reporting.

Changes in Internal Control Over Financial Reporting

During the year ended December 31, 2014, there was no change in the Registrant’s internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, the Registrant’s internal control over financial reporting.

IDENTIFICATION OF THE AUDIT COMMITTEE

The disclosure provided under “Audit, Finance and Pension Investment Committee Information-Composition of the Audit, Finance and Pension Investment Committee” on page 123 of Exhibit 99.1, the Registrant’s Annual Information Form (the “AIF”), is incorporated by reference herein. The Registrant has a separately-designated standing audit committee established in accordance with Section 3(a)(58)(A) of the Exchange Act.

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AUDIT COMMITTEE FINANCIAL EXPERT

The disclosure provided under “Audit, Finance and Pension Investment Committee Information-Composition of the Audit and Finance Committee” on page 123 of Exhibit 99.1, the AIF, is incorporated by reference herein. The SEC has indicated that the designation or identification of an audit committee financial expert does not deem an “expert” for any purpose, impose any duties, obligations or liability on such expert that are greater than those imposed on members of the audit committee and board of directors who do not carry this designation or identification, or affect the duties, obligations or liability of any other member of the audit committee or board of directors.

AUDIT COMMITTEE PRE-APPROVAL POLICIES AND PROCEDURES

The disclosure provided under “Audit, Finance and Pension Investment Committee Information-Pre-Approval Policies and Procedures” on page 126 of Exhibit 99.1, the AIF, is incorporated by reference herein. During the fiscal year ended December 31, 2014, the waiver of pre-approval provisions set forth in the applicable rules of the SEC were not utilized for any services related to Audit-Related Fees, Tax Fees or All Other Fees and the Audit Committee did not approve any such fees subject to the waiver of pre-approval provisions.

PRINCIPAL ACCOUNTANT FEES AND SERVICES

The disclosure provided under the heading “Audit, Finance and Pension Investment Committee Information-External Auditor Service Fees” on page 126 of Exhibit 99.1, the AIF, is incorporated by reference herein.

CODE OF ETHICS

The disclosure provided under the heading “Corporate Governance Disclosure-Ethical Business Conduct” on page 131 of Exhibit 99.1, the AIF, is incorporated by reference herein. The Code of Business Conduct (the “Code”) applies to all directors, officers and employees of the Registrant, including the Chief Executive Officer and Chief Financial Officer. A copy of the Code has been posted on the Registrant’s website at http://www.hydroone.com/InvestorRelations and has also been furnished to the Commission as Exhibit 99.1 to Form 6-K dated November 13, 2013.

OFF BALANCE SHEET ARRANGEMENTS

The disclosure provided under the heading “Off Balance Sheet Arrangements” on page 34 of Exhibit 99.3, the Registrant’s Management’s Discussion and Analysis (the “MD&A”), is incorporated by reference herein.

TABULAR DISCLOSURE OF CONTRACTUAL OBLIGATIONS

The tabular disclosure provided under the heading “Summary of Contractual Obligations and Other Commercial Commitments” on page 34 of Exhibit 99.3, the MD&A, is incorporated by reference herein.

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INTERACTIVE DATA FILE

Concurrent with this filing, the Registrant has submitted to the Commission and posted on its corporate website an Interactive Data File.

MINE SAFETY DISCLOSURE

Not applicable.

UNDERTAKING AND CONSENT TO SERVICE OF PROCESS

Undertaking

Registrant undertakes to make available, in person or by telephone, representatives to respond to inquiries made by the Commission staff, and to furnish promptly, when requested to do so by the Commission staff, information relating to the securities in relation to which the obligation to file an annual report on Form 40-F arises.

Consent to Service of Process

The Registrant has previously filed a Form F-X in connection with the class of securities in relation to which the obligation to file this report arises.

Any change to the name or address of the agent for service of process of the Registrant shall be communicated promptly to the Commission by an amendment to the Form F-X referencing the file number of the relevant registration statement.

3

SIGNATURES

Pursuant to the requirements of the Exchange Act, the Registrant certifies that it meets all of the requirements for filing on Form 40-F and has duly caused this annual report to be signed on its behalf by the undersigned, thereto duly authorized.

DATED this 27^th day of February, 2015.

HYDRO ONE INC.
By:	/s/ Carmine Marcello
	Name:	Carmine Marcello
	Title:	President and Chief Executive Officer

4

EXHIBIT INDEX

Exhibit Number	Description
99.1	2014 Annual Information Form dated February 27, 2015 for the fiscal year ended December 31, 2014.
99.2	Consolidated Financial Statements as at December 31, 2014 and December 31, 2013 and for the years then ended, and the accompanying auditors’ report.
99.3	Management’s Discussion and Analysis for the fiscal year ended December 31, 2014.
99.4	Consent of KPMG LLP.
99.5	Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the U.S. Securities Exchange Act of 1934, as amended.
99.6	Certification of Chief Financial Officer (Acting) pursuant to Rule 13a-14(a) or 15d-14(a) of the U.S. Securities Exchange Act of 1934, as amended.
99.7	Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.8	Certification of Chief Financial Officer (Acting) pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101	Interactive Data File.

EX-99.1

Exhibit 99.1

ANNUAL INFORMATION FORM
For the Year Ended December 31, 2014
February 27, 2015
hydro One

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	OEB
19	OPA and IESO
20	2013 Long-Term Energy Plan
20	Recent Industry Activity
20	Premier’s Advisory Council on Government Assets
21	Customer Service Initiatives
21	Distribution Sector Consolidation
23	Regulated Price Plan Structure
23	TOU Pricing Structure
25	Procurement of New Generation
25	Recent Developments at Hydro One
25	Sustainable Electricity Company Designation
27	OVERVIEW OF HYDRO ONE
29	DESCRIPTION OF THE BUSINESS
29	Our Business Segments
29	Our Transmission Business
29	Overview
30	Transmission Planning
30	Transmission Assets
30	Transmission Stations
31	Transmission Lines
31	Network Operations
32	Telecommunications Facilities
32	Transmission Capital Expenditure Plans
33	Major Transmission Capital Development Projects
35	Transmission Projects at the Local Load Connection Level
36	Transmission Sustainment

2014 ANNUAL INFORMATION FORM     i

TABLE OF CONTENTS

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

ii    HYDRO ONE INC.

TABLE OF CONTENTS

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

2014 ANNUAL INFORMATION FORM    iii

TABLE OF CONTENTS

76	DIRECTORS AND OFFICERS
76	Directors
76	Name and Municipality of Residence
83	Information Regarding Certain Directors
84	Executive Officers
84	Name and Municipality of Residence
84	Indebtedness of Directors and Executive Officers
85	INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS
85	Relationships with the Province and Other Parties
85	Overview
85	Transfer Orders
86	Indemnities
87	Payments in Lieu of Corporate Taxes
87	Memorandum of Agreement
89	TRUSTEES AND REGISTRARS
90	MATERIAL CONTRACTS
93	INTERESTS OF EXPERTS
94	ADDITIONAL INFORMATION
95	STATEMENT OF EXECUTIVE COMPENSATION
95	Compensation Discussion and Analysis
95	Overview
97	Governance
97	Composition of the CGHRC
97	Committee Members Relevant and Direct Experience
99	Compensation Policies and Practices Aligned to Risk Management
100	Independent Consultant for the CGHRC
101	ELEMENTS OF COMPENSATION
102	Base Salary
103	Performance-Based Compensation
103	Fund Determination
104	Fund Allocation
104	Corporate Performance Measures and Targets
106	Injury-Free Workplace
106	Satisfying our Customers
107	Continuous Improvement and Cost Effectiveness
108	Maintaining a Commercial Culture
109	Overall Performance for 2014
109	Individual Performance

iv    HYDRO ONE INC.

TABLE OF CONTENTS

112	Benefits
113	Role of NEOs in Determining Executive Compensation
114	SUMMARY COMPENSATION TABLE
116	Pension Plan Benefits
116	Defined Benefit Pension Plan
119	Termination and Change of Control Benefits
120	Director Compensation
121	Director Compensation Table
122	APPOINTMENT OF AUDITOR
123	AUDIT, FINANCE AND PENSION INVESTMENT COMMITTEE INFORMATION
123	The Audit, Finance and Pension Investment Committee’s Charter
123	Composition of the Audit, Finance and Pension Investment Committee
123	Relevant Education and Experience
126	Audit, Finance and Pension Investment Committee Oversight
126	Pre-Approval Policies and Procedures
126	External Auditor Service Fees
127	CORPORATE GOVERNANCE DISCLOSURE
127	Board of Directors
128	Summary of Attendance of Directors
129	Directors’ Board Memberships in Other Reporting Issuers
129	Board Mandate
129	Position Descriptions
129	Committees of the Board (as at December 31, 2014)
129	Audit, Finance and Pension Investment Committee
130	Business Transformation Committee
130	Corporate Governance and Human Resources Committee
130	Health, Safety and Environment Committee
131	Regulatory and Public Policy Committee
131	Strategy Committee
131	Orientation and Continuing Education
131	Ethical Business Conduct
132	Board, Committee and Director Assessments
133	Board and Executive Composition
134	APPENDIX “A” AUDIT, FINANCE AND PENSION INVESTMENT COMMITTEE MANDATE
147	APPENDIX “B” HYDRO ONE INC. BOARD OF DIRECTORS MANDATE
150	APPENDIX “C” HYDRO ONE TRANSMISSION AND DISTRIBUTION LICENCES

2014 ANNUAL INFORMATION FORM    v

EXCEPT WHERE OTHERWISE INDICATED,
ALL INFORMATION PRESENTED HEREIN IS AS AT DECEMBER 31, 2014
2014 ANNUAL INFORMATION FORM 1

DEFINITIONS
DEFINITIONS
2 HYDRO ONE INC.

DEFINITIONS

For convenience, in this Annual Information Form:

“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;

“ADS” means the Advanced Distribution System;

“AIF” means this Annual Information Form;

“B2M LP” refers to B2M Limited Partnership;

“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;

“Council” means the Premier’s Advisory Council on Government Assets;

“DS” means a distribution station;

“DSC” means the Distribution System Code;

“EA” means the Environmental Assessment Act (Ontario);

“ECA” means an Electricity Conservation Agreement

“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 U.S. 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;

2014 ANNUAL INFORMATION FORM    3

DEFINITIONS

“IASB” refers to the International Accounting Standards Board;

“IESO” refers to the Independent Electricity System Operator, previously named the Independent Electricity Market Operator;

“IFRS” means International Financial Reporting Standards;

“Inergi Agreement” means the outsourcing service agreement with Inergi LP entered into on November 28, 2014 and commencing March 1, 2015;

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

“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;

“LRAM” means Lost Revenue Adjustment Mechanism;

“MAAD Application” means an application for a Merger Acquisition Amalgamation and Divestiture filed with the OEB;

“Market Rules” means the rules made under section 32 of the Electricity Act that are administered by the IESO;

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

“Ministry” or “Minister” means the 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;

4    HYDRO ONE INC.

DEFINITIONS

“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 Operation, Maintenance and Administration;

“OPA” refers to the Ontario Power Authority;

“Open Access” refers to the opening of Ontario’s wholesale and retail electricity markets to competition, which officially occurred on May 1, 2002;

“OPG” refers to Ontario Power Generation Inc.;

“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.

2014 ANNUAL INFORMATION FORM    5

HYDRO ONE BRAMPTON NETWORKS INC. HYDRO ONE REMOTE COMMUNITIES INC. HYDRO ONE TELECOM INC. 6 HYDRO ONE INC.

CORPORATE STRUCTURE

CORPORATE STRUCTURE

Hydro One Inc. was incorporated as Ontario Hydro Services Company Inc. by Articles of Incorporation dated December 1, 1998, under the Business Corporations Act (Ontario). On May 1, 2000, we changed our name to Hydro One Inc.

Our registered office and head office is located at 483 Bay Street, 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.

2014 ANNUAL INFORMATION FORM    7

FORWARD-LOOKING INFORMATION FORWARD-LOOKING INFORMATION 8 HYDRO ONE INC.

FORWARD-LOOKING INFORMATION

FORWARD-LOOKING INFORMATION

This AIF contains, and Hydro One’s oral and written public communications often contain, forward-looking statements that are based on current expectations, estimates, forecasts and projections about the business of Hydro One and the industry in which Hydro One operates and includes beliefs and assumptions made by the management of our company.

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 related to distribution sector consolidation, the 2013 LTEP, the Council, and customer service initiatives; statements related to the OEB’s RPP and TOU pricing, including expectations regarding the exemption of TOU pricing for certain rural customers and the timeline for converting those customers to TOU pricing; statements related to the FIT program; 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

required compliance/exceptions, the cost impact of their adoption, and possible recovery of these costs in rates; statements about smart meters; 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 regarding the Broader Public Sector Executive Compensation Act, 2014; statements about our outsourcing arrangements; expectations regarding environmental expenditures and other environmental matters including potential future costs related to PCBs, 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; expectations related to amendments to electricity industry codes; statements regarding the RRFE; expectations regarding our operating agreement with the IESO; statements regarding our transmission and distribution rates and customer bill impacts resulting from our rate applications; statements related to our connection assets including recovery of costs related thereto; expectations regarding developments in the statutory and operating framework for electricity distribution and transmission in Ontario including changes to rates, rate orders, cost recovery, rates

2014 ANNUAL INFORMATION FORM    9

FORWARD-LOOKING INFORMATION

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 of our company. 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, the Province could mandate the selling of all or part of our distribution business, as well as potential conflicts of interest that may arise between us, the Province and related parties;

10    HYDRO ONE INC.

FORWARD-LOOKING INFORMATION

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

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

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

— 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;

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

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

— the ability to negotiate appropriate collective agreements;

— the risk of labour disputes;

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

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

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

— 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 future environmental expenditures are not recoverable in future electricity rates;

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

— the risk that 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 impact of not being able to recover our pension costs;

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

— the potential that we may incur significant expenses to replace some or all of the functions currently outsourced if our agreements with Inergi LP or Brookfield Johnson Controls Canada LP are terminated or expire before a new service provider is selected;

2014 ANNUAL INFORMATION FORM    11

FORWARD-LOOKING INFORMATION

— 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;

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

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

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

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

— unanticipated changes in our costs;

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

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

— the inability to prepare financial statements using U.S. GAAP, or IFRS, as applicable;

— 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 statements provided in this AIF concerning potential future expenditures are provided in order to provide context to the nature of some of our future plans and may not be appropriate for other purposes.

12    HYDRO ONE INC.

FORWARD-LOOKING INFORMATION
Simplified Illustration of an Electric Power System
Renewable Generation
Generating Station
Transformer Station 500,000 Volts - 230,000 Volts
Transmission Lines 230,000 Volts - 115,000 Volts
Step-Down Transformer Station
Distribution Lines 44,000 Volts
Step-Down Distribution Station
Distribution Lines Below 44,000 Volts
Pole-Mounted Transformer
Home Wiring 120/240 Volts
2014 ANNUAL INFORMATION FORM 13
FORWARD-LOOKING INFORMATION

ABOUT HYDRO ONE
ABOUT HYDRO ONE
14 HYDRO ONE INC.

ABOUT HYDRO ONE

ABOUT HYDRO ONE

Hydro One is wholly owned by the Province, and our transmission and distribution businesses are regulated by the OEB. Our industry, including our company, is governed within the broad legislative framework of the Electricity Act and the OEB Act.

Our AIF provides material information about us and our business in the context of historical and future developments. 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 power supply. We will continue to focus our efforts

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ABOUT HYDRO ONE

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

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ABOUT HYDRO ONE

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 2014, Hydro One was one of the six LDCs honoured by the State of New Jersey in recognition of our support in the recovery efforts from Hurricane Sandy. Additionally, we were presented with the Utility Analytics Institute’s 2014 Innovation Award in Grid Analytics for the creation and implementation of an asset analytics application tool.

In 2013, 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 2014, we successfully completed our first annual Surveillance Audit required for our company to maintain our certification under the OHSAS 18001 Standard.

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GENERAL DEVELOPMENT OF THE BUSINESS
GENERAL DEVELOPMENT OF THE BUSINESS
18 HYDRO ONE INC.

GENERAL DEVELOPMENT OF THE BUSINESS

GENERAL DEVELOPMENT OF THE BUSINESS

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

Electricity Sector Landscape
As a participant in the Ontario electricity sector, our company is affected by the following key parties in the electricity sector in Ontario.
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.
OPA and IESO
The OPA was created in 2004 by virtue of an amendment to the Electricity Act, as a non-profit corporation without share capital, licensed and regulated by the OEB. Part II.1 of the Electricity Act defined its objects and the OPA had a mandate to ensure the adequacy and efficiency of electricity supply in Ontario through planning of electricity supply and demand. 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. The OPA and the IESO were amalgamated effective January 1, 2015.

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GENERAL DEVELOPMENT OF THE BUSINESS

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 leverage existing areas of expertise and grow revenues for the benefit of Ontarians”. The Province expects Hydro One to begin planning for a new Northwest bulk transmission line, west of Thunder Bay (the “North West Bulk Transmission Line Project”), with the project scope to be recommended by the OPA. On October 1, 2014, Hydro One received correspondence from the OPA requesting that the project commence development according to the scope and timing contained within the letter. Subsequently, the Company applied to the OEB for a variance account to track the project’s development costs for future recovery. The application is now in the interrogatory phase.

Recent Industry Activity

Premier’s Advisory Council on Government Assets

On April 11, 2014, the Province announced the appointment of the Premier’s Advisory Council on Government Assets to provide the Province with

recommendations designed to maximize the value of certain provincially owned assets, one of which being the Company. The objective of the review is to advise the Province on how to best maximize value from its assets. The Council’s Terms of Reference provided guidance indicating that it would give preference to continued ownership of government assets, but would consider mergers, acquisitions and divestments if there is a strong business case, and would enhance value to taxpayers of the Province.

The interim report released on November 19, 2014, noted the Company’s transmission business is a well-run entity with some opportunities to deliver savings on the operating side and on capital expenditures, and recommended that the Province maintain its ownership of the Company’s transmission business. The interim report noted that Ontario’s local electricity distribution system is an unnecessarily cluttered and fragmented system with too many entities, some of which are highly inefficient, unable to adapt to the changing environment and lack capital to modernize or consolidate.

Consequently, the Council recommended that the Company’s transmission and distribution businesses be separated, and that Hydro One Networks Inc.’s distribution business and Hydro One Brampton Networks Inc. be used to spur industry consolidation. The Council also recommended that the Province reduce its interest in our Company’s distribution business by bringing in private sector investment.

The Province has now asked the Council to build on its work by entering phase two, which includes the Council receiving and discussing written ideas related to encouraging consolidation and to Hydro One Brampton Networks Inc. and Hydro One Networks Inc.’s distribution business, and

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GENERAL DEVELOPMENT OF THE BUSINESS

finalizing its recommendations to the Province. We understand that the Province is specifically considering the sale of Hydro One Brampton Networks Inc., as well as the distribution business of Hydro One Networks Inc.

Customer Service Initiatives

During 2014, we focused tremendous effort on serving our customers and building stronger relationships. Through a series of three teletownhalls, we spoke to more than 60,000 customers from across Ontario and received their feedback on how we serve them and their ideas on making it easier to do business with Hydro One. To further improve our customer service performance culture, we have recently announced two initiatives: our draft customer commitments and a third party expert Customer Service Advisory Panel. Our customer commitments will form the basis of our promises to our customers, and the Customer Service Advisory Panel will provide advice and hold us accountable to the promises we make to our customers. Once our customer commitments are finalized with input received from our customers, our employees and our Customer Service Advisory Panel, we will develop a public scorecard and will report on our performance as a transparent, accountable and customer focused organization. Service levels of our billing system and at our call centre are now better than they were before we implemented our new billing system and we have set new targets that, when achieved, will put us among the best in the business.

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. In April 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”). In December 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 10 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 several LDCs. Hydro One was the successful proponent in three acquisitions in 2014: Norfolk Power Inc. (“Norfolk Power”), Woodstock Hydro Holdings Inc. (“Woodstock Hydro”), and Haldimand County Utilities Inc. (“Haldimand Hydro”).

In April 2013, Hydro One entered into an agreement with the Corporation of Norfolk County (“Norfolk County”) to purchase all the outstanding shares of Norfolk Power for approximately

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GENERAL DEVELOPMENT OF THE BUSINESS

$93 million, subject to OEB approval. On July 3, 2014, the OEB issued its Decisions and Order for our company to acquire all of the outstanding shares of Norfolk Power and for the transfer of Norfolk Power Distribution Inc.’s (the distribution company of Norfolk Power) distribution system to Hydro One Networks Inc.

In August 2014, we completed the Norfolk Power acquisition transaction. The total purchase price for Norfolk Power, net of the long-term debt assumed and adjusted for preliminary working capital and other closing adjustments was approximately $68 million.

In May 2014, we entered into an agreement with the City of Woodstock to purchase all outstanding shares of Woodstock Hydro for approximately $46 million, subject to OEB approval. Hydro One will pay the City of Woodstock approximately $29 million, being the enterprise value of Woodstock Hydro, net of Woodstock Hydro’s existing debt of approximately $17 million. Woodstock Hydro is the holding company which owns Woodstock Hydro Services Inc., a local distribution company serving the City of Woodstock. Hydro One filed its MAAD

Application on July 9, 2014 seeking OEB approval of the acquisition of Woodstock Hydro. An oral hearing for this application was held in January 2015.

In June 2014, we entered into an agreement with Haldimand County to purchase all of the outstanding shares of Haldimand Hydro for approximately $75 million, subject to OEB approval. Hydro One will pay Haldimand County approximately $65 million, being the enterprise value of Haldimand Hydro, net of Haldimand Hydro’s existing debt of approximately $10 million. Haldimand Hydro is the holding company which owns Haldimand County Hydro Inc., a local distribution company, and Haldimand County Energy Inc., a non-rate-regulated telecom company. Hydro One filed its MAAD Application on July 31, 2014 seeking OEB approval of the acquisition of Haldimand Hydro.

We intend to continue to consider growth opportunities through LDC consolidation by leveraging our existing assets, technologies, capabilities, unparalleled experience in LDC acquisitions and our distribution footprint.

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GENERAL DEVELOPMENT OF THE BUSINESS

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. Prices are developed using the RPP Manual methodology involving two essential steps; forecasting the total RPP supply cost for twelve months and establishing prices to recover the

forecast supply cost for RPP consumers over the period. The price structures are designed to make their consumption weighted average price equal to the average supply cost. There are two price structures: tiered pricing and TOU pricing. A consumer with an average load profile will pay the same average price under either price structure.

RPP Pricing (per kWh)
Winter (Nov. 1, 2013 – April 30, 2014)	Lower Tier Price	8.3 cents
	Upper Tier Price	9.7 cents
Summer (May 1, 2014 – Oct. 31, 2014)	Lower Tier Price	8.6 cents
	Upper Tier Price	10.1 cents
Winter (Nov. 1, 2014 – April 30, 2015)	Lower Tier Price	8.8 cents
	Upper Tier Price	10.3 cents

TOU Pricing Structure

TOU pricing structure is for consumers with eligible smart meters. 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. On December 1, 2014, Hydro One filed a request for a five year exemption extension for 120,000 hard-to-reach customers and requested permission to migrate an additional 50,000 customers back to tiered pricing as it is not economically feasible to consistently provide actual readings from these meters. An interim Decision dated December 18, 2014, has granted the exemption until June 30, 2015 or until a final Decision has been issued. Below is a chart outlining the TOU periods and the prices.

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GENERAL DEVELOPMENT OF THE BUSINESS

 RPP Pricing (per kWh) –TOU Prices

Winter (Nov. 1, 2013 – April 30, 2014)	Off-peak Price   7pm – 7am Weekdays, Weekends and Holidays	7.2 cents
	Mid-peak Price   11am – 5pm Weekdays	10.9 cents
	On-peak Price   7am – 11am, 5pm – 7pm   Weekdays	12.9 cents
Summer (May 1, 2014 – Oct. 31, 2014)	Off-peak Price   7 pm – 7 am   Weekdays, Weekends and Holidays	7.5 cents
	Mid-peak Price   7 am – 11 am, 5 pm – 7 pm   Weekdays	11.2 cents
	On-peak Price   11 am – 5 pm Weekdays	13.5 cents
Winter (Nov. 1, 2014 – April 30, 2015)	Off-peak Price   7 pm – 7 am   Weekdays, Weekends and Holidays	7.7 cents
	Mid-peak Price   11 am – 5 pm Weekdays	11.4 cents
	On-peak Price   7 am – 11 am, 5 pm – 7 pm   Weekdays	14.0 cents

New RPP prices are computed at six-month intervals and are the result of an integrated consideration of rebasing and true-ups.

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GENERAL DEVELOPMENT OF THE BUSINESS

Procurement of New Generation

Pursuant to a directive from the Province, 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 kW and generally up to 500 kW depending on connection voltage); and

— Large Renewable Procurement (competitive bids for projects generally greater than 500 kW) – this program has not been finalized.

All such projects may result in connection to Hydro One Networks Inc.’s distribution or transmission systems. 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.

In May 2013, the Province announced 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 which is expected to launch in 2015.

Recent Developments at Hydro One

Sustainable Electricity Company Designation

In January 2015, Hydro One Networks Inc. was designated a “Sustainable Electricity Company”. The Sustainable Electricity Company™ brand mark is a designation established by the Canadian Electricity Association. Companies that wish to use the Sustainable Electricity Company™ brand mark must commit to core subjects, issues and related actions and expectations contained in the standard that are deemed applicable and significant to the company and its stakeholders. The brand mark is granted for five years, with the option for renewal thereafter. The use of the Sustainable Electricity Company™ brand mark demonstrates Hydro One’s commitment to responsible environmental, social and economic practices, and to the principles of sustainable development.

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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 $12.5 billion of our total assets of $22.5 billion as at December 31, 2014, being approximately 56% of our total assets, 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 $9.8 billion of our total assets of $22.5 billion as at December 31, 2014, being approximately 43% of our total assets, distributes electricity through our low-voltage distribution system to municipalities and to rural areas. Customers of our distribution business include LDCs, customers with loads exceeding 5 MW, and rural and urban customers.

Hydro One Brampton Networks Inc. is our urban distribution company serving customers in the 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 $0.2 billion of our total assets of $22.5 billion as at December 31, 2014, being approximately 1% of our total assets.

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DESCRIPTION OF THE BUSINESS

DESCRIPTION OF THE BUSINESS

Our Business Segments

Our Transmission Business

Overview

Our transmission system operates at 500 kV, 230 kV and 115 kV and transmits electricity to customers consisting of 46 LDCs, our own distribution businesses and 90 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 113 in Ontario are connected directly to the transmission grid. Our transmission system serves approximately five million customers, directly or indirectly, and transported approximately 139.8 TWh of energy throughout Ontario in 2014. Revenues from our transmission business accounted for approximately 24% of our total revenues in 2014 and approximately 25% and 26% of our total revenues in 2013 and 2012, respectively.

Our transmission system forms an integrated transmission grid that can be divided into two categories based on function. The 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 27, 2014, estimates that, in the summer, with all transmission elements in service, the theoretical maximum capability for exports is up to 5,960 MW and for imports is up to 6,631 MW; in the winter, the theoretical maximum capability for exports is 6,295 MW and for imports is 6,963 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.

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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 whose rights may be potentially impacted 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. Telecommunications 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

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DESCRIPTION OF THE BUSINESS

terminal stations, including switchyards located at generating facilities, which are used mainly for switching and voltage transformation between the 500 kV, 230 kV, and 115 kV systems. The second category consists of customer supply stations, which are transmission stations that deliver power 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 290 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 271 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.

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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.

3. Transmission Capital Expenditure Plans

Transmission Capital Expenditure Plans consist of four segments:

A. Major Transmission Capital Development Projects,

B. Transmission Projects at the Local Load Connection Level,

C. Transmission Sustainment, and

D. Bruce to Milton Double Circuit Transmission Line.

Capital expenditures for the transmission portion of our business for 2015 are estimated to be approximately $900 million net overall. Our capital investment plan is designed to address

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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 115 kV and 230 kV. This plan also furthers our ongoing objective of sustaining the performance of aging assets through refurbishment programs and end-of-life asset replacements.

In February 2011, the Minister 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 completed the upgrade of the Lambton to Longwood transmission lines. This work was placed in service in September 2014. The OPA has not yet provided Hydro One Networks Inc. with any recommendations related to the build of a new transmission line west of London.

To enable the Province’s expectations contained in the 2013 LTEP, 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 Northwest Bulk Transmission Line Project. The scope and timing of the Northwest Bulk Transmission Line Project shall be in accordance with the recommendations of the OPA. On October 1, 2014, Hydro One received a letter from the OPA recommending scope and timing for this project. The Province also expects Hydro One and Infrastructure Ontario to work together to explore ways to ensure that the Northwest Bulk Transmission Line Project is developed and delivered in a cost-effective manner and results in value for Ontario electricity customers. These discussions are currently underway.

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

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proceed to construction if requisite approvals are not obtained or if anticipated generation does not materialize.

— 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 planned 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 with the remaining work expected to be completed in 2015.

— 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 upgrades at Allanburg TS and Leaside TS were completed in December 2014. All breakers at Manby TS and Hawthorne TS have been replaced and the planned in-service dates for the additional station work are mid-2016 and mid-2015 respectively.

— 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 remaining construction of the project will take approximately two months to complete once a land settlement agreement has been concluded between the Province, the federal government, 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

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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 project was approved for construction in November 2012, and placed in service in September 2014.

— 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 autotransformer 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. Hydro One began construction in July 2014, and the planned in-service date is 2017.

— Guelph Area Transmission Refurbishment Project

The project includes an upgrade of five 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. Hydro One started construction in late 2014 and the expected in-service date is approximately 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-2018.

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.

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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 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 moved to more integrated station and circuit centric 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.

D. Bruce to Milton Double Circuit Transmission Line

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 contemplated that ownership of Hydro One Networks Inc.’s 500 kV double circuit transmission line between the Bruce Nuclear Station and the Milton SS would be transferred to a partnership, being B2M LP, in which the SON would acquire an interest.

In November 2013, the OEB issued a decision and order granting B2M LP a transmission licence and granting Hydro One Networks Inc. leave to transfer the relevant transmission assets to B2M LP. In December 2014, the assets were transferred to B2M LP and the SON acquired a 34.2% interest in B2M LP. Our company operates the line for the partnership.

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 and also by relevant regulatory authorities in Canada, including the OEB. Accordingly, in Ontario the definition came into effect in July 2014 with full compliance in 2016.

Significantly more transmission facilities (facilities at or above 100 kV except excluded by definition) are now being designated BES and will 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 will result in significant additional

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costs to the transmission facility owners, including Hydro One. We anticipate these incremental costs will be spread over a number of years, and expect that they will be recovered in rates.

In Ontario, the IESO has developed a “made in Ontario” BES Exception Procedure and criteria to allow market participants such as Hydro One to submit an exception application for a newly designated BES element. Hydro One is currently in the process of submitting exception applications for some of the newly designated BES elements.

5. NERC Critical Infrastructure Protection Standards

NERC critical infrastructure protection 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.

Hydro One is currently mandated to comply with 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 22, 2013. On November 13, 2014, the NERC Board of Trustees adopted a number of revisions to Version 5 of the standards in response to a FERC Order No. 791. NERC is required to file revisions by February 3, 2015. The expected enforcement dates for Ontario vary depending on the requirements; many requirements are expected to become enforceable on April 1, 2016, while others are to become enforceable later.

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 2014, 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 150,000 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 37 customers with loads exceeding 5 MW. The distribution system comprises approximately 3,300 feeders operating at voltages less than 50 kV, totalling approximately 123,000 circuit kilometres of lines; and 1,026 distribution and regulating stations. Our distribution systems distribute electricity from our transmission system and more than 14,200 small generators (approximately 1,600 generators that are greater

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than 10 kW and approximately 12,600 that are less than or equal to 10 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 system in Brampton is a densely-populated urban area. Accordingly, the distribution system is designed with a large 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 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 75% of our total revenues in 2014 and approximately 74% and 73% of our total revenues in 2013 and 2012, respectively.

This section on our distribution business consists of six topics:

1. Distribution Capital Expenditure Plans

2. Distribution Assets

3. Remote Communities

4. Conservation and Demand Management

5. Advanced Distribution System

6. Smart Meters

1. Distribution Capital Expenditure Plans

Capital expenditures for the distribution portion of our business for 2015 are estimated to be approximately $700 million net overall. Consistent with our approved distribution rate application, capital expenditures for our distribution business for 2014 were focused on new load connections, trouble calls and storm damage, wood pole replacement, and system capability reinforcement. Going forward into 2015 and 2016, we expect to 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.

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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 by these remote communities is produced by 57

installed diesel generators owned or operated by us, which are supplemented by small amounts of wind or hydroelectric generation. Pursuant to section 48.1 of the Electricity Act and Ontario Regulation 199/02 thereunder, we are required, through one or more of our subsidiaries, to operate and maintain existing generation and distribution assets in, and supply electricity to, these remote communities.

4. Conservation and Demand Management

The Province has established specific provincial targets for CDM that are fully funded through the Global Adjustment. 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 a report, by September 30 annually, with the results of its CDM program.

The OPA annually submits to the OEB proposed expenditure, revenue requirements and fees for review pursuant to subsection 25.21 of the

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Electricity Act. Included in these submissions is the OPA’s operating budget required to administer 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 licensees. The CDM Code was created in response to a directive dated March 31, 2010 by the Minister. On November 12, 2010, the OEB issued final CDM targets for the period 2011-2014. The distribution business Hydro One Networks Inc. was assign 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 of 2011-2014, which is equivalent to about a 6% peak demand reduction and on a cumulative basis, a 5% energy reduction.

On April 26, 2012, the OEB issued its CDM guidelines for all electricity distributors. These guidelines provide more specific guidance on certain provisions in the CDM Code and the type of evidence that should be filed by distributors in

support of an application for OEB-approved CDM programs. 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, 2014, in accordance with the CDM Code, Hydro One Networks Inc. and Hydro One Brampton Networks Inc. each filed a 2013 Annual CDM Report with the OEB outlining each company’s CDM activities, energy and peak demand savings results achieved in 2013, and expectations regarding CDM targets for the end of 2014. Hydro One Networks Inc. reported that it expected to reach 95%-100% of its demand target and 80% of its cumulative energy target by the end of 2014. Hydro One Brampton Networks Inc. reported that it expected to reach 60% of its demand target and 100% of its cumulative energy target by the end of 2014.

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.

In March 2014, the Ministry issued parallel directives to the OEB and the OPA, respectively, regarding the new “2015-2020 Conservation Framework”. The directives call for the OPA to establish a provincial target of 7 TWh of persistent energy savings to be achieved by 2020 and for all LDCs to enter into an ECA with the OPA by December 31, 2014. Both Hydro One Networks

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Inc. and Hydro One Brampton Networks Inc. submitted their signed ECAs to the OPA in December 2014. Conservation opportunities will be provided to customers and available to distributors to ensure both end-user usage and utility systems are as efficient as possible.

The OPA allocated targets and budgets to LDCs on October 31, 2014. Hydro One Networks Inc.’s 2015-2020 CDM savings target is 1,159 GWh to be achieved with a budget of $322 million. Hydro

One Brampton Networks Inc.’s 2015-2020 CDM savings target is 255.2 GWh to be achieved with a budget of approximately $67 million. All LDCs must submit CDM Plans indicating how they will achieve their allocated targets by May 1, 2015 using either “Full Cost Recovery” or “Pay-for-Performance” funding models. All CDM programs must be cost-effective to ensure full cost recovery. LDCs may, at any point, resubmit changes to their CDM Plan for approval by the OPA.

On December 19, 2014, the OEB issued its new Conservation and Demand Management Requirement Guidelines (the “2015 Guidelines”). The 2015 Guidelines are consistent with the Directive the OEB received on March 24, 2014 from the Minister requiring the OEB to take steps to promote CDM, including amendments to the licences of electricity distributors and the establishment of CDM Requirement guidelines.

The 2015 Guidelines are effective January 1, 2015 and apply to CDM programs beginning January 1, 2015. Effective January 1, 2015, the OPA merged with the IESO and therefore the 2015 Guidelines refer to the IESO for future conservation activities since the IESO is now responsible for these functions beginning January 1, 2015. The CDM Code and April 26, 2012 guidelines will continue to apply to all activities related to the 2011 to 2014 CDM Framework.

5. Advanced Distribution System

The ADS project is an 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. We did not seek any funding in 2012. OM&A in the amount of $15.6 million 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 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)

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at the OGCC. In 2013, the majority of the build phase was completed, with the remainder planned for completion in early 2015. End-to-end solution validation, to confirm design decisions and provide real time experience with the components, has delivered the foundation for distribution automation and distributed generation integration.

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 2015 and will be augmented with additional projects that build on the objectives of delivering customer benefits and operational efficacies.

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. LDCs are accountable for the deployment of smart meter infrastructure and related technology for communications to meet minimum requirements as defined in the regulations. The Province has appointed the IESO to be the entity whose mandate includes the storage of all provincial hourly data. Distributors are also accountable for the implementation of TOU pricing.

Hydro One Networks Inc. and Hydro One Brampton Networks Inc. have installed approximately 1.4 million smart meters as of the end of 2014 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.

At the end of 2014, Hydro One completed all material activities associated with the implementation of smart meters and transitioned to regular sustainment maintenance activities. Hydro One Networks Inc. has installed approximately 1.2 million smart meters as of the end of 2014 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 2014, Hydro One continued to optimize the smart meter communication network through a number of firmware and software upgrades and communication network equipment

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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 2014. 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 and its transition to TOU pricing by 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 (eight months) and 2014 (full year) and is estimated at $1 million and $1.5 million respectively.

Smart meter expenditures for 2014 were $16.1 million for Hydro One Networks Inc. Planned expenditures in 2015 are expected to be approximately $0.5 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 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. In December 2014, Hydro One Networks Inc. filed another application to continue the TOU exemption for a period of five years for customers in portions of Hydro One Networks Inc.’s service territory where communication capability is inadequate to support smart metering. In December 2014, the OEB granted an interim extension to the TOU exemption which will expire June 30, 2015 or at the final determination of the application. The written proceeding on the matter commenced in the first quarter of 2015.

Hydro One Networks Inc. replaced a certain type of installed commercial/industrial grade smart meter as approximately 0.35% of this class of meter has malfunctioned in a manner causing physical damage to the meter. Approximately 17,000 of the affected meters have been successfully replaced.

Hydro One Brampton Networks Inc. is replacing a certain type of smart meter for its small commercial and industrial customers. Since the installation of these meters, approximately 0.26% of this class of meter have malfunctioned in a manner causing physical damage to the meter. Hydro One Brampton Networks Inc. will be replacing these meters beginning in January 2015.

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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 Arrangements

5. Environmental

6. Health and Safety

7. Insurance

8. Legal Proceedings and Regulatory Actions

9. Financial

10. Cornerstone

1. Employees

At the end of 2014, our Hydro One Networks Inc. subsidiary had 5,145 regular (i.e., permanent) employees comprised of 584 non-represented executive and managerial staff, 3,271 employees represented by the PWU and 1,290 employees represented by the Society. Hydro One Inc., Hydro One Remote Communities Inc. and Hydro One Telecom Inc. together have 224 employees in total. Hydro One Inc., Hydro One Networks Inc., Hydro One Remote Communities Inc. and Hydro One Telecom Inc. also had 2,211 non-regular (i.e., temporary) employees comprised of 29 executive and managerial staff, 174 employees represented by the PWU, 54 employees represented by the Society, 599 employees covered by Appendix “A” of the PWU agreement (PWU Hiring Hall) and 1,355 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

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One’s membership in EPSCA is ongoing. Our Norfolk Power Distribution Inc. subsidiary had 41 regular employees comprised of 13 non-represented management staff, and 28 employees represented by the PWU, and 3 non-regular (i.e., temporary) employees. In addition, our Hydro One Brampton Networks Inc. subsidiary had 58 non-represented regular staff, 108 active employees represented by UNIFOR (previously the Canadian Auto Workers), 43 employees represented by the International Brotherhood of Electrical Workers and 23 contract staff.

On March 31, 2014, Hydro One Brampton Networks Inc. and UNIFOR reached a Memorandum of Agreement for a renewal collective agreement. The term of the renewal collective agreement is from April 1, 2014 to March 31, 2017. On May 5, 2014, Hydro One Brampton Networks Inc. and the International Brotherhood of Electrical Workers reached a Memorandum of Agreement for a renewal collective agreement. The term of the renewal collective agreement is from April 1, 2014 to March 31, 2017. The collective agreement between Hydro One Inc. and the Canadian Union of Skilled Workers expired on April 30, 2014 and discussions are on-going. The collective agreement between Hydro One Inc. and the PWU expires on March 31, 2015. 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.

In December 2014, Bill 8, An Act to Promote Public Sector and MPP Accountability and Transparency by Enacting the Broader Public Sector Executive Compensation Act, 2014 and Amending Various Acts, was passed. Schedule 1 to Bill 8 is the Broader Public Sector Executive Compensation Act, 2014, which will come into force when it is proclaimed. The passing of this legislation has the effect of giving the government the authority to create comprehensive compensation frameworks for certain employers in

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the broader public sector, including our company, and would implement a number of measures to enhance accountability and transparency in the government and the public sector. The legislation applies to certain defined, designated executives, primarily senior management, at Hydro One. See “Statement of Executive Compensation”.

3. Pension Plan

We established a defined benefit registered pension plan on December 31, 1999. Hydro One Inc. manages and invests the assets and liabilities of the pension fund as plan sponsor and administrator of the plan. As of December 31, 2014, there were 5,324 active members and 7,682 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, 2013 was filed with the Financial Services Commission of Ontario in June 2014. 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 Arrangements

The current outsourcing services agreement with Inergi LP (an affiliate of Capgemini Canada Inc.), entered into as of December 28, 2001 (“2001 Inergi Agreement”), expires on February 28, 2015. On November 28, 2014 we entered into an agreement through our subsidiary Hydro One Networks Inc., with Inergi LP, the service provider selected through

a competitive procurement process which began in 2013, for second-generation back office and IT outsourcing services for a term of 58 months, commencing March 1, 2015 and continuing to December 31, 2019. Under this agreement, Inergi LP will provide us with settlements, source to pay services, pay operations services, information technology and finance and accounting services.

Coincident with the conclusion of negotiations on the back office and IT outsourcing services, we reached agreement with Inergi LP to provide us with second-generation customer service operations outsourcing services for a fixed period of three years beginning March 1, 2015, to February 28, 2018. The back office and IT outsourcing and the customer service operations outsourcing arrangements with Inergi LP commencing in 2015 are collectively referred to as the “Inergi Agreement”.

The Inergi Agreement guarantees aggregate minimum revenue to Inergi LP of approximately $326 million over the terms 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.

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Fees are subject to decreases based on optional external benchmarking analyses. 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 certain rights of early termination for convenience or 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 Arrangements”.

On September 15, 2014, we entered into an agreement, through our subsidiary Hydro One Networks Inc., with Brookfield Johnson Controls Canada LP (the “Brookfield Agreement”), the service provider selected through a competitive procurement process, for facilities management services for a term of ten years, effective January 1, 2015 to December 31, 2024, with the option to renew for an additional term of three years. Over the term of the contract, Hydro One Networks Inc. will transition the facilities management of all of our facilities. Under the Brookfield Agreement, Brookfield Johnson Controls Canada LP will provide us with facilities management and execution of certain capital projects as may be deemed to be required by Hydro One Networks Inc.

The Brookfield Agreement has a value of up to approximately $658 million over the ten year term of the agreement, including the facilities management portion of the contract, plus a variable amount of capital work depending on the needs that may arise as determined by Hydro One Networks Inc., with no minimum capital work guarantee. The Brookfield Agreement provides for 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 Arrangements”.

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

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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.

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

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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.

In April 2014, amendments to the PCB regulations were enacted and came into force January 1, 2015. The amendments among other things, extend the end-of-use deadline for Hydro One’s PCBs in concentrations of 500 parts per million or more from December 31, 2014 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 current PCB regulations is about $195 million. After consideration of our 2014 spending of $5 million, this represents a decrease from the prior year of about $42 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 $33 million in 2014. 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 $33 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 $9 million liability in respect of this obligation as at December 31, 2014, based on the net present value of the Company’s best estimate of the total future expenditures of $18 million to complete its asbestos removal activities. We anticipate that such future expenditures will be recoverable in future electricity rates.

Herbicides

We use herbicides for the control of incompatible vegetation on transmission and distribution rights-of-way and for total vegetation control on station sites. We currently use an integrated vegetation management approach toward vegetation management using manual and mechanical cutting, together with the use of herbicides. The Pesticides Act (Ontario) and associated Regulation 63/09 include a public works exception under which herbicide application is allowed for utility programs. We are working with both government and external agencies to ensure we are in compliance. As indicated below, the historical use of herbicides has contaminated some of our properties and some nearby properties.

On March 11, 2011, the Ministry of Natural Resources created an independent fact-finding

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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, which were released to the public on June 13, 2013, assessed potential health impacts of historical exposure scenarios. The Workplace Safety and Insurance Board has put in place a special adjudication team to handle claims arising out of potential exposure to 2,4,5-T.

Wood Preservatives

Wood preservatives are used in wood poles to protect the wood against fungi and insects and thereby extend their service lives. In the past, we have used poles which were impregnated with pentachlorophenol. We respond to contamination problems related to pentachlorophenol migration as they arise.

Land Assessment and Remediation

Hydro One Networks Inc. has a voluntary land assessment and remediation program in place to identify and, where necessary, remediate historical contamination that has resulted from past (Ontario Hydro) operational practices and uses of certain long-lasting chemicals, at our transmission and distribution stations and service centres. Our Hydro One Remote Communities Inc. subsidiary also has a similar program in place for generating stations it owns or operates. These programs involve the systematic identification of any contamination at or from these facilities and, where necessary, the development of remediation plans for our properties and affected adjacent private properties. Potential contaminants include insulating oils, substances previously used for 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 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 or mitigated risk related to 471 sites of the 628 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

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remediation program are currently estimated at approximately $57 million. These expenditures are expected to be spent over the period ending 2023. The consolidated expenditures on this program (including Hydro One Remote Communities Inc.) for 2014 were approximately $13 million.

Electric and Magnetic Fields

Electric and magnetic fields exist wherever electricity is used or transmitted, including electric power facilities such as transmission and distribution lines and substations, and within every building in Ontario that has electrical service. National and international health agencies, including the World Health Organization, have reported that the evidence is insufficient to conclude that the low levels of these fields in our communities have adverse effects on peoples’ health. 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 schools, including those located just outside the boundaries of power line corridors.” 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 workplace injuries. These measures 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

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

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

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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 2014, 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 2014. It is expected to continue in future years.

During 2014, there was a focus on the following areas: Journey to Zero initiatives, improving health and safety risk assessment and data mining, application of safety by design, effective investigation and corrective actions, healthy workplace (mental health), job planning, slip/trip/fall prevention best practices, and environment management system improvements.

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 in 2013 allows Hydro One to enhance our health & safety 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 our enterprise wide SAP system and use of next-generation business tools to

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make precision investments in capital and OM&A to obtain maximum benefit, continuation of optimizing our outsourcing arrangements pursuant to which we outsourced non-core functions to Inergi LP and the consolidation of our system operations functions, as well as facility services to Brookfield Johnson Controls Canada LP.

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.

Hydro One began reporting under U.S. GAAP in the first quarter of 2012. In 2013, we registered with the SEC on Form F-10 and listed medium term notes on the NYSE. The OEB approved our use of U.S. GAAP and the Province passed a regulation which consequently allowed us to use U.S. GAAP as it better reflects our financial position and is consistent with comparator companies.

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, 2014.

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 focused on further optimization between 2011 and 2014, during which time the new enterprise IT system was expanded to drive additional business value, improve end-to-end process efficiency and improve asset lifecycle management analytics/decisions. Cornerstone Phase Three was 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). The new system went into service in May 2013. The project entered sustainment mode in 2014.

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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”.

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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.; OEB 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, approval of leave to construct, change in ownership, 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. In the case of rate proceedings, 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 December 31, 2019.

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.

In May 2014, the OEB adopted two more amendments to the DSC. One amendment governs the relationship between distributors and unmetered load customers. The second amendment stipulates the requirement for a distributor to install an interval meter on any installation that is forecast to have a monthly average peak demand during the calendar year of over 50 kW.

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”.

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REGULATION

Rate Orders and Related Issues for Hydro One’s Businesses

The OEB approves both the revenue requirements of and the rates charged by our regulated businesses. The rates are designed to permit our businesses to recover the allowed costs and to earn a formula-based annual rate of return on our common equity by applying a specified equity risk premium to forecast interest rates on long-term bonds.

The term “utility rate base” refers to the investment in regulated operations, consisting of gross plant (property, plant and equipment) in service, less accumulated depreciation, plus necessary working capital and in general excluding construction work in progress. Utility rate base is used to determine the capital structure for our regulated businesses, enabling a determination of approved financing charges and return on common equity for them.

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 May 2012, Hydro One Networks Inc. submitted a cost of service rate application for its transmission business for 2013 and 2014 for revenue requirements of $1,438 million and $1,528 million respectively. In November 2012, the OEB approved the rate order for 2013. The draft rate order for 2014 was filed in December 2013 using an increased revenue requirement of $1,535 million due to the adjusted cost of capital parameters. The 2014 rate order was approved in January 2014. The approved 2014 revenue requirement represented a transmission rate increase of 6.3% in 2014, or 0.5% when considering total bill impact for a typical residential customer consuming 800 kWh per month.

In December 2014, Hydro One Networks Inc. submitted its draft transmission rate order that implements the OEB’s oral decision accepting Hydro One Networks Inc.’s Transmission Settlement Agreement on the 2015 and 2016 transmission revenue requirement. On January 8, 2015, the OEB issued the approved Rate Order. The 2015 base revenue requirement is $1,477.3 million (excluding the B2M LP revenue requirement). This represents an increase on a typical residential customer’s total bill of 0.03%. The 2016 revenue requirement of $1,515.9 million (excluding the B2M LP revenue requirement) will be further updated to reflect

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the OEB’s November 2015 cost of capital parameters in the 2016 draft rate order.

In October, 2014, B2M LP filed an application with the OEB for an interim transmission rate, effective January 1, 2015, seeking the approval of a revenue requirement of $41 million in 2015. This rate is equal to the amount included in Hydro One Networks Inc.’s transmission rates for the Bruce to Milton transmission line assets, resulting in no change to overall Uniform Transmission Rates. The Interim Rate Order was approved by the OEB on December 11, 2014. B2M LP was directed to file a full cost-of-service application for final 2015 transmission rates by April 1, 2015.

Bypass

Bypass occurs when we have invested in the provision of transmission facilities to a customer which then obtains all or part of its transmission services in another manner or takes action to avoid its use of our transmission services before the rates collected have paid for the investment. Recovery of the remaining costs for the stranded facilities then necessitates higher transmission rates from the remaining customers.

In August 2005, following an extensive consultation process, the OEB issued a revised 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.

Facilities Applications

Transmission line construction, expansion, or reinforcement 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 appropriate consultation with First Nations and Métis communities. This is to ensure a complete review of proposed transmission projects. Cost recovery of approved facilities requires a final approval from the OEB as part of a transmission rate application.

In January 2014, the OEB amended the transmission licence of Hydro One Networks Inc. to develop and seek approval for the expansion for the Northwest Bulk Transmission Line Project.

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In October 2014, as part of the 2013 LTEP, the OPA directed Hydro One to commence development according to the scope and timing contained within the OPA’s letter. Subsequently, the Company applied to the OEB for a variance account to track the project’s development costs for future recovery. The application is now in the interrogatory phase.

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.

In March 2014, the OEB issued its “Report of the Board on Performance Measurement for Electricity Distributors: A Scorecard Approach” setting out

the OEB’s policies on the measures to assess a distributor’s effectiveness and improvement in achieving customer focus, operational effectiveness, public policy responsiveness, and financial performance to the benefit of existing and future customers. LDCs’ scorecards were published on the OEB website on September 25, 2014.

Current Rate Orders and Distribution Rate Structure

a) Hydro One Networks Inc.

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 was submitted under the OEB’s RRFE. It was customized to fit Hydro One Networks Inc.’s specific circumstances, which necessitate significant and necessary multi-year investments. We are seeking OEB approvals for distribution revenue requirement of $1,415 million for 2015, $1,523 million for 2016, $1,578 million for 2017, $1,615 million for 2018, and $1,660 million for 2019. If the application is approved as filed, the resulting change to the distribution portion of the bill for a typical residential customer will be approximately a 1.4% decrease in 2015, 3.8% increase in 2016, 2.3% increase in 2017, 1.2% increase in 2018, and 2.6% increase in 2019. When

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considering total bill impact, the resulting change will be approximately a 1.5% decrease in 2015, 1.3% increase in 2016, 0.8% increase in 2017, 0.4% increase in 2018, and 0.9% increase in 2019 for a typical residential customer. A technical conference, a settlement conference and an oral hearing took place in the third quarter of 2014. In December 2014, the OEB issued a Decision and Interim Rate Order approving the 2014 distribution rates as interim 2015 rates effective January 1, 2015. The OEB also approved the discontinuation of the collection of revenues for the provincially funded portion of renewable generation connection investments of approximately $20 million per year from rate payers effective December 31, 2014. A final Decision and Order from the OEB is anticipated in the first quarter of 2015.

b) Hydro One Brampton Networks Inc.

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.

In April 2014, Hydro One Brampton Networks Inc. filed a cost of service rate application requesting distribution rates effective January 1, 2015 under rate setting method one; the 4th Generation Incentive Rate-setting (4th Generation IR). On December 18, 2014 the OEB issued its Decision and Order on Hydro One Brampton Networks Inc.’s 2015 Cost of Service Rate Application and the OEB approved a revenue requirement of $72.1 million dollars. The OEB also approved adjustments to transmission rates and the disposition of balances related to the lost revenue adjustment mechanism of $0.5 million and stranded meters of $0.5 million. In addition the OEB approved a rate rider for the recovery of $5.8 million over a three year period, related to changes in Hydro One Brampton Networks Inc.’s capitalization policy. The OEB also approved rate riders for the disposition of $1.3 million of group 1 and 2 deferral and variance accounts to be recovered over a one year period. The impact on the distribution component of the customer’s bill for a typical residential customer with monthly electricity consumption of 800 kWh will be an increase of approximately $1.12 or 4.53%, and an increase of approximately $1.89 or 1.58% on the total bill. On January 15, 2015, the OEB issued its Final Rate Order approving the rates and riders as submitted by Hydro One Brampton Networks Inc. in its Draft Rate Order.

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 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

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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%.

In September 2014, Hydro One Remote Communities Inc. filed an application for 2015 distribution rates under the OEB’s Price Cap Incentive. The final rate increase will be adjusted by the OEB’s updated rate adjustment parameters.

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 December 2014, the OEB estimated the total RRRP benefit in 2015 to be $174 million, which includes the $127 million payable to Hydro One Networks Inc. Any over or under collection of the $174 million will be tracked in a variance account.

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

On December 19, 2014, the OEB determined that effective January 1, 2015 the RRRP charge to be collected by the IESO shall remain at 0.13 cents per kilowatt-hour and the RRRP charge billed to customers by a distributor shall also remain at 0.13 cents per kilowatt-hour.

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. On December 18, 2014, the OEB granted Hydro One Networks Inc.’s request to discontinue collection of revenue through the renewable connection funding adder from provincial ratepayers under Ontario Regulation 330/09 made under the OEB Act, effective December 31, 2014.

Ontario Clean Energy Benefit Act

As announced in its 2010 Ontario Economic Outlook and Fiscal Review, the Province

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introduced the Ontario Clean Energy Benefit Act, 2010 (the “Clean Energy Act”), which is designed to assist Ontario electricity consumers through the transition to a cleaner, modern electricity system. Under the Clean Energy 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.

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 Networks Inc. is currently seeking disposition of the deferral accounts associated with connecting these generators in its 2015-2019 custom rate application.

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RISK FACTORS

Ownership by the Province

The Province owns all of our outstanding shares. Accordingly, the Province has the power to determine the composition of our Board, 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 2001 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.

Effective December 17, 2014, the Province made a further declaration pursuant to the memorandum of agreement and section 108 of the Business Corporations Act (Ontario) regarding the provision of information, personnel and resources to the Premier’s Advisory Council on Government Assets. By way of the declaration and concurrent shareholder resolution, the Province restricted the rights, powers and duties of our Board, and at the same time assumed such rights, powers and duties, with respect to providing the Council, the Government or the Ministries and their advisors and consultants all information, assistance, personnel, resources and reports as and when requested and co-operating with those Government advisors tasked with providing recommendations on labour relations matters and

pension-related matters. The directors are charged with carrying out the intention of the declaration and resolution, including taking such necessary steps to issue similar declarations and resolutions with respect to Hydro One Networks Inc. and Hydro One Brampton Networks Inc. See “Interest of Management and Others in Material Transactions – Relationships with the Province and Other Parties – Memorandum of Agreement”. The Province could mandate the selling of all or part of our distribution business and this could have a material adverse effect on our company.

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

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ownership interest in our company, including any potential outcomes arising out of the recommendations of the Ontario Distribution Sector Review Panel’s report, the Province’s ownership of OPG, and the determination of the amount of dividend or proxy tax payments. We may not be able to resolve any potential conflict with the Province on terms satisfactory to us, which could have a material adverse effect on our business.

Regulatory Risk

We are subject to regulatory risks, including the approval by the OEB of rates for our transmission and distribution businesses that permit a reasonable opportunity to recover the estimated costs of providing safe and reliable service on a timely basis and earn the approved rates of return.

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

The OEB’s new RRFE requires that the term of a custom rate application (distribution business) be 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.

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 of recovery of costs could have an adverse effect on our company.

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Risk of Natural and Other Unexpected Occurrences

Our facilities are exposed to the effects of severe weather conditions, natural disasters, man-made events including cyber and physical terrorist type attacks and, potentially, catastrophic events, such as a major accident or incident at a facility of a third party (such as a generating plant) to which our transmission or distribution assets are connected. Although constructed, operated and maintained to industry standards, our facilities may not withstand occurrences of this type in all circumstances. We do not have insurance for damage to our transmission and distribution wires, poles and towers located outside our transmission and distribution stations resulting from these events. Losses from lost revenues and repair costs could be substantial, especially for many of our facilities that are located in remote areas. We could also be subject to claims for damages caused by our failure to transmit or distribute electricity. Our risk is partly mitigated because our transmission system is designed and operated to withstand the loss of any major element and possesses inherent redundancy that provides alternate means to deliver large amounts of power. In the event of a large uninsured loss we would apply to the OEB for recovery of such loss; however, there can be no assurance that the OEB would approve any such applications, in whole or in part, which could have a material adverse effect on our net income.

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, engagement and consultation 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 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 terms of payment. 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 2014, we paid approximately $0.9 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

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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 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.

Work Force Demographic Risk

By the end of 2014, approximately 17% of our

employees were eligible for retirement and by the end of 2015 up to 21% could be eligible. These percentages are not evenly spread across our workforce, but tend naturally to be most significant in the most senior levels of our staff and especially among management and executive staff. Accordingly our continued success will be tied to our ability to attract and retain sufficient qualified staff to replace the capability lost through retirements and meet the demands of our work programs. This will be more challenging than in the past for a number of reasons.

Firstly, we expect the skilled labour market for our industry to be highly competitive in the future: many of our current employees and many of the employees we are going to be looking for possess skills and experience that will also be highly sought after by other organizations inside and outside the electricity sector; secondly, a variety of restraints on compensation and benefits for management and executive staff (including Bill 8) together with possible pension plan changes, and the uncertainty attaching to Hydro One’s future size and scope as a result of the work of the Council, may adversely impact our ability to attract and retain the number and calibre of people we need in these roles.

In order to mitigate the potential effects of these factors, we are focused on earlier identification and more rapid development of staff who demonstrate the potential to progress quickly, especially those who demonstrate leadership potential, and on maintaining robust but flexible succession plans for the organization. In addition we continue to advance our apprenticeship and technical training programs to ensure that our future operational staffing needs will be met.

Labour Relations Risk

The substantial majority of our employees are

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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.

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 $550 million maturing in 2015 and $500 million maturing in 2016. We plan to incur capital expenditures of approximately $1,600 million in 2015 and $1,625 million in 2016. 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.

Asset Condition

We continually monitor the condition of our assets to determine need and timing of preventative or remedial actions to maintain the desired level of service. Condition assessment is one of the key drivers for asset maintenance, refurbishment or replacement strategies 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.

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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.

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

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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.

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 most recently filed valuation was prepared as at December 31, 2013, and was filed in June 2014. Our company contributed approximately $160 million in respect of 2013 and approximately $174 million in respect of 2014 to its pension plan to satisfy minimum funding requirements. Contributions beyond 2014 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.

Risk Associated with Outsourcing Arrangements

Consistent with our strategy of reducing operating costs, we entered into outsourcing arrangements with Inergi LP and Brookfield Johnson Controls Canada LP. See “Description of the Business – Outsourcing Arrangements”. If either of these outsourcing arrangements are 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 or insource, which could have a material adverse effect on our business, operating results, financial condition or prospects.

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’ 2015 net income by approximately $20 million and our Hydro One Networks Inc. distribution business’ 2015 net income by approximately $13 million. Our net income is adversely impacted by rising interest rates as our maturing long-term debt is refinanced at market

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RISK FACTORS

rates. We periodically utilize interest rate swap agreements to mitigate elements of interest rate risk.

Financial assets create a risk that a counterparty will fail to discharge an obligation, causing a financial loss. Derivative financial instruments result in exposure to credit risk, since there is a risk of counterparty default. We monitor and minimize credit risk through various techniques, including dealing with highly-rated counterparties, limiting total exposure levels with individual counterparties, and by entering into master agreements which enable net settlement and by monitoring the financial condition of counterparties. We do not trade in any energy derivatives. We do, however, have interest rate swap contracts outstanding from time to time. Currently, there are no significant concentrations of credit risk with respect to any class of financial assets. We are required to procure electricity on behalf of competitive retailers and embedded LDCs for resale to their customers. The resulting concentrations of credit risk are mitigated through the use of various security arrangements, including letters of credit, which are incorporated into our service agreements with these retailers in accordance with the OEB’s Retail Settlement Code. The failure to properly manage these risks could have a material adverse effect on our company.

Risk Associated with Transmission Projects

Transmission projects involve either modifying existing or building new transmission lines and/or stations or both. Such projects are required primarily to address limitations on the transmission network to transfer power from generation sources to load centres, improve regional load supply capacity and reliability, connect new generators and load customers, and to meet new or changes to codes and standards.

In many cases, transmission 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 possibly some identified enabler facilities and network enhancement projects. The facilitation of competitive transmission could impact our future work program and our ability to expand our current transmission footprint. In addition, as bid costs are recoverable only by the successful proponent, additional costs for unsuccessful bids would be absorbed. This could have a material adverse effect on our company.

Risk from Provincial Ownership of Transmission Corridors

Pursuant to the Reliable Energy and Consumer Protection Act, 2002, the Province acquired ownership of our transmission corridor lands underlying our transmission system. Although we have the statutory right to use the transmission corridors, we may be limited in our ability to expand our systems. Also, other uses of the transmission corridors by third parties in conjunction with the operation of our systems may increase safety or environmental risks, which could have an adverse effect on our company.

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DIVIDENDS

DIVIDENDS

Dividends on our common shares and Series A preferred shares are declared at the discretion of our Board and are recommended by our management based on our results of operations, maintenance of the deemed regulatory capital structure, financial condition, cash requirements and other relevant factors, such as industry practice and shareholder expectations.

Our company’s policy is to declare and pay cash dividends on our common shares on the basis of a calculation involving our regulated net income net of preferred dividends and non-regulated net income. Any factor that adversely affects our company’s net income would likely be reflected in our dividend payments.

We declared and paid to the Province annual dividends on our outstanding 100,000 common shares totalling approximately $269 million in 2014 as compared with $200 million in 2013

and $352 million in 2012. 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 2014, 2013 and 2012, which was calculated at a rate of $1.375 per annum per share, as stipulated in our company’s Articles of Incorporation. Additionally, in 2014 we made payments in lieu of taxes to OEFC in the amount of approximately $86 million, as compared to $138 million in 2013.

72    HYDRO ONE INC.

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, 2014, 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 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, Series 31 Notes (Floating Rate 3-month BA + 0.35%) due 2019 and Series 32 Notes (4.17%) due 2044, 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 2014:

Note	Principal Amount   (million) ($)	Sale Price ($) /   $100 principal  amount	Gross Proceeds ($)
Series 30 Notes (4.29%) due 2064	50	99.938	49,969,000.00
Series 31 (Floating Rate 3-month BA + 0.35%) due 2019	125	100.00	125,000,000.00
Series 31 (Floating Rate 3-month BA + 0.35%) due 2019	50	100.048	50,024,000.00
Series 31 (Floating Rate 3-month BA + 0.35%) due 2019	53	100.046	53,024,380.00
Series 32 Notes (4.17%) due 2044	350	99.898	349,643,000.00

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, 2014, 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, 2014.

Name and Municipality of Residence	Principal Occupation
Sandra Pupatello (6)	Chair of the Board of Directors of
Windsor, Ontario	Hydro One Inc.
Canada
(Director since November 20, 2013,	Director of Business Development and
Chair of the Board since April 1, 2014)	Global Markets,
	PricewaterhouseCoopers, Canada
	Chief Executive Officer,
	WindsorEssex Economic
	Development Corporation
Kathryn A. Bouey (2) (5) 6)	President,
Toronto, Ontario	TBG Strategic Services Inc.
Canada	Corporate Director
(Director since March 30, 2007)
George Cooke (1) (2) (6)	President,
Toronto, Ontario	Martello Associates Consulting
Canada
(Director since January 25, 2010)	Chair of the Board of Directors of
	OMERS Administration Corporation
Sally Daub (1) (3)	President and Chief Executive Officer,
Toronto, Ontario	ViXS Systems Inc.
Canada
(Director since April 25, 2014)
Catherine Karakatsanis (3) (4) (5)	Chief Operating Officer,
Toronto, Ontario	Morrison Hershfield Group Inc.
Canada
(Director since November 27, 2013)
William Limbrick (2) (5)	Corporate Director
Georgetown, Ontario
Canada
(Director since April 11, 2014)

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Don MacKinnon (1) (3) (4)	President,
Chatsworth, Ontario	Power Workers’ Union
Canada
(Director since June 11, 2002)
Carmine Marcello (6)	President and Chief Executive Officer,
Thornhill, Ontario	Hydro One Inc.
Canada
(Director since January 1, 2013)
Tom Moss (4) (5)	Corporate Director
Nepean, Ontario
Canada
(Director since April 11, 2014)
Yezdi Pavri (1) (2) (6)	Corporate Director
Toronto, Ontario
Canada
(Director since December 6, 2012)
Gale Rubenstein (2) (3) (4) (6)	Partner, Goodmans LLP
Toronto, Ontario
Canada
(Director since March 30, 2007)
Maureen Sabia (1) (5)	Non-Executive Chairman of the Board of
Toronto, Ontario	Directors of Canadian Tire Corporation Limited
Canada
(Director since April 25, 2014)
John Wiersma (4) (5)	Corporate Director
Wasaga Beach, Ontario
Canada
(Director since April 11, 2014)
Carole Workman (1) (3)	Corporate Director
Orleans, Ontario
Canada
(Director since April 25, 2014)

(1) Member of the Audit, Finance and Pension Investment Committee

(2) Member of the Corporate Governance and Human Resources Committee

(3) Member of the Regulatory and Public Policy Committee

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

(5) Member of the Business Transformation Committee

(6) Member of the Strategy Committee

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SANDRA PUPATELLO Chair Sandra Pupatello was appointed Chair of the Board of Directors of Hydro One Inc. on April 1, 2014. Ms. Pupatello is also 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, appointed to Cabinet in 2003. Between 2003 and 2011, she held several portfolios, including Minister of Community and Social Services, Minister of Education, and spent 6 years as Minister of Economic Development and Trade. Ms. Pupatello held a host of volunteer positions in her hometown of Windsor, Ontario including the Board of Windsor Regional Hospital and Windsor Regional Children’s Centre. She holds a Hon. Bachelor of Arts and Honourary Doctor of Laws degree from the University of Windsor. Ms. Pupatello has been a Director of our company since November 20, 2013.

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 L. 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 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

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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.

    SALLY DAUB Director Sally Daub is a director of ViXS Systems Inc. (“ViXS”), a leading semiconductor company headquartered in Toronto, Ontario, and served as the President and Chief Executive Officer of ViXS from 2001 until February 2015. Having taken the company public on the TSX in July 2013, Ms. Daub has consistently been recognized for her entrepreneurial and business expertise, including: Women’s Executive Network: Canada’s Most Powerful Women: Top 100; RBC Women of Influence, Trailblazer Category; and PROFIT Magazine’s Top 100 Women Entrepreneur. Trained as a chemical engineer and lawyer, with degrees from University of Ottawa and Dalhousie respectively, Ms. Daub began her career as a patent attorney both at the law firm of Smart & Biggar and Nortel Networks, where she specialized in IP licensing, strategy, development and management. Directly prior to joining ViXS, Ms. Daub served as Vice President and Chief Legal Counsel for ATI Technologies, a graphics chips supplier. Ms. Daub is also a registered patent agent in both Canada and the United States. Previously she has also served as Chair of the Small Business Agency of Ontario (part of what is now the Ontario Ministry of Economic Development, Trade and Employment) and as a board member of the Information Technology Association of Canada and the Global Semiconductor Association. Ms. Daub has been a Director of our company since April 25, 2014.

    CATHERINE KARAKATSANIS
Director Catherine Karakatsanis is the Chief Operating Officer and board member of Morrison Hershfield Group Inc., a consulting engineering and management firm with offices across North America. Ms. Karakatsanis has had a progressive career at Morrison Hershfield moving successfully through a series of engineering and senior management positions before becoming COO in 2012. Throughout her career, Ms. Karakatsanis has been active within the engineering profession, having served as President and Chair of Engineers Canada, representing the 250,000 Professional Engineers in Canada, President and Chair of both of Ontario’s licensure and advocacy engineering bodies, and was a member of the board of the Canadian Engineering Memorial Foundation and the Foundation for Education. Ms. Karakatsanis currently also sits on the boards of Engineers Without Borders, Western Engineering and the Hellenic Heritage Foundation. Ms. Karakatsanis has consistently been recognized for her business and engineering contributions including having been inducted into The Canadian Academy of Engineering as a Fellow; awarded the Engineering Medal of Management; been named one of Canada’s Most Powerful Women: Top 100 in both the Professional and Corporate Governance categories; and was also recently awarded Ontario Women’s Directorate – Leading Women Building Communities Award, among others. She is a member of a number of professional organizations, including Professional Engineers Ontario, The Ontario Society of Professional Engineers, Consulting Engineers Ontario, and Geologists and

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Geophysicists of Alberta and has authored more than a dozen papers. 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.

 
WILLIAM LIMBRICK Director William Limbrick was the Vice President of Information and Technology Services, and Chief Information Officer of the Independent Electricity System Operator (IESO). The IESO’s Information and Technology Services business unit is responsible for information technology, organizational governance, and oversight of the Smart Metering Entity. Mr. Limbrick’s role also included the introduction of the provincial smart metering database, the MDM/R. Prior to joining the IESO, Mr. Limbrick was a Principal Consultant within the utilities practice of PricewaterhouseCoopers (PwC) and Sun Life Assurance in the United Kingdom. As a PwC Principal Consultant, he worked with the IESO to implement the IESO-administered market and in 1998 as overall program manager; he previously worked on the expansion of the competitive electricity market in the UK. He obtained a degree in Mathematical Economics from the University of Essex. Mr. Limbrick has been a Director of our company since April 11, 2014.

 
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. Mr. MacKinnon is a member of the Board of Plug’n Drive Ontario and a member of the Board Advisory Council of the Waterloo Institute for Sustainable Energy (WISE), University of Waterloo. Most recently, he became a member of the Advisory Board of the Ivey Energy Policy and Management Centre. Mr. MacKinnon has been a Director of our company since June 11, 2002.

 
CARMINE MARCELLO President and CEO 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,

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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 was inducted as a Fellow of the Canadian Academy of Engineering in 2014. 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.

 
TOM MOSS Director Tom Moss is the former President and Chief Operating Officer of Telecom Ottawa. An executive with over 35 years’ experience in the telecommunications, software and government sectors, both in Canada and the United States, Mr. Moss has held senior executive positions with high profile public and private companies together with two local start-up companies. He has held strategic policy positions in the federal government at Treasury Board and Industry Canada (formerly Communications). Mr. Moss has served on the Queensway Carleton Hospital Board of Directors since June 2008 and is the Vice-Chairman of the Barrhaven Business Improvement Area. Mr. Moss has been a Director of our company since April 11, 2014.

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 the immediate past Chairman of the Board of Trustees of United Way Toronto and also served as the Treasurer of the Board of the Toronto Region Immigrant Employment Council. He was recently appointed as the Chairman of the Board of the Canada – India Business Council. He has been a Director of our company since December 6, 2012.

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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.

MAUREEN SABIA Director Maureen Sabia is the Non-Executive Chairman of the Board of Directors of the Canadian Tire Corporation (March 8, 2007 – present), and President, Maureen Sabia International Inc., a consulting firm. Miss Sabia is also a director of Canadian Tire Bank where she serves on its Audit Committee and immediate past Chairman of the Foreign Affairs and International Trade Canada Departmental Audit Committee. Miss Sabia co-authored “Integrity in the Spotlight – Opportunities for Audit Committees” published in 2002, and “Integrity in the Spotlight – Audit Committees in a High Risk World” published in 2005. Miss Sabia was a member of the Board of Trustees of Brock University where she also served as Chairman of its Audit Committee, until mid 2014 and is a member of the Leadership Council of the Perimeter Institute. Miss Sabia is a lawyer and has had careers in the public and private sectors and served as the Chairman of the Export Development Corporation. She is past Chairman of the Audit Committee of Canadian Tire Corporation and immediate past Vice-Chairman of the Public Accountants Council for the Province of Ontario. Miss Sabia was formerly a director of Gulf Canada Resources Limited, Hollinger Inc., Laurentian General Insurance Company Inc., O & Y FPT Inc., O & Y Properties Corporation and Skyjack Inc. She has been a member of the Board of Governors of the University of Guelph, Chairman of the Sunnybrook Medical Centre Foundation and a member of the Board of Trustees for Sunnybrook Medical Centre. In 2011, Miss Sabia was appointed an Officer of the Order of Canada. She holds a J.D. from the Faculty of Law of the University of Toronto, an Honours Bachelor of Arts from McGill University, and has been awarded two honorary LL.Ds. She is an Officer of the Order of Canada. She has been a Director of our company since April 25, 2014.

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JOHN WIERSMA Director John Wiersma, P.Eng. is an electrical engineer and is the former and founding President and CEO of Veridian Corporation (1999-2004). Following Mr. Wiersma’s retirement from Veridian in 2004, he served as the Chairman of Veridian’s Board of Directors from January 29, 2004 to May 20, 2005. In 2004, Mr. Wiersma was appointed as a member of the Electrical Safety Authority (Ontario) where he served as a director until 2013 and as Chair of the Board from 2007 until 2013. In 2005, Mr. Wiersma was appointed as a member of the Independent Electricity System Operator’s (IESO) Board of Directors where he served as a director until April 3, 2014. He also served on the Board of the Electrical and Utilities Safety Association and the Canadian Energy Efficiency Alliance. He is a Past President of the Ajax Pickering Board of Trade, Past Chair of the Rouge Valley Health System Foundation and a former board member of the Rouge Valley Health System. Mr. Wiersma obtained his Bachelor of Engineering from McMaster University. He has been a Director of our company since April 11, 2014.

CAROLE WORKMAN Director

Carole Workman is a Chartered Professional Accountant (Chartered Accountant). She is a member of the Board of Allstate Insurance of Canada and is Chair of their Audit Committee and Compliance Committee. She is a member of The Ottawa Hospital Board of Directors, Past Chair of the Board, and a member of their Audit and Finance Committee. She served 7 years as a member of Hydro Ottawa, chaired the wholly owned Local Distribution Company Board and served as a member of the Audit Committee. She was also a member and Chair of the Canadian University Insurance Exchange Reciprocal for many years. She had a long career in executive and financial management and served the University of Ottawa for 24 years as its Chief Financial Officer and Vice President, Finance & Administration until her retirement in 2004. Ms. Workman has a B. Commerce and a Masters of Public Administration and completed the Harvard International Management Program. She has been a Director of our company since April 25, 2014.

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

Information Regarding Certain Directors

Tom Moss was a director and President of 6495478 Canada Inc. when it declared bankruptcy on December 17, 2007.

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Executive Officers

The following table sets forth the name, municipality of residence and position of each of our executive officers as of December 31, 2014.

Name and Municipality of Residence	Position With Our Company
Sandra Pupatello	Chair of the Board of Directors of
Windsor, Ontario	Hydro One Inc.
Canada
Carmine Marcello	President and Chief Executive Officer
Thornhill, Ontario
Canada
Sandy Struthers	Chief Operating Officer and Executive
Toronto, Ontario	Vice President, Strategic Planning
Canada
Ali Suleman	Chief Financial Officer (Acting)
Toronto, Ontario
Canada

Sandra Pupatello biographical information is presented above under “Directors”.

Carmine Marcello’s biographical information is presented above under “Directors”.

Sandy Struthers was appointed as Chief Operating Officer and Executive Vice President, Strategic Planning effective November 17, 2014. Prior to this, Mr. Struthers was Chief Administration Officer 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, Senior Vice President and Chief Financial Officer in 2009, and then was appointed Executive Vice President and Chief Financial Officer in 2010. Prior to joining Hydro One, Mr. Struthers was a partner in a national accounting firm.

Ali Suleman was appointed as Chief Financial Officer (Acting) effective November 17, 2014. Prior to this, Mr. Suleman served as Vice President and Treasurer from 2004, and as Treasurer from

1999. Mr. Suleman joined Ontario Hydro in 1991 as Treasury Analyst. In 1994, Mr. Suleman worked with Manulife Financial as Manager, Corporate Finance before rejoining Ontario Hydro in 1995 as Manager, Debt. Prior to joining Ontario Hydro in 1991, Mr. Suleman worked in the municipal bond area in New York City.

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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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 corporate 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 corporate subsidiaries is, in turn, wholly owned (directly or indirectly) by us. However, pursuant to the Electricity Act, we and each of our corporate 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.

One of our subsidiaries is a limited partnership, which we control through our sole ownership of

its corporate general partner. The partnership, because of its nature, is treated as a flow through entity for income tax and proxy tax purposes. As such, the partnership is not required to pay amounts to OEFC under the Electricity Act.

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 offshoring of jobs under the 2001 Inergi Agreement. The declaration allows the Province to assume all decision-making power in respect of the offshoring of jobs under the 2001 Inergi Agreement and removes these powers from the Board. The

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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 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 2001 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.

Effective December 17, 2014, the Province made a further declaration pursuant to the memorandum of agreement and section 108 of the Business Corporations Act (Ontario) regarding the provision of information, personnel and resources to the Premier’s Advisory Council on Government Assets. By way of the declaration and concurrent shareholder resolution, the Province restricted the rights, powers and duties of our Board, and at the same time assumed such rights, powers and duties, with respect to providing the Council, the Government or the Ministries and their advisors and consultants all information, assistance, personnel, resources and reports as and when requested and co-operating with those Government advisors tasked with providing recommendations on labour relations matters and pension-related matters. The directors are charged with carrying out the intention of the declaration and resolution, including taking such necessary steps to issue similar declarations and resolutions with respect to Hydro One Networks Inc. and Hydro One Brampton Networks Inc.

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 on SEDAR at www.sedar.com.

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TRUSTEES AND REGISTRARS

TRUSTEES AND REGISTRARS

The trustee and registrar for our company’s debt securities is Computershare Trust Company of Canada, located in Toronto, Ontario. The U.S. trustee and registrar for certain of our company’s debt securities is 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)	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;
(xi)	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;
(xii)	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;
(xiii)	a twenty-second supplemental trust indenture dated as of July 29, 2011 amending the definition of “Canadian GAAP” in the Trust Indenture;
(xiv)	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;
(xv)	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;
(xvi)	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;
(xvii)	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;
(xviii)	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;
(xix)	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 was drawn down on October 9, 2013, pursuant to the Trust Indenture;
(xx)	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;

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(xxi)	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;
(xxii)	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, $50,000,000 was drawn down on May 14, 2014, and $53,000,000 was drawn down on June 24, 2014, pursuant to the Trust Indenture; and
(xxiii)	a thirty-second supplemental trust indenture dated as of June 6, 2014 relating to the issuance of Series 32 Notes in the aggregate principal amount of $1,000,000,000 of which $350,000,000 was drawn down on June 6, 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 SEDAR at www.sedar.com.

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INTERESTS OF EXPERTS

KPMG LLP

For the year ended December 31, 2014, 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., HOPF-PEP Investments Ltd. and HOPF-INN Investments Ltd.

KPMG LLP is independent in Canada in accordance with its rules of professional conduct.

Towers Watson

Towers Watson provides the following services to our company:

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

(b) tri-annual funding actuarial valuation (last valuation completed as of December 31, 2013, next scheduled no later than as of December 31, 2016); and

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

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ADDITIONAL INFORMATION

ADDITIONAL INFORMATION

Additional Information about Hydro One is available on SEDAR (“System for Electronic Document Analysis and Retrieval”) at www.sedar.com.

As our sole shareholder is the Province, we are not required to prepare an information circular. Additional financial information is contained in our audited consolidated financial statements, together with the auditors’ report thereon, and our Management’s Discussion and Analysis for our most recently completed fiscal year, each of which may be found on SEDAR at www.sedar.com.

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STATEMENT OF EXECUTIVE COMPENSATION

STATEMENT OF EXECUTIVE COMPENSATION

Compensation Discussion and Analysis

Overview

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

Hydro One’s executive compensation program is designed:

— to attract, motivate and retain executives with the skills necessary to sustain and develop a safe, reliable, and 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.

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. In 2014, the compensation study performed by the Hay Group Limited on

Hydro One’s behalf showed that target total compensation for senior executives is falling below the 50th percentile of the comparator group as a result of compensation restraint measures.

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 2014, 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. In December 2014, Bill 8, An Act to Promote Public Sector and MPP Accountability and

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Transparency by Enacting the Broader Public Sector Executive Compensation Act, 2014 and Amending Various Acts, was passed. Schedule 1 to Bill 8 is the Broader Public Sector Executive Compensation Act, 2014, which will come into force when it is proclaimed. Under the Broader Public Sector Executive Compensation Act, 2014, the government will have the authority to create comprehensive compensation frameworks for certain employers in the broader public sector, including our company, and the authority to

implement a number of measures to enhance accountability and transparency in the government and the public sector. The legislation applies to certain defined, designated executives, primarily senior management, at Hydro One. Until such time as this new legislation is proclaimed, Hydro One must continue to comply with the BPSAA with respect to compensation as it affects designated executives.

The NEOs of Hydro One for 2014 were:

Name	Title
Carmine Marcello	President and Chief Executive Officer
Ali Suleman1	Chief Financial Officer (Acting)
Sandy Struthers2	Chief Operating Officer and     Executive Vice President Strategic     Planning
Wayne Smith	Senior Vice President, Operations
Robert Cultraro	Senior Vice President and Chief     Investment     and Pension Officer
Joseph Agostino	Senior Vice President, General Counsel     and Chief Compliance Officer

(1) Vice President and Treasurer to November 16, 2014 and Chief Financial Officer (Acting) from and after November 17, 2014

(2) Chief Administration Officer and Chief Financial Officer to November 16, 2014 and Chief Operating Officer and Executive Vice President, Strategic Planning from and after November 17, 2014

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Governance

The Corporate Governance and Human Resources Committee of the Hydro One Board of Directors (the “CGHRC”) is comprised entirely of independent directors within the meaning of Canadian securities laws. As part of its mandate, the CGHRC 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 CGHRC 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 CGHRC’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 CGHRC’s decision;

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

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

As well, the CGHRC:

— annually reviews the performance agreements of the direct reports to the President and Chief Executive Officer;

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

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

Composition of the CGHRC

As at December 31, 2014, the members of our CGHRC were Gale Rubenstein, Kathryn Bouey, George Cooke, Yezdi Pavri and William Limbrick. Members of the CGHRC have been selected and appointed to the CGHRC 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 CGHRC are appointed by the Board, upon recommendation of the Chair, and management has no role in the selection of the committee members.

Committee Members Relevant and Direct Experience

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 CGHRC (formerly the Human Resources Committee) since December 9, 2010. Ms. Rubenstein was appointed Chair of the CGHRC on May 6, 2014. 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

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approved by the court in cases of insolvency and corporate reorganization transactions.

Kathryn Bouey has been a member of the Hydro One Board of Directors since March 30, 2007 and has been a member of CGHRC since May 6, 2014. She was previously a member of the Human Resources Committee from April 5, 2007 to December 9, 2010 and served on the Investment Pension Committee from December 12, 2013 to May 6, 2014. As such she is familiar with the compensation practices of Hydro One. Her background includes extensive work while employed by the Ontario government on compensation and pension matters, including as Deputy Minister of Management Board Secretariat and Chair of the Civil Service Commission. She was also a member of the Board of Directors of the Ontario Pension Board. She completed the Directors Education Program offered by Institute of Corporate Directors and Rotman School of Business and has been an Institute Certified Director since 2006. She has also attended a number of educational sessions on compensation and pensions.

George Cooke has been a member of the Hydro One Board of Directors since January 26, 2010. He was appointed to the CGHRC on May 6, 2014. Mr. Cooke was a director of Atomic Energy of Canada Limited from 1995 to 1999 and was a member of the Human Resources Committee of Atomic Energy of Canada Limited. While President and Chief Executive Officer of The Dominion of Canada General Insurance Company, the human resources function reported directly to Mr. Cooke. He is, in his role as Chair of the Board of Directors of OMERS Administration Corporation (one of Canada’s largest pension funds), an ex-officio member of its human resources committee. Mr. Cooke was a member of Hydro One’s Investment Pension Committee and now is Chair of the Audit,

Finance and Pension Investment Committee and is accordingly familiar with pension matters related to compensation. Mr. Cooke is cognizant of the compensation policies and practices at Hydro One.

Yezdi Pavri has been a member of the Hydro One Board of Directors since December 6, 2012. Mr. Pavri was appointed to the CGHRC on May 6, 2014. He is a former Vice Chairman of Deloitte Canada and has also been the Managing Partner of its Toronto Practice, where he was responsible for the evaluation and compensation of the Partner Group. Since his retirement from Deloitte Canada in June 2012, Mr. Pavri has been appointed to the Boards of ICICI Bank Canada and Enterra Holdings Limited (EHL), which is the holding company of Golder Associates. He is the Chair of the Audit Committee and a member of the Governance and Compensation Committee at ICICI Bank Canada, with oversight of senior management compensation. Mr. Pavri is also the Chair of the Finance & Audit Committee at EHL, a member of the EHL Risk Committee and also the Share Ownership Committee, which has oversight of the Employee Ownership model.

William Limbrick joined the Hydro One Board of Directors effective April 11, 2014. He was appointed to the CGHRC on May 6, 2014. Mr. Limbrick was the Vice President of Information and Technology Services and Chief Information Officer at the IESO from 2001 to February 2014. Prior to joining the IESO, he was a member of the utilities practices with PwC in the United Kingdom where he held a number of increasingly senior positions. At the IESO, in the last four years of his service there, Mr. Limbrick was responsible for human resources matters including supporting the Human Resources Committee of the IESO board of directors. In that capacity, he made recommendations on compensation matters and

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was involved in union matters and negotiations. Additionally, Mr. Limbrick was a member of the IESO Pension Committee.

Compensation Policies and Practices Aligned to Risk Management

The Board 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 CGHRC, 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 CGHRC 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 into 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 recommended to the Board for approval by the CGHRC;

— annual incentive funding is determined on a collective basis – the CGHRC assesses the overall annual performance against the

measures and targets in the corporate scorecard and determines its recommendation to the Board 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 CGHRC 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 CGHRC, prior to the review and assessment by the CGHRC;

— 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 payments for the NEOs are at-risk and not guaranteed; performance of the NEOs is reviewed and assessed by the CGHRC 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%

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

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

Independent Consultant for the CGHRC

In 2014, the CGHRC, retained Hugessen Consulting Inc., an independent consulting firm that provides advice to boards and compensation committees on executive compensation, to provide the CGHRC with consulting services to support the creation and approval of Hydro One’s scorecard and on the year end scorecard results. In 2013, Hugessen Consulting Inc. also provided to the former Human Resources Committee consulting services 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 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
2014	$33,845.35	$0
2013	$25,917.41	$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 2014, the CGHRC 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 CGHRC 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. Eight of these entities are not reportable segments of their reporting parent and therefore financial information was not available. However, these eight companies do form part of the Hay Group Limited compensation information pool. Of the 22 entities in the comparator group with publicly available financial information, approximately 63.6% are smaller in size when compared to Hydro One, based on both revenues and assets, according to their most recent publicly available annual financial statements.

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The list of comparator group companies is as follows:

Public Sector	Private Sector
Atomic Energy of Canada Limited	ArcelorMittal Canada
Business Development Bank of Canada	Amec Americas Limited
Canada Mortgage and Housing Corporation	Barrick Gold Corporation
Canadian Standards Association/CSA Group	Bombardier Transportation Canada Inc.
Enersource Hydro Mississauga Inc.	Bruce Power LP
Farm Credit Canada	Canadian National Railway Company
Government of Ontario	Fortis Inc.
Hydro Ottawa Limited	FortisBC Energy Inc.
NB Power Holding Corporation	Glencore
Ontario Power Authority	Goldcorp Inc.
Ontario Power Generation	Newfoundland Power Inc.
Royal Canadian Mint	Siemens Canada Limited
SaskEnergy Incorporated	Suncor Energy Inc.
Sask Tel	Ultramar Ltée
Toronto Hydro	Vale Canada
Total 15	Total 15

(1) Base Salary

Base (annual) salary is intended to compensate the NEOs for day-to-day, ongoing performance. The Board 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 Board 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 2014, the roles,

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accountabilities and responsibilities of certain of the NEOs were increased due to an organizational restructuring 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, 2013 or 2014.

(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. 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 CGHRC 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 CGHRC and approved by the Board.

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, 2014, 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. Smith, Mr. Cultraro and Mr. Agostino. For Mr. Suleman, as he is in an acting role, the range for him remained at his previous range of between 0% and 40% of base salary. The range for Mr. Marcello was set by the former Human Resources Committee 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 former Human Resources Committee and approved by the Board in 2006 and it has not changed since then.

There are two components to performance-based compensation for all management employees, including the 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 Board, based on a recommendation by the CGHRC. 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 2014, the maximum percentage of funds available for allocation for all management employees (including the NEOs) was set at 65% of this total potential payout. This determination was made by the CGHRC, and recommended to, and approved

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by, the Board, by measuring the company’s performance at the end of the year against various corporate performance targets and measures set at the beginning of the year.

Fund Allocation: The fund is allocated among individual executives on the basis of individual performance. It is not an across the board allocation. NEOs are assessed against their performance agreement based on objective and subjective assessments. The CGHRC conducted and approved the assessment of the President and Chief Executive Officer, and approved the assessments and recommendations regarding the Chief Operating Officer and Executive Vice President, Strategic Planning (including his role during the year as Chief Administration Officer and Chief Financial Officer), the Chief Financial Officer (Acting) (including his role during the year as Vice President and Treasurer), the Senior Vice President, Operations, the Senior Vice President and Chief Investment and Pension Officer and the Senior Vice President, General Counsel and Chief Compliance 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 CGHRC, 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 2014, the corporate performance measures were tied to Hydro One’s corporate strategy which was updated in 2014. See “About Hydro One – Our Strategy” for additional information. Management and the CGHRC 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 2014, the CGHRC determined that Hydro One should focus on four strategic objectives and 14 performance measures and targets aligned to such objectives. The CGHRC then recommended the measures and targets to the full Board for approval. These measures and targets were based on Hydro One’s key strategic goals in the areas of (i) injury-free workplace, (ii) satisfying our customers, (iii) continuous improvement and cost effectiveness in the building and maintaining reliable transmission and distribution systems and (iv) maintaining a commercial culture that increases shareholder value.

The following table sets out Hydro One’s corporate performance measures for 2014, which were aligned to its strategic objectives and the targets for each of those measures. In 2014, the Board determined that, with respect to the targets, Hydro One met or exceeded eight of the targets and six 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
Injury-free Workplace	Recordable Rate	ê	1.8	1.9
	(# of recordable injuries/illnesses per
	200,000 hours worked)
Satisfying Our Customers	Customer Satisfaction – Transmission	r	77	84
	(% satisfied)
	Customer Satisfaction - Distribution	r	85	87
	(% satisfied)
	Connection of New Services -   Distribution	ê	97	90
	(% completed in < 5 days)
	Unscheduled Estimated Bills	ê	1.2	1.8
	(% of total bills issued)
	No Bill Volume	ê	2.6	8.0
	(number of customers) (thousand)
Continuous Improvement  & Cost Effectiveness in the Building and Maintaining Reliable Transmission and Distribution Systems	Transmission Unit Costs	ê	2.7	2.9
	(OM&A/Gross Fixed Assets) (%)
	Distribution Unit Costs	r	6.1	5.7
	(OM&A/Gross Fixed Assets) (%)
	Customer Interruption Duration -   Transmission	r	11.8	8.9
	(minutes per delivery point)
	Customer Interruption Duration -   Distribution	r	7.4	6.7
	(hours per customer)
Maintaining a Commercial Culture that Increases Shareholder Value	Net Income After Tax ($M)	ê	749	668
	Customer Service Recovery Cost ($M)	r	88.3	47.8
	In-Service Capital – Transmission (% of   Plan)	ê	99	85
	In-Service Capital – Distribution (% of   Plan)	ê	97	87

  Legend  ê  Better than plan (³5%)   — On Plan  r Below Plan

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The 2014 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 CGHRC 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, challenges and shortfalls 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 CGHRC, but subject to the ultimate discretion of the Board. If, on balance, scorecard performance is not met, the CGHRC will determine and recommend a funding level, also subject to the ultimate discretion of the Board. In 2014, the Board 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 65% of the maximum short term incentive fund. In accordance with the BPSAA, the funding envelope for the short term incentive for 2014 cannot exceed the amount that was paid in aggregate in the performance pay cycle for 2011. In setting the funding level at 65% for 2014, Hydro One has complied with this requirement.

1. Injury-Free Workplace

The safety of our employees is paramount. For 2014, Hydro One used the measure of all work-related injuries or illnesses as the performance

measure for this strategic objective. A “recordable” injury/illness is one of the following: medical attention (treatment beyond first aid); modified work (restricted duties); lost time; or death. For 2014, the Board set the target at 1.9 recordable injuries per 200,000 hours worked for this measure. Hydro One exceeded this target.

2. Satisfying our Customers

In 2014, Hydro One approached the objective of customer satisfaction by addressing five measures related to improving customer relations. These measures relate to transmission and distribution customer satisfaction and connection of new services, as well as estimated bills and no bill volume, as part of our customer service recovery project. Our customer service recovery project was a result of billing issues Hydro One encountered due to the implementation in May of 2013 of its new customer information system.

a) Customer Satisfaction – Transmission

This measure is to determine the degree to which our transmission customers are satisfied with the service they receive from our company. It is based on survey results of customer surveys conducted on Hydro One’s behalf by independent third parties. The survey is given to three major groups of transmission customers. In 2014, we targeted a transmission customer satisfaction rate of 84%. We did not meet this target.

b) Customer Satisfaction – Distribution

Similar to the transmission customers, Hydro One surveys its distribution customers to assess the degree to which they are satisfied with the service they receive from Hydro One. The results arise from surveys conducted on Hydro One’s behalf by independent third parties. This measure reflects the overall satisfaction levels of three major distribution customer segments, based on transaction satisfaction levels, annual satisfaction

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surveys and the meeting of OEB milestones respectively for the three segments. For 2014, Hydro One set a target for distribution customer satisfaction at 87%, and did well on the transactional elements but did not meet this target on an overall basis.

c) Connection of New Customers

This measure relates to distribution low voltage connections that are reported annually to the OEB. It addresses our customers’ needs for a specific and timely connection date and assesses our efficiency in connecting new customers. It measures the percentage of connections for a requested new service (<750 volts). The connection must be completed within 5 business days from the day on which all applicable service conditions are satisfied, or at a later date agreed upon by the customer and Hydro One. Hydro One set a 2014 target of 90%, which it exceeded.

d) Unscheduled Estimated Bills

With respect to this measure, Hydro One seeks to track its ability to provide accurate bills to its customers. It tracks the percentage of total customers that have received unscheduled estimates in any billing period. Hydro One established a target of 1.8% of all bills for this measure. We exceeded the target.

e) No Bill Volume

No Bill Volume is a customer service measure related to the Company’s ability to provide timely bills to its customers. This measure tracks the number of customers who have not received a bill in three consecutive billing periods. Our expectation was to reach a volume of 8,000 no-bill customers by September 2014, and sustain this level beyond that date. Hydro One exceeded this target.

3. Continuous Improvement and Cost Effectiveness

As part of our strategic objectives to increase productivity through efficiency improvements and effective management of costs, Hydro One measures transmission unit cost and distribution unit cost and set targets for those costs. Regarding the maintenance and reliability of the transmission and distribution systems, Hydro One continues to build and retain public confidence and trust in its operations, as stewards of Ontario’s electricity grid. In 2014, 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.

a) Transmission Unit Costs

For 2014, the transmission unit cost measure shows the transmission business cost-effectiveness by comparing the ratio of OM&A spending to gross fixed asset costs, using benchmarking initiatives. Hydro One set a target of 2.9% for 2014, and exceeded the target.

b) Distribution Unit Costs

Similar to transmission unit cost, the distribution unit cost measure demonstrated the distribution cost-effectiveness by comparing the ratio of OM&A spending to gross fixed assets costs, using benchmarking initiatives. For 2014, Hydro One set a target of 5.7%, but did not meet this target.

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c) Customer Interruption Duration – Transmission

This measure monitors the reliability of the transmission system by tracking the average length of unplanned interruptions (in minutes) to multiple-circuit supplied delivery points. Hydro One has set a target of 8.9 minutes per delivery point for 2014. During 2014, Hydro One was aware that it would miss the target, which was not indicative of degrading reliability, but rather a result of refurbishing aging assets. In doing so, this resulted in occasions where load with a multi-circuit supply was placed on single supply to accommodate the work program. This exposed the system to interruptions if there was a loss of the single supply. Hydro One determined that it was important to continue with the maintenance program even if this would result in missing the target. Hydro One, in fact, did not meet this target.

d) Customer Interruption Duration – Distribution

This measure is an indicator of the distribution system reliability that expresses the average length of outages in hours that a customer can expect to experience in the year. This measure excludes force majeure events and loss of supply events (events caused by transmission system or other distributors). Hydro One set a target of 6.7 hours per customer for this measure. In 2014, there were numerous storm events which were not considered force majeure events and comparatively more equipment outages that resulted in higher than normal customer interruptions. In the circumstances, we did not meet this target.

4. Maintaining a Commercial Culture

a) Net Income

Achievement of strong financial performance is measured by a performance measure of targeted level of net income after tax. Our target was

$668 million net income after tax for 2014 and we exceeded our target.

b) Customer Service Recovery Cost

As a result of billing issues that arose from the implementation of our new customer information system in 2013, the effects of which became acute in early 2014, Hydro One established the customer service recovery project to dedicate staff to resolve outstanding and any new billing issues and stabilize the billing system. Hydro One anticipated, and fixed as a target, costs of $47.8 million (including revenue impacts) for this project. The project was completed in 2014 and the customer information system is now in sustainment mode. As the costs of the customer service recovery project exceeded the target, Hydro One did not meet this anticipated target.

c) In-Service Capital – Transmission

This new measure for 2014 evaluates how Hydro One is meeting its OEB targets for in-service capital. For our transmission business, the 2014 target of 85% of in-service capital to our business plan is based on historical performance, our increasing capital work program and the additional variability caused by external commitments and required approvals. Our 2014 result shows that Hydro One exceeded the target.

d) In-Service Capital – Distribution

For our distribution business, Hydro One set the 2014 target of 87% of in-service capital to our business plan based on historical performance, with adjustments, to reflect that our distribution business has more storm-related capital spending than our transmission business, as well as the performance of our smart meter and distributed generation capital work programs. Our 2014 result was better than the target.

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Overall Performance for 2014

For 2014, the CGHRC determined that of the 14 targets, eight were exceeded and six were not met. In determining its recommendation to the Board on the funding for the short term incentive, the CGHRC deliberated at length on the work-related fatality in late 2014 resulting from a motor vehicle collision. In setting the corporate scorecard for 2014, the Board had decided that a work related fatality in 2014 could reduce the short term incentive fund by 50%. However, the CGHRC, in considering some key accomplishments for 2014, noted Hydro One made significant progress in terms of meeting its strategic objective of an injury free workplace as evidenced by the results of the 2014 scorecard. The CGHRC, in making its recommendation to the Board, retained the discretion to consider other accomplishments and mitigating factors in setting the short term incentive fund. In considering some of the key accomplishments in 2014, the CGHRC noted Hydro One’s concerted and successful response, through the customer service recovery project, to the billing issues that arose from the Customer Information System, the signing of the historic SON agreement and its excellent in-service capital results. The CGHRC determined and recommended to the Board that the short term incentive fund be set at 65% of the maximum short term incentive payout. The Board considered the CGHRC’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 Hydro One, to accept the CGHRC’s recommendation and approved that the short term incentive fund be set at 65% of the maximum short term incentive payout. Accordingly, the funding at 65% of the maximum short term incentive payout was the available amount for distribution to management employees, including the NEOs.

(b) Individual Performance

The second component of determining the amount of short term incentive payments to be made to NEOs pursuant to the Incentive Plan is their individual performance. Individual target performance criteria are outlined in individual performance agreements which include both broad corporate and individual specific targets. NEOs are expected to align their efforts with and advance the corporate performance measures and targets discussed above. The NEOs were required to provide visible leadership to develop and maintain a safe and healthy workplace. 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, 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. These targets may be objective, numeric-based targets or more subjective targets. They 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

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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 CGHRC with respect to the NEOs other than the President and Chief Executive Officer and the CGHRC 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 50%) were: safety, customer, continuous improvement and cost effectiveness in the building and maintaining of reliable distribution and transmission system and maintaining a commercial culture that increases shareholder value. These quantitative targets were the same as and tied to achieving the Corporate Performance Measures and targets described above. The qualitative factors (overall total 50%) and key elements of these factors were: strategy (ongoing review of corporate strategy including identification of strategic opportunities), risk (to ensure the Board and management have a clear, timely and transparent view to known and emerging risks in order to apply appropriate mitigation), corporate reputation (to advance to Company’s objectives and capitalize on emerging opportunities in the market by establishing and maintaining effective and strategic relationships in the electricity sector and the broader public sector and private sector), succession planning (to

stabilize the executive organization structure), cultural transformation (to lead a cultural transformation that entrenches measurement, accountability and performance), customer (to improve customer relationships to establish Hydro One as an accountable, responsive, knowledgeable and trusted partner), major projects (meet in-year LTEP commitments related to transmission development by pursuing commercial opportunities, engaging First Nations in Hydro One projects and working to further industry consolidation) and leadership (to exhibit strong leadership to support achievement of Hydro One’s strategic objectives, including strengthening Hydro One’s brand).

Mr. Struthers was the Chief Administration Officer and Chief Financial Officer (CAO and CFO) until November 17, 2014 when he assumed the role of Chief Operating Officer and Executive Vice President, Strategic Planning. As CAO and CFO, he had targets comprised of quantitative and qualitative factors. The quantitative factors (overall total 70%) were as follows: injury-free workplace, satisfying our customers, building and maintaining reliable distribution and transmission systems, maintaining a commercial culture that increases shareholder value and continuous improvement and cost effectiveness. The qualitative factors (overall total 30%) were comprised of three key responsibilities: (i) strategic planning and key priorities (increase shareholder value; drive a culture of safety and performance; improve service to internal customers; improve corporate reputation; and leadership); (ii) service function objectives (treasury and risk (obtain cost-effective financing to support capital projects); financial reporting (integrate acquired LDCs into Hydro One’s financial system); pension (provide oversight on the plan’s performance); regulatory (support successful distribution and transmission rate applications); business planning (manage

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the five year business plan process); outsourcing (complete the process to select the proponent(s) to provide the outsourcing services); fleet (reconfirm current fleet strategy to manage fleet costs and meet operations support requirements); procurement (work with Hydro One’s engineering group to update standards and reduce contract extensions); and real estate (complete the facilities outsourcing)); (iii) management role (enhancing his and management’s relationship with the Board and help drive Hydro One’s culture in support of its core values).

Mr. Suleman, Mr. Smith, Mr. Cultraro and Mr. Agostino each entered into performance agreements that had three corporate focus areas: health and safety (to demonstrate commitment to the success of our Journey to Zero initiatives); customer (to manage the business and operations in a commercial manner the benefits the customer, the shareholder and Hydro One); and engagement (to create and sustain an environment where employees can be fully engaged). As well, they each had individual focus areas related to their specific areas of work. In each of these focus areas, these NEOs set out their specific initiatives for the focus area, their plans or measures to implement their initiatives and, how they would they would achieve their measures in accordance with our “Craft of Management” principles.

In 2014, the CGHRC and the Board assessed the performance of Mr. Marcello. As well, the CGHRC reviewed the assessment of the performance of the other NEOs, and other direct reports to the President and Chief Executive Officer, from which it made its own assessment. In making their assessments, the CGHRC and the Board paid particular attention to the corporate scorecard results and their assessments of these results and the personal performance and contributions of each of the NEOs to Hydro One throughout the year.

With respect to Mr. Marcello, the CGHRC and the Board gave significant weight to his strong personal performance and certain personal accomplishments, which include: improving the corporate reputation through the customer service recovery project; restructuring of the company as a result of the departure of several senior executives; achieving a significant cultural transformation as reflected in the injury-free target results; effectively managed several external reviews of Hydro One and delivered several high profile projects including the historic agreement with the Saugeen Ojibway Nation. On the basis of this assessment, Mr. Marcello was awarded a short term incentive payment of $290,000, which represents 85% of his maximum eligible award.

In its assessment of Mr. Struthers, who was the CAO and CFO until November 16, 2014, the CGHRC noted key accomplishments which include: active management of the KPMG upside opportunity assessment of Hydro One prepared on behalf of the Council; improved fleet safety in 2014; key performance indicators were developed for our outsourcing strategy; attended investor meetings to help raise cost effective debt; completed the outsourcing agreements for facilities and real estate and the services provided by Inergi; and his transition into his significant new role as Chief Operating Officer. Mr. Struthers’ accomplishments resulted in a short term incentive payment award of $180,000, which represents 69% of his maximum eligible award.

Regarding Mr. Suleman, who was the Vice President and Treasurer until November 16, 2014, the CGHRC considered the following accomplishments: obtained a cost effective insurance program; managed the risk assessment function; maintained contacts with investors and funds raised by way of debt with proper oversight; provided creative support to the Bruce to Milton limited partnership with the Saugeen Ojibway

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Nation and its successful closing; managed the treasury function strategically to obtain fair and reasonably priced debt issuances; and his successful assumption of the role of Chief Financial Officer (Acting). In recognition of this performance, Mr. Suleman was given a short term incentive payment of $75,000, which represents 69% of his maximum eligible award.

With respect to Mr. Smith, the CGHRC noted certain accomplishments: a 20% improvement in medical attention incidents in the business group for which he had oversight; the significantly increased volume of planned work completed and the reduction in the level of rework required on completed projects; the highest customer satisfaction rate to date for the OGCC in the transmission customer survey; exceeded service metric targets in the lines and forestry groups; led the company in cost savings in response to the customer service recovery project; and improved Hydro One’s investment review process. Mr. Smith was awarded a short term incentive payment of $125,000, which is 61% of his maximum eligible award.

Mr. Cultraro had a number of key accomplishments recognized by the CGHRC, including: good pension plan performance with returns well exceeding the going concern discount rate; astute tactical investment and rebalancing decisions were made during the year; strategic investment decisions during the year continued to provide long term benefits; beneficial decisions on obtaining an actuarial valuation at the most opportune time; and conducting an asset liability study to set the Hydro One pension fund’s asset mix and de-risking strategy for the long term. In recognition of these accomplishments, Mr. Cultraro received a short term incentive payment of $110,000, which is 73% of his maximum eligible award.

Regarding Mr. Agostino, the CGHRC considered accomplishments including his membership and contributions to the steering committee of the customer service recovery project; his assistance in responses to the Ombudsman’s investigation regarding billing issues; his contributions to the executive team in addressing matters for the Council and the Premier’s Secretariat to provide information to the Secretariat; his contributions to regulatory compliance and developing the overall compliance program; his continued spearheading and support for Hydro One’s records management program; and his contributions on key legal matters such as the outsourcing transactions and LDC acquisitions. Based on these accomplishments, Mr. Agostino was given a short term incentive payment of $80,000, which is 53% of his maximum eligible award.

The determination of Incentive Plan amounts for the NEOs is independent from the assessment of base salary adjustments. However, the final dollar amount of an annual Incentive Plan payment is impacted by any changes to base salary since it is a percentage of base salary.

(3) Benefits

In addition to the base salary and Incentive Plan compensation, as part of their compensation package, the NEOs also participate in the Hydro One registered pension plan and supplementary pension plan and participate in a flexible benefits plan, which is available to all other management employees. The flexible benefits plan provides various benefits, including life insurance, vacation and health care benefits. Hydro One provides to each executive and management employee certain core benefits, which include basic life insurance, 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

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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. Cultraro, 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. Cultraro, 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. Cultraro’s benefits and pension benefits differ from those of the other NEOs as Mr. Cultraro became an employee of Hydro One after January 1, 2004 and his benefits and pension benefits are in accordance with the reduced benefits for management employees who became employees of Hydro One after January 1, 2004.

Role of NEOs in Determining Executive Compensation

An NEO does not play any part in determining his or her own compensation. The Senior Vice-President, People and Culture/Health, Safety and Environment, working with the Hay Group Limited, is responsible for providing recommendations regarding compensation to the CGHRC consistent with the Board approved compensation strategy. The CGHRC 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 CGHRC reviews, discusses and makes a recommendation to the Board, who must consider, discuss and ultimately approve the final compensation level for the President and Chief Executive Officer. In 2014, in addition to the above recommendations, the CGHRC and the Board considered the requirements of the BPSAA in determining the base salary and Incentive Plan payments for all the NEOs for 2014.

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SUMMARY COMPENSATION TABLE

The following table summarizes the compensation paid in 2014, 2013 and 2012 to the Chief Executive Officer, each individual who served as Chief Financial Officer and to each of the three other most highly paid officers in 2014.

Name and	Year	Salary	Non-equity incentive plan				Pension	All Other		Total
Principal		($)	compensation ($)				Value 7	Compensation		Compensation
Position			Annual		Long-term		($)	($)		($)
			incentive		incentive
			plans1		plans
C. Marcello2	2014	$525,000		$290,000		$0	$411,000		$0		$1,226,000
President &	2013	$525,000		$170,625		$0	$2,889,000		$0		$3,584,625
CEO	2012	$300,000		$156,000		$0	($13,000)		$0		$443,000
A. Suleman3	2014	$248,100		$75,000		$0	$100,000		$0		$423,100
CFO	2013	$244,615		$71,000		$0	$5,000		$0		$320,615
	2012	$244,615		$93,000		$0	$29,000		$0		$366,615
S. Struthers4	2014	$366,430		$180,000		$0	$266,000		$0		$812,430
COO	2013	$375,000		$135,000		$0	$324,000		$0		$834,000
	2012	$325,000		$169,000		$0	$38,000		$0		$532,000
W. Smith5	2014	$313,576		$125,000		$0	$101,000		$0		$539,576
Senior Vice	2013	$274,050		$125,000		$0	($6,000)		$0		$393,050
President,	2012	$274,050		$150,000		$0	$16,000		$0		$440,050
Operations
R. Cultraro	2014	$250,000		$110,000		$0	($19,000)		$0		$341,000
Senior Vice	2013	$250,000		$110,000		$0	$64,000		$0		$424,000
President	2012	$250,000		$130,000		$0	$104,000		$0		$484,000
and Chief
Investment and Pension
Officer
J. Agostino6	2014	$228,375		$80,000		$0	$94,000		$0		$402,375
Senior Vice	2013	$228,375		$75,000		$0	$70,000		$0		$373,375
President,	2012	$228,375		$68,500		$0	$23,000		$0		$319,875
General
Counsel and Chief
Compliance
Officer

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

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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 his increased responsibilities. Mr. Marcello was from February 25, 2014 until November 17, 2014, the interim Chief Operating Officer following the resignation of the former Chief Operating Officer in February of 2014.

³  Effective November 17, 2014, Mr. Suleman, who was the Vice President and Treasurer, was appointed Chief Financial Officer (Acting) as part of an organizational restructuring, pending a determination by the Board on the selection of new Chief Financial Officer. As a result of this restructuring and the new and added responsibilities for Mr. Suleman, his annual compensation increased, from $244,615 to $280,000, commensurate with the position in an acting capacity, effective November 17, 2014. In July 2014, Hydro One moved from a monthly pay cycle for management employees to a biweekly pay cycle, paid in arrears. As a result of this pay cycle change, management employees had the option to take a transition adjustment for that two week period, subject to a repayment obligation. Mr. Suleman took the transition adjustment. As such, Mr. Suleman’s salary for the year reflects his previous annual salary, the transition adjustment and his new salary.

⁴  Effective January 1, 2013, as part of an organizational realignment to better deliver on key priorities of Hydro One, Mr. Struthers was appointed Chief Administration Officer and Chief Financial Officer, which positions brought under Mr. Struthers oversight and direction of the shared services of Hydro One. As a result of this realignment and added responsibilities,

Mr. Struthers’ compensation increased commensurate with the position and increased responsibilities, effective January 1, 2013. On November 17, 2014, Mr. Struthers became the Chief Operating Officer and Executive Vice President, Strategic Planning as part of organizational restructuring and took over the Chief Operating Officer position from Mr. Marcello. In taking on this significant role, Mr. Struthers became accountable for the end-to-end delivery of Hydro One’s work and improving the efficiency and effectiveness of Hydro One’s operations. Additionally, in this role Mr. Struthers is accountable for Hydro One’s work as it relates to the Council on Government Assets. As of November 17, 2014, Mr. Struthers compensation increased, from $375,000 to $435,000, commensurate with this position and increased responsibilities. In connection with Hydro One’s move to a bi-weekly pay period from a monthly pay period, management employees could elect to receive a transition adjustment subject to a repayment obligation. As Mr. Struthers did not make such an election, notwithstanding the increase in salary close to the year end, his reported base salary for 2014 is slightly lower than in 2013.

⁵  Effective January 1, 2013, Mr. Smith, as part of the organizational realignment became the Senior Vice President, Planning and Operation. With the departure of the former Chief Operating Officer in February 2014, as of March 14, 2014, Mr. Smith took on a new role of Senior Vice President, Operations with increased accountabilities and his annual base compensation increased from $274,050 to $340,000. Mr. Smith did not take a transition adjustment when Hydro One moved from a monthly pay period to a bi-weekly pay period. Mr. Smith retired effective December 31, 2014.

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⁶  Effective December 1, 2014, Mr. Agostino was appointed Senior Vice President, General Counsel and Chief Compliance Officer with enhanced accountabilities in the compliance role as part of the organizational restructuring. Mr. Agostino’s compensation increased to $250,000 per year effective December 1, 2014. As Hydro One moved to a bi-weekly pay period with salary payments made in arrears, this increase in compensation for the one month period in 2014 is not reflected in the 2014 pay.

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.

None of the NEO’s are entitled to other benefits or perquisites in the aggregate amount that exceeds $50,000 or 10% of their respective annual salaries.

Mr. Marcello did not receive any additional compensation for his services as a director of Hydro One and its subsidiaries.

Pension Plan Benefits

Defined Benefit Pension Plan

Hydro One provides a defined benefit pension plan to its employees. Each of the NEOs participates in the Hydro One Pension Plan (consisting of the Hydro One registered pension plan and the supplementary pension plan). The benefits for these individuals are calculated in a consistent manner with all other Hydro One employees, as described below.

For each year of credited service under the Hydro One Pension Plan, to a maximum of 35 years, the benefit provided for each of the employees who participate in the plan is equal to 2% of the member’s average base annual earnings during the 36 consecutive months (60 consecutive months for management employees hired on or after January 1, 2004 and for employees represented by the Society of Energy Professionals hired on or after November 17, 2005) when his or her base annual earnings were highest. Base annual earnings are comprised of the member’s salary and 50% of his or her short term incentive.

The approximate projected credited years of service that each NEO will have if he or she works until the age of 65 is as follows: Mr. Marcello – 35.0 years; Mr. Suleman – 24.4 years; Mr. Struthers – 24.0 years; Mr. Cultraro – 28.2 years. Mr. Smith retired on December 31, 2014 and his credited service at retirement is 34.2 years. Mr. Agostino is currently over age 65 and his credited service as at December 31, 2014 is 19.7 years. This pension is reduced by 0.625% of the member’s average base annual earnings up to the average 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

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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 $155,000 in 2014. Participants whose pensions would otherwise be restricted by the Income Tax Act (Canada) participate in an unregistered supplementary pension plan that provides benefits equal to the difference between the Income Tax Act (Canada) maximum pension benefits and the benefits determined in accordance with the formula set out in Hydro One’s registered pension plan. The supplementary pension plan is unfunded and the additional retirement income is paid from general revenues. Hydro One’s obligations to participants under the supplementary pension plan are secured by a letter of credit.

The table below shows the following information for each NEO participating in the company’s defined benefit pension arrangements:

— Years of credited service as at December 31, 2014;

— Estimated annual lifetime benefit payable for service up to December 31, 2014 and up to the normal retirement age of 65 (based on current age as at December 31, 2014 for Mr. Smith and Mr. Agostino); and

— A reconciliation of the present value of the defined benefit obligation from December 31, 2013 to December 31, 2014. 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.

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Name	Number of years credited service		Annual benefits payable				Opening present value of defined benefit obligation1 ($)		2014 Compensatory change ($)				2014 Non- compensatory change4 ($)		Closing present value of defined benefit obligation5 ($)
			($)
			At 12.31.2014		At age 65
									Service		Other3
									Cost2
C. Marcello		27.1 yrs		$281,000		$363,000		$6,555,000		$216,000		$195,000		$1,629,000	$8,595,000
A. Suleman		19.8 yrs		$108,000		$133,000		$1,944,000		$82,000		$18,000		$409,000	$2,453,000
S. Struthers		14.9 yrs		$125,000		$202,000		$2,106,000		$131,000		$135,000		$596,000	$2,968,000
W. Smith		34.2 yrs		$249,000		$249,000		$4,228,000		$119,000		($18,000)		$1,667,000	$5,996,000
R. Cultraro		8.8 yrs		$44,000		$141,000		$667,000		$67,000		($86,000)		$238,000	$886,000
J. Agostino		19.7 yrs		$97,000		$97,000		$1,669,000		$71,000		$23,000		$196,000	$1,959,000

¹ The opening present value of the defined benefit obligation is the value of the projected pension earned for service at January 1, 2014. 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.

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 experienced gains and losses.

⁵  The closing present value of the defined benefit obligation is the value of the projected pension earned for service to December 31, 2014. The values have been determined using the same actuarial assumptions used for determining the pension plan obligations at December 31, 2014 as disclosed in the notes to the 2014 consolidated financial statements, based on the actual earnings for 2014 and adjusted to reflect expected increases in pensionable earnings.

Notes:

— All members are currently vested in their pension entitlements earned to December 31, 2014.

— 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

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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, Mr. Cultraro and Mr. Agostino 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 and Mr. Struthers, if their employment is terminated by Hydro One without cause, each of Mr. Marcello and Mr. Struthers is entitled to receive an amount equal to 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 and Mr. Struthers 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.

Regarding Mr. Cultraro, if his employment were terminated by Hydro One without cause, he is entitled to a lump sum payment equivalent to 12 months of base salary and to no other entitlements.

For Mr. Agostino, if his employment were terminated by Hydro One without cause, he is entitled to receive an amount equal to his base salary at the date of termination in equal monthly instalments for a period of 20 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). Mr. Agostino would continue to earn credited service under the Hydro One Pension Plan during such 20-month period.

The amount of salary and incentive plan benefits expected to be paid if Mr. Marcello, Mr. Struthers, Mr. Cultraro and Mr. Agostino were terminated on December 31, 2014 is summarized in the following table.

Name	Base Salary	3 year average   Incentive Payment	Total Payment
C. Marcello	$1,050,000	$335,750	$1,385,750
S. Struthers	$870,000	$320,666	$1,190,666
R. Cultraro	$250,000	N/A	$250,000
J. Agostino	$416,666	$110,277	$526,943

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

Mr. Marcello’s annual pension accrued at December 31, 2014 would be expected to increase by $80,000.

Mr. Struthers’s annual pension accrued at December 31, 2014 would be expected to increase by $35,000.

Mr. Cultraro’s annual pension accrued at December 31, 2014 would be expected to increase by $9,000.

Mr. Agostino’s annual pension accrued at December 31, 2014 would be expected to increase by $15,000.

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, Mr. Cultraro and Mr. Agostino 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

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.

Ms. Sandra Pupatello was appointed Chair of the Board on April 1, 2014. Ms. Pupatello replaced Mr. James Arnett who held the position of Chair of the Board from March 31, 2008 until March 31, 2014. The Chair receives annual remuneration of $150,000 per annum and does not receive any additional fees for serving as a director.

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The following table summarizes the compensation earned in 2014 by the directors of Hydro One.

Director Compensation Table

Name	Fees Earned		All other compensation1		Total
Sandra Pupatello		$112,500.002		$0		$112,500.00
Chair (April 1, 2014 to
December 31, 2014)
Director		$14,264.383		$0		$14,264.38
(January 1, 2014 to
March 31, 2014)
James Arnett		$37,500.002		$0		$37,500.00
Chair (January 1, 2014 to March 31, 2014)
Kathryn Bouey		$67,600.00		$0		$67,600.00
George Cooke		$62,972.59		$0		$62,972.59
Sally Daub5		$32,491.78		$0		$32,491.78
Catherine Karakatsanis		$51,272.59		$0		$51,272.59
William Limbrick5		$42,450.69		$0		$42,450.69
Don MacKinnon		$51,400.00		$0		$51,400.00
Tom Moss5		$37,950.69		$5,400.00		$43,350.69
Michael Mueller4		$19,371.23		$900.00		$20,271.23
Walter Murray4		$19,371.23		$1,800.00		$21,171.23
Robert Pace4		$16,671.23		$1,800.00		$18,471.23
Yezdi Pavri		$61,000.00		$0		$61,000.00
Gale Rubenstein		$61,300.00		$0		$61,300.00
Maureen Sabia5		$33,391.78		$0		$33,391.78
Douglas Speers4		$20,271.23		$3,600.00		$23,871.23
John Wiersma5		$35,250.69		$5,400.00		$40,650.69
Carole Workman5		$35,191.78		$5,400.00		$40,591.78
TOTAL		$812,221.89		$24,300.00		$836,521.89

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

(2) The Chair of the Board receives an annual remuneration of $150,000.00. Sandra Pupatello received $112,500.00 in remuneration in 2014, which is her prorated share of earned fees as Chair of the Board from April 1, 2014 to December 31, 2014. James Arnett received $37,500.00 in remuneration in 2014, which is his prorated share of earned fees as Chair of the Board from January 1, 2014 to March 31, 2014.

(3) Sandra Pupatello received $14,264.38 in 2014, which represents fees earned as a Member of the Board from January 1, 2014 to March 31, 2014.

(4) Michael Mueller, Walter Murray, Robert Pace and Douglas Speers were members of the Board from January 1, 2014 until April 11, 2014.

(5) William Limbrick, Tom Moss and John Wiersma were elected to the Board on April 11, 2014. Sally Daub, Maureen Sabia and Carole Workman were elected to the Board on April 25, 2014.

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APPOINTMENT OF AUDITOR

APPOINTMENT OF AUDITOR

The auditor of our company is KPMG LLP.

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AUDIT, FINANCE AND PENSION INVESTMENT COMMITTEE INFORMATION

The Audit, Finance and Pension Investment Committee’s Charter

Our Audit, Finance and Pension Investment Committee’s mandate is attached hereto as Appendix “A”, which Appendix is hereby incorporated by reference. The Board amended its Board Committee Structure and Membership on May 6, 2014. The amended Committee Structure included the amalgamation of the Audit and Finance Committee with the Investment-Pension Committee and was renamed the Audit, Finance and Pension Investment Committee. The Audit, Finance and Pension Investment Committee’s mandate was reviewed on June 24, 2014.

Composition of the Audit, Finance and Pension Investment Committee

As at December 31, 2014, the members of our Audit, Finance and Pension Investment Committee were George Cooke (Chair), Sally Daub, Don MacKinnon, Yezdi Pavri, Maureen Sabia and Carole Workman. Mr. Cooke was appointed Chair of the Committee on May 6, 2014, having served on the Audit and Finance Committee since February 11, 2010. Mr. Pavri has served on the Audit and Finance Committee since December 13, 2012. Ms. Daub, Mr. MacKinnon, Miss Sabia and Ms. Workman were appointed as members of the Committee by the Board on May 6, 2014. 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, Finance and Pension Investment Committee, the board determined that at least one of the members, being the current Chair of the Audit, Finance and Pension Investment Committee, Mr. George Cooke, is qualified as an “audit committee financial expert”, and that all members of the Audit, Finance and Pension Investment

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, Finance and Pension Investment Committee member who was serving as a member of the Audit, Finance and Pension Investment Committee on December 31, 2014 that is relevant to the performance of his or her responsibilities as an Audit, Finance and Pension Investment Committee member is described below.

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 Board (1988-1989), and positions with the OEB (1980-1988). Mr. Cooke was a member of the

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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.

Ms. Daub is a director of ViXS Systems Inc. (“ViXS”), a leading semiconductor company headquartered in Toronto, Ontario and served as the President and Chief Executive Officer of ViXS from 2001 until February 2015. Having taken the company public on the TSX in July 2013, Ms. Daub has consistently been recognized for her entrepreneurial and business expertise, including: Women’s Executive Network: Canada’s Most Powerful Women: Top 100; RBC Women of Influence, Trailblazer Category; and PROFIT Magazine’s Top 100 Women Entrepreneur. Trained as a chemical engineer and lawyer, with degrees from University of Ottawa and Dalhousie respectively, Ms. Daub began her career as a patent attorney both at the law firm of Smart & Biggar and Nortel Networks, where she specialized in IP licensing, strategy, development and management. Directly prior to joining ViXS, Ms. Daub served as Vice President and Chief Legal Counsel for ATI Technologies, a graphics chips supplier. Ms. Daub is also a registered patent agent in both Canada and the United States. Previously she has also served as Chair of the Small Business Agency of Ontario (part of what is now the Ontario Ministry of Economic Development, Trade and Employment) and as a board member of the Information Technology

Association of Canada and the Global Semiconductor Association.

Mr. 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. Mr. MacKinnon is a member of the Board of Plug’n Drive Ontario and a member of the Board Advisory Council of the Waterloo Institute for Sustainable Energy (WISE), University of Waterloo. Most recently, he became a member of the Advisory Board of the Ivey Energy Policy and Management Centre.

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

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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.

Maureen Sabia is the Non-Executive Chairman of the Board of Directors of the Canadian Tire Corporation (March 8, 2007 – present), and President, Maureen Sabia International Inc., a consulting firm. Miss Sabia is also a director of Canadian Tire Bank where she serves on its Audit Committee and immediate past Chairman of the Foreign Affairs and International Trade Canada Departmental Audit Committee. Miss Sabia co-authored “Integrity in the Spotlight – Opportunities for Audit Committees” published in 2002, and “Integrity in the Spotlight – Audit Committees in a High Risk World” published in 2005. Miss Sabia was a member of the Board of Trustees of Brock University where she also served as Chairman of its Audit Committee, until mid 2014 and is a member of the Leadership Council of the Perimeter Institute. Miss Sabia is a lawyer and has had careers in the public and private sectors and served as the Chairman of the Export Development Corporation. She is past Chairman of the Audit Committee of Canadian Tire Corporation and immediate past Vice-Chairman of the Public Accountants Council for the Province of Ontario. Miss Sabia was formerly a director of Gulf Canada Resources Limited, Hollinger Inc., Laurentian General Insurance Company Inc.,

O & Y FPT Inc., O & Y Properties Corporation and Skyjack Inc. She has been a member of the Board of Governors of the University of Guelph, Chairman of the Sunnybrook Medical Centre Foundation and a member of the Board of Trustees for Sunnybrook Medical Centre. In 2011, Miss Sabia was appointed an Officer of the Order of Canada. She holds a J.D. from the Faculty of Law of the University of Toronto, an Honours Bachelor of Arts from McGill University, and has been awarded two honorary LL.Ds. She is an Officer of the Order of Canada.

Ms. Workman is a Chartered Professional Accountant (Chartered Accountant). She is a member of the Board of Allstate Insurance of Canada and is Chair of their Audit Committee and Compliance Committee. She is a member of The Ottawa Hospital Board of Directors, Past Chair of the Board, and a member of their Audit and Finance Committee. She served 7 years as a member of Hydro Ottawa, chaired the wholly owned Local Distribution Company Board and served as a member of the Audit Committee. She was also a member and Chair of the Canadian University Insurance Exchange Reciprocal for many years. She had a long career in executive and financial management and served the University of Ottawa for 24 years as its Chief Financial Officer and Vice President, Finance & Administration until her retirement in 2004. Ms. Workman has a B. Commerce and a Masters of Public Administration and completed the Harvard International Management Program.

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Audit, Finance and Pension Investment Committee Oversight

There have been no recommendations of our Audit, Finance and Pension Investment Committee to nominate or compensate an external auditor which has not been adopted by our Board.

Pre-Approval Policies and Procedures

In accordance with the provisions of its mandate, the Audit, Finance and Pension Investment 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 2014		Fiscal 2013
Type of Fees	Fees	% of Total	Fees	% of Total
Audit Fees	$735, 776	84.1%	$807,176	78.1%
Audit-Related Fees	139,0831	15.9%	204,0832	19.8%
Tax Fees	—	—  %	—	—  %
All Other Fees3	—	—  %	21,714	2.1%
Total	$874,859	100%	$1,032,973	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, 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, incremental procedures performed over implementation of the Customer Information System, 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, Ms. Sandra Pupatello, the Chair of our Board, is also not considered independent as she 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 2014, twelve such sessions without management were held at Board meetings. Each Committee of the Board also holds regular in-camera sessions without management present. As well, the Audit, Finance and Pension Investment Committee regularly holds such sessions with the external auditors and with the internal auditor. The Chair of the Audit, Finance and Pension Investment 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, 2014.

Director	Board Meetings Attended
Sandra Pupatello	16 of 16
James Arnett1	4 of 4
Kathryn Bouey	16 of 16
George Cooke	16 of 16
Sally Daub3	10 of 11
Catherine Karakatsanis	11 of 16
William Limbrick4	11 of 12
Don MacKinnon5	14 of 14
Carmine Marcello	16 of 16
Tom Moss4	11 of 12
Michael Mueller2	4 of 4
Walter Murray2	4 of 4
Robert Pace2	4 of 4
Yezdi Pavri	16 of 16
Gale Rubenstein	14 of 16
Maureen Sabia3	8 of 11
Douglas Speers2	4 of 4
John Wiersma4	8 of 12
Carole Workman3	11 of 11

(1) Mr. Arnett resigned from the Board on April 1, 2014 and four meetings of the Board were held in 2014 prior to his resignation from the Board.

(2) Mr. Mueller, Mr. Murray, Mr. Pace and Mr. Speers were members of the Board until April 11, 2014 when they were not re-elected by the shareholder. Four meetings of the Board were held in 2014 prior to that date.

(3) Ms. Daub, Miss Sabia and Ms. Workman were elected to the Board on April 25, 2014 and eleven meetings of the Board were held in 2014 after their election to the Board.

(4) Mr. Limbrick, Mr. Moss and Mr. Wiersma were elected to the Board on April 11, 2014 and 12 meetings were held in 2014 after their election to the Board.

(5) Mr. MacKinnon was not in attendance for two meetings of the Board because these meetings solely addressed labour relations matters and, as President of the PWU, there was a conflict of interest that precluded his attendance. Those meetings are therefore not included in the total number of Board meetings Mr. MacKinnon could have attended.

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Directors’ Board Memberships in Other Reporting Issuers

Director	Reporting Issuer
Maureen Sabia	Canadian Tire Corporation Limited
Sally Daub	ViXS Systems Inc.
Sandra Pupatello	Martinrea International Inc.

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 (as at December 31, 2014)

The Board has established six 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 six standing committees of the Board are the Audit, Finance and Pension Investment Committee, the Business Transformation Committee, the Corporate Governance and Human Resources Committee, the Health, Safety and Environment Committee, the Regulatory and Public Policy Committee, and the Strategy 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 2014, 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, Finance and Pension Investment Committee

The Audit, Finance and Pension Investment 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, Finance and Pension Investment Committee which is attached and the discussion concerning the composition of the Audit, Finance and Pension Investment Committee above). The Audit, Finance and Pension Investment

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Committee oversees the integrity of 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, Finance and Pension Investment Committee was updated to ensure compliance with U.S. securities legislation. In addition, the Audit, Finance and Pension Investment Committee assists the Board in fulfilling its oversight responsibilities in all matters related to the Hydro One Pension Plan including the Hydro One Pension Fund.

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 (“Smart Grid”) 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 and Human Resources Committee

The Corporate Governance and Human Resources Committee is composed entirely of independent directors. The Corporate Governance and Human Resources 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 and Human Resources 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. The Corporate Governance and Human Resources Committee leads an annual evaluation of the Board and makes recommendations on modifications of the evaluation process.

In addition, the Corporate Governance and Human Resources 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 Corporate Governance and Human Resources Committee also reviews succession planning and the recommendations for the appointment of persons to senior executive positions. The Corporate Governance and Human Resources Committee retained Hugessen Consulting Inc. in 2014 to advise the Committee on the development of Hydro One’s corporate scorecard and compensation matters, and to provide advice on the year end scorecard results and compensation matters. In 2013, Hugessen Consulting Inc. also provided to the former Human Resources Committee consulting services on matters of compensation. For additional information relating to the compensation of our company’s senior executives, see “Statement of Executive Compensation”.

Health, Safety and Environment Committee

The Health, Safety and Environment Committee advises the Board on health, safety and

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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.

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.

Strategy Committee

The Strategy Committee was established in 2014 to assist the Board with matters relating to the Council and generally, as the Board may delegate to it from time to time, to assist the Board in fulfilling its oversight responsibility for strategic planning as set out in the Board mandate.

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 Human Resources and Audit, Finance and Pension Investment 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/education sessions, presentations and updates from senior management and external speakers on relevant topics related to our company’s business. These information items/education sessions 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

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all of Hydro One’s directors, officers and employees. The Code also applies to Hydro One’s agents, consultants, contractors and business partners, to the extent feasible. The Code is posted on the corporate intranet site and on the external corporate website at www.HydroOne.com.

Our company has a Corporate Ethics Officer who is accountable for making sure that the appropriate actions are taken to investigate and resolve known or suspected violations of the Code, and for ensuring the tracking and reporting of all violations. The Board monitors compliance with the Code through the Corporate Governance and Human Resources Committee and the Audit, Finance and Pension Investment 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. The Board also 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:

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 and Human Resources Committee to determine what, if any, actions may need to be taken. The Chair of the Corporate Governance and Human Resources Committee provides a report on the summary reports to the Board.

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Board and Executive Composition

Our company’s Board is elected annually by its sole shareholder, and it is the sole shareholder that determines the board composition and the term for the directors. The shareholder, and the Company, does not pre-set a term for the directors, though it is a one year term, unless re-elected at the annual election. Seven of the 14 members of our Board, or 50%, are women.

In accordance with our Corporate Diversity and Inclusiveness Policy, we strive for an inclusive corporate culture where all employees are valued and have equal access to opportunities and in particular we strive to ensure that our gender diversity is appropriately reflected at all levels of the corporation including executive officer positions after taking into account all relevant factors, such as merit, capability and equal treatment of employees. Of the executive officers across Hydro One and its major subsidiaries, approximately 28%, or seven of 25 senior executive positions, are women.

Targets are not in place for either Board positions or executive officer positions.

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APPENDIX “A”

APPENDIX “A”

AUDIT, FINANCE AND PENSION INVESTMENT COMMITTEE

Mandate

1. Pursuant to By-Law No. 1 of Hydro One Inc. (the “Corporation”), a consolidated committee of the directors to be known as the Audit, Finance and Pension Investment Committee (the “Committee”), being an amalgamation of the previous Audit and Finance Committee and the Investment-Pension Committee, is hereby established to assist the Board in its monitoring of, and compliance with applicable laws and regulations relating to, the Corporation’s:

(a) financial reporting and disclosure; and

(b) Pension Plan and Fund.

Committee Composition

2. The Committee shall be composed of a minimum of four directors, none of whom shall be an officer of the Corporation, 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:

Ÿ 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.

Ÿ 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

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by the Board if the membership of the Committee is less than four directors as a result of the vacancy. Whenever there is a vacancy on the Committee, the remaining members may exercise all of the powers of the Committee as long as a quorum remains in office.

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

Time and Place of Meetings

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.

Reporting to the Board

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 and making recommendations to the Board as the Committee deems appropriate.

Responsibilities and Duties with Respect to Financial Disclosure and Reporting

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.

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To fulfill its responsibilities and duties with respect to its monitoring and oversight of audit and financial matters, the Committee shall:

(1)  in connection with its advisory functions:

(a)  review the internal audit procedures of the Corporation and advise the Board on its auditing practices and procedures and obtain adequate assurance that internal controls are adequate;

(b)   meet separately with the external auditors and internal auditors;

(c)   recommend to the Board and shareholder the retention and, if appropriate, the removal of external auditors, evaluating and remunerating them, and monitoring their qualifications, performance and independence;

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

(f)  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

(g)  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

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(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;

(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;

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(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 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

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Corporation and any significant issues and auditor recommendations concerning such subsidiary entities;

(o)   review the basis and amount of the external auditor’s fees in light of the number and nature of reports issued by the auditors, the quality of the internal controls, the size, complexity and financial condition of the Corporation and the extent of internal audit and other support provided by the Corporation to the external auditors and review all other non-audit fees of the auditors or other accounting firms;

(p)   review management’s retention of consulting and professional services, including external legal services, on an annual basis;

(q)   review and appropriately address any complaints regarding accounting, internal accounting controls, or auditing matters received since the Committee’s last meeting, including complaints confidentially submitted by those wishing to remain anonymous; and

(r)   receive and review any reports of evidence of a material violation of securities laws or breaches of fiduciary duty tabled by the Corporation’s legal counsel as a result of an inappropriate response from management.

(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.

Responsibilities and Duties with Respect to the Pension Plan and Fund

8. The Board is a fiduciary of the Hydro One Pension Plan (the “Pension Plan”). The objective of the Committee in relation to the Pension Plan is to assist the Board in fulfilling its oversight responsibilities in all matters related to the Pension Plan, including the Hydro One Pension Fund (the “Fund”), and to ensure that all funding and investment activities meet the Pension Plan’s terms, administrative policies and legislative requirements.

9. With respect to the Pension Plan and Fund, in connection with the exercise of its powers, and in connection with its advisory powers, the Committee shall be responsible for the matters more particularly set out in the Pensions Governance Structure – Table (the “Table”), which is attached as Schedule A. Without restricting the generality of the foregoing, the Committee shall be responsible for the following matters and in the event of any inconsistency between the items as enumerated below and the Table, the responsibilities set out below shall be paramount:

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In respect of the Pension Plan and Fund:

(a) Review and recommend to the Board for its approval:

(i.) the overall pension governance structure, including the mandate of the Committee, and the provisions of the Board mandate relating to pensions;

(ii.) the Policy Asset Mix (the “PAM”), including the PAM ranges and Fund objective(s);

(iii.) the organizational structure of investment management and benefit administration functions (meaning internal or external management);

(iv.) appointment of actuary;

(v.) the funding strategy;

(vi.) the Pension Plan and Fund Annual Report (including financial statements);

(vii.) the appointment of the external Pension Plan and Fund Auditor; and

(viii.) the actuarial valuation report.

(b) Consider, Review and, if appropriate, approve the following matters:

(i.) the investment policies of the Pension Plan and Fund, including the Statement of Investment Policies and Procedures (“SIP&P”), the Implementation Guidelines (Statement of Investment Principles and Beliefs - SIP&B), the Pension Plan and Fund Monitoring and Reporting Policy, the Rebalancing Policy, and the Derivatives Policy;

(ii.) the Risk Management Framework;

(iii.) amendments to the Plan text, and the filing of amendments with applicable regulators;

(iv.) the Fiduciary Development Policy and Annual Education Plan; and

(v.) Annual Committee work plan related to pension matters.

(c) Receive for its information the following and such other reports as may be provided from time to time:

(i.) the results of monitoring of Investment Managers (“IM“s);

(ii.) reports on terminations, hirings and retention of IMs;

(iii.) reports on terminations, hirings and retention of third party service providers;

(iv.) quarterly reports on Fund performance, funded status, Fund objectives, and Fund administration;

(v.) the results of the annual Pension Plan and Fund risk assessment; and

(vi.) reports on compliance by third party service providers.

(d) Consider, review and, if appropriate, approve and recommend to the Corporate Governance and Human Resources Committee for its approval:

(i.) the pension communications strategy; and

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(ii.) pension member communications as described in the communications strategy (for example, report to members).

Engaging Independent Counsel and Other Advisors

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

Corporate Scorecard

11. 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 and Human Resources Committee of the Board.

Review of Committee Mandate

12. The Committee shall 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.

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Schedule A to the Audit, Finance and Pension Investment Committee Mandate – Pension Governance Structure

Level	Approval Items	Recommendation Items	Monitoring Items
Board of Directors (the “Board”) Responsible for overseeing the Hydro One Pension Plan (“Pension Plan”) and Pension Fund (“Pension Fund”); responsible for all fiduciary matters	Approves: —  overall pension governance structure, including the mandate of the Committee, and the provisions of the Board mandate relating to pensions —  the Policy Asset Mix (the “PAM”), including the PAM ranges (triennial review) and Pension Fund objective(s) —  Pension Plan and Fund Annual Report (including financial statements) —  actuarial valuation reports —  funding strategy —  appointment of external Pension Plan and Pension Fund auditor —  appointment of actuary —  organizational structure of investment management and benefit administration functions (meaning internal or external management)		Monitors: —  funded status of the Pension Plan —  achievement of Pension Fund objectives —  compliance by the Committee with its mandate
Audit, Finance and Pension Investment Committee (the “Committee”) Responsible for the approval of matters relating to pension investments, and review of and recommendation of all matters requiring Board approval	Approves: —  Investment Policies, including: Statement of Investment Policies and Procedures -SIP&P, Implementation Guidelines (Statement of Investment Principles and Beliefs – SIP&B), Pension Plan and Fund Monitoring and Reporting Policy, Rebalancing Policy, and the Derivatives Policy —  Risk Management Framework —  amendments to the Pension Plan text, and filing with applicable regulators —  Fiduciary Development Policy and Annual Education Plan —  Annual Committee Work Plan related to pension matters	Reviews and Recommends to the Board: All items listed for approval of the Board, above	Receives for its information: —  results of monitoring of Investment Managers (“IM“s) —  terminations, hirings and retention of IMs —  terminations, hirings and retention of third- party service providers —  quarterly reports on Pension Fund performance, funded status, Pension Fund

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Level	Approval Items	Recommendation Items	Monitoring Items
				objectives, and Pension Fund administration
			—	annual Pension Plan and Pension Fund risk assessment
			—	compliance by third-party service providers
			Approves and recommends to the Corporate Governance and Human Resources Committee for approval:
			—	pension communications strategy
			—	pension member communications as described in the communications strategy (for example, report to members)
Management Pension Committee (the “MPC”) ADVISORY Reviews and advises on pension implementation and operational matters, including all pension matters requiring Committee and Board approval			Advises on:
			—	all items for which the Committee is responsible, above, under Approval Items, Recommendation Items and Monitoring Items
			—	services provided by and compliance with mandates by all third-party service providers, including but not limited to the following:

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Level	Approval Items			Recommendation Items	Monitoring Items
						a)	IMs
						b)	trustee/custodian
						c)	external pension plan administrator
						d)	consultants
					Monitors:
					—	quarterly reports on Pension Fund performance, funded status, performance of IMs, and Pension Fund objectives
Pension Division	Responsible for, among other matters:
	—	Conducting thorough and careful analyses of all investment-related matters and benefits administration matters affecting the Pension Plan and Pension Fund;
	—	Providing recommendations on all pension matters requiring either Committee or Board approval. Developing and reviewing all policies and the Risk Management Framework.
	—	The hiring, retention and termination of all third party service providers to the Pension Plan and Pension Fund, including, but not limited to; any:
		a)	investment managers
		b)	trustee/custodian
		c)	external pension plan administrator, and
		d)	consultants;
	—	Performing regular and ongoing risk analysis and risk sensitivity analysis of the Pension Plan and Pension Fund;
	—	Conducting an annual Pension Plan and Pension Fund risk assessment

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Level	Approval Items		Recommendation Items	Monitoring Items
	—	Reporting to the Committee on the purpose, performance and amounts of all derivatives transactions entered into on behalf of the Pension Fund.
	—	Preparing and providing reports on Pension Fund performance, funded status, Pension Fund objectives and Pension Fund administration to the Committee and the Board;
	—	Maintaining the internal controls of the Pension Plan and Pension Fund, ensuring the safekeeping of Pension Fund assets;
	—	Voting on behalf of the Pension Fund with regard to voting rights related to pooled Pension Fund units and interests in partnerships or limited partnerships;
	—	Co-ordinating fiduciary development for the Committee and Board, ensuring that members of the Board and Committee are able to fulfill their legal and fiduciary obligations in this regard;
	—	Developing, maintaining, and adhering to all internal operational policies and procedures relating to the Pension Plan and Pension Fund;
	—	Ensuring that all regulatory, reporting and compliance requirements relating to the Pension Plan and Pension Fund are met;
	—	Advising the Committee and Board of the results of monitoring all third-party service providers;
	—	Executing the communications plan, which is based on the communications strategy approved by the Corporate Governance and Human Resources Committee;

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Level	Approval Items			Recommendation Items	Monitoring Items
	—	Managing all the day-to-day administration activities of the Pension Plan and Pension Fund, including, but not limited to:
		a)	maintaining pension-related records and data;
		b)	calculating benefits entitlement and processing benefit payments;
		c)	carrying out communications with members;
		d)	providing support to the Pension Plan actuary, as necessary;
		e)	satisfying all legislative and/or regulatory requirements pertaining to benefit administration;
		g)	providing support to the Labour Relations department, as necessary, and maintaining effective communications with that department;
		h)	managing special projects pertaining to benefits administration, as required; and
	—	Any other activities required for the good, prudent and proper administration of the benefits or funding functions of the Pension Plan and Pension Fund not specifically assigned to any other committee.

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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 (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 and Human Resources 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 Corporate Governance and 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, Finance and Pension Investment Committee, the Business Transformation Committee, the

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Corporate Governance and Human Resources Committee, the Health, Safety and Environment Committee, the Regulatory and Public Policy Committee and the Strategy 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 the Corporation’s Director Education Program and any continuing director development programs.

2. Annually, with the assistance of the Corporate Governance and Human Resources 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”

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. The current agreement expires December 31, 2019. See “Regulation – Contractual Arrangements, Codes and Licences – Operating Agreement with the IESO”.

— Non-discriminatory Access – If a generator, distributor, retailer, 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.

— 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 or the making of an interconnection 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 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

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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.

— Expansion and Upgrading of Transmission System Further to Ministerial Directive – For the purposes of accommodating the safe connection of renewable energy generation facilities, we shall develop and implement transmission projects and develop and seek approvals for the expansion or reinforcement of our transmission electricity system as required.

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. Additional key conditions include:

— Separation of Business Activity – We shall keep the distribution business financial records separate from those of the transmission business in accordance with the Accounting Procedures Handbook and as directed by the OEB.

— Distribution Rates – We shall 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 – We shall comply with the Retail Settlement Code, the DSC, the Standard Supply Service Code and the Affiliate Relationships Code for Electricity Distributors and Transmitters.

— Market Power Mitigation Rebates – We must pass through any rebates from OPG to customers in accordance with the specified rebate conditions.

— Obligation to Connect and Serve and Priority Connection Access – We must connect a building to our distribution system under prescribed circumstances, and 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 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 and Submission of Plans – We are required to prepare and submit plans for approval by the OEB, in the manner and at the times mandated by the OEB or as prescribed by regulation, that identify distribution system planning activities and expansion or reinforcement of the distribution system required to accommodate the connection of renewable energy generation facilities and forecast load growth. The contents of our Distribution System Plan filing will provide information to support the achievement of the RRFE performance outcomes; customer focus, operational effectiveness, public policy responsiveness and financial performance.

— Obligation to Maintain System Integrity – We will maintain our distribution system in accordance with the standards established in the DSC and Market Rules and any other recognized industry operating or planning standards adopted by the OEB.

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— Customer Complaint and Dispute Resolution – We will have a published process for resolving disputes with customers in a fair, reasonable and timely manner and refer any unresolved complaints to a third party chosen by the OEB for resolution.

— Conservation and Demand Management – We will meet our OPA assigned CDM targets through the delivery of OEB approved CDM programs and CDM programs made available by the OPA. We will provide programs to all consumer types in compliance with the CDM Code for Electricity Distributors.

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

EX-99.2

Exhibit 99.2

HYDRO ONE INC.

MANAGEMENT’S REPORT

The Consolidated Financial Statements, Management’s Discussion and Analysis (MD&A) and related financial information have been prepared by the management of Hydro One Inc. (Hydro One or the Company). Management is responsible for the integrity, consistency and reliability of all such information presented. The Consolidated Financial Statements have been prepared in accordance with United States Generally Accepted Accounting Principles and applicable securities legislation. The MD&A has been prepared in accordance with National Instrument 51-102.

The preparation of the Consolidated Financial Statements and information in the MD&A involves the use of estimates and assumptions based on management’s judgment, particularly when transactions affecting the current accounting period cannot be finalized with certainty until future periods. Estimates and assumptions are based on historical experience, current conditions and various other assumptions believed to be reasonable in the circumstances, with critical analysis of the significant accounting policies followed by the Company as described in Note 2 to the Consolidated Financial Statements. The preparation of the Consolidated Financial Statements and the MD&A includes information regarding the estimated impact of future events and transactions. The MD&A also includes information regarding sources of liquidity and capital resources, operating trends, risks and uncertainties. Actual results in the future may differ materially from the present assessment of this information because future events and circumstances may not occur as expected. The Consolidated Financial Statements and MD&A have been properly prepared within reasonable limits of materiality and in light of information up to February 11, 2015.

Management is responsible for establishing and maintaining adequate internal control over financial reporting for the Company. In meeting its responsibility for the reliability of financial information, management maintains and relies on a comprehensive system of internal control and internal audit. The system of internal control includes a written corporate conduct policy; implementation of a risk management framework; effective segregation of duties and delegation of authorities; and sound and conservative accounting policies that are regularly reviewed. This structure is designed to provide reasonable assurance that assets are safeguarded and that reliable information is available on a timely basis. In addition, management has assessed the design and operating effectiveness of the Company’s internal control over financial reporting in accordance with the criteria set forth in Internal Control – Integrated Framework (2013), issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, management concluded that the Company maintained effective internal control over financial reporting as of December 31, 2014. The effectiveness of these internal controls is reported to the Audit, Finance and Pension Investment Committee of the Hydro One Board of Directors, as required.

The Consolidated Financial Statements have been audited by KPMG LLP, independent external auditors appointed by the Shareholder. The external auditors’ responsibility is to express their opinion on whether the Consolidated Financial Statements are fairly presented in accordance with United States Generally Accepted Accounting Principles. The Independent Auditors’ Report outlines the scope of their examination and their opinion.

The Hydro One Board of Directors, through its Audit, Finance and Pension Investment Committee, is responsible for ensuring that management fulfills its responsibilities for financial reporting and internal controls. The Audit, Finance and Pension Investment Committee of Hydro One met periodically with management, the internal auditors and the external auditors to satisfy itself that each group had properly discharged its respective responsibility and to review the Consolidated Financial Statements before recommending approval by the Board of Directors. The external auditors had direct and full access to the Audit, Finance and Pension Investment Committee, with and without the presence of management, to discuss their audit findings, if any.

The President and Chief Executive Officer and the Chief Financial Officer (Acting) have certified Hydro One’s annual Consolidated Financial Statements and annual MD&A, related disclosure controls and procedures and the design and effectiveness of related internal controls over financial reporting.

On behalf of Hydro One Inc.’s management:

Carmine Marcello	Ali R. Suleman
President and Chief Executive Officer	Chief Financial Officer (Acting)

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HYDRO ONE INC.

INDEPENDENT AUDITORS’ REPORT

To the Shareholder of Hydro One Inc.

We have audited the accompanying Consolidated Financial Statements of Hydro One Inc., which comprise the consolidated balance sheets as at December 31, 2014 and December 31, 2013, the consolidated statements of operations and comprehensive income, changes in equity and cash flows for the years then ended, and notes, comprising a summary of significant accounting policies and other explanatory information.

Management’s Responsibility for the Consolidated Financial Statements

Management is responsible for the preparation and fair presentation of these Consolidated Financial Statements in accordance with United States Generally Accepted Accounting Principles, and for such internal control as management determines is necessary to enable the preparation of Consolidated Financial Statements that are free from material misstatement, whether due to fraud or error.

Auditors’ Responsibility

Our responsibility is to express an opinion on these Consolidated Financial Statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards. Those standards require that we comply with ethical requirements and plan and perform the audit to obtain reasonable assurance about whether the Consolidated Financial Statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the Consolidated Financial Statements. The procedures selected depend on our judgment, including the assessment of the risks of material misstatement of the Consolidated Financial Statements, whether due to fraud or error. In making those risk assessments, we consider internal control relevant to the entity’s preparation and fair presentation of the Consolidated Financial Statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the Consolidated Financial Statements.

We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the Consolidated Financial Statements present fairly, in all material respects, the consolidated financial position of Hydro One Inc. as at December 31, 2014 and December 31, 2013, and its consolidated results of operations and its consolidated cash flows for the years then ended in accordance with United States Generally Accepted Accounting Principles.

Chartered Professional Accountants, Licensed Public Accountants

Toronto, Canada

February 11, 2015

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HYDRO ONE INC.

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

For the years ended December 31, 2014 and 2013

Year ended December 31 (millions of Canadian dollars, except per share amounts)	2014			2013
Revenues
Distribution (includes $159 related party revenues; 2013 – $160) (Note 20)		4,903			4,484
Transmission (includes $1,567 related party revenues; 2013 – $1,517) (Note 20)		1,588			1,529
Other		57			61
		6,548			6,074
Costs
Purchased power (includes $2,633 related party costs; 2013 – $2,500) (Note 20)		3,419			3,020
Operation, maintenance and administration (Note 20)		1,192			1,106
Depreciation and amortization (Note 5)		722			676
		5,333			4,802
Income before financing charges and provision for payments in lieu of corporate income taxes		1,215			1,272
Financing charges (Note 6)		379			360
Income before provision for payments in lieu of corporate income taxes		836			912
Provision for payments in lieu of corporate income taxes (Notes 7, 20)		89			109
Net income		747			803
Net income (loss) attributable to noncontrolling interest (Note 4)		(2	)		—
Net income attributable to the Shareholder of Hydro One Inc.		749			803
Other comprehensive income		—			—
Comprehensive income		747			803
Comprehensive income (loss) attributable to noncontrolling interest (Note 4)		(2	)		—
Comprehensive income attributable to the Shareholder of Hydro One Inc.		749			803
Basic and fully diluted earnings per common share (dollars) (Note 18)		7,319			7,850
Dividends per common share declared (dollars) (Note 19)		2,696			2,000

See accompanying notes to Consolidated Financial Statements.

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HYDRO ONE INC.

CONSOLIDATED BALANCE SHEETS

At December 31, 2014 and 2013

December 31 (millions of Canadian dollars)	2014		2013
Assets
Current assets:
Cash and cash equivalents (Note 13)		100		565
Accounts receivable (net of allowance for doubtful accounts – $66; 2013 – $36) (Note 8)		1,016		923
Due from related parties (Note 20)		224		197
Regulatory assets (Note 11)		31		47
Materials and supplies		23		23
Deferred income tax assets (Note 7)		19		18
Derivative instruments (Note 13)		2		6
Investment (Notes 13, 20)		—		251
Prepaid expenses and other assets		35		28
		1,450		2,058
Property, plant and equipment (Note 9):
Property, plant and equipment in service		25,356		23,820
Less: accumulated depreciation		9,134		8,615
		16,222		15,205
Construction in progress		1,025		1,078
Future use land, components and spares		154		148
		17,401		16,431
Other long-term assets:
Regulatory assets (Note 11)		3,200		2,636
Intangible assets (net of accumulated amortization – $305; 2013 – $252) (Note 10)		276		313
Goodwill (Note 4)		173		133
Deferred debt issuance costs		36		36
Deferred income tax assets (Note 7)		7		11
Derivative instruments (Note 13)		—		6
Other		7		1
		3,699		3,136
Total assets		22,550		21,625

See accompanying notes to Consolidated Financial Statements.

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HYDRO ONE INC.

CONSOLIDATED BALANCE SHEETS (continued)

At December 31, 2014 and 2013

December 31 (millions of Canadian dollars, except number of shares)	2014			2013
Liabilities
Current liabilities:
Bank indebtedness (Note 13)		2			31
Accounts payable		173			135
Accrued liabilities (Notes 15, 16)		611			654
Due to related parties (Note 20)		227			230
Accrued interest		100			100
Regulatory liabilities (Note 11)		47			85
Derivative instruments (Note 13)		3			—
Long-term debt payable within one year (includes $252 measured at fair value; 2013 – $506) (Notes 12, 13)		552			756
		1,715			1,991
Long-term debt (includes $nil measured at fair value; 2013 – $256) (Notes 12, 13)		8,373			8,301
Other long-term liabilities:
Post-retirement and post-employment benefit liability (Note 15)		1,533			1,488
Deferred income tax liabilities (Note 7)		1,313			1,129
Pension benefit liability (Note 15)		1,236			845
Environmental liabilities (Note 16)		221			239
Regulatory liabilities (Note 11)		168			163
Net unamortized debt premiums		18			20
Asset retirement obligations (Note 17)		9			14
Long-term accounts payable and other liabilities		17			20
		4,515			3,918
Total liabilities		14,603			14,210
Contingencies and commitments (Notes 22, 23)
Subsequent Event (Note 25)
Preferred shares (authorized: unlimited; issued: 12,920,000) (Notes 18, 19)		323			323
Noncontrolling interest subject to redemption (Note 4)		21			—
Equity
Common shares (authorized: unlimited; issued: 100,000) (Notes 18, 19)		3,314			3,314
Retained earnings		4,249			3,787
Accumulated other comprehensive loss		(9	)		(9	)
Noncontrolling interest (Note 4)		49			—
Total equity		7,603			7,092
		22,550			21,625

See accompanying notes to Consolidated Financial Statements.

On behalf of the Board of Directors:

Sandra Pupatello	George L. Cooke
Chair	Chair, Audit, Finance and Pension Investment Committee

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HYDRO ONE INC.

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

For the years ended December 31, 2014 and 2013

Year ended December 31, 2014 (millions of Canadian dollars)	Common Shares		Retained Earnings			Accumulated Other Comprehensive Loss			Noncontrolling Interest			Total Equity
January 1, 2014		3,314		3,787			(9	)		—			7,092
Net income		—		749			—			(1	)		748
Other comprehensive income		—		—			—			—			—
Amount contributed by noncontrolling interest		—		—			—			50			50
Dividends on preferred shares		—		(18	)		—			—			(18	)
Dividends on common shares		—		(269	)		—			—			(269	)
December 31, 2014		3,314		4,249			(9	)		(49	)		7,603

Year ended December 31, 2013 (millions of Canadian dollars)	Common Shares		Retained Earnings			Accumulated Other Comprehensive Loss			Noncontrolling Interest		Total Equity
January 1, 2013		3,314		3,202			(9	)		—		6,507
Net income		—		803			—			—		803
Other comprehensive income		—		—			—			—		—
Dividends on preferred shares		—		(18	)		—			—		(18	)
Dividends on common shares		—		(200	)		—			—		(200	)
December 31, 2013		3,314		3,787			(9	)		—		7,092

See accompanying notes to Consolidated Financial Statements.

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HYDRO ONE INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the years ended December 31, 2014 and 2013

Year ended December 31 (millions of Canadian dollars)	2014			2013
Operating activities
Net income		747			803
Environmental expenditures		(18	)		(16	)
Adjustments for non-cash items:
Depreciation and amortization (excluding removal costs)		641			597
Regulatory assets and liabilities		(69	)		3
Deferred income taxes		10			(2	)
Other		—			8
Changes in non-cash balances related to operations (Note 21)		(55	)		11
Net cash from operating activities		1,256			1,404
Financing activities
Long-term debt issued		628			1,185
Long-term debt retired		(776	)		(600	)
Amount contributed by noncontrolling interest (Note 4)		72			—
Dividends paid		(287	)		(218	)
Change in bank indebtedness		(29	)		(11	)
Other		(3	)		(5	)
Net cash from (used in) financing activities		(395	)		351
Investing activities
Capital expenditures (Note 21)
Property, plant and equipment		(1,481	)		(1,308	)
Intangible assets		(23	)		(79	)
Acquisition of Norfolk Power Inc. (Note 4)		(66	)		—
Proceeds from investment		250			—
Other		(6	)		2
Net cash used in investing activities		(1,326	)		(1,385	)
Net change in cash and cash equivalents		(465	)		370
Cash and cash equivalents, beginning of year		565			195
Cash and cash equivalents, end of year		100			565

See accompanying notes to Consolidated Financial Statements.

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HYDRO ONE INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2014 and 2013

1. DESCRIPTION OF THE BUSINESS

Hydro One Inc. (Hydro One or the Company) was incorporated on December 1, 1998, under the Business Corporations Act (Ontario) and is wholly owned by the Province of Ontario (Province). The principal businesses of Hydro One are the transmission and distribution of electricity to customers within Ontario. The electricity rates of these businesses are regulated by the Ontario Energy Board (OEB).

2. SIGNIFICANT ACCOUNTING POLICIES

Basis of Consolidation

These Consolidated Financial Statements include the accounts of the Company and its wholly owned subsidiaries: Hydro One Networks Inc. (Hydro One Networks), Hydro One Remote Communities Inc. (Hydro One Remote Communities), Hydro One Brampton Networks Inc. (Hydro One Brampton Networks), Hydro One Telecom Inc. (Hydro One Telecom), Hydro One Lake Erie Link Management Inc., Hydro One Lake Erie Link Company Inc., Norfolk Power Inc. (Norfolk Power), and Hydro One B2M Holdings. Intercompany transactions and balances have been eliminated.

Basis of Accounting

These Consolidated Financial Statements are prepared and presented in accordance with United States (US) Generally Accepted Accounting Principles (GAAP) and in Canadian dollars.

Hydro One performed an evaluation of subsequent events through to February 11, 2015, the date these Consolidated Financial Statements were issued, to determine whether any events or transactions warranted recognition and disclosure in these Consolidated Financial Statements. See Note 25 – Subsequent Event.

Use of Management Estimates

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

Rate Setting

The Company’s Transmission Business includes the separately regulated transmission businesses of Hydro One Networks and B2M Limited Partnership (B2M LP). The Company’s consolidated Distribution Business includes the separately regulated distribution businesses of Hydro One Networks and the newly acquired Norfolk Power, as well as the subsidiaries Hydro One Brampton Networks and Hydro One Remote Communities.

The OEB has approved the use of US GAAP for rate setting and regulatory accounting and reporting by Hydro One Networks’ transmission and distribution businesses, as well as by Hydro One Remote Communities, beginning with the year 2012. Up to the year ended December 31, 2014, Hydro One Brampton Networks used Canadian GAAP (Part V) for its distribution rate-setting purposes, and has transitioned to International Financial Reporting Standards beginning on January 1, 2015.

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HYDRO ONE INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

For the years ended December 31, 2014 and 2013

Transmission

In May 2012, Hydro One Networks filed a cost-of-service application with the OEB for 2013 and 2014 transmission rates. In December 2012, the OEB approved the 2013 and 2014 revenue requirement of $1,438 million and $1,528 million, respectively.

In December 2013, Hydro One Networks filed a draft Rate Order with the OEB for 2014 transmission rates. The 2014 transmission revenue requirement was increased to $1,535 million from the originally-approved revenue requirement of $1,528 million, primarily due to changes in the cost of capital parameters for 2014 released by the OEB in November 2013. On January 9, 2014, the OEB approved the draft Rate Order for 2014 transmission rates as filed.

Distribution

In June 2012, Hydro One Networks filed an Incentive Regulation Mechanism (IRM) application with the OEB for 2013 distribution rates, to be effective January 1, 2013. In December 2012, the OEB issued its final Decision, which resulted in an increase in distribution rates of approximately 1.3% in 2013, or 0.4% when considering total bill impact, for a typical residential customer consuming 800 kWh per month. In April 2013, Hydro One Networks filed an IRM application with the OEB for 2014 distribution rates, to be effective January 1, 2014. In December 2013, the OEB issued its final Decision, which resulted in an increase in distribution rates of approximately 2.4% in 2014, or 0.85% when considering total bill impact, for a typical residential customer consuming 800 kWh per month.

In August 2012, Hydro One Brampton Networks filed an IRM application with the OEB for 2013 distribution rates, to be effective January 1, 2013. In December 2012, the OEB issued its final Decision, which resulted in an increase in distribution rates of approximately 0.3% in 2013, or less than 0.1% when considering total bill impact, for a typical residential customer consuming 800 kWh per month. In August 2013, Hydro One Brampton Networks filed an IRM application with the OEB for 2014 distribution rates, to be effective January 1, 2014. In December 2013, the OEB issued its final Decision, which resulted in a reduction in distribution rates of approximately 2.3% in 2014, or 0.5% when considering total bill impact, for a typical residential customer consuming 800 kWh per month.

In September 2012, Hydro One Remote Communities filed a cost-of-service application with the OEB for 2013 rates, seeking approval for a 2013 revenue requirement of $53 million. In June 2013, the OEB approved a revenue requirement of $51 million for 2013. In October 2013, Hydro One Remote Communities filed an IRM application with the OEB for 2014 rates, seeking approval for a rate increase of approximately 0.5%. In March 2014, the OEB approved an increase of approximately 1.7% to basic rates for the distribution and generation of electricity, with an effective date of May 1, 2014. The final rate increase was adjusted by the OEB’s updated rate adjustment parameters and Hydro One Remote Communities’ IRM stretch factor.

Regulatory Accounting

The OEB has the general power to include or exclude revenues, costs, gains or losses in the rates of a specific period, resulting in a change in the timing of accounting recognition from that which would have been applied in an unregulated company. Such change in timing involves the application of rate-regulated accounting, giving rise to the recognition of regulatory assets and liabilities. The Company’s regulatory assets represent certain amounts receivable from future customers and costs that have been deferred for accounting purposes because it is probable that they will be recovered in future rates. In addition, the Company has recorded regulatory liabilities that generally represent amounts that are refundable to future customers. The Company continually assesses the likelihood of recovery of each of its regulatory assets and continues to believe that it is probable that the OEB will factor its regulatory assets and liabilities into the setting of future rates. If, at some future date, the Company judges that it is no longer probable that the OEB will include a regulatory asset or liability in setting future rates, the appropriate carrying amount will be reflected in results of operations in the period that the assessment is made.

Cash and Cash Equivalents

Cash and cash equivalents include cash and short-term investments with an original maturity of three months or less.

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HYDRO ONE INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

For the years ended December 31, 2014 and 2013

Revenue Recognition

Transmission revenues are collected through OEB-approved rates, which are based on an approved revenue requirement that includes a rate of return. Such revenue is recognized as electricity is transmitted and delivered to customers.

Distribution revenues are recognized on an accrual basis and include billed and unbilled revenues. Distribution revenues attributable to the delivery of electricity are based on OEB-approved distribution rates and are recognized as electricity is delivered to customers. The Company estimates monthly revenue for a period based on wholesale electricity purchases because customer meters are not generally read at the end of each month. At the end of each month, the electricity delivered to customers, but not billed, is estimated and revenue is recognized. The unbilled revenue estimate is affected by energy demand, weather, line losses and changes in the composition of customer classes.

Distribution revenue also includes an amount relating to rate protection for rural, residential and remote customers, which is received from the Independent Electricity System Operator (IESO) based on a standardized customer rate that is approved by the OEB. Current legislation provides rate protection for prescribed classes of rural, residential and remote consumers by reducing the electricity rates that would otherwise apply.

Revenues also include amounts related to sales of other services and equipment. Such revenue is recognized as services are rendered or as equipment is delivered.

Revenues are recorded net of indirect taxes.

Accounts Receivable and Allowance for Doubtful Accounts

Billed accounts receivable are recorded at the invoiced amount, net of allowance for doubtful accounts. Unbilled accounts receivable are estimated and recorded based on wholesale electricity purchases. Overdue amounts related to regulated billings bear interest at OEB-approved rates. The allowance for doubtful accounts reflects the Company’s best estimate of losses on billed accounts receivable balances. The allowance is based on accounts receivable aging, historical experience and other currently available information. The Company estimates the allowance for doubtful accounts on customer receivables by applying internally developed loss rates to the outstanding receivable balances by risk segment. Risk segments represent groups of customers with similar credit quality indicators and are computed based on various attributes, including number of days receivables are past due, delinquency of balances and payment history. Loss rates applied to the accounts receivable balances are based on historical average write-offs as a percentage of accounts receivable in each risk segment. An account is considered delinquent if the final amount billed is not received within 110 days of the invoiced date. Accounts receivable are written off against the allowance when they are deemed uncollectible. The existing allowance for uncollectible accounts will continue to be affected by changes in volume, prices and economic conditions.

Noncontrolling interest

Noncontrolling interest represents the portion of equity ownership in subsidiaries that is not attributable to the Shareholder of the parent company. Noncontrolling interest is initially recorded at fair value and subsequently the amount is adjusted for the proportionate share of net income (loss) and other comprehensive income (loss) attributable to the noncontrolling interest and any dividends or distributions paid to the noncontrolling interest.

If a transaction results in the acquisition of all, or part, of a noncontrolling interest in a subsidiary, the acquisition of the noncontrolling interest is accounted for as an equity transaction. No gain or loss is recognized in consolidated net income or comprehensive income as a result of changes in the noncontrolling interest, unless a change results in the loss of control by the Company.

Corporate Income Taxes

Under the Electricity Act, 1998, Hydro One is required to make payments in lieu of corporate income taxes (PILs) to the Ontario Electricity Financial Corporation (OEFC). These payments are calculated in accordance with the rules for computing income and other relevant amounts contained in the Income Tax Act (Canada) and the Taxation Act, 2007 (Ontario) as modified by the Electricity Act, 1998 and related regulations.

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HYDRO ONE INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

For the years ended December 31, 2014 and 2013

Current and deferred income taxes are computed based on the tax rates and tax laws enacted at the balance sheet date. Tax benefits associated with income tax positions taken, or expected to be taken, in a tax return are recorded only when the “more-likely-than-not” recognition threshold is satisfied and are measured at the largest amount of benefit that has a greater than 50% likelihood of being realized upon settlement. Management evaluates each position based solely on the technical merits and facts and circumstances of the position, assuming the position will be examined by a taxing authority having full knowledge of all relevant information. Significant management judgment is required to determine recognition thresholds and the related amount of tax benefits to be recognized in the Consolidated Financial Statements. Management re-evaluates tax positions each period in which new information about recognition or measurement becomes available.

Current Income Taxes

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

Deferred Income Taxes

Deferred income taxes are provided for using the liability method. Deferred income taxes are recognized based on the estimated future tax consequences attributable to temporary differences between the carrying amount of assets and liabilities in the Consolidated Financial Statements and their corresponding tax bases.

Deferred income tax liabilities are generally recognized on all taxable temporary differences. Deferred tax assets are recognized to the extent that it is more-likely-than-not that these assets will be realized from taxable income available against which deductible temporary differences can be utilized.

Deferred income taxes are calculated at the tax rates that are expected to apply in the period when the liability is settled or the asset is realized, based on the tax rates and tax laws that have been enacted at the balance sheet date. Deferred income taxes that are not included in the rate-setting process are charged or credited to the Consolidated Statements of Operations and Comprehensive Income.

If management determines that it is more-likely-than-not that some or all of a deferred income tax asset will not be realized, a valuation allowance is recorded against the deferred income tax asset to report the net balance at the amount expected to be realized. Previously unrecognized deferred income tax assets are reassessed at each balance sheet date and are recognized to the extent that it has become more-likely-than-not that the tax benefit will be realized.

The Company records regulatory assets and liabilities associated with deferred income taxes that will be included in the rate-setting process.

The Company uses the flow-through method to account for investment tax credits (ITCs) earned on eligible scientific research and experimental development expenditures, and apprenticeship job creation. Under this method, only non-refundable ITCs are recognized as a reduction to income tax expense.

Materials and Supplies

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

Property, Plant and Equipment

Property, plant and equipment is recorded at original cost, net of customer contributions received in aid of construction and any accumulated impairment losses. The cost of additions, including betterments and replacement asset components, is included on the Consolidated Balance Sheets as property, plant and equipment.

The original cost of property, plant and equipment includes direct materials, direct labour (including employee benefits), contracted services, attributable capitalized financing costs, asset retirement costs, and direct and indirect overheads that are related to the capital project or program. Indirect overheads include a portion of corporate costs such as finance, treasury, human resources, information technology and executive costs. Overhead costs, including corporate functions and field services costs, are capitalized on a fully allocated basis, consistent with an OEB-approved methodology.

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HYDRO ONE INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

For the years ended December 31, 2014 and 2013

Property, plant and equipment in service consists of transmission, distribution, communication, administration and service assets and land easements. Property, plant and equipment also includes future use assets, such as land, major components and spare parts, and capitalized project development costs associated with deferred capital projects.

Transmission

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

Distribution

Distribution assets include assets related to the distribution of low-voltage electricity, including lines, poles, switches, transformers, protective devices and metering systems.

Communication

Communication assets include the fibre optic and microwave radio system, optical ground wire, towers, telephone equipment and associated buildings.

Administration and Service

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

Easements

Easements include statutory rights of use for transmission corridors and abutting lands granted under the Reliable Energy and Consumer Protection Act, 2002, as well as other land access rights.

Intangible Assets

Intangible assets separately acquired or internally developed are measured on initial recognition at cost, which comprises purchased software, direct labour (including employee benefits), consulting, engineering, overheads and attributable capitalized financing charges. Following initial recognition, intangible assets are carried at cost, net of any accumulated amortization and accumulated impairment losses. The Company’s intangible assets primarily represent major company-wide computer applications.

Capitalized Financing Costs

Capitalized financing costs represent interest costs attributable to the construction of property, plant and equipment or development of intangible assets. The financing cost of attributable borrowed funds is capitalized as part of the acquisition cost of such assets. The capitalized portion of financing costs is a reduction to financing charges recognized in the Consolidated Statements of Operations and Comprehensive Income. Capitalized financing costs are calculated using the Company’s weighted average effective cost of debt.

Construction and Development in Progress

Construction and development in progress consists of the capitalized cost of constructed assets that are not yet complete and which have not yet been placed in service.

12

HYDRO ONE INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

For the years ended December 31, 2014 and 2013

Depreciation and Amortization

The cost of property, plant and equipment and intangible assets is depreciated or amortized on a straight-line basis based on the estimated remaining service life of each asset category, except for transport and work equipment, which is depreciated on a declining balance basis.

The Company periodically initiates an external independent review of its property, plant and equipment and intangible asset depreciation and amortization rates, as required by the OEB. Any changes arising from OEB approval of such a review are implemented on a remaining service life basis, consistent with their inclusion in electricity rates. The last review resulted in changes to rates effective January 1, 2013. A summary of average service lives and depreciation and amortization rates for the various classes of assets is included below:

	Average		Rate
	Service Life		Range	Average
Transmission		57 years	1% – 2%		2	%
Distribution		42 years	1% – 20%		2	%
Communication		19 years	1% – 15%		4	%
Administration and service		15 years	3% – 20%		7	%

The cost of intangible assets is included primarily within the administration and service classification above. Amortization rates for computer applications software and other intangible assets range from 9% to 20%.

In accordance with group depreciation practices, the original cost of property, plant and equipment, or major components thereof, and intangible assets that are normally retired, is charged to accumulated depreciation, with no gain or loss being reflected in results of operations. Where a disposition of property, plant and equipment occurs through sale, a gain or loss is calculated based on proceeds and such gain or loss is included in depreciation expense. Depreciation expense also includes the costs incurred to remove property, plant and equipment where no ARO has been recorded.

Goodwill

Goodwill represents the cost of acquired local distribution companies that is in excess of the fair value of the net identifiable assets acquired at the acquisition date. Goodwill is not included in rate base.

Goodwill is evaluated for impairment on an annual basis, or more frequently if circumstances require. The Company performs a qualitative assessment to determine whether it is more-likely-than-not that the fair value of the applicable reporting unit is less than its carrying amount. If the Company determines, as a result of its qualitative assessment, that it is not more-likely-than-not that the fair value of the applicable reporting unit is less than its carrying amount, no further testing is required. If the Company determines, as a result of its qualitative assessment, that it is more-likely-than-not that the fair value of the applicable reporting unit is less than its carrying amount, a goodwill impairment assessment is performed using a two-step, fair value-based test. The first step compares the fair value of the applicable reporting unit to its carrying amount, including goodwill. If the carrying amount of the applicable reporting unit exceeds its fair value, a second step is performed. The second step requires an allocation of fair value to the individual assets and liabilities using purchase price allocation in order to determine the implied fair value of goodwill. If the implied fair value of goodwill is less than the carrying amount, an impairment loss is recorded as a reduction to goodwill and as a charge to results of operations.

For the year ended December 31, 2014, based on the qualitative assessment performed as at September 30, 2014, the Company has determined that it is not more-likely-than-not that the fair value of each applicable reporting unit assessed is less than its carrying amount. As a result, no further testing was performed, and the Company has concluded that goodwill was not impaired at December 31, 2014.

Long-Lived Asset Impairment

When circumstances indicate the carrying value of long-lived assets may not be recoverable, the Company evaluates whether the carrying value of such assets, excluding goodwill, has been impaired. For such long-lived assets, impairment exists when the carrying value exceeds the sum of the future estimated undiscounted cash flows expected to result from the use and

13

HYDRO ONE INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

For the years ended December 31, 2014 and 2013

eventual disposition of the asset. When alternative courses of action to recover the carrying amount of a long-lived asset are under consideration, a probability-weighted approach is used to develop estimates of future undiscounted cash flows. If the carrying value of the long-lived asset is not recoverable based on the estimated future undiscounted cash flows, an impairment loss is recorded, measured as the excess of the carrying value of the asset over its fair value. As a result, the asset’s carrying value is adjusted to its estimated fair value.

Within its regulated business, the carrying costs of most of Hydro One’s long-lived assets are included in rate base where they earn an OEB-approved rate of return. Asset carrying values and the related return are recovered through approved rates. As a result, such assets are only tested for impairment in the event that the OEB disallows recovery, in whole or in part, or if such a disallowance is judged to be probable.

Hydro One regularly monitors the assets of its unregulated Hydro One Telecom subsidiary for indications of impairment. Management assesses the fair value of such long-lived assets using commonly accepted techniques, and may use more than one. Techniques used to determine fair value include, but are not limited to, the use of recent third party comparable sales for reference and internally developed discounted cash flow analysis. Significant changes in market conditions, changes to the condition of an asset, or a change in management’s intent to utilize the asset are generally viewed by management as triggering events to reassess the cash flows related to these long-lived assets. As at December 31, 2014, no asset impairment had been recorded for assets within either the Company’s regulated or unregulated businesses.

Costs of Arranging Debt Financing

For financial liabilities classified as other than held-for-trading, the Company defers the external transaction costs related to obtaining debt financing and presents such amounts as deferred debt issuance costs on the Consolidated Balance Sheets. Deferred debt issuance costs are amortized over the contractual life of the related debt on an effective-interest basis and the amortization is included within financing charges in the Consolidated Statements of Operations and Comprehensive Income. Transaction costs for items classified as held-for-trading are expensed immediately.

Comprehensive Income

Comprehensive income is comprised of net income and other comprehensive income (OCI). Hydro One presents net income and OCI in a single continuous Consolidated Statement of Operations and Comprehensive Income.

Financial Assets and Liabilities

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

Derivative instruments are measured at fair value. Gains and losses from fair valuation are included within financing charges in the period in which they arise. The Company determines the classification of its financial assets and liabilities at the date of initial recognition. The Company designates certain of its financial assets and liabilities to be held at fair value, when it is consistent with the Company’s risk management policy disclosed in Note 13 – Fair Value of Financial Instruments and Risk Management.

Derivative Instruments and Hedge Accounting

The Company closely monitors the risks associated with changes in interest rates on its operations and, where appropriate, uses various instruments to hedge these risks. Certain of these derivative instruments qualify for hedge accounting and are designated as accounting hedges, while others either do not qualify as hedges or have not been designated as hedges (hereinafter referred to as undesignated contracts) as they are part of economic hedging relationships.

14

HYDRO ONE INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

For the years ended December 31, 2014 and 2013

The accounting guidance for derivative instruments requires the recognition of all derivative instruments not identified as meeting the normal purchase and sale exemption as either assets or liabilities recorded at fair value on the Consolidated Balance Sheets. For derivative instruments that qualify for hedge accounting, the Company may elect to designate such derivative instruments as either cash flow hedges or fair value hedges. The Company offsets fair value amounts recognized on its Consolidated Balance Sheets related to derivative instruments executed with the same counterparty under the same master netting agreement.

For derivative instruments that qualify for hedge accounting and which are designated as cash flow hedges, the effective portion of any gain or loss, net of tax, is reported as a component of accumulated OCI (AOCI) and is reclassified to results of operations in the same period or periods during which the hedged transaction affects results of operations. Any gains or losses on the derivative instrument that represent either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in results of operations. For fair value hedges, changes in fair value of both the derivative instrument and the underlying hedged exposure are recognized in the Consolidated Statements of Operations and Comprehensive Income in the current period. The gain or loss on the derivative instrument is included in the same line item as the offsetting gain or loss on the hedged item in the Consolidated Statements of Operations and Comprehensive Income. Additionally, the Company enters into derivative agreements that are economic hedges which either do not qualify for hedge accounting or have not been designated as hedges. The changes in fair value of these undesignated derivative instruments are reflected in results of operations.

Embedded derivative instruments are separated from their host contracts and carried at fair value on the Consolidated Balance Sheets when: (a) the economic characteristics and risks of the embedded derivative are not clearly and closely related to the economic characteristics and risks of the host contract; (b) the hybrid instrument is not measured at fair value, with changes in fair value recognized in results of operations each period; and (c) the embedded derivative itself meets the definition of a derivative. The Company does not engage in derivative trading or speculative activities and had no embedded derivatives at December 31, 2014 or 2013.

Hydro One periodically develops hedging strategies taking into account risk management objectives. At the inception of a hedging relationship where the Company has elected to apply hedge accounting, Hydro One formally documents the relationship between the hedged item and the hedging instrument, the related risk management objective, the nature of the specific risk exposure being hedged, and the method for assessing the effectiveness of the hedging relationship. The Company also assesses, both at the inception of the hedge and on a quarterly basis, whether the hedging instruments are effective in offsetting changes in fair values or cash flows of the hedged items.

Employee Future Benefits

Employee future benefits provided by Hydro One include pension, post-retirement and post-employment benefits. The costs of the Company’s pension, post-retirement and post-employment benefit plans are recorded over the periods during which employees render service.

The Company recognizes the funded status of its pension, post-retirement and post-employment plans on its Consolidated Balance Sheets and subsequently recognizes the changes in funded status at the end of each reporting year. Pension, post-retirement and post-employment plans are considered to be underfunded when the projected benefit obligation exceeds the fair value of the plan assets. Liabilities are recognized on the Consolidated Balance Sheets for any net underfunded projected benefit obligation. The net underfunded projected benefit obligation may be disclosed as a current liability, long-term liability, or both. The current portion is the amount by which the actuarial present value of benefits included in the benefit obligation payable in the next 12 months exceeds the fair value of plan assets. If the fair value of plan assets exceeds the projected benefit obligation of the plan, an asset is recognized equal to the net overfunded projected benefit obligation. The post-retirement and post-employment benefit plans are unfunded because there are no related plan assets.

15

HYDRO ONE INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

For the years ended December 31, 2014 and 2013

Pension benefits

In accordance with the OEB’s rate orders, pension costs are recorded on a cash basis as employer contributions are paid to the pension fund in accordance with the Pension Benefits Act (Ontario). Pension costs are recorded on an accrual basis for financial reporting purposes. Pension costs are actuarially determined using the projected benefit method prorated on service and are based on assumptions that reflect management’s best estimate of the effect of future events, including future compensation increases. Past service costs from plan amendments and all actuarial gains and losses are amortized on a straight-line basis over the expected average remaining service period of active employees in the plan, and over the estimated remaining life expectancy of inactive employees in the plan. Pension plan assets, consisting primarily of listed equity securities as well as corporate and government debt securities, are fair valued at the end of each year.

Hydro One records a regulatory asset equal to the net underfunded projected benefit obligation for its pension plan. The regulatory asset for the net underfunded projected benefit obligation for the pension plan, in the absence of regulatory accounting, would be recognized in AOCI. A regulatory asset is recognized because management considers it to be probable that pension benefit costs will be recovered in the future through the rate-setting process. The pension regulatory assets are remeasured at the end of each year based on the current status of the pension plan.

All future pension benefit costs are attributed to labour and are either charged to results of operations or capitalized as part of the cost of property, plant and equipment and intangible assets.

Post-retirement and post-employment benefits

Post-retirement and post-employment benefits are recorded and included in rates on an accrual basis. Costs are determined by independent actuaries using the projected benefit method prorated on service and based on assumptions that reflect management’s best estimates. Past service costs from plan amendments are amortized to results of operations based on the expected average remaining service period.

Hydro One records a regulatory asset equal to the incremental net unfunded projected benefit obligation for post-retirement and post-employment plans recorded at each year end based on annual actuarial reports. The regulatory asset for the incremental net unfunded projected benefit obligation for post-retirement and post-employment plans, in the absence of regulatory accounting, would be recognized in AOCI. A regulatory asset is recognized because management considers it to be probable that post-retirement and post-employment benefit costs will be recovered in the future through the rate-setting process.

For post-retirement benefits, all actuarial gains or losses are deferred using the “corridor” approach. The amount calculated above the “corridor” is amortized to results of operations on a straight-line basis over the expected average remaining service life of active employees in the plan and over the remaining life expectancy of inactive employees in the plan. The post-retirement benefit obligation is remeasured to its fair value at each year end based on an annual actuarial report, with an offset to the associated regulatory asset, to the extent of the remeasurement adjustment.

For post-employment obligations, the associated regulatory liabilities representing actuarial gains on transition to US GAAP are amortized to results of operations based on the “corridor” approach. Post transition, the actuarial gains and losses on post-employment obligations that are incurred during the year are recognized immediately to results of operations. The post-employment benefit obligation is remeasured to its fair value at each year end based on an annual actuarial report, with an offset to the associated regulatory asset, to the extent of the remeasurement adjustment.

All post-retirement and post-employment future benefit costs are attributed to labour and are either charged to results of operations or capitalized as part of the cost of property, plant and equipment and intangible assets.

Multiemployer Pension Plan

Employees of Hydro One Brampton Networks and the newly acquired Norfolk Power participate in the Ontario Municipal Employees Retirement System Fund (OMERS), a multiemployer, contributory, defined benefit public sector pension fund. OMERS provides retirement pension payments based on members’ length of service and salary. Both the participating employers and members are required to make plan contributions. The OMERS plan assets are pooled together to provide

16

HYDRO ONE INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

For the years ended December 31, 2014 and 2013

benefits to all plan participants and the plan assets are not segregated by member entity. OMERS is registered with the Financial Services Commission of Ontario under Registration #0345983. At December 31, 2013, OMERS had approximately 440,000 members, with approximately 335 members being current employees of Hydro One Brampton Networks and Norfolk Power.

The OMERS plan is accounted for as a defined contribution plan by Hydro One because it is not practicable to determine the present value of the Company’s obligation, the fair value of plan assets or the related current service cost applicable to Hydro One Brampton Networks and Norfolk Power employees. Hydro One recognizes its contributions to the OMERS plan as pension expense, with a portion being capitalized. The expensed amount is included in operation, maintenance and administration costs in the Consolidated Statements of Operations and Comprehensive Income.

Loss Contingencies

Hydro One is involved in certain legal and environmental matters that arise in the normal course of business. In the preparation of its Consolidated Financial Statements, management makes judgments regarding the future outcome of contingent events and records a loss for a contingency based on its best estimate when it is determined that such loss is probable and the amount of the loss can be reasonably estimated. Where the loss amount is recoverable in future rates, a regulatory asset is also recorded. When a range estimate for the probable loss exists and no amount within the range is a better estimate than any other amount, the Company records a loss at the minimum amount within the range.

Management regularly reviews current information available to determine whether recorded provisions should be adjusted and whether new provisions are required. Estimating probable losses may require analysis of multiple forecasts and scenarios that often depend on judgments about potential actions by third parties, such as federal, provincial and local courts or regulators. Contingent liabilities are often resolved over long periods of time. Amounts recorded in the Consolidated Financial Statements may differ from the actual outcome once the contingency is resolved. Such differences could have a material impact on future results of operations, financial position and cash flows of the Company.

Provisions are based upon current estimates and are subject to greater uncertainty where the projection period is lengthy. A significant upward or downward trend in the number of claims filed, the nature of the alleged injuries, and the average cost of resolving each claim could change the estimated provision, as could any substantial adverse or favourable verdict at trial. A federal or provincial legislative outcome or structured settlement could also change the estimated liability. Legal fees are expensed as incurred.

Environmental Liabilities

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

Asset Retirement Obligations

AROs are recorded for legal obligations associated with the future removal and disposal of long-lived assets. Such obligations may result from the acquisition, construction, development and/or normal use of the asset. Conditional AROs are recorded when there is a legal obligation to perform a future asset retirement activity but where the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the Company. In such a case, the obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and/or method of settlement.

17

HYDRO ONE INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

For the years ended December 31, 2014 and 2013

When recording an ARO, the present value of the estimated future expenditures required to complete the asset retirement activity is recorded in the period in which the obligation is incurred, if a reasonable estimate can be made. In general, the present value of the estimated future expenditures is added to the carrying amount of the associated asset and the resulting asset retirement cost is depreciated over the estimated useful life of the asset. Where an asset is no longer in service when an ARO is recorded, the asset retirement cost is recorded in results of operations.

Some of the Company’s transmission and distribution assets, particularly those located on unowned easements and rights-of-way, may have AROs, conditional or otherwise. The majority of the Company’s easements and rights-of-way are either of perpetual duration or are automatically renewed annually. Land rights with finite terms are generally subject to extension or renewal. As the Company expects to use the majority of its facilities in perpetuity, no ARO currently exists for these assets. If, at some future date, a particular facility is shown not to meet the perpetuity assumption, it will be reviewed to determine whether an estimable ARO exists. In such a case, an ARO would be recorded at that time.

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

3. NEW ACCOUNTING PRONOUNCEMENTS

Recently Adopted Accounting Pronouncements

In July 2013, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2013-11, Income Taxes (Topic 740): Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists. This ASU provides guidance on the presentation of unrecognized tax benefits. This ASU is effective for fiscal years, and interim periods within those years, beginning after December 15, 2013, and should be applied prospectively to all unrecognized tax benefits that exist at the effective date. The adoption of this ASU did not have a significant impact on the Company’s consolidated financial statements.

Recent Accounting Guidance Not Yet Adopted

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606). This ASU provides guidance on revenue recognition that depicts the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods and services. This ASU is required to be applied retrospectively and is effective for fiscal years, and interim periods within those years, beginning after December 15, 2016. The Company is currently assessing the impact of adoption of ASU 2014-09 on its consolidated financial statements.

In August 2014, the FASB issued ASU 2014-15, Presentation of Financial Statements – Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern. This ASU provides guidance about management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern and related disclosures. This ASU is effective for the annual period ending December 31, 2016, and for annual and interim periods thereafter. The adoption of this ASU is not anticipated to have a significant impact on the Company’s consolidated financial statements.

In November 2014, the FASB issued ASU 2014-16, Derivatives and Hedging (Topic 815). This ASU provides guidance on accounting for hybrid financial instruments issued in the form of a share. This ASU is effective for fiscal years, and interim periods within those years, beginning after December 15, 2015. The Company is currently assessing the impact of adoption of ASU 2014-16 on its consolidated financial statements.

18

HYDRO ONE INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

For the years ended December 31, 2014 and 2013

4. BUSINESS COMBINATIONS

B2M Limited Partnership

In 2012, Hydro One entered into an agreement with the Chippewas of Nawash First Nation and the Chippewas of Saugeen First Nation, collectively referred to as the Saugeen Ojibway Nation (SON), where a noncontrolling equity interest in Hydro One’s new limited partnership, B2M LP, would be made available for purchase at fair value by the SON. B2M LP was formed by Hydro One in 2013 to hold most of the transmission lines and a licence to use the related land. These assets are associated with Hydro One’s Bruce to Milton Transmission Reinforcement Project, an electricity transmission line (Bruce to Milton Line) in southwestern Ontario, from the Bruce Power facility in Kincardine to Hydro One’s Milton Switching Station in the Town of Milton. Hydro One Networks will maintain and operate the Bruce to Milton Line in accordance with an operation and management services agreement. In November 2013, the OEB issued a Decision and Order granting B2M LP a transmission licence and granting Hydro One Networks leave to sell the relevant Bruce to Milton Line transmission assets to B2M LP.

On December 16, 2014, the relevant Bruce to Milton Line transmission assets totalling $526 million were transferred from Hydro One Networks to B2M LP. This was financed by 60% debt ($316 million) and 40% equity ($210 million). On December 17, 2014, the SON acquired a 34.2% equity interest in B2M LP for consideration of $72 million, representing the fair value of the equity interest acquired.

Part of the SON’s equity interest in B2M LP is in Class B units of B2M LP that have a mandatory put option. The put option requires that upon the occurrence of an enforcement event (i.e. an event of default such as a debt default by the SON or insolvency event), the SON has the ability to require Hydro One to purchase the Class B units of B2M LP for net book value on the redemption date.

The noncontrolling interest relating to the Class B units is classified on the Consolidated Balance Sheet as temporary equity because the redemption feature is outside the control of the Company. The balance of the noncontrolling interest is classified within equity. At December 31, 2014, the total noncontrolling interest was reduced by the 2014 net loss attributable to noncontrolling interest totalling $2 million, including $1 million relating to noncontrolling interest subject to redemption.

Acquisition of Norfolk Power

On August 29, 2014, Hydro One acquired 100% of the common shares of Norfolk Power, an electricity distribution and telecom company located in southwestern Ontario. The total purchase price for Norfolk Power, net of the long-term debt assumed and adjusted for preliminary working capital and other closing adjustments, is approximately $68 million.

The following table summarizes the preliminary determination of the fair value of the assets acquired and liabilities assumed:

(millions of Canadian dollars)
Working capital	6
Property, plant and equipment	56
Deferred income tax assets	1
Goodwill	40
Bank indebtedness	(3	)
Derivative instruments	(3	)
Long-term debt	(26	)
Post-retirement and post-employment benefit liability	(1	)
Environmental liability	(1	)
Long-term accounts payable and other liabilities	(1	)
	68

The determination of the fair values of assets acquired and liabilities assumed has been based upon management’s estimates and certain assumptions with respect to the fair values of the assets acquired and liabilities assumed. The purchase agreement provides for final purchase price adjustments based on agreed working capital and other balances at the acquisition date which have not yet been finalized. The Company will continue to review information and perform further analysis prior to finalizing the total purchase price and therefore the actual total purchase price and the consequent impact on goodwill may differ from the amounts above.

19

HYDRO ONE INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

For the years ended December 31, 2014 and 2013

Goodwill of approximately $40 million arising from the Norfolk Power acquisition consists largely of the synergies and economies of scale expected from combining the operations of Hydro One and Norfolk Power. All of the goodwill was assigned to Hydro One’s Distribution Business segment. None of the goodwill recognized is expected to be deductible for income tax purposes.

Norfolk Power contributed revenues of $18 million and net income of less than $1 million to the Company’s consolidated financial results for the year ended December 31, 2014.

All costs related to the acquisition have been expensed through the Consolidated Statements of Operations and Comprehensive Income. The disclosure of Norfolk Power’s pro forma information is immaterial to the Company’s consolidated financial results for the year ended December 31, 2014.

Woodstock Hydro Purchase Agreement

On May 21, 2014, Hydro One reached an agreement with the City of Woodstock to acquire 100% of the common shares of Woodstock Hydro Holdings Inc. (Woodstock Hydro), an electricity distribution company located in southwestern Ontario. The acquisition is pending a regulatory decision from the OEB. The purchase price for Woodstock Hydro will be approximately $29 million, subject to final closing adjustments. The transaction is anticipated to be completed in 2015. In anticipation of the Woodstock Hydro acquisition, the Company made a refundable deposit totalling $2 million, which is recorded in prepaid expenses and other assets on the Consolidated Balance Sheet.

Haldimand Hydro Purchase Agreement

On June 10, 2014, Hydro One reached an agreement with Haldimand County to acquire 100% of the common shares of Haldimand County Utilities Inc. (Haldimand Hydro), an electricity distribution and telecom company located in southwestern Ontario. The acquisition is pending a regulatory decision from the OEB. The purchase price for Haldimand Hydro will be approximately $65 million, subject to final closing adjustments. The transaction is anticipated to be completed in 2015. In anticipation of the Haldimand Hydro acquisition, the Company made a refundable deposit totalling $3 million, which is recorded in prepaid expenses and other assets on the Consolidated Balance Sheet.

5. DEPRECIATION AND AMORTIZATION

Year ended December 31 (millions of Canadian dollars)	2014		2013
Depreciation of property, plant and equipment		565		533
Amortization of intangible assets		53		48
Asset removal costs		81		79
Amortization of regulatory assets		23		16
		722		676

6. FINANCING CHARGES

Year ended December 31 (millions of Canadian dollars)	2014			2013
Interest on long-term debt		432			416
Other		12			9
Less: Interest capitalized on construction and development in progress		(49	)		(51	)
Gain on interest-rate swap agreements		(10	)		(11	)
Interest earned on investments		(6	)		(3	)
		379			360

20

HYDRO ONE INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

For the years ended December 31, 2014 and 2013

7. PROVISION FOR PAYMENTS IN LIEU OF CORPORATE INCOME TAXES

The provision for PILs differs from the amount that would have been recorded using the combined Canadian federal and Ontario statutory income tax rate. The reconciliation between the statutory and the effective tax rates is provided as follows:

Year ended December 31 (millions of Canadian dollars)	2014			2013
Income before provision for PILs		836			912
Canadian federal and Ontario statutory income tax rate		26.50	%		26.50	%
Provision for PILs at statutory rate		222			242
Increase (decrease) resulting from:
Net temporary differences included in amounts charged to customers:
Capital cost allowance in excess of depreciation and amortization		(72	)		(72	)
Pension contributions in excess of pension expense		(24	)		(23	)
Overheads capitalized for accounting but deducted for tax purposes		(15	)		(14	)
Interest capitalized for accounting but deducted for tax purposes		(13	)		(13	)
Environmental expenditures		(5	)		(4	)
Prior year’s adjustments		(4	)		(8	)
Non-refundable investment tax credits		(3	)		(4	)
Post-retirement and post-employment benefit expense in excess of cash payments		3			4
Other		(1	)		(1	)
Net temporary differences		(134	)		(135	)
Net permanent differences		1			2
Total provision for PILs		89			109

The major components of income tax expense are as follows:

Year ended December 31 (millions of Canadian dollars)	2014			2013
Current provision for PILs		79			111
Deferred provision (recovery) for PILs		10			(2	)
Total provision for PILs		89			109
Effective income tax rate		10.63	%		11.98	%

The current provision for PILs is remitted to, or received from, the OEFC. At December 31, 2014, $39 million due from the OEFC was included in due from related parties on the Consolidated Balance Sheet (2013 – $29 million).

At December 31, 2014, the total provision for PILs includes deferred provision for PILs of $10 million (2013 – deferred recovery of $2 million) that is not included in the rate-setting process, using the liability method of accounting. Deferred PILs balances expected to be included in the rate-setting process are offset by regulatory assets and liabilities to reflect the anticipated recovery or disposition of these balances within future electricity rates.

21

HYDRO ONE INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

For the years ended December 31, 2014 and 2013

Deferred Income Tax Assets and Liabilities

Deferred income tax assets and liabilities arise from differences between the carrying amounts and tax basis of the Company’s assets and liabilities. At December 31, 2014 and 2013, deferred income tax assets and liabilities consisted of the following:

December 31 (millions of Canadian dollars)	2014			2013
Deferred income tax assets
Post-retirement and post-employment benefits expense in excess of cash payments		8			7
Environmental expenditures		4			5
Depreciation and amortization in excess of capital cost allowance		(4	)		—
Other		(1	)		(1	)
Total deferred income tax assets		7			11
Less: current portion		—			—
		7			11
December 31 (millions of Canadian dollars)	2014			2013
Deferred income tax liabilities
Capital cost allowance in excess of depreciation and amortization		(1,713	)		(1,556	)
Regulatory amounts that are not recognized for tax purposes		(140	)		(144	)
Partnership interest		(38	)		—
Goodwill		(21	)		(20	)
Post-retirement and post-employment benefits expense in excess of cash payments		559			542
Environmental expenditures		59			66
Other		—			1
Total deferred income tax liabilities		(1,294	)		(1,111	)
Less: current portion		19			18
		(1,313	)		(1,129	)

During 2014 and 2013, there were no changes in the rate applicable to future taxes.

8. ACCOUNTS RECEIVABLE

December 31 (millions of Canadian dollars)	2014			2013
Accounts receivable – billed		496			268
Accounts receivable – unbilled		586			691
Accounts receivable, gross		1,082			959
Allowance for doubtful accounts		(66	)		(36	)
Accounts receivable, net		1,016			923

The following table shows the movements in the allowance for doubtful accounts for the years ended December 31, 2014 and 2013:

Year ended December 31 (millions of Canadian dollars)	2014			2013
Allowance for doubtful accounts – January 1		(36	)		(23	)
Write-offs		24			24
Additions to allowance for doubtful accounts		(54	)		(37	)
Allowance for doubtful accounts – December 31		(66	)		(36	)

22

HYDRO ONE INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

For the years ended December 31, 2014 and 2013

9. PROPERTY, PLANT AND EQUIPMENT

December 31, 2014 (millions of Canadian dollars)	Property, Plant and Equipment		Accumulated Depreciation		Construction in Progress		Total
Transmission		13,209		4,416		626		9,419
Distribution		9,076		3,225		320		6,171
Communication		1,100		615		56		541
Administration and Service		1,502		793		23		732
Easements		623		85		—		538
		25,510		9,134		1,025		17,401
December 31, 2013 (millions of Canadian dollars)	Property, Plant and Equipment		Accumulated Depreciation		Construction in Progress		Total
Transmission		12,413		4,215		671		8,869
Distribution		8,498		3,046		316		5,768
Communication		1,060		560		53		553
Administration and Service		1,380		716		38		702
Easements		617		78		—		539
		23,968		8,615		1,078		16,431

Financing charges capitalized on property, plant and equipment under construction were $48 million in 2014 (2013 – $48 million).

10. INTANGIBLE ASSETS

December 31, 2014 (millions of Canadian dollars)	Intangible Assets		Accumulated Amortization		Development in Progress		Total
Computer applications software		573		303		3		273
Other		5		2		—		3
		578		305		3		276
December 31, 2013 (millions of Canadian dollars)	Intangible Assets		Accumulated Amortization		Development in Progress		Total
Computer applications software		557		249		3		311
Other		5		3		—		2
		562		252		3		313

Financing charges capitalized on intangible assets under development were $1 million in 2014 (2013 – $3 million). The estimated annual amortization expense for intangible assets is as follows: 2015 – $53 million; 2016 – $53 million; 2017 – $53 million; 2018 – $45 million; and 2019 – $31 million.

23

HYDRO ONE INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

For the years ended December 31, 2014 and 2013

11. REGULATORY ASSETS AND LIABILITIES

Regulatory assets and liabilities arise as a result of the rate-setting process. Hydro One has recorded the following regulatory assets and liabilities:

December 31 (millions of Canadian dollars)	2014		2013
Regulatory assets:
Deferred income tax regulatory asset		1,327		1,145
Pension benefit regulatory asset		1,236		845
Post-retirement and post-employment benefits		273		308
Environmental		239		266
Pension cost variance		90		80
DSC exemption		16		7
OEB cost assessment differential		12		9
Retail settlement variance accounts		11		—
Long-term project development costs		—		5
Other		27		18
Total regulatory assets		3,231		2,683
Less: current portion		31		47
		3,200		2,636
Regulatory liabilities:
Rider 11		83		55
External revenue variance		54		81
CDM deferral variance account		25		—
Deferred income tax regulatory liability		21		19
PST savings deferral		19		17
Hydro One Brampton Networks rider		2		8
Retail settlement variance accounts		—		35
Rider 9		—		19
Other		11		14
Total regulatory liabilities		215		248
Less: current portion		47		85
		168		163

Deferred Income Tax Regulatory Asset and Liability

Deferred income taxes are recognized on temporary differences between the carrying amount of assets and liabilities in the financial statements and the corresponding tax bases used in the computation of taxable profit. The Company has recognized regulatory assets and liabilities that correspond to deferred income taxes that flow through the rate-setting process. In the absence of rate-regulated accounting, the Company’s provision for PILs would have been recognized using the liability method and there would be no regulatory accounts established for taxes to be recovered through future rates. As a result, the 2014 provision for PILs would have been higher by approximately $132 million (2013 – $139 million).

Pension Benefit Regulatory Asset

The Company recognizes the net unfunded status of pension obligations on the Consolidated Balance Sheets with an offset to the associated regulatory asset. A regulatory asset is recognized because management considers it to be probable that pension benefit costs will be recovered in the future through the rate-setting process. The pension benefit obligation is remeasured to its fair value at each year end based on an annual actuarial report, with an offset to the associated regulatory asset, to the extent of the remeasurement adjustment. In the absence of rate-regulated accounting, 2014 OCI would have been lower by $391 million (2013 – higher by $670 million).

24

HYDRO ONE INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

For the years ended December 31, 2014 and 2013

Post-Retirement and Post-Employment Benefits

The Company recognizes the net unfunded status of post-retirement and post-employment obligations on the Consolidated Balance Sheets with an incremental offset to the associated regulatory assets. A regulatory asset is recognized because management considers it to be probable that post-retirement and post-employment benefit costs will be recovered in the future through the rate-setting process. The post-retirement and post-employment benefit obligation is remeasured to its fair value at each year end based on an annual actuarial report, with an offset to the associated regulatory asset, to the extent of the remeasurement adjustment. In the absence of rate-regulated accounting, 2014 OCI would have been higher by $35 million (2013 – $12 million).

Environmental

Hydro One records a liability for the estimated future expenditures required to remediate environmental contamination. Because such expenditures are expected to be recoverable in future rates, the Company has recorded an equivalent amount as a regulatory asset. In 2014, the environmental regulatory asset decreased by $33 million (2013 – $3 million) to reflect related changes in the Company’s PCB liability, and increased by $13 million (2013 – $26 million) due to changes in the LAR liability. The environmental regulatory asset is amortized to results of operations based on the pattern of actual expenditures incurred and charged to environmental liabilities. The OEB has the discretion to examine and assess the prudency and the timing of recovery of all of Hydro One’s actual environmental expenditures. In the absence of rate-regulated accounting, 2014 operation, maintenance and administration expenses would have been lower by $20 million (2013 – higher by $23 million). In addition, 2014 amortization expense would have been lower by $18 million (2013 – $16 million), and 2014 financing charges would have been higher by $11 million (2013 – $10 million).

Pension Cost Variance

A pension cost variance account was established for Hydro One Networks’ transmission and distribution businesses to track the difference between the actual pension expenses incurred and estimated pension costs approved by the OEB. The balance in this regulatory account reflects the excess of pension costs paid as compared to OEB-approved amounts. In the absence of rate-regulated accounting, 2014 revenue would have been lower by $10 million (2013 – $19 million).

DSC Exemption

In June 2010, Hydro One Networks filed an application with the OEB regarding the OEB’s new cost responsibility rules contained in the OEB’s October 2009 Notice of Amendment to the Distribution System Code (DSC), with respect to the connection of certain renewable generators that were already connected or that had received a connection impact assessment prior to October 21, 2009. The application sought approval to record and defer the unanticipated costs incurred by Hydro One Networks that resulted from the connection of certain renewable generation facilities. The OEB ruled that identified specific expenditures can be recorded in a deferral account subject to the OEB’s review until the next Hydro One Networks’ distribution cost-of-service application. This program effectively ended at the end of 2014 with no new principal to be recorded in 2015.

OEB Cost Assessment Differential

In April 2010, the OEB issued its Decision regarding Hydro One Networks’ distribution rate application for 2010 and 2011. As part of this decision, the OEB also approved the distribution-related OEB Cost Assessment Differential Account to record the difference between the amounts approved in rates and actual expenditures with respect to the OEB’s cost assessments. This continued for 2012-2014 until the next Hydro One Networks’ distribution cost-of-service application, which was submitted in 2014. This program effectively ended at the end of 2014 with no new activity to be recorded in 2015.

Retail Settlement Variance Accounts (RSVAs)

Hydro One has deferred certain retail settlement variance amounts under the provisions of Article 490 of the OEB’s Accounting Procedures Handbook. In December 2012, the OEB approved the disposition of the total RSVA balance accumulated from January 2010 to December 2011, including accrued interest, to be disposed over a 24-month period from January 1, 2013 to December 31, 2014. At December 31, 2014, the RSVA was in a net asset position due to a change in global adjustment.

25

HYDRO ONE INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

For the years ended December 31, 2014 and 2013

Long-Term Project Development Costs

In May 2009, the OEB approved the creation of a deferral account to record Hydro One Networks’ costs of preliminary work to advance certain transmission projects identified in the Company’s 2009 and 2010 transmission rate applications. In March 2010, the OEB issued a decision amending the scope of the account to include the 20 major transmission projects identified in the September 2009 request from the Ministry of Energy and Infrastructure. In December 2012, the OEB approved the recovery of the December 31, 2012 balance, including accrued interest, to be recovered over a one-year period from January 1, 2014 to December 31, 2014.

Rider 11

In April 2010, the OEB requested the establishment of deferral accounts which capture the difference between the revenue recorded on the basis of Green Energy Plan expenditures incurred and the actual recoveries received. Rider 11 includes amounts previously included as Rider 8.

External Revenue Variance

In May 2009, the OEB approved forecasted amounts related to export service revenue, external revenue from secondary land use, and external revenue from station maintenance and engineering and construction work. In November 2012, the OEB again approved forecasted amounts related to these revenue categories and extended the scope to encompass all other external revenues. The external revenue variance account balance reflects the excess of actual external revenues compared to the OEB-approved forecasted amounts.

CDM Deferral Variance Account

As part of Hydro One Networks’ application for 2013 and 2014 transmission rates, Hydro One agreed to establish a new regulatory deferral variance account to track the impact of actual Conservation and Demand Management (CDM) and demand response results on the load forecast compared to the estimated load forecast included in the revenue requirement. The balance in the CDM deferral variance account relates to the actual 2013 CDM compared to the amounts included in 2013 revenue requirement. The OEB rate order specifically states that the Ontario Power Authority (OPA) data used to calculate the difference between forecasted and actual savings will be provided one year in arrears, and as a result, no amount should be recorded in advance of notification from the OPA of actual results. This notification from the OPA typically occurs in September of each year.

PST Savings Deferral Account

The provincial sales tax (PST) and goods and services tax (GST) were harmonized in July 2010. Unlike the GST, the PST was included in operation, maintenance and administration expenses or capital expenditures for past revenue requirements approved during a full cost-of-service hearing. Under the harmonized sales tax (HST) regime, the HST included in operation, maintenance and administration expenses or capital expenditures is not a cost ultimately borne by the Company and as such, a refund of the prior PST element in the approved revenue requirement is applicable, and calculations for tracking and refund were requested by the OEB. For Hydro One Networks’ transmission revenue requirement, PST was included between July 1, 2010 and December 31, 2010 and recorded in a deferral account, per direction from the OEB. For Hydro One Networks’ distribution revenue requirement, PST was included between July 1, 2010 and December 31, 2014 and recorded in a deferral account, per direction from the OEB.

Hydro One Brampton Networks Rider

In December 2013, the OEB issued a decision for Hydro One Brampton Networks’ 2014 distribution rates. Included in the OEB’s decision was the approval of certain deferral account balances, primarily RSVAs. The OEB ordered that the approved balances be aggregated into a single regulatory account and disposed of through a rate rider over a two-year period from January 1, 2014 to December 31, 2015.

26

HYDRO ONE INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

For the years ended December 31, 2014 and 2013

Rider 9

In December 2012, as part of Hydro One Networks’ 2013 IRM distribution rate application, the OEB approved for disposition certain distribution-related deferral account balances, including RSVA amounts and balances of Rider 2 and Rider 3, accumulated up to December 2011, including accrued interest, to be disposed over a 24-month period from January 1, 2013 to December 31, 2014.

12. DEBT AND CREDIT AGREEMENTS

Short-Term Notes

Hydro One meets its short-term liquidity requirements in part through the issuance of commercial paper under its Commercial Paper Program which has a maximum authorized amount of $1,000 million. These short-term notes are denominated in Canadian dollars with varying maturities not exceeding 365 days. Hydro One had no commercial paper borrowings outstanding as at December 31, 2014 and 2013.

Hydro One has a $1,500 million committed and unused revolving standby credit facility with a syndicate of banks, maturing in June 2019. If used, interest on the facility would apply based on Canadian benchmark rates. This credit facility is unsecured and supports the Company’s Commercial Paper Program. The Company may use the credit facility for general corporate purposes, including meeting short-term funding requirements. The obligation of each lender to make any credit extension to the Company under its credit facility is subject to various conditions including, among other things, that no event of default has occurred or would result from such credit extension.

Long-Term Debt

The Company issues notes for long-term financing under its Medium-Term Note (MTN) Program. The maximum authorized principal amount of notes issuable under this program is $3,000 million. At December 31, 2014, $1,187 million remained available for issuance until October 2015.

27

HYDRO ONE INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

For the years ended December 31, 2014 and 2013

The following table presents the outstanding long-term debt at December 31, 2014 and 2013:

December 31 (millions of Canadian dollars)	2014			2013
3.13% Series 19 notes due 20141		—			750
2.95% Series 21 notes due 20151		500			500
Floating-rate Series 22 notes due 20152		50			50
4.64% Series 10 notes due 2016		450			450
Floating-rate Series 27 notes due 20162		50			50
5.18% Series 13 notes due 2017		600			600
2.78% Series 28 notes due 2018		750			750
Floating-rate Series 31 notes due 20192		228			—
4.40% Series 20 notes due 2020		300			300
3.20% Series 25 notes due 2022		600			600
7.35% Debentures due 2030		400			400
6.93% Series 2 notes due 2032		500			500
6.35% Series 4 notes due 2034		385			385
5.36% Series 9 notes due 2036		600			600
4.89% Series 12 notes due 2037		400			400
6.03% Series 17 notes due 2039		300			300
5.49% Series 18 notes due 2040		500			500
4.39% Series 23 notes due 2041		300			300
6.59% Series 5 notes due 2043		315			315
4.59% Series 29 notes due 2043		435			435
4.17% Series 32 notes due 2044		350			—
5.00% Series 11 notes due 2046		325			325
4.00% Series 24 notes due 2051		225			225
3.79% Series 26 notes due 2062		310			310
4.29% Series 30 notes due 2064		50			—
		8,923			9,045
Add: Unrealized mark-to-market loss1		2			12
Less: Long-term debt payable within one year		(552	)		(756	)
Long-term debt		8,373			8,301

¹  The unrealized mark-to-market loss relates to $250 million of the Series 21 notes due 2015 (2013 – $500 million of the Series 19 notes due 2014, and $250 million of the Series 21 notes due 2015). The unrealized mark-to-market loss is offset by a $2 million (2013 – $12 million) unrealized mark-to-market gain on the related fixed-to-floating interest-rate swap agreements, which are accounted for as fair value hedges. See Note 13 – Fair Value of Financial Instruments and Risk Management for details of fair value hedges.

²  The interest rates of the floating-rate notes are referenced to the 3-month Canadian dollar bankers’ acceptance rate, plus a margin.

In 2014, Hydro One issued $628 million (2013 – $1,185 million) of long-term debt under the MTN Program, and repaid the $750 million MTN Series 19 notes (2013 – repaid $600 million MTN Series 15 notes). In addition, the Company repaid long-term debt totalling $26 million assumed on the Norfolk Power acquisition.

The long-term debt is unsecured and denominated in Canadian dollars. The long-term debt is summarized by the number of years to maturity in Note 13 – Fair Value of Financial Instruments and Risk Management.

13. FAIR VALUE OF FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

Fair value is considered to be the exchange price in an orderly transaction between market participants to sell an asset or transfer a liability at the measurement date. The fair value definition focuses on an exit price, which is the price that would be received in the sale of an asset or the amount that would be paid to transfer a liability.

28

HYDRO ONE INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

For the years ended December 31, 2014 and 2013

Hydro One classifies its fair value measurements based on the following hierarchy, as prescribed by the accounting guidance for fair value, which prioritizes the inputs to valuation techniques used to measure fair value into three levels:

Level 1 inputs are unadjusted quoted prices in active markets for identical assets or liabilities that Hydro One has the ability to access. An active market for the asset or liability is one in which transactions for the asset or liability occur with sufficient frequency and volume to provide ongoing pricing information.

Level 2 inputs are those other than quoted market prices that are observable, either directly or indirectly, for an asset or liability. Level 2 inputs include, but are not limited to, quoted prices for similar assets or liabilities in an active market, quoted prices for identical or similar assets or liabilities in markets that are not active and inputs other than quoted market prices that are observable for the asset or liability, such as interest-rate curves and yield curves observable at commonly quoted intervals, volatilities, credit risk and default rates. A Level 2 measurement cannot have more than an insignificant portion of the valuation based on unobservable inputs.

Level 3 inputs are any fair value measurements that include unobservable inputs for the asset or liability for more than an insignificant portion of the valuation. A Level 3 measurement may be based primarily on Level 2 inputs.

Non-Derivative Financial Assets and Liabilities

At December 31, 2014 and 2013, the Company’s carrying amounts of accounts receivable, due from related parties, cash and cash equivalents, bank indebtedness, accounts payable, and due to related parties are representative of fair value because of the short-term nature of these instruments.

Fair Value Measurements of Long-Term Debt

The fair values and carrying values of the Company’s long-term debt at December 31, 2014 and 2013 are as follows:

December 31 (millions of Canadian dollars)	2014 Carrying Value		2014 Fair Value		2013 Carrying Value		2013 Fair Value
Long-term debt
$500 million of MTN Series 19 notes1		—		—		506		506
$250 million of MTN Series 21 notes1		252		252		256		256
Other notes and debentures2		8,673		10,159		8,295		9,018
		8,925		10,411		9,057		9,780

¹  The fair value of $500 million of the MTN Series 19 notes and of $250 million of the MTN Series 21 notes subject to hedging is primarily based on changes in the present value of future cash flows due to a change in the yield in the swap market for the related swap (hedged risk).

² The fair value of other notes and debentures, and the portions of the MTN Series 19 notes and the MTN Series 21 notes that are not subject to hedging, represents the market value of the notes and debentures and is based on unadjusted period-end market prices for the same or similar debt of the same remaining maturities.

Fair Value Measurements of Derivative Instruments

At December 31, 2014, the Company had interest-rate swaps totalling $250 million (2013 – $750 million) that were used to convert fixed-rate debt to floating-rate debt. These swaps are classified as fair value hedges. The Company’s fair value hedge exposure was equal to about 3% (2013 – 8%) of its total long-term debt of $8,925 million (2013 – $9,057 million). At December 31, 2014, the Company had the following interest-rate swaps designated as fair value hedges:

(a) two $125 million fixed-to-floating interest-rate swap agreements to convert $250 million of the $500 million MTN Series 21 notes maturing September 11, 2015 into three-month variable-rate debt.

At December 31, 2014, the Company also had interest-rate swaps with a total notional value of $409 million (2013 – $900 million) classified as undesignated contracts. The undesignated contracts consist of the following interest-rate swaps:

(b) a $150 million floating-to-fixed interest-rate swap agreement that locks in the floating rate the Company pays on a portion of the above fixed-to-floating interest-rate swaps from December 11, 2014 to September 11, 2015;

29

HYDRO ONE INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

For the years ended December 31, 2014 and 2013

(c) a $50 million floating-to-fixed interest-rate swap agreement that locks in the floating rate the Company pays on the $50 million floating-rate MTN Series 22 notes from January 24, 2014 to January 24, 2015;

(d) a $137 million floating-to-fixed interest-rate swap agreement that locks in the floating rate the Company pays on the $228 million floating-rate MTN Series 31 notes from December 22, 2014 to December 21, 2015;

(e) a $30 million floating-to-fixed interest-rate swap agreement that locks in the floating rate the Company pays on the $50 million floating-rate MTN Series 27 notes from March 3, 2015 to December 3, 2015;

(f) a $30 million floating-to-fixed interest-rate swap agreement that locks in the floating rate the Company pays on the $50 million floating-rate MTN Series 22 notes from January 26, 2015 to July 24, 2015; and

(g) three interest-rate swaps with a total notional value of $12 million that were assumed as part of the Norfolk Power acquisition. These swaps consist of $8 million and $2 million floating-to-fixed interest-rate swap agreements maturing on September 20, 2029, and a $2 million floating-to-fixed interest-rate swap agreement maturing on September 20, 2019.

Fair Value Hierarchy

The fair value hierarchy of financial assets and liabilities at December 31, 2014 and 2013 is as follows:

December 31, 2014 (millions of Canadian dollars)	Carrying Value		Fair Value		Level 1		Level 2		Level 3
Assets:
Cash and cash equivalents		100		100		100		—		—
Derivative instruments
Fair value hedges – interest-rate swaps		2		2		—		2		—
		102		102		100		2		—
Liabilities:
Bank indebtedness		2		2		2		—		—
Derivative instruments
Undesignated contracts – interest-rate swaps		3		3		—		3		—
Long-term debt		8,925		10,411		—		10,411		—
		8,930		10,416		2		10,414		—
December 31, 2013 (millions of Canadian dollars)	Carrying Value		Fair Value		Level 1		Level 2		Level 3
Assets:
Cash and cash equivalents		565		565		565		—		—
Investment		251		251		—		251		—
Derivative instruments
Fair value hedges – interest-rate swaps		12		12		—		12		—
		828		828		565		263		—
Liabilities:
Bank indebtedness		31		31		31		—		—
Long-term debt		9,057		9,780		—		9,780		—
		9,088		9,811		31		9,780		—

Cash and cash equivalents include cash and short-term investments. At December 31, 2014, short-term investments consisted of bankers’ acceptances and money market funds totalling $nil (2013 – $515 million). The carrying values are representative of fair value because of the short-term nature of these instruments.

30

HYDRO ONE INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

For the years ended December 31, 2014 and 2013

The investment at December 31, 2013 represented the Province of Ontario Floating-Rate Notes that matured in November 2014. The fair value of the investment was determined using inputs other than quoted prices that are observable for the asset, with unrecognized gains or losses recognized in financing charges. The Company obtained quotes from an independent third party for the fair value of the investment, who uses the market price of similar securities adjusted for changes in observable inputs such as maturity dates and interest rates.

The fair value of the derivative instruments is determined using inputs other than quoted prices that are observable for these assets. The fair value is primarily based on the present value of future cash flows using a swap yield curve to determine the assumptions for interest rates.

The fair value of the hedged portion of the long-term debt is primarily based on the present value of future cash flows using a swap yield curve to determine the assumption for interest rates. The fair value of the unhedged portion of the long-term debt is based on unadjusted period-end market prices for the same or similar debt of the same remaining maturities.

There were no significant transfers between any of the fair value levels during the years ended December 31, 2014 and 2013.

Risk Management

Exposure to market risk, credit risk and liquidity risk arises in the normal course of the Company’s business.

Market Risk

Market risk refers primarily to the risk of loss that results from changes in commodity prices, foreign exchange rates and interest rates. The Company does not have commodity risk. The Company does have foreign exchange risk as it enters into agreements to purchase materials and equipment associated with capital programs and projects that are settled in foreign currencies. This foreign exchange risk is not material, although the Company could in the future decide to issue foreign currency-denominated debt which would be hedged back to Canadian dollars consistent with its risk management policy. Hydro One is exposed to fluctuations in interest rates as the regulated rate of return for the Company’s Transmission and Distribution Businesses is derived using a formulaic approach that is based on the forecast for long-term Government of Canada bond yields and the spread in 30-year “A”-rated Canadian utility bonds over the 30-year benchmark Government of Canada bond yield. The Company estimates that a 1% decrease in the forecasted long-term Government of Canada bond yield or the “A”-rated Canadian utility spread used in determining the Company’s rate of return would reduce the Transmission Business’ 2014 annual results of operations by approximately $20 million (2013 – $19 million) and Hydro One Networks’ distribution business’ 2014 annual results of operations by approximately $10 million (2013 – $10 million).

The Company uses a combination of fixed and variable-rate debt to manage the mix of its debt portfolio. The Company also uses derivative financial instruments to manage interest-rate risk. The Company utilizes interest-rate swaps, which are typically designated as fair value hedges, as a means to manage its interest rate exposure to achieve a lower cost of debt. In addition, the Company may utilize interest-rate derivative instruments to lock in interest-rate levels in anticipation of future financing. Hydro One may also enter into derivative agreements such as forward-starting pay fixed-interest-rate swap agreements to hedge against the effect of future interest-rate movements on long-term fixed-rate borrowing requirements. Such arrangements are typically designated as cash flow hedges. No cash flow hedge agreements were in existence as at December 31, 2014 or 2013.

A hypothetical 10% increase in the interest rates associated with variable-rate debt would not have resulted in a significant decrease in Hydro One’s results of operations for the years ended December 31, 2014 or 2013.

31

HYDRO ONE INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

For the years ended December 31, 2014 and 2013

Fair Value Hedges

For derivative instruments that are designated and qualify as fair value hedges, the gain or loss on the derivative as well as the offsetting loss or gain on the hedged item attributable to the hedged risk are recognized in the Consolidated Statements of Operations and Comprehensive Income. The net unrealized loss (gain) on the hedged debt and the related interest-rate swaps for the years ended December 31, 2014 and 2013 are included in financing charges as follows:

Year ended December 31 (millions of Canadian dollars)	2014			2013
Unrealized loss (gain) on hedged debt		(3	)		(8	)
Unrealized loss (gain) on fair value interest-rate swaps		3			8
Net unrealized loss (gain)		—			—

At December 31, 2014, Hydro One had $250 million (2013 – $750 million) of notional amounts of fair value hedges outstanding related to interest-rate swaps, with assets at fair value of $2 million (2013 – $12 million). During the years ended December 31, 2014 and 2013, there was no significant impact on the results of operations as a result of any ineffectiveness attributable to fair value hedges.

Credit Risk

Financial assets create a risk that a counterparty will fail to discharge an obligation, causing a financial loss. At December 31, 2014 and 2013, there were no significant concentrations of credit risk with respect to any class of financial assets. The Company’s revenue is earned from a broad base of customers. As a result, Hydro One did not earn a significant amount of revenue from any single customer. At December 31, 2014 and 2013, there was no significant accounts receivable balance due from any single customer.

At December 31, 2014, the Company’s provision for bad debts was $66 million (2013 – $36 million). Adjustments and write-offs were determined on the basis of a review of overdue accounts, taking into consideration historical experience. At December 31, 2014, approximately 6% of the Company’s net accounts receivable were aged more than 60 days (2013 – 4%).

Hydro One manages its counterparty credit risk through various techniques including: entering into transactions with highly-rated counterparties; limiting total exposure levels with individual counterparties consistent with the Company’s Board-approved Credit Risk Policy; entering into master agreements which enable net settlement and the contractual right of offset; and monitoring the financial condition of counterparties. In addition to payment netting language in master agreements, the Company establishes credit limits, margining thresholds and collateral requirements for each counterparty. Counterparty credit limits are based on an internal credit review that considers a variety of factors, including the results of a scoring model, leverage, liquidity, profitability, credit ratings and risk management capabilities. The determination of credit exposure for a particular counterparty is the sum of current exposure plus the potential future exposure with that counterparty. The current exposure is calculated as the sum of the principal value of money market exposures and the market value of all contracts that have a positive mark-to-market position on the measurement date. The Company would offset the positive market values against negative values with the same counterparty only where permitted by the existence of a legal netting agreement such as an International Swap Dealers Association master agreement. The potential future exposure represents a safety margin to protect against future fluctuations of interest rates, currencies, equities, and commodities. It is calculated based on factors developed by the Bank of International Settlements, following extensive historical analysis of random fluctuations of interest rates and currencies. To the extent that a counterparty’s margining thresholds are exceeded, the counterparty is required to post collateral with the Company as specified in each agreement. The Company monitors current and forward credit exposure to counterparties both on an individual and an aggregate basis. The Company’s credit risk for accounts receivable is limited to the carrying amounts on the Consolidated Balance Sheets.

Derivative financial instruments result in exposure to credit risk since there is a risk of counterparty default. The credit exposure of derivative contracts, before collateral, is represented by the fair value of contracts at the reporting date. At December 31, 2014, the counterparty credit risk exposure on the fair value of these interest-rate swap contracts was $3 million (2013 – $14 million). At December 31, 2014, Hydro One’s credit exposure for all derivative instruments, and applicable payables and receivables, had a credit rating of investment grade, with five financial institutions as the counterparties. The credit exposure of three of the five counterparties accounted for more than 10% of the total credit exposure of derivative contracts.

Liquidity Risk

Liquidity risk refers to the Company’s ability to meet its financial obligations as they come due. Hydro One meets its short-term liquidity requirements using cash and cash equivalents on hand, funds from operations, the issuance of commercial paper, and the revolving standby credit facility of $1,500 million. The short-term liquidity under the Commercial Paper Program, and anticipated levels of funds from operations should be sufficient to fund normal operating requirements.

32

HYDRO ONE INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

For the years ended December 31, 2014 and 2013

At December 31, 2014, accounts payable and accrued liabilities in the amount of $784 million (2013 – $789 million) were expected to be settled in cash at their carrying amounts within the next 12 months.

At December 31, 2014, Hydro One had issued long-term debt in the principal amount of $8,923 million (2013 – $9,045 million). Principal repayments, interest payments and related weighted average interest rates are summarized by the number of years to maturity in the following table:

	Long-term Debt Principal Repayments		Interest Payments		Weighted Average Interest Rate
Years to Maturity	(millions of Canadian dollars)		(millions of Canadian dollars)		(%)
1 year		550		419		2.8
2 years		500		393		4.3
3 years		600		381		5.2
4 years		750		350		2.8
5 years		228		327		1.6
		2,628		1,870		3.5
6 – 10 years		900		1,522		3.6
Over 10 years		5,395		4,373		5.4
		8,923		7,765		4.7

14. CAPITAL MANAGEMENT

The Company’s objectives with respect to its capital structure are to maintain effective access to capital on a long-term basis at reasonable rates, and to deliver appropriate financial returns. In order to ensure ongoing effective access to capital, the Company targets to maintain an “A” category long-term credit rating.

The Company considers its capital structure to consist of Shareholder’s equity, preferred shares, long-term debt, and cash and cash equivalents. At December 31, 2014 and 2013, the Company’s capital structure was as follows:

December 31 (millions of Canadian dollars)	2014		2013
Long-term debt payable within one year		552		756
Less: cash and cash equivalents		100		565
		452		191
Long-term debt		8,373		8,301
Preferred shares		323		323
Common shares		3,314		3,314
Retained earnings		4,249		3,787
		7,563		7,101
Total capital		16,711		15,916

The Company has customary covenants typically associated with long-term debt. Among other things, Hydro One’s long-term debt and credit facility covenants limit the permissible debt to 75% of the Company’s total capitalization, limit the ability to sell assets and impose a negative pledge provision, subject to customary exceptions. At December 31, 2014 and 2013, Hydro One was in compliance with all of these covenants and limitations.

33

HYDRO ONE INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

For the years ended December 31, 2014 and 2013

15. PENSION AND POST-RETIREMENT AND POST-EMPLOYMENT BENEFITS

Hydro One has a defined benefit pension plan, a supplementary pension plan, and post-retirement and post-employment benefit plans. The defined benefit pension plan (Pension Plan) is contributory and covers all regular employees of Hydro One and its subsidiaries, except employees of Hydro One Brampton Networks and Norfolk Power. Employees of Hydro One Brampton Networks and Norfolk Power participate in the OMERS plan. The supplementary pension plan provides members of the Pension Plan with benefits that would have been earned and payable under the Pension Plan but for the limitations imposed by the Income Tax Act (Canada). The supplementary pension plan obligation is included with other post-retirement and post-employment benefit obligations on the Consolidated Balance Sheets.

The OMERS Plan

Hydro One contributions to the OMERS plan for the year ended December 31, 2014 were $2 million (2013 – $2 million). Company contributions payable at December 31, 2014 and included in accrued liabilities on the Consolidated Balance Sheets were less than $1 million (2013 – less than $1 million). Hydro One contributions do not represent more than 5% of total contributions to the OMERS plan, as indicated in OMERS’ most recently available annual report for the year ended December 31, 2013.

At December 31, 2013, the OMERS plan was 88.2% funded, with an unfunded liability of $8,641 million. This unfunded liability could result in future payments by participating employers and members. Hydro One future contributions could be increased substantially if other entities withdraw from the plan.

Pension Plan, Post-Retirement and Post-Employment Plans

The Pension Plan provides benefits based on highest three-year average pensionable earnings. For new management employees who commenced employment on or after January 1, 2004, and for new Society of Energy Professionals-represented staff hired after November 17, 2005, benefits are based on highest five-year average pensionable earnings. After retirement, pensions are indexed to inflation.

Company and employee contributions to the Pension Plan are based on actuarial valuations performed at least every three years. Annual Pension Plan contributions for 2014 of $174 million (2013 – $160 million) were based on an actuarial valuation effective December 31, 2013 (2013 – effective December 31, 2011) and the expected level of pensionable earnings. Estimated annual Pension Plan contributions for 2015 and 2016 are approximately $174 million and $175 million, respectively, based on the actuarial valuation as at December 31, 2013 and projected levels of pensionable earnings. Future minimum contributions beyond 2016 will be based on an actuarial valuation effective no later than December 31, 2016. Contributions are payable one month in arrears. All of the contributions are expected to be in the form of cash.

Hydro One recognizes the overfunded or underfunded status of the Pension Plan, and post-retirement and post-employment benefit plans (Plans) as an asset or liability on its Consolidated Balance Sheets, with offsetting regulatory assets and liabilities as appropriate. The underfunded benefit obligations for the Plans, in the absence of regulatory accounting, would be recognized in AOCI. The impact of changes in assumptions used to measure pension, post-retirement and post-employment benefit obligations is generally recognized over the expected average remaining service period of the employees. The measurement date for the Plans is December 31.

34

HYDRO ONE INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

For the years ended December 31, 2014 and 2013

	Pension Benefits						Post-Retirement and Post-Employment Benefits
Year ended December 31 (millions of Canadian dollars)	2014			2013			2014			2013
Change in projected benefit obligation
Projected benefit obligation, beginning of year		6,576			6,507			1,531			1,459
Current service cost		145			170			41			40
Interest cost		312			278			73			63
Reciprocal transfers		—			1			—			—
Benefits paid		(319	)		(317	)		(45	)		(44	)
Net actuarial loss (gain)		821			(63	)		(18	)		13
Projected benefit obligation, end of year		7,535			6,576			1,582			1,531
Change in plan assets
Fair value of plan assets, beginning of year		5,731			4,992			—			—
Actual return on plan assets		703			887			—			—
Reciprocal transfers		—			1			—			—
Benefits paid		(319	)		(317	)		—			—
Employer contributions		174			160			—			—
Employee contributions		35			30			—			—
Administrative expenses		(25	)		(22	)		—			—
Fair value of plan assets, end of year		6,299			5,731			—			—
Unfunded status		1,236			845			1,582			1,531

Hydro One presents its benefit obligations and plan assets net on its Consolidated Balance Sheets within the following line items:

	Pension Benefits				Post-Retirement and Post-Employment Benefits
December 31 (millions of Canadian dollars)	2014		2013		2014		2013
Accrued liabilities		—		—		49		43
Pension benefit liability		1,236		845		—		—
Post-retirement and post-employment benefit liability		—		—		1,533		1,488
Unfunded status		1,236		845		1,582		1,531

The funded or unfunded status of the pension, post-retirement and post-employment benefit plans refers to the difference between the fair value of plan assets and the projected benefit obligations for the Plans. The funded/unfunded status changes over time due to several factors, including contribution levels, assumed discount rates and actual returns on plan assets.

The following table provides the projected benefit obligation (PBO), accumulated benefit obligation (ABO) and fair value of plan assets for the Pension Plan:

December 31 (millions of Canadian dollars)	2014		2013
PBO		7,535		6,576
ABO		6,887		5,998
Fair value of plan assets		6,299		5,731

On an ABO basis, the Pension Plan was funded at 91% at December 31, 2014 (2013 – 96%). On a PBO basis, the Pension Plan was funded at 84% at December 31, 2014 (2013 – 87%). The ABO differs from the PBO in that the ABO includes no assumption about future compensation levels.

35

HYDRO ONE INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

For the years ended December 31, 2014 and 2013

Components of Net Periodic Benefit Costs

The following table provides the components of the net periodic benefit costs for the years ended December 31, 2014 and 2013 for the Pension Plan:

Year ended December 31 (millions of Canadian dollars)	2014			2013
Current service cost, net of employee contributions		110			141
Interest cost		312			278
Expected return on plan assets, net of expenses		(369	)		(309	)
Actuarial loss amortization		103			175
Prior service cost amortization		2			2
Net periodic benefit costs		158			287
Charged to results of operations1		81			72

¹ The Company follows the cash basis of accounting consistent with the inclusion of pension costs in OEB-approved rates. During the year ended December 31, 2014, pension costs of $174 million (2013 – $160 million) were attributed to labour, of which $81 million (2013 – $72 million) was charged to operations, and $93 million (2013 – $88 million) was capitalized as part of the cost of property, plant and equipment and intangible assets.

The following table provides the components of the net periodic benefit costs for the years ended December 31, 2014 and 2013 for the post-retirement and post-employment benefit plans:

Year ended December 31 (millions of Canadian dollars)	2014		2013
Current service cost, net of employee contributions		41		40
Interest cost		73		63
Actuarial loss amortization		18		27
Prior service cost amortization		2		3
Net periodic benefit costs		134		133
Charged to results of operations		62		58

Assumptions

The measurement of the obligations of the Plans and the costs of providing benefits under the Plans involves various factors, including the development of valuation assumptions and accounting policy elections. When developing the required assumptions, the Company considers historical information as well as future expectations. The measurement of benefit obligations and costs is impacted by several assumptions including the discount rate applied to benefit obligations, the long-term expected rate of return on plan assets, Hydro One’s expected level of contributions to the Plans, the incidence of mortality, the expected remaining service period of plan participants, the level of compensation and rate of compensation increases, employee age, length of service, and the anticipated rate of increase of health care costs, among other factors. The impact of changes in assumptions used to measure the obligations of the Plans is generally recognized over the expected average remaining service period of the plan participants. In selecting the expected rate of return on plan assets, Hydro One considers historical economic indicators that impact asset returns, as well as expectations regarding future long-term capital market performance, weighted by target asset class allocations. In general, equity securities, real estate and private equity investments are forecasted to have higher returns than fixed-income securities.

36

HYDRO ONE INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

For the years ended December 31, 2014 and 2013

The following weighted average assumptions were used to determine the benefit obligations at December 31, 2014 and 2013:

	Pension Benefits						Post-Retirement and Post-Employment Benefits
Year ended December 31	2014			2013			2014			2013
Significant assumptions:
Weighted average discount rate		4.00	%		4.75	%		4.00	%		4.75	%
Rate of compensation scale escalation (without merit)		2.50	%		2.50	%		2.50	%		2.50	%
Rate of cost of living increase		2.00	%		2.00	%		2.00	%		2.00	%
Rate of increase in health care cost trends1		—			—			4.36	%		4.39	%

¹ 6.52% per annum in 2015, grading down to 4.36% per annum in and after 2031 (2013 – 6.81% in 2014, grading down to 4.39% per annum in and after 2031)

The following weighted average assumptions were used to determine the net periodic benefit costs for the years ended December 31, 2014 and 2013. Assumptions used to determine current year-end benefit obligations are the assumptions used to estimate the subsequent year’s net periodic benefit costs.

Year ended December 31	2014			2013
Pension Benefits:
Weighted average expected rate of return on plan assets		6.50	%		6.25	%
Weighted average discount rate		4.75	%		4.25	%
Rate of compensation scale escalation (without merit)		2.50	%		2.50	%
Rate of cost of living increase		2.00	%		2.00	%
Average remaining service life of employees (years)		11			11
Post-Retirement and Post-Employment Benefits:
Weighted average discount rate		4.75	%		4.25	%
Rate of compensation scale escalation (without merit)		2.50	%		2.50	%
Rate of cost of living increase		2.00	%		2.00	%
Average remaining service life of employees (years)		12			12
Rate of increase in health care cost trends1		4.39	%		4.39	%

¹  6.81% per annum in 2014, grading down to 4.39% per annum in and after 2031 (2013 – 6.91% in 2013, grading down to 4.39% per annum in and after 2031)

The discount rate used to determine the current year pension obligation and the subsequent year’s net periodic benefit costs is based on a yield curve approach. Under the yield curve approach, expected future benefit payments for each plan are discounted by a rate on a third party bond yield curve corresponding to each duration. The yield curve is based on “AA” long-term corporate bonds. A single discount rate is calculated that would yield the same present value as the sum of the discounted cash flows.

The effect of a 1% change in health care cost trends on the projected benefit obligation for the post-retirement and post-employment benefits at December 31, 2014 and 2013 is as follows:

December 31 (millions of Canadian dollars)	2014			2013
Projected benefit obligation:
Effect of a 1% increase in health care cost trends		248			258
Effect of a 1% decrease in health care cost trends		(193	)		(200	)

37

HYDRO ONE INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

For the years ended December 31, 2014 and 2013

The effect of a 1% change in health care cost trends on the service cost and interest cost for the post-retirement and post-employment benefits for the years ended December 31, 2014 and 2013 is as follows:

Year ended December 31 (millions of Canadian dollars)	2014			2013
Service cost and interest cost:
Effect of a 1% increase in health care cost trends		23			21
Effect of a 1% decrease in health care cost trends		(17	)		(16	)

The following approximate life expectancies were used in the mortality assumptions to determine the projected benefit obligations for the pension and post-retirement and post-employment plans at December 31, 2014 and 2013:

December 31, 2014				December 31, 2013
Life expectancy at 65 for a member currently at				Life expectancy at 65 for a member currently at
Age 65		Age 45		Age 65		Age 45
Male	Female	Male	Female	Male	Female	Male	Female
23	25	24	26	23	25	24	26

Estimated Future Benefit Payments

At December 31, 2014, estimated future benefit payments to the participants of the Plans were:

(millions of Canadian dollars)	Pension Benefits		Post-Retirement and Post-Employment Benefits
2015		305		50
2016		316		52
2017		328		54
2018		339		56
2019		350		59
2020 through to 2024		1,889		332
Total estimated future benefit payments through to 2024		3,527		603

Components of Regulatory Assets

A portion of actuarial gains and losses and prior service costs is recorded within regulatory assets on Hydro One’s Consolidated Balance Sheets to reflect the expected regulatory inclusion of these amounts in future rates, which would otherwise be recorded in OCI. The following table provides the actuarial gains and losses and prior service costs recorded within regulatory assets:

Year ended December 31 (millions of Canadian dollars)	2014			2013
Pension Benefits:
Actuarial loss (gain) for the year		511			(619	)
Actuarial loss amortization		(103	)		(175	)
Prior service cost amortization		(2	)		(2	)
		406			(796	)
Post-Retirement and Post-Employment Benefits:
Actuarial loss (gain) for the year		(18	)		13
Actuarial loss amortization		(18	)		(27	)
Prior service cost amortization		(2	)		(3	)
		(38	)		(17	)

38

HYDRO ONE INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

For the years ended December 31, 2014 and 2013

The following table provides the components of regulatory assets that have not been recognized as components of net periodic benefit costs for the years ended December 31, 2014 and 2013:

Year ended December 31 (millions of Canadian dollars)	2014		2013
Pension Benefits:
Prior service cost		2		3
Actuarial loss		1,234		842
		1,236		845
Post-Retirement and Post-Employment Benefits:
Prior service cost		—		2
Actuarial loss		273		306
		273		308

The following table provides the components of regulatory assets at December 31 that are expected to be amortized as components of net periodic benefit costs in the following year:

	Pension Benefits				Post-Retirement and Post-Employment Benefits
December 31 (millions of Canadian dollars)	2014		2013		2014		2013
Prior service cost		2		2		—		2
Actuarial loss		119		103		10		15
		121		105		10		17

Pension Plan Assets

Investment Strategy

On a regular basis, Hydro One evaluates its investment strategy to ensure that Pension Plan assets will be sufficient to pay Pension Plan benefits when due. As part of this ongoing evaluation, Hydro One may make changes to its targeted asset allocation and investment strategy. The Pension Plan is managed at a net asset level. The main objective of the Pension Plan is to sustain a certain level of net assets in order to meet the pension obligations of the Company. The Pension Plan fulfills its primary objective by adhering to specific investment policies outlined in its Summary of Investment Policies and Procedures (SIPP), which is reviewed and approved by the Audit, Finance and Pension Investment Committee of Hydro One’s Board of Directors. The Company manages net assets by engaging knowledgeable external investment managers who are charged with the responsibility of investing existing funds and new funds (current year’s employee and employer contributions) in accordance with the approved SIPP. The performance of the managers is monitored through a governance structure. Increases in net assets are a direct result of investment income generated by investments held by the Pension Plan and contributions to the Pension Plan by eligible employees and by the Company. The main use of net assets is for benefit payments to eligible Pension Plan members.

Pension Plan Asset Mix

At December 31, 2014, the Pension Plan target asset allocations and weighted average asset allocations were as follows:

	Target Allocation (%)		Pension Plan Assets (%)
Equity securities		60.0		60.9
Debt securities		35.0		35.9
Other1		5.0		3.2
		100.0		100.0

¹  Other investments include real estate and infrastructure investments.

At December 31, 2014, the Pension Plan held no Hydro One corporate bonds (2013 – $15 million) and $340 million of debt securities of the Province (2013 – $217 million).

39

HYDRO ONE INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

For the years ended December 31, 2014 and 2013

Concentrations of Credit Risk

Hydro One evaluated its Pension Plan’s asset portfolio for the existence of significant concentrations of credit risk as at December 31, 2014 and 2013. Concentrations that were evaluated include, but are not limited to, investment concentrations in a single entity, concentrations in a type of industry, and concentrations in individual funds. At December 31, 2014 and 2013, there were no significant concentrations (defined as greater than 10% of plan assets) of risk in the Pension Plan’s assets.

The Pension Plan manages its counterparty credit risk with respect to bonds by investing in investment-grade and government bonds and with respect to derivative instruments by transacting only with financial institutions rated at least “A+” by Standard and Poor’s Rating Services Inc., DBRS Limited, and Fitch Ratings Inc., and “A1” by Moody’s Investors Service Inc., and also by utilizing exposure limits to each counterparty and ensuring that exposure is diversified across counterparties. The risk of default on transactions in listed securities is considered minimal, as the trade will fail if either party to the transaction does not meet its obligation.

Fair Value Measurements

The following tables present the Pension Plan assets measured and recorded at fair value on a recurring basis and their level within the fair value hierarchy at December 31, 2014 and 2013:

December 31, 2014 (millions of Canadian dollars)	Level 1		Level 2		Level 3		Total
Pooled funds		—		18		142		160
Cash and cash equivalents		166		—		—		166
Short-term securities		—		176		—		176
Real estate		—		—		2		2
Corporate shares – Canadian		1,008		—		—		1,008
Corporate shares – Foreign		2,766		—		—		2,766
Bonds and debentures – Canadian		—		1,799		—		1,799
Bonds and debentures – Foreign		—		211		—		211
Total fair value of plan assets1		3,940		2,204		144		6,288

¹  At December 31, 2014, the total fair value of Pension Plan assets excludes $18 million of interest and dividends receivable, and $7 million relating to accruals for pension administration expense.

December 31, 2013 (millions of Canadian dollars)	Level 1		Level 2		Level 3		Total
Pooled funds		1		16		117		134
Cash and cash equivalents		150		—		—		150
Short-term securities		—		180		—		180
Real estate		—		—		2		2
Corporate shares – Canadian		943		—		—		943
Corporate shares – Foreign		2,708		—		—		2,708
Bonds and debentures – Canadian		—		1,416		—		1,416
Bonds and debentures – Foreign		—		186		—		186
Total fair value of plan assets1		3,802		1,798		119		5,719

¹  At December 31, 2013, the total fair value of Pension Plan assets excludes $19 million of interest and dividends receivable, and $7 million relating to accruals for pension administration expense.

See Note 13 – Fair Value of Financial Instruments and Risk Management for a description of levels within the fair value hierarchy.

40

HYDRO ONE INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

For the years ended December 31, 2014 and 2013

Changes in the Fair Value of Financial Instruments Classified in Level 3

The following table summarizes the changes in fair value of financial instruments classified in Level 3 for the years ended December 31, 2014 and 2013. The Pension Plan classifies financial instruments as Level 3 when the fair value is measured based on at least one significant input that is not observable in the markets or due to lack of liquidity in certain markets. The gains and losses presented in the table below may include changes in fair value based on both observable and unobservable inputs.

Year ended December 31 (millions of Canadian dollars)	2014			2013
Fair value, beginning of year		119			106
Realized and unrealized gains		30			23
Purchases		23			—
Sales and disbursements		(28	)		(10	)
Fair value, end of year		144			119

There were no significant transfers between any of the fair value levels during the years ended December 31, 2014 and 2013.

The Company performs sensitivity analysis for fair value measurements classified in Level 3, substituting the unobservable inputs with one or more reasonably possible alternative assumptions. These sensitivity analyses resulted in negligible changes in the fair value of financial instruments classified in this level.

Valuation Techniques Used to Determine Fair Value

Pooled Funds

The pooled fund category mainly consists of private equity and infrastructure investments. Private equity investments represent private equity funds that invest in operating companies that are not publicly traded on a stock exchange. Investment strategies in private equity include limited partnerships in businesses that are characterized by high internal growth and operational efficiencies, venture capital, leveraged buyouts and special situations such as distressed investments. Infrastructure investments represent infrastructure funds that invest in real assets which are not publicly traded on a stock exchange. Investment strategies in infrastructure include limited partnerships in core infrastructure assets focusing on assets that generate stable, long-term cash flows and deliver incremental returns relative to conventional fixed-income investments. Private equity and infrastructure valuations are reported by the fund manager and are based on the valuation of the underlying investments which includes inputs such as cost, operating results, discounted future cash flows and market-based comparable data. Since these valuation inputs are not highly observable, private equity and infrastructure investments have been categorized as Level 3 within pooled funds.

Cash Equivalents

Demand cash deposits held with banks and cash held by the investment managers are considered cash equivalents and are included in the fair value measurements hierarchy as Level 1.

Short-Term Securities

Short-term securities are valued at cost plus accrued interest, which approximates fair value due to their short-term nature. Short-term securities have been categorized as Level 2.

Real Estate

Real estate investments represent private equity investments in holding companies that invest in real estate properties. The investments in the holding companies are valued using net asset values reported by the fund manager. Real estate investments are categorized as Level 3.

Corporate Shares

Corporate shares are valued based on quoted prices in active markets and are categorized as Level 1. Investments denominated in foreign currencies are translated into Canadian currency at year-end rates of exchange.

41

HYDRO ONE INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

For the years ended December 31, 2014 and 2013

Bonds and Debentures

Bonds and debentures are presented at published closing trade quotations, and are categorized as Level 2.

16. ENVIRONMENTAL LIABILITIES

The following tables show the movements in environmental liabilities for the years ended December 31, 2014 and 2013:

Year ended December 31, 2014 (millions of Canadian dollars)	PCB			LAR			Total
Environmental liabilities, January 1		201			65			266
Interest accretion		9			2			11
Expenditures		(5	)		(13	)		(18	)
Revaluation adjustment		(33	)		13			(20	)
Environmental liabilities, December 31		172			67			239
Less: current portion		8			10			18
		164			57			221

Year ended December 31, 2013 (millions of Canadian dollars)	PCB			LAR			Total
Environmental liabilities, January 1		197			52			249
Interest accretion		9			1			10
Expenditures		(2	)		(14	)		(16	)
Revaluation adjustment		(3	)		26			23
Environmental liabilities, December 31		201			65			266
Less: current portion		15			12			27
		186			53			239

The following tables show the reconciliation between the undiscounted basis of the environmental liabilities and the amount recognized on the Consolidated Balance Sheets after factoring in the discount rate:

December 31, 2014 (millions of Canadian dollars)	PCB		LAR		Total
Undiscounted environmental liabilities		195		70		265
Less: discounting accumulated liabilities to present value		23		3		26
Discounted environmental liabilities		172		67		239

December 31, 2013 (millions of Canadian dollars)	PCB		LAR		Total
Undiscounted environmental liabilities		237		68		305
Less: discounting accumulated liabilities to present value		36		3		39
Discounted environmental liabilities		201		65		266

At December 31, 2014, the estimated future environmental expenditures were as follows:

(millions of Canadian dollars)
2015	18
2016	37
2017	36
2018	35
2019	33
Thereafter	106
	265

At December 31, 2014, of the total estimated future environmental expenditures, $195 million relates to PCBs (2013 – $237 million) and $70 million relates to LAR (2013 – $68 million).

42

HYDRO ONE INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

For the years ended December 31, 2014 and 2013

Hydro One records a liability for the estimated future expenditures for the contaminated LAR and for the phase-out and destruction of PCB-contaminated mineral oil removed from electrical equipment when it is determined that future environmental remediation expenditures are probable under existing statute or regulation and the amount of the future expenditures can be reasonably estimated.

There are uncertainties in estimating future environmental costs due to potential external events such as changes in legislation or regulations, and advances in remediation technologies. In determining the amounts to be recorded as environmental liabilities, the Company estimates the current cost of completing required work and makes assumptions as to when the future expenditures will actually be incurred, in order to generate future cash flow information. A long-term inflation rate assumption of approximately 2% has been used to express these current cost estimates as estimated future expenditures. Future expenditures have been discounted using factors ranging from approximately 2.3% to 6.3%, depending on the appropriate rate for the period when expenditures are expected to be incurred. All factors used in estimating the Company’s environmental liabilities represent management’s best estimates of the present value of costs required to meet existing legislation or regulations. However, it is reasonably possible that numbers or volumes of contaminated assets, cost estimates to perform work, inflation assumptions and the assumed pattern of annual cash flows may differ significantly from the Company’s current assumptions. In addition, with respect to the PCB environmental liability, the availability of critical resources such as skilled labour and replacement assets and the ability to take maintenance outages in critical facilities may influence the timing of expenditures.

PCBs

The Environment Canada regulations, enacted under the Canadian Environmental Protection Act, 1999, govern the management, storage and disposal of PCBs based on certain criteria, including type of equipment, in-use status, and PCB-contamination thresholds. Under current regulations, Hydro One’s PCBs have to be disposed of by the end of 2025, with the exception of specifically exempted equipment. Contaminated equipment will generally be replaced, or will be decontaminated by removing PCB-contaminated insulating oil and retro filling with replacement oil that contains PCBs in concentrations of less than 2 ppm.

The Company’s best estimate of the total estimated future expenditures to comply with current PCB regulations is $195 million. These expenditures are expected to be incurred over the period from 2015 to 2025. As a result of its annual review of environmental liabilities, the Company recorded a revaluation adjustment in 2014 to reduce the PCB environmental liability by $33 million (2013 – $3 million).

LAR

The Company’s best estimate of the total estimated future expenditures to complete its LAR program is $70 million. These expenditures are expected to be incurred over the period from 2015 to 2023. As a result of its annual review of environmental liabilities, the Company recorded a revaluation adjustment in 2014 to increase the LAR environmental liability by $13 million (2013 – $26 million).

17. ASSET RETIREMENT OBLIGATIONS

Hydro One records a liability for the estimated future expenditures for the removal and disposal of asbestos-containing materials installed in some of its facilities and for the decommissioning of specific switching stations located on unowned sites. AROs, which represent legal obligations associated with the retirement of certain tangible long-lived assets, are computed as the present value of the projected expenditures for the future retirement of specific assets and are recognized in the period in which the liability is incurred, if a reasonable estimate of fair value can be made. If the asset remains in service at the recognition date, the present value of the liability is added to the carrying amount of the associated asset in the period the liability is incurred and this additional carrying amount is depreciated over the remaining life of the asset. If an ARO is recorded in respect of an out-of-service asset, the asset retirement cost is charged to results of operations. Subsequent to the initial recognition, the liability is adjusted for any revisions to the estimated future cash flows associated with the ARO, which can occur due to a number of factors including, but not limited to, cost escalation, changes in technology applicable to the assets to be retired, changes in legislation or regulations, as well as for accretion of the liability due to the passage of time until the obligation is settled. Depreciation expense is adjusted prospectively for any increases or decreases to the carrying amount of the associated asset.

43

HYDRO ONE INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

For the years ended December 31, 2014 and 2013

In determining the amounts to be recorded as AROs, the Company estimates the current fair value for completing required work and makes assumptions as to when the future expenditures will actually be incurred, in order to generate future cash flow information. A long-term inflation assumption of approximately 2% has been used to express these current cost estimates as estimated future expenditures. Future expenditures have been discounted using factors ranging from approximately 3.0% to 5.0%, depending on the appropriate rate for the period when expenditures are expected to be incurred. All factors used in estimating the Company’s AROs represent management’s best estimates of the cost required to meet existing legislation or regulations. However, it is reasonably possible that numbers or volumes of contaminated assets, cost estimates to perform work, inflation assumptions and the assumed pattern of annual cash flows may differ significantly from the Company’s current assumptions. AROs are reviewed annually or more frequently if significant changes in regulations or other relevant factors occur. Estimate changes are accounted for prospectively.

At December 31, 2014, Hydro One had recorded AROs of $9 million (2013 – $14 million), consisting of $8 million (2013 – $7 million) related to the estimated future expenditures associated with the removal and disposal of asbestos-containing materials installed in some of its facilities, as well as $1 million (2013 – $7 million) related to the future decommissioning and removal of two switching stations. The amount of interest recorded is nominal.

18. SHARE CAPITAL

Preferred Shares

The Company has 12,920,000 issued and outstanding 5.5% cumulative preferred shares with a redemption value of $25 per share or $323 million total value. The Company is authorized to issue an unlimited number of preferred shares.

The Company’s preferred shares are entitled to an annual cumulative dividend of $18 million, or $1.375 per share, which is payable on a quarterly basis. The preferred shares are not subject to mandatory redemption (except on liquidation) but are redeemable in certain circumstances. The shares are redeemable at the option of the Province at the redemption value, plus any accrued and unpaid dividends, if the Province sells a number of the common shares which it owns to the public such that the Province’s holdings are reduced to less than 50% of the common shares of the Company. Hydro One may elect, without condition, to pay all or part of the redemption price by issuing additional common shares to the Province. If the Province does not exercise its redemption right, the Company would have the ability to adjust the dividend on the preferred shares to produce a yield that is 0.50% less than the then-current dividend market yield for similarly rated preferred shares. The preferred shares do not carry voting rights, except in limited circumstances, and would rank in priority over the common shares upon liquidation.

These preferred shares have conditions for their redemption that are outside the control of the Company because the Province can exercise its right to redeem in the event of change in ownership without approval of the Company’s Board of Directors. Because the conditional redemption feature is outside the control of the Company, the preferred shares are classified outside of equity on the Consolidated Balance Sheets. Management believes that it is not probable that the preferred shares will become redeemable. No adjustment to the carrying value of the preferred shares has been recognized at December 31, 2014. If it becomes probable in the future that the preferred shares will be redeemed, the redemption value would be adjusted.

Common Shares

The Company has 100,000 issued and outstanding common shares. The Company is authorized to issue an unlimited number of common shares.

Common share dividends are declared at the sole discretion of the Hydro One Board of Directors, and are recommended by management based on results of operations, maintenance of the deemed regulatory capital structure, financial conditions, cash requirements, and other relevant factors, such as industry practice and Shareholder expectations.

44

HYDRO ONE INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

For the years ended December 31, 2014 and 2013

Earnings per Share

Basic and diluted earnings per share have been calculated on the basis of net income attributable to the Shareholder of Hydro One and the weighted average number of common shares outstanding during the year.

19. DIVIDENDS

In 2014, preferred share dividends in the amount of $18 million (2013 – $18 million) and common share dividends in the amount of $269 million (2013 – $200 million) were declared.

20. RELATED PARTY TRANSACTIONS

Hydro One is owned by the Province. The OEFC, IESO, OPA, Ontario Power Generation Inc. (OPG) and the OEB are related parties to Hydro One because they are controlled or significantly influenced by the Province.

The Province

During 2014, Hydro One paid dividends to the Province totalling $287 million (2013 – $218 million).

In November 2014, the Company redeemed the $250 million Province of Ontario Floating-Rate Notes held as a long-term investment. These notes were originally purchased in January 2010 with a maturity date of November 19, 2014.

IESO

In 2014, Hydro One purchased power in the amount of $2,601 million (2013 – $2,477 million) from the IESO-administered electricity market.

Hydro One receives revenues for transmission services from the IESO, based on OEB-approved uniform transmission rates. Transmission revenues for 2014 include $1,556 million (2013 – $1,509 million) related to these services.

Hydro One receives amounts for rural rate protection from the IESO. Distribution revenues for 2014 include $127 million (2013 – $127 million) related to this program.

Hydro One also receives revenues related to the supply of electricity to remote northern communities from the IESO. Distribution revenues for 2014 include $32 million (2013 – $33 million) related to these services.

OPA

The OPA funds substantially all of the Company’s conservation and demand management programs. The funding includes program costs, incentives, and management fees. In 2014, Hydro One received $33 million (2013 – $34 million) from the OPA related to these programs.

OPG

In 2014, Hydro One purchased power in the amount of $23 million (2013 – $15 million) from OPG.

Hydro One has service level agreements with OPG. These services include field, engineering, logistics and telecommunications services. In 2014, revenues related to the provision of construction and equipment maintenance services with respect to these service level agreements were $12 million (2013 – $9 million), primarily for the Transmission Business. Operation, maintenance and administration costs in 2014 related to the purchase of services with respect to these service level agreements were $1 million (2013 – $1 million).

45

HYDRO ONE INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

For the years ended December 31, 2014 and 2013

OEFC

In 2014, Hydro One made payments in lieu of corporate income taxes to the OEFC totalling $86 million (2013 – $138 million).

In 2014, Hydro One purchased power in the amount of $9 million (2013 – $8 million) from power contracts administered by the OEFC.

Hydro One pays a $5 million annual fee to the OEFC for indemnification against adverse claims in excess of $10 million paid by the OEFC with respect to certain of Ontario Hydro’s businesses transferred to Hydro One on April 1, 1999.

PILs and payments in lieu of property taxes are paid to the OEFC.

OEB

Under the Ontario Energy Board Act, 1998, the OEB is required to recover all of its annual operating costs from gas and electricity distributors and transmitters. In 2014, Hydro One incurred $12 million (2013 – $12 million) in OEB fees.

Sales to and purchases from related parties occur at normal market prices or at a proxy for fair value based on the requirements of the OEB’s Affiliate Relationships Code. Outstanding balances at period end are interest free and settled in cash.

The amounts due to and from related parties as a result of the transactions referred to above are as follows:

December 31 (millions of Canadian dollars)	2014			2013
Due from related parties		224			197
Due to related parties1		(227	)		(230	)
Investment		—			251

¹  Included in due to related parties at December 31, 2014 are amounts owing to the IESO in respect of power purchases of $214 million (2013 – $217 million).

21. CONSOLIDATED STATEMENTS OF CASH FLOWS

The changes in non-cash balances related to operations consist of the following:

Year ended December 31 (millions of Canadian dollars)	2014			2013
Accounts receivable		(93	)		(78	)
Due from related parties		(27	)		(43	)
Prepaid expenses and other assets		(13	)		(5	)
Accounts payable		39			13
Accrued liabilities		(35	)		71
Due to related parties		(3	)		(31	)
Accrued interest		—			5
Long-term accounts payable and other liabilities		(3	)		(5	)
Post-retirement and post-employment benefit liability		80			84
		(55	)		11

46

HYDRO ONE INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

For the years ended December 31, 2014 and 2013

Capital Expenditures

The following table illustrates the reconciliation between investments in property, plant and equipment and the amount presented in the Consolidated Statements of Cash Flows after factoring in capitalized depreciation and the net change in related accruals:

Year ended December 31 (millions of Canadian dollars)	2014			2013
Capital investments in property, plant and equipment		(1,511	)		(1,312	)
Capitalized depreciation and net change in accruals included in capital investments in property, plant and equipment		30			4
Capital expenditures – property, plant and equipment		(1,481	)		(1,308	)

The following table illustrates the reconciliation between investments in intangible assets and the amount presented in the Consolidated Statements of Cash Flows after factoring in the net change in related accruals:

Year ended December 31 (millions of Canadian dollars)	2014			2013
Capital investments in intangible assets		(19	)		(82	)
Net change in accruals included in capital investments in intangible assets		(4	)		3
Capital expenditures – intangible assets		(23	)		(79	)

Supplementary Information

Year ended December 31 (millions of Canadian dollars)	2014		2013
Net interest paid		412		395
PILs		86		138

22. CONTINGENCIES

Legal Proceedings

Hydro One is involved in various lawsuits, claims and regulatory proceedings in the normal course of business. In the opinion of management, the outcome of such matters will not have a material adverse effect on the Company’s consolidated financial position, results of operations or cash flows.

Transfer of Assets

The transfer orders by which the Company acquired certain of Ontario Hydro’s businesses as of April 1, 1999 did not transfer title to some assets located on Reserves (as defined in the Indian Act (Canada)). Currently, the OEFC holds these assets. Under the terms of the transfer orders, the Company is required to manage these assets until it has obtained all consents necessary to complete the transfer of title of these assets to itself. The Company cannot predict the aggregate amount that it may have to pay, either on an annual or one-time basis, to obtain the required consents. In 2014, the Company paid approximately $1 million (2013 – $2 million) in respect of these consents. If the Company cannot obtain the required consents, the OEFC will continue to hold these assets for an indefinite period of time. If the Company cannot reach a satisfactory settlement, it may have to relocate these assets to other locations at a cost that could be substantial or, in a limited number of cases, to abandon a line and replace it with diesel-generation facilities. The costs relating to these assets could have a material adverse effect on the Company’s results of operations if the Company is not able to recover them in future rate orders.

47

HYDRO ONE INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

For the years ended December 31, 2014 and 2013

23. COMMITMENTS

Outsourcing Agreements

The current agreement with Inergi LP (Inergi), an affiliate of Capgemini Canada Inc., expires on February 28, 2015. On November 28, 2014, Hydro One entered into an agreement with Inergi (Inergi Agreement), the service provider selected through a competitive procurement process which began in 2013, for second-generation back office and IT outsourcing services for a term of 58 months, commencing March 1, 2015 to December 31, 2019. Under the agreement, Inergi will provide Hydro One with settlements, source to pay services, pay operations services, information technology and finance and accounting services. Coincident with the conclusion of negotiations on the Inergi Agreement, Hydro One reached agreement with Inergi for the provision of second-generation customer service operations outsourcing services for a fixed period of three years beginning March 1, 2015 to February 28, 2018.

In September 2014, Hydro One entered into an agreement with Brookfield Johnson Controls Canada LP (Brookfield) for facilities management services for a term of ten years, from January 1, 2015 to December 31, 2024, with the option to renew for an additional term of three years. Under the agreement, Brookfield will provide us with facilities management and execution of certain capital projects as deemed required by the Company. The Brookfield Agreement has a value of up to approximately $658 million over the ten-year term of the agreement, including the facilities management portion of the contract, plus a variable amount of capital work depending on the needs that may arise as determined by the Company, with no minimum capital work guarantee. The agreement also includes a fixed management fee of approximately $2 million for each year of the term.

At December 31, 2014, the annual commitments under the outsourcing agreements were as follows: 2015 – $179 million; 2016 – $146 million; 2017 – $145 million; 2018 – $113 million; 2019 – $105 million; and thereafter – $13 million.

Prudential Support

Purchasers of electricity in Ontario, through the IESO, are required to provide security to mitigate the risk of their default based on their expected activity in the market. As at December 31, 2014, the Company provided prudential support to the IESO on behalf of its subsidiaries using parental guarantees of $330 million (2013 – $325 million), and on behalf of two distributors using guarantees of $1 million (2013 – $1 million). In addition, as at December 31, 2014, the Company has provided letters of credit in the amount of $8 million (2013 – $21 million) to the IESO. The IESO could draw on these guarantees and/or letters of credit if these subsidiaries or distributors fail to make a payment required by a default notice issued by the IESO. The maximum potential payment is the face value of any letters of credit plus the amount of the parental guarantees.

Retirement Compensation Arrangements

Bank letters of credit have been issued to provide security for the Company’s liability under the terms of a trust fund established pursuant to the supplementary pension plan for eligible employees of Hydro One. The supplementary pension plan trustee is required to draw upon these letters of credit if Hydro One is in default of its obligations under the terms of this plan. Such obligations include the requirement to provide the trustee with an annual actuarial report as well as letters of credit sufficient to secure the Company’s liability under the plan, to pay benefits payable under the plan and to pay the letter of credit fee. The maximum potential payment is the face value of the letters of credit. At December 31, 2014, Hydro One had letters of credit of $126 million (2013 – $127 million) outstanding relating to retirement compensation arrangements.

Operating Leases

Hydro One is committed as lessee to irrevocable operating lease contracts for buildings used in administrative and service-related functions and storing telecommunications equipment. These leases have a typical term of between three and five years, but several leases have lesser or greater terms to address special circumstances and/or opportunities. Renewal options, which are generally prevalent in most leases, have similar terms of three to five years. All leases include a clause to enable upward revision of the rental charge on an annual basis or on renewal according to prevailing market conditions or pre-established rents. There are no restrictions placed upon Hydro One by entering into these leases. Hydro One Networks and Hydro One Telecom are the principal entities concerned.

48

HYDRO ONE INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

For the years ended December 31, 2014 and 2013

During the year ended December 31, 2014, the Company made lease payments totalling $11 million (2013 – $11 million). At December 31, 2014, the future minimum lease payments under non-cancellable operating leases were as follows: 2015 – $7 million; 2016 – $10 million; 2017 – $9 million; 2018 – $7 million; 2019 – $3 million; and thereafter – $9 million.

24. SEGMENTED REPORTING

Hydro One has three reportable segments:

• The Transmission Business, which comprises the core business of providing electricity transportation and connection services, is responsible for transmitting electricity throughout the Ontario electricity grid;

• The Distribution Business, which comprises the core business of delivering and selling electricity to customers; and

• Other, which includes certain corporate activities and the operations of the telecommunications business.

The designation of segments has been based on a combination of regulatory status and the nature of the products and services provided. Operating segments of the Company are determined based on information used by the chief operating decision maker in deciding how to allocate resources and evaluate the performance of each of the segments. The Company evaluates segment performance based on income before financing charges and provision for PILs from continuing operations (excluding certain allocated corporate governance costs).

The accounting policies followed by the segments are the same as those described in the summary of significant accounting policies (see Note 2 – Significant Accounting Policies). Segment information on the above basis is as follows:

Year ended December 31, 2014 (millions of Canadian dollars)	Transmission		Distribution		Other			Consolidated
Revenues		1,588		4,903		57			6,548
Purchased power		—		3,419		—			3,419
Operation, maintenance and administration		394		742		56			1,192
Depreciation and amortization		346		367		9			722
Income (loss) before financing charges and provision for PILs		848		375		(8	)		1,215
Capital investments		845		680		5			1,530

Year ended December 31, 2013 (millions of Canadian dollars)	Transmission		Distribution		Other			Consolidated
Revenues		1,529		4,484		61			6,074
Purchased power		—		3,020		—			3,020
Operation, maintenance and administration		375		672		59			1,106
Depreciation and amortization		327		340		9			676
Income (loss) before financing charges and provision for PILs		827		452		(7	)		1,272
Capital investments		714		673		7			1,394

Total Assets by Segment:

December 31 (millions of Canadian dollars)	2014		2013
Transmission		12,540		11,846
Distribution		9,805		8,805
Other		205		974
Total assets		22,550		21,625

All revenues, costs and assets, as the case may be, are earned, incurred or held in Canada.

49

HYDRO ONE INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

For the years ended December 31, 2014 and 2013

25. SUBSEQUENT EVENT

On February 11, 2015, preferred share dividends in the amount of $4 million and common share dividends in the amount of $25 million were declared.

50

EX-99.3

Exhibit 99.3

HYDRO ONE INC.

MANAGEMENT’S DISCUSSION AND ANALYSIS

For the years ended December 31, 2014 and 2013

The following Management’s Discussion and Analysis (MD&A) of the financial condition and results of operations should be read together with the consolidated financial statements and accompanying notes (the Consolidated Financial Statements) of Hydro One Inc. (Hydro One or the Company) for the year ended December 31, 2014. The Consolidated Financial Statements are presented in Canadian dollars and have been prepared in accordance with United States (US) Generally Accepted Accounting Principles (GAAP). All financial information in this MD&A is presented in Canadian dollars, unless otherwise indicated.

The Company has prepared this MD&A in accordance with National Instrument 51-102 – Continuous Disclosure Obligations of the Canadian Securities Administrators. Under the US/Canada Multijurisdictional Disclosure System, the Company is permitted to prepare this MD&A in accordance with the disclosure requirements of Canada, which are different from those of the US. This MD&A provides information for the year ended December 31, 2014, based on information available to management as of February 11, 2015.

EXECUTIVE SUMMARY

We are wholly owned by the Province of Ontario (Province or Shareholder), and our Transmission and Distribution Businesses are regulated by the Ontario Energy Board (OEB).

During 2014, we continued to focus tremendous effort on customer service and on forming a stronger relationship between our customers’ satisfaction with our service and their perceptions of our company. The expectation is that in doing so, we will emerge from the challenges of this year with a renewed, transparent and consistent experience for all our customers by creating new customer tools, products, and processes and by establishing new standards for customer service. We have implemented a strong governance system that will ensure we are monitoring and measuring key performance indicators to support and advance our values with respect to being a customer caring company. We have achieved a number of targets with respect to call centre performance and billing issues to stabilize customer operations following the implementation of our new billing system, and we will continue to strive for stronger performance and an ever-improving experience for our customers.

To further improve our customer service performance culture, we have recently announced two new initiatives – a third party expert Customer Service Advisory Panel and our draft Customer Commitments. Our Customer Commitments will form the basis of our promises to our customers, and the Customer Service Advisory Panel will provide advice and hold us accountable to the promises we make to our customers. Once our Customer Commitments are finalized with input received from our customers, our employees and our Customer Service Advisory Panel, we will develop a public scorecard and will report on our performance as a transparent, accountable and customer focused organization.

Our mission and vision reflects the unique role we play in the economy of the Province and as a provider of critical infrastructure to all our customers. We strive to be an innovative and trusted company, delivering electricity safely, reliably and efficiently to create value for our customers. We operate as a commercial enterprise with an independent Board of Directors. Our strategic plan is driven by our values: health and safety; excellence; stewardship; and innovation. Safety is of utmost importance to us because we work in an environment that can be hazardous. We take our responsibility as stewards of critical provincial assets seriously. We demonstrate sound stewardship by managing our assets in a manner that is commercial, transparent and which values our customers. We strive for excellence by being trained, prepared and equipped to deliver high-quality service. We value innovation because it allows us to increase our productivity and develop enhanced methods to meet the needs of our customers.

We manage our business using the following framework:

1

HYDRO ONE INC.

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2014 and 2013

Core Business and Strategy

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

Key Performance Drivers

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

Capability to Deliver Results

We continue to use a balanced scorecard approach as we strive to manage our performance and deliver results each and every year. In 2014, we set 14 performance measure targets and we met or exceeded eight of them. We exceeded our targets for an injury-free workplace, timely and efficient connection of new customers, the ability to provide timely and accurate bills to customers, our Transmission Business cost-effectiveness, net income after tax, and our transmission and distribution in-service capital. Our targets, and our 2014 performance relating to these targets, are discussed in the section “Overview – Performance Measures and Targets.” Our ability to deliver results in each of our strategic areas is limited by risks inherent in our regulatory environment, our business, our workforce, and in the economic environment. These risks, as well as our strategies to mitigate them, are discussed in the section “Risk Management and Risk Factors.”

Results and Outlook

Consolidated Statements of Operations and Comprehensive Income

Year ended December 31 (millions of Canadian dollars, except per share amounts)	2014		2013		2012
Total revenue		6,548		6,074		5,728
Net income attributable to the Shareholder of Hydro One		749		803		745
Basic and fully diluted earnings per common share (dollars)		7,319		7,850		7,280
Cash dividends per common share (dollars)		2,696		2,000		3,523
Cash dividends per preferred share (dollars)		1.375		1.375		1.375

Consolidated Balance Sheets

December 31 (millions of Canadian dollars)	2014		2013		2012
Total assets		22,550		21,625		20,811
Total long-term debt		8,925		9,057		8,479
Preferred shares		323		323		323
Net assets		7,947		7,415		6,830

During 2014, we earned net income of $749 million and revenues of $6,548 million. We made capital investments totalling $1,530 million to improve our transmission and distribution systems’ reliability and performance, address our aging power system infrastructure, facilitate new generation, and improve service to our customers. A full discussion of our results of operations, financing activities, and capital investments can be found in the sections “Annual Results of Operations” and “Liquidity and Capital Resources.”

In August 2014, we completed the acquisition of Norfolk Power Inc. (Norfolk Power), an electricity distribution and telecom company located in southwestern Ontario. Hydro One has been a proud electricity distributor in Norfolk County for decades, serving approximately 14,000 Norfolk County customers. The acquisition of Norfolk Power enables our company to extend our service to the entire Norfolk County and a further 18,000 distribution customers. We are committed to delivering cost-effective service for Norfolk Power’s customers and we remain focused on prudent management, efficient operations and

2

HYDRO ONE INC.

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2014 and 2013

improving the customer experience for everyone we serve. In 2014, we also signed agreements to purchase two more local distribution companies (LDCs): Woodstock Hydro Holdings Inc. (Woodstock Hydro) and Haldimand County Utilities Inc. (Haldimand Hydro). A full discussion of the Norfolk Power, Woodstock Hydro and Haldimand Hydro acquisitions can be found in the section “New Developments in 2014 – Business Combinations.”

In addition, we have completed a partnership transaction with the Saugeen Ojibway Nation (SON), where the SON has acquired a noncontrolling equity interest in our new limited partnership, B2M Limited Partnership (B2M LP). A full discussion of this transaction can be found in the section “New Developments in 2014 – Business Combinations.”

OVERVIEW

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. Our consolidated distribution system is the largest in Ontario and spans roughly 75% of the province. Our Businesses Our company has three reportable segments: •     Our Transmission Business, which comprises the core business of providing electricity transportation and connection services, is responsible for transmitting electricity throughout the Ontario electricity grid;

•     Our Distribution Business, which comprises the core business of delivering and selling electricity to customers; and •     Other Business, which includes certain corporate activities and the operations of our telecommunications business.

Transmission Business

	2014		2013
Electricity transmitted (TWh)1		139.8		140.7
Ontario 20-minute system peak demand (MW)1		23,040		24,957
Ontario 60-minute system peak demand (MW)1		22,774		24,927
Total transmission lines spanning the province (circuit-kilometres)		29,344		29,344
Transmission stations (#)		290		285
Transmission transformers (#)		1,471		1,416
Transmission customers (approximate #)		5,000,000		5,000,000

¹  System-related statistics include preliminary figures for December.

TWh means terawatt-hours

MW means megawatts

Our transmission system totals 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. We also own 290 transmission stations and over 1,400 transmission transformers. Our transmission system operates at 500 kV, 230 kV and 115 kV over relatively long distances and transmits electricity from hydroelectric, wind, solar, nuclear and coal-burning generators to customers consisting of 46 LDCs, our own distribution businesses, and 90 transmission-connected companies. It is also linked to five adjoining jurisdictions through 26 interconnections, through which we can accommodate electricity imports of up to 6,963 MW, and electricity exports of up to 6,295 MW. During 2014, our transmission system transported approximately 139.8 TWh of energy throughout Ontario.

Our Transmission Business includes the transmission businesses of our subsidiary Hydro One Networks Inc. (Hydro One Networks) as well as B2M LP. We own and operate substantially all of Ontario’s electricity transmission system, and serve, directly or indirectly, approximately five million customers. Our transmission system forms an integrated transmission grid that is monitored, controlled and managed centrally from our Ontario Grid Control Centre.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2014 and 2013

In 2014, we earned total transmission revenues of $1,588 million, representing approximately 24% of our total 2014 revenues. At December 31, 2014, our Transmission Business assets were $12,540 million, representing approximately 56% of our total assets.

Distribution Business

	2014		2013
Electricity distributed to Hydro One customers (TWh)1		29.8		29.8
Electricity distributed through Hydro One lines (TWh)1,2		42.4		42.5
Total distribution lines spanning the province (circuit-kilometres)		123,657		122,853
Distribution wood poles (approximate #)		1,551,000		1,550,000
Distribution and regulating stations (#)		1,026		1,017
Distribution customers (#)		1,439,321		1,420,379

¹  System-related statistics include preliminary figures for December.

²  Units distributed through Hydro One lines represent total distribution system requirements and include electricity distributed to consumers who purchased power directly from the IESO.

Our distribution system totals over 123,000 circuit-kilometres of distribution lines, and we own over 1,000 distribution and regulating stations and over 1.5 million distribution wood poles. Our distribution system distributes electricity from our transmission system and from more than 14,200 small generators to approximately 1.4 million of our rural and urban customers within Ontario. During 2014, approximately 42.4 TWh of electricity was distributed through our distribution system, including 29.8 TWh of electricity delivered to Hydro One customers.

Our consolidated Distribution Business includes the distribution businesses of our subsidiary Hydro One Networks and the newly acquired Norfolk Power, as well as our subsidiaries Hydro One Brampton Networks Inc. (Hydro One Brampton Networks), and Hydro One Remote Communities Inc. (Hydro One Remote Communities).   •       Hydro One Networks’ distribution business operates a low-voltage electrical distribution network that distributes electricity to customers, including 23 LDCs not directly connected to our transmission system, 33 LDCs connected to our transmission system, 31 customers with loads exceeding 5 MW, and approximately 1.3 million rural and urban customers.   •       Hydro One Brampton Networks operates the electricity distribution system and facilities within the City of Brampton, Ontario, serving approximately 150,000 urban retail customers.

• Hydro One Remote Communities operates 19 small, regulated generation and distribution systems in 21 remote communities across northern Ontario that are not connected to Ontario’s electricity grid, serving approximately 3,500 customers.

In 2014, we earned total distribution revenues of $4,903 million, including cost of purchased power of $3,419 million, representing approximately 75% of our total 2014 revenues. At December 31, 2014, our Distribution Business assets were $9,805 million, representing approximately 43% of our total assets.

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HYDRO ONE INC.

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2014 and 2013

Other Business

Our Other Business segment includes the operations of our subsidiary, Hydro One Telecom Inc. (Hydro One Telecom), which operates a fibre optic communications network spanning over 6,000 kilometres. Hydro One Telecom provides dark fibre and lit fibre optic capacity to telecommunications carriers and commercial customers with broadband network requirements, including a dedicated optical network providing secure, high-capacity connectivity across numerous health care locations in Ontario. Hydro One Telecom also provides telecommunication systems management and related functions which are required for our transmission and distribution businesses, including corporate data and voice networks and smart meter operations.

In 2014, our Other Business segment contributed revenues of $57 million, representing approximately 1% of our total 2014 revenues. At December 31, 2014, our Other Business segment assets were $205 million, representing approximately 1% of our total assets.

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 Occupational Health and Safety Assessment Series (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 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 Advanced Distribution System (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

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2014 and 2013

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, 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.

Performance Measures and Targets

We target and measure our performance by using a balanced scorecard approach. Key performance drivers are closely monitored throughout the year to ensure that we maintain a focus on our strategic objectives and take mitigating actions as required. In 2014, we met or exceeded eight of 14 performance measure targets. Overall, we are making progress towards achieving many of our strategic goals.

Injury-free Workplace

The safety of our employees is paramount. For 2014, our company used the measure of all work-related injuries or illnesses as the performance measure for this strategic objective. A “recordable” injury/illness is one of the following: medical attention (treatment beyond first aid); modified work (restricted duties); lost time; or death. For 2014, our Board of Directors set the target at 1.9 recordable injuries per 200,000 hours worked for this measure. We exceeded this target.

Satisfying our Customers

In 2014, we approached the objective of customer satisfaction by addressing five measures related to improving customer relations. These measures relate to transmission and distribution customer satisfaction, and connection of new services, as well as estimated bills and no bill volume, as part of our customer service recovery project. Our customer service recovery project was a result of billing issues our company encountered due to the implementation in May 2013 of our new Customer Information System (CIS).

• Customer Satisfaction – Transmission

This measure is to determine the degree to which our transmission customers are satisfied with the service they receive from our company. It is based on survey results of customer surveys conducted on our company’s behalf by independent third parties. The survey is given to three major groups of transmission customers. In 2014, we targeted a transmission customer satisfaction rate of 84%. We did not meet this target.

• Customer Satisfaction – Distribution

Similar to the transmission customers, we survey our distribution customers to assess the degree to which they are satisfied with the service they receive from our company. The results arise from surveys conducted on our

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HYDRO ONE INC.

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2014 and 2013

company’s behalf by independent third parties. This measure reflects the overall satisfaction levels of three major distribution customer segments, based on transaction satisfaction levels, annual satisfaction surveys and the meeting of OEB milestones, respectively, for the three segments. For 2014, our company set a target for distribution customer satisfaction at 87%, and did well on the transactional elements, but did not meet this target on an overall basis.

• Connection of New Customers

This measure relates to distribution low-voltage connections that is reported annually to the OEB. It addresses our customers’ needs for a specific and timely connection date and assesses our efficiency in connecting new customers. It measures the percentage of connections for a requested new service (< 750 volts). The connection must be completed within five business days from the day on which all applicable service conditions are satisfied, or at a later date agreed upon by the customer and our company. We set a 2014 target of 90%, which we exceeded.

• Unscheduled Estimated Bills

With respect to this measure, we seek to track our company’s ability to provide accurate bills to our customers. We track the percentage of total customers that have received unscheduled estimates in any billing period. Our company established a target of 1.8% of all bills for this measure. We exceeded the target.

• No Bill Volume

No bill volume is a customer service measure related to our company’s ability to provide timely bills to our customers. This measure tracks the number of customers who have not received a bill in three consecutive billing periods. Our expectation was to reach a volume of 8,000 no-bill customers by September 2014, and sustain this level beyond that date. We exceeded this target.

Continuous Improvement and Cost-effectiveness

As part of our strategic objectives to increase productivity through efficiency improvements and effective management of costs, our company measures transmission unit cost and distribution unit cost and sets targets for those costs. Regarding the maintenance and reliability of the transmission and distribution systems, we continue to build and retain public confidence and trust in our company’s operations, as stewards of Ontario’s electricity grid. In 2014, we continued our focus on this strategic priority by investing in the key assets of the electricity delivery system and by operating the existing system for customers in a safe, reliable and efficient fashion. Our company 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.

• Transmission Unit Costs

For 2014, the transmission unit cost measure shows the Transmission Business cost-effectiveness by comparing the ratio of operation, maintenance and administration spending to gross fixed asset costs, using benchmarking initiatives. Our company set a target of 2.9% for 2014, and exceeded the target.

• Distribution Unit Costs

Similar to transmission unit cost, the distribution unit cost measure demonstrates the distribution cost-effectiveness by comparing the ratio of operation, maintenance and administration spending to gross fixed asset costs, using benchmarking initiatives. For 2014, our company set a target of 5.7%, but did not meet this target.

• Customer Interruption Duration – Transmission

This measure monitors the reliability of the transmission system by tracking the average length of unplanned interruptions (in minutes) to multiple-circuit supplied delivery points. Our company has set a target of 8.9 minutes per delivery point for 2014. During 2014, our company was aware that we would miss the target, which was not indicative of degrading reliability, but rather a result of refurbishing aging assets. In doing so, this resulted in occasions where load with a multiple-circuit supply was placed on single supply to accommodate the work program. This exposed the system to interruptions if there was a loss of the single supply. Our company determined that it was important to continue with the maintenance program even if this would result in missing the target. Our company, in fact, did not meet this target.

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HYDRO ONE INC.

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2014 and 2013

• Customer Interruption Duration – Distribution

This measure is an indicator of the distribution system reliability that expresses the average length of outages in hours that a customer can expect to experience in the year. This measure excludes force majeure events and loss of supply events (events caused by the transmission system or other distributors). Our company set a target of 6.7 hours per customer for this measure. In 2014, there were numerous storm events which were not considered force majeure events and comparatively more equipment outages that resulted in higher than normal customer interruptions. In the circumstances, we did not meet this target.

Maintaining a Commercial Culture

• Net Income

Achievement of strong financial performance is measured by a performance measure of targeted level of net income after tax. Our target was $668 million net income after tax for 2014, and we exceeded our target.

• Customer Service Recovery Cost

As a result of billing issues that arose from the implementation of our new CIS in 2013, the effects of which became acute in early 2014, our company established the customer service recovery project to dedicate staff to resolve outstanding and any new billing issues and stabilize the billing system. We anticipated, and fixed as a target, costs of $48 million (including revenue impacts) for this project. The project was completed in 2014 and the CIS is now in sustainment mode. As the costs of the customer service recovery project exceeded the target, our company did not meet this anticipated target.

• In-Service Capital – Transmission

This new measure for 2014 evaluates how our company is meeting the OEB targets for in-service capital. For our Transmission Business, the 2014 target of 85% of in-service capital to our business plan is based on historical performance, our increasing capital work program, and the additional variability caused by external commitments and required approvals. Our 2014 result shows that our company exceeded the target.

• In-Service Capital – Distribution

For our Distribution Business, our company set the 2014 target of 87% of in-service capital to our business plan based on historical performance, with adjustments to reflect that our Distribution Business has more storm-related capital spending than our Transmission Business, as well as the performance of our smart meter and distributed generation capital work programs. Our 2014 result was better than the target.

REGULATION

Our Transmission and Distribution Businesses are primarily regulated by the OEB and the National Energy Board (NEB).

Provincial Framework

The Electricity Act, 1998, and the OEB Act primarily establish the broad legislative framework for Ontario’s electricity market. The Electricity Act, 1998, sets out the fundamental principles of Ontario’s electricity industry, enabling open and nondiscriminatory 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 electrical utilities’ distribution and transmission revenue requirements so that rates may be established based on historical average or forecasted needs.

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 forecasted interest rates on long-term bonds. In addition, the OEB approves rate riders to allow for the recovery or disposition of specific regulatory accounts over specified timeframes.

The OEB approved the use of US GAAP for rate setting and regulatory accounting and reporting by Hydro One Networks’ Transmission and Distribution Businesses, as well as by Hydro One Remote Communities, beginning with the year 2012. Up to the year ended December 31, 2014, Hydro One Brampton Networks used Canadian GAAP (Part V) for its distribution rate-setting purposes, and has transitioned to International Financial Reporting Standards (IFRS) beginning on January 1, 2015.

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HYDRO ONE INC.

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2014 and 2013

Renewed Regulatory Framework

In December 2010, the OEB initiated a coordinated consultation process for the development of a Renewed Regulatory Framework for Electricity (RRFE). In October 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 Incentive Regulation Mechanism (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’ 2014 distribution rates.

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). Hydro One Networks 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.

In 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, as the owner of such lines, to comply with specified North American Electric Reliability Corporation (NERC) and Northeast Power Coordinating Council Inc. (NPCC) reliability standards, (ii) mandate certain reporting requirements, and (iii) contain provisions for IPL owners to seek exemptions. In March 2013, Hydro One Networks 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 or to the IPLs it owns. On November 13, 2013, the NEB granted Hydro One Networks’ exemption requests, with some minor exceptions. Hydro One Networks maintains compliance with all applicable NEB orders and seeks approval for all appropriate exemptions, as required.

NERC Critical Infrastructure Protection (Cyber Security) 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, our physical, electronic and information security processes have been upgraded to meet more stringent security requirements in order to meet NERC’s requirements. The NERC Cyber Security standards were updated and revised in 2013, resulting in additional work, effort and associated costs for our company. We anticipate these costs will be spread over a number of years, and expect that they will be recovered in future rates.

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HYDRO ONE INC.

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2014 and 2013

Regulatory Proceedings

The following table summarizes our company’s recent major regulatory proceedings:

Application	Year(s)	Type	Date Filed	Current Status
Electricity Rates – Transmission Rate Applications
Hydro One Networks	2013-2014	Cost-of-service	May 28, 2012	OEB decision received on January 9, 20141
Hydro One Networks	2015-2016	Cost-of-service	September 16, 2014	OEB decision received on December 2, 2014
B2M LP	2015	Interim	October 24, 2014	OEB decision received on December 11, 2014
Electricity Rates – Distribution Rate Applications
Hydro One Networks	2014	IRM	April 26, 2013	OEB decision received December 5, 2013
Hydro One Networks	2015-2019	Custom	December 19, 2013	OEB decision anticipated in 2015 Q1
Hydro One Brampton Networks	2014	IRM	August 14, 2013	OEB decision received December 5, 2013
Hydro One Brampton Networks	2015	Cost-of-service	April 23, 2014	OEB decision received on January 15, 2015
Hydro One Remote Communities	2014	IRM	October 25, 2013	OEB decision received March 13, 2014
Hydro One Remote Communities	2015	IRM	September 24, 2014	OEB decision anticipated in 2015 Q1
Mergers Acquisitions Amalgamations and Divestitures (MAAD) Applications
Norfolk Power	n/a	Acquisition	April 26, 2013	OEB decision received July 3, 2014
Woodstock Hydro	n/a	Acquisition	July 9, 2014	OEB decision anticipated in 2015
Haldimand Hydro	n/a	Acquisition	July 31, 2014	OEB decision anticipated in 2015
Leave to Construct Application
Supply to Essex County Transmission Reinforcement Project	n/a	Section 92	January 22, 2014	OEB decision anticipated in 2015

¹  OEB Oral Decision for 2013 transmission rates was received on November 8, 2012. On December 6, 2013, we submitted a draft Rate Order for our 2014 transmission rates. On January 9, 2014, the OEB approved the draft Rate Order for 2014 transmission rates as filed.

Electricity Rates

Under the current market structure, low-volume and designated consumers pay electricity rates established through the Regulated Price Plan (RPP). The RPP regulates the commodity price of electricity only and does not affect the rates charged for transmission and distribution of electricity. The OEB sets prices for RPP customers based on both a two-tiered electricity pricing structure with seasonal consumption thresholds, and a three-tiered electricity pricing structure with Time-of-Use (TOU) thresholds. New RPP prices are computed at six-month intervals and are the result of an integrated consideration of rebasing and true-ups. The following is a summary of the two-tiered RPP and the TOU RPP prices for the reporting and comparative periods:

RPP	Tier Threshold (kWh/month)				Tier Rates (cents/kWh)
Effective Date	Residential		Non-Residential		Lower Tier 1		Upper Tier 2
November 1, 2012		1,000		750		7.4		8.7
May 1, 2013		600		750		7.8		9.1
November 1, 2013		1,000		750		8.3		9.7
May 1, 2014		600		750		8.6		10.1
November 1, 2014		1,000		750		8.8		10.3

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HYDRO ONE INC.

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2014 and 2013

TOU RPP	Rates (cents/kWh)
Effective Date	On Peak		Mid Peak		Off Peak
November 1, 2012		11.8		9.9		6.3
May 1, 2013		12.4		10.4		6.7
November 1, 2013		12.9		10.9		7.2
May 1, 2014		13.5		11.2		7.5
November 1, 2014		14.0		11.4		7.7

In 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. An exemption from the requirement to move these customers to TOU pricing was approved until December 31, 2014. On December 1, 2014, Hydro One filed a request with the OEB for a five-year exemption extension for 120,000 hard-to-reach customers and requested permission to migrate an additional 50,000 customers back to two-tiered RPP pricing, as it is not economically feasible to consistently provide actual readings from these meters. An OEB Hearing on this matter has commenced. The OEB issued an interim Decision granting an exemption extension until June 30, 2015 or until a final OEB Decision is issued.

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

A typical residential customer consumes 800 kWh of electricity per month. The total bill for a typical residential customer consists of the following: electricity usage charges based on RPP rates; electricity delivery charges based on OEB-approved distribution rates; transmission pass-through charges for the usage of the transmission system; regulatory charges, which include wholesale market costs and rural and remote rate protection amounts; the debt retirement charge; and the harmonized sales tax (HST).

Transmission Rates

Our transmission revenues primarily include our transmission tariff, which is based on the province-wide Uniform Transmission Rates (UTRs) approved by the OEB for all transmitters across Ontario. The OEB rate-setting process is a rigorous judicial process based on evidence, and usually legal cross-examination of witnesses who testify to the volumes of information submitted. The transmission tariff rates are set based on an approved revenue requirement that provides for cost recovery and a return on our common equity.

• Hydro One Networks

In May 2012, we filed a cost-of-service rate application with the OEB for our 2013 and 2014 transmission rates. The application sought OEB approval for revenue requirement increases of approximately 0.6% in 2013 and 9.1% in 2014, or estimated increases of 0% in 2013 and 0.7% in 2014 on a typical residential customer’s total bill. In November 2012, we submitted a draft Rate Order, which included revenue requirements of approximately $1,438 million and $1,528 million for 2013 and 2014, respectively. For a typical residential customer, this represents no change from the 2012 OEB-approved rate levels in 2013 and a 5.8% increase in 2014 for the transmission portion of the bill, or no change for 2013 and an increase of 0.5% for 2014 when considering total bill impact. In December 2012, the OEB approved the 2013 and 2014 transmission revenue requirements as requested. The 2013 Ontario UTRs remained unchanged at the 2012 levels.

On December 6, 2013, we submitted a draft Rate Order for our 2014 transmission rates. The 2014 revenue requirement increased to $1,535 million from the originally-approved revenue requirement of $1,528 million, primarily due to changes in the cost of capital parameters for 2014 released by the OEB in November 2013. On January 9, 2014, the OEB approved the draft Rate Order for 2014 transmission rates as filed. For a typical residential customer, this represents an increase of 6.3% in 2014 for the transmission portion of the bill, or 0.5% when considering total bill impact.

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HYDRO ONE INC.

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2014 and 2013

On September 16, 2014, Hydro One Networks filed its application, evidence and Settlement Agreement with the OEB in support of proposed transmission revenue requirements to be implemented on January 1, 2015 and January 1, 2016. This application is pursuant to a comprehensive Settlement Agreement between the stakeholders and Hydro One Networks. On January 8, 2015, the OEB approved the Hydro One transmission rates revenue requirement, excluding the B2M LP revenue requirement, for 2015 of $1,477 million and the 2016 revenue requirement of $1,516 million, subject to adjustments for the cost of capital parameters. For a typical residential customer, this represents increases of 0.4% in 2015 and 1.4% in 2016 for the transmission portion of the bill, or increases of 0.03% in 2015 and 0.1% in 2016 when considering total bill impact.

• B2M LP

On October 24, 2014, B2M LP filed an application with the OEB for an interim transmission rate, effective January 1, 2015, seeking approval for a revenue requirement of $41 million in 2015. This rate is equal to the amount included in Hydro One Networks’ transmission rates for the Bruce to Milton Line assets, resulting in no change to overall UTRs. The interim Rate Order was approved by the OEB on December 11, 2014. B2M LP was directed to file a full cost-of-service application for final 2015 transmission rates by April 1, 2015.

A full discussion of the B2M LP transaction can be found in the section “New Developments in 2014 – Business Combinations.”

Distribution Rates

Our distribution revenues primarily include our distribution tariff, which is based on OEB-approved rates, and the recovery of the cost of purchased power used by our customers. The distribution tariff rates are set based on an approved revenue requirement that provides for cost recovery and a return on our common equity.

• Hydro One Networks

In June 2012, Hydro One Networks filed an IRM application with the OEB for 2013 distribution rates, to be effective January 1, 2013. In December 2012, the OEB issued a final Rate Order, which resulted in an increase in distribution rates of approximately 1.3% in 2013, or 0.4% when considering total bill impact, for a typical residential customer.

On April 26, 2013, Hydro One Networks filed an IRM application with the OEB for 2014 distribution rates, to be effective January 1, 2014. On September 26, 2013, the OEB issued a partial Decision, approving a rate rider to recover a 2014 revenue requirement of $29 million for operation, maintenance and administration expenses and in-service capital costs of the ADS Project, which will modernize our distribution system. On December 5, 2013, the OEB issued its final Decision, which resulted in an increase of distribution rates of approximately 2.4% in 2014, or 0.85% when considering total bill impact, for a typical residential customer.

On December 19, 2013, Hydro One Networks filed a 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 rate application submitted under the OEB’s RRFE, and has been customized to fit Hydro One Networks’ specific circumstances, which necessitate significant multi-year investments. We are seeking OEB approval for distribution revenue requirements of $1,415 million for 2015, $1,523 million for 2016, $1,578 million for 2017, $1,615 million for 2018, and $1,660 million for 2019. If the application is approved as filed, the resulting change to the distribution portion of the bill for a typical residential customer will be approximately a 1.4% decrease in 2015, 3.8% increase in 2016, 2.3% increase in 2017, 1.2% increase in 2018, and 2.6% increase in 2019. When considering total bill impact, the resulting change will be approximately a 1.5% decrease in 2015, 1.3% increase in 2016, 0.8% increase in 2017, 0.4% increase in 2018, and 0.9% increase in 2019 for a typical residential customer. A technical conference, a settlement conference and an Oral Hearing took place in the third quarter of 2014. On December 18, 2014, the OEB issued a Decision and interim Rate Order approving the 2014 distribution rates as interim 2015 rates effective January 1, 2015. The OEB also approved the discontinuation of the collection of revenues for the provincially funded portion of renewable generation connection investments of approximately $20 million per year from ratepayers effective December 31, 2014. A final Decision and Order from the OEB is anticipated in the first quarter of 2015.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2014 and 2013

• Hydro One Brampton Networks

In August 2012, Hydro One Brampton Networks filed an IRM application with the OEB for 2013 distribution rates, to be effective January 1, 2013. In December 2012, the OEB released a Decision that resulted in an increase in distribution rates of approximately 0.3% for 2013, or less than 0.1% on the average total bill for a typical residential customer.

In August 2013, Hydro One Brampton Networks filed an IRM application with the OEB for 2014 distribution rates, to be effective January 1, 2014. On December 5, 2013, the OEB released a Decision that resulted in a reduction in distribution rates of approximately 2.3% for 2014, or a 0.5% reduction on the average total bill for a typical residential customer.

On April 23, 2014, Hydro One Brampton Networks filed a cost-of-service application with the OEB for 2015 distribution rates, to be effective January 1, 2015, after being in an IRM application period for three years. The 2015 distribution rate application was seeking the approval of a revenue requirement of approximately $74 million for 2015. In its application, Hydro One Brampton Networks also requested OEB approval for retail transmission service rates and the approval of rate riders to dispose of certain deferral and variance accounts. A partial Settlement Proposal was filed with the OEB and the unsettled issues were heard by the OEB in an Oral Hearing in October 2014. On December 18, 2014, the OEB approved a revenue requirement of $72 million. The reduction of $2 million is mainly attributable to updates to the cost of capital parameters, operation, maintenance and administration, and depreciation expense. For a typical residential customer, this represents an increase of 4.5% in 2015 for the distribution portion of the bill, or 1.6% when considering total bill impact. The increase is reflective of increased rate base and higher operation, maintenance and administration costs since Hydro One Brampton Networks’ last cost-of-service application in 2011. On January 15, 2015, the OEB issued its final Rate Order approving the application.

• Hydro One Remote Communities

In September 2012, Hydro One Remote Communities filed a cost-of-service application with the OEB for 2013 distribution rates, seeking approval for a 2013 revenue requirement of $53 million. In August 2013, the OEB issued a final Decision approving a revenue requirement of $51 million and rate increase of approximately 3.45%, with an effective date of May 1, 2013.

In October 2013, Hydro One Remote Communities filed an IRM application with the OEB for 2014 distribution rates, seeking approval for a rate increase of approximately 0.48%. On March 13, 2014, the OEB approved an increase of approximately 1.7% to basic rates for the distribution and generation of electricity, with an effective date of May 1, 2014. The final rate increase was adjusted by the OEB’s updated rate adjustment parameters.

On September 24, 2014, Hydro One Remote Communities filed an IRM application with the OEB for 2015 rates, seeking approval for increased base rates for the distribution and generation of electricity of 1.7% to be effective May 1, 2015. A final Decision from the OEB is anticipated in the first quarter of 2015.

Mergers Acquisitions Amalgamations and Divestitures (MAAD) Applications

Norfolk Power Acquisition

On April 26, 2013, Hydro One filed a MAAD application with the OEB for the approval of the acquisition of Norfolk Power. On July 3, 2014, the OEB issued its Decision and Order granting Hydro One leave to acquire all of the issued and outstanding common shares of Norfolk Power within 18 months from the date of this Decision and Order. In addition, among other items, the OEB’s Decision and Order granted Norfolk Power Distribution Inc. (NPDI), a subsidiary of Norfolk Power, leave to transfer its distribution system to Hydro One Networks within 18 months from the date of this Decision and Order, and ordered that NPDI file with the OEB a draft Rate Order that includes a proposed Tariff of Rates and Changes reflecting the OEB’s approval of a 1% reduction relative to NPDI’s 2012 base electricity delivery rates. As part of the Norfolk Power acquisition agreement, Norfolk Power residential customers received a 1.4% reduction to their monthly distribution delivery rates, and general service customers received a reduction of between 1.4% and 1.6%, depending on their rate class, effective September 8, 2014. In addition, Norfolk Power customers’ distribution rates will be frozen for the next five years. Once the NPDI distribution system transfer is completed, the OEB will transfer NPDI’s electricity distribution licence and NPDI’s Rate Order to Hydro One Networks. A full discussion of the Norfolk Power acquisition can be found in the section “New Developments in 2014 – Business Combinations.”

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2014 and 2013

Woodstock Hydro Acquisition

On July 9, 2014, Hydro One filed a MAAD application with the OEB for the approval of the acquisition of Woodstock Hydro, which is anticipated to be completed in 2015. A full discussion of the Woodstock Hydro acquisition can be found in the section “New Developments in 2014 – Business Combinations.”

Haldimand Hydro Acquisition

On July 31, 2014, Hydro One filed a MAAD application with the OEB for the approval of the acquisition of Haldimand Hydro, which is anticipated to be completed in 2015. A full discussion of the Haldimand Hydro acquisition can be found in the section “New Developments in 2014 – Business Combinations.”

Leave to Construct Application

Supply to Essex County Transmission Reinforcement Project

On January 22, 2014, Hydro One Networks submitted a Leave to Construct application to the OEB under Section 92 of the OEB Act to construct a new 13-kilometre 230 kV double-circuit transmission line in the Windsor-Essex region. The new transmission line will connect to a proposed transmission station in the Municipality of Leamington and an existing 230 kV transmission line between Chatham and Windsor. Further discussion of the Supply to Essex County Transmission Reinforcement Project can be found in the section “Liquidity and Capital Resources – Investing Activities – Major Transmission Projects.”

Contractual Agreements, Codes and Licences

As a regulated company, we are subject to various contractual arrangements, codes and licences.

Operating Agreement with the 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.

Under the Electricity Act, 1998, 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 December 31, 2019. 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 Transmission System Code (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, 1998, LDCs must provide nondiscriminatory access for eligible generators and customers to the wholesale markets administered by the IESO.

Electricity Industry Codes

The OEB has issued and revised several codes that govern the operation of OEB-licensed entities in Ontario. These codes include, but are not limited to, the Affiliate Relationships Code for Electricity Distributors and Transmitters, the Standard Supply Service Code, the TSC, the Distribution System Code (DSC), the Retail Settlement Code, the Electricity Retailer Code of Conduct, the Smart Sub-Metering Code, and the Conservation and Demand Management (CDM) Code. These codes prescribe minimum standards of conduct and standards of service for transmitters, distributors, smart sub-metering providers and/or retailers in the electricity market.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2014 and 2013

Electricity Industry Licences

Our 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. Further discussion of the OEB’s Electricity Reporting and Record Keeping Requirements can be found in the section “Regulation – Regulatory Developments – Performance Measurement and Continuous Improvement.” Our licences promote the expansion and upgrading of the transmission and distribution systems to accommodate load due to forecasted demand growth over the long term, the connection of renewable energy generation facilities, and implementation of modern technologies to improve reliability, operations and network planning.

Regulatory Developments

Long-Term Energy Plan

On December 2, 2013, the Province released its updated Long-Term Energy Plan (2013 LTEP), Achieving Balance, 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 Ontario Power Generation Inc. (OPG) and Hydro One to explore new business lines and opportunities inside and outside Ontario. These opportunities will help leverage existing areas of expertise and grow revenues for the benefit of Ontarians.” We will continue to work with the Province to develop business plans and efficiency targets that will reduce costs and result in significant ratepayer savings. The 2013 LTEP encourages conservation and reinforces the policy of considering conservation first in planning processes. Under the 2013 LTEP, conservation will be used to lessen the need for new supply-and-demand response initiatives to meet peak demand requirements.

Procurement of New Generation

The Ontario Power Authority’s (OPA) Feed-in Tariff (FIT) Program is designed to procure energy from a wide range of renewable energy sources, including wind, solar, photovoltaic, bio-energy, and water power up to 50 MW. The FIT program is currently divided into three streams: MicroFIT (projects up to 10 kW), Small FIT (projects between 10 kW and 500 kW), and regular FIT (projects greater than 500 kW), all of which may result in connections to our 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. We continue to connect projects for which there are firm contracts.

On May 30, 2013, the Province announced that it would make 900 MW of new capacity available between 2013 and 2018 for the Small FIT and MicroFIT programs. The Province has set annual procurement targets, from 2014 onwards, of 150 MW for Small FIT generation and 50 MW for MicroFIT 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. As at December 31, 2014, our company has connected more than 560 FIT and nearly 12,000 MicroFIT projects, enough energy to power approximately 274,000 homes. These connections represent over 1,000 MW of power.

Conservation and Demand Management

The OEB’s CDM guidelines for electricity distributors provide guidance on certain provisions in the CDM Code and the type of evidence that should be filed by distributors in support of applications for OEB-approved CDM programs. The guidelines also provide details on the Lost Revenue Adjustment Mechanism (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. The funding for the OPA-contracted Ontario-wide CDM programs is in place until December 31, 2015. This will provide an opportunity for the OPA and LDCs to work collaboratively to strengthen the current framework, and to keep customer programs in place for 2015.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2014 and 2013

On September 30, 2014, in accordance with the CDM Code, Hydro One Networks and Hydro One Brampton Networks each filed a 2013 Annual CDM Report with the OEB outlining CDM activities, energy and peak demand savings results achieved in 2013, and expectations regarding CDM targets for 2014. Hydro One Networks reported that it expected to reach 95% to 100% of its demand target and 80% of its cumulative energy target by the end of 2014. Hydro One Brampton Networks reported that it expected to reach 60% of its demand target and 100% of its cumulative energy target by the end of 2014.

In March 2014, the Minister of Energy issued parallel directives to the OEB and the OPA, respectively, regarding the new “2015-2020 Conservation Framework.” The directives call for the OPA to establish a provincial target of 7 TWh of persistent energy savings to be achieved by 2020 and for all LDCs to enter into an Electricity Conservation Agreement with the OPA by December 31, 2014. Both Hydro One Networks and Hydro One Brampton Networks submitted their signed Electricity Conservation Agreements to the OPA in December 2014. Conservation opportunities will be provided to customers and available to distributors to ensure both end-user usage and utility systems are as efficient as possible.

The OPA allocated targets and budgets to LDCs on October 31, 2014. Hydro One Networks’ 2015-2020 CDM savings target is 1,159 GWh, to be achieved with a budget of approximately $322 million. Hydro One Brampton Networks’ 2015-2020 CDM savings target is 255.2 GWh, to be achieved with a budget of approximately $67 million. All LDCs must submit CDM Plans indicating how they will achieve their allocated targets by May 1, 2015 using either “Full Cost Recovery” or “Pay-for-Performance” funding models. All CDM programs must be cost-effective to ensure full cost recovery. LDCs may, at any point, resubmit changes to their CDM Plan for approval by the OPA.

On December 19, 2014, the OEB issued its new CDM Guidelines (2015 Guidelines). The 2015 Guidelines are consistent with the Directive the OEB received in March 2014 from the Minister of Energy requiring the OEB to take steps to promote CDM, including amendments to the licences of electricity distributors and the establishment of CDM Requirement guidelines.

Revenue Decoupling for Distributors

In November 2012, the OEB initiated a project to coordinate revenue decoupling with the new rate-setting policies proposed in the RRFE. On April 3, 2014, the OEB released a Draft Report of the Board on Rate Design for Electricity Distributors (Rate Design Report) to solicit stakeholder comments. The Rate Design Report presents three proposals to achieve revenue decoupling: (1) a single monthly charge which is the same for all consumers within the rate class; (2) a fixed monthly charge, with the size of the charge to be based on the size of the electrical connection; and (3) a fixed monthly charge where the size of the charge is based on use during peak hours. The OEB expects to issue a report in early 2015 regarding the phase-in implementation of fixed rates.

Performance Measurement and Continuous Improvement

On March 5, 2014, the OEB issued its Report of the Board on Performance Measurement for Electricity Distributors: A Scorecard Approach (Performance Report) under its RRFE. The Performance Report sets out the OEB’s policies on the measures that will be used by the OEB to assess a distributor’s effectiveness and improvement in achieving customer focus, operational effectiveness, public policy responsiveness, and financial performance to the benefit of existing and future customers, as well as the form and implementation of a performance monitoring tool – a Scorecard.

On July 15, 2014, the OEB issued a Staff Discussion Paper “Electricity Distribution System Reliability Measures and Targets” to establish specific performance targets for the existing system reliability measures, to develop customer-specific reliability measures and to address the monitoring of momentary outages.

Regional Plans

In August 2013, the OEB amended the TSC and DSC to implement a more formal and structured approach to regional planning in Ontario. The new regional planning approach consists of two main processes: Regional Infrastructure Planning (RIP) to be led by transmitters, and Integrated Regional Resource Planning (IRRP) to be led by the OPA. The RIP process focuses mainly on wires planning, both transmission and distribution, and the IRRP process focuses on resources planning

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2014 and 2013

(e.g. generation, CDM) and the integration of resources with wires planning. The development of regional plans will involve close coordination of the two processes and active participation by the OPA, transmitters, distributors and other applicable agencies such as the IESO.

The regional plans are intended to support investments brought forward in transmitter and distributor rate submissions and transmitter Leave to Construct applications. Regional plans are to be reviewed or developed at least every five years. The OEB expects the first cycle of regional plans for all regions in Ontario to be completed in the next three to four years. For regional planning purposes, the province has been subdivided into 21 regions. Hydro One is the lead transmitter responsible for the RIP process for 19 of the 21 regions. Planning activities are underway and the regional plans are expected to be completed between 2015 and 2017.

NEW DEVELOPMENTS IN 2014

Premier’s Advisory Council on Government Assets

On April 11, 2014, the Province announced the appointment of the Premier’s Advisory Council on Government Assets (Council) to provide the Province with recommendations designed to maximize the value of certain provincially owned assets, one of which being our company. The objective of the review is to advise the Province on how to best maximize value from its assets. The Council’s Terms of Reference provided guidance indicating that it would give preference to continued ownership of government assets, but would consider mergers, acquisitions, divestments if there is a strong business case, and would enhance value to taxpayers of the Province.

The interim report released on November 19, 2014, noted our company’s Transmission Business is a well-run entity with some opportunities to deliver savings on the operating side and on capital expenditures, and recommended that the Province maintain its ownership of our company’s Transmission Business. The interim report noted that Ontario’s local electricity distribution system is an unnecessarily cluttered and fragmented system with too many entities, some of which are highly inefficient, unable to adapt to the changing environment and lack capital to modernize or consolidate.

Consequently, the Council recommended that our company’s Transmission and Distribution Businesses be separated, and that Hydro One Networks’ distribution business and Hydro One Brampton Networks be used to spur industry consolidation. The Council also recommended that the Province reduce its equity interest in our company’s Distribution Business by bringing in private sector investment.

The Province has now asked the Council to build on its work by entering phase two, which includes the Council receiving and discussing written ideas related to encouraging consolidation and to Hydro One Brampton Networks and Hydro One Networks’ distribution business, and finalizing its recommendations to the Province. We understand that the Province is specifically considering the sale of Hydro One Brampton Networks, as well as the distribution business of Hydro One Networks.

Business Combinations

B2M LP

In 2012, we entered into an agreement with the Chippewas of Nawash First Nation and the Chippewas of Saugeen First Nation, collectively referred to as the SON, where a noncontrolling equity interest in B2M LP would be made available for purchase at fair value by the SON. B2M LP was formed by Hydro One in 2013 to hold most of the transmission lines and a licence to use the related land. These assets are associated with our Bruce to Milton Transmission Reinforcement Project, an electricity transmission line (Bruce to Milton Line) in southwestern Ontario, from the Bruce Power facility in Kincardine to our Milton Switching Station in the Town of Milton. Hydro One Networks will maintain and operate the Bruce to Milton Line in accordance with an operation and management services agreement. In November 2013, the OEB issued a Decision and Order granting B2M LP a transmission licence and granting Hydro One Networks leave to sell the relevant Bruce to Milton Line transmission assets to B2M LP.

On December 16, 2014, the relevant Bruce to Milton Line transmission assets totalling $526 million were transferred from Hydro One Networks to B2M LP. This was financed by 60% debt ($316 million) and 40% equity ($210 million). On December 17, 2014, the SON acquired a 34.2% equity interest in B2M LP for consideration of $72 million, representing the fair value of the equity interest acquired. B2M LP is now operational.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2014 and 2013

Details of B2M LP’s transmission rate application can be found in the section “Regulation – Regulatory Proceedings – Transmission Rates.”

Norfolk Power Acquisition

On August 29, 2014, our company completed the acquisition of the outstanding shares of Norfolk Power from The Corporation of Norfolk County. Norfolk Power is a holding company that owns NPDI, a local electricity distribution company, and Norfolk Energy Inc., a non-rate regulated energy services company, located in southwestern Ontario. The selection of our company as successful bidder followed a comprehensive, competitive sales process initiated by Norfolk Power.

The total purchase price for Norfolk Power, net of the long-term debt assumed and adjusted for preliminary working capital and other closing adjustments, is approximately $68 million. The determination of the fair values of assets acquired and liabilities assumed has been based upon management’s estimates and certain assumptions with respect to the fair values of the assets acquired and liabilities assumed. We have also determined the preliminary purchase price adjustments based on agreed working capital and other balances at the acquisition date. The resulting preliminary goodwill of approximately $40 million arising from the Norfolk Power acquisition consists largely of the synergies and economies of scale expected from combining the operations of Hydro One and Norfolk Power. We intend to complete the determination of the final purchase price adjustments during the first half of 2015.

Norfolk Power contributed revenues of $18 million and net income of less than $1 million to our company’s consolidated financial results for the year ended December 31, 2014.

Details of the Norfolk Power MAAD application can be found in the section “Regulation – Regulatory Proceedings – MAAD Applications.”

Woodstock Hydro Purchase Agreement

On May 21, 2014, we reached an agreement with the City of Woodstock to acquire 100% of the common shares of Woodstock Hydro for approximately $29 million, subject to final closing adjustments. Woodstock Hydro is an urban electricity distribution company located in southwestern Ontario. The transaction is the result of extensive discussions between Hydro One and the City of Woodstock which involved consideration of economic development opportunities and other benefits resulting from the sale of Woodstock Hydro. The acquisition is pending a regulatory decision from the OEB and is anticipated to be completed in 2015.

Details of the Woodstock Hydro MAAD application can be found in the section “Regulation – Regulatory Proceedings – MAAD Applications.”

Haldimand Hydro Purchase Agreement

On June 10, 2014, we reached an agreement with Haldimand County to acquire 100% of the common shares of Haldimand Hydro for approximately $65 million, subject to final closing adjustments. Haldimand Hydro is an electricity distribution and telecom company located in southwestern Ontario. The transaction is the result of extensive discussions between Hydro One and Haldimand County. The acquisition is pending a regulatory decision from the OEB and is anticipated to be completed in 2015.

Details of the Haldimand Hydro MAAD application can be found in the section “Regulation – Regulatory Proceedings – MAAD Applications.”

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2014 and 2013

Other

Environment Canada Regulations

In April 2014, Environment Canada issued Canada Gazette II, which included amendments to the existing polychlorinated biphenyl (PCB) regulations, including the extension of the end-of-use deadline beyond 2014 for equipment containing certain concentrations of PCBs, with an effective date of January 1, 2015. The amendments extend the end-of-use deadline for our company’s PCBs in concentrations of 500 parts per million or more from December 31, 2014 to December 31, 2025. As a result of an annual review of environmental liabilities, our company recorded a revaluation adjustment in 2014 to reduce our environmental liabilities by $20 million. This adjustment included the impact of the PCB regulations amendments.

Electricity Sector Pension Plans

On August 1, 2014, a Report on the Sustainability of Electricity Sector Pension Plans (Sustainability Report) was released by Jim Leech, Special Advisor to the Minister of Finance for Ontario. As part of its fiscal 2013 budget, the Province announced its intention to establish a government-led industry Working Group (Working Group) to address pension issues associated with the single-employer pension plans at Hydro One, OPG, IESO and the Electrical Safety Authority (ESA). This Sustainability Report is intended to inform and help frame the efforts of the Working Group. The Sustainability Report noted that it is critically important for any pension plan for public-sector workers to be sustainable so that the retirement income of retirees and active members is secure. Management will continue to monitor the initiatives of this Working Group and potential impacts of any recommendations for Hydro One accordingly. To ensure the sustainability of the Hydro One Pension Plan, our company has implemented a gradual increase in the amount of employee contributions to the plan.

Outsourcing Agreements

The current agreement with Inergi LP (Inergi), an affiliate of Capgemini Canada Inc., expires on February 28, 2015. On November 28, 2014, we entered into an agreement with Inergi (Inergi Agreement), the service provider selected through a competitive procurement process which began in 2013, for second-generation back office and IT outsourcing services for a term of 58 months, commencing March 1, 2015 to December 31, 2019. Under the agreement, Inergi will provide us with settlements, source to pay services, pay operations services, information technology and finance and accounting services.

Coincident with the conclusion of negotiations on the Inergi Agreement, we reached agreement with Inergi to provide us with second-generation customer service operations outsourcing services for a fixed period of three years beginning March 1, 2015 to February 28, 2018.

In its re-tendering initiative, Hydro One set out four objectives for its new outsourcing agreements: continually improved value for money; providing operational flexibility; delivery of services to reflect global best practices; and robust, effective performance management and governance. This agreement achieves those objectives and supports our company’s key strategic objectives, while allowing the Company to focus on its core activities of maintaining, planning and operating our Transmission and Distribution Businesses and delivering excellent service to our customers. The agreement will see cost savings on annual base fees while at the same time providing service delivery improvements, as we continue our ongoing efforts to reduce costs and drive more efficiency in our business.

In September 2014, we entered into an agreement with Brookfield Johnson Controls Canada LP (Brookfield), a service provider selected through a competitive procurement process, for facilities management services for a term of ten years, effective January 1, 2015 to December 31, 2024, with the option to renew for an additional term of three years. Over the term of the contract we will transition the facilities management of all of our facilities. Under the agreement, Brookfield will provide us with facilities management and execution of certain capital projects as deemed required by our company. The Brookfield Agreement has a value of up to approximately $658 million over the ten-year term of the agreement, including the facilities management portion of the contract, plus a variable amount of capital work depending on the needs that may arise as determined by our company, with no minimum capital work guarantee.

Details of our contractual obligations under our outsourcing agreements can be found in the section “Liquidity and Capital Resources – Summary of Contractual Obligations and Other Commercial Commitments.”

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2014 and 2013

ANNUAL RESULTS OF OPERATIONS

Year ended December 31 (millions of Canadian dollars)	2014			2013		$ Change			% Change
Revenues		6,548			6,074		474			8
Purchased power		3,419			3,020		399			13
Operation, maintenance and administration		1,192			1,106		86			8
Depreciation and amortization		722			676		46			7
		5,333			4,802		531			11
Income before financing charges and provision for payments in lieu of corporate income taxes		1,215			1,272		(57	)		(4	)
Financing charges		379			360		19			5
Income before provision for payments in lieu of corporate income taxes		836			912		(76	)		(8	)
Provision for payments in lieu of corporate income taxes		89			109		(20	)		(18	)
Net income		747			803		(56	)		(7	)
Net income (loss) attributable to noncontrolling interest		(2	)		—		(2	)		(100	)
Net income attributable to Shareholder of Hydro One		749			803		(54	)		(7	)

Revenues

Year ended December 31 (millions of Canadian dollars)	2014		2013		$ Change			% Change
Transmission		1,588		1,529		59			4
Distribution		4,903		4,484		419			9
Other		57		61		(4	)		(7	)
		6,548		6,074		474			8
Average annual Ontario 60-minute peak demand (MW)1		20,596		21,493		(897	)		(4	)
Distribution – units distributed to our customers (TWh)1		29.8		29.8		—			—

¹  System-related statistics are preliminary.

Transmission
Transmission revenues primarily consist of our transmission tariff, which is based on the monthly peak electricity demand across our high-voltage network. The tariff is designed to recover revenues necessary to support a transmission system with sufficient capacity to accommodate the maximum expected demand. Demand is primarily influenced by weather and economic conditions. Transmission revenues also include export revenues associated with transmitting excess generation to surrounding markets, ancillary revenues primarily attributable to maintenance services provided to generators, and secondary use of our land rights.
Our 2014 transmission revenues increased by $59 million, or 4%, compared to 2013. The components of the increase include the following:

• $90 million increase due to new transmission rates effective January 1, 2014 approved by the OEB in January 2014;

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2014 and 2013

• $42 million increase due to the OEB’s approval of increased export service revenues in recognition of higher electricity exports to other jurisdictions and the disposition of certain OEB-approved transmission regulatory accounts;

• $45 million decrease due to lower average Ontario 60-minute peak demand in 2014. The lower electricity demand in 2014 was mainly due to milder weather in the summer and fall of 2014, compared to 2013; and

• $28 million decrease due to ancillary transmission revenues, primarily associated with OEB-approved regulatory accounts.

Distribution   Distribution revenues include our distribution tariff and amounts to recover the cost of purchased power used by the customers of our Distribution Business. Accordingly, our distribution revenues are influenced by the amount of electricity we distribute, the cost of purchased power and our distribution tariff rates. Distribution revenues also include minor ancillary distribution service revenues, such as fees related to the joint use of our distribution poles by the telecommunications and cable television industries, as well as miscellaneous charges such as charges for late payments.   Our 2014 distribution revenues increased by $419 million, or 9%, compared to 2013. The components of the increase include the following:  

• $399 million increase due to the recovery of higher purchased power costs, as described below under “Purchased Power;”

• $12 million increase due to new distribution rates effective January 1, 2014 approved by the OEB in December 2013; and

• $8 million increase due to ancillary distribution revenues, primarily associated with OEB-approved regulatory accounts.

Purchased Power

Purchased power costs are incurred by our Distribution Business and represent the cost of purchased electricity delivered to customers within our distribution service territory. These costs comprise the wholesale commodity cost of energy, the IESO wholesale market service charges, and transmission charges levied by the IESO. The commodity cost of energy is based on the OEB’s RPP or the market price for electricity. A discussion of the electricity rates can be found in the section “Regulation – Regulatory Proceedings – Electricity Rates.”

Our purchased power costs increased by $399 million, or 13%, in 2014, compared to 2013. The components of the increase include the following:

• $291 million increase resulting from higher purchased power costs for customers who are not eligible for the RPP;

• $78 million increase resulting from the impact of changes in the OEB’s RPP rates for residential and other eligible customers;

• $26 million increase resulting from the OEB transmission rate decision effective January 1, 2014;

• $10 million increase due to wholesale market service charges levied by the IESO;

• $4 million increase resulting from the IESO’s Smart Metering Entity charge effective May 1, 2013; and

• $10 million decrease due to lower energy consumption in 2014, mainly resulting from a milder summer and a warmer fall in 2014.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2014 and 2013

Operation, Maintenance and Administration

Our operation, maintenance and administration costs consist of labour, which is substantially established under collective bargaining agreements, and materials, equipment and purchased services, which are subject to public tenders. Key enablers of the successful implementation of our work programs are our human and material resourcing strategies. Our human resources strategy is focused on hiring through our apprenticeship program and our association with universities, colleges and our unions, as well as skills development and retention, including earlier identification and more rapid development of staff who demonstrate management potential. Our skilled labour pool primarily consists of line, forestry, construction and stations staff who live and work across the province.

Our operation, maintenance and administration expenditures include work program costs and costs to support the operation and maintenance of the transmission and distribution systems. Also included in these costs are payments in lieu of property taxes related to our transmission and distribution lines, stations and buildings. Our transmission operation, maintenance and administration costs are incurred to sustain our high-voltage transmission stations, lines and rights-of-way, and include preventive and corrective maintenance costs related to our power equipment, overhead transmission lines, transmission station sites, and brush control. Our distribution operation, maintenance and administration costs are required to maintain our low-voltage distribution system, and include costs related to distribution line clearing and brush control, line maintenance and repair, as well as land assessment and remediation (LAR). Our company continues to focus on managing its costs, while continuing to complete our planned work programs for both our Transmission and Distribution Businesses.

Year ended December 31 (millions of Canadian dollars)	2014		2013		$ Change			% Change
Transmission		394		375		19			5
Distribution		742		672		70			10
Other		56		59		(3	)		(5	)
		1,192		1,106		86			8

Transmission

Our 2014 transmission operation, maintenance and administration costs increased by $19 million, or 5%, compared to 2013.

Our 2014 transmission work program costs were $240 million, compared to $237 million in 2013, an increase of $3 million. The increase is mainly due to the following:

• increased forestry expenditures related to brush control and line clearing on our transmission rights-of-way;

• a higher volume of corrective and preventive maintenance on power equipment and overhead lines; and

• higher transmission site facilities maintenance requirements.

Our 2014 transmission support costs were $154 million, compared to $138 million in 2013, an increase of $16 million. The increase is mainly due to the following:

• a one-time reduction to our provision for payments in lieu of property taxes in 2013 related to transmission stations for the years 1999 to 2012, inclusive, following the finalization of the related regulations and receipt of a final assessment of our property tax returns;

• partially offset by lower expenditures due to the recovery of insurance proceeds for the 2013 floods at our Richview and Manby transmission stations; and

• increased attribution of overheads to capital project expenditures in 2014.

Distribution

Our 2014 distribution operation, maintenance and administration costs increased by $70 million, or 10%, compared to 2013.

22

HYDRO ONE INC.

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2014 and 2013

Our 2014 distribution work program costs were $599 million, compared to $515 million in 2013, an increase of $84 million. The increase is mainly due to the following:

• our customer service recovery initiatives and the increase in our bad debt expense, resulting from higher electricity consumption due to a substantially colder than normal winter, combined with higher electricity prices and the suspension of certain collection tools and efforts during several months in 2014. We resumed some of our collection tools and efforts in September 2014.

Our 2014 distribution support costs were $143 million, compared to $157 million in 2013, a decrease of $14 million. The decrease is mainly due to the following:

• decreased expenditures in 2014 related to CIS, as it was placed in-service in May 2013.

Depreciation and Amortization

Our 2014 depreciation and amortization costs increased by $46 million, or 7%, compared to 2013. This increase was primarily attributable to higher property, plant and equipment depreciation expense in 2014, mainly related to the growth in capital assets as we continue to place new assets in-service, consistent with our ongoing capital work program.

Financing Charges

Our 2014 financing charges increased by $19 million, or 5%, compared to 2013. The increase is primarily due to the following:

• an increase in interest expense on our long-term debt due to a higher average level of debt;

• partially offset by a lower average interest rate.

Provision for Payments in Lieu of Corporate Income Taxes

The provision for payments in lieu of corporate income taxes (PILs) decreased by $20 million, or 18%, to $89 million in 2014, compared to 2013. The decrease is primarily due to lower levels of pre-tax income in 2014 compared to 2013.

Net Income

Our 2014 net income attributable to the Shareholder of Hydro One decreased by $54 million, or 7%, to $749 million, compared to 2013. The decrease is primarily due to the following:

• $70 million increase in our 2014 distribution operation, maintenance and administration costs, mainly due to our customer service recovery initiatives and the increase in our bad debt expense, resulting from higher electricity consumption due to a substantially colder than normal winter, combined with higher electricity prices and the suspension of certain collection tools and efforts during several months in 2014;

• $46 million increase in our 2014 depreciation and amortization costs, mainly due to higher property, plant and equipment depreciation expense in 2014, related to the growth in capital assets as we continue to place new assets in-service, consistent with our ongoing capital work program; and

• partially offset by a $59 million increase in our 2014 transmission revenues, mainly due to new OEB-approved 2014 transmission rates.

QUARTERLY RESULTS OF OPERATIONS

The following table sets forth unaudited quarterly information for each of the eight quarters, from the quarter ended March 31, 2013 through to December 31, 2014. This information has been derived from our unaudited interim Consolidated Financial Statements and our audited annual Consolidated Financial Statements, which include all adjustments, consisting only of normal recurring adjustments, necessary for fair presentation of our financial position and results of operations for those periods. These operating results are not necessarily indicative of results for any future period and should not be relied upon to predict our future performance.

23

HYDRO ONE INC.

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2014 and 2013

(millions of Canadian dollars)	2014								2013
Quarter ended	Dec. 31		Sept. 30		Jun. 30		Mar. 31		Dec. 31		Sept. 30		Jun. 30		Mar. 31
Total revenue		1,662		1,556		1,566		1,764		1,557		1,542		1,403		1,572
Net income attributable to Shareholder of Hydro One		221		173		115		240		160		218		168		257
Net income to common Shareholder of Hydro One		216		169		110		236		155		214		163		253

Electricity demand generally follows normal weather-related variations, and consequently, our electricity-related revenues and profit, all other things being equal, would tend to be higher in the first and third quarters than in the second and fourth quarters.

2014 Fourth Quarter Results of Operations

Three months ended December 31 (millions of Canadian dollars)	2014			2013		$ Change			% Change
Revenues		1,662			1,557		105			7
Purchased power		893			794		99			12
Operation, maintenance and administration		247			286		(39	)		(14	)
Depreciation and amortization		190			184		6			3
		1,330			1,264		66			5
Income before financing charges and provision for payments in lieu of corporate income taxes		332			293		39			13
Financing charges		98			93		5			5
Income before provision for payments in lieu of corporate income taxes		234			200		34			17
Provision for payments in lieu of corporate income taxes		15			40		(25	)		(63	)
Net income		219			160		59			37
Net income (loss) attributable to noncontrolling interest		(2	)		—		(2	)		(100	)
Net income attributable to Shareholder of Hydro One		221			160		61			38

Our total revenues for the three months ended December 31, 2014 were $1,662 million, compared to $1,557 million during the same period in 2013, an increase of $105 million or 7%. The increase is mainly due to the following:

• the recovery of higher purchased power costs;

• new transmission and distribution rates effective January 1, 2014;

• the OEB’s approval of increased export service revenues in recognition of higher electricity exports to other jurisdictions and the disposition of certain OEB-approved transmission regulatory accounts;

• partially offset by lower average Ontario 60-minute peak demand and energy consumption in the fourth quarter of 2014, mainly due to milder weather in the fall of 2014; and

• lower ancillary revenues, primarily associated with OEB-approved regulatory accounts.

Our purchased power costs for the three months ended December 31, 2014 were $893 million, compared to $794 million during the same period in 2013, an increase of $99 million or 12%. The increase is mainly due to the following:

• higher purchased power costs for customers who are not eligible for the RPP;

• partially offset by lower energy consumption in the fourth quarter of 2014, mainly due to milder weather in the fall of 2014;

• wholesale market service charges levied by the IESO; and

• OEB transmission rate decision effective January 1, 2014.

24

HYDRO ONE INC.

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2014 and 2013

Our operation, maintenance and administration costs for the three months ended December 31, 2014 were $247 million, compared to $286 million during the same period in 2013, a decrease of $39 million or 14%. The decrease is mainly due to the following:

• decreased distribution operation, maintenance and administration costs, primarily due to lower storm response expenditures as a result of lower storm activity in 2014, compared to 2013; and

• decreased expenditures related to brush control and distribution line maintenance work.

Our depreciation and amortization costs for the three months ended December 31, 2014 were $190 million, compared to $184 million during the same period in 2013, an increase of $6 million or 3%. The increase is mainly due to higher property, plant and equipment depreciation expense in 2014, mainly related to the growth in capital assets as we continue to place new assets in-service, consistent with our ongoing capital work program.

Our financing charges for the three months ended December 31, 2014 were $98 million, compared to $93 million during the same period in 2013, an increase of $5 million or 5%. The increase is mainly due to the following:

• an increase in interest expense on our long-term debt due to a higher average level of debt; and

• partially offset by a lower average interest rate.

Our provision for PILs for the three months ended December 31, 2014 was $15 million, compared to $40 million during the same period in 2013, a decrease of $25 million or 63%. The decrease is due to the following:

• changes in net temporary differences, such as capital cost allowance in excess of depreciation, deductions for pension payments made in excess of amounts expensed for accounting purposes, and interest deducted for tax purposes in excess of interest expensed for accounting purposes; and

• partially offset by higher pre-tax income for the three months ended December 31, 2014 compared to the same period in 2013.

Net income attributable to the Shareholder of Hydro One for the three months ended December 31, 2014 was $221 million, compared to $160 million during the same period in 2013, an increase of $61 million or 38%. The increase is mainly due to the following:

• decreased distribution operation, maintenance and administration costs, primarily due to lower storm response expenditures as a result of lower storm activity in 2014, compared to 2013, and decreased expenditures related to brush control and distribution line maintenance work;

• a decrease in our provision for PILs, primarily due to changes in net temporary differences; and

• an increase in our 2014 transmission revenues, mainly due to new OEB-approved 2014 transmission rates.

25

HYDRO ONE INC.

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2014 and 2013

LIQUIDITY AND CAPITAL RESOURCES

Our primary sources of liquidity and capital resources are funds generated from our operations, debt capital market borrowings and bank financing. These resources will be used to satisfy our capital resource requirements, which continue to include our capital expenditures, servicing and repayment of our debt, and dividends.

Summary of Sources and Uses of Cash

Year ended December 31 (millions of Canadian dollars)	2014			2013
Operating activities		1,256			1,404
Financing activities
Long-term debt issued		628			1,185
Long-term debt retired		(776	)		(600	)
Amount contributed by noncontrolling interest		72			—
Dividends paid		(287	)		(218	)
Investing activities
Capital expenditures		(1,504	)		(1,387	)
Acquisition of Norfolk Power		(66	)		—
Proceeds from investment		250			—
Other financing and investing activities		(38	)		(14	)
Net change in cash and cash equivalents		(465	)		370

Operating Activities

Net cash from operating activities decreased by $148 million to $1,256 million in 2014, compared to 2013. The decrease was primarily due to the following:

• lower 2014 net income, compared to 2013;

• changes in accrual balances, mainly related to timing of capital projects;

• changes in regulatory accounts, including the retail settlement and external revenue variance accounts; and

• partially offset by higher property, plant and equipment depreciation expense in 2014, mainly related to the growth in capital assets as we continue to place new assets in-service, consistent with our ongoing capital work program.

Financing Activities

Short-term liquidity is provided through funds from operations, our Commercial Paper Program, under which we are authorized to issue up to $1,000 million in short-term notes with a term to maturity of less than 365 days, and our revolving credit facility.

Our Commercial Paper Program is supported by our $1,500 million committed revolving credit facility with a syndicate of banks, which matures in June 2019. The short-term liquidity under this program and anticipated levels of funds from operations should be sufficient to fund our normal operating requirements.

At December 31, 2014, we had $8,923 million in long-term debt outstanding, including the current portion. Our notes and debentures mature between 2015 and 2064. Long-term financing is provided by our access to the debt markets, primarily through our Medium-Term Note (MTN) Program. The maximum authorized principal amount of medium-term notes issuable under this program is $3,000 million. At December 31, 2014, $1,187 million remained available until October 2015.

26

HYDRO ONE INC.

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2014 and 2013

We rely on debt financing through our MTN Program and our Commercial Paper Program to repay our existing indebtedness and fund a portion of our capital expenditures. The credit ratings assigned to our 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 us 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 corporate credit ratings from approved rating organizations are as follows:

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

We have the customary covenants normally associated with long-term debt. Among other things, our long-term debt covenants limit our permissible debt as a percentage of our total capitalization, limit our ability to sell assets, and impose a negative pledge provision, subject to customary exceptions. The credit agreements related to our credit facilities have no material adverse change clauses that could trigger default. However, the credit agreements require that we provide notice to the lenders of any material adverse change within three business days of the occurrence. The agreements also provide limitations that debt cannot exceed 75% of total capitalization and that third party debt issued by our subsidiaries cannot exceed 10% of the total book value of our assets. We were in compliance with all of these covenants and limitations as at December 31, 2014.

In 2014, we issued $628 million of long-term debt under our MTN Program, compared to $1,185 million of long-term debt issued in 2013. In 2014, we also repaid $750 million in maturing long-term debt, compared to $600 million of long-term debt repaid in 2013. In addition, long-term debt totalling $26 million assumed on the Norfolk Power acquisition was repaid in September 2014. We had no short-term notes outstanding at December 31, 2014 or December 31, 2013.

Common share dividends are declared at the sole discretion of our Board of Directors, and are recommended by management based on results of operations, maintenance of the deemed regulatory capital structure, financial condition, cash requirements, and other relevant factors, such as industry practice and Shareholder expectations. Common share dividends pertaining to our quarterly financial results are generally declared and paid in the following quarter.

During 2014, we paid dividends to the Province in the amount of $287 million, consisting of $269 million in common share dividends and $18 million in preferred share dividends, compared to dividends of $218 million, consisting of $200 million of common share dividends and $18 million of preferred share dividends, paid to the Province in 2013.

Our objectives with respect to our capital structure are to maintain effective access to capital on a long-term basis at reasonable rates and to deliver appropriate financial returns to our Shareholder.

Investing Activities

During 2014, we continued to focus on making important investments in our transmission and distribution systems to address our aging power system infrastructure, improve our systems’ reliability and performance, and improve service to our customers. We made capital investments totalling $1,530 million in 2014, compared to $1,394 million of capital investments in 2013, and have placed $1,574 million of new assets in-service in 2014, compared to $1,491 million of new assets placed in-service in 2013.

Capital investments consist of cash capital expenditures and related accruals. Capital investments primarily relate to sustaining, enhancing and reinforcing our transmission and distribution infrastructure.

Year ended December 31 (millions of Canadian dollars)	2014		2013		$ Change			% Change
Transmission		845		714		131			18
Distribution		680		673		7			1
Other		5		7		(2	)		(29	)
Total capital investments		1,530		1,394		136			10

Transmission Capital Investments

Our 2014 transmission capital investments were $845 million, compared to $714 million in 2013, an increase of $131 million or 18%, primarily due to sustainment programs to address our aging infrastructure. Given the aging of our infrastructure, we have ongoing investment plans which are designed to reliably power our economy and to support the innovation that can be expected over the next decade.

27

HYDRO ONE INC.

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2014 and 2013

The following table presents the main components of our transmission capital investments during 2014 and 2013.

Year ended December 31 (millions of Canadian dollars)	2014		2013		$ Change			% Change
Sustainment		625		481		144			30
Development		132		170		(38	)		(22	)
Other		88		63		25			40
Total transmission capital investments		845		714		131			18

Sustainment Transmission Capital Investments

Our current transmission sustainment programs include protection and control systems, wood poles, breakers and high-voltage instrument transformer replacements. Our 2014 transmission sustainment capital investments were $625 million, compared to $481 million in 2013, an increase of $144 million or 30%. The increase was mainly due to the following:

•       several system re-investments, including the Gerrard and Timmins transmission stations and new type of breakers at our Bruce Transmission Station, which progressed in 2014, as well as completed projects, such as the Pinard Transmission Station Breakers and the Wallaceburg Transmission Station; •       several replacements of end-of-life power transformers at our Pembroke Transmission Station in eastern Ontario, and our Hanover, Allanburg, and Elmira transmission stations in southwestern Ontario, as well as the emergency replacement of a unit at the Trafalgar Transmission Station;

• increased work within our station and lines equipment replacement and refurbishment projects and programs, including our investment to address the condition of the conductors on the 170 kilometre 230 kV circuit from the Chats Falls Switching Station to the Havelock Transmission Station in southeastern Ontario, and increased work on overhead lines wood pole structure replacements; and

• increased volume of replacements related to addressing aging protection and control equipment.

Development Transmission Capital Investments

Our current transmission development projects include transmission system upgrades, local area supply projects, and inter-area network projects. These investments will expand and reinforce power reliability for electricity customers throughout the province, including our residential and industrial customers. Our 2014 development capital investments to expand and reinforce our transmission system were $132 million, compared to $170 million in 2013, a decrease of $38 million or 22%. The decrease was mainly due to the following:

• the successful completion of our Sundusk and Summerhaven Switching Stations upgrades in 2013 to incorporate renewable energy into our transmission system; and

• reduced expenditures related to some of our major projects which were completed in 2014, such as the Lambton to Longwood Transmission Upgrade Project, the Barwick Transmission Station, and the Allanburg Transmission Station to ensure mandatory transmission system standards are met.

Other Transmission Capital Investments

Our 2014 other transmission capital investments were $88 million, compared to $63 million in 2013, an increase of $25 million or 40%. The increase was mainly due to the following:

• the development phase investment in our Network Management System Project, a critical operating tool used for monitoring and control of our transmission system;

• the investment in our Payroll Transformation Project to realize various process efficiencies; and

28

HYDRO ONE INC.

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2014 and 2013

• partially offset by a decrease from the higher investments in 2013 as a result of emergency flood restoration work at our Richview Transmission Station resulting from a major rainstorm in July 2013.

Major Transmission Projects

Our company successfully advanced or completed a number of transmission capital investments projects during 2014. The following table summarizes the status of our major projects at December 31, 2014:

Project Name	Location	Type	Planned In- Service Date	Approved Budget	Capital Cost To-Date	Current Status
Lambton to Longwood Transmission Upgrade	Sarnia area to west of London area Southwestern Ontario	Transmission line upgrade	2014	$41 million	$24 million	Placed in-service in September 2014
Barwick Transmission Station	Rainy River/Fort Frances Northwestern Ontario	New transmission station	2014	$25 million	$21 million	Placed in-service in September 2014
Allanburg Transmission Station	Niagara area Southwestern Ontario	Transmission station upgrade	2014	$33 million	$29 million	Placed in-service in December 2014
Toronto Midtown Transmission Reinforcement	Toronto Southwestern Ontario	New transmission line	2015	$115 million	$83 million	Project is in progress
Guelph Area Transmission Refurbishment	Guelph area Southwestern Ontario	Transmission line upgrade	2016	$103 million	$24 million	Project is in progress
Manby Transmission Station	Toronto Southwestern Ontario	Transmission station upgrade	2016	$24 million	$14 million	Project is in progress
Clarington Transmission Station	Oshawa area Eastern GTA	New transmission station	2017	$297 million	$42 million	Project is in progress
Supply to Essex County Transmission Reinforcement	Windsor-Essex area Southwestern Ontario	New transmission line and station	2018	To be determined	—	Section 92 application filed with OEB in January 2014
Northwest Bulk Transmission Line	Thunder Bay Northwestern Ontario	New transmission line	As early as 2020	To be determined	—	OPA recommendation letter received in October 2014

Lambton to Longwood Transmission Upgrade

Our Lambton to Longwood Transmission Upgrade project involved the upgrade of approximately 70 kilometres of 230 kV double-circuit transmission line between our Lambton and Longwood transmission stations in southwestern Ontario. The investment refurbished 36 tower foundations, replaced the conductor with a higher capacity wire and replaced insulators along the line. This project involved an innovative new technology that allowed the vast majority of the towers to remain in place, and will enable approximately 500 MW of additional clean energy to be connected to the grid. The additional capacity on the grid will also contribute to meeting provincial energy supply targets for installed non-hydroelectric renewable generation by 2021.

Barwick Transmission Station

Our Barwick Transmission Station provides more capacity for communities between Rainy River and Fort Frances in northwestern Ontario, thereby strengthening the reliability of the power supply for both residential and commercial customers in the area. The Barwick Transmission Station consists of two 115 kV/44 kV transformers and allows for shorter spans of 44 kV power lines to connect customers to our system, ultimately improving the reliability of their power supply. The project involved in-house construction crews, local vendors and labour from the Rainy River First Nation community.

29

HYDRO ONE INC.

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2014 and 2013

Allanburg Transmission Station

As a result of new generation connections and various transmission project upgrades in the Niagara area of southwestern Ontario, the Allanburg Transmission Station 115 kV switchyard short circuit level has increased and exceeded breaker capability limits. Consequently, upgrade work was required to replace 15 end-of-life breakers with upgraded short circuit capability in accordance with the TSC standards.

Toronto Midtown Transmission Reinforcement

Supply to the midtown Toronto area is currently provided by three 115 kV circuits between the Leaside Transmission Station and the Wiltshire Transmission Station. These circuits also supply the Bridgman and Dufferin Transmission Stations and provide load transfer capability between the Leaside and Manby transmission stations. The Toronto Midtown Transmission Reinforcement project includes the replacement of an aging underground cable which is nearing its end of life; the installation of an additional 115 kV circuit between the Leaside and Bridgman transmission stations to relieve loading on the existing circuits which are currently operating above their capacity; and the installation of new equipment at the Leaside Transmission Station, and Bayview, Birch and Bridgman Junctions. These transmission infrastructure reinforcements are intended to reduce the risk of power outages, improve reliability for electricity customers, and provide additional supply capability to meet future load growth in midtown Toronto as well as areas to the west.

Guelph Area Transmission Refurbishment

The Guelph Area Transmission Refurbishment Project, an upgrade of a transmission line and transmission stations in Guelph and the surrounding area, includes the installation of two new autotransformers at the existing Cedar Transmission Station, an upgrade of approximately five kilometres of an existing transmission line from 115 kV to 230 kV in south-central Guelph, and an upgrade of the existing Guelph North Junction to a switching station by installing new facilities and fencing. These refurbishments will reinforce the electricity supply and will minimize the impact of any major transmission outages on area customers.

Manby Transmission Station

The Manby Transmission Station project will upgrade the station short circuit capability and install higher rated breakers, which will permit incorporation of new renewable generation in the central Toronto area. Upgrade work requires the replacement of 16 end-of-life breakers and other components in the 115 kV Manby switchyard.

Clarington Transmission Station

To accommodate the eventual closure of the Pickering Nuclear Generating Station, the Clarington Transmission Station will provide additional autotransformer capacity to reliably supply load in the eastern GTA. Upon completion, the Clarington Transmission Station will consist of two 500/230 kV autotransformers and a 230 kV switchyard, and will connect to the existing 230 kV and 500 kV transmission lines. The project will enable future electricity demand growth in the local area and provide the area with the necessary facilities to ensure a safe, reliable supply of electricity to existing and future customers.

Supply to Essex County Transmission Reinforcement Project

On January 22, 2014, Hydro One Networks submitted a Leave to Construct application to the OEB under Section 92 of the OEB Act to construct a new 13-kilometre 230 kV double-circuit transmission line in the Windsor-Essex region. The new transmission line will connect to a proposed transmission station in the Municipality of Leamington and an existing 230 kV transmission line between Chatham and Windsor. The new transmission line and transmission station will address future growth in electricity demand and anticipated expansion in the local agricultural sector and improve the reliability of electricity supply in the broader Windsor-Essex region.

30

HYDRO ONE INC.

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2014 and 2013

Northwest Bulk Transmission Line

In November 2013, the Minister of Energy issued a Directive to the OEB, which in turn issued a Decision and Order on January 9, 2014, to amend the transmission licence of Hydro One Networks to develop and seek approval for the Northwest Bulk Transmission Line Project, an expansion and reinforcement of the transmission system in the area west of Thunder Bay in northwestern Ontario. The project consists of a new transmission line that would increase transmission capacity and maintain the reliability of electricity supply to meet forecasted electricity demand growth and accommodate new generation capacity. Over the long term, it would also enhance the potential for development and connection of renewable energy facilities. Because of its importance to the region, this new line has been identified as a priority project in Ontario’s LTEP. The Northwest Bulk Transmission Line Project will be developed by our company in cooperation with Infrastructure Ontario. The scope and timing of the project shall be in accordance with the recommendations of the OPA.

On October 1, 2014, Hydro One received a letter from the OPA outlining the scope and timing of the Northwest Bulk Transmission Line Project. The scope of the development work will include preliminary design and engineering, cost estimation, public engagement and consultation, routing and siting, and the preparation of an environmental assessment in support of this project. Hydro One is currently initiating the development work for the project and discussions are ongoing with Infrastructure Ontario on the project plan and related accountabilities.

Other Transmission Capital Investments

Pan American (Pan Am) Games

The Pan Am Games project tracking initiative is underway to ensure that we provide a high level of electricity supply reliability to the Pan Am and Parapan Am Games during the summer of 2015, and that operating, maintenance and capital work plans are coordinated across lines of business to minimize outage risks to the venues hosting the 2015 Pan Am and Parapan Am Games. Key major capital projects and site-specific maintenance work in the GTA are being monitored on a monthly basis to ensure our customer commitments are met. This work will ultimately benefit all of our customers in the GTA.

Niagara Reinforcement Project

This project comprises the construction of 76 kilometres of 230 kV line from our Allanburg Transmission Station in the Niagara area to our Middleport Transmission Station in the Hamilton area. The Niagara Reinforcement Project status is considered substantially on time, with the exception that some project work has been delayed due to access issues related to Aboriginal land claims on a section of the line.

Distribution Capital Investments

Our 2014 distribution capital investments were $680 million, compared to $673 million in 2013, an increase of $7 million or 1%, primarily due to our distribution sustainment programs to address our aging infrastructure.

The following table presents the main components of our distribution capital investments during 2014 and 2013.

Year ended December 31 (millions of Canadian dollars)	2014		2013		$ Change			% Change
Sustainment		356		324		32			10
Development		236		235		1			—
Other		88		114		(26	)		(23	)
Total distribution capital investments		680		673		7			1

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HYDRO ONE INC.

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2014 and 2013

Sustainment Distribution Capital Investments

Our current distribution sustainment programs include wood pole and meter replacements, emergency work for storm restoration, distribution station refurbishments and upgrades, and work related to joint-use and relocation of our distribution lines. Our 2014 distribution sustainment capital investments were $356 million, compared to $324 million in 2013, an increase of $32 million or 10%. The increase is mainly due to the following:

•     increased investments in meter replacements, including Itron Sentinel 16S meter replacements and Field Metering Services installations;
•     higher volume of end-of-life wood pole replacements; •     increased focus on capital lines work, mainly due to the lines large sustainment initiatives program; •     increased work within our station refurbishment programs due to more refurbishments accomplished in 2014; and •     partially offset by less storm restoration work in 2014 due to lower storm activity compared to 2013.

Development Distribution Capital Investments

Our current development projects to expand and reinforce our distribution network include new customer connections and upgrades, system capability reinforcement projects, line transfers requested by our customers, and connections to new generation facilities. Our 2014 distribution development capital expenditures were $236 million, compared to $235 million in 2013, an increase of $1 million. The increase is mainly due to the following:

• increased work for subdivision connections, new customer connections, and upgrades;

• the purchase of retail revenue meters for all new connections and service upgrades; and

• partially offset by less lines and stations work related to upgrading and adding capacity to our distribution system.

Other Distribution Capital Investments

Our 2014 other distribution capital expenditures were $88 million, compared to $114 million in 2013, a decrease of $26 million or 23%. The decrease is mainly due to the following:

• decreased expenditures in 2014 related to CIS, as it was placed in-service in May 2013;

• decrease due to higher investments in 2013 as a result of emergency flood restoration work at our Richview Transmission Station resulting from a major rainstorm in July 2013; and

• partially offset by the investment in our Payroll Transformation Project to realize various process efficiencies.

Future Capital Investments

Our capital investments for 2015 are budgeted at approximately $1,600 million. Our 2015 capital budgets for our Transmission and Distribution Businesses are approximately $900 million and $700 million, respectively. Consolidated capital investments are expected to be approximately $1,625 million in 2016 and $1,575 million in 2017. These investment levels reflect our continued sustainment focus on our aging infrastructure. Our sustainment program capital investments are expected to be approximately $925 million in 2015, $950 million in 2016 and $1,000 million in 2017. Our development capital investments are expected to be approximately $450 million in 2015, $450 million in 2016, and $375 million in 2017. Our development projects include the inter-area network upgrades that reflect supply mix policies, local area supply improvements, the ADS Project, new load and generation connections and requirements to enable DG, and customer demand work. Other capital investments are expected to be $225 million in 2015, $225 million in 2016, and $200 million in 2017. This includes investments in operating infrastructure integration, information technology (IT), fleet services and facilities, and real estate. Our future capital investments amounts do not include future LDC acquisitions.  

32

HYDRO ONE INC.

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2014 and 2013

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. In addition, investments that are cross-functional and/or require IT involvement are governed by a productivity framework with substantive benefits. These capital investment plans are also included in our rate filings submitted to the OEB for approval.

Transmission

Transmission capital investments are incurred to manage the replacement and refurbishment of our aging transmission infrastructure in order to ensure a continued reliable supply of energy to customers throughout the province. Our sustainment program future capital investments include the replacement and/or refurbishment of end-of-life air blast circuit breakers and switchgear, high-voltage underground cables, high-voltage circuits and power transformers. Also, given the current age of our assets and infrastructure and to achieve significant cost efficiencies, we have moved to a more integrated station and circuit centric refurbishments approach than has been undertaken historically in order to address and bundle component and refurbishment replacements that would have occurred over time into one project. These investments are necessary to ensure that we maintain our current levels of supply to our customers and continue to meet all regulatory, compliance, safety and environmental objectives.

Our future development capital investments include the Clarington Transmission Station Project to install additional autotransformer capacity in the eastern GTA; the Guelph Area Transmission Refurbishment Project, an upgrade of a transmission line and transmission stations in south-central Guelph; investments in ADS; requirements to enable DG; the Supply to Essex County Transmission Reinforcement Project, a new transmission line in the Windsor-Essex region; and the Toronto Midtown Transmission Reinforcement Project, a new circuit in midtown Toronto and the refurbishment of an underground cable. Development capital investments also include the connection of new generation projects to the transmission system; however, these investments are largely funded by the connecting generation customers.

Based on the OEB’s framework for competitive designation for the development of eligible transmission projects, we did not include in our budgeted future capital investments any projects that could meet the definition of expansions. We do not plan to undertake large capital investments without a reasonable expectation of recovering them through our rates.

The actual timing and investments of many development projects are uncertain as they are dependent upon various regulatory approvals, negotiations with customers, neighbouring utilities and other stakeholders, and consultations with First Nations and Métis communities. Projects are also dependent upon the timing and level of generator contributions for enabling facilities.

Distribution

Distribution capital investments include the sustainment of our infrastructure. Our core work will continue to focus on maintaining the performance of our aging distribution asset base through renewal and refurbishment activities. Planned capital investments include the continued replacements of equipment and components that are beyond their expected service life, as well as increased wood pole replacements and distribution station refurbishments. Sustainment capital investments related to the smart metering project will decrease through 2016.

Distribution development capital investments are expected to be relatively stable through 2016, with the exception of capital contributions for capacity improvements at the Orleans Transmission Station in the Ottawa area in 2015 and the Hanmer Transmission Station in the Sudbury area in 2016. We will continue to make investments required to connect new load and DG customers, as well as investments to ensure the system is capable of supplying customer needs. During 2015 and 2016, a number of our projects will address local load growth issues. Generation connection investments, consisting of OPA-contracted FIT and MicroFIT Program generators, will decrease as the volume of connections is expected to decrease.

The ADS Project continues to pilot various technologies and related capital investments and will begin to decrease in 2015 and 2016. Pilot technologies include improvements to outage response management through more effective resource dispatch, automation to isolate faults where needed, and the dynamic regulation of voltage to reduce power losses.

33

HYDRO ONE INC.

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2014 and 2013

Off-Balance Sheet Arrangements

There are no off-balance sheet arrangements that have, or are reasonably likely to have, a material current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.

Summary of Contractual Obligations and Other Commercial Commitments

The following table presents a summary of our debt and other major contractual obligations, as well as other major commercial commitments:

December 31, 2014 (millions of Canadian dollars)	Total		Less than 1 year		1-3 years		3-5 years		More than 5 years
Contractual obligations (due by year)
Long-term debt – principal repayments1		8,923		550		1,100		978		6,295
Long-term debt – interest payments1		7,765		419		774		677		5,895
Pension2		361		174		187		—		—
Environmental and asset retirement obligations3		284		19		73		68		124
Outsourcing agreements4		701		179		291		218		13
Operating lease commitments		45		7		19		10		9
Total contractual obligations		18,079		1,348		2,444		1,951		12,336
Other commercial commitments (by year of expiry)
Bank line5		1,500		—		—		1,500		—
Letters of credit6		134		134		—		—		—
Guarantees6		331		331		—		—		—
Total other commercial commitments		1,965		465		—		1,500		—

¹  The “long-term debt – principal repayments” amounts are not charged to our results of operations, but are reflected on our Consolidated Balance Sheets and Consolidated Statements of Cash Flows. Interest associated with the long-term debt is recorded in financing charges on our Consolidated Statements of Operations and Comprehensive Income or as a cost of our capital programs.

²  Contributions to the Hydro One Pension Fund were generally made one month in arrears. However, due to the interest rate environment, the annual contributions have been prepaid in each of the last two years. No contribution prepayments are anticipated in 2015. The 2015 and 2016 minimum pension contributions are based on an actuarial valuation as at December 31, 2013. Pension contributions totalling $174 million were made during the year ended December 31, 2014. Minimum pension contributions beyond 2016 will be based on an actuarial valuation effective no later than December 31, 2016, and will depend on future investment returns, changes in benefits, or actuarial assumptions. Pension contributions beyond 2016 are not estimable at this time.

³  We record a liability for the estimated future expenditures associated with the removal and destruction of PCB-contaminated insulating oils and related electrical equipment, and for the assessment and remediation of chemically-contaminated lands. We also record a liability for asset retirement obligations associated with the removal and disposal of asbestos-containing materials installed in some of our facilities, as well as the future decommissioning and removal of two of our switching stations. The forecasted expenditure pattern reflects our planned work programs for the periods.

⁴ In 2014, we have finalized a new outsourcing agreement with Inergi for the provision of certain services, as well as a facilities outsourcing agreement with Brookfield. Details of the new outsourcing agreements can be found in the section “New Developments in 2014 – Other – Outsourcing Agreements.” Based on the September 2013 Shareholder Resolution, the Province requires us to contract only with parties who are employed and physically located in Ontario when providing services to our company. The contractual amounts disclosed include an estimated contractual annual inflation adjustment in the range of 1.9% to 2.1%. Payments in respect of our outsourcing agreements are recorded in operation, maintenance and administration costs on our Consolidated Statements of Operations and Comprehensive Income or as a cost of our capital programs.

⁵  In support of our liquidity requirements, we have a $1,500 million revolving standby credit facility with a syndicate of banks maturing in June 2019.

⁶  We currently have outstanding bank letters of credit of $126 million relating to retirement compensation arrangements. We provide prudential support to the IESO in the form of letters of credit, the amount of which is calculated based on forecasted monthly power consumption. At December 31, 2014, we have provided a letter of credit to the IESO in the amount of $8 million to meet our current prudential requirement. We have also provided prudential support to the IESO on behalf of our subsidiaries as required by the IESO’s Market Rules, using parental guarantees of $330 million, and on behalf of two distributors using total guarantees of $1 million.

34

HYDRO ONE INC.

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2014 and 2013

RELATED PARTY TRANSACTIONS

We are owned by the Province. The Ontario Electricity Financial Corporation (OEFC), IESO, OPA, OPG, and the OEB are related parties to our company because they are controlled or significantly influenced by the Province. The following is a summary of our related party transactions during the year ended December 31, 2014:

The Province

• During 2014, we paid dividends to the Province totalling $287 million, compared to $218 million paid in 2013.

• In November 2014, we redeemed the $250 million Province of Ontario Floating-Rate Notes held as a long-term investment. These notes were originally purchased in January 2010 with a maturity date of November 19, 2014.

IESO

• During 2014, we purchased power in the amount of $2,601 million from the IESO-administered electricity market, compared to $2,477 million purchased in 2013.

• We receive revenues for transmission services from the IESO, based on OEB-approved UTRs. Our 2014 transmission revenues include $1,556 million related to these services, compared to $1,509 million in 2013.

• We receive amounts for rural rate protection from the IESO. Our 2014 distribution revenues include $127 million related to this program, compared to $127 million in 2013.

• We receive revenues related to the supply of electricity to remote northern communities from the IESO. Our 2014 distribution revenues include $32 million related to these services, compared to $33 million in 2013.

OPA

• The OPA funds substantially all of our CDM programs. The funding includes program costs, incentives, and management fees. During 2014, we received $33 million from the OPA related to these programs, compared to $34 million received in 2013.

OPG

• During 2014, we purchased power in the amount of $23 million from OPG, compared to $15 million in 2013.

• Our company has service level agreements with OPG. These services include field, engineering, logistics and telecommunications services. Our 2014 other revenues include $12 million related to these service level agreements, compared to $9 million in 2013. Our 2014 operation, maintenance and administration costs related to the purchase of services with respect to these service level contracts were $1 million, compared to $1 million in 2013.

OEFC

• During 2014, we made payments in lieu of corporate income taxes to the OEFC totalling $86 million, compared to payments of $138 million made in 2013.

• During 2014, we purchased power in the amount of $9 million from power contracts administered by the OEFC, compared to $8 million purchased in 2013.

• During 2014, our company paid a $5 million annual fee to the OEFC, compared to $5 million paid in 2013, for indemnification against adverse claims in excess of $10 million paid by the OEFC with respect to certain of Ontario Hydro’s businesses transferred to Hydro One on April 1, 1999.

OEB

• Under the OEB Act, the OEB is required to recover all of its annual operating costs from gas and electricity distributors and transmitters. During 2014, we incurred $12 million in OEB fees, compared to $12 million incurred in 2013.

At December 31, 2014, the amounts due from and due to related parties as a result of the transactions described above were $224 million and $227 million, respectively, compared to $197 million and $230 million at December 31, 2013, respectively. At December 31, 2014, included in amounts due to related parties were amounts owing to the IESO in respect of power purchases of $214 million, compared to $217 million at December 31, 2013.

35

HYDRO ONE INC.

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2014 and 2013

CONSIDERATIONS OF CURRENT ECONOMIC CONDITIONS

Effect of Load on Revenue

Our load, based on normal weather patterns, is expected to increase in 2015 due to economic growth in all sectors of the Ontario economy, partially offset by the load impact of CDM and embedded generation. Overall load growth due to the economy alone is forecasted to be approximately 1.9%, with the commercial and industrial sectors slightly outperforming the residential sector. The load impacts of CDM and embedded generation are expected to have a negative impact on load growth of approximately 0.6% and 0.4%, respectively. On the whole, our load is expected to increase by approximately 0.9% in 2015. Our approved revenue requirement for 2015 has taken the negative load impact of CDM and embedded generation into account. A load growth below our load forecast, included in our approved revenue requirement, would negatively impact our financial results.

Effect of Interest Rates

Changes in interest rates will impact the calculation of the revenue requirements upon which our rates are based. The first component impacted by interest rates is our return on equity (ROE). The OEB-approved adjustment formula for calculating ROE will increase or decrease by 50% of the change between the current Long Canada Bond Forecast and the risk-free rate established at 4.25% and 50% of the change in the spread in 30-year “A”-rated Canadian utility bonds over the 30-year benchmark Government of Canada bond yield established at 1.415%. All other things being equal, we estimate that a 1% decrease in the forecasted long-term Government of Canada bond yield used in determining our ROE would reduce Hydro One Networks’ transmission and distribution businesses’ 2015 results of operations by approximately $20 million and $13 million, respectively. As interest rates decline, there is more risk of a decline in our net income. The second component of revenue requirement that would be impacted by interest rates is the return on debt. The difference between actual interest rates on new debt issuances and those approved for return by the OEB would impact our results of operations.

Input Costs

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

During 2014, we finalized a new outsourcing agreement with Inergi for the provision of certain services, as well as a facilities outsourcing agreement. Details of the new outsourcing agreements can be found in the section “New Developments in 2014 – Other – Outsourcing Agreements.”

Pension Plan

In 2014, we contributed approximately $174 million to our pension plan, compared to contributions of approximately $160 million made in 2013, and incurred $158 million in net periodic pension benefit costs, compared to $287 million incurred in 2013. We currently estimate our total annual pension contributions to be approximately $174 million for 2015 and $175 million for 2016, based on an actuarial valuation as at December 31, 2013 and projected levels of pensionable earnings. Actuarial valuations are required to be filed at least every three years. Future minimum contributions beyond 2016 will be based on an actuarial valuation effective no later than December 31, 2016. In 2014, our pension plan experienced positive returns of approximately 12.3%, compared to approximately 17.9% in 2013.

Our pension benefits obligation is impacted by various assumptions and estimates, such as discount rate, rate of return on plan assets, rate of cost of living increase, and mortality assumptions. A full discussion of the significant assumptions and estimates can be found in the section “Critical Accounting Estimates – Employee Future Benefits.”

36

HYDRO ONE INC.

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2014 and 2013

RISK MANAGEMENT AND RISK FACTORS

We have an Enterprise Risk Management (ERM) Program that aims at balancing business risks and returns. A company-wide approach enables regulatory, strategic, operational and financial risks to be managed and aligned with our strategic goals. Our ERM program helps us to better understand uncertainty and its potential impact on our strategic goals. It sets out the uniform principles, processes and criteria for identifying, assessing, evaluating, treating, monitoring and communicating risks across all lines of business. It supports our Board of Directors’ corporate governance needs and the due diligence responsibilities of senior management.

While our philosophy is that risk management is the responsibility of all employees, the Board of Directors annually reviews our company’s risk tolerances, risk management policies, processes and accountabilities. Twice per year, the Board of Directors reviews our risk profile, which is the list of key risks prepared by senior management, and represents the greatest threats to meeting our strategic objectives. The Board of Directors’ committees review risks relevant to their mandate at every meeting. The Audit, Finance and Pension Investment Committee of our Board of Directors annually reviews the status of our internal control framework.

Our President and Chief Executive Officer (CEO) has ultimate accountability for risk management. Our Leadership Team provides senior management oversight of our risk portfolio and our risk management processes. The leadership team provides direction on the evolution of these processes and identifies priority areas of focus for risk assessment and mitigation planning.

Our Chief Financial Officer (CFO) is responsible for ensuring that the risk management program is an integral part of our business strategy, planning and objective setting. The CFO has specific accountability for ensuring that ERM processes are established, properly documented and maintained by our company.

Our senior managers, line and functional managers are responsible for managing risks within the scope of their authority and accountability. Risk acceptance or mitigation decisions are made within the risk tolerances specified by the head of the subsidiary or function.

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

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

37

HYDRO ONE INC.

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2014 and 2013

Our key risks are as follows:

Ownership by the Province

The Province owns all of our outstanding shares. Accordingly, the Province has the power to determine the composition of our Board of Directors, 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 2001 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 MicroFIT 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.

Effective December 17, 2014, the Province made a further declaration pursuant to the memorandum of agreement and section 108 of the Business Corporations Act (Ontario) regarding the provision of information, personnel and resources to the Premier’s Advisory Council on Government Assets. By way of the declaration and concurrent Shareholder resolution, the Province restricted the rights, powers and duties of our Board of Directors, and at the same time assumed such rights, powers and duties, with respect to providing the Premier’s Advisory Council on Government Assets, the Government or the Ministries and their advisors and consultants all information, assistance, personnel, resources and reports as and when requested and co-operating with those Government advisors tasked with providing recommendations on labour relations matters and pension-related matters. The directors are charged with carrying out the intention of the declaration and resolution, including taking such necessary steps to issue similar declarations and resolutions with respect to Hydro One Networks and Hydro One Brampton Networks. The Province could mandate the selling of all or part of our distribution business and this could have a material adverse effect on our company.

In 2009, the Province required our company, among other entities, to adhere to certain accountability measures regarding consulting contracts and employee travel, meal and hospitality expenses. The Province may require us to adhere to further accountability measures or may make similar declarations in the future, some of which may have a material adverse effect on our business. Our company’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 our company’s ownership by the Province.

Conflicts of interest may arise between us and the Province as a result of the obligation of the Province to act in the best interests of the residents of Ontario in a broad range of matters, including the regulation of Ontario’s electricity industry and environmental matters, any future sale or other transaction by the Province with respect to its ownership interest in our company, including any potential outcomes arising out of the recommendations of the Ontario Distribution Sector Review Panel’s report, the Province’s ownership of OPG, and the determination of the amount of dividend or proxy tax payments. We may not be able to resolve any potential conflict with the Province on terms satisfactory to us, which could have a material adverse effect on our business.

Regulatory Risk

We are subject to regulatory risks, including the approval by the OEB of rates for our Transmission and Distribution Businesses that permit a reasonable opportunity to recover the estimated costs of providing safe and reliable service on a timely basis and earn the approved rates of return.

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

The OEB’s new RRFE requires that the term of a custom rate application (distribution business) be 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 our company’s capability to execute 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.

38

HYDRO ONE INC.

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2014 and 2013

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 the United States Federal Energy Regulatory Commission’s definition of Bulk Electric System unless we are granted an exception which will allow the application of the new definition in a cost-effective manner. Our company plans to submit exception applications and will look for recovery of costs incurred in meeting the definition in our rates; however, an adverse decision on an exception of 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 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.

First Nations 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, engagement and consultation 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 from Transfer of Assets Located on Reserves

The transfer orders by which we acquired certain of Ontario Hydro’s businesses as of April 1, 1999, did not transfer title to some assets located on Reserves. Currently, OEFC holds legal title to these assets and we manage them until we have obtained necessary authorizations to complete the title transfer. To occupy Reserves, our company 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, our company must negotiate terms of payment. 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 2014, we paid approximately $1 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.

39

HYDRO ONE INC.

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2014 and 2013

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.

Workforce Demographic Risk

By the end of 2014, approximately 17% of our employees were eligible for retirement and by the end of 2015 up to 21% could be eligible. These percentages are not evenly spread across our workforce, but tend naturally to be most significant in the most senior levels of our staff and especially among management and executive staff. Accordingly our continued success will be tied to our ability to attract and retain sufficient qualified staff to replace the capability lost through retirements and meet the demands of our work programs. This will be more challenging than in the past for a number of reasons.

Firstly, we expect the skilled labour market for our industry to be highly competitive in the future: many of our current employees and many of the employees we are going to be looking for possess skills and experience that will also be highly sought after by other organizations inside and outside the electricity sector; secondly, a variety of restraints on compensation and benefits for management and executive staff (including Bill 8) together with possible pension plan changes, and the uncertainty attaching to Hydro One’s future size and scope as a result of the work of the Council, may adversely impact our ability to attract and retain the number and calibre of people we need in these roles.

In order to mitigate the potential effects of these factors, we are focused on earlier identification and more rapid development of staff who demonstrate the potential to progress quickly, especially those who demonstrate leadership potential, and on maintaining robust but flexible succession plans for the organization. In addition we continue to advance our apprenticeship and technical training programs to ensure that our future operational staffing needs will be met.

Labour Relations Risk

The substantial majority of our employees are represented by either the Power Workers’ Union (PWU) or the Society of Energy Professionals (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.

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 $550 million maturing in 2015 and $500 million maturing in 2016. We plan to incur capital expenditures of approximately $1,600 million in 2015 and $1,625 million in 2016. 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

40

HYDRO ONE INC.

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2014 and 2013

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.

Asset Condition

We continually monitor the condition of our assets to determine need and timing of preventative or remedial actions to maintain the desired level of service. Condition assessment is one of the key drivers for asset maintenance, refurbishment or replacement strategies 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.

Environmental Risk

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

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

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2014 and 2013

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.

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 most recently filed valuation was prepared as at December 31, 2013, and was filed in June 2014. Our company contributed approximately $160 million in respect of 2013 and approximately $174 million in respect of 2014 to its pension plan to satisfy minimum funding requirements. Contributions beyond 2014 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.

Risk Associated with Outsourcing Arrangement

Consistent with our strategy of reducing operating costs, we entered into outsourcing arrangements with Inergi and Brookfield. Details of the new outsourcing agreements can be found in the section “New Developments in 2014 – Other – Outsourcing Agreements.” If either of these outsourcing agreements are terminated for any reason or expire before a new supplier is selected, we could be required to incur significant expenses to transfer to another service provider or insource, which could have a material adverse effect on our business, operating results, financial condition or prospects.

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’ 2015 net income by approximately $20 million and our Hydro One Networks’ distribution business’ 2015 net income by approximately $13 million. Our net income is adversely impacted by rising interest rates as our maturing long-term debt is refinanced at market rates. We periodically utilize interest rate swap agreements to mitigate elements of interest rate risk.

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

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2014 and 2013

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 Associated with Transmission Projects

Transmission projects involve either modifying existing or building new transmission lines and/or stations or both. Such projects are required primarily to address limitations on the transmission network to transfer power from generation sources to load centres, improve regional load supply capacity and reliability, connect new generators and load customers, and to meet new, or changes to, codes and standards.

In many cases, transmission investments are contingent upon one or more of the following approvals and/or processes: Environmental Assessment Act (Ontario) approval(s); receipt of OEB approvals which can include expropriation; and appropriate consultation processes with First Nations and Métis communities. Obtaining OEB and/or Environmental Assessment Act (Ontario) 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 possibly some identified enabler facilities and network enhancement projects. The facilitation of competitive transmission could impact our future work program and our ability to expand our current transmission footprint. In addition, as bid costs are recoverable only by the successful proponent, additional costs for unsuccessful bids would be absorbed. This could have a material adverse effect on our company.

Risk from Provincial Ownership of Transmission Corridors

Pursuant to the Reliable Energy and Consumer Protection Act, 2002, the Province acquired ownership of our transmission corridor lands underlying our transmission system. Although we have the statutory right to use the transmission corridors, we may be limited in our ability to expand our systems. Also, other uses of the transmission corridors by third parties in conjunction with the operation of our systems may increase safety or environmental risks, which could have an adverse effect on our company.

CRITICAL ACCOUNTING ESTIMATES

The preparation of our Consolidated Financial Statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and costs, and related disclosures of contingencies. We base our estimates and judgments on historical experience, current conditions and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities, as well as identifying and assessing our accounting treatment with respect to commitments and contingencies. Actual results may differ from these estimates and judgments. We have identified the following critical accounting estimates used in the preparation of our Consolidated Financial Statements:

Revenues

Our monthly distribution revenue is estimated based on wholesale electricity purchases. At the end of each month, the electricity delivered to customers, but not billed, is estimated and revenue is recognized. The newly implemented CIS phase of our entity-wide system improvement project will allow us to use historical trends at a customer level to better estimate our unbilled revenue each period. This change in methodology for estimating revenue is anticipated to be implemented in 2015. Any changes in estimate will be accounted for prospectively.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2014 and 2013

Allowance for Doubtful Accounts

The allowance for doubtful accounts reflects management’s best estimate of losses on billed accounts receivable balances. The allowance is based on accounts receivable aging, historical experience and other currently available information. The allowance for doubtful accounts on customer receivables is estimated by applying internally developed loss rates to the outstanding receivable balances by risk segment. Risk segments represent groups of customers with similar credit quality indicators and are computed based on various attributes, including number of days receivables are past due, delinquency of balances and payment history. Loss rates applied to the accounts receivable balances are based on historical average write-offs as a percentage of accounts receivable in each risk segment.

Regulatory Assets and Liabilities

Our regulatory assets represent certain amounts receivable from future electricity customers and costs that have been deferred for accounting purposes because it is probable that they will be recovered in future rates. Our regulatory assets mainly include costs related to the pension benefit liability, deferred income tax liabilities, post-retirement and post-employment benefit liability, and environmental liabilities. Our regulatory liabilities represent certain amounts that are refundable to future electricity customers, and pertain primarily to OEB deferral and variance accounts. The regulatory assets and liabilities can be recognized for rate-setting and financial reporting purposes only if the amounts have been approved for inclusion in the electricity rates by the OEB, or if such approval is judged to be probable by management. If management judges that it is no longer probable that the OEB will allow the inclusion of a regulatory asset or liability in future electricity rates, the applicable carrying amount of the regulatory asset or liability will be reflected in results of operations in the period that the judgment is made by management.

Environmental Liabilities

We record a liability for the estimated future expenditures associated with the removal and destruction of PCB-contaminated insulating oils and related electrical equipment, and for the assessment and remediation of chemically-contaminated lands.

There are uncertainties in estimating future environmental costs due to potential external events such as changes in legislation or regulations and advances in remediation technologies. In determining the amounts to be recorded as environmental liabilities, the Company estimates the current cost of completing required work and makes assumptions as to when the future expenditures will actually be incurred, in order to generate future cash flow information. All factors used in estimating the Company’s environmental liabilities represent management’s best estimates of the present value of costs required to meet existing legislation or regulations. However, it is reasonably possible that numbers or volumes of contaminated assets, cost estimates to perform work, inflation assumptions and the assumed pattern of annual cash flows may differ significantly from the Company’s current assumptions. Environmental liabilities are reviewed annually or more frequently if significant changes in regulations or other relevant factors occur. Estimate changes are accounted for prospectively.

In April 2014, Environment Canada enacted amendments to the existing PCB regulations, which included the extension of the end-of-use deadline from 2014 to 2025 for equipment containing certain concentrations of PCBs. Further discussion of the PCB amendments and related impact on our company can be found in the section “New Developments in 2014 – Other – Environment Canada Regulations.”

Employee Future Benefits

Our employee future benefits consist of pension and post-retirement and post-employment plans, and include pension, group life insurance, health care, and long-term disability benefits provided to our current and retired employees. Employee future benefits costs are included in our labour costs that are either charged to results of operations or capitalized as part of the cost of property, plant and equipment and intangible assets. Changes in assumptions affect the benefit obligation of the employee future benefits and the amounts that will be charged to our results of operations or capitalized in future years. The following significant assumptions and estimates are used to determine employee future benefit costs and obligations:

Weighted Average Discount Rate

The weighted average discount rate used to calculate the employee future benefits obligation is determined at each year end by referring to the most recently available market interest rates based on “AA”-rated corporate bond yields reflecting the duration of the applicable employee future benefit plan. The discount rate at December 31, 2014 decreased to 4.00% from 4.75% used at December 31, 2013, in conjunction with decreases in bond yields over this period. The decrease in the discount rate has resulted in a corresponding increase in employee future benefits liabilities for accounting purposes. The liabilities are determined by independent actuaries using the projected benefit method prorated on service and based on assumptions that reflect management’s best estimates.

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2014 and 2013

Expected Rate of Return on Plan Assets

The expected rate of return on pension plan assets is based on expectations of long-term rates of return at the beginning of the year and reflects a pension asset mix consistent with the pension plan’s current investment policy.

Rates of return on the respective portfolios are determined with reference to respective published market indices. The expected rate of return on pension plan assets reflects our long-term expectations. We believe that this assumption is reasonable because, with the pension plan’s balanced investment approach, the higher volatility of equity investment returns is intended to be offset by the greater stability of fixed-income and short-term investment returns. The net result, on a long-term basis, is a lower return than might be expected by investing in equities alone. In the short term, the pension plan can experience fluctuations in actual rates of return.

Rate of Cost of Living Increase

The rate of cost of living increase is determined by considering differences between long-term Government of Canada nominal bonds and real return bonds, which decreased from 2.00% per annum as at December 31, 2013 to approximately 1.70% per annum as at December 31, 2014. Given the Bank of Canada’s commitment to keep long-term inflation between 1.00% and 3.00%, management believes that the current rate is reasonable to use as a long-term assumption and as such, has used a 2.0% per annum inflation rate for employee future benefits liability valuation purposes as at December 31, 2014.

Mortality Assumptions

Our employee future benefits liability is also impacted by changes in life expectancies used in mortality assumptions. Increases in life expectancies of plan members result in increases in the employee future benefits liability. The mortality assumption at December 31, 2014 was updated to the final tables issued by the Canadian Institute of Actuaries (for public sector, with projection scale CPM-B and no adjustment due to pension size). As at December 31, 2013, the draft tables published by the Canadian Institute of Actuaries were used.

Rate of Increase in Health Care Cost Trends

The costs of post-retirement and post-employment benefits are determined at the beginning of the year and are based on assumptions for expected claims experience and future health care cost inflation. A 1% increase in the health care cost trends would result in a $23 million increase in 2014 interest cost plus service cost, and a $248 million increase in the year-end 2014 benefit liability.

Asset Impairment

Within our regulated businesses, the carrying costs of most of our long-lived assets are included in the rate base where they earn an OEB-approved rate of return. Asset carrying values and the related return are recovered through OEB-approved rates. As a result, such assets are only tested for impairment in the event that the OEB disallows recovery, in whole or in part, or if such a disallowance is judged to be probable. We regularly monitor the assets of our unregulated Hydro One Telecom subsidiary for indications of impairment. As at December 31, 2014, no asset impairment had been recorded for assets within our regulated or unregulated businesses.

Goodwill represents the cost of acquired LDCs that is in excess of the fair value of the net identifiable assets acquired at the acquisition date. Goodwill is evaluated for impairment on an annual basis, or more frequently if circumstances require. We have concluded that goodwill was not impaired at December 31, 2014.

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HYDRO ONE INC.

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2014 and 2013

DISCLOSURE CONTROLS AND INTERNAL CONTROLS OVER FINANCIAL REPORTING

Internal controls have been documented and tested for adequacy and effectiveness, and continue to be refined over all business processes.

In compliance with the requirements of National Instrument 52-109, our Certifying Officers have reviewed and certified the Consolidated Financial Statements for the year ended December 31, 2014, together with other financial information included in our securities filings. Our Certifying Officers have also certified that disclosure controls and procedures (DC&P) have been designed to provide reasonable assurance that material information relating to our company is made known within our company. Further, our Certifying Officers have certified that internal controls over financial reporting (ICFR) have been designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Consolidated Financial Statements. Based on the evaluation of the design and operating effectiveness of our company’s DC&P and ICFR, our Certifying Officers concluded that our company’s DC&P and ICFR were effective as at December 31, 2014.

NEW ACCOUNTING PRONOUNCEMENTS

In May 2014, the Financial Accounting Standards Board (FASB) issued an accounting standards update that provides guidance on revenue recognition which depicts the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods and services. This update is applicable to our company for the years and interim periods beginning on January 1, 2017. We are currently assessing the impact of adoption of this accounting standards update on our consolidated financial statements.

In August 2014, the FASB issued an accounting standards update that provides guidance about management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern and related disclosures. This update is applicable to our company for the year ending December 31, 2016, and for annual and interim periods thereafter. We do not anticipate that the adoption of this accounting standards update will have a significant impact on our consolidated financial statements.

In November 2014, the FASB issued an accounting standards update that provides guidance on accounting for hybrid financial instruments issued in the form of a share. This update is applicable to our company for the years and interim periods beginning on January 1, 2016. We are currently assessing the impact of adoption of this accounting standards update on our consolidated financial statements.

OUTLOOK

We will achieve our mission and vision and 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. We will do this by continuing to concentrate on our strategic objectives of safety, customer satisfaction, continuous innovation, reliability, protection of the environment, championing people and culture, Shareholder value and productivity and cost-effectiveness. We continue to seek to strike the right balance between making prudent risk-based reliability investments and keeping customers’ rates low. Effectively and efficiently managing costs is an important part of achieving this balance.

Given the nature of the work undertaken by our employees and contractors, safety remains our top priority. We will continue to focus on creating an injury-free workplace and maintaining public safety through several health and safety initiatives, including maintaining our OHSAS 18001 standing.

We are focused on becoming a customer centric company and achieving our vision of improving customer satisfaction, maintaining affordable rates for the portion of the customers’ bill within our control and building a trusted partner relationship with our customers. Our plan has taken into account discussions with our customers and reflects the planned development and delivery of targeted customer segment strategies, products and services which respond to our customers’ unique needs. This includes realizing value from our new CIS, simplifying and shortening timeframes for the delivery of services, enhancing accessibility in person, by phone or through our web portal and/or our mobile application to ensure effective self-service for simple transactions, and delivering programs which help customers better manage their energy

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2014 and 2013

consumption. In addition, to further improve our customer service performance culture as a transparent, accountable and customer-focused organization, we have recently announced two new initiatives – a third party expert Customer Service Advisory Panel and our draft Customer Commitments.

We will continue to focus on driving our transformation to a culture that is accountability-based. All of our management staff received training under our Craft of Management program. In addition, a new Talent Management program was piloted in 2014 and will be rolled out company-wide in 2015. These programs will serve as the foundation for establishing that culture of accountability. Investments in these programs, coupled with existing programs which enhance employee skills and ability, will help us deliver best-in-class service to our customers, continue the drive to zero workplace injuries and create a great workplace that will lead to improved employee engagement. We remain focused on managing the resourcing requirements of an increasing work program through appropriate compensation policies, labour negotiations, use of outsourced multi-skilled staff and support of internal and external college and university training programs. Aging workforce demographics provide opportunities, through retirements, to restructure and transform the workforce.

Our assets are in the midst of a demographic change with an increasing proportion of assets reaching the end of their expected service life and an increasing average asset age. To ensure the electricity system’s reliability in the public interest, we have planned for significant investments in transmission and distribution infrastructure. Our plan includes targeted, risk-based investments to maintain, refurbish and replace existing assets that are in poor condition and beyond their expected service life, within the policy set by the OEB. Investments in technology, such as the successful implementation of Asset Analytics, have provided us with real-time asset condition and performance data, giving us the ability to make asset optimization life-cycle decisions, and opportunities through planning and scheduling data to improve materials procurement and to deploy work crews to better manage work programs to meet customer needs.

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

Over the last five years, we have replaced all of our core IT systems with a company-wide IT system. Further development of the existing IT platform will enable various tools to consistently provide a comprehensive and cascading information view of asset risks based on demographics, condition, performance, criticality, economics and utilization. In addition, we have introduced talent management, employee pay and time reporting enhancements to reduce costs, and to further develop and retain critical core competencies, skills and knowledge of our people. These new initiatives will allow us to effectively plan and reprioritize work and integrate customers’ needs into multi-year investment plans. This outcome is consistent with the OEB’s direction in its new Outcomes-Based Approach to regulation.

Our plan is focused on delivering integrated asset-to-work planning, optimized scheduling, and execution, as well as field mobility. Through our investment in our Workflow of the Future initiative (currently a pilot program), we will bring together data, analytics and mobility to allow our employees, especially those in the field, to do more at the job site with their mobile devices.

Significant opportunity resides with smart meters and the proliferation of ADS including energy efficiency, demand response and distributed-resource technologies over the long term. Our investments in this area will focus on reliability, customer needs and affordability. We will continue to invest on a prudent basis in the development of ADS and related grid modernization standards, customer demand work (connections and upgrades), smart meters, DG connections, including station upgrades, protection and control, new lines and some contestable work, for which we will receive customer capital contributions. There is little flexibility to reduce this work as most of it is customer demand driven.

Consistent with our corporate strategy, we will pursue an LDC consolidation approach that is robust but prudent, to facilitate the consolidation of Ontario’s distribution sector. This is consistent with the Ontario Distribution Sector Review Panel’s assessment that there are substantial efficiencies to be found through consolidation of Ontario LDCs and we are key to the solution. We will also work with our Shareholder to address the recommendations of the Council once they are finalized in the Council’s final report which is anticipated in the spring of 2015. Our plan does not include funding for LDC acquisitions or assume any disposition of our service territory. These opportunities will be managed as they arise. Our plan also does not incorporate any projects related to competitive transmission. However, as leaders in the sector, we plan to bid on key projects. The OEB notes in its Framework for Transmission Project Development Plans that where projects are otherwise equivalent or close in other factors, information such as socio-economic benefits, including First Nations involvement, could prove decisive in a competitive bid. As such, First Nations involvement in competitive bids is likely to become more prevalent.

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HYDRO ONE INC.

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2014 and 2013

CHANGES TO OUR BOARD OF DIRECTORS

On March 7, 2014, our Shareholder, the Minister of Energy, on behalf of the Government of Ontario, announced that Sandra Pupatello would be appointed Chair of our Board of Directors, effective April 1, 2014, and on April 1, 2014, the Shareholder formally elected Ms. Pupatello as our new Chair. Ms. Pupatello is the Director of Business Development and Global Markets at PricewaterhouseCoopers Canada. She is also the Chief Executive Officer of the WindsorEssex Economic Development Corporation. Ms. Pupatello has been a member of our Board of Directors since November 2013.

On April 11, 2014, the following new members were added to our Board of Directors: William Limbrick, Tom Moss, and John Wiersma. William Limbrick was the Vice President of Information and Technology Services, Chief Information Officer of the IESO, and a Principal Consultant within the utilities practice of PricewaterhouseCoopers and Sun Life Assurance in the United Kingdom. Tom Moss is the former President and Chief Operating Officer of Telecom Ottawa, and has held strategic policy positions in the federal government at Treasury Board and Industry Canada. John Wiersma, P.Eng., is a former director of the ESA (Ontario) and IESO Board of Directors, and a former member of the Board of the Electrical and Utilities Safety Association and the Canadian Energy Efficiency Alliance.

On April 25, 2014, the following new members were added to our Board of Directors: Sally Daub, Maureen Sabia, and Carole Workman. Sally Daub is a director and former President and Chief Executive Officer of ViXS Systems, a former chair of the Small Business Agency of Ontario, and a former board member of the Information Technology Association of Canada and the Global Semiconductor Association. Maureen Sabia is the Chair of the Board of Canadian Tire Corporation Limited, and has an extensive background with organizations at the provincial and federal levels. She has been named one of Canada’s Most Powerful Women and is also an officer of the Order of Canada. Carole Workman is a member of the Board of Allstate Insurance of Canada (Toronto). She also served on the Board of the Ottawa Hospital and its affiliates since 2007, and is a former member of the Board of Hydro Ottawa Holding Inc.

On April 1, 2014, James Arnett resigned from our Board of Directors. Mr. Arnett has been a member and Chair of our Board of Directors since March 2008. The Board of Directors terms for Michael Mueller, Walter Murray, Robert Pace, and Douglas Speers expired on April 11, 2014.

FORWARD-LOOKING STATEMENTS AND INFORMATION

Our oral and written public communications, including this document, often contain forward-looking statements that are based on current expectations, estimates, forecasts and projections about our business and the industry in which we operate, and include beliefs and assumptions made by the management of our company. Such statements include, but are not limited to: expectations regarding energy-related revenues and profit and their trend; statements regarding our transmission and distribution rates and customer bills resulting from our rate applications; statements related to the FIT program; statements about CDM; statements about our strategy, including our strategic objectives; statements regarding considerations of current economic conditions; statements regarding the new regional planning process; statements related to employee future benefits; expectations regarding First Nation involvement in competitive bids; statements regarding our liquidity and capital resources and operational requirements; statements about our standby credit facility; expectations regarding our financing activities; statements regarding our maturing debt; statements regarding our ongoing and planned projects and/or initiatives including the expected results of these projects and/or initiatives (including productivity savings, process improvements, and customer satisfaction) and their completion dates; expectations regarding the recoverability of large capital investments; expectations regarding generation connection investments; statements regarding expected future capital and development investments, the timing of these expenditures and our investment plans; expectations regarding OPA recommendations; statements regarding contractual obligations and other commercial commitments; statements related to the OEB; statements regarding future pension contributions, our pension plan and actuarial valuation; statements about our outsourcing arrangements with Inergi and Brookfield and such future outsourcing arrangements; statements regarding customer service performance culture, including statements about the Customer Service Advisory Panel and Customer Commitments; expectations regarding work and costs of compliance with environmental and health and safety regulations; statements related to the 2013 LTEP; statements regarding recent accounting-related guidance; statements related to the Council; statements related to the Working

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MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2014 and 2013

Group on electricity sector pension plans; statements related to B2M LP; and statements related to LDC consolidation including our acquisition of Norfolk Power, Woodstock Hydro, and Haldimand Hydro. Words such as “expect”, “anticipate”, “intend”, “attempt”, “may”, “plan”, “will”, “believe”, “seek”, “estimate”, “goal”, “aim”, “target”, and variations of such words and similar expressions are intended to identify such forward-looking statements. These statements are not guarantees of future performance and involve assumptions and risks and uncertainties that are difficult to predict. Therefore, actual outcomes and results may differ materially from what is expressed, implied or forecasted in such forward-looking statements. We do not intend, and we disclaim any obligation, to update any forward-looking statements, except as required by law.

These forward-looking statements are based on a variety of factors and assumptions including, but not limited to, the following: no unforeseen changes in the legislative and operating framework for Ontario’s electricity market; favourable decisions from the OEB and other regulatory bodies concerning outstanding rate and other applications; no delays in obtaining the required approvals; no unforeseen changes in rate orders or rate structures for our Distribution and Transmission Businesses; continued use of US GAAP; a stable regulatory environment; no unfavourable changes in environmental regulation; and no significant event occurring outside the ordinary course of business. These assumptions are based on information currently available to us, including information obtained from third party sources. Actual results may differ materially from those predicted by such forward-looking statements. While we do not know what impact any of these differences may have, our business, results of operations, financial condition and our credit stability may be materially adversely affected. Factors that could cause actual results or outcomes to differ materially from the results expressed or implied by forward-looking statements include, among other things:

• the risks associated with being controlled by the Province including the possibility that the Province may make declarations pursuant to the memorandum of agreement, the Province could mandate the selling of all or part of our Distribution Business, as well as potential conflicts of interest that may arise between us, the Province and related parties;

• the risks associated with being subject to extensive regulation including risks associated with OEB action or inaction, including regulatory decisions regarding our revenue requirements, cost recovery, rates, acquisitions and divestitures;

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

• 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;

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

• the risk that we may incur significant costs associated with transferring assets located on Reserves (as defined in the Indian Act (Canada));

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

• the ability to negotiate appropriate collective agreements;

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

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

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

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

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

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HYDRO ONE INC.

MANAGEMENT’S DISCUSSION AND ANALYSIS (continued)

For the years ended December 31, 2014 and 2013

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

• the potential that we may incur significant expenses to replace some or all of the functions currently outsourced if either of our agreements with Inergi or Brookfield are terminated or expire before a new service provider is selected;

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

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

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

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

• the inability to prepare financial statements using US GAAP, or IFRS, as applicable;

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

• unanticipated changes in electricity demand or in our costs;

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

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

We caution the reader that the above list of factors is not exhaustive. Some of these and other factors are discussed in more detail in the section “Risk Management and Risk Factors” in this MD&A. You should review this section in detail.

In addition, we caution the reader that information provided in this MD&A regarding our outlook on certain matters, including potential future expenditures, is provided in order to give context to the nature of some of our future plans and may not be appropriate for other purposes.

Additional information about the Company, including the Company’s Annual Information Form, can be found on SEDAR at www.sedar.com and on the US Securities and Exchange Commission’s website at www.sec.gov.

50

EX-99.4

Exhibit 99.4

Consent of Independent Registered Public Accounting Firm

The Board of Directors

Hydro One Inc.

We consent to the use of our report, dated February 11, 2015, with respect to the consolidated financial statements included in this annual report on Form 40-F.

We also consent to the incorporation by reference of such report in the Registration Statements (No. 333-190657) on Form F-10 of Hydro One Inc.

/s/ KPMG LLP

Chartered Professional Accountants, Licensed Public Accountants

February 27, 2015

Toronto, Canada

EX-99.5

Exhibit 99.5

CERTIFICATION

Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

I, Carmine Marcello, President and Chief Executive Officer, Hydro One Inc., certify that:

1. I have reviewed this annual report on Form 40-F of Hydro One Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report;

4. The issuer’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the issuer and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Evaluated the effectiveness of the issuer’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation;

c) Disclosed in this report any change in the issuer’s internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the issuer’s internal control over financial reporting; and

d) Disclosed in this report any change in the issuer’s internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the issuer’s internal control over financial reporting; and

5. The issuer’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer’s auditors and the audit committee of the issuer’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer’s internal control over financial reporting.

Date: February 27, 2015	/s/ Carmine Marcello
	Carmine Marcello
	President and Chief Executive Officer

EX-99.6

Exhibit 99.6

CERTIFICATION

Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

I, Ali Suleman, Chief Financial Officer (Acting), Hydro One Inc., certify that:

1. I have reviewed this annual report on Form 40-F of Hydro One Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report;

4. The issuer’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the issuer and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Evaluated the effectiveness of the issuer’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation;

c) Disclosed in this report any change in the issuer’s internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the issuer’s internal control over financial reporting; and

d) Disclosed in this report any change in the issuer’s internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the issuer’s internal control over financial reporting; and

5. The issuer’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer’s auditors and the audit committee of the issuer’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer’s internal control over financial reporting.

Date: February 27, 2015	/s/ Ali R. Suleman
	Ali R. Suleman
	Chief Financial Officer (Acting)

EX-99.7

Exhibit 99.7

CERTIFICATION

Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the Annual Report of Hydro One Inc. (the “Company”) on Form 40-F for the year ended December 31, 2014 (the “Report”) as filed with the U.S. Securities and Exchange Commission,

I, Carmine Marcello, President and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as enacted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

i. The Report fully complies with the requirements of Section 13(a) or 15(d) of the U.S. Securities Exchange Act of 1934; and

ii. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: February 27, 2015	/s/ Carmine Marcello
	Carmine Marcello
	President and Chief Executive Officer

EX-99.8

Exhibit 99.8

CERTIFICATION

Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the Annual Report of Hydro One Inc. (the “Company”) on Form 40-F for the year ended December 31, 2014 (the “Report”) as filed with the U.S. Securities and Exchange Commission,

I, Ali Suleman, Chief Financial Officer (Acting) of the Company, certify, pursuant to 18 U.S.C. Section 1350, as enacted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

i. The Report fully complies with the requirements of Section 13(a) or 15(d) of the U.S. Securities Exchange Act of 1934; and

ii. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: February 27, 2015	/s/ Ali R. Suleman
	Ali R. Suleman
	Chief Financial Officer (Acting)

XML

Accounts Receivable (Tables)

12 Months Ended

Dec. 31, 2014

Receivables [Abstract]

Schedule of Accounts Receivable

December 31 (millions of Canadian dollars)	2014			2013
Accounts receivable – billed		496			268
Accounts receivable – unbilled		586			691
Accounts receivable, gross		1,082			959
Allowance for doubtful accounts		(66	)		(36	)
Accounts receivable, net		1,016			923

Schedule of Allowance for Doubtful Accounts

The following table shows the movements in the allowance for doubtful accounts for the years ended December 31, 2014 and 2013:

Year ended December 31 (millions of Canadian dollars)	2014			2013
Allowance for doubtful accounts – January 1		(36	)		(23	)
Write-offs		24			24
Additions to allowance for doubtful accounts		(54	)		(37	)
Allowance for doubtful accounts – December 31		(66	)		(36	)

XML

Consolidated Statements of Cash Flows - Schedule of Consolidated Statement of Cash Flows (Detail) (CAD) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Supplemental Cash Flow Elements [Abstract]
Accounts receivable	(93)	(78)
Due from related parties	(27)	(43)
Prepaid expenses and other assets	(13)	(5)
Accounts payable	39	13
Accrued liabilities	(35)	71
Due to related parties	(3)	(31)
Accrued interest		5
Long-term accounts payable and other liabilities	(3)	(5)
Post-retirement and post-employment benefit liability	80	84
Changes in non-cash balances related to operations, Total	(55)	11
Capital Expenditures
Capital investments in property, plant and equipment	(1,511)	(1,312)
Capitalized depreciation and net change in accruals included in capital investments in property, plant and equipment	30	4
Capital expenditures - property, plant and equipment	(1,481)	(1,308)
Capital investments in intangible assets	(19)	(82)
Net change in accruals included in capital investments in intangible assets	(4)	3
Capital expenditures - intangible assets	(23)	(79)
Supplementary Information
Net interest paid	412	395
PILs	86	138

XML

Business Combinations - Additional Information (Detail) (CAD)	12 Months Ended	0 Months Ended
	Dec. 31, 2014	Dec. 17, 2014	Dec. 16, 2014	Dec. 31, 2013	Aug. 29, 2014	May 21, 2014	Jun. 10, 2014
Business Acquisition [Line Items]
Business acquisition, net loss attributable to noncontrolling interest	(2,000,000)
Goodwill	173,000,000			133,000,000
Class B Units [Member]
Business Acquisition [Line Items]
Business acquisition, net loss attributable to noncontrolling interest	(2,000,000)
Business acquisition, net loss attributable to noncontrolling interest subject to redemption	(1,000,000)
Norfolk Power [Member]
Business Acquisition [Line Items]
Percentage of common shares acquired					100.00%
Date of acquisition agreement	Aug. 29, 2014
Purchase price of acquisition					68,000,000
Goodwill	40,000,000
Goodwill, Expected Tax Deductible Amount	0
Revenues	18,000,000
Norfolk Power [Member] | Maximum [Member]
Business Acquisition [Line Items]
Net income	1,000,000
Woodstock Hydro [Member]
Business Acquisition [Line Items]
Percentage of common shares acquired						100.00%
Date of acquisition agreement	May 21, 2014
Purchase price of acquisition						29,000,000
Business acquisition, anticipated completion period	The transaction is anticipated to be completed in 2015.
Refundable deposit on acquisition	2,000,000
Haldimand Hydro [Member]
Business Acquisition [Line Items]
Percentage of common shares acquired							100.00%
Date of acquisition agreement	Jun. 10, 2014
Purchase price of acquisition							65,000,000
Business acquisition, anticipated completion period	The transaction is anticipated to be completed in 2015.
Refundable deposit on acquisition	3,000,000
B2M Limited Partnership [Member]
Business Acquisition [Line Items]
Business combination assets transferred			526,000,000
Percentage of common shares acquired		34.20%
Business acquisition, consideration paid		72,000,000
B2M Limited Partnership [Member] | Debt [Member]
Business Acquisition [Line Items]
Business combination assets transferred			316,000,000
Business combination percentage transferred			60.00%
B2M Limited Partnership [Member] | Equity [Member]
Business Acquisition [Line Items]
Business combination assets transferred			210,000,000
Business combination percentage transferred			40.00%

XML

Related Party Transactions (Tables)

12 Months Ended

Dec. 31, 2014

Related Party Transactions [Abstract]

Schedule of Amounts Due to and from Related Parties

The amounts due to and from related parties as a result of the transactions referred to above are as follows:

December 31 (millions of Canadian dollars)	2014			2013
Due from related parties		224			197
Due to related parties1		(227	)		(230	)
Investment		—			251

¹  Included in due to related parties at December 31, 2014 are amounts owing to the IESO in respect of power purchases of $214 million (2013 – $217 million).

XML

Debt and Credit Agreements - Additional Information (Detail) (CAD)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Debt Instrument [Line Items]
Commercial paper borrowings outstanding	0	0
Issuance of long-term debt under MTN Program	628,000,000	1,185,000,000
Medium-Term Note [Member]
Debt Instrument [Line Items]
Remaining borrowing capacity	1,187,000,000
Maximum authorized principal amount	3,000,000,000
Remaining available for issuance period	October 2015
Issuance of long-term debt under MTN Program	628,000,000	1,185,000,000
Medium-Term Note [Member] | Norfolk Power [Member]
Debt Instrument [Line Items]
MTN loan repaid and redeemed	26,000,000
Medium-Term Note [Member] | Series 19 Notes [Member]
Debt Instrument [Line Items]
MTN loan repaid and redeemed	750,000,000
Medium-Term Note [Member] | Series 15 Notes [Member]
Debt Instrument [Line Items]
MTN loan repaid and redeemed		600,000,000
Commercial Paper [Member]
Debt Instrument [Line Items]
Maximum borrowing capacity	1,000,000,000
Maturities days of commercial paper	365 days
Committed Revolving Standby Credit Facility [Member]
Debt Instrument [Line Items]
Maximum borrowing capacity	1,500,000,000
Remaining borrowing capacity	1,500,000,000
Revolving credit facility maturity period	June 2019

XML

Business Combinations - Summary of Preliminary Determination of Fair Value of Assets Acquired and Liabilities Assumed (Detail) (CAD) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Business Acquisition [Line Items]
Goodwill	173	133
Norfolk Power [Member]
Business Acquisition [Line Items]
Working capital	6
Property, plant and equipment	56
Deferred income tax assets	1
Goodwill	40
Bank indebtedness	(3)
Derivative instruments	(3)
Long-term debt	(26)
Post-retirement and post-employment benefit liability	(1)
Environmental liability	(1)
Long-term accounts payable and other liabilities	(1)
Total	68

XML

Fair Value of Financial Instruments and Risk Management - Summary of Principal Repayments, Interest Payments and Related Weighted Average Interest Rates (Detail) (CAD) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Debt Instrument [Line Items]
Long-term Debt Principal Repayments, 1 year	550
Long-term Debt Principal Repayments, 2 years	500
Long-term Debt Principal Repayments, 3 years	600
Long-term Debt Principal Repayments, 4 years	750
Long-term Debt Principal Repayments, 5 years	228
Long-term Debt Principal Repayments, After 5 years Total	2,628
Long-term Debt Principal Repayments, 6 - 10 years	900
Long-term Debt Principal Repayments, Over 10 years	5,395
Long-term Debt Principal Repayments	8,923	9,045
Interest Payments	7,765
Weighted Average Interest Rate	4.70%
1 Year [Member]
Debt Instrument [Line Items]
Interest Payments	419
Weighted Average Interest Rate	2.80%
2 Years [Member]
Debt Instrument [Line Items]
Interest Payments	393
Weighted Average Interest Rate	4.30%
3 Years [Member]
Debt Instrument [Line Items]
Interest Payments	381
Weighted Average Interest Rate	5.20%
4 Years [Member]
Debt Instrument [Line Items]
Interest Payments	350
Weighted Average Interest Rate	2.80%
5 Years [Member]
Debt Instrument [Line Items]
Interest Payments	327
Weighted Average Interest Rate	1.60%
5 Years, Total [Member]
Debt Instrument [Line Items]
Interest Payments	1,870
Weighted Average Interest Rate	3.50%
6-10 Years [Member]
Debt Instrument [Line Items]
Interest Payments	1,522
Weighted Average Interest Rate	3.60%
Over 10 Years [Member]
Debt Instrument [Line Items]
Interest Payments	4,373
Weighted Average Interest Rate	5.40%

XML

Environmental Liabilities - Schedule of Estimated Future Environmental Expenditures (Detail) (CAD) In Millions, unless otherwise specified	Dec. 31, 2014
Environmental Expense and Liabilities [Abstract]
2015	18
2016	37
2017	36
2018	35
2019	33
Thereafter	106
Total	265

XML

Pension and Post-Retirement and Post-Employment Benefits (Tables)

12 Months Ended

Dec. 31, 2014

Change in Projected Benefit Obligation and Change in Plan Assets

The impact of changes in assumptions used to measure pension, post-retirement and post-employment benefit obligations is generally recognized over the expected average remaining service period of the employees. The measurement date for the Plans is December 31.

	Pension Benefits						Post-Retirement and Post-Employment Benefits
Year ended December 31 (millions of Canadian dollars)	2014			2013			2014			2013
Change in projected benefit obligation
Projected benefit obligation, beginning of year		6,576			6,507			1,531			1,459
Current service cost		145			170			41			40
Interest cost		312			278			73			63
Reciprocal transfers		—			1			—			—
Benefits paid		(319	)		(317	)		(45	)		(44	)
Net actuarial loss (gain)		821			(63	)		(18	)		13
Projected benefit obligation, end of year		7,535			6,576			1,582			1,531
Change in plan assets
Fair value of plan assets, beginning of year		5,731			4,992			—			—
Actual return on plan assets		703			887			—			—
Reciprocal transfers		—			1			—			—
Benefits paid		(319	)		(317	)		—			—
Employer contributions		174			160			—			—
Employee contributions		35			30			—			—
Administrative expenses		(25	)		(22	)		—			—
Fair value of plan assets, end of year		6,299			5,731			—			—
Unfunded status		1,236			845			1,582			1,531

Schedule of Benefit Obligations and Plan Assets

Hydro One presents its benefit obligations and plan assets net on its Consolidated Balance Sheets within the following line items:

	Pension Benefits				Post-Retirement and Post-Employment Benefits
December 31 (millions of Canadian dollars)	2014		2013		2014		2013
Accrued liabilities		—		—		49		43
Pension benefit liability		1,236		845		—		—
Post-retirement and post-employment benefit liability		—		—		1,533		1,488
Unfunded status		1,236		845		1,582		1,531

Schedule of Projected Benefit Obligation (PBO), Accumulated Benefit Obligation (ABO) and Fair Value of Plan Assets

The following table provides the projected benefit obligation (PBO), accumulated benefit obligation (ABO) and fair value of plan assets for the Pension Plan:

December 31 (millions of Canadian dollars)	2014		2013
PBO		7,535		6,576
ABO		6,887		5,998
Fair value of plan assets		6,299		5,731

Schedule of Weighted Average Assumptions Used to Determine Benefit Obligations

The following weighted average assumptions were used to determine the benefit obligations at December 31, 2014 and 2013:

	Pension Benefits						Post-Retirement and Post-Employment Benefits
Year ended December 31	2014			2013			2014			2013
Significant assumptions:
Weighted average discount rate		4.00	%		4.75	%		4.00	%		4.75	%
Rate of compensation scale escalation (without merit)		2.50	%		2.50	%		2.50	%		2.50	%
Rate of cost of living increase		2.00	%		2.00	%		2.00	%		2.00	%
Rate of increase in health care cost trends1		—			—			4.36	%		4.39	%

¹ 6.52% per annum in 2015, grading down to 4.36% per annum in and after 2031 (2013 – 6.81% in 2014, grading down to 4.39% per annum in and after 2031)

Schedule of Weighted Average Assumptions Used to Determine Net Periodic Benefit Costs

The following weighted average assumptions were used to determine the net periodic benefit costs for the years ended December 31, 2014 and 2013. Assumptions used to determine current year-end benefit obligations are the assumptions used to estimate the subsequent year’s net periodic benefit costs.

Year ended December 31	2014			2013
Pension Benefits:
Weighted average expected rate of return on plan assets		6.50	%		6.25	%
Weighted average discount rate		4.75	%		4.25	%
Rate of compensation scale escalation (without merit)		2.50	%		2.50	%
Rate of cost of living increase		2.00	%		2.00	%
Average remaining service life of employees (years)		11			11
Post-Retirement and Post-Employment Benefits:
Weighted average discount rate		4.75	%		4.25	%
Rate of compensation scale escalation (without merit)		2.50	%		2.50	%
Rate of cost of living increase		2.00	%		2.00	%
Average remaining service life of employees (years)		12			12
Rate of increase in health care cost trends1		4.39	%		4.39	%

¹  6.81% per annum in 2014, grading down to 4.39% per annum in and after 2031 (2013 – 6.91% in 2013, grading down to 4.39% per annum in and after 2031)

Schedule of Effect of One Percent Change in Health Care Cost Trends on Projected Benefit Obligation

The effect of a 1% change in health care cost trends on the projected benefit obligation for the post-retirement and post-employment benefits at December 31, 2014 and 2013 is as follows:

December 31 (millions of Canadian dollars)	2014			2013
Projected benefit obligation:
Effect of a 1% increase in health care cost trends		248			258
Effect of a 1% decrease in health care cost trends		(193	)		(200	)

Schedule of Effect of One Percent Change in Health Care Cost Trends on Service Cost and Interest Cost

The effect of a 1% change in health care cost trends on the service cost and interest cost for the post-retirement and post-employment benefits for the years ended December 31, 2014 and 2013 is as follows:

Year ended December 31 (millions of Canadian dollars)	2014			2013
Service cost and interest cost:
Effect of a 1% increase in health care cost trends		23			21
Effect of a 1% decrease in health care cost trends		(17	)		(16	)

Approximate Life Expectancies Used to Determine Projected Benefit Obligations for Pension, Post-Retirement and Post-Employment Plans

The following approximate life expectancies were used in the mortality assumptions to determine the projected benefit obligations for the pension and post-retirement and post-employment plans at December 31, 2014 and 2013:

December 31, 2014				December 31, 2013
Life expectancy at 65 for a member currently at				Life expectancy at 65 for a member currently at
Age 65		Age 45		Age 65		Age 45
Male	Female	Male	Female	Male	Female	Male	Female
23	25	24	26	23	25	24	26

Schedule of Estimated Future Benefit Payments

At December 31, 2014, estimated future benefit payments to the participants of the Plans were:

(millions of Canadian dollars)	Pension Benefits		Post-Retirement and Post-Employment Benefits
2015		305		50
2016		316		52
2017		328		54
2018		339		56
2019		350		59
2020 through to 2024		1,889		332
Total estimated future benefit payments through to 2024		3,527		603

Schedule of Actuarial Gains and Losses and Prior Service Costs Recorded Within Regulatory Assets

The following table provides the actuarial gains and losses and prior service costs recorded within regulatory assets:

Year ended December 31 (millions of Canadian dollars)	2014			2013
Pension Benefits:
Actuarial loss (gain) for the year		511			(619	)
Actuarial loss amortization		(103	)		(175	)
Prior service cost amortization		(2	)		(2	)
		406			(796	)
Post-Retirement and Post-Employment Benefits:
Actuarial loss (gain) for the year		(18	)		13
Actuarial loss amortization		(18	)		(27	)
Prior service cost amortization		(2	)		(3	)
		(38	)		(17	)

Components of Regulatory Assets That Have Not Been Recognized as Components of Net Periodic Benefit Costs

The following table provides the components of regulatory assets that have not been recognized as components of net periodic benefit costs for the years ended December 31, 2014 and 2013:

Year ended December 31 (millions of Canadian dollars)	2014		2013
Pension Benefits:
Prior service cost		2		3
Actuarial loss		1,234		842
		1,236		845
Post-Retirement and Post-Employment Benefits:
Prior service cost		—		2
Actuarial loss		273		306
		273		308

Components of Regulatory Assets Expected to be Amortized as Components of Net Periodic Benefit Costs

The following table provides the components of regulatory assets at December 31 that are expected to be amortized as components of net periodic benefit costs in the following year:

	Pension Benefits				Post-Retirement and Post-Employment Benefits
December 31 (millions of Canadian dollars)	2014		2013		2014		2013
Prior service cost		2		2		—		2
Actuarial loss		119		103		10		15
		121		105		10		17

Schedule of Pension Plan Target Asset and Weighted Average Asset Allocations

At December 31, 2014, the Pension Plan target asset allocations and weighted average asset allocations were as follows:

	Target Allocation (%)		Pension Plan Assets (%)
Equity securities		60.0		60.9
Debt securities		35.0		35.9
Other1		5.0		3.2
		100.0		100.0

¹  Other investments include real estate and infrastructure investments.

Pension Plan Assets Measured and Recorded at Fair Value on Recurring Basis

The following tables present the Pension Plan assets measured and recorded at fair value on a recurring basis and their level within the fair value hierarchy at December 31, 2014 and 2013:

December 31, 2014 (millions of Canadian dollars)	Level 1		Level 2		Level 3		Total
Pooled funds		—		18		142		160
Cash and cash equivalents		166		—		—		166
Short-term securities		—		176		—		176
Real estate		—		—		2		2
Corporate shares – Canadian		1,008		—		—		1,008
Corporate shares – Foreign		2,766		—		—		2,766
Bonds and debentures – Canadian		—		1,799		—		1,799
Bonds and debentures – Foreign		—		211		—		211
Total fair value of plan assets1		3,940		2,204		144		6,288

¹  At December 31, 2014, the total fair value of Pension Plan assets excludes $18 million of interest and dividends receivable, and $7 million relating to accruals for pension administration expense.

December 31, 2013 (millions of Canadian dollars)	Level 1		Level 2		Level 3		Total
Pooled funds		1		16		117		134
Cash and cash equivalents		150		—		—		150
Short-term securities		—		180		—		180
Real estate		—		—		2		2
Corporate shares – Canadian		943		—		—		943
Corporate shares – Foreign		2,708		—		—		2,708
Bonds and debentures – Canadian		—		1,416		—		1,416
Bonds and debentures – Foreign		—		186		—		186
Total fair value of plan assets1		3,802		1,798		119		5,719

¹  At December 31, 2013, the total fair value of Pension Plan assets excludes $19 million of interest and dividends receivable, and $7 million relating to accruals for pension administration expense.

Changes in Fair Value of Financial Instruments Classified in Level 3

The following table summarizes the changes in fair value of financial instruments classified in Level 3 for the years ended December 31, 2014 and 2013. The Pension Plan classifies financial instruments as Level 3 when the fair value is measured based on at least one significant input that is not observable in the markets or due to lack of liquidity in certain markets. The gains and losses presented in the table below may include changes in fair value based on both observable and unobservable inputs.

Year ended December 31 (millions of Canadian dollars)	2014			2013
Fair value, beginning of year		119			106
Realized and unrealized gains		30			23
Purchases		23			—
Sales and disbursements		(28	)		(10	)
Fair value, end of year		144			119

Pension Plan [Member]

Components of Net Periodic Benefit Costs

The following table provides the components of the net periodic benefit costs for the years ended December 31, 2014 and 2013 for the Pension Plan:

Year ended December 31 (millions of Canadian dollars)	2014			2013
Current service cost, net of employee contributions		110			141
Interest cost		312			278
Expected return on plan assets, net of expenses		(369	)		(309	)
Actuarial loss amortization		103			175
Prior service cost amortization		2			2
Net periodic benefit costs		158			287
Charged to results of operations1		81			72

¹ The Company follows the cash basis of accounting consistent with the inclusion of pension costs in OEB-approved rates. During the year ended December 31, 2014, pension costs of $174 million (2013 – $160 million) were attributed to labour, of which $81 million (2013 – $72 million) was charged to operations, and $93 million (2013 – $88 million) was capitalized as part of the cost of property, plant and equipment and intangible assets.

Post-Retirement and Post-Employment Benefits [Member]

Components of Net Periodic Benefit Costs

The following table provides the components of the net periodic benefit costs for the years ended December 31, 2014 and 2013 for the post-retirement and post-employment benefit plans:

Year ended December 31 (millions of Canadian dollars)	2014		2013
Current service cost, net of employee contributions		41		40
Interest cost		73		63
Actuarial loss amortization		18		27
Prior service cost amortization		2		3
Net periodic benefit costs		134		133
Charged to results of operations		62		58

XML

Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2014

Accounting Policies [Abstract]

Basis of Consolidation

Basis of Consolidation

These Consolidated Financial Statements include the accounts of the Company and its wholly owned subsidiaries: Hydro One Networks Inc. (Hydro One Networks), Hydro One Remote Communities Inc. (Hydro One Remote Communities), Hydro One Brampton Networks Inc. (Hydro One Brampton Networks), Hydro One Telecom Inc. (Hydro One Telecom), Hydro One Lake Erie Link Management Inc., Hydro One Lake Erie Link Company Inc., Norfolk Power Inc. (Norfolk Power), and Hydro One B2M Holdings. Intercompany transactions and balances have been eliminated.

Basis of Accounting

Basis of Accounting

These Consolidated Financial Statements are prepared and presented in accordance with United States (US) Generally Accepted Accounting Principles (GAAP) and in Canadian dollars.

Hydro One performed an evaluation of subsequent events through to February 11, 2015, the date these Consolidated Financial Statements were issued, to determine whether any events or transactions warranted recognition and disclosure in these Consolidated Financial Statements. See Note 25 – Subsequent Event.

Use of Management Estimates

Use of Management Estimates

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

Rate Setting

Rate Setting

The Company’s Transmission Business includes the separately regulated transmission businesses of Hydro One Networks and B2M Limited Partnership (B2M LP). The Company’s consolidated Distribution Business includes the separately regulated distribution businesses of Hydro One Networks and the newly acquired Norfolk Power, as well as the subsidiaries Hydro One Brampton Networks and Hydro One Remote Communities.

The OEB has approved the use of US GAAP for rate setting and regulatory accounting and reporting by Hydro One Networks’ transmission and distribution businesses, as well as by Hydro One Remote Communities, beginning with the year 2012. Up to the year ended December 31, 2014, Hydro One Brampton Networks used Canadian GAAP (Part V) for its distribution rate-setting purposes, and has transitioned to International Financial Reporting Standards beginning on January 1, 2015.

Transmission

In May 2012, Hydro One Networks filed a cost-of-service application with the OEB for 2013 and 2014 transmission rates. In December 2012, the OEB approved the 2013 and 2014 revenue requirement of $1,438 million and $1,528 million, respectively.

In December 2013, Hydro One Networks filed a draft Rate Order with the OEB for 2014 transmission rates. The 2014 transmission revenue requirement was increased to $1,535 million from the originally-approved revenue requirement of $1,528 million, primarily due to changes in the cost of capital parameters for 2014 released by the OEB in November 2013. On January 9, 2014, the OEB approved the draft Rate Order for 2014 transmission rates as filed.

Distribution

In June 2012, Hydro One Networks filed an Incentive Regulation Mechanism (IRM) application with the OEB for 2013 distribution rates, to be effective January 1, 2013. In December 2012, the OEB issued its final Decision, which resulted in an increase in distribution rates of approximately 1.3% in 2013, or 0.4% when considering total bill impact, for a typical residential customer consuming 800 kWh per month. In April 2013, Hydro One Networks filed an IRM application with the OEB for 2014 distribution rates, to be effective January 1, 2014. In December 2013, the OEB issued its final Decision, which resulted in an increase in distribution rates of approximately 2.4% in 2014, or 0.85% when considering total bill impact, for a typical residential customer consuming 800 kWh per month.

In August 2012, Hydro One Brampton Networks filed an IRM application with the OEB for 2013 distribution rates, to be effective January 1, 2013. In December 2012, the OEB issued its final Decision, which resulted in an increase in distribution rates of approximately 0.3% in 2013, or less than 0.1% when considering total bill impact, for a typical residential customer consuming 800 kWh per month. In August 2013, Hydro One Brampton Networks filed an IRM application with the OEB for 2014 distribution rates, to be effective January 1, 2014. In December 2013, the OEB issued its final Decision, which resulted in a reduction in distribution rates of approximately 2.3% in 2014, or 0.5% when considering total bill impact, for a typical residential customer consuming 800 kWh per month.

In September 2012, Hydro One Remote Communities filed a cost-of-service application with the OEB for 2013 rates, seeking approval for a 2013 revenue requirement of $53 million. In June 2013, the OEB approved a revenue requirement of $51 million for 2013. In October 2013, Hydro One Remote Communities filed an IRM application with the OEB for 2014 rates, seeking approval for a rate increase of approximately 0.5%. In March 2014, the OEB approved an increase of approximately 1.7% to basic rates for the distribution and generation of electricity, with an effective date of May 1, 2014. The final rate increase was adjusted by the OEB’s updated rate adjustment parameters and Hydro One Remote Communities’ IRM stretch factor.

Regulatory Accounting

Regulatory Accounting

The OEB has the general power to include or exclude revenues, costs, gains or losses in the rates of a specific period, resulting in a change in the timing of accounting recognition from that which would have been applied in an unregulated company. Such change in timing involves the application of rate-regulated accounting, giving rise to the recognition of regulatory assets and liabilities. The Company’s regulatory assets represent certain amounts receivable from future customers and costs that have been deferred for accounting purposes because it is probable that they will be recovered in future rates. In addition, the Company has recorded regulatory liabilities that generally represent amounts that are refundable to future customers. The Company continually assesses the likelihood of recovery of each of its regulatory assets and continues to believe that it is probable that the OEB will factor its regulatory assets and liabilities into the setting of future rates. If, at some future date, the Company judges that it is no longer probable that the OEB will include a regulatory asset or liability in setting future rates, the appropriate carrying amount will be reflected in results of operations in the period that the assessment is made.

Cash and Cash Equivalents

Cash and Cash Equivalents

Cash and cash equivalents include cash and short-term investments with an original maturity of three months or less.

Revenue Recognition

Revenue Recognition

Transmission revenues are collected through OEB-approved rates, which are based on an approved revenue requirement that includes a rate of return. Such revenue is recognized as electricity is transmitted and delivered to customers.

Distribution revenues are recognized on an accrual basis and include billed and unbilled revenues. Distribution revenues attributable to the delivery of electricity are based on OEB-approved distribution rates and are recognized as electricity is delivered to customers. The Company estimates monthly revenue for a period based on wholesale electricity purchases because customer meters are not generally read at the end of each month. At the end of each month, the electricity delivered to customers, but not billed, is estimated and revenue is recognized. The unbilled revenue estimate is affected by energy demand, weather, line losses and changes in the composition of customer classes.

Distribution revenue also includes an amount relating to rate protection for rural, residential and remote customers, which is received from the Independent Electricity System Operator (IESO) based on a standardized customer rate that is approved by the OEB. Current legislation provides rate protection for prescribed classes of rural, residential and remote consumers by reducing the electricity rates that would otherwise apply.

Revenues also include amounts related to sales of other services and equipment. Such revenue is recognized as services are rendered or as equipment is delivered.

Revenues are recorded net of indirect taxes.

Accounts Receivable and Allowance for Doubtful Accounts

Accounts Receivable and Allowance for Doubtful Accounts

Billed accounts receivable are recorded at the invoiced amount, net of allowance for doubtful accounts. Unbilled accounts receivable are estimated and recorded based on wholesale electricity purchases. Overdue amounts related to regulated billings bear interest at OEB-approved rates. The allowance for doubtful accounts reflects the Company’s best estimate of losses on billed accounts receivable balances. The allowance is based on accounts receivable aging, historical experience and other currently available information. The Company estimates the allowance for doubtful accounts on customer receivables by applying internally developed loss rates to the outstanding receivable balances by risk segment. Risk segments represent groups of customers with similar credit quality indicators and are computed based on various attributes, including number of days receivables are past due, delinquency of balances and payment history. Loss rates applied to the accounts receivable balances are based on historical average write-offs as a percentage of accounts receivable in each risk segment. An account is considered delinquent if the final amount billed is not received within 110 days of the invoiced date. Accounts receivable are written off against the allowance when they are deemed uncollectible. The existing allowance for uncollectible accounts will continue to be affected by changes in volume, prices and economic conditions.

Noncontrolling interest

Noncontrolling interest

Noncontrolling interest represents the portion of equity ownership in subsidiaries that is not attributable to the Shareholder of the parent company. Noncontrolling interest is initially recorded at fair value and subsequently the amount is adjusted for the proportionate share of net income (loss) and other comprehensive income (loss) attributable to the noncontrolling interest and any dividends or distributions paid to the noncontrolling interest.

If a transaction results in the acquisition of all, or part, of a noncontrolling interest in a subsidiary, the acquisition of the noncontrolling interest is accounted for as an equity transaction. No gain or loss is recognized in consolidated net income or comprehensive income as a result of changes in the noncontrolling interest, unless a change results in the loss of control by the Company.

Corporate Income Taxes

Corporate Income Taxes

Under the Electricity Act, 1998, Hydro One is required to make payments in lieu of corporate income taxes (PILs) to the Ontario Electricity Financial Corporation (OEFC). These payments are calculated in accordance with the rules for computing income and other relevant amounts contained in the Income Tax Act (Canada) and the Taxation Act, 2007 (Ontario) as modified by the Electricity Act, 1998 and related regulations.

Current and deferred income taxes are computed based on the tax rates and tax laws enacted at the balance sheet date. Tax benefits associated with income tax positions taken, or expected to be taken, in a tax return are recorded only when the “more-likely-than-not” recognition threshold is satisfied and are measured at the largest amount of benefit that has a greater than 50% likelihood of being realized upon settlement. Management evaluates each position based solely on the technical merits and facts and circumstances of the position, assuming the position will be examined by a taxing authority having full knowledge of all relevant information. Significant management judgment is required to determine recognition thresholds and the related amount of tax benefits to be recognized in the Consolidated Financial Statements. Management re-evaluates tax positions each period in which new information about recognition or measurement becomes available.

Current Income Taxes

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

Deferred Income Taxes

Deferred income taxes are provided for using the liability method. Deferred income taxes are recognized based on the estimated future tax consequences attributable to temporary differences between the carrying amount of assets and liabilities in the Consolidated Financial Statements and their corresponding tax bases.

Deferred income tax liabilities are generally recognized on all taxable temporary differences. Deferred tax assets are recognized to the extent that it is more-likely-than-not that these assets will be realized from taxable income available against which deductible temporary differences can be utilized.

Deferred income taxes are calculated at the tax rates that are expected to apply in the period when the liability is settled or the asset is realized, based on the tax rates and tax laws that have been enacted at the balance sheet date. Deferred income taxes that are not included in the rate-setting process are charged or credited to the Consolidated Statements of Operations and Comprehensive Income.

If management determines that it is more-likely-than-not that some or all of a deferred income tax asset will not be realized, a valuation allowance is recorded against the deferred income tax asset to report the net balance at the amount expected to be realized. Previously unrecognized deferred income tax assets are reassessed at each balance sheet date and are recognized to the extent that it has become more-likely-than-not that the tax benefit will be realized.

The Company records regulatory assets and liabilities associated with deferred income taxes that will be included in the rate-setting process.

The Company uses the flow-through method to account for investment tax credits (ITCs) earned on eligible scientific research and experimental development expenditures, and apprenticeship job creation. Under this method, only non-refundable ITCs are recognized as a reduction to income tax expense.

Materials and Supplies

Materials and Supplies

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

Property, Plant and Equipment

Property, Plant and Equipment

Property, plant and equipment is recorded at original cost, net of customer contributions received in aid of construction and any accumulated impairment losses. The cost of additions, including betterments and replacement asset components, is included on the Consolidated Balance Sheets as property, plant and equipment.

The original cost of property, plant and equipment includes direct materials, direct labour (including employee benefits), contracted services, attributable capitalized financing costs, asset retirement costs, and direct and indirect overheads that are related to the capital project or program. Indirect overheads include a portion of corporate costs such as finance, treasury, human resources, information technology and executive costs. Overhead costs, including corporate functions and field services costs, are capitalized on a fully allocated basis, consistent with an OEB-approved methodology.

Property, plant and equipment in service consists of transmission, distribution, communication, administration and service assets and land easements. Property, plant and equipment also includes future use assets, such as land, major components and spare parts, and capitalized project development costs associated with deferred capital projects.

Transmission

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

Distribution

Distribution assets include assets related to the distribution of low-voltage electricity, including lines, poles, switches, transformers, protective devices and metering systems.

Communication

Communication assets include the fibre-optic and microwave radio system, optical ground wire, towers, telephone equipment and associated buildings.

Administration and Service

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

Easements

Easements include statutory rights of use for transmission corridors and abutting lands granted under the Reliable Energy and Consumer Protection Act, 2002, as well as other land access rights.

Intangible Assets

Intangible Assets

Intangible assets separately acquired or internally developed are measured on initial recognition at cost, which comprises purchased software, direct labour (including employee benefits), consulting, engineering, overheads and attributable capitalized financing charges. Following initial recognition, intangible assets are carried at cost, net of any accumulated amortization and accumulated impairment losses. The Company’s intangible assets primarily represent major company-wide computer applications.

Capitalized Financing Costs

Capitalized Financing Costs

Capitalized financing costs represent interest costs attributable to the construction of property, plant and equipment or development of intangible assets. The financing cost of attributable borrowed funds is capitalized as part of the acquisition cost of such assets. The capitalized portion of financing costs is a reduction to financing charges recognized in the Consolidated Statements of Operations and Comprehensive Income. Capitalized financing costs are calculated using the Company’s weighted average effective cost of debt.

Construction and Development in Progress

Construction and Development in Progress

Construction and development in progress consists of the capitalized cost of constructed assets that are not yet complete and which have not yet been placed in service.

Depreciation and Amortization

Depreciation and Amortization

The cost of property, plant and equipment and intangible assets is depreciated or amortized on a straight-line basis based on the estimated remaining service life of each asset category, except for transport and work equipment, which is depreciated on a declining balance basis.

The Company periodically initiates an external independent review of its property, plant and equipment and intangible asset depreciation and amortization rates, as required by the OEB. Any changes arising from OEB approval of such a review are implemented on a remaining service life basis, consistent with their inclusion in electricity rates. The last review resulted in changes to rates effective January 1, 2013. A summary of average service lives and depreciation and amortization rates for the various classes of assets is included below:

	Average		Rate
	Service Life		Range	Average
Transmission		57 years	1% – 2%		2	%
Distribution		42 years	1% – 20%		2	%
Communication		19 years	1% – 15%		4	%
Administration and service		15 years	3% – 20%		7	%

The cost of intangible assets is included primarily within the administration and service classification above. Amortization rates for computer applications software and other intangible assets range from 9% to 20%.

In accordance with group depreciation practices, the original cost of property, plant and equipment, or major components thereof, and intangible assets that are normally retired, is charged to accumulated depreciation, with no gain or loss being reflected in results of operations. Where a disposition of property, plant and equipment occurs through sale, a gain or loss is calculated based on proceeds and such gain or loss is included in depreciation expense. Depreciation expense also includes the costs incurred to remove property, plant and equipment where no ARO has been recorded.

Goodwill

Goodwill

Goodwill represents the cost of acquired local distribution companies that is in excess of the fair value of the net identifiable assets acquired at the acquisition date. Goodwill is not included in rate base.

Goodwill is evaluated for impairment on an annual basis, or more frequently if circumstances require. The Company performs a qualitative assessment to determine whether it is more-likely-than-not that the fair value of the applicable reporting unit is less than its carrying amount. If the Company determines, as a result of its qualitative assessment, that it is not more-likely-than-not that the fair value of the applicable reporting unit is less than its carrying amount, no further testing is required. If the Company determines, as a result of its qualitative assessment, that it is more-likely-than-not that the fair value of the applicable reporting unit is less than its carrying amount, a goodwill impairment assessment is performed using a two-step, fair value-based test. The first step compares the fair value of the applicable reporting unit to its carrying amount, including goodwill. If the carrying amount of the applicable reporting unit exceeds its fair value, a second step is performed. The second step requires an allocation of fair value to the individual assets and liabilities using purchase price allocation in order to determine the implied fair value of goodwill. If the implied fair value of goodwill is less than the carrying amount, an impairment loss is recorded as a reduction to goodwill and as a charge to results of operations.

For the year ended December 31, 2014, based on the qualitative assessment performed as at September 30, 2014, the Company has determined that it is not more-likely-than-not that the fair value of each applicable reporting unit assessed is less than its carrying amount. As a result, no further testing was performed, and the Company has concluded that goodwill was not impaired at December 31, 2014.

Long-Lived Asset Impairment

Long-Lived Asset Impairment

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

Within its regulated business, the carrying costs of most of Hydro One’s long-lived assets are included in rate base where they earn an OEB-approved rate of return. Asset carrying values and the related return are recovered through approved rates. As a result, such assets are only tested for impairment in the event that the OEB disallows recovery, in whole or in part, or if such a disallowance is judged to be probable.

Hydro One regularly monitors the assets of its unregulated Hydro One Telecom subsidiary for indications of impairment. Management assesses the fair value of such long-lived assets using commonly accepted techniques, and may use more than one. Techniques used to determine fair value include, but are not limited to, the use of recent third party comparable sales for reference and internally developed discounted cash flow analysis. Significant changes in market conditions, changes to the condition of an asset, or a change in management’s intent to utilize the asset are generally viewed by management as triggering events to reassess the cash flows related to these long-lived assets. As at December 31, 2014, no asset impairment had been recorded for assets within either the Company’s regulated or unregulated businesses.

Costs of Arranging Debt Financing

Costs of Arranging Debt Financing

For financial liabilities classified as other than held-for-trading, the Company defers the external transaction costs related to obtaining debt financing and presents such amounts as deferred debt issuance costs on the Consolidated Balance Sheets. Deferred debt issuance costs are amortized over the contractual life of the related debt on an effective-interest basis and the amortization is included within financing charges in the Consolidated Statements of Operations and Comprehensive Income. Transaction costs for items classified as held-for-trading are expensed immediately.

Comprehensive Income

Comprehensive Income

Comprehensive income is comprised of net income and other comprehensive income (OCI). Hydro One presents net income and OCI in a single continuous Consolidated Statement of Operations and Comprehensive Income.

Financial Assets and Liabilities

Financial Assets and Liabilities

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

Derivative instruments are measured at fair value. Gains and losses from fair valuation are included within financing charges in the period in which they arise. The Company determines the classification of its financial assets and liabilities at the date of initial recognition. The Company designates certain of its financial assets and liabilities to be held at fair value, when it is consistent with the Company’s risk management policy disclosed in Note 13 – Fair Value of Financial Instruments and Risk Management.

Derivative Instruments and Hedge Accounting

Derivative Instruments and Hedge Accounting

The Company closely monitors the risks associated with changes in interest rates on its operations and, where appropriate, uses various instruments to hedge these risks. Certain of these derivative instruments qualify for hedge accounting and are designated as accounting hedges, while others either do not qualify as hedges or have not been designated as hedges (hereinafter referred to as undesignated contracts) as they are part of economic hedging relationships.

The accounting guidance for derivative instruments requires the recognition of all derivative instruments not identified as meeting the normal purchase and sale exemption as either assets or liabilities recorded at fair value on the Consolidated Balance Sheets. For derivative instruments that qualify for hedge accounting, the Company may elect to designate such derivative instruments as either cash flow hedges or fair value hedges. The Company offsets fair value amounts recognized on its Consolidated Balance Sheets related to derivative instruments executed with the same counterparty under the same master netting agreement.

For derivative instruments that qualify for hedge accounting and which are designated as cash flow hedges, the effective portion of any gain or loss, net of tax, is reported as a component of accumulated OCI (AOCI) and is reclassified to results of operations in the same period or periods during which the hedged transaction affects results of operations. Any gains or losses on the derivative instrument that represent either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in results of operations. For fair value hedges, changes in fair value of both the derivative instrument and the underlying hedged exposure are recognized in the Consolidated Statements of Operations and Comprehensive Income in the current period. The gain or loss on the derivative instrument is included in the same line item as the offsetting gain or loss on the hedged item in the Consolidated Statements of Operations and Comprehensive Income. Additionally, the Company enters into derivative agreements that are economic hedges which either do not qualify for hedge accounting or have not been designated as hedges. The changes in fair value of these undesignated derivative instruments are reflected in results of operations.

Embedded derivative instruments are separated from their host contracts and carried at fair value on the Consolidated Balance Sheets when: (a) the economic characteristics and risks of the embedded derivative are not clearly and closely related to the economic characteristics and risks of the host contract; (b) the hybrid instrument is not measured at fair value, with changes in fair value recognized in results of operations each period; and (c) the embedded derivative itself meets the definition of a derivative. The Company does not engage in derivative trading or speculative activities and had no embedded derivatives at December 31, 2014 or 2013.

Hydro One periodically develops hedging strategies taking into account risk management objectives. At the inception of a hedging relationship where the Company has elected to apply hedge accounting, Hydro One formally documents the relationship between the hedged item and the hedging instrument, the related risk management objective, the nature of the specific risk exposure being hedged, and the method for assessing the effectiveness of the hedging relationship. The Company also assesses, both at the inception of the hedge and on a quarterly basis, whether the hedging instruments are effective in offsetting changes in fair values or cash flows of the hedged items.

Employee Future Benefits

Employee Future Benefits

Employee future benefits provided by Hydro One include pension, post-retirement and post-employment benefits. The costs of the Company’s pension, post-retirement and post-employment benefit plans are recorded over the periods during which employees render service.

The Company recognizes the funded status of its pension, post-retirement and post-employment plans on its Consolidated Balance Sheets and subsequently recognizes the changes in funded status at the end of each reporting year. Pension, post-retirement and post-employment plans are considered to be underfunded when the projected benefit obligation exceeds the fair value of the plan assets. Liabilities are recognized on the Consolidated Balance Sheets for any net underfunded projected benefit obligation. The net underfunded projected benefit obligation may be disclosed as a current liability, long-term liability, or both. The current portion is the amount by which the actuarial present value of benefits included in the benefit obligation payable in the next 12 months exceeds the fair value of plan assets. If the fair value of plan assets exceeds the projected benefit obligation of the plan, an asset is recognized equal to the net overfunded projected benefit obligation. The post-retirement and post-employment benefit plans are unfunded because there are no related plan assets.

Pension benefits

In accordance with the OEB’s rate orders, pension costs are recorded on a cash basis as employer contributions are paid to the pension fund in accordance with the Pension Benefits Act (Ontario). Pension costs are recorded on an accrual basis for financial reporting purposes. Pension costs are actuarially determined using the projected benefit method prorated on service and are based on assumptions that reflect management’s best estimate of the effect of future events, including future compensation increases. Past service costs from plan amendments and all actuarial gains and losses are amortized on a straight-line basis over the expected average remaining service period of active employees in the plan, and over the estimated remaining life expectancy of inactive employees in the plan. Pension plan assets, consisting primarily of listed equity securities as well as corporate and government debt securities, are fair valued at the end of each year.

Hydro One records a regulatory asset equal to the net underfunded projected benefit obligation for its pension plan. The regulatory asset for the net underfunded projected benefit obligation for the pension plan, in the absence of regulatory accounting, would be recognized in AOCI. A regulatory asset is recognized because management considers it to be probable that pension benefit costs will be recovered in the future through the rate-setting process. The pension regulatory assets are remeasured at the end of each year based on the current status of the pension plan.

All future pension benefit costs are attributed to labour and are either charged to results of operations or capitalized as part of the cost of property, plant and equipment and intangible assets.

Post-retirement and post-employment benefits

Post-retirement and post-employment benefits are recorded and included in rates on an accrual basis. Costs are determined by independent actuaries using the projected benefit method prorated on service and based on assumptions that reflect management’s best estimates. Past service costs from plan amendments are amortized to results of operations based on the expected average remaining service period.

Hydro One records a regulatory asset equal to the incremental net unfunded projected benefit obligation for post-retirement and post-employment plans recorded at each year end based on annual actuarial reports. The regulatory asset for the incremental net unfunded projected benefit obligation for post-retirement and post-employment plans, in the absence of regulatory accounting, would be recognized in AOCI. A regulatory asset is recognized because management considers it to be probable that post-retirement and post-employment benefit costs will be recovered in the future through the rate-setting process.

For post-retirement benefits, all actuarial gains or losses are deferred using the “corridor” approach. The amount calculated above the “corridor” is amortized to results of operations on a straight-line basis over the expected average remaining service life of active employees in the plan and over the remaining life expectancy of inactive employees in the plan. The post-retirement benefit obligation is remeasured to its fair value at each year end based on an annual actuarial report, with an offset to the associated regulatory asset, to the extent of the remeasurement adjustment.

For post-employment obligations, the associated regulatory liabilities representing actuarial gains on transition to US GAAP are amortized to results of operations based on the “corridor” approach. Post transition, the actuarial gains and losses on post-employment obligations that are incurred during the year are recognized immediately to results of operations. The post-employment benefit obligation is remeasured to its fair value at each year end based on an annual actuarial report, with an offset to the associated regulatory asset, to the extent of the remeasurement adjustment.

All post-retirement and post-employment future benefit costs are attributed to labour and are either charged to results of operations or capitalized as part of the cost of property, plant and equipment and intangible assets.

Multiemployer Pension Plan

Multiemployer Pension Plan

Employees of Hydro One Brampton Networks and the newly acquired Norfolk Power participate in the Ontario Municipal Employees Retirement System Fund (OMERS), a multiemployer, contributory, defined benefit public sector pension fund. OMERS provides retirement pension payments based on members’ length of service and salary. Both the participating employers and members are required to make plan contributions. The OMERS plan assets are pooled together to provide benefits to all plan participants and the plan assets are not segregated by member entity. OMERS is registered with the Financial Services Commission of Ontario under Registration #0345983. At December 31, 2013, OMERS had approximately 440,000 members, with approximately 335 members being current employees of Hydro One Brampton Networks and Norfolk Power.

The OMERS plan is accounted for as a defined contribution plan by Hydro One because it is not practicable to determine the present value of the Company’s obligation, the fair value of plan assets or the related current service cost applicable to Hydro One Brampton Networks and Norfolk Power employees. Hydro One recognizes its contributions to the OMERS plan as pension expense, with a portion being capitalized. The expensed amount is included in operation, maintenance and administration costs in the Consolidated Statements of Operations and Comprehensive Income.

Loss Contingencies

Loss Contingencies

Hydro One is involved in certain legal and environmental matters that arise in the normal course of business. In the preparation of its Consolidated Financial Statements, management makes judgments regarding the future outcome of contingent events and records a loss for a contingency based on its best estimate when it is determined that such loss is probable and the amount of the loss can be reasonably estimated. Where the loss amount is recoverable in future rates, a regulatory asset is also recorded. When a range estimate for the probable loss exists and no amount within the range is a better estimate than any other amount, the Company records a loss at the minimum amount within the range.

Management regularly reviews current information available to determine whether recorded provisions should be adjusted and whether new provisions are required. Estimating probable losses may require analysis of multiple forecasts and scenarios that often depend on judgments about potential actions by third parties, such as federal, provincial and local courts or regulators. Contingent liabilities are often resolved over long periods of time. Amounts recorded in the Consolidated Financial Statements may differ from the actual outcome once the contingency is resolved. Such differences could have a material impact on future results of operations, financial position and cash flows of the Company.

Provisions are based upon current estimates and are subject to greater uncertainty where the projection period is lengthy. A significant upward or downward trend in the number of claims filed, the nature of the alleged injuries, and the average cost of resolving each claim could change the estimated provision, as could any substantial adverse or favourable verdict at trial. A federal or provincial legislative outcome or structured settlement could also change the estimated liability. Legal fees are expensed as incurred.

Environmental Liabilities

Environmental Liabilities

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

Asset Retirement Obligations

Asset Retirement Obligations

AROs are recorded for legal obligations associated with the future removal and disposal of long-lived assets. Such obligations may result from the acquisition, construction, development and/or normal use of the asset. Conditional AROs are recorded when there is a legal obligation to perform a future asset retirement activity but where the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the Company. In such a case, the obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and/or method of settlement.

When recording an ARO, the present value of the estimated future expenditures required to complete the asset retirement activity is recorded in the period in which the obligation is incurred, if a reasonable estimate can be made. In general, the present value of the estimated future expenditures is added to the carrying amount of the associated asset and the resulting asset retirement cost is depreciated over the estimated useful life of the asset. Where an asset is no longer in service when an ARO is recorded, the asset retirement cost is recorded in results of operations.

Some of the Company’s transmission and distribution assets, particularly those located on unowned easements and rights-of-way, may have AROs, conditional or otherwise. The majority of the Company’s easements and rights-of-way are either of perpetual duration or are automatically renewed annually. Land rights with finite terms are generally subject to extension or renewal. As the Company expects to use the majority of its facilities in perpetuity, no ARO currently exists for these assets. If, at some future date, a particular facility is shown not to meet the perpetuity assumption, it will be reviewed to determine whether an estimable ARO exists. In such a case, an ARO would be recorded at that time.

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

New Accounting Pronouncements

Recently Adopted Accounting Pronouncements

In July 2013, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2013-11, Income Taxes (Topic 740): Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists. This ASU provides guidance on the presentation of unrecognized tax benefits. This ASU is effective for fiscal years, and interim periods within those years, beginning after December 15, 2013, and should be applied prospectively to all unrecognized tax benefits that exist at the effective date. The adoption of this ASU did not have a significant impact on the Company’s consolidated financial statements.

Recent Accounting Guidance Not Yet Adopted

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606). This ASU provides guidance on revenue recognition that depicts the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods and services. This ASU is required to be applied retrospectively and is effective for fiscal years, and interim periods within those years, beginning after December 15, 2016. The Company is currently assessing the impact of adoption of ASU 2014-09 on its consolidated financial statements.

In August 2014, the FASB issued ASU 2014-15, Presentation of Financial Statements – Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern. This ASU provides guidance about management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern and related disclosures. This ASU is effective for the annual period ending December 31, 2016, and for annual and interim periods thereafter. The adoption of this ASU is not anticipated to have a significant impact on the Company’s consolidated financial statements.

In November 2014, the FASB issued ASU 2014-16, Derivatives and Hedging (Topic 815). This ASU provides guidance on accounting for hybrid financial instruments issued in the form of a share. This ASU is effective for fiscal years, and interim periods within those years, beginning after December 15, 2015. The Company is currently assessing the impact of adoption of ASU 2014-16 on its consolidated financial statements.

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Capital Management - Summary of Company's Capital Structure (Detail) (CAD) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Statement of Financial Position [Abstract]
Long-term debt payable within one year	552	756
Less: cash and cash equivalents	100	565	195
Net Long-term debt payable within one year	452	191
Long-term debt	8,373	8,301
Preferred shares	323	323
Common shares	3,314	3,314
Retained earnings	4,249	3,787
Total stockholders equity excluding accumulated other comprehensive income	7,563	7,101
Total capital	16,711	15,916

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Fair Value of Financial Instruments and Risk Management - Summary of Fair Values and Carrying Values of Long-Term Debt (Detail) (CAD) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Schedule Of Carrying Values And Estimated Fair Values Of Debt Instruments [Line Items]
Carrying Value	8,925	9,057
Fair Value	10,411	9,780
$500 Million of MTN Series 19 Notes [Member]
Schedule Of Carrying Values And Estimated Fair Values Of Debt Instruments [Line Items]
Carrying Value		506
Fair Value		506
$250 Million of MTN Series 21 Notes [Member]
Schedule Of Carrying Values And Estimated Fair Values Of Debt Instruments [Line Items]
Carrying Value	252	256
Fair Value	252	256
Other Notes and Debentures [Member]
Schedule Of Carrying Values And Estimated Fair Values Of Debt Instruments [Line Items]
Carrying Value	8,673	8,295
Fair Value	10,159	9,018

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Pension and Post-Retirement and Post-Employment Benefits - Schedule of Weighted Average Assumptions Used to Determine Net Periodic Benefit Costs (Detail)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Pension Benefits [Member]
Schedule Of Weighted Average Assumption Determining Pension Plan And Other Post retirement Benefit Plan [Line Items]
Weighted average expected rate of return on plan assets	6.50%	6.25%
Weighted average discount rate	4.75%	4.25%
Rate of compensation scale escalation (without merit)	2.50%	2.50%
Rate of cost of living increase	2.00%	2.00%
Average remaining service life of employees (years)	11 years	11 years
Post-Retirement and Post-Employment Benefits [Member]
Schedule Of Weighted Average Assumption Determining Pension Plan And Other Post retirement Benefit Plan [Line Items]
Weighted average discount rate	4.75%	4.25%
Rate of compensation scale escalation (without merit)	2.50%	2.50%
Rate of cost of living increase	2.00%	2.00%
Average remaining service life of employees (years)	12 years	12 years
Rate of increase in health care cost trends	4.39%	4.39%

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Financing Charges - Schedule of Financing Charges (Detail) (CAD) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Interest Income And Interest Expense [Abstract]
Interest on long-term debt	432	416
Other	12	9
Less: Interest capitalized on construction and development in progress	(49)	(51)
Gain on interest-rate swap agreements	(10)	(11)
Interest earned on investments	(6)	(3)
Net financing charges	379	360

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Related Party Transactions - Additional Information (Detail) (CAD) In Millions, unless otherwise specified	1 Months Ended		12 Months Ended
	Jun. 30, 2013	Sep. 30, 2012	Dec. 31, 2014	Dec. 31, 2013	Nov. 30, 2014
Related Party Transaction [Line Items]
Dividends paid			287	218
Amount of power purchased			3,419	3,020
Transmission revenues			1,588	1,529
Distribution revenues from electricity supply to remote northern communities	51	53	4,903	4,484
Payment made in lieu of corporate income taxes			86	138
Annual fee to the OEFC for indemnification against adverse claims			5
Businesses transferred date			Apr. 01, 1999
Floating-Rate Notes [Member]
Related Party Transaction [Line Items]
Redemption of notes held as a long-term investment					250
Debt maturity date			Nov. 19, 2014
IESO [Member]
Related Party Transaction [Line Items]
Amount of power purchased			2,601	2,477
Transmission revenues			1,556	1,509
Distribution revenues for rural rate protection			127	127
Distribution revenues from electricity supply to remote northern communities			32	33
OPG [Member]
Related Party Transaction [Line Items]
Amount of power purchased			23	15
Revenues with respect to service level agreements			12	9
Costs related to purchase of services with respect to service level agreements			1	1
OEFC [Member]
Related Party Transaction [Line Items]
Amount of power purchased			9	8
Payment made in lieu of corporate income taxes			86	138
Amount paid by OEFC with respect to business transferred			10
OEB [Member]
Related Party Transaction [Line Items]
Costs related to purchase of services with respect to service level agreements			12	12
OPA [Member]
Related Party Transaction [Line Items]
Funding received for program costs, incentives and management fees			33	34

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Fair Value of Financial Instruments and Risk Management - Fair Value Hierarchy of Financial Assets and Liabilities (Detail) (CAD) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Assets:
Cash and cash equivalents	100	565	195
Fair value hedges - interest-rate swaps		6
Liabilities:
Long-term debt		256
Level 1 [Member]
Assets:
Cash and cash equivalents	100	565
Total assets	100	565
Liabilities:
Bank indebtedness	2	31
Total liabilities	2	31
Level 2 [Member]
Assets:
Investment		251
Fair value hedges - interest-rate swaps	2	12
Total assets	2	263
Liabilities:
Long-term debt	10,411	9,780
Total liabilities	10,414	9,780
Level 2 [Member] | Undesignated Contracts [Member] | Interest-Rate Swaps [Member]
Liabilities:
Derivative instruments, liabilities	3
Carrying Value [Member]
Assets:
Cash and cash equivalents	100	565
Investment		251
Fair value hedges - interest-rate swaps	2	12
Total assets	102	828
Liabilities:
Bank indebtedness	2	31
Long-term debt	8,925	9,057
Total liabilities	8,930	9,088
Carrying Value [Member] | Undesignated Contracts [Member] | Interest-Rate Swaps [Member]
Liabilities:
Derivative instruments, liabilities	3
Fair Value [Member]
Assets:
Cash and cash equivalents	100	565
Investment		251
Fair value hedges - interest-rate swaps	2	12
Total assets	102	828
Liabilities:
Bank indebtedness	2	31
Long-term debt	10,411	9,780
Total liabilities	10,416	9,811
Fair Value [Member] | Undesignated Contracts [Member] | Interest-Rate Swaps [Member]
Liabilities:
Derivative instruments, liabilities	3

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Pension and Post-Retirement and Post-Employment Benefits - Components of Net Periodic Benefit Costs (Parenthetical) (Detail) (CAD) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Compensation and Retirement Disclosure [Abstract]
Pension costs	174	160
Pension costs charged to operations	81	72
Pension costs capitalized	93	88

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Pension and Post-Retirement and Post-Employment Benefits - Additional Information (Detail) (CAD)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Accrued liabilities	611,000,000	654,000,000
Pension plan average pensionable earnings	3 years
New pension plan average pensionable earnings	5 years
Annual pension plan contributions	174,000,000	160,000,000
Estimated annual pension plan contributions for 2015	174,000,000
Estimated annual pension plan contributions for 2016	175,000,000
Percentage of assets to ascertain concentration of credit risk	10.00%
ABO [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Funded percentage	91.00%	96.00%
PBO [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Funded percentage	84.00%	87.00%
OMERS [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Employers contributions	2,000,000	2,000,000
Contribution not more than maximum of total contribution		5.00%
Funded percentage		88.20%
Unfunded liability		8,641,000,000
Maximum [Member] | OMERS [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Accrued liabilities	1,000,000	1,000,000
Parent Company [Member] | Corporate Bond Securities [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Pension plan	0	15,000,000
Ontario [Member] | Debt Securities [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Pension plan	340,000,000	217,000,000

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Pension and Post-Retirement and Post-Employment Benefits - Schedule of Weighted Average Assumptions Used to Determine Benefit Obligations (Detail)	Dec. 31, 2014	Dec. 31, 2013
Pension Benefits [Member]
Schedule Of Weighted Average Assumption Determining Pension Plan And Other Post retirement Benefit Plan [Line Items]
Weighted average discount rate	4.00%	4.75%
Rate of compensation scale escalation (without merit)	2.50%	2.50%
Rate of cost of living increase	2.00%	2.00%
Post-Retirement and Post-Employment Benefits [Member]
Schedule Of Weighted Average Assumption Determining Pension Plan And Other Post retirement Benefit Plan [Line Items]
Weighted average discount rate	4.00%	4.75%
Rate of compensation scale escalation (without merit)	2.50%	2.50%
Rate of cost of living increase	2.00%	2.00%
Rate of increase in health care cost trends	4.36%	4.39%

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Fair Value of Financial Instruments and Risk Management - Summary of Net Unrealized Loss (Gain) on Hedged Debt and Related Interest Rate Swaps (Detail) (CAD) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Fair Value Disclosures [Abstract]
Unrealized loss (gain) on hedged debt	(3)	(8)
Unrealized loss (gain) on fair value interest-rate swaps	3	8
Net unrealized loss (gain)	0	0

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Debt and Credit Agreements - Schedule of Outstanding Long-Term Debt (Detail) (CAD) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Debt Instrument [Line Items]
Long-term debt, Total	8,923	9,045
Add: Unrealized mark-to-market loss	2	12
Less: Long-term debt payable within one year	(552)	(756)
Long-term debt	8,373	8,301
3.13% Series 19 Notes Due 2014 [Member]
Debt Instrument [Line Items]
Long-term debt, Total		750
2.95% Series 21 Notes Due 2015 [Member]
Debt Instrument [Line Items]
Long-term debt, Total	500	500
Floating-Rate Series 22 Notes Due 2015 [Member]
Debt Instrument [Line Items]
Long-term debt, Total	50	50
4.64% Series 10 Notes Due 2016 [Member]
Debt Instrument [Line Items]
Long-term debt, Total	450	450
Floating-Rate Series 27 Notes Due 2016 [Member]
Debt Instrument [Line Items]
Long-term debt, Total	50	50
5.18% Series 13 Notes Due 2017 [Member]
Debt Instrument [Line Items]
Long-term debt, Total	600	600
2.78% Series 28 Notes due 2018 [Member]
Debt Instrument [Line Items]
Long-term debt, Total	750	750
Floating-Rate Series 31 Notes Due 2019 [Member]
Debt Instrument [Line Items]
Long-term debt, Total	228
4.40% Series 20 Notes Due 2020 [Member]
Debt Instrument [Line Items]
Long-term debt, Total	300	300
3.20% Series 25 Notes Due 2022 [Member]
Debt Instrument [Line Items]
Long-term debt, Total	600	600
7.35% Debentures Due 2030 [Member]
Debt Instrument [Line Items]
Long-term debt, Total	400	400
6.93% Series 2 Notes Due 2032 [Member]
Debt Instrument [Line Items]
Long-term debt, Total	500	500
6.35% Series 4 Notes Due 2034 [Member]
Debt Instrument [Line Items]
Long-term debt, Total	385	385
5.36% Series 9 Notes Due 2036 [Member]
Debt Instrument [Line Items]
Long-term debt, Total	600	600
4.89% Series 12 Notes Due 2037 [Member]
Debt Instrument [Line Items]
Long-term debt, Total	400	400
6.03% Series 17 Notes Due 2039 [Member]
Debt Instrument [Line Items]
Long-term debt, Total	300	300
5.49% Series 18 Notes Due 2040 [Member]
Debt Instrument [Line Items]
Long-term debt, Total	500	500
4.39% Series 23 Notes Due 2041 [Member]
Debt Instrument [Line Items]
Long-term debt, Total	300	300
6.59% Series 5 Notes Due 2043 [Member]
Debt Instrument [Line Items]
Long-term debt, Total	315	315
4.59% Series 29 Notes Due 2043 [Member]
Debt Instrument [Line Items]
Long-term debt, Total	435	435
4.17% Series 32 Notes Due 2044 [Member]
Debt Instrument [Line Items]
Long-term debt, Total	350
5.00% Series 11 Notes Due 2046 [Member]
Debt Instrument [Line Items]
Long-term debt, Total	325	325
4.00% Series 24 Notes Due 2051 [Member]
Debt Instrument [Line Items]
Long-term debt, Total	225	225
3.79% Series 26 Notes Due 2062 [Member]
Debt Instrument [Line Items]
Long-term debt, Total	310	310
4.29% Series 30 Notes Due 2064 [Member]
Debt Instrument [Line Items]
Long-term debt, Total	50

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Share Capital

12 Months Ended

Dec. 31, 2014

Equity [Abstract]

Share Capital

18. SHARE CAPITAL

Preferred Shares

The Company has 12,920,000 issued and outstanding 5.5% cumulative preferred shares with a redemption value of $25 per share or $323 million total value. The Company is authorized to issue an unlimited number of preferred shares.

The Company’s preferred shares are entitled to an annual cumulative dividend of $18 million, or $1.375 per share, which is payable on a quarterly basis. The preferred shares are not subject to mandatory redemption (except on liquidation) but are redeemable in certain circumstances. The shares are redeemable at the option of the Province at the redemption value, plus any accrued and unpaid dividends, if the Province sells a number of the common shares which it owns to the public such that the Province’s holdings are reduced to less than 50% of the common shares of the Company. Hydro One may elect, without condition, to pay all or part of the redemption price by issuing additional common shares to the Province. If the Province does not exercise its redemption right, the Company would have the ability to adjust the dividend on the preferred shares to produce a yield that is 0.50% less than the then-current dividend market yield for similarly rated preferred shares. The preferred shares do not carry voting rights, except in limited circumstances, and would rank in priority over the common shares upon liquidation.

These preferred shares have conditions for their redemption that are outside the control of the Company because the Province can exercise its right to redeem in the event of change in ownership without approval of the Company’s Board of Directors. Because the conditional redemption feature is outside the control of the Company, the preferred shares are classified outside of equity on the Consolidated Balance Sheets. Management believes that it is not probable that the preferred shares will become redeemable. No adjustment to the carrying value of the preferred shares has been recognized at December 31, 2014. If it becomes probable in the future that the preferred shares will be redeemed, the redemption value would be adjusted.

Common Shares

The Company has 100,000 issued and outstanding common shares. The Company is authorized to issue an unlimited number of common shares.

Common share dividends are declared at the sole discretion of the Hydro One Board of Directors, and are recommended by management based on results of operations, maintenance of the deemed regulatory capital structure, financial conditions, cash requirements, and other relevant factors, such as industry practice and Shareholder expectations.

Earnings per Share

Basic and diluted earnings per share have been calculated on the basis of net income attributable to the Shareholder of Hydro One and the weighted average number of common shares outstanding during the year.

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Segmented Reporting (Tables)

12 Months Ended

Dec. 31, 2014

Segment Reporting [Abstract]

Summary of Segment Information

The accounting policies followed by the segments are the same as those described in the summary of significant accounting policies (see Note 2 – Significant Accounting Policies). Segment information on the above basis is as follows:

Year ended December 31, 2014 (millions of Canadian dollars)	Transmission		Distribution		Other			Consolidated
Revenues		1,588		4,903		57			6,548
Purchased power		—		3,419		—			3,419
Operation, maintenance and administration		394		742		56			1,192
Depreciation and amortization		346		367		9			722
Income (loss) before financing charges and provision for PILs		848		375		(8	)		1,215
Capital investments		845		680		5			1,530

Year ended December 31, 2013 (millions of Canadian dollars)	Transmission		Distribution		Other			Consolidated
Revenues		1,529		4,484		61			6,074
Purchased power		—		3,020		—			3,020
Operation, maintenance and administration		375		672		59			1,106
Depreciation and amortization		327		340		9			676
Income (loss) before financing charges and provision for PILs		827		452		(7	)		1,272
Capital investments		714		673		7			1,394

Total Assets by Segment:

December 31 (millions of Canadian dollars)	2014		2013
Transmission		12,540		11,846
Distribution		9,805		8,805
Other		205		974
Total assets		22,550		21,625

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Regulatory Assets and Liabilities (Tables)

12 Months Ended

Dec. 31, 2014

Regulated Operations [Abstract]

Schedule of Regulatory Assets and Liabilities

Hydro One has recorded the following regulatory assets and liabilities:

December 31 (millions of Canadian dollars)	2014		2013
Regulatory assets:
Deferred income tax regulatory asset		1,327		1,145
Pension benefit regulatory asset		1,236		845
Post-retirement and post-employment benefits		273		308
Environmental		239		266
Pension cost variance		90		80
DSC exemption		16		7
OEB cost assessment differential		12		9
Retail settlement variance accounts		11		—
Long-term project development costs		—		5
Other		27		18
Total regulatory assets		3,231		2,683
Less: current portion		31		47
		3,200		2,636
Regulatory liabilities:
Rider 11		83		55
External revenue variance		54		81
CDM deferral variance account		25		—
Deferred income tax regulatory liability		21		19
PST savings deferral		19		17
Hydro One Brampton Networks rider		2		8
Retail settlement variance accounts		—		35
Rider 9		—		19
Other		11		14
Total regulatory liabilities		215		248
Less: current portion		47		85
		168		163

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Fair Value of Financial Instruments and Risk Management - Additional Information (Detail) (CAD)	12 Months Ended
	Dec. 31, 2014 Counterparty	Dec. 31, 2013	Dec. 31, 2012
Schedule Of Carrying Values And Estimated Fair Values Of Debt Instruments [Line Items]
Fair value hedge exposure	3.00%	8.00%
Long-term debt	8,923,000,000	9,045,000,000
Term debt		256,000,000
Floating-to-fixed interest-rate swap	150,000,000
Short-term investments		251,000,000
Bench mark period of government bond Yield	30 years
Transmission Business' annual results of operations	20,000,000	19,000,000
Distribution Business' annual results of operations	10,000,000	10,000,000
Description of cash flow hedge agreements	No cash flow hedge agreements were in existence as at December 31, 2014 or 2013.
Assets at fair value	2,000,000	12,000,000
Provision for bad debts	66,000,000	36,000,000	23,000,000
Account receivable, Percentage	6.00%	4.00%
Account receivable, Period	60 days
Counterparty credit risk exposure on the fair value	3,000,000	14,000,000
Number of counterparties	5
Credit exposure	10.00%
Accounts payable and accrued liabilities	784,000,000	789,000,000
Scenario, Forecast [Member]
Schedule Of Carrying Values And Estimated Fair Values Of Debt Instruments [Line Items]
Percentage of increase/(decrease) in interest rate	(1.00%)
Variable Interest Rate [Member] | Scenario, Forecast [Member]
Schedule Of Carrying Values And Estimated Fair Values Of Debt Instruments [Line Items]
Percentage of increase/(decrease) in interest rate	10.00%	10.00%
Customer Concentration Risk [Member]
Schedule Of Carrying Values And Estimated Fair Values Of Debt Instruments [Line Items]
Accounts receivable	0	0
Banker's Acceptances and Money Market Funds [Member]
Schedule Of Carrying Values And Estimated Fair Values Of Debt Instruments [Line Items]
Short-term investments		515,000,000
Revolving Standby Credit Facility [Member]
Schedule Of Carrying Values And Estimated Fair Values Of Debt Instruments [Line Items]
Commercial paper program debt	1,500,000,000
2.95% Series 21 Notes Due 2015 [Member]
Schedule Of Carrying Values And Estimated Fair Values Of Debt Instruments [Line Items]
Fixed-to-floating interest-rate swap	125,000,000
Long-term debt	500,000,000	500,000,000
Number of agreements	2
Conversion of debt	250,000,000
Term debt	500,000,000
Debt maturity date	Sep. 11, 2015
Floating-Rate Series 22 Notes Due 2015 [Member]
Schedule Of Carrying Values And Estimated Fair Values Of Debt Instruments [Line Items]
Long-term debt	50,000,000	50,000,000
Term debt	50,000,000
Floating-to-fixed interest-rate swap	50,000,000
Floating-Rate Series 31 Notes Due 2019 [Member]
Schedule Of Carrying Values And Estimated Fair Values Of Debt Instruments [Line Items]
Long-term debt	228,000,000
Term debt	228,000,000
Floating-to-fixed interest-rate swap	137,000,000
Floating-Rate Series 27 Notes Due 2016 [Member]
Schedule Of Carrying Values And Estimated Fair Values Of Debt Instruments [Line Items]
Long-term debt	50,000,000	50,000,000
Term debt	50,000,000
Floating-to-fixed interest-rate swap	30,000,000
Floating Rate Series 22 Notes Due July 2015 [Member]
Schedule Of Carrying Values And Estimated Fair Values Of Debt Instruments [Line Items]
Term debt	50,000,000
Floating-to-fixed interest-rate swap	30,000,000
Interest-Rate Swaps [Member]
Schedule Of Carrying Values And Estimated Fair Values Of Debt Instruments [Line Items]
Fixed-to-floating interest-rate swap	250,000,000	750,000,000
Notional value	409,000,000	900,000,000
Interest-Rate Swaps [Member] | Norfolk Power [Member]
Schedule Of Carrying Values And Estimated Fair Values Of Debt Instruments [Line Items]
Notional value	12,000,000
Number of interest-rate swaps	3
Interest-Rate Swaps [Member] | Fair Value Hedges [Member]
Schedule Of Carrying Values And Estimated Fair Values Of Debt Instruments [Line Items]
Notional value	250,000,000	750,000,000
Fair Value Hedge [Member]
Schedule Of Carrying Values And Estimated Fair Values Of Debt Instruments [Line Items]
Long-term debt	8,925,000,000	9,057,000,000
One Interest-Rate Swaps [Member]
Schedule Of Carrying Values And Estimated Fair Values Of Debt Instruments [Line Items]
Debt maturity date	Sep. 20, 2029
Floating-to-fixed interest-rate swap	8,000,000
Two Interest-Rate Swaps [Member]
Schedule Of Carrying Values And Estimated Fair Values Of Debt Instruments [Line Items]
Debt maturity date	Sep. 20, 2029
Floating-to-fixed interest-rate swap	2,000,000
Three Interest-Rate Swaps [Member]
Schedule Of Carrying Values And Estimated Fair Values Of Debt Instruments [Line Items]
Debt maturity date	Sep. 20, 2019
Floating-to-fixed interest-rate swap	2,000,000

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Pension and Post-Retirement and Post-Employment Benefits - Components of Regulatory Assets Expected to be Amortized as Components of Net Periodic Benefit Costs (Detail) (CAD) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Pension Benefits [Member]
Schedule Of Weighted Average Assumption Determining Pension Plan And Other Post retirement Benefit Plan [Line Items]
Prior service cost	2	2
Actuarial loss	119	103
Net periodic benefit costs	121	105
Post-Retirement and Post-Employment Benefits [Member]
Schedule Of Weighted Average Assumption Determining Pension Plan And Other Post retirement Benefit Plan [Line Items]
Prior service cost		2
Actuarial loss	10	15
Net periodic benefit costs	10	17

XML

Financing Charges (Tables)

12 Months Ended

Dec. 31, 2014

Banking and Thrift, Interest [Abstract]

Schedule of Financing Charges

Year ended December 31 (millions of Canadian dollars)	2014			2013
Interest on long-term debt		432			416
Other		12			9
Less: Interest capitalized on construction and development in progress		(49	)		(51	)
Gain on interest-rate swap agreements		(10	)		(11	)
Interest earned on investments		(6	)		(3	)
		379			360

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Significant Accounting Policies - Additional Information (Detail) (CAD)	1 Months Ended		12 Months Ended		1 Months Ended
	Jun. 30, 2013	Sep. 30, 2012	Dec. 31, 2014	Dec. 31, 2013	Oct. 31, 2013	Mar. 31, 2014
Accounting Policies [Line Items]
Transmission revenue requirements			1,588,000,000	1,529,000,000
Distribution revenue requirements	51,000,000	53,000,000	4,903,000,000	4,484,000,000
Short-term investments original maturity			3 months
Accounts receivable, delinquent period			110 days
Gain (loss) recognized in consolidated net income or comprehensive income result of changes in noncontrolling interest			0
Income tax examination, Likelihood of unfavorable settlement			Tax benefits associated with income tax positions taken, or expected to be taken, in a tax return are recorded only when the "more-likely-than-not" recognition threshold is satisfied and are measured at the largest amount of benefit that has a greater than 50% likelihood of being realized upon settlement.
Threshold probability for recognition			50.00%
Asset impairment charges			0
Embedded derivatives			0	0
Distribution [Member]
Accounting Policies [Line Items]
Change in rate			2.40%	1.30%
Increase (reduction) in basic rate, distribution and generation of electricity considering total bill impact			0.85%	0.40%
Residential customer energy consumption, in kWh			800	800
Hydro One Brampton Networks Rider [Member] | Distribution [Member]
Accounting Policies [Line Items]
Change in rate			(2.30%)	0.30%
Increase (reduction) in basic rate, distribution and generation of electricity considering total bill impact			(0.50%)
Residential customer energy consumption, in kWh			800	800
December 2012 Approved Revenue Requirement [Member] | Hydro One Networks [Member]
Accounting Policies [Line Items]
Transmission revenue requirements			1,528,000,000	1,438,000,000
December 2013 Approved Revenue Requirement [Member] | Hydro One Networks [Member]
Accounting Policies [Line Items]
Transmission revenue requirements			1,535,000,000
October 2013 Seeking Approval Revenue Requirement [Member]
Accounting Policies [Line Items]
Increase in basic rate, distribution and generation of electricity					0.50%
March 2014 Approved Revenue Requirement [Member]
Accounting Policies [Line Items]
Increase in basic rate, distribution and generation of electricity						1.70%
Minimum [Member] | Computer Applications Software and Other Intangible Assets [Member]
Accounting Policies [Line Items]
Amortization rates			9.00%
Maximum [Member] | Computer Applications Software and Other Intangible Assets [Member]
Accounting Policies [Line Items]
Amortization rates			20.00%
Maximum [Member] | Hydro One Brampton Networks Rider [Member] | Distribution [Member]
Accounting Policies [Line Items]
Increase (reduction) in basic rate, distribution and generation of electricity considering total bill impact				0.10%
OMERS [Member]
Accounting Policies [Line Items]
Number of employees covered in multiemployer pension plan				440,000
Hydro One Brampton Networks And Norfolk Power [Member]
Accounting Policies [Line Items]
Number of employees covered in multiemployer pension plan				335

XML

Intangible Assets - Additional Information (Detail) (CAD) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Goodwill and Intangible Assets Disclosure [Abstract]
Financing charges related to intangible assets under development	1	3
Amortization expense for intangible assets, 2015	53
Amortization expense for intangible assets, 2016	53
Amortization expense for intangible assets, 2017	53
Amortization expense for intangible assets, 2018	45
Amortization expense for intangible assets, 2019	31

XML

Related Party Transactions - Schedule of Amounts Due to and from Related Parties (Parenthetical) (Detail) (CAD) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Related Party Transaction Due From To Related Party [Line Items]
Due to related parties, amounts owing on power purchases	227	230
IESO [Member]
Related Party Transaction Due From To Related Party [Line Items]
Due to related parties, amounts owing on power purchases	214	217

XML

Provision for Payments in Lieu of Corporate Income Taxes - Schedule of Deferred Income Tax Assets and Liabilities (Detail) (CAD) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Deferred income tax assets
Post-retirement and post-employment benefits expense in excess of cash payments	8	7
Environmental expenditures	4	5
Depreciation and amortization in excess of capital cost allowance	(4)
Other	(1)	(1)
Total deferred income tax assets	7	11
Less: current portion	0	0
Deferred income tax assets, Noncurrent	7	11
Deferred income tax liabilities
Capital cost allowance in excess of depreciation and amortization	(1,713)	(1,556)
Regulatory amounts that are not recognized for tax purposes	(140)	(144)
Partnership interest	(38)
Goodwill	(21)	(20)
Post-retirement and post-employment benefits expense in excess of cash payments	559	542
Environmental expenditures	59	66
Other		1
Total deferred income tax liabilities	(1,294)	(1,111)
Less: current portion	19	18
Deferred income tax liabilities, Noncurrent	(1,313)	(1,129)

XML

Environmental Liabilities (Tables)

12 Months Ended

Dec. 31, 2014

Text Block [Abstract]

Schedule of Movements in Environmental Liabilities

The following tables show the movements in environmental liabilities for the years ended December 31, 2014 and 2013:

Year ended December 31, 2014 (millions of Canadian dollars)	PCB			LAR			Total
Environmental liabilities, January 1		201			65			266
Interest accretion		9			2			11
Expenditures		(5	)		(13	)		(18	)
Revaluation adjustment		(33	)		13			(20	)
Environmental liabilities, December 31		172			67			239
Less: current portion		8			10			18
		164			57			221

Year ended December 31, 2013 (millions of Canadian dollars)	PCB			LAR			Total
Environmental liabilities, January 1		197			52			249
Interest accretion		9			1			10
Expenditures		(2	)		(14	)		(16	)
Revaluation adjustment		(3	)		26			23
Environmental liabilities, December 31		201			65			266
Less: current portion		15			12			27
		186			53			239

Reconciliation between Undiscounted Basis of Environmental Liabilities and Amount Recognized on Consolidated Balance Sheets

The following tables show the reconciliation between the undiscounted basis of the environmental liabilities and the amount recognized on the Consolidated Balance Sheets after factoring in the discount rate:

December 31, 2014 (millions of Canadian dollars)	PCB		LAR		Total
Undiscounted environmental liabilities		195		70		265
Less: discounting accumulated liabilities to present value		23		3		26
Discounted environmental liabilities		172		67		239

December 31, 2013 (millions of Canadian dollars)	PCB		LAR		Total
Undiscounted environmental liabilities		237		68		305
Less: discounting accumulated liabilities to present value		36		3		39
Discounted environmental liabilities		201		65		266

Schedule of Estimated Future Environmental Expenditures

At December 31, 2014, the estimated future environmental expenditures were as follows:

(millions of Canadian dollars)
2015	18
2016	37
2017	36
2018	35
2019	33
Thereafter	106
	265

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Significant Accounting Policies

12 Months Ended

Dec. 31, 2014

Accounting Policies [Abstract]

Significant Accounting Policies

2. SIGNIFICANT ACCOUNTING POLICIES

Basis of Consolidation

These Consolidated Financial Statements include the accounts of the Company and its wholly owned subsidiaries: Hydro One Networks Inc. (Hydro One Networks), Hydro One Remote Communities Inc. (Hydro One Remote Communities), Hydro One Brampton Networks Inc. (Hydro One Brampton Networks), Hydro One Telecom Inc. (Hydro One Telecom), Hydro One Lake Erie Link Management Inc., Hydro One Lake Erie Link Company Inc., Norfolk Power Inc. (Norfolk Power), and Hydro One B2M Holdings. Intercompany transactions and balances have been eliminated.

Basis of Accounting

These Consolidated Financial Statements are prepared and presented in accordance with United States (US) Generally Accepted Accounting Principles (GAAP) and in Canadian dollars.

Hydro One performed an evaluation of subsequent events through to February 11, 2015, the date these Consolidated Financial Statements were issued, to determine whether any events or transactions warranted recognition and disclosure in these Consolidated Financial Statements. See Note 25 – Subsequent Event.

Use of Management Estimates

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

Rate Setting

The Company’s Transmission Business includes the separately regulated transmission businesses of Hydro One Networks and B2M Limited Partnership (B2M LP). The Company’s consolidated Distribution Business includes the separately regulated distribution businesses of Hydro One Networks and the newly acquired Norfolk Power, as well as the subsidiaries Hydro One Brampton Networks and Hydro One Remote Communities.

The OEB has approved the use of US GAAP for rate setting and regulatory accounting and reporting by Hydro One Networks’ transmission and distribution businesses, as well as by Hydro One Remote Communities, beginning with the year 2012. Up to the year ended December 31, 2014, Hydro One Brampton Networks used Canadian GAAP (Part V) for its distribution rate-setting purposes, and has transitioned to International Financial Reporting Standards beginning on January 1, 2015.

Transmission

In May 2012, Hydro One Networks filed a cost-of-service application with the OEB for 2013 and 2014 transmission rates. In December 2012, the OEB approved the 2013 and 2014 revenue requirement of $1,438 million and $1,528 million, respectively.

In December 2013, Hydro One Networks filed a draft Rate Order with the OEB for 2014 transmission rates. The 2014 transmission revenue requirement was increased to $1,535 million from the originally-approved revenue requirement of $1,528 million, primarily due to changes in the cost of capital parameters for 2014 released by the OEB in November 2013. On January 9, 2014, the OEB approved the draft Rate Order for 2014 transmission rates as filed.

Distribution

In June 2012, Hydro One Networks filed an Incentive Regulation Mechanism (IRM) application with the OEB for 2013 distribution rates, to be effective January 1, 2013. In December 2012, the OEB issued its final Decision, which resulted in an increase in distribution rates of approximately 1.3% in 2013, or 0.4% when considering total bill impact, for a typical residential customer consuming 800 kWh per month. In April 2013, Hydro One Networks filed an IRM application with the OEB for 2014 distribution rates, to be effective January 1, 2014. In December 2013, the OEB issued its final Decision, which resulted in an increase in distribution rates of approximately 2.4% in 2014, or 0.85% when considering total bill impact, for a typical residential customer consuming 800 kWh per month.

In August 2012, Hydro One Brampton Networks filed an IRM application with the OEB for 2013 distribution rates, to be effective January 1, 2013. In December 2012, the OEB issued its final Decision, which resulted in an increase in distribution rates of approximately 0.3% in 2013, or less than 0.1% when considering total bill impact, for a typical residential customer consuming 800 kWh per month. In August 2013, Hydro One Brampton Networks filed an IRM application with the OEB for 2014 distribution rates, to be effective January 1, 2014. In December 2013, the OEB issued its final Decision, which resulted in a reduction in distribution rates of approximately 2.3% in 2014, or 0.5% when considering total bill impact, for a typical residential customer consuming 800 kWh per month.

In September 2012, Hydro One Remote Communities filed a cost-of-service application with the OEB for 2013 rates, seeking approval for a 2013 revenue requirement of $53 million. In June 2013, the OEB approved a revenue requirement of $51 million for 2013. In October 2013, Hydro One Remote Communities filed an IRM application with the OEB for 2014 rates, seeking approval for a rate increase of approximately 0.5%. In March 2014, the OEB approved an increase of approximately 1.7% to basic rates for the distribution and generation of electricity, with an effective date of May 1, 2014. The final rate increase was adjusted by the OEB’s updated rate adjustment parameters and Hydro One Remote Communities’ IRM stretch factor.

Regulatory Accounting

The OEB has the general power to include or exclude revenues, costs, gains or losses in the rates of a specific period, resulting in a change in the timing of accounting recognition from that which would have been applied in an unregulated company. Such change in timing involves the application of rate-regulated accounting, giving rise to the recognition of regulatory assets and liabilities. The Company’s regulatory assets represent certain amounts receivable from future customers and costs that have been deferred for accounting purposes because it is probable that they will be recovered in future rates. In addition, the Company has recorded regulatory liabilities that generally represent amounts that are refundable to future customers. The Company continually assesses the likelihood of recovery of each of its regulatory assets and continues to believe that it is probable that the OEB will factor its regulatory assets and liabilities into the setting of future rates. If, at some future date, the Company judges that it is no longer probable that the OEB will include a regulatory asset or liability in setting future rates, the appropriate carrying amount will be reflected in results of operations in the period that the assessment is made.

Cash and Cash Equivalents

Cash and cash equivalents include cash and short-term investments with an original maturity of three months or less.

Revenue Recognition

Transmission revenues are collected through OEB-approved rates, which are based on an approved revenue requirement that includes a rate of return. Such revenue is recognized as electricity is transmitted and delivered to customers.

Distribution revenues are recognized on an accrual basis and include billed and unbilled revenues. Distribution revenues attributable to the delivery of electricity are based on OEB-approved distribution rates and are recognized as electricity is delivered to customers. The Company estimates monthly revenue for a period based on wholesale electricity purchases because customer meters are not generally read at the end of each month. At the end of each month, the electricity delivered to customers, but not billed, is estimated and revenue is recognized. The unbilled revenue estimate is affected by energy demand, weather, line losses and changes in the composition of customer classes.

Distribution revenue also includes an amount relating to rate protection for rural, residential and remote customers, which is received from the Independent Electricity System Operator (IESO) based on a standardized customer rate that is approved by the OEB. Current legislation provides rate protection for prescribed classes of rural, residential and remote consumers by reducing the electricity rates that would otherwise apply.

Revenues also include amounts related to sales of other services and equipment. Such revenue is recognized as services are rendered or as equipment is delivered.

Revenues are recorded net of indirect taxes.

Accounts Receivable and Allowance for Doubtful Accounts

Billed accounts receivable are recorded at the invoiced amount, net of allowance for doubtful accounts. Unbilled accounts receivable are estimated and recorded based on wholesale electricity purchases. Overdue amounts related to regulated billings bear interest at OEB-approved rates. The allowance for doubtful accounts reflects the Company’s best estimate of losses on billed accounts receivable balances. The allowance is based on accounts receivable aging, historical experience and other currently available information. The Company estimates the allowance for doubtful accounts on customer receivables by applying internally developed loss rates to the outstanding receivable balances by risk segment. Risk segments represent groups of customers with similar credit quality indicators and are computed based on various attributes, including number of days receivables are past due, delinquency of balances and payment history. Loss rates applied to the accounts receivable balances are based on historical average write-offs as a percentage of accounts receivable in each risk segment. An account is considered delinquent if the final amount billed is not received within 110 days of the invoiced date. Accounts receivable are written off against the allowance when they are deemed uncollectible. The existing allowance for uncollectible accounts will continue to be affected by changes in volume, prices and economic conditions.

Noncontrolling interest

Noncontrolling interest represents the portion of equity ownership in subsidiaries that is not attributable to the Shareholder of the parent company. Noncontrolling interest is initially recorded at fair value and subsequently the amount is adjusted for the proportionate share of net income (loss) and other comprehensive income (loss) attributable to the noncontrolling interest and any dividends or distributions paid to the noncontrolling interest.

If a transaction results in the acquisition of all, or part, of a noncontrolling interest in a subsidiary, the acquisition of the noncontrolling interest is accounted for as an equity transaction. No gain or loss is recognized in consolidated net income or comprehensive income as a result of changes in the noncontrolling interest, unless a change results in the loss of control by the Company.

Corporate Income Taxes

Under the Electricity Act, 1998, Hydro One is required to make payments in lieu of corporate income taxes (PILs) to the Ontario Electricity Financial Corporation (OEFC). These payments are calculated in accordance with the rules for computing income and other relevant amounts contained in the Income Tax Act (Canada) and the Taxation Act, 2007 (Ontario) as modified by the Electricity Act, 1998 and related regulations.

Current and deferred income taxes are computed based on the tax rates and tax laws enacted at the balance sheet date. Tax benefits associated with income tax positions taken, or expected to be taken, in a tax return are recorded only when the “more-likely-than-not” recognition threshold is satisfied and are measured at the largest amount of benefit that has a greater than 50% likelihood of being realized upon settlement. Management evaluates each position based solely on the technical merits and facts and circumstances of the position, assuming the position will be examined by a taxing authority having full knowledge of all relevant information. Significant management judgment is required to determine recognition thresholds and the related amount of tax benefits to be recognized in the Consolidated Financial Statements. Management re-evaluates tax positions each period in which new information about recognition or measurement becomes available.

Current Income Taxes

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

Deferred Income Taxes

Deferred income taxes are provided for using the liability method. Deferred income taxes are recognized based on the estimated future tax consequences attributable to temporary differences between the carrying amount of assets and liabilities in the Consolidated Financial Statements and their corresponding tax bases.

Deferred income tax liabilities are generally recognized on all taxable temporary differences. Deferred tax assets are recognized to the extent that it is more-likely-than-not that these assets will be realized from taxable income available against which deductible temporary differences can be utilized.

Deferred income taxes are calculated at the tax rates that are expected to apply in the period when the liability is settled or the asset is realized, based on the tax rates and tax laws that have been enacted at the balance sheet date. Deferred income taxes that are not included in the rate-setting process are charged or credited to the Consolidated Statements of Operations and Comprehensive Income.

If management determines that it is more-likely-than-not that some or all of a deferred income tax asset will not be realized, a valuation allowance is recorded against the deferred income tax asset to report the net balance at the amount expected to be realized. Previously unrecognized deferred income tax assets are reassessed at each balance sheet date and are recognized to the extent that it has become more-likely-than-not that the tax benefit will be realized.

The Company records regulatory assets and liabilities associated with deferred income taxes that will be included in the rate-setting process.

The Company uses the flow-through method to account for investment tax credits (ITCs) earned on eligible scientific research and experimental development expenditures, and apprenticeship job creation. Under this method, only non-refundable ITCs are recognized as a reduction to income tax expense.

Materials and Supplies

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

Property, Plant and Equipment

Property, plant and equipment is recorded at original cost, net of customer contributions received in aid of construction and any accumulated impairment losses. The cost of additions, including betterments and replacement asset components, is included on the Consolidated Balance Sheets as property, plant and equipment.

The original cost of property, plant and equipment includes direct materials, direct labour (including employee benefits), contracted services, attributable capitalized financing costs, asset retirement costs, and direct and indirect overheads that are related to the capital project or program. Indirect overheads include a portion of corporate costs such as finance, treasury, human resources, information technology and executive costs. Overhead costs, including corporate functions and field services costs, are capitalized on a fully allocated basis, consistent with an OEB-approved methodology.

Property, plant and equipment in service consists of transmission, distribution, communication, administration and service assets and land easements. Property, plant and equipment also includes future use assets, such as land, major components and spare parts, and capitalized project development costs associated with deferred capital projects.

Transmission

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

Distribution

Distribution assets include assets related to the distribution of low-voltage electricity, including lines, poles, switches, transformers, protective devices and metering systems.

Communication

Communication assets include the fibre optic and microwave radio system, optical ground wire, towers, telephone equipment and associated buildings.

Administration and Service

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

Easements

Easements include statutory rights of use for transmission corridors and abutting lands granted under the Reliable Energy and Consumer Protection Act, 2002, as well as other land access rights.

Intangible Assets

Intangible assets separately acquired or internally developed are measured on initial recognition at cost, which comprises purchased software, direct labour (including employee benefits), consulting, engineering, overheads and attributable capitalized financing charges. Following initial recognition, intangible assets are carried at cost, net of any accumulated amortization and accumulated impairment losses. The Company’s intangible assets primarily represent major company-wide computer applications.

Capitalized Financing Costs

Capitalized financing costs represent interest costs attributable to the construction of property, plant and equipment or development of intangible assets. The financing cost of attributable borrowed funds is capitalized as part of the acquisition cost of such assets. The capitalized portion of financing costs is a reduction to financing charges recognized in the Consolidated Statements of Operations and Comprehensive Income. Capitalized financing costs are calculated using the Company’s weighted average effective cost of debt.

Construction and Development in Progress

Construction and development in progress consists of the capitalized cost of constructed assets that are not yet complete and which have not yet been placed in service.

Depreciation and Amortization

The cost of property, plant and equipment and intangible assets is depreciated or amortized on a straight-line basis based on the estimated remaining service life of each asset category, except for transport and work equipment, which is depreciated on a declining balance basis.

The Company periodically initiates an external independent review of its property, plant and equipment and intangible asset depreciation and amortization rates, as required by the OEB. Any changes arising from OEB approval of such a review are implemented on a remaining service life basis, consistent with their inclusion in electricity rates. The last review resulted in changes to rates effective January 1, 2013. A summary of average service lives and depreciation and amortization rates for the various classes of assets is included below:

	Average		Rate
	Service Life		Range	Average
Transmission		57 years	1% – 2%		2	%
Distribution		42 years	1% – 20%		2	%
Communication		19 years	1% – 15%		4	%
Administration and service		15 years	3% – 20%		7	%

The cost of intangible assets is included primarily within the administration and service classification above. Amortization rates for computer applications software and other intangible assets range from 9% to 20%.

In accordance with group depreciation practices, the original cost of property, plant and equipment, or major components thereof, and intangible assets that are normally retired, is charged to accumulated depreciation, with no gain or loss being reflected in results of operations. Where a disposition of property, plant and equipment occurs through sale, a gain or loss is calculated based on proceeds and such gain or loss is included in depreciation expense. Depreciation expense also includes the costs incurred to remove property, plant and equipment where no ARO has been recorded.

Goodwill

Goodwill represents the cost of acquired local distribution companies that is in excess of the fair value of the net identifiable assets acquired at the acquisition date. Goodwill is not included in rate base.

Goodwill is evaluated for impairment on an annual basis, or more frequently if circumstances require. The Company performs a qualitative assessment to determine whether it is more-likely-than-not that the fair value of the applicable reporting unit is less than its carrying amount. If the Company determines, as a result of its qualitative assessment, that it is not more-likely-than-not that the fair value of the applicable reporting unit is less than its carrying amount, no further testing is required. If the Company determines, as a result of its qualitative assessment, that it is more-likely-than-not that the fair value of the applicable reporting unit is less than its carrying amount, a goodwill impairment assessment is performed using a two-step, fair value-based test. The first step compares the fair value of the applicable reporting unit to its carrying amount, including goodwill. If the carrying amount of the applicable reporting unit exceeds its fair value, a second step is performed. The second step requires an allocation of fair value to the individual assets and liabilities using purchase price allocation in order to determine the implied fair value of goodwill. If the implied fair value of goodwill is less than the carrying amount, an impairment loss is recorded as a reduction to goodwill and as a charge to results of operations.

For the year ended December 31, 2014, based on the qualitative assessment performed as at September 30, 2014, the Company has determined that it is not more-likely-than-not that the fair value of each applicable reporting unit assessed is less than its carrying amount. As a result, no further testing was performed, and the Company has concluded that goodwill was not impaired at December 31, 2014.

Long-Lived Asset Impairment

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

Within its regulated business, the carrying costs of most of Hydro One’s long-lived assets are included in rate base where they earn an OEB-approved rate of return. Asset carrying values and the related return are recovered through approved rates. As a result, such assets are only tested for impairment in the event that the OEB disallows recovery, in whole or in part, or if such a disallowance is judged to be probable.

Hydro One regularly monitors the assets of its unregulated Hydro One Telecom subsidiary for indications of impairment. Management assesses the fair value of such long-lived assets using commonly accepted techniques, and may use more than one. Techniques used to determine fair value include, but are not limited to, the use of recent third party comparable sales for reference and internally developed discounted cash flow analysis. Significant changes in market conditions, changes to the condition of an asset, or a change in management’s intent to utilize the asset are generally viewed by management as triggering events to reassess the cash flows related to these long-lived assets. As at December 31, 2014, no asset impairment had been recorded for assets within either the Company’s regulated or unregulated businesses.

Costs of Arranging Debt Financing

For financial liabilities classified as other than held-for-trading, the Company defers the external transaction costs related to obtaining debt financing and presents such amounts as deferred debt issuance costs on the Consolidated Balance Sheets. Deferred debt issuance costs are amortized over the contractual life of the related debt on an effective-interest basis and the amortization is included within financing charges in the Consolidated Statements of Operations and Comprehensive Income. Transaction costs for items classified as held-for-trading are expensed immediately.

Comprehensive Income

Comprehensive income is comprised of net income and other comprehensive income (OCI). Hydro One presents net income and OCI in a single continuous Consolidated Statement of Operations and Comprehensive Income.

Financial Assets and Liabilities

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

Derivative instruments are measured at fair value. Gains and losses from fair valuation are included within financing charges in the period in which they arise. The Company determines the classification of its financial assets and liabilities at the date of initial recognition. The Company designates certain of its financial assets and liabilities to be held at fair value, when it is consistent with the Company’s risk management policy disclosed in Note 13 – Fair Value of Financial Instruments and Risk Management.

Derivative Instruments and Hedge Accounting

The Company closely monitors the risks associated with changes in interest rates on its operations and, where appropriate, uses various instruments to hedge these risks. Certain of these derivative instruments qualify for hedge accounting and are designated as accounting hedges, while others either do not qualify as hedges or have not been designated as hedges (hereinafter referred to as undesignated contracts) as they are part of economic hedging relationships.

The accounting guidance for derivative instruments requires the recognition of all derivative instruments not identified as meeting the normal purchase and sale exemption as either assets or liabilities recorded at fair value on the Consolidated Balance Sheets. For derivative instruments that qualify for hedge accounting, the Company may elect to designate such derivative instruments as either cash flow hedges or fair value hedges. The Company offsets fair value amounts recognized on its Consolidated Balance Sheets related to derivative instruments executed with the same counterparty under the same master netting agreement.

For derivative instruments that qualify for hedge accounting and which are designated as cash flow hedges, the effective portion of any gain or loss, net of tax, is reported as a component of accumulated OCI (AOCI) and is reclassified to results of operations in the same period or periods during which the hedged transaction affects results of operations. Any gains or losses on the derivative instrument that represent either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in results of operations. For fair value hedges, changes in fair value of both the derivative instrument and the underlying hedged exposure are recognized in the Consolidated Statements of Operations and Comprehensive Income in the current period. The gain or loss on the derivative instrument is included in the same line item as the offsetting gain or loss on the hedged item in the Consolidated Statements of Operations and Comprehensive Income. Additionally, the Company enters into derivative agreements that are economic hedges which either do not qualify for hedge accounting or have not been designated as hedges. The changes in fair value of these undesignated derivative instruments are reflected in results of operations.

Embedded derivative instruments are separated from their host contracts and carried at fair value on the Consolidated Balance Sheets when: (a) the economic characteristics and risks of the embedded derivative are not clearly and closely related to the economic characteristics and risks of the host contract; (b) the hybrid instrument is not measured at fair value, with changes in fair value recognized in results of operations each period; and (c) the embedded derivative itself meets the definition of a derivative. The Company does not engage in derivative trading or speculative activities and had no embedded derivatives at December 31, 2014 or 2013.

Hydro One periodically develops hedging strategies taking into account risk management objectives. At the inception of a hedging relationship where the Company has elected to apply hedge accounting, Hydro One formally documents the relationship between the hedged item and the hedging instrument, the related risk management objective, the nature of the specific risk exposure being hedged, and the method for assessing the effectiveness of the hedging relationship. The Company also assesses, both at the inception of the hedge and on a quarterly basis, whether the hedging instruments are effective in offsetting changes in fair values or cash flows of the hedged items.

Employee Future Benefits

Employee future benefits provided by Hydro One include pension, post-retirement and post-employment benefits. The costs of the Company’s pension, post-retirement and post-employment benefit plans are recorded over the periods during which employees render service.

The Company recognizes the funded status of its pension, post-retirement and post-employment plans on its Consolidated Balance Sheets and subsequently recognizes the changes in funded status at the end of each reporting year. Pension, post-retirement and post-employment plans are considered to be underfunded when the projected benefit obligation exceeds the fair value of the plan assets. Liabilities are recognized on the Consolidated Balance Sheets for any net underfunded projected benefit obligation. The net underfunded projected benefit obligation may be disclosed as a current liability, long-term liability, or both. The current portion is the amount by which the actuarial present value of benefits included in the benefit obligation payable in the next 12 months exceeds the fair value of plan assets. If the fair value of plan assets exceeds the projected benefit obligation of the plan, an asset is recognized equal to the net overfunded projected benefit obligation. The post-retirement and post-employment benefit plans are unfunded because there are no related plan assets.

Pension benefits

In accordance with the OEB’s rate orders, pension costs are recorded on a cash basis as employer contributions are paid to the pension fund in accordance with the Pension Benefits Act (Ontario). Pension costs are recorded on an accrual basis for financial reporting purposes. Pension costs are actuarially determined using the projected benefit method prorated on service and are based on assumptions that reflect management’s best estimate of the effect of future events, including future compensation increases. Past service costs from plan amendments and all actuarial gains and losses are amortized on a straight-line basis over the expected average remaining service period of active employees in the plan, and over the estimated remaining life expectancy of inactive employees in the plan. Pension plan assets, consisting primarily of listed equity securities as well as corporate and government debt securities, are fair valued at the end of each year.

Hydro One records a regulatory asset equal to the net underfunded projected benefit obligation for its pension plan. The regulatory asset for the net underfunded projected benefit obligation for the pension plan, in the absence of regulatory accounting, would be recognized in AOCI. A regulatory asset is recognized because management considers it to be probable that pension benefit costs will be recovered in the future through the rate-setting process. The pension regulatory assets are remeasured at the end of each year based on the current status of the pension plan.

All future pension benefit costs are attributed to labour and are either charged to results of operations or capitalized as part of the cost of property, plant and equipment and intangible assets.

Post-retirement and post-employment benefits

Post-retirement and post-employment benefits are recorded and included in rates on an accrual basis. Costs are determined by independent actuaries using the projected benefit method prorated on service and based on assumptions that reflect management’s best estimates. Past service costs from plan amendments are amortized to results of operations based on the expected average remaining service period.

Hydro One records a regulatory asset equal to the incremental net unfunded projected benefit obligation for post-retirement and post-employment plans recorded at each year end based on annual actuarial reports. The regulatory asset for the incremental net unfunded projected benefit obligation for post-retirement and post-employment plans, in the absence of regulatory accounting, would be recognized in AOCI. A regulatory asset is recognized because management considers it to be probable that post-retirement and post-employment benefit costs will be recovered in the future through the rate-setting process.

For post-retirement benefits, all actuarial gains or losses are deferred using the “corridor” approach. The amount calculated above the “corridor” is amortized to results of operations on a straight-line basis over the expected average remaining service life of active employees in the plan and over the remaining life expectancy of inactive employees in the plan. The post-retirement benefit obligation is remeasured to its fair value at each year end based on an annual actuarial report, with an offset to the associated regulatory asset, to the extent of the remeasurement adjustment.

For post-employment obligations, the associated regulatory liabilities representing actuarial gains on transition to US GAAP are amortized to results of operations based on the “corridor” approach. Post transition, the actuarial gains and losses on post-employment obligations that are incurred during the year are recognized immediately to results of operations. The post-employment benefit obligation is remeasured to its fair value at each year end based on an annual actuarial report, with an offset to the associated regulatory asset, to the extent of the remeasurement adjustment.

All post-retirement and post-employment future benefit costs are attributed to labour and are either charged to results of operations or capitalized as part of the cost of property, plant and equipment and intangible assets.

Multiemployer Pension Plan

Employees of Hydro One Brampton Networks and the newly acquired Norfolk Power participate in the Ontario Municipal Employees Retirement System Fund (OMERS), a multiemployer, contributory, defined benefit public sector pension fund. OMERS provides retirement pension payments based on members’ length of service and salary. Both the participating employers and members are required to make plan contributions. The OMERS plan assets are pooled together to provide benefits to all plan participants and the plan assets are not segregated by member entity. OMERS is registered with the Financial Services Commission of Ontario under Registration #0345983. At December 31, 2013, OMERS had approximately 440,000 members, with approximately 335 members being current employees of Hydro One Brampton Networks and Norfolk Power.

The OMERS plan is accounted for as a defined contribution plan by Hydro One because it is not practicable to determine the present value of the Company’s obligation, the fair value of plan assets or the related current service cost applicable to Hydro One Brampton Networks and Norfolk Power employees. Hydro One recognizes its contributions to the OMERS plan as pension expense, with a portion being capitalized. The expensed amount is included in operation, maintenance and administration costs in the Consolidated Statements of Operations and Comprehensive Income.

Loss Contingencies

Hydro One is involved in certain legal and environmental matters that arise in the normal course of business. In the preparation of its Consolidated Financial Statements, management makes judgments regarding the future outcome of contingent events and records a loss for a contingency based on its best estimate when it is determined that such loss is probable and the amount of the loss can be reasonably estimated. Where the loss amount is recoverable in future rates, a regulatory asset is also recorded. When a range estimate for the probable loss exists and no amount within the range is a better estimate than any other amount, the Company records a loss at the minimum amount within the range.

Management regularly reviews current information available to determine whether recorded provisions should be adjusted and whether new provisions are required. Estimating probable losses may require analysis of multiple forecasts and scenarios that often depend on judgments about potential actions by third parties, such as federal, provincial and local courts or regulators. Contingent liabilities are often resolved over long periods of time. Amounts recorded in the Consolidated Financial Statements may differ from the actual outcome once the contingency is resolved. Such differences could have a material impact on future results of operations, financial position and cash flows of the Company.

Provisions are based upon current estimates and are subject to greater uncertainty where the projection period is lengthy. A significant upward or downward trend in the number of claims filed, the nature of the alleged injuries, and the average cost of resolving each claim could change the estimated provision, as could any substantial adverse or favourable verdict at trial. A federal or provincial legislative outcome or structured settlement could also change the estimated liability. Legal fees are expensed as incurred.

Environmental Liabilities

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

Asset Retirement Obligations

AROs are recorded for legal obligations associated with the future removal and disposal of long-lived assets. Such obligations may result from the acquisition, construction, development and/or normal use of the asset. Conditional AROs are recorded when there is a legal obligation to perform a future asset retirement activity but where the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the Company. In such a case, the obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and/or method of settlement.

When recording an ARO, the present value of the estimated future expenditures required to complete the asset retirement activity is recorded in the period in which the obligation is incurred, if a reasonable estimate can be made. In general, the present value of the estimated future expenditures is added to the carrying amount of the associated asset and the resulting asset retirement cost is depreciated over the estimated useful life of the asset. Where an asset is no longer in service when an ARO is recorded, the asset retirement cost is recorded in results of operations.

Some of the Company’s transmission and distribution assets, particularly those located on unowned easements and rights-of-way, may have AROs, conditional or otherwise. The majority of the Company’s easements and rights-of-way are either of perpetual duration or are automatically renewed annually. Land rights with finite terms are generally subject to extension or renewal. As the Company expects to use the majority of its facilities in perpetuity, no ARO currently exists for these assets. If, at some future date, a particular facility is shown not to meet the perpetuity assumption, it will be reviewed to determine whether an estimable ARO exists. In such a case, an ARO would be recorded at that time.

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

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Segmented Reporting - Summary of Segment Information (Detail) (CAD) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Segment Reporting Information [Line Items]
Revenues	6,548	6,074
Purchased power	3,419	3,020
Operation, maintenance and administration	1,192	1,106
Depreciation and amortization	722	676
Income before financing charges and provision for payments in lieu of corporate income taxes	1,215	1,272
Capital investments	1,530	1,394
Total assets	22,550	21,625
Transmission [Member]
Segment Reporting Information [Line Items]
Revenues	1,588	1,529
Operation, maintenance and administration	394	375
Depreciation and amortization	346	327
Income before financing charges and provision for payments in lieu of corporate income taxes	848	827
Capital investments	845	714
Total assets	12,540	11,846
Distribution [Member]
Segment Reporting Information [Line Items]
Revenues	4,903	4,484
Purchased power	3,419	3,020
Operation, maintenance and administration	742	672
Depreciation and amortization	367	340
Income before financing charges and provision for payments in lieu of corporate income taxes	375	452
Capital investments	680	673
Total assets	9,805	8,805
Other [Member]
Segment Reporting Information [Line Items]
Revenues	57	61
Operation, maintenance and administration	56	59
Depreciation and amortization	9	9
Income before financing charges and provision for payments in lieu of corporate income taxes	(8)	(7)
Capital investments	5	7
Total assets	205	974

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Accounts Receivable - Schedule of Accounts Receivable (Detail) (CAD) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable, gross	1,082	959
Allowance for doubtful accounts	(66)	(36)	(23)
Accounts receivable, net	1,016	923
Accounts Receivable - Billed [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable, gross	496	268
Accounts Receivable - Unbilled [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable, gross	586	691

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Debt and Credit Agreements (Tables)

12 Months Ended

Dec. 31, 2014

Debt Disclosure [Abstract]

Schedule of Outstanding Long-Term Debt

The following table presents the outstanding long-term debt at December 31, 2014 and 2013:

December 31 (millions of Canadian dollars)	2014			2013
3.13% Series 19 notes due 20141		—			750
2.95% Series 21 notes due 20151		500			500
Floating-rate Series 22 notes due 20152		50			50
4.64% Series 10 notes due 2016		450			450
Floating-rate Series 27 notes due 20162		50			50
5.18% Series 13 notes due 2017		600			600
2.78% Series 28 notes due 2018		750			750
Floating-rate Series 31 notes due 20192		228			—
4.40% Series 20 notes due 2020		300			300
3.20% Series 25 notes due 2022		600			600
7.35% Debentures due 2030		400			400
6.93% Series 2 notes due 2032		500			500
6.35% Series 4 notes due 2034		385			385
5.36% Series 9 notes due 2036		600			600
4.89% Series 12 notes due 2037		400			400
6.03% Series 17 notes due 2039		300			300
5.49% Series 18 notes due 2040		500			500
4.39% Series 23 notes due 2041		300			300
6.59% Series 5 notes due 2043		315			315
4.59% Series 29 notes due 2043		435			435
4.17% Series 32 notes due 2044		350			—
5.00% Series 11 notes due 2046		325			325
4.00% Series 24 notes due 2051		225			225
3.79% Series 26 notes due 2062		310			310
4.29% Series 30 notes due 2064		50			—
		8,923			9,045
Add: Unrealized mark-to-market loss1		2			12
Less: Long-term debt payable within one year		(552	)		(756	)
Long-term debt		8,373			8,301

¹  The unrealized mark-to-market loss relates to $250 million of the Series 21 notes due 2015 (2013 – $500 million of the Series 19 notes due 2014, and $250 million of the Series 21 notes due 2015). The unrealized mark-to-market loss is offset by a $2 million (2013 – $12 million) unrealized mark-to-market gain on the related fixed-to-floating interest-rate swap agreements, which are accounted for as fair value hedges. See Note 13 – Fair Value of Financial Instruments and Risk Management for details of fair value hedges.

²  The interest rates of the floating-rate notes are referenced to the 3-month Canadian dollar bankers’ acceptance rate, plus a margin.

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Contingencies

12 Months Ended

Dec. 31, 2014

Commitments and Contingencies Disclosure [Abstract]

Contingencies

22. CONTINGENCIES

Legal Proceedings

Hydro One is involved in various lawsuits, claims and regulatory proceedings in the normal course of business. In the opinion of management, the outcome of such matters will not have a material adverse effect on the Company’s consolidated financial position, results of operations or cash flows.

Transfer of Assets

The transfer orders by which the Company acquired certain of Ontario Hydro’s businesses as of April 1, 1999 did not transfer title to some assets located on Reserves (as defined in the Indian Act (Canada)). Currently, the OEFC holds these assets. Under the terms of the transfer orders, the Company is required to manage these assets until it has obtained all consents necessary to complete the transfer of title of these assets to itself. The Company cannot predict the aggregate amount that it may have to pay, either on an annual or one-time basis, to obtain the required consents. In 2014, the Company paid approximately $1 million (2013 – $2 million) in respect of these consents. If the Company cannot obtain the required consents, the OEFC will continue to hold these assets for an indefinite period of time. If the Company cannot reach a satisfactory settlement, it may have to relocate these assets to other locations at a cost that could be substantial or, in a limited number of cases, to abandon a line and replace it with diesel-generation facilities. The costs relating to these assets could have a material adverse effect on the Company’s results of operations if the Company is not able to recover them in future rate orders.

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Consolidated Statements of Cash Flows

12 Months Ended

Dec. 31, 2014

Supplemental Cash Flow Elements [Abstract]

Consolidated Statements of Cash Flows

21. CONSOLIDATED STATEMENTS OF CASH FLOWS

The changes in non-cash balances related to operations consist of the following:

Year ended December 31 (millions of Canadian dollars)	2014			2013
Accounts receivable		(93	)		(78	)
Due from related parties		(27	)		(43	)
Prepaid expenses and other assets		(13	)		(5	)
Accounts payable		39			13
Accrued liabilities		(35	)		71
Due to related parties		(3	)		(31	)
Accrued interest		—			5
Long-term accounts payable and other liabilities		(3	)		(5	)
Post-retirement and post-employment benefit liability		80			84
		(55	)		11

Capital Expenditures

The following table illustrates the reconciliation between investments in property, plant and equipment and the amount presented in the Consolidated Statements of Cash Flows after factoring in capitalized depreciation and the net change in related accruals:

Year ended December 31 (millions of Canadian dollars)	2014			2013
Capital investments in property, plant and equipment		(1,511	)		(1,312	)
Capitalized depreciation and net change in accruals included in capital investments in property, plant and equipment		30			4
Capital expenditures – property, plant and equipment		(1,481	)		(1,308	)

The following table illustrates the reconciliation between investments in intangible assets and the amount presented in the Consolidated Statements of Cash Flows after factoring in the net change in related accruals:

Year ended December 31 (millions of Canadian dollars)	2014			2013
Capital investments in intangible assets		(19	)		(82	)
Net change in accruals included in capital investments in intangible assets		(4	)		3
Capital expenditures – intangible assets		(23	)		(79	)

Supplementary Information

Year ended December 31 (millions of Canadian dollars)	2014		2013
Net interest paid		412		395
PILs		86		138

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Pension and Post-Retirement and Post-Employment Benefits - Pension Plan Assets Measured and Recorded at Fair Value on Recurring Basis (Parenthetical) (Detail) (CAD) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Compensation and Retirement Disclosure [Abstract]
Interest and dividend receivable excluded from fair value of pension plan assets	18	19
Accruals for pension administration expense excluded from fair value of pension plan assets	7	7

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Depreciation and Amortization - Schedule of Depreciation and Amortization (Detail) (CAD) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Depreciation, Depletion and Amortization [Abstract]
Depreciation of property, plant and equipment	565	533
Amortization of intangible assets	53	48
Asset removal costs	81	79
Amortization of regulatory assets	23	16
Total depreciation and amortization	722	676

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Fair Value of Financial Instruments and Risk Management (Tables)

12 Months Ended

Dec. 31, 2014

Fair Value Disclosures [Abstract]

Summary of Fair Values and Carrying Values of Long-Term Debt

The fair values and carrying values of the Company’s long-term debt at December 31, 2014 and 2013 are as follows:

December 31 (millions of Canadian dollars)	2014 Carrying Value		2014 Fair Value		2013 Carrying Value		2013 Fair Value
Long-term debt
$500 million of MTN Series 19 notes1		—		—		506		506
$250 million of MTN Series 21 notes1		252		252		256		256
Other notes and debentures2		8,673		10,159		8,295		9,018
		8,925		10,411		9,057		9,780

¹  The fair value of $500 million of the MTN Series 19 notes and of $250 million of the MTN Series 21 notes subject to hedging is primarily based on changes in the present value of future cash flows due to a change in the yield in the swap market for the related swap (hedged risk).

² The fair value of other notes and debentures, and the portions of the MTN Series 19 notes and the MTN Series 21 notes that are not subject to hedging, represents the market value of the notes and debentures and is based on unadjusted period-end market prices for the same or similar debt of the same remaining maturities.

Summary of Fair Value Hierarchy of Financial Assets and Liabilities

The fair value hierarchy of financial assets and liabilities at December 31, 2014 and 2013 is as follows:

December 31, 2014 (millions of Canadian dollars)	Carrying Value		Fair Value		Level 1		Level 2		Level 3
Assets:
Cash and cash equivalents		100		100		100		—		—
Derivative instruments
Fair value hedges – interest-rate swaps		2		2		—		2		—
		102		102		100		2		—
Liabilities:
Bank indebtedness		2		2		2		—		—
Derivative instruments
Undesignated contracts – interest-rate swaps		3		3		—		3		—
Long-term debt		8,925		10,411		—		10,411		—
		8,930		10,416		2		10,414		—
December 31, 2013 (millions of Canadian dollars)	Carrying Value		Fair Value		Level 1		Level 2		Level 3
Assets:
Cash and cash equivalents		565		565		565		—		—
Investment		251		251		—		251		—
Derivative instruments
Fair value hedges – interest-rate swaps		12		12		—		12		—
		828		828		565		263		—
Liabilities:
Bank indebtedness		31		31		31		—		—
Long-term debt		9,057		9,780		—		9,780		—
		9,088		9,811		31		9,780		—

Summary of Net Unrealized Loss (Gain) on Hedged Debt and Related Interest Rate Swaps

 The net unrealized loss (gain) on the hedged debt and the related interest-rate swaps for the years ended December 31, 2014 and 2013 are included in financing charges as follows:

Year ended December 31 (millions of Canadian dollars)	2014			2013
Unrealized loss (gain) on hedged debt		(3	)		(8	)
Unrealized loss (gain) on fair value interest-rate swaps		3			8
Net unrealized loss (gain)		—			—

Summary of Principal Repayments, Interest Payments and Related Weighted Average Interest Rates

Principal repayments, interest payments and related weighted average interest rates are summarized by the number of years to maturity in the following table:

	Long-term Debt Principal Repayments		Interest Payments		Weighted Average Interest Rate
Years to Maturity	(millions of Canadian dollars)		(millions of Canadian dollars)		(%)
1 year		550		419		2.8
2 years		500		393		4.3
3 years		600		381		5.2
4 years		750		350		2.8
5 years		228		327		1.6
		2,628		1,870		3.5
6 – 10 years		900		1,522		3.6
Over 10 years		5,395		4,373		5.4
		8,923		7,765		4.7

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Commitments

12 Months Ended

Dec. 31, 2014

Commitments and Contingencies Disclosure [Abstract]

Commitments

23. COMMITMENTS

Outsourcing Agreements

The current agreement with Inergi LP (Inergi), an affiliate of Capgemini Canada Inc., expires on February 28, 2015. On November 28, 2014, Hydro One entered into an agreement with Inergi (Inergi Agreement), the service provider selected through a competitive procurement process which began in 2013, for second-generation back office and IT outsourcing services for a term of 58 months, commencing March 1, 2015 to December 31, 2019. Under the agreement, Inergi will provide Hydro One with settlements, source to pay services, pay operations services, information technology and finance and accounting services. Coincident with the conclusion of negotiations on the Inergi Agreement, Hydro One reached agreement with Inergi for the provision of second-generation customer service operations outsourcing services for a fixed period of three years beginning March 1, 2015 to February 28, 2018.

In September 2014, Hydro One entered into an agreement with Brookfield Johnson Controls Canada LP (Brookfield) for facilities management services for a term of ten years, from January 1, 2015 to December 31, 2024, with the option to renew for an additional term of three years. Under the agreement, Brookfield will provide us with facilities management and execution of certain capital projects as deemed required by the Company. The Brookfield Agreement has a value of up to approximately $658 million over the ten-year term of the agreement, including the facilities management portion of the contract, plus a variable amount of capital work depending on the needs that may arise as determined by the Company, with no minimum capital work guarantee. The agreement also includes a fixed management fee of approximately $2 million for each year of the term.

At December 31, 2014, the annual commitments under the outsourcing agreements were as follows: 2015 – $179 million; 2016 – $146 million; 2017 – $145 million; 2018 – $113 million; 2019 – $105 million; and thereafter – $13 million.

Prudential Support

Purchasers of electricity in Ontario, through the IESO, are required to provide security to mitigate the risk of their default based on their expected activity in the market. As at December 31, 2014, the Company provided prudential support to the IESO on behalf of its subsidiaries using parental guarantees of $330 million (2013 – $325 million), and on behalf of two distributors using guarantees of $1 million (2013 – $1 million). In addition, as at December 31, 2014, the Company has provided letters of credit in the amount of $8 million (2013 – $21 million) to the IESO. The IESO could draw on these guarantees and/or letters of credit if these subsidiaries or distributors fail to make a payment required by a default notice issued by the IESO. The maximum potential payment is the face value of any letters of credit plus the amount of the parental guarantees.

Retirement Compensation Arrangements

Bank letters of credit have been issued to provide security for the Company’s liability under the terms of a trust fund established pursuant to the supplementary pension plan for eligible employees of Hydro One. The supplementary pension plan trustee is required to draw upon these letters of credit if Hydro One is in default of its obligations under the terms of this plan. Such obligations include the requirement to provide the trustee with an annual actuarial report as well as letters of credit sufficient to secure the Company’s liability under the plan, to pay benefits payable under the plan and to pay the letter of credit fee. The maximum potential payment is the face value of the letters of credit. At December 31, 2014, Hydro One had letters of credit of $126 million (2013 – $127 million) outstanding relating to retirement compensation arrangements.

Operating Leases

Hydro One is committed as lessee to irrevocable operating lease contracts for buildings used in administrative and service-related functions and storing telecommunications equipment. These leases have a typical term of between three and five years, but several leases have lesser or greater terms to address special circumstances and/or opportunities. Renewal options, which are generally prevalent in most leases, have similar terms of three to five years. All leases include a clause to enable upward revision of the rental charge on an annual basis or on renewal according to prevailing market conditions or pre-established rents. There are no restrictions placed upon Hydro One by entering into these leases. Hydro One Networks and Hydro One Telecom are the principal entities concerned.

During the year ended December 31, 2014, the Company made lease payments totalling $11 million (2013 – $11 million). At December 31, 2014, the future minimum lease payments under non-cancellable operating leases were as follows: 2015 – $7 million; 2016 – $10 million; 2017 – $9 million; 2018 – $7 million; 2019 – $3 million; and thereafter – $9 million.

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Segmented Reporting

12 Months Ended

Dec. 31, 2014

Segment Reporting [Abstract]

Segmented Reporting

24. SEGMENTED REPORTING

Hydro One has three reportable segments:

• The Transmission Business, which comprises the core business of providing electricity transportation and connection services, is responsible for transmitting electricity throughout the Ontario electricity grid;

• The Distribution Business, which comprises the core business of delivering and selling electricity to customers; and

• Other, which includes certain corporate activities and the operations of the telecommunications business.

The designation of segments has been based on a combination of regulatory status and the nature of the products and services provided. Operating segments of the Company are determined based on information used by the chief operating decision maker in deciding how to allocate resources and evaluate the performance of each of the segments. The Company evaluates segment performance based on income before financing charges and provision for PILs from continuing operations (excluding certain allocated corporate governance costs).

The accounting policies followed by the segments are the same as those described in the summary of significant accounting policies (see Note 2 – Significant Accounting Policies). Segment information on the above basis is as follows:

Year ended December 31, 2014 (millions of Canadian dollars)	Transmission		Distribution		Other			Consolidated
Revenues		1,588		4,903		57			6,548
Purchased power		—		3,419		—			3,419
Operation, maintenance and administration		394		742		56			1,192
Depreciation and amortization		346		367		9			722
Income (loss) before financing charges and provision for PILs		848		375		(8	)		1,215
Capital investments		845		680		5			1,530

Year ended December 31, 2013 (millions of Canadian dollars)	Transmission		Distribution		Other			Consolidated
Revenues		1,529		4,484		61			6,074
Purchased power		—		3,020		—			3,020
Operation, maintenance and administration		375		672		59			1,106
Depreciation and amortization		327		340		9			676
Income (loss) before financing charges and provision for PILs		827		452		(7	)		1,272
Capital investments		714		673		7			1,394

Total Assets by Segment:

December 31 (millions of Canadian dollars)	2014		2013
Transmission		12,540		11,846
Distribution		9,805		8,805
Other		205		974
Total assets		22,550		21,625

All revenues, costs and assets, as the case may be, are earned, incurred or held in Canada.

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Description of the Business

12 Months Ended

Dec. 31, 2014

Accounting Policies [Abstract]

Description of the Business

1. DESCRIPTION OF THE BUSINESS

Hydro One Inc. (Hydro One or the Company) was incorporated on December 1, 1998, under the Business Corporations Act (Ontario) and is wholly owned by the Province of Ontario (Province). The principal businesses of Hydro One are the transmission and distribution of electricity to customers within Ontario. The electricity rates of these businesses are regulated by the Ontario Energy Board (OEB).

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Subsequent Event

12 Months Ended

Dec. 31, 2014

Subsequent Events [Abstract]

Subsequent Event

25. SUBSEQUENT EVENT

On February 11, 2015, preferred share dividends in the amount of $4 million and common share dividends in the amount of $25 million were declared.

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Pension and Post-Retirement and Post-Employment Benefits - Schedule of Benefit Obligations and Plan Assets (Detail) (CAD)	Dec. 31, 2014	Dec. 31, 2013
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Accrued liabilities	611,000,000	654,000,000
Pension benefit liability	1,236,000,000	845,000,000
Pension Benefits [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Pension benefit liability	1,236,000,000	845,000,000
Unfunded status	1,236,000,000	845,000,000
Post-Retirement and Post-Employment Benefits [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Accrued liabilities	49,000,000	43,000,000
Post-retirement and post-employment benefit liability	1,533,000,000	1,488,000,000
Unfunded status	1,582,000,000	1,531,000,000

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Commitments - Additional Information (Detail) (CAD) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014 Distributor	Dec. 31, 2013
Commitments [Line Items]
Annual commitments for 2015	179
Annual commitments for 2016	146
Annual commitments for 2017	145
Annual commitments for 2018	113
Annual commitments for 2019	105
Annual commitments for thereafter	13
Number of distributor	2
Letters of credit provided	8	21
Letters of credit outstanding relating to retirement compensation arrangements	126	127
Lease payments	11	11
Future minimum lease payments for 2015	7
Future minimum lease payments for 2016	10
Future minimum lease payments for 2017	9
Future minimum lease payments for 2018	7
Future minimum lease payments for 2019	3
Future minimum lease payments, thereafter	9
Inergi LP [Member]
Commitments [Line Items]
Agreement expiry date	Feb. 28, 2015
Inergi LP [Member] | Second-Generation Customer Service Operations Outsourcing Services [Member]
Commitments [Line Items]
Agreement expiry date	Feb. 28, 2018
Agreement period	3 years
Agreement commencement date	Mar. 01, 2015
Inergi LP [Member] | Pay Services Pay Operations Services Information Technology and Finance and Accounting Services [Member]
Commitments [Line Items]
Agreement expiry date	Dec. 31, 2019
Agreement period	58 months
Agreement commencement date	Mar. 01, 2015
Brookfield Johnson Controls Canada LP [Member] | Facility Management Services [Member]
Commitments [Line Items]
Agreement expiry date	Dec. 31, 2024
Agreement period	10 years
Agreement commencement date	Jan. 01, 2015
Agreement renewal period	3 years
Estimated value of agreement	658
Annual management fee	2
Minimum [Member]
Commitments [Line Items]
Typical term of irrevocable operating lease	3 years
Operating lease renewal options	3 years
Maximum [Member]
Commitments [Line Items]
Typical term of irrevocable operating lease	5 years
Operating lease renewal options	5 years
Subsidiaries [Member]
Commitments [Line Items]
Parental guarantees	330	325
Distributor [Member]
Commitments [Line Items]
Parental guarantees	1	1

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Property, Plant and Equipment (Tables)

12 Months Ended

Dec. 31, 2014

Property, Plant and Equipment [Abstract]

Schedule of Property, Plant and Equipment

December 31, 2014 (millions of Canadian dollars)	Property, Plant and Equipment		Accumulated Depreciation		Construction in Progress		Total
Transmission		13,209		4,416		626		9,419
Distribution		9,076		3,225		320		6,171
Communication		1,100		615		56		541
Administration and Service		1,502		793		23		732
Easements		623		85		—		538
		25,510		9,134		1,025		17,401
December 31, 2013 (millions of Canadian dollars)	Property, Plant and Equipment		Accumulated Depreciation		Construction in Progress		Total
Transmission		12,413		4,215		671		8,869
Distribution		8,498		3,046		316		5,768
Communication		1,060		560		53		553
Administration and Service		1,380		716		38		702
Easements		617		78		—		539
		23,968		8,615		1,078		16,431

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Significant Accounting Policies - Average Service Lives and Depreciation and Amortization Rates (Detail)	12 Months Ended
	Dec. 31, 2014
Transmission [Member]
Property Plant And Equipment Estimated Useful Lifes [Line Items]
Average Service Life	57 years
Annual average rate of depreciation and amortization	2.00%
Distribution [Member]
Property Plant And Equipment Estimated Useful Lifes [Line Items]
Average Service Life	42 years
Annual average rate of depreciation and amortization	2.00%
Communication [Member]
Property Plant And Equipment Estimated Useful Lifes [Line Items]
Average Service Life	19 years
Annual average rate of depreciation and amortization	4.00%
Administration and Service [Member]
Property Plant And Equipment Estimated Useful Lifes [Line Items]
Average Service Life	15 years
Annual average rate of depreciation and amortization	7.00%
Minimum [Member] | Transmission [Member]
Property Plant And Equipment Estimated Useful Lifes [Line Items]
Annual rate of depreciation and amortization	1.00%
Minimum [Member] | Distribution [Member]
Property Plant And Equipment Estimated Useful Lifes [Line Items]
Annual rate of depreciation and amortization	1.00%
Minimum [Member] | Communication [Member]
Property Plant And Equipment Estimated Useful Lifes [Line Items]
Annual rate of depreciation and amortization	1.00%
Minimum [Member] | Administration and Service [Member]
Property Plant And Equipment Estimated Useful Lifes [Line Items]
Annual rate of depreciation and amortization	3.00%
Maximum [Member] | Transmission [Member]
Property Plant And Equipment Estimated Useful Lifes [Line Items]
Annual rate of depreciation and amortization	2.00%
Maximum [Member] | Distribution [Member]
Property Plant And Equipment Estimated Useful Lifes [Line Items]
Annual rate of depreciation and amortization	20.00%
Maximum [Member] | Communication [Member]
Property Plant And Equipment Estimated Useful Lifes [Line Items]
Annual rate of depreciation and amortization	15.00%
Maximum [Member] | Administration and Service [Member]
Property Plant And Equipment Estimated Useful Lifes [Line Items]
Annual rate of depreciation and amortization	20.00%

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Debt and Credit Agreements - Schedule of Outstanding Long-Term Debt (Parenthetical) (Detail) (CAD) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Debt Instrument [Line Items]
Unrealized mark-to-market gain (loss)	2	12
3.13% Series 19 Notes Due 2014 [Member]
Debt Instrument [Line Items]
Long-term debt, Interest rate	3.13%	3.13%
Long-term debt, Maturity year	2014	2014
Unrealized mark-to-market gain (loss)		500
2.95% Series 21 Notes Due 2015 [Member]
Debt Instrument [Line Items]
Long-term debt, Interest rate	2.95%	2.95%
Long-term debt, Maturity year	2015	2015
Unrealized mark-to-market gain (loss)	250	250
Floating-Rate Series 22 Notes Due 2015 [Member]
Debt Instrument [Line Items]
Long-term debt, Maturity year	2015	2015
4.64% Series 10 Notes Due 2016 [Member]
Debt Instrument [Line Items]
Long-term debt, Interest rate	4.64%	4.64%
Long-term debt, Maturity year	2016	2016
Floating-Rate Series 27 Notes Due 2016 [Member]
Debt Instrument [Line Items]
Long-term debt, Maturity year	2016	2016
5.18% Series 13 Notes Due 2017 [Member]
Debt Instrument [Line Items]
Long-term debt, Interest rate	5.18%	5.18%
Long-term debt, Maturity year	2017	2017
2.78% Series 28 Notes due 2018 [Member]
Debt Instrument [Line Items]
Long-term debt, Interest rate	2.78%	2.78%
Long-term debt, Maturity year	2018	2018
Floating-Rate Series 31 Notes Due 2019 [Member]
Debt Instrument [Line Items]
Long-term debt, Maturity year	2019	2019
4.40% Series 20 Notes Due 2020 [Member]
Debt Instrument [Line Items]
Long-term debt, Interest rate	4.40%	4.40%
Long-term debt, Maturity year	2020	2020
3.20% Series 25 Notes Due 2022 [Member]
Debt Instrument [Line Items]
Long-term debt, Interest rate	3.20%	3.20%
Long-term debt, Maturity year	2022	2022
7.35% Debentures Due 2030 [Member]
Debt Instrument [Line Items]
Long-term debt, Interest rate	7.35%	7.35%
Long-term debt, Maturity year	2030	2030
6.93% Series 2 Notes Due 2032 [Member]
Debt Instrument [Line Items]
Long-term debt, Interest rate	6.93%	6.93%
Long-term debt, Maturity year	2032	2032
6.35% Series 4 Notes Due 2034 [Member]
Debt Instrument [Line Items]
Long-term debt, Interest rate	6.35%	6.35%
Long-term debt, Maturity year	2034	2034
5.36% Series 9 Notes Due 2036 [Member]
Debt Instrument [Line Items]
Long-term debt, Interest rate	5.36%	5.36%
Long-term debt, Maturity year	2036	2036
4.89% Series 12 Notes Due 2037 [Member]
Debt Instrument [Line Items]
Long-term debt, Interest rate	4.89%	4.89%
Long-term debt, Maturity year	2037	2037
6.03% Series 17 Notes Due 2039 [Member]
Debt Instrument [Line Items]
Long-term debt, Interest rate	6.03%	6.03%
Long-term debt, Maturity year	2039	2039
5.49% Series 18 Notes Due 2040 [Member]
Debt Instrument [Line Items]
Long-term debt, Interest rate	5.49%	5.49%
Long-term debt, Maturity year	2040	2040
4.39% Series 23 Notes Due 2041 [Member]
Debt Instrument [Line Items]
Long-term debt, Interest rate	4.39%	4.39%
Long-term debt, Maturity year	2041	2041
6.59% Series 5 Notes Due 2043 [Member]
Debt Instrument [Line Items]
Long-term debt, Interest rate	6.59%	6.59%
Long-term debt, Maturity year	2043	2043
4.59% Series 29 Notes Due 2043 [Member]
Debt Instrument [Line Items]
Long-term debt, Interest rate	4.59%	4.59%
Long-term debt, Maturity year	2043	2043
4.17% Series 32 Notes Due 2044 [Member]
Debt Instrument [Line Items]
Long-term debt, Interest rate	4.17%	4.17%
Long-term debt, Maturity year	2044	2044
5.00% Series 11 Notes Due 2046 [Member]
Debt Instrument [Line Items]
Long-term debt, Interest rate	5.00%	5.00%
Long-term debt, Maturity year	2046	2046
4.00% Series 24 Notes Due 2051 [Member]
Debt Instrument [Line Items]
Long-term debt, Interest rate	4.00%	4.00%
Long-term debt, Maturity year	2051	2051
3.79% Series 26 Notes Due 2062 [Member]
Debt Instrument [Line Items]
Long-term debt, Interest rate	3.79%	3.79%
Long-term debt, Maturity year	2062	2062
4.29% Series 30 Notes Due 2064 [Member]
Debt Instrument [Line Items]
Long-term debt, Interest rate	4.29%	4.29%
Long-term debt, Maturity year	2064	2064
Interest-Rate Swaps [Member]
Debt Instrument [Line Items]
Unrealized mark-to-market gain (loss)	2	12

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Consolidated Statements of Operations and Comprehensive Income (CAD) In Millions, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Revenues
Distribution (includes $159 related party revenues; 2013 - $160) (Note 20)	4,903	4,484
Transmission (includes $1,567 related party revenues; 2013 - $1,517) (Note 20)	1,588	1,529
Other	57	61
Total revenues	6,548	6,074
Costs
Purchased power (includes $2,633 related party costs; 2013 - $2,500) (Note 20)	3,419	3,020
Operation, maintenance and administration (Note 20)	1,192	1,106
Depreciation and amortization (Note 5)	722	676
Total costs	5,333	4,802
Income before financing charges and provision for payments in lieu of corporate income taxes	1,215	1,272
Financing charges (Note 6)	379	360
Income before provision for payments in lieu of corporate income taxes	836	912
Provision for payments in lieu of corporate income taxes (Notes 7, 20)	89	109
Net income	747	803
Net income (loss) attributable to noncontrolling interest (Note 4)	(2)
Net income attributable to the Shareholder of Hydro One Inc.	749	803
Other comprehensive income	0	0
Comprehensive income	747	803
Comprehensive income (loss) attributable to noncontrolling interest (Note 4)	(2)
Comprehensive income attributable to the Shareholder of Hydro One Inc.	749	803
Basic and fully diluted earnings per common share (dollars) (Note 18)	7,319	7,850
Dividends per common share declared (dollars) (Note 19)	2,696	2,000

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Capital Management (Tables)

12 Months Ended

Dec. 31, 2014

Text Block [Abstract]

Summary of Company's Capital Structure

At December 31, 2014 and 2013, the Company’s capital structure was as follows:

December 31 (millions of Canadian dollars)	2014		2013
Long-term debt payable within one year		552		756
Less: cash and cash equivalents		100		565
		452		191
Long-term debt		8,373		8,301
Preferred shares		323		323
Common shares		3,314		3,314
Retained earnings		4,249		3,787
		7,563		7,101
Total capital		16,711		15,916

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Pension and Post-Retirement and Post-Employment Benefits - Components of Regulatory Assets That Have Not Been Recognized as Components of Net Periodic Benefit Costs (Detail) (CAD) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Pension Benefits [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Actuarial loss	(821)	63
Net periodic benefit costs	121	105
Post-Retirement and Post-Employment Benefits [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Actuarial loss	18	(13)
Net periodic benefit costs	10	17
Not Recognized as Combined Net Period Benefit Cost [Member] | Pension Benefits [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Prior service cost	2	3
Actuarial loss	1,234	842
Net periodic benefit costs	1,236	845
Not Recognized as Combined Net Period Benefit Cost [Member] | Post-Retirement and Post-Employment Benefits [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Prior service cost		2
Actuarial loss	273	306
Net periodic benefit costs	273	308

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Contingencies - Additional Information (Detail) (CAD) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Commitments and Contingencies Disclosure [Abstract]
Payments made	1	2

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Consolidated Statements of Changes in Equity (CAD) In Millions	Total	Common Shares [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Loss [Member]	Noncontrolling Interest [Member]
Beginning balance at Dec. 31, 2012	6,507	3,314	3,202	(9)
Net income	803		803
Other comprehensive income	0	0	0	0	0
Dividends on preferred shares	(18)		(18)
Dividends on common shares	(200)		(200)
Ending balance at Dec. 31, 2013	7,092	3,314	3,787	(9)
Net income	748		749		(1)
Other comprehensive income	0	0	0	0	0
Amount contributed by noncontrolling interest	50				50
Dividends on preferred shares	(18)		(18)
Dividends on common shares	(269)		(269)
Ending balance at Dec. 31, 2014	7,603	3,314	4,249	(9)	(49)

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Pension and Post-Retirement and Post-Employment Benefits - Schedule of Estimated Future Benefit Payments (Detail) (CAD) In Millions, unless otherwise specified	Dec. 31, 2014
Pension Benefits [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
2015	305
2016	316
2017	328
2018	339
2019	350
2020 through to 2024	1,889
Total estimated future benefit payments through to 2024	3,527
Post-Retirement and Post-Employment Benefits [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
2015	50
2016	52
2017	54
2018	56
2019	59
2020 through to 2024	332
Total estimated future benefit payments through to 2024	603

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Provision for Payments in Lieu of Corporate Income Taxes - Major Components of Income Tax Expense (Detail) (CAD) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Components Of Income Tax Expense Benefit [Line Items]
Deferred provision (recovery) for PILs	10	(2)
Total provision for PILs	89	109
PILs [Member]
Components Of Income Tax Expense Benefit [Line Items]
Current provision for PILs	79	111
Deferred provision (recovery) for PILs	10	(2)
Total provision for PILs	89	109
Effective income tax rate	10.63%	11.98%

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Pension and Post-Retirement and Post-Employment Benefits - Pension Plan Assets Measured and Recorded at Fair Value on Recurring Basis (Detail) (CAD) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Schedule Of Weighted Average Assumption Determining Pension Plan And Other Post retirement Benefit Plan [Line Items]
Total fair value of plan assets	6,288	5,719
Pooled Funds [Member]
Schedule Of Weighted Average Assumption Determining Pension Plan And Other Post retirement Benefit Plan [Line Items]
Total fair value of plan assets	160	134
Cash and Cash Equivalents [Member]
Schedule Of Weighted Average Assumption Determining Pension Plan And Other Post retirement Benefit Plan [Line Items]
Total fair value of plan assets	166	150
Short-term Securities [Member]
Schedule Of Weighted Average Assumption Determining Pension Plan And Other Post retirement Benefit Plan [Line Items]
Total fair value of plan assets	176	180
Real Estate [Member]
Schedule Of Weighted Average Assumption Determining Pension Plan And Other Post retirement Benefit Plan [Line Items]
Total fair value of plan assets	2	2
Corporate Shares - Canadian [Member]
Schedule Of Weighted Average Assumption Determining Pension Plan And Other Post retirement Benefit Plan [Line Items]
Total fair value of plan assets	1,008	943
Corporate Shares - Foreign [Member]
Schedule Of Weighted Average Assumption Determining Pension Plan And Other Post retirement Benefit Plan [Line Items]
Total fair value of plan assets	2,766	2,708
Bonds and Debentures - Canadian [Member]
Schedule Of Weighted Average Assumption Determining Pension Plan And Other Post retirement Benefit Plan [Line Items]
Total fair value of plan assets	1,799	1,416
Bonds and debentures - Foreign [Member]
Schedule Of Weighted Average Assumption Determining Pension Plan And Other Post retirement Benefit Plan [Line Items]
Total fair value of plan assets	211	186
Level 1 [Member]
Schedule Of Weighted Average Assumption Determining Pension Plan And Other Post retirement Benefit Plan [Line Items]
Total fair value of plan assets	3,940	3,802
Level 1 [Member] | Pooled Funds [Member]
Schedule Of Weighted Average Assumption Determining Pension Plan And Other Post retirement Benefit Plan [Line Items]
Total fair value of plan assets		1
Level 1 [Member] | Cash and Cash Equivalents [Member]
Schedule Of Weighted Average Assumption Determining Pension Plan And Other Post retirement Benefit Plan [Line Items]
Total fair value of plan assets	166	150
Level 1 [Member] | Corporate Shares - Canadian [Member]
Schedule Of Weighted Average Assumption Determining Pension Plan And Other Post retirement Benefit Plan [Line Items]
Total fair value of plan assets	1,008	943
Level 1 [Member] | Corporate Shares - Foreign [Member]
Schedule Of Weighted Average Assumption Determining Pension Plan And Other Post retirement Benefit Plan [Line Items]
Total fair value of plan assets	2,766	2,708
Level 2 [Member]
Schedule Of Weighted Average Assumption Determining Pension Plan And Other Post retirement Benefit Plan [Line Items]
Total fair value of plan assets	2,204	1,798
Level 2 [Member] | Pooled Funds [Member]
Schedule Of Weighted Average Assumption Determining Pension Plan And Other Post retirement Benefit Plan [Line Items]
Total fair value of plan assets	18	16
Level 2 [Member] | Short-term Securities [Member]
Schedule Of Weighted Average Assumption Determining Pension Plan And Other Post retirement Benefit Plan [Line Items]
Total fair value of plan assets	176	180
Level 2 [Member] | Bonds and Debentures - Canadian [Member]
Schedule Of Weighted Average Assumption Determining Pension Plan And Other Post retirement Benefit Plan [Line Items]
Total fair value of plan assets	1,799	1,416
Level 2 [Member] | Bonds and debentures - Foreign [Member]
Schedule Of Weighted Average Assumption Determining Pension Plan And Other Post retirement Benefit Plan [Line Items]
Total fair value of plan assets	211	186
Level 3 [Member]
Schedule Of Weighted Average Assumption Determining Pension Plan And Other Post retirement Benefit Plan [Line Items]
Total fair value of plan assets	144	119
Level 3 [Member] | Pooled Funds [Member]
Schedule Of Weighted Average Assumption Determining Pension Plan And Other Post retirement Benefit Plan [Line Items]
Total fair value of plan assets	142	117
Level 3 [Member] | Real Estate [Member]
Schedule Of Weighted Average Assumption Determining Pension Plan And Other Post retirement Benefit Plan [Line Items]
Total fair value of plan assets	2	2

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Business Combinations (Tables) (Norfolk Power [Member])

12 Months Ended

Dec. 31, 2014

Norfolk Power [Member]

Summary of Preliminary Determination of Fair Value of Assets Acquired and Liabilities Assumed

The following table summarizes the preliminary determination of the fair value of the assets acquired and liabilities assumed:

(millions of Canadian dollars)
Working capital	6
Property, plant and equipment	56
Deferred income tax assets	1
Goodwill	40
Bank indebtedness	(3	)
Derivative instruments	(3	)
Long-term debt	(26	)
Post-retirement and post-employment benefit liability	(1	)
Environmental liability	(1	)
Long-term accounts payable and other liabilities	(1	)
	68

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Property, Plant and Equipment - Additional Information (Detail) (CAD) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Property Plant and Equipment Useful Life and Values [Abstract]
Financing charges capitalized on property, plant and equipment	48	48

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Pension and Post-Retirement and Post-Employment Benefits

12 Months Ended

Dec. 31, 2014

Text Block [Abstract]

Pension and Post-Retirement and Post-Employment Benefits

15. PENSION AND POST-RETIREMENT AND POST-EMPLOYMENT BENEFITS

Hydro One has a defined benefit pension plan, a supplementary pension plan, and post-retirement and post-employment benefit plans. The defined benefit pension plan (Pension Plan) is contributory and covers all regular employees of Hydro One and its subsidiaries, except employees of Hydro One Brampton Networks and Norfolk Power. Employees of Hydro One Brampton Networks and Norfolk Power participate in the OMERS plan. The supplementary pension plan provides members of the Pension Plan with benefits that would have been earned and payable under the Pension Plan but for the limitations imposed by the Income Tax Act (Canada). The supplementary pension plan obligation is included with other post-retirement and post-employment benefit obligations on the Consolidated Balance Sheets.

The OMERS Plan

Hydro One contributions to the OMERS plan for the year ended December 31, 2014 were $2 million (2013 – $2 million). Company contributions payable at December 31, 2014 and included in accrued liabilities on the Consolidated Balance Sheets were less than $1 million (2013 – less than $1 million). Hydro One contributions do not represent more than 5% of total contributions to the OMERS plan, as indicated in OMERS’ most recently available annual report for the year ended December 31, 2013.

At December 31, 2013, the OMERS plan was 88.2% funded, with an unfunded liability of $8,641 million. This unfunded liability could result in future payments by participating employers and members. Hydro One future contributions could be increased substantially if other entities withdraw from the plan.

Pension Plan, Post-Retirement and Post-Employment Plans

The Pension Plan provides benefits based on highest three-year average pensionable earnings. For new management employees who commenced employment on or after January 1, 2004, and for new Society of Energy Professionals-represented staff hired after November 17, 2005, benefits are based on highest five-year average pensionable earnings. After retirement, pensions are indexed to inflation.

Company and employee contributions to the Pension Plan are based on actuarial valuations performed at least every three years. Annual Pension Plan contributions for 2014 of $174 million (2013 – $160 million) were based on an actuarial valuation effective December 31, 2013 (2013 – effective December 31, 2011) and the expected level of pensionable earnings. Estimated annual Pension Plan contributions for 2015 and 2016 are approximately $174 million and $175 million, respectively, based on the actuarial valuation as at December 31, 2013 and projected levels of pensionable earnings. Future minimum contributions beyond 2016 will be based on an actuarial valuation effective no later than December 31, 2016. Contributions are payable one month in arrears. All of the contributions are expected to be in the form of cash.

Hydro One recognizes the overfunded or underfunded status of the Pension Plan, and post-retirement and post-employment benefit plans (Plans) as an asset or liability on its Consolidated Balance Sheets, with offsetting regulatory assets and liabilities as appropriate. The underfunded benefit obligations for the Plans, in the absence of regulatory accounting, would be recognized in AOCI. The impact of changes in assumptions used to measure pension, post-retirement and post-employment benefit obligations is generally recognized over the expected average remaining service period of the employees. The measurement date for the Plans is December 31.

	Pension Benefits						Post-Retirement and Post-Employment Benefits
Year ended December 31 (millions of Canadian dollars)	2014			2013			2014			2013
Change in projected benefit obligation
Projected benefit obligation, beginning of year		6,576			6,507			1,531			1,459
Current service cost		145			170			41			40
Interest cost		312			278			73			63
Reciprocal transfers		—			1			—			—
Benefits paid		(319	)		(317	)		(45	)		(44	)
Net actuarial loss (gain)		821			(63	)		(18	)		13
Projected benefit obligation, end of year		7,535			6,576			1,582			1,531
Change in plan assets
Fair value of plan assets, beginning of year		5,731			4,992			—			—
Actual return on plan assets		703			887			—			—
Reciprocal transfers		—			1			—			—
Benefits paid		(319	)		(317	)		—			—
Employer contributions		174			160			—			—
Employee contributions		35			30			—			—
Administrative expenses		(25	)		(22	)		—			—
Fair value of plan assets, end of year		6,299			5,731			—			—
Unfunded status		1,236			845			1,582			1,531

Hydro One presents its benefit obligations and plan assets net on its Consolidated Balance Sheets within the following line items:

	Pension Benefits				Post-Retirement and Post-Employment Benefits
December 31 (millions of Canadian dollars)	2014		2013		2014		2013
Accrued liabilities		—		—		49		43
Pension benefit liability		1,236		845		—		—
Post-retirement and post-employment benefit liability		—		—		1,533		1,488
Unfunded status		1,236		845		1,582		1,531

The funded or unfunded status of the pension, post-retirement and post-employment benefit plans refers to the difference between the fair value of plan assets and the projected benefit obligations for the Plans. The funded/unfunded status changes over time due to several factors, including contribution levels, assumed discount rates and actual returns on plan assets.

The following table provides the projected benefit obligation (PBO), accumulated benefit obligation (ABO) and fair value of plan assets for the Pension Plan:

December 31 (millions of Canadian dollars)	2014		2013
PBO		7,535		6,576
ABO		6,887		5,998
Fair value of plan assets		6,299		5,731

On an ABO basis, the Pension Plan was funded at 91% at December 31, 2014 (2013 – 96%). On a PBO basis, the Pension Plan was funded at 84% at December 31, 2014 (2013 – 87%). The ABO differs from the PBO in that the ABO includes no assumption about future compensation levels.

Components of Net Periodic Benefit Costs

The following table provides the components of the net periodic benefit costs for the years ended December 31, 2014 and 2013 for the Pension Plan:

Year ended December 31 (millions of Canadian dollars)	2014			2013
Current service cost, net of employee contributions		110			141
Interest cost		312			278
Expected return on plan assets, net of expenses		(369	)		(309	)
Actuarial loss amortization		103			175
Prior service cost amortization		2			2
Net periodic benefit costs		158			287
Charged to results of operations1		81			72

¹ The Company follows the cash basis of accounting consistent with the inclusion of pension costs in OEB-approved rates. During the year ended December 31, 2014, pension costs of $174 million (2013 – $160 million) were attributed to labour, of which $81 million (2013 – $72 million) was charged to operations, and $93 million (2013 – $88 million) was capitalized as part of the cost of property, plant and equipment and intangible assets.

The following table provides the components of the net periodic benefit costs for the years ended December 31, 2014 and 2013 for the post-retirement and post-employment benefit plans:

Year ended December 31 (millions of Canadian dollars)	2014		2013
Current service cost, net of employee contributions		41		40
Interest cost		73		63
Actuarial loss amortization		18		27
Prior service cost amortization		2		3
Net periodic benefit costs		134		133
Charged to results of operations		62		58

Assumptions

The measurement of the obligations of the Plans and the costs of providing benefits under the Plans involves various factors, including the development of valuation assumptions and accounting policy elections. When developing the required assumptions, the Company considers historical information as well as future expectations. The measurement of benefit obligations and costs is impacted by several assumptions including the discount rate applied to benefit obligations, the long-term expected rate of return on plan assets, Hydro One’s expected level of contributions to the Plans, the incidence of mortality, the expected remaining service period of plan participants, the level of compensation and rate of compensation increases, employee age, length of service, and the anticipated rate of increase of health care costs, among other factors. The impact of changes in assumptions used to measure the obligations of the Plans is generally recognized over the expected average remaining service period of the plan participants. In selecting the expected rate of return on plan assets, Hydro One considers historical economic indicators that impact asset returns, as well as expectations regarding future long-term capital market performance, weighted by target asset class allocations. In general, equity securities, real estate and private equity investments are forecasted to have higher returns than fixed-income securities.

The following weighted average assumptions were used to determine the benefit obligations at December 31, 2014 and 2013:

	Pension Benefits						Post-Retirement and Post-Employment Benefits
Year ended December 31	2014			2013			2014			2013
Significant assumptions:
Weighted average discount rate		4.00	%		4.75	%		4.00	%		4.75	%
Rate of compensation scale escalation (without merit)		2.50	%		2.50	%		2.50	%		2.50	%
Rate of cost of living increase		2.00	%		2.00	%		2.00	%		2.00	%
Rate of increase in health care cost trends1		—			—			4.36	%		4.39	%

¹ 6.52% per annum in 2015, grading down to 4.36% per annum in and after 2031 (2013 – 6.81% in 2014, grading down to 4.39% per annum in and after 2031)

The following weighted average assumptions were used to determine the net periodic benefit costs for the years ended December 31, 2014 and 2013. Assumptions used to determine current year-end benefit obligations are the assumptions used to estimate the subsequent year’s net periodic benefit costs.

Year ended December 31	2014			2013
Pension Benefits:
Weighted average expected rate of return on plan assets		6.50	%		6.25	%
Weighted average discount rate		4.75	%		4.25	%
Rate of compensation scale escalation (without merit)		2.50	%		2.50	%
Rate of cost of living increase		2.00	%		2.00	%
Average remaining service life of employees (years)		11			11
Post-Retirement and Post-Employment Benefits:
Weighted average discount rate		4.75	%		4.25	%
Rate of compensation scale escalation (without merit)		2.50	%		2.50	%
Rate of cost of living increase		2.00	%		2.00	%
Average remaining service life of employees (years)		12			12
Rate of increase in health care cost trends1		4.39	%		4.39	%

¹  6.81% per annum in 2014, grading down to 4.39% per annum in and after 2031 (2013 – 6.91% in 2013, grading down to 4.39% per annum in and after 2031)

The discount rate used to determine the current year pension obligation and the subsequent year’s net periodic benefit costs is based on a yield curve approach. Under the yield curve approach, expected future benefit payments for each plan are discounted by a rate on a third party bond yield curve corresponding to each duration. The yield curve is based on “AA” long-term corporate bonds. A single discount rate is calculated that would yield the same present value as the sum of the discounted cash flows.

The effect of a 1% change in health care cost trends on the projected benefit obligation for the post-retirement and post-employment benefits at December 31, 2014 and 2013 is as follows:

December 31 (millions of Canadian dollars)	2014			2013
Projected benefit obligation:
Effect of a 1% increase in health care cost trends		248			258
Effect of a 1% decrease in health care cost trends		(193	)		(200	)

The effect of a 1% change in health care cost trends on the service cost and interest cost for the post-retirement and post-employment benefits for the years ended December 31, 2014 and 2013 is as follows:

Year ended December 31 (millions of Canadian dollars)	2014			2013
Service cost and interest cost:
Effect of a 1% increase in health care cost trends		23			21
Effect of a 1% decrease in health care cost trends		(17	)		(16	)

The following approximate life expectancies were used in the mortality assumptions to determine the projected benefit obligations for the pension and post-retirement and post-employment plans at December 31, 2014 and 2013:

December 31, 2014				December 31, 2013
Life expectancy at 65 for a member currently at				Life expectancy at 65 for a member currently at
Age 65		Age 45		Age 65		Age 45
Male	Female	Male	Female	Male	Female	Male	Female
23	25	24	26	23	25	24	26

Estimated Future Benefit Payments

At December 31, 2014, estimated future benefit payments to the participants of the Plans were:

(millions of Canadian dollars)	Pension Benefits		Post-Retirement and Post-Employment Benefits
2015		305		50
2016		316		52
2017		328		54
2018		339		56
2019		350		59
2020 through to 2024		1,889		332
Total estimated future benefit payments through to 2024		3,527		603

Components of Regulatory Assets

A portion of actuarial gains and losses and prior service costs is recorded within regulatory assets on Hydro One’s Consolidated Balance Sheets to reflect the expected regulatory inclusion of these amounts in future rates, which would otherwise be recorded in OCI. The following table provides the actuarial gains and losses and prior service costs recorded within regulatory assets:

Year ended December 31 (millions of Canadian dollars)	2014			2013
Pension Benefits:
Actuarial loss (gain) for the year		511			(619	)
Actuarial loss amortization		(103	)		(175	)
Prior service cost amortization		(2	)		(2	)
		406			(796	)
Post-Retirement and Post-Employment Benefits:
Actuarial loss (gain) for the year		(18	)		13
Actuarial loss amortization		(18	)		(27	)
Prior service cost amortization		(2	)		(3	)
		(38	)		(17	)

The following table provides the components of regulatory assets that have not been recognized as components of net periodic benefit costs for the years ended December 31, 2014 and 2013:

Year ended December 31 (millions of Canadian dollars)	2014		2013
Pension Benefits:
Prior service cost		2		3
Actuarial loss		1,234		842
		1,236		845
Post-Retirement and Post-Employment Benefits:
Prior service cost		—		2
Actuarial loss		273		306
		273		308

The following table provides the components of regulatory assets at December 31 that are expected to be amortized as components of net periodic benefit costs in the following year:

	Pension Benefits				Post-Retirement and Post-Employment Benefits
December 31 (millions of Canadian dollars)	2014		2013		2014		2013
Prior service cost		2		2		—		2
Actuarial loss		119		103		10		15
		121		105		10		17

Pension Plan Assets

Investment Strategy

On a regular basis, Hydro One evaluates its investment strategy to ensure that Pension Plan assets will be sufficient to pay Pension Plan benefits when due. As part of this ongoing evaluation, Hydro One may make changes to its targeted asset allocation and investment strategy. The Pension Plan is managed at a net asset level. The main objective of the Pension Plan is to sustain a certain level of net assets in order to meet the pension obligations of the Company. The Pension Plan fulfills its primary objective by adhering to specific investment policies outlined in its Summary of Investment Policies and Procedures (SIPP), which is reviewed and approved by the Audit, Finance and Pension Investment Committee of Hydro One’s Board of Directors. The Company manages net assets by engaging knowledgeable external investment managers who are charged with the responsibility of investing existing funds and new funds (current year’s employee and employer contributions) in accordance with the approved SIPP. The performance of the managers is monitored through a governance structure. Increases in net assets are a direct result of investment income generated by investments held by the Pension Plan and contributions to the Pension Plan by eligible employees and by the Company. The main use of net assets is for benefit payments to eligible Pension Plan members.

Pension Plan Asset Mix

At December 31, 2014, the Pension Plan target asset allocations and weighted average asset allocations were as follows:

	Target Allocation (%)		Pension Plan Assets (%)
Equity securities		60.0		60.9
Debt securities		35.0		35.9
Other1		5.0		3.2
		100.0		100.0

¹  Other investments include real estate and infrastructure investments.

At December 31, 2014, the Pension Plan held no Hydro One corporate bonds (2013 – $15 million) and $340 million of debt securities of the Province (2013 – $217 million).

Concentrations of Credit Risk

Hydro One evaluated its Pension Plan’s asset portfolio for the existence of significant concentrations of credit risk as at December 31, 2014 and 2013. Concentrations that were evaluated include, but are not limited to, investment concentrations in a single entity, concentrations in a type of industry, and concentrations in individual funds. At December 31, 2014 and 2013, there were no significant concentrations (defined as greater than 10% of plan assets) of risk in the Pension Plan’s assets.

The Pension Plan manages its counterparty credit risk with respect to bonds by investing in investment-grade and government bonds and with respect to derivative instruments by transacting only with financial institutions rated at least “A+” by Standard and Poor’s Rating Services Inc., DBRS Limited, and Fitch Ratings Inc., and “A1” by Moody’s Investors Service Inc., and also by utilizing exposure limits to each counterparty and ensuring that exposure is diversified across counterparties. The risk of default on transactions in listed securities is considered minimal, as the trade will fail if either party to the transaction does not meet its obligation.

Fair Value Measurements

The following tables present the Pension Plan assets measured and recorded at fair value on a recurring basis and their level within the fair value hierarchy at December 31, 2014 and 2013:

December 31, 2014 (millions of Canadian dollars)	Level 1		Level 2		Level 3		Total
Pooled funds		—		18		142		160
Cash and cash equivalents		166		—		—		166
Short-term securities		—		176		—		176
Real estate		—		—		2		2
Corporate shares – Canadian		1,008		—		—		1,008
Corporate shares – Foreign		2,766		—		—		2,766
Bonds and debentures – Canadian		—		1,799		—		1,799
Bonds and debentures – Foreign		—		211		—		211
Total fair value of plan assets1		3,940		2,204		144		6,288

¹  At December 31, 2014, the total fair value of Pension Plan assets excludes $18 million of interest and dividends receivable, and $7 million relating to accruals for pension administration expense.

December 31, 2013 (millions of Canadian dollars)	Level 1		Level 2		Level 3		Total
Pooled funds		1		16		117		134
Cash and cash equivalents		150		—		—		150
Short-term securities		—		180		—		180
Real estate		—		—		2		2
Corporate shares – Canadian		943		—		—		943
Corporate shares – Foreign		2,708		—		—		2,708
Bonds and debentures – Canadian		—		1,416		—		1,416
Bonds and debentures – Foreign		—		186		—		186
Total fair value of plan assets1		3,802		1,798		119		5,719

¹  At December 31, 2013, the total fair value of Pension Plan assets excludes $19 million of interest and dividends receivable, and $7 million relating to accruals for pension administration expense.

See Note 13 – Fair Value of Financial Instruments and Risk Management for a description of levels within the fair value hierarchy.

Changes in the Fair Value of Financial Instruments Classified in Level 3

The following table summarizes the changes in fair value of financial instruments classified in Level 3 for the years ended December 31, 2014 and 2013. The Pension Plan classifies financial instruments as Level 3 when the fair value is measured based on at least one significant input that is not observable in the markets or due to lack of liquidity in certain markets. The gains and losses presented in the table below may include changes in fair value based on both observable and unobservable inputs.

Year ended December 31 (millions of Canadian dollars)	2014			2013
Fair value, beginning of year		119			106
Realized and unrealized gains		30			23
Purchases		23			—
Sales and disbursements		(28	)		(10	)
Fair value, end of year		144			119

There were no significant transfers between any of the fair value levels during the years ended December 31, 2014 and 2013.

The Company performs sensitivity analysis for fair value measurements classified in Level 3, substituting the unobservable inputs with one or more reasonably possible alternative assumptions. These sensitivity analyses resulted in negligible changes in the fair value of financial instruments classified in this level.

Valuation Techniques Used to Determine Fair Value

Pooled Funds

The pooled fund category mainly consists of private equity and infrastructure investments. Private equity investments represent private equity funds that invest in operating companies that are not publicly traded on a stock exchange. Investment strategies in private equity include limited partnerships in businesses that are characterized by high internal growth and operational efficiencies, venture capital, leveraged buyouts and special situations such as distressed investments. Infrastructure investments represent infrastructure funds that invest in real assets which are not publicly traded on a stock exchange. Investment strategies in infrastructure include limited partnerships in core infrastructure assets focusing on assets that generate stable, long-term cash flows and deliver incremental returns relative to conventional fixed-income investments. Private equity and infrastructure valuations are reported by the fund manager and are based on the valuation of the underlying investments which includes inputs such as cost, operating results, discounted future cash flows and market-based comparable data. Since these valuation inputs are not highly observable, private equity and infrastructure investments have been categorized as Level 3 within pooled funds.

Cash Equivalents

Demand cash deposits held with banks and cash held by the investment managers are considered cash equivalents and are included in the fair value measurements hierarchy as Level 1.

Short-Term Securities

Short-term securities are valued at cost plus accrued interest, which approximates fair value due to their short-term nature. Short-term securities have been categorized as Level 2.

Real Estate

Real estate investments represent private equity investments in holding companies that invest in real estate properties. The investments in the holding companies are valued using net asset values reported by the fund manager. Real estate investments are categorized as Level 3.

Corporate Shares

Corporate shares are valued based on quoted prices in active markets and are categorized as Level 1. Investments denominated in foreign currencies are translated into Canadian currency at year-end rates of exchange.

Bonds and Debentures

Bonds and debentures are presented at published closing trade quotations, and are categorized as Level 2.

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Depreciation and Amortization (Tables)

12 Months Ended

Dec. 31, 2014

Text Block [Abstract]

Schedule of Depreciation and Amortization

Year ended December 31 (millions of Canadian dollars)	2014		2013
Depreciation of property, plant and equipment		565		533
Amortization of intangible assets		53		48
Asset removal costs		81		79
Amortization of regulatory assets		23		16
		722		676

XML

Pension and Post-Retirement and Post-Employment Benefits - Schedule of Pension Plan Target Asset and Weighted Average Asset Allocations (Detail)	Dec. 31, 2014
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Target Allocation	100.00%
Pension Plan Assets	100.00%
Equity Securities [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Target Allocation	60.00%
Pension Plan Assets	60.90%
Debt Securities [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Target Allocation	35.00%
Pension Plan Assets	35.90%
Other [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Target Allocation	5.00%
Pension Plan Assets	3.20%

XML

Asset Retirement Obligations

12 Months Ended

Dec. 31, 2014

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

17. ASSET RETIREMENT OBLIGATIONS

Hydro One records a liability for the estimated future expenditures for the removal and disposal of asbestos-containing materials installed in some of its facilities and for the decommissioning of specific switching stations located on unowned sites. AROs, which represent legal obligations associated with the retirement of certain tangible long-lived assets, are computed as the present value of the projected expenditures for the future retirement of specific assets and are recognized in the period in which the liability is incurred, if a reasonable estimate of fair value can be made. If the asset remains in service at the recognition date, the present value of the liability is added to the carrying amount of the associated asset in the period the liability is incurred and this additional carrying amount is depreciated over the remaining life of the asset. If an ARO is recorded in respect of an out-of-service asset, the asset retirement cost is charged to results of operations. Subsequent to the initial recognition, the liability is adjusted for any revisions to the estimated future cash flows associated with the ARO, which can occur due to a number of factors including, but not limited to, cost escalation, changes in technology applicable to the assets to be retired, changes in legislation or regulations, as well as for accretion of the liability due to the passage of time until the obligation is settled. Depreciation expense is adjusted prospectively for any increases or decreases to the carrying amount of the associated asset.

In determining the amounts to be recorded as AROs, the Company estimates the current fair value for completing required work and makes assumptions as to when the future expenditures will actually be incurred, in order to generate future cash flow information. A long-term inflation assumption of approximately 2% has been used to express these current cost estimates as estimated future expenditures. Future expenditures have been discounted using factors ranging from approximately 3.0% to 5.0%, depending on the appropriate rate for the period when expenditures are expected to be incurred. All factors used in estimating the Company’s AROs represent management’s best estimates of the cost required to meet existing legislation or regulations. However, it is reasonably possible that numbers or volumes of contaminated assets, cost estimates to perform work, inflation assumptions and the assumed pattern of annual cash flows may differ significantly from the Company’s current assumptions. AROs are reviewed annually or more frequently if significant changes in regulations or other relevant factors occur. Estimate changes are accounted for prospectively.

At December 31, 2014, Hydro One had recorded AROs of $9 million (2013 – $14 million), consisting of $8 million (2013 – $7 million) related to the estimated future expenditures associated with the removal and disposal of asbestos-containing materials installed in some of its facilities, as well as $1 million (2013 – $7 million) related to the future decommissioning and removal of two switching stations. The amount of interest recorded is nominal.

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Regulatory Assets and Liabilities - Schedule of Regulatory Assets and Liabilities (Detail) (CAD) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Regulatory assets:
Total regulatory assets	3,231	2,683
Less: current portion	31	47
Regulatory assets	3,200	2,636
Regulatory liabilities:
Total regulatory liabilities	215	248
Less: current portion	47	85
Regulatory liabilities	168	163
Deferred Income Tax Regulatory Asset [Member]
Regulatory assets:
Total regulatory assets	1,327	1,145
Pension Benefit Regulatory Asset [Member]
Regulatory assets:
Total regulatory assets	1,236	845
Post-Retirement and Post-Employment Benefits [Member]
Regulatory assets:
Total regulatory assets	273	308
Environmental [Member]
Regulatory assets:
Total regulatory assets	239	266
Pension Cost Variance [Member]
Regulatory assets:
Total regulatory assets	90	80
DSC Exemption [Member]
Regulatory assets:
Total regulatory assets	16	7
OEB Cost Assessment Differential [Member]
Regulatory assets:
Total regulatory assets	12	9
Retail Settlement Variance Accounts [Member]
Regulatory assets:
Total regulatory assets	11
Long-Term Project Development Costs [Member]
Regulatory assets:
Total regulatory assets		5
Other Regulatory Assets [Member]
Regulatory assets:
Total regulatory assets	27	18
Rider 11 [Member]
Regulatory liabilities:
Total regulatory liabilities	83	55
External Revenue Variance [Member]
Regulatory liabilities:
Total regulatory liabilities	54	81
CDM Deferral Variance Account [Member]
Regulatory liabilities:
Total regulatory liabilities	25
Deferred Income Tax Regulatory Liability [Member]
Regulatory liabilities:
Total regulatory liabilities	21	19
PST Savings Deferral [Member]
Regulatory liabilities:
Total regulatory liabilities	19	17
Hydro One Brampton Networks Rider [Member]
Regulatory liabilities:
Total regulatory liabilities	2	8
Retail Settlement Variance Accounts [Member]
Regulatory liabilities:
Total regulatory liabilities		35
Rider 9 [Member]
Regulatory liabilities:
Total regulatory liabilities		19
Other Regulatory Liabilities [Member]
Regulatory liabilities:
Total regulatory liabilities	11	14

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Dividends - Additional Information (Detail) (CAD) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Dividends [Abstract]
Dividends on preferred shares	18	18
Common share dividends	269	200

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Consolidated Statements of Cash Flows (CAD) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Operating activities
Net income	747	803
Environmental expenditures	(18)	(16)
Adjustments for non-cash items:
Depreciation and amortization (excluding removal costs)	641	597
Regulatory assets and liabilities	(69)	3
Deferred income taxes	10	(2)
Other		8
Changes in non-cash balances related to operations (Note 21)	(55)	11
Net cash from operating activities	1,256	1,404
Financing activities
Long-term debt issued	628	1,185
Long-term debt retired	(776)	(600)
Amount contributed by noncontrolling interest (Note 4)	72
Dividends paid	(287)	(218)
Change in bank indebtedness	(29)	(11)
Other	(3)	(5)
Net cash from (used in) financing activities	(395)	351
Investing activities
Property, plant and equipment (Note 21)	(1,481)	(1,308)
Intangible assets (Note 21)	(23)	(79)
Acquisition of Norfolk Power Inc. (Note 4)	(66)
Proceeds from investment	250
Other	(6)	2
Net cash used in investing activities	(1,326)	(1,385)
Net change in cash and cash equivalents	(465)	370
Cash and cash equivalents, beginning of year	565	195
Cash and cash equivalents, end of year	100	565

XML

Consolidated Statements of Operations and Comprehensive Income (Parenthetical) (CAD) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Distribution revenues	4,903	4,484
Transmission revenues	1,588	1,529
Purchased power costs	3,419	3,020
Related Party [Member]
Distribution revenues	159	160
Transmission revenues	1,567	1,517
Purchased power costs	2,633	2,500

XML

Intangible Assets

12 Months Ended

Dec. 31, 2014

Goodwill and Intangible Assets Disclosure [Abstract]

Intangible Assets

10. INTANGIBLE ASSETS

December 31, 2014 (millions of Canadian dollars)	Intangible Assets		Accumulated Amortization		Development in Progress		Total
Computer applications software		573		303		3		273
Other		5		2		—		3
		578		305		3		276
December 31, 2013 (millions of Canadian dollars)	Intangible Assets		Accumulated Amortization		Development in Progress		Total
Computer applications software		557		249		3		311
Other		5		3		—		2
		562		252		3		313

Financing charges capitalized on intangible assets under development were $1 million in 2014 (2013 – $3 million). The estimated annual amortization expense for intangible assets is as follows: 2015 – $53 million; 2016 – $53 million; 2017 – $53 million; 2018 – $45 million; and 2019 – $31 million.

XML

Environmental Liabilities - Reconciliation between Undiscounted Basis of Environmental Liabilities and Amount Recognized on Consolidated Balance Sheets (Detail) (CAD) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Environmental Liabilities [Line Items]
Undiscounted environmental liabilities	265	305
Less: discounting accumulated liabilities to present value	26	39
Discounted environmental liabilities	239	266
PCB [Member]
Environmental Liabilities [Line Items]
Undiscounted environmental liabilities	195	237
Less: discounting accumulated liabilities to present value	23	36
Discounted environmental liabilities	172	201
LAR [Member]
Environmental Liabilities [Line Items]
Undiscounted environmental liabilities	70	68
Less: discounting accumulated liabilities to present value	3	3
Discounted environmental liabilities	67	65

XML

Pension and Post-Retirement and Post-Employment Benefits - Approximate Life Expectancies Used to Determine Projected Benefit Obligations for Pension, Post-Retirement and Post-Employment Plans (Detail)	Dec. 31, 2014 Employees	Dec. 31, 2013 Employees
Life Expectancy At Age Sixty Five [Member] | Male [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Approximate life expectancy at particular age	23	23
Life Expectancy At Age Sixty Five [Member] | Female [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Approximate life expectancy at particular age	25	25
Life Expectancy At Age Forty Five [Member] | Male [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Approximate life expectancy at particular age	24	24
Life Expectancy At Age Forty Five [Member] | Female [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Approximate life expectancy at particular age	26	26

XML

Pension and Post-Retirement and Post-Employment Benefits - Schedule of Effect of One Percent Change in Health Care Cost Trends on Projected Benefit Obligation (Detail) (Post-Retirement and Post-Employment Benefits [Member], CAD) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Post-Retirement and Post-Employment Benefits [Member]
Schedule Of Effect Of One Percentage Point Change In Assumed Health Care Cost Trend Rates [Line Items]
Effect of a 1% increase in health care cost trends	248	258
Effect of a 1% decrease in health care cost trends	(193)	(200)

XML

Document and Entity Information	12 Months Ended
	Dec. 31, 2014
Document And Entity Information [Abstract]
Document Type	40-F
Amendment Flag	false
Document Period End Date	Dec. 31, 2014
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	FY
Entity Registrant Name	HYDRO ONE INC
Entity Central Index Key	0001114445
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Common Stock, Shares Outstanding	100,000

XML

Regulatory Assets and Liabilities

12 Months Ended

Dec. 31, 2014

Regulated Operations [Abstract]

Regulatory Assets and Liabilities

11. REGULATORY ASSETS AND LIABILITIES

Regulatory assets and liabilities arise as a result of the rate-setting process. Hydro One has recorded the following regulatory assets and liabilities:

December 31 (millions of Canadian dollars)	2014		2013
Regulatory assets:
Deferred income tax regulatory asset		1,327		1,145
Pension benefit regulatory asset		1,236		845
Post-retirement and post-employment benefits		273		308
Environmental		239		266
Pension cost variance		90		80
DSC exemption		16		7
OEB cost assessment differential		12		9
Retail settlement variance accounts		11		—
Long-term project development costs		—		5
Other		27		18
Total regulatory assets		3,231		2,683
Less: current portion		31		47
		3,200		2,636
Regulatory liabilities:
Rider 11		83		55
External revenue variance		54		81
CDM deferral variance account		25		—
Deferred income tax regulatory liability		21		19
PST savings deferral		19		17
Hydro One Brampton Networks rider		2		8
Retail settlement variance accounts		—		35
Rider 9		—		19
Other		11		14
Total regulatory liabilities		215		248
Less: current portion		47		85
		168		163

Deferred Income Tax Regulatory Asset and Liability

Deferred income taxes are recognized on temporary differences between the carrying amount of assets and liabilities in the financial statements and the corresponding tax bases used in the computation of taxable profit. The Company has recognized regulatory assets and liabilities that correspond to deferred income taxes that flow through the rate-setting process. In the absence of rate-regulated accounting, the Company’s provision for PILs would have been recognized using the liability method and there would be no regulatory accounts established for taxes to be recovered through future rates. As a result, the 2014 provision for PILs would have been higher by approximately $132 million (2013 – $139 million).

Pension Benefit Regulatory Asset

The Company recognizes the net unfunded status of pension obligations on the Consolidated Balance Sheets with an offset to the associated regulatory asset. A regulatory asset is recognized because management considers it to be probable that pension benefit costs will be recovered in the future through the rate-setting process. The pension benefit obligation is remeasured to its fair value at each year end based on an annual actuarial report, with an offset to the associated regulatory asset, to the extent of the remeasurement adjustment. In the absence of rate-regulated accounting, 2014 OCI would have been lower by $391 million (2013 – higher by $670 million).

Post-Retirement and Post-Employment Benefits

The Company recognizes the net unfunded status of post-retirement and post-employment obligations on the Consolidated Balance Sheets with an incremental offset to the associated regulatory assets. A regulatory asset is recognized because management considers it to be probable that post-retirement and post-employment benefit costs will be recovered in the future through the rate-setting process. The post-retirement and post-employment benefit obligation is remeasured to its fair value at each year end based on an annual actuarial report, with an offset to the associated regulatory asset, to the extent of the remeasurement adjustment. In the absence of rate-regulated accounting, 2014 OCI would have been higher by $35 million (2013 – $12 million).

Environmental

Hydro One records a liability for the estimated future expenditures required to remediate environmental contamination. Because such expenditures are expected to be recoverable in future rates, the Company has recorded an equivalent amount as a regulatory asset. In 2014, the environmental regulatory asset decreased by $33 million (2013 – $3 million) to reflect related changes in the Company’s PCB liability, and increased by $13 million (2013 – $26 million) due to changes in the LAR liability. The environmental regulatory asset is amortized to results of operations based on the pattern of actual expenditures incurred and charged to environmental liabilities. The OEB has the discretion to examine and assess the prudency and the timing of recovery of all of Hydro One’s actual environmental expenditures. In the absence of rate-regulated accounting, 2014 operation, maintenance and administration expenses would have been lower by $20 million (2013 – higher by $23 million). In addition, 2014 amortization expense would have been lower by $18 million (2013 – $16 million), and 2014 financing charges would have been higher by $11 million (2013 – $10 million).

Pension Cost Variance

A pension cost variance account was established for Hydro One Networks’ transmission and distribution businesses to track the difference between the actual pension expenses incurred and estimated pension costs approved by the OEB. The balance in this regulatory account reflects the excess of pension costs paid as compared to OEB-approved amounts. In the absence of rate-regulated accounting, 2014 revenue would have been lower by $10 million (2013 – $19 million).

DSC Exemption

In June 2010, Hydro One Networks filed an application with the OEB regarding the OEB’s new cost responsibility rules contained in the OEB’s October 2009 Notice of Amendment to the Distribution System Code (DSC), with respect to the connection of certain renewable generators that were already connected or that had received a connection impact assessment prior to October 21, 2009. The application sought approval to record and defer the unanticipated costs incurred by Hydro One Networks that resulted from the connection of certain renewable generation facilities. The OEB ruled that identified specific expenditures can be recorded in a deferral account subject to the OEB’s review until the next Hydro One Networks’ distribution cost-of-service application. This program effectively ended at the end of 2014 with no new principal to be recorded in 2015.

OEB Cost Assessment Differential

In April 2010, the OEB issued its Decision regarding Hydro One Networks’ distribution rate application for 2010 and 2011. As part of this decision, the OEB also approved the distribution-related OEB Cost Assessment Differential Account to record the difference between the amounts approved in rates and actual expenditures with respect to the OEB’s cost assessments. This continued for 2012-2014 until the next Hydro One Networks’ distribution cost-of-service application, which was submitted in 2014. This program effectively ended at the end of 2014 with no new activity to be recorded in 2015.

Retail Settlement Variance Accounts (RSVAs)

Hydro One has deferred certain retail settlement variance amounts under the provisions of Article 490 of the OEB’s Accounting Procedures Handbook. In December 2012, the OEB approved the disposition of the total RSVA balance accumulated from January 2010 to December 2011, including accrued interest, to be disposed over a 24-month period from January 1, 2013 to December 31, 2014. At December 31, 2014, the RSVA was in a net asset position due to a change in global adjustment.

Long-Term Project Development Costs

In May 2009, the OEB approved the creation of a deferral account to record Hydro One Networks’ costs of preliminary work to advance certain transmission projects identified in the Company’s 2009 and 2010 transmission rate applications. In March 2010, the OEB issued a decision amending the scope of the account to include the 20 major transmission projects identified in the September 2009 request from the Ministry of Energy and Infrastructure. In December 2012, the OEB approved the recovery of the December 31, 2012 balance, including accrued interest, to be recovered over a one-year period from January 1, 2014 to December 31, 2014.

Rider 11

In April 2010, the OEB requested the establishment of deferral accounts which capture the difference between the revenue recorded on the basis of Green Energy Plan expenditures incurred and the actual recoveries received. Rider 11 includes amounts previously included as Rider 8.

External Revenue Variance

In May 2009, the OEB approved forecasted amounts related to export service revenue, external revenue from secondary land use, and external revenue from station maintenance and engineering and construction work. In November 2012, the OEB again approved forecasted amounts related to these revenue categories and extended the scope to encompass all other external revenues. The external revenue variance account balance reflects the excess of actual external revenues compared to the OEB-approved forecasted amounts.

CDM Deferral Variance Account

As part of Hydro One Networks’ application for 2013 and 2014 transmission rates, Hydro One agreed to establish a new regulatory deferral variance account to track the impact of actual Conservation and Demand Management (CDM) and demand response results on the load forecast compared to the estimated load forecast included in the revenue requirement. The balance in the CDM deferral variance account relates to the actual 2013 CDM compared to the amounts included in 2013 revenue requirement. The OEB rate order specifically states that the Ontario Power Authority (OPA) data used to calculate the difference between forecasted and actual savings will be provided one year in arrears, and as a result, no amount should be recorded in advance of notification from the OPA of actual results. This notification from the OPA typically occurs in September of each year.

PST Savings Deferral Account

The provincial sales tax (PST) and goods and services tax (GST) were harmonized in July 2010. Unlike the GST, the PST was included in operation, maintenance and administration expenses or capital expenditures for past revenue requirements approved during a full cost-of-service hearing. Under the harmonized sales tax (HST) regime, the HST included in operation, maintenance and administration expenses or capital expenditures is not a cost ultimately borne by the Company and as such, a refund of the prior PST element in the approved revenue requirement is applicable, and calculations for tracking and refund were requested by the OEB. For Hydro One Networks’ transmission revenue requirement, PST was included between July 1, 2010 and December 31, 2010 and recorded in a deferral account, per direction from the OEB. For Hydro One Networks’ distribution revenue requirement, PST was included between July 1, 2010 and December 31, 2014 and recorded in a deferral account, per direction from the OEB.

Hydro One Brampton Networks Rider

In December 2013, the OEB issued a decision for Hydro One Brampton Networks’ 2014 distribution rates. Included in the OEB’s decision was the approval of certain deferral account balances, primarily RSVAs. The OEB ordered that the approved balances be aggregated into a single regulatory account and disposed of through a rate rider over a two-year period from January 1, 2014 to December 31, 2015.

Rider 9

In December 2012, as part of Hydro One Networks’ 2013 IRM distribution rate application, the OEB approved for disposition certain distribution-related deferral account balances, including RSVA amounts and balances of Rider 2 and Rider 3, accumulated up to December 2011, including accrued interest, to be disposed over a 24-month period from January 1, 2013 to December 31, 2014.

XML

Capital Management - Additional Information (Detail)	Dec. 31, 2014
Statement of Financial Position [Abstract]
Permissible limit on debt to total capital percentage	75.00%

XML

Pension and Post-Retirement and Post-Employment Benefits - Schedule of Weighted Average Assumptions Used to Determine Net Periodic Benefit Costs (Parenthetical) (Detail) (Maximum [Member])	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Grading Down in and After 2031 [Member]
Schedule Of Weighted Average Assumption Determining Pension Plan And Other Post retirement Benefit Plan [Line Items]
Assumed health care cost trend, percentage	4.39%	4.39%
2014 [Member]
Schedule Of Weighted Average Assumption Determining Pension Plan And Other Post retirement Benefit Plan [Line Items]
Assumed health care cost trend, percentage	6.81%
2013 [Member]
Schedule Of Weighted Average Assumption Determining Pension Plan And Other Post retirement Benefit Plan [Line Items]
Assumed health care cost trend, percentage		6.91%

XML

Consolidated Balance Sheets (CAD) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Current assets:
Cash and cash equivalents (Note 13)	100	565
Accounts receivable (net of allowance for doubtful accounts - $66; 2013 - $36) (Note 8)	1,016	923
Due from related parties (Note 20)	224	197
Regulatory assets (Note 11)	31	47
Materials and supplies	23	23
Deferred income tax assets (Note 7)	19	18
Derivative instruments (Note 13)	2	6
Investment (Notes 13, 20)		251
Prepaid expenses and other assets	35	28
Total current assets	1,450	2,058
Property, plant and equipment (Note 9):
Property, plant and equipment in service	25,356	23,820
Less: accumulated depreciation	9,134	8,615
Property, plant and equipment before construction in progress and future use land components and spares	16,222	15,205
Construction in progress	1,025	1,078
Future use land, components and spares	154	148
Property, plant and equipment, Total	17,401	16,431
Other long-term assets:
Regulatory assets (Note 11)	3,200	2,636
Intangible assets (net of accumulated amortization - $305; 2013 - $252) (Note 10)	276	313
Goodwill (Note 4)	173	133
Deferred debt issuance costs	36	36
Deferred income tax assets (Note 7)	7	11
Derivative instruments (Note 13)		6
Other	7	1
Total other long-term assets	3,699	3,136
Total assets	22,550	21,625
Current liabilities:
Bank indebtedness (Note 13)	2	31
Accounts payable	173	135
Accrued liabilities (Notes 15, 16)	611	654
Due to related parties (Note 20)	227	230
Accrued interest	100	100
Regulatory liabilities (Note 11)	47	85
Derivative instruments (Note 13)	3
Long-term debt payable within one year (includes $252 measured at fair value; 2013 - $506) (Notes 12, 13)	552	756
Total current liabilities	1,715	1,991
Long-term debt (includes $nil measured at fair value; 2013 - $256) (Notes 12, 13)	8,373	8,301
Other long-term liabilities:
Post-retirement and post-employment benefit liability (Note 15)	1,533	1,488
Deferred income tax liabilities (Note 7)	1,313	1,129
Pension benefit liability (Note 15)	1,236	845
Environmental liabilities (Note 16)	221	239
Regulatory liabilities (Note 11)	168	163
Net unamortized debt premiums	18	20
Asset retirement obligations (Note 17)	9	14
Long-term accounts payable and other liabilities	17	20
Total other long-term liabilities	4,515	3,918
Total liabilities	14,603	14,210
Contingencies and commitments (Notes 22, 23)
Subsequent Event (Note 25)
Preferred shares (authorized: unlimited; issued: 12,920,000) (Notes 18, 19)	323	323
Noncontrolling interest subject to redemption (Note 4)	21
Equity
Common shares (authorized: unlimited; issued: 100,000) (Notes 18, 19)	3,314	3,314
Retained earnings	4,249	3,787
Accumulated other comprehensive loss	(9)	(9)
Noncontrolling interest (Note 4)	49
Total equity	7,603	7,092
Total liabilities, preferred shares, noncontrolling interest subject to redemption and equity	22,550	21,625

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Depreciation and Amortization

12 Months Ended

Dec. 31, 2014

Text Block [Abstract]

Depreciation and Amortization

5. DEPRECIATION AND AMORTIZATION

Year ended December 31 (millions of Canadian dollars)	2014		2013
Depreciation of property, plant and equipment		565		533
Amortization of intangible assets		53		48
Asset removal costs		81		79
Amortization of regulatory assets		23		16
		722		676

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Business Combinations

12 Months Ended

Dec. 31, 2014

Business Combinations [Abstract]

Business Combinations

4. BUSINESS COMBINATIONS

B2M Limited Partnership

In 2012, Hydro One entered into an agreement with the Chippewas of Nawash First Nation and the Chippewas of Saugeen First Nation, collectively referred to as the Saugeen Ojibway Nation (SON), where a noncontrolling equity interest in Hydro One’s new limited partnership, B2M LP, would be made available for purchase at fair value by the SON. B2M LP was formed by Hydro One in 2013 to hold most of the transmission lines and a licence to use the related land. These assets are associated with Hydro One’s Bruce to Milton Transmission Reinforcement Project, an electricity transmission line (Bruce to Milton Line) in southwestern Ontario, from the Bruce Power facility in Kincardine to Hydro One’s Milton Switching Station in the Town of Milton. Hydro One Networks will maintain and operate the Bruce to Milton Line in accordance with an operation and management services agreement. In November 2013, the OEB issued a Decision and Order granting B2M LP a transmission licence and granting Hydro One Networks leave to sell the relevant Bruce to Milton Line transmission assets to B2M LP.

On December 16, 2014, the relevant Bruce to Milton Line transmission assets totalling $526 million were transferred from Hydro One Networks to B2M LP. This was financed by 60% debt ($316 million) and 40% equity ($210 million). On December 17, 2014, the SON acquired a 34.2% equity interest in B2M LP for consideration of $72 million, representing the fair value of the equity interest acquired.

Part of the SON’s equity interest in B2M LP is in Class B units of B2M LP that have a mandatory put option. The put option requires that upon the occurrence of an enforcement event (i.e. an event of default such as a debt default by the SON or insolvency event), the SON has the ability to require Hydro One to purchase the Class B units of B2M LP for net book value on the redemption date.

The noncontrolling interest relating to the Class B units is classified on the Consolidated Balance Sheet as temporary equity because the redemption feature is outside the control of the Company. The balance of the noncontrolling interest is classified within equity. At December 31, 2014, the total noncontrolling interest was reduced by the 2014 net loss attributable to noncontrolling interest totalling $2 million, including $1 million relating to noncontrolling interest subject to redemption.

Acquisition of Norfolk Power

On August 29, 2014, Hydro One acquired 100% of the common shares of Norfolk Power, an electricity distribution and telecom company located in southwestern Ontario. The total purchase price for Norfolk Power, net of the long-term debt assumed and adjusted for preliminary working capital and other closing adjustments, is approximately $68 million.

The following table summarizes the preliminary determination of the fair value of the assets acquired and liabilities assumed:

(millions of Canadian dollars)
Working capital	6
Property, plant and equipment	56
Deferred income tax assets	1
Goodwill	40
Bank indebtedness	(3	)
Derivative instruments	(3	)
Long-term debt	(26	)
Post-retirement and post-employment benefit liability	(1	)
Environmental liability	(1	)
Long-term accounts payable and other liabilities	(1	)
	68

The determination of the fair values of assets acquired and liabilities assumed has been based upon management’s estimates and certain assumptions with respect to the fair values of the assets acquired and liabilities assumed. The purchase agreement provides for final purchase price adjustments based on agreed working capital and other balances at the acquisition date which have not yet been finalized. The Company will continue to review information and perform further analysis prior to finalizing the total purchase price and therefore the actual total purchase price and the consequent impact on goodwill may differ from the amounts above.

Goodwill of approximately $40 million arising from the Norfolk Power acquisition consists largely of the synergies and economies of scale expected from combining the operations of Hydro One and Norfolk Power. All of the goodwill was assigned to Hydro One’s Distribution Business segment. None of the goodwill recognized is expected to be deductible for income tax purposes.

Norfolk Power contributed revenues of $18 million and net income of less than $1 million to the Company’s consolidated financial results for the year ended December 31, 2014.

All costs related to the acquisition have been expensed through the Consolidated Statements of Operations and Comprehensive Income. The disclosure of Norfolk Power’s pro forma information is immaterial to the Company’s consolidated financial results for the year ended December 31, 2014.

Woodstock Hydro Purchase Agreement

On May 21, 2014, Hydro One reached an agreement with the City of Woodstock to acquire 100% of the common shares of Woodstock Hydro Holdings Inc. (Woodstock Hydro), an electricity distribution company located in southwestern Ontario. The acquisition is pending a regulatory decision from the OEB. The purchase price for Woodstock Hydro will be approximately $29 million, subject to final closing adjustments. The transaction is anticipated to be completed in 2015. In anticipation of the Woodstock Hydro acquisition, the Company made a refundable deposit totalling $2 million, which is recorded in prepaid expenses and other assets on the Consolidated Balance Sheet.

Haldimand Hydro Purchase Agreement

On June 10, 2014, Hydro One reached an agreement with Haldimand County to acquire 100% of the common shares of Haldimand County Utilities Inc. (Haldimand Hydro), an electricity distribution and telecom company located in southwestern Ontario. The acquisition is pending a regulatory decision from the OEB. The purchase price for Haldimand Hydro will be approximately $65 million, subject to final closing adjustments. The transaction is anticipated to be completed in 2015. In anticipation of the Haldimand Hydro acquisition, the Company made a refundable deposit totalling $3 million, which is recorded in prepaid expenses and other assets on the Consolidated Balance Sheet.

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Environmental Liabilities

12 Months Ended

Dec. 31, 2014

Text Block [Abstract]

Environmental Liabilities

16. ENVIRONMENTAL LIABILITIES

The following tables show the movements in environmental liabilities for the years ended December 31, 2014 and 2013:

Year ended December 31, 2014 (millions of Canadian dollars)	PCB			LAR			Total
Environmental liabilities, January 1		201			65			266
Interest accretion		9			2			11
Expenditures		(5	)		(13	)		(18	)
Revaluation adjustment		(33	)		13			(20	)
Environmental liabilities, December 31		172			67			239
Less: current portion		8			10			18
		164			57			221

Year ended December 31, 2013 (millions of Canadian dollars)	PCB			LAR			Total
Environmental liabilities, January 1		197			52			249
Interest accretion		9			1			10
Expenditures		(2	)		(14	)		(16	)
Revaluation adjustment		(3	)		26			23
Environmental liabilities, December 31		201			65			266
Less: current portion		15			12			27
		186			53			239

The following tables show the reconciliation between the undiscounted basis of the environmental liabilities and the amount recognized on the Consolidated Balance Sheets after factoring in the discount rate:

December 31, 2014 (millions of Canadian dollars)	PCB		LAR		Total
Undiscounted environmental liabilities		195		70		265
Less: discounting accumulated liabilities to present value		23		3		26
Discounted environmental liabilities		172		67		239

December 31, 2013 (millions of Canadian dollars)	PCB		LAR		Total
Undiscounted environmental liabilities		237		68		305
Less: discounting accumulated liabilities to present value		36		3		39
Discounted environmental liabilities		201		65		266

At December 31, 2014, the estimated future environmental expenditures were as follows:

(millions of Canadian dollars)
2015	18
2016	37
2017	36
2018	35
2019	33
Thereafter	106
	265

At December 31, 2014, of the total estimated future environmental expenditures, $195 million relates to PCBs (2013 – $237 million) and $70 million relates to LAR (2013 – $68 million).

Hydro One records a liability for the estimated future expenditures for the contaminated LAR and for the phase-out and destruction of PCB-contaminated mineral oil removed from electrical equipment when it is determined that future environmental remediation expenditures are probable under existing statute or regulation and the amount of the future expenditures can be reasonably estimated.

There are uncertainties in estimating future environmental costs due to potential external events such as changes in legislation or regulations, and advances in remediation technologies. In determining the amounts to be recorded as environmental liabilities, the Company estimates the current cost of completing required work and makes assumptions as to when the future expenditures will actually be incurred, in order to generate future cash flow information. A long-term inflation rate assumption of approximately 2% has been used to express these current cost estimates as estimated future expenditures. Future expenditures have been discounted using factors ranging from approximately 2.3% to 6.3%, depending on the appropriate rate for the period when expenditures are expected to be incurred. All factors used in estimating the Company’s environmental liabilities represent management’s best estimates of the present value of costs required to meet existing legislation or regulations. However, it is reasonably possible that numbers or volumes of contaminated assets, cost estimates to perform work, inflation assumptions and the assumed pattern of annual cash flows may differ significantly from the Company’s current assumptions. In addition, with respect to the PCB environmental liability, the availability of critical resources such as skilled labour and replacement assets and the ability to take maintenance outages in critical facilities may influence the timing of expenditures.

PCBs

The Environment Canada regulations, enacted under the Canadian Environmental Protection Act, 1999, govern the management, storage and disposal of PCBs based on certain criteria, including type of equipment, in-use status, and PCB-contamination thresholds. Under current regulations, Hydro One’s PCBs have to be disposed of by the end of 2025, with the exception of specifically exempted equipment. Contaminated equipment will generally be replaced, or will be decontaminated by removing PCB-contaminated insulating oil and retro filling with replacement oil that contains PCBs in concentrations of less than 2 ppm.

The Company’s best estimate of the total estimated future expenditures to comply with current PCB regulations is $195 million. These expenditures are expected to be incurred over the period from 2015 to 2025. As a result of its annual review of environmental liabilities, the Company recorded a revaluation adjustment in 2014 to reduce the PCB environmental liability by $33 million (2013 – $3 million).

LAR

The Company’s best estimate of the total estimated future expenditures to complete its LAR program is $70 million. These expenditures are expected to be incurred over the period from 2015 to 2023. As a result of its annual review of environmental liabilities, the Company recorded a revaluation adjustment in 2014 to increase the LAR environmental liability by $13 million (2013 – $26 million).

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Debt and Credit Agreements

12 Months Ended

Dec. 31, 2014

Debt Disclosure [Abstract]

Debt and Credit Agreements

12. DEBT AND CREDIT AGREEMENTS

Short-Term Notes

Hydro One meets its short-term liquidity requirements in part through the issuance of commercial paper under its Commercial Paper Program which has a maximum authorized amount of $1,000 million. These short-term notes are denominated in Canadian dollars with varying maturities not exceeding 365 days. Hydro One had no commercial paper borrowings outstanding as at December 31, 2014 and 2013.

Hydro One has a $1,500 million committed and unused revolving standby credit facility with a syndicate of banks, maturing in June 2019. If used, interest on the facility would apply based on Canadian benchmark rates. This credit facility is unsecured and supports the Company’s Commercial Paper Program. The Company may use the credit facility for general corporate purposes, including meeting short-term funding requirements. The obligation of each lender to make any credit extension to the Company under its credit facility is subject to various conditions including, among other things, that no event of default has occurred or would result from such credit extension.

Long-Term Debt

The Company issues notes for long-term financing under its Medium-Term Note (MTN) Program. The maximum authorized principal amount of notes issuable under this program is $3,000 million. At December 31, 2014, $1,187 million remained available for issuance until October 2015.

The following table presents the outstanding long-term debt at December 31, 2014 and 2013:

December 31 (millions of Canadian dollars)	2014			2013
3.13% Series 19 notes due 20141		—			750
2.95% Series 21 notes due 20151		500			500
Floating-rate Series 22 notes due 20152		50			50
4.64% Series 10 notes due 2016		450			450
Floating-rate Series 27 notes due 20162		50			50
5.18% Series 13 notes due 2017		600			600
2.78% Series 28 notes due 2018		750			750
Floating-rate Series 31 notes due 20192		228			—
4.40% Series 20 notes due 2020		300			300
3.20% Series 25 notes due 2022		600			600
7.35% Debentures due 2030		400			400
6.93% Series 2 notes due 2032		500			500
6.35% Series 4 notes due 2034		385			385
5.36% Series 9 notes due 2036		600			600
4.89% Series 12 notes due 2037		400			400
6.03% Series 17 notes due 2039		300			300
5.49% Series 18 notes due 2040		500			500
4.39% Series 23 notes due 2041		300			300
6.59% Series 5 notes due 2043		315			315
4.59% Series 29 notes due 2043		435			435
4.17% Series 32 notes due 2044		350			—
5.00% Series 11 notes due 2046		325			325
4.00% Series 24 notes due 2051		225			225
3.79% Series 26 notes due 2062		310			310
4.29% Series 30 notes due 2064		50			—
		8,923			9,045
Add: Unrealized mark-to-market loss1		2			12
Less: Long-term debt payable within one year		(552	)		(756	)
Long-term debt		8,373			8,301

¹  The unrealized mark-to-market loss relates to $250 million of the Series 21 notes due 2015 (2013 – $500 million of the Series 19 notes due 2014, and $250 million of the Series 21 notes due 2015). The unrealized mark-to-market loss is offset by a $2 million (2013 – $12 million) unrealized mark-to-market gain on the related fixed-to-floating interest-rate swap agreements, which are accounted for as fair value hedges. See Note 13 – Fair Value of Financial Instruments and Risk Management for details of fair value hedges.

²  The interest rates of the floating-rate notes are referenced to the 3-month Canadian dollar bankers’ acceptance rate, plus a margin.

In 2014, Hydro One issued $628 million (2013 – $1,185 million) of long-term debt under the MTN Program, and repaid the $750 million MTN Series 19 notes (2013 – repaid $600 million MTN Series 15 notes). In addition, the Company repaid long-term debt totalling $26 million assumed on the Norfolk Power acquisition.

The long-term debt is unsecured and denominated in Canadian dollars. The long-term debt is summarized by the number of years to maturity in Note 13 – Fair Value of Financial Instruments and Risk Management.

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Pension and Post-Retirement and Post-Employment Benefits - Schedule of Projected Benefit Obligation (PBO), Accumulated Benefit Obligation (ABO) and Fair Value of Plan Assets (Detail) (Pension Benefits [Member], CAD) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Pension Benefits [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
PBO	7,535	6,576	6,507
ABO	6,887	5,998
Fair value of plan assets	6,299	5,731	4,992

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Accounts Receivable

12 Months Ended

Dec. 31, 2014

Receivables [Abstract]

Accounts Receivable

8. ACCOUNTS RECEIVABLE

December 31 (millions of Canadian dollars)	2014			2013
Accounts receivable – billed		496			268
Accounts receivable – unbilled		586			691
Accounts receivable, gross		1,082			959
Allowance for doubtful accounts		(66	)		(36	)
Accounts receivable, net		1,016			923

The following table shows the movements in the allowance for doubtful accounts for the years ended December 31, 2014 and 2013:

Year ended December 31 (millions of Canadian dollars)	2014			2013
Allowance for doubtful accounts – January 1		(36	)		(23	)
Write-offs		24			24
Additions to allowance for doubtful accounts		(54	)		(37	)
Allowance for doubtful accounts – December 31		(66	)		(36	)

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Provision for Payments in Lieu of Corporate Income Taxes - Additional Information (Detail) (CAD)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Income Tax Expenses [Line Items]
Current provision due from related parties	224,000,000	197,000,000
PILs [Member]
Income Tax Expenses [Line Items]
Deferred provision (recovery) for PILs	10,000,000	(2,000,000)
Deferred tax liability	0	0
PILs [Member] | OEFC [Member]
Income Tax Expenses [Line Items]
Current provision due from related parties	39,000,000	29,000,000

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Related Party Transactions - Schedule of Amounts Due to and from Related Parties (Detail) (CAD) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Related Party Transactions [Abstract]
Due from related parties	224	197
Due to related parties	(227)	(230)
Investment		251

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Financing Charges

12 Months Ended

Dec. 31, 2014

Banking and Thrift, Interest [Abstract]

Financing Charges

6. FINANCING CHARGES

Year ended December 31 (millions of Canadian dollars)	2014			2013
Interest on long-term debt		432			416
Other		12			9
Less: Interest capitalized on construction and development in progress		(49	)		(51	)
Gain on interest-rate swap agreements		(10	)		(11	)
Interest earned on investments		(6	)		(3	)
		379			360

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Provision for Payments in Lieu of Corporate Income Taxes

12 Months Ended

Dec. 31, 2014

Income Tax Disclosure [Abstract]

Provision for Payments in Lieu of Corporate Income Taxes

7. PROVISION FOR PAYMENTS IN LIEU OF CORPORATE INCOME TAXES

The provision for PILs differs from the amount that would have been recorded using the combined Canadian federal and Ontario statutory income tax rate. The reconciliation between the statutory and the effective tax rates is provided as follows:

Year ended December 31 (millions of Canadian dollars)	2014			2013
Income before provision for PILs		836			912
Canadian federal and Ontario statutory income tax rate		26.50	%		26.50	%
Provision for PILs at statutory rate		222			242
Increase (decrease) resulting from:
Net temporary differences included in amounts charged to customers:
Capital cost allowance in excess of depreciation and amortization		(72	)		(72	)
Pension contributions in excess of pension expense		(24	)		(23	)
Overheads capitalized for accounting but deducted for tax purposes		(15	)		(14	)
Interest capitalized for accounting but deducted for tax purposes		(13	)		(13	)
Environmental expenditures		(5	)		(4	)
Prior year’s adjustments		(4	)		(8	)
Non-refundable investment tax credits		(3	)		(4	)
Post-retirement and post-employment benefit expense in excess of cash payments		3			4
Other		(1	)		(1	)
Net temporary differences		(134	)		(135	)
Net permanent differences		1			2
Total provision for PILs		89			109

The major components of income tax expense are as follows:

Year ended December 31 (millions of Canadian dollars)	2014			2013
Current provision for PILs		79			111
Deferred provision (recovery) for PILs		10			(2	)
Total provision for PILs		89			109
Effective income tax rate		10.63	%		11.98	%

The current provision for PILs is remitted to, or received from, the OEFC. At December 31, 2014, $39 million due from the OEFC was included in due from related parties on the Consolidated Balance Sheet (2013 – $29 million).

At December 31, 2014, the total provision for PILs includes deferred provision for PILs of $10 million (2013 – deferred recovery of $2 million) that is not included in the rate-setting process, using the liability method of accounting. Deferred PILs balances expected to be included in the rate-setting process are offset by regulatory assets and liabilities to reflect the anticipated recovery or disposition of these balances within future electricity rates.

Deferred Income Tax Assets and Liabilities

Deferred income tax assets and liabilities arise from differences between the carrying amounts and tax basis of the Company’s assets and liabilities. At December 31, 2014 and 2013, deferred income tax assets and liabilities consisted of the following:

December 31 (millions of Canadian dollars)	2014			2013
Deferred income tax assets
Post-retirement and post-employment benefits expense in excess of cash payments		8			7
Environmental expenditures		4			5
Depreciation and amortization in excess of capital cost allowance		(4	)		—
Other		(1	)		(1	)
Total deferred income tax assets		7			11
Less: current portion		—			—
		7			11
December 31 (millions of Canadian dollars)	2014			2013
Deferred income tax liabilities
Capital cost allowance in excess of depreciation and amortization		(1,713	)		(1,556	)
Regulatory amounts that are not recognized for tax purposes		(140	)		(144	)
Partnership interest		(38	)		—
Goodwill		(21	)		(20	)
Post-retirement and post-employment benefits expense in excess of cash payments		559			542
Environmental expenditures		59			66
Other		—			1
Total deferred income tax liabilities		(1,294	)		(1,111	)
Less: current portion		19			18
		(1,313	)		(1,129	)

During 2014 and 2013, there were no changes in the rate applicable to future taxes.

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Property, Plant and Equipment

12 Months Ended

Dec. 31, 2014

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

9. PROPERTY, PLANT AND EQUIPMENT

December 31, 2014 (millions of Canadian dollars)	Property, Plant and Equipment		Accumulated Depreciation		Construction in Progress		Total
Transmission		13,209		4,416		626		9,419
Distribution		9,076		3,225		320		6,171
Communication		1,100		615		56		541
Administration and Service		1,502		793		23		732
Easements		623		85		—		538
		25,510		9,134		1,025		17,401
December 31, 2013 (millions of Canadian dollars)	Property, Plant and Equipment		Accumulated Depreciation		Construction in Progress		Total
Transmission		12,413		4,215		671		8,869
Distribution		8,498		3,046		316		5,768
Communication		1,060		560		53		553
Administration and Service		1,380		716		38		702
Easements		617		78		—		539
		23,968		8,615		1,078		16,431

Financing charges capitalized on property, plant and equipment under construction were $48 million in 2014 (2013 – $48 million).

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Property, Plant and Equipment - Schedule of Property, Plant and Equipment (Detail) (CAD) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Property, Plant and Equipment [Line Items]
Property, Plant Equipment, Gross	25,510	23,968
Accumulated Depreciation	9,134	8,615
Construction in progress	1,025	1,078
Property, plant and equipment, Total	17,401	16,431
Transmission [Member]
Property, Plant and Equipment [Line Items]
Property, Plant Equipment, Gross	13,209	12,413
Accumulated Depreciation	4,416	4,215
Construction in progress	626	671
Property, plant and equipment, Total	9,419	8,869
Distribution [Member]
Property, Plant and Equipment [Line Items]
Property, Plant Equipment, Gross	9,076	8,498
Accumulated Depreciation	3,225	3,046
Construction in progress	320	316
Property, plant and equipment, Total	6,171	5,768
Communication [Member]
Property, Plant and Equipment [Line Items]
Property, Plant Equipment, Gross	1,100	1,060
Accumulated Depreciation	615	560
Construction in progress	56	53
Property, plant and equipment, Total	541	553
Administration and Service [Member]
Property, Plant and Equipment [Line Items]
Property, Plant Equipment, Gross	1,502	1,380
Accumulated Depreciation	793	716
Construction in progress	23	38
Property, plant and equipment, Total	732	702
Easements [Member]
Property, Plant and Equipment [Line Items]
Property, Plant Equipment, Gross	623	617
Accumulated Depreciation	85	78
Property, plant and equipment, Total	538	539

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Pension and Post-Retirement and Post-Employment Benefits - Components of Net Periodic Benefit Costs (Detail) (CAD) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Pension Plan [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Current service cost, net of employee contributions	110	141
Interest cost	312	278
Expected return on plan assets, net of expenses	(369)	(309)
Actuarial loss amortization	103	175
Prior service cost amortization	2	2
Net periodic benefit costs	158	287
Charged to results of operations	81	72
Post-Retirement and Post-Employment Benefits [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Interest cost	73	63
Actuarial loss amortization	18	27
Prior service cost amortization	2	3
Net periodic benefit costs	134	133
Charged to results of operations	62	58
Current service cost, net of employee contributions	41	40

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Intangible Assets - Schedule of Intangible Assets (Detail) (CAD) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Finite-Lived Intangible Assets [Line Items]
Intangible Assets	578	562
Accumulated Amortization	305	252
Development in Progress	3	3
Total	276	313
Computer Applications Software [Member]
Finite-Lived Intangible Assets [Line Items]
Intangible Assets	573	557
Accumulated Amortization	303	249
Development in Progress	3	3
Total	273	311
Other [Member]
Finite-Lived Intangible Assets [Line Items]
Intangible Assets	5	5
Accumulated Amortization	2	3
Total	3	2

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Environmental Liabilities - Schedule of Movements in Environmental Liabilities (Detail) (CAD) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Environmental Liabilities [Line Items]
Environmental liabilities, Beginning balance	266	249
Interest accretion	11	10
Expenditures	(18)	(16)
Revaluation adjustment	(20)	23
Environmental liabilities, Ending balance	239	266
Less: current portion	18	27
Environmental liabilities non current portion	221	239
PCB [Member]
Environmental Liabilities [Line Items]
Environmental liabilities, Beginning balance	201	197
Interest accretion	9	9
Expenditures	(5)	(2)
Revaluation adjustment	(33)	(3)
Environmental liabilities, Ending balance	172	201
Less: current portion	8	15
Environmental liabilities non current portion	164	186
LAR [Member]
Environmental Liabilities [Line Items]
Environmental liabilities, Beginning balance	65	52
Interest accretion	2	1
Expenditures	(13)	(14)
Revaluation adjustment	13	26
Environmental liabilities, Ending balance	67	65
Less: current portion	10	12
Environmental liabilities non current portion	57	53

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Accounts Receivable - Schedule of Allowance for Doubtful Accounts (Detail) (CAD) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Receivables [Abstract]
Allowance for doubtful accounts beginning balance	(36)	(23)
Write-offs	24	24
Additions to allowance for doubtful accounts	(54)	(37)
Allowance for doubtful accounts ending balance	(66)	(36)

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Pension and Post-Retirement and Post-Employment Benefits - Schedule of Effect of One Percent Change in Health Care Cost Trends on Service Cost and Interest Cost (Detail) (Post-Retirement and Post-Employment Benefits [Member], CAD) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Post-Retirement and Post-Employment Benefits [Member]
Schedule Of Effect Of One Percentage Point Change In Assumed Health Care Cost Trend Rates [Line Items]
Effect of a 1% increase in health care cost trends	23	21
Effect of a 1% decrease in health care cost trends	(17)	(16)

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Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2014

Accounting Policies [Abstract]

Average Service Lives and Depreciation and Amortization Rates

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

	Average		Rate
	Service Life		Range	Average
Transmission		57 years	1% – 2%		2	%
Distribution		42 years	1% – 20%		2	%
Communication		19 years	1% – 15%		4	%
Administration and service		15 years	3% – 20%		7	%

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Description of the Business - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2014
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Date of incorporation	Dec. 01, 1998

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Capital Management

12 Months Ended

Dec. 31, 2014

Text Block [Abstract]

Capital Management

14. CAPITAL MANAGEMENT

The Company’s objectives with respect to its capital structure are to maintain effective access to capital on a long-term basis at reasonable rates, and to deliver appropriate financial returns. In order to ensure ongoing effective access to capital, the Company targets to maintain an “A” category long-term credit rating.

The Company considers its capital structure to consist of Shareholder’s equity, preferred shares, long-term debt, and cash and cash equivalents. At December 31, 2014 and 2013, the Company’s capital structure was as follows:

December 31 (millions of Canadian dollars)	2014		2013
Long-term debt payable within one year		552		756
Less: cash and cash equivalents		100		565
		452		191
Long-term debt		8,373		8,301
Preferred shares		323		323
Common shares		3,314		3,314
Retained earnings		4,249		3,787
		7,563		7,101
Total capital		16,711		15,916

The Company has customary covenants typically associated with long-term debt. Among other things, Hydro One’s long-term debt and credit facility covenants limit the permissible debt to 75% of the Company’s total capitalization, limit the ability to sell assets and impose a negative pledge provision, subject to customary exceptions. At December 31, 2014 and 2013, Hydro One was in compliance with all of these covenants and limitations.

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Segmented Reporting - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2014 Segment
Segment Reporting [Abstract]
Number of reportable segments	3

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Dividends

12 Months Ended

Dec. 31, 2014

Text Block [Abstract]

Dividends

19. DIVIDENDS

In 2014, preferred share dividends in the amount of $18 million (2013 – $18 million) and common share dividends in the amount of $269 million (2013 – $200 million) were declared.

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Pension and Post-Retirement and Post-Employment Benefits - Schedule of Actuarial Gains and Losses and Prior Service Costs Recorded Within Regulatory Assets (Detail) (CAD) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Post-Retirement and Post-Employment Benefits [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Actuarial loss (gain) for the year	(18)	13
Pension Benefits [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Actuarial loss (gain) for the year	821	(63)
Post-Retirement and Post-Employment Benefits [Member] | Post-Retirement and Post-Employment Benefits [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Actuarial loss (gain) for the year	(18)	13
Actuarial loss amortization	(18)	(27)
Prior service cost amortization	(2)	(3)
Total actuarial gains and losses and prior service costs	(38)	(17)
Pension Benefit Regulatory Asset [Member] | Pension Benefits [Member]
Pension Plans, Postretirement and Other Employee Benefits [Line Items]
Actuarial loss (gain) for the year	511	(619)
Actuarial loss amortization	(103)	(175)
Prior service cost amortization	(2)	(2)
Total actuarial gains and losses and prior service costs	406	(796)

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Consolidated Statements of Cash Flows (Tables)

12 Months Ended

Dec. 31, 2014

Supplemental Cash Flow Elements [Abstract]

Schedule of Consolidated Statement of Cash Flows

The changes in non-cash balances related to operations consist of the following:

Year ended December 31 (millions of Canadian dollars)	2014			2013
Accounts receivable		(93	)		(78	)
Due from related parties		(27	)		(43	)
Prepaid expenses and other assets		(13	)		(5	)
Accounts payable		39			13
Accrued liabilities		(35	)		71
Due to related parties		(3	)		(31	)
Accrued interest		—			5
Long-term accounts payable and other liabilities		(3	)		(5	)
Post-retirement and post-employment benefit liability		80			84
		(55	)		11

Capital Expenditures

The following table illustrates the reconciliation between investments in property, plant and equipment and the amount presented in the Consolidated Statements of Cash Flows after factoring in capitalized depreciation and the net change in related accruals:

Year ended December 31 (millions of Canadian dollars)	2014			2013
Capital investments in property, plant and equipment		(1,511	)		(1,312	)
Capitalized depreciation and net change in accruals included in capital investments in property, plant and equipment		30			4
Capital expenditures – property, plant and equipment		(1,481	)		(1,308	)

The following table illustrates the reconciliation between investments in intangible assets and the amount presented in the Consolidated Statements of Cash Flows after factoring in the net change in related accruals:

Year ended December 31 (millions of Canadian dollars)	2014			2013
Capital investments in intangible assets		(19	)		(82	)
Net change in accruals included in capital investments in intangible assets		(4	)		3
Capital expenditures – intangible assets		(23	)		(79	)

Supplementary Information

Year ended December 31 (millions of Canadian dollars)	2014		2013
Net interest paid		412		395
PILs		86		138

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Environmental Liabilities - Additional Information (Detail) (CAD) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Environmental Liabilities [Line Items]
Long-term inflation rate assumption of current costs	2.00%
Reduction of environmental liability due to revaluation adjustment	(20)	23
Minimum [Member]
Environmental Liabilities [Line Items]
Future environmental expenditure discount rate	2.30%
Maximum [Member]
Environmental Liabilities [Line Items]
Future environmental expenditure discount rate	6.30%
PCB [Member]
Environmental Liabilities [Line Items]
Estimated future environmental expenditure	195	237
Reduction of environmental liability due to revaluation adjustment	(33)	(3)
LAR [Member]
Environmental Liabilities [Line Items]
Estimated future environmental expenditure	70	68
Reduction of environmental liability due to revaluation adjustment	13	26

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Intangible Assets (Tables)

12 Months Ended

Dec. 31, 2014

Goodwill and Intangible Assets Disclosure [Abstract]

Schedule of Intangible Assets

December 31, 2014 (millions of Canadian dollars)	Intangible Assets		Accumulated Amortization		Development in Progress		Total
Computer applications software		573		303		3		273
Other		5		2		—		3
		578		305		3		276
December 31, 2013 (millions of Canadian dollars)	Intangible Assets		Accumulated Amortization		Development in Progress		Total
Computer applications software		557		249		3		311
Other		5		3		—		2
		562		252		3		313

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Share Capital - Additional Information (Detail) (CAD) In Millions, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Class of Stock [Line Items]
Common shares, issued	100,000	100,000
Cumulative Preferred Shares [Member]
Class of Stock [Line Items]
Preferred shares, issued	12,920,000
Preferred shares, outstanding	12,920,000
Cumulative preferred shares, percentage	5.50%
Cumulative preferred shares value per share	25
Cumulative preferred shares, total value	323
Preferred shares dividend, amount	18
Preferred shares dividend, per share	1.375
Reduction in Province's holdings of common shares	50.00%
Adjustment of preferred dividend	0.50%
Common Shares [Member]
Class of Stock [Line Items]
Common shares, issued	100,000
Common shares, outstanding	100,000

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Consolidated Balance Sheets (Parenthetical) (CAD) In Millions, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Statement of Financial Position [Abstract]
Allowance for doubtful accounts	66	36
Accumulated Amortization	305	252
Long-term debt payable within one year, fair value	252	506
Long-term debt measured at fair value		256
Preferred shares, issued	12,920,000	12,920,000
Common shares, issued	100,000	100,000

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Pension and Post-Retirement and Post-Employment Benefits - Schedule of Weighted Average Assumptions Used to Determine Benefit Obligations (Parenthetical) (Detail) (Minimum [Member])	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Grading Down in and After 2031 [Member]
Schedule Of Weighted Average Assumption Determining Pension Plan And Other Post retirement Benefit Plan [Line Items]
Assumed health care cost trend, percentage	4.36%	4.39%
2015 [Member]
Schedule Of Weighted Average Assumption Determining Pension Plan And Other Post retirement Benefit Plan [Line Items]
Assumed health care cost trend, percentage	6.52%
2014 [Member]
Schedule Of Weighted Average Assumption Determining Pension Plan And Other Post retirement Benefit Plan [Line Items]
Assumed health care cost trend, percentage		6.81%

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New Accounting Pronouncements

12 Months Ended

Dec. 31, 2014

Accounting Changes and Error Corrections [Abstract]

New Accounting Pronouncements

3. NEW ACCOUNTING PRONOUNCEMENTS

Recently Adopted Accounting Pronouncements

In July 2013, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2013-11, Income Taxes (Topic 740): Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists. This ASU provides guidance on the presentation of unrecognized tax benefits. This ASU is effective for fiscal years, and interim periods within those years, beginning after December 15, 2013, and should be applied prospectively to all unrecognized tax benefits that exist at the effective date. The adoption of this ASU did not have a significant impact on the Company’s consolidated financial statements.

Recent Accounting Guidance Not Yet Adopted

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606). This ASU provides guidance on revenue recognition that depicts the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods and services. This ASU is required to be applied retrospectively and is effective for fiscal years, and interim periods within those years, beginning after December 15, 2016. The Company is currently assessing the impact of adoption of ASU 2014-09 on its consolidated financial statements.

In August 2014, the FASB issued ASU 2014-15, Presentation of Financial Statements – Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern. This ASU provides guidance about management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern and related disclosures. This ASU is effective for the annual period ending December 31, 2016, and for annual and interim periods thereafter. The adoption of this ASU is not anticipated to have a significant impact on the Company’s consolidated financial statements.

In November 2014, the FASB issued ASU 2014-16, Derivatives and Hedging (Topic 815). This ASU provides guidance on accounting for hybrid financial instruments issued in the form of a share. This ASU is effective for fiscal years, and interim periods within those years, beginning after December 15, 2015. The Company is currently assessing the impact of adoption of ASU 2014-16 on its consolidated financial statements.

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Provision for Payments in Lieu of Corporate Income Taxes - Reconciliation between Statutory and Effective Tax Rates (Detail) (CAD) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Reconciliation Of Statutory Federal Tax Rate [Line Items]
Income before provision for PILs	836	912
Net temporary differences included in amounts charged to customers:
Total provision for PILs	89	109
PILs [Member]
Reconciliation Of Statutory Federal Tax Rate [Line Items]
Income before provision for PILs	836	912
Canadian federal and Ontario statutory income tax rate	26.50%	26.50%
Provision for PILs at statutory rate	222	242
Net temporary differences included in amounts charged to customers:
Capital cost allowance in excess of depreciation and amortization	(72)	(72)
Pension contributions in excess of pension expense	(24)	(23)
Overheads capitalized for accounting but deducted for tax purposes	(15)	(14)
Interest capitalized for accounting but deducted for tax purposes	(13)	(13)
Environmental expenditures	(5)	(4)
Prior year's adjustments	(4)	(8)
Non-refundable investment tax credits	(3)	(4)
Post-retirement and post-employment benefit expense in excess of cash payments	3	4
Other	(1)	(1)
Net temporary differences	(134)	(135)
Net permanent differences	1	2
Total provision for PILs	89	109

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Pension and Post-Retirement and Post-Employment Benefits - Change in Projected Benefit Obligation and Change in Plan Assets (Detail) (CAD) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Change in plan assets
Employer contributions	174	160
Pension Benefits [Member]
Change in projected benefit obligation
Projected benefit obligation, beginning of year	6,576	6,507
Current service cost	145	170
Interest cost	312	278
Reciprocal transfers		1
Benefits paid	(319)	(317)
Net actuarial loss (gain)	821	(63)
Projected benefit obligation, end of year	7,535	6,576
Change in plan assets
Fair value of plan assets, beginning of year	5,731	4,992
Actual return on plan assets	703	887
Reciprocal transfers		1
Benefits paid	(319)	(317)
Employer contributions	174	160
Employee contributions	35	30
Administrative expenses	(25)	(22)
Fair value of plan assets, end of year	6,299	5,731
Unfunded status	1,236	845
Post-Retirement and Post-Employment Benefits [Member]
Change in projected benefit obligation
Projected benefit obligation, beginning of year	1,531	1,459
Current service cost	41	40
Interest cost	73	63
Benefits paid	(45)	(44)
Net actuarial loss (gain)	(18)	13
Projected benefit obligation, end of year	1,582	1,531
Change in plan assets
Benefits paid	(45)	(44)
Unfunded status	1,582	1,531

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Asset Retirement Obligations - Additional Information (Detail) (CAD) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Asset Retirement Obligations [Line Items]
Long-term inflation assumption of current costs	2.00%
Asset retirement obligations recorded	9	14
Removal and Disposal of Asbestos [Member]
Asset Retirement Obligations [Line Items]
Asset retirement obligations recorded	8	7
Facility Decommissioning Costs [Member]
Asset Retirement Obligations [Line Items]
Asset retirement obligations recorded	1	7
Number of assets retired in future	2
Minimum [Member]
Asset Retirement Obligations [Line Items]
Discounted future expenditures	3.00%
Maximum [Member]
Asset Retirement Obligations [Line Items]
Discounted future expenditures	5.00%

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Regulatory Assets and Liabilities - Additional Information (Detail) (CAD) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
PILs [Member]
Regulatory Matters [Line Items]
Increase in PILs including the impact of a change in enacted tax rates	132	139
Pension Benefit Regulatory Asset [Member]
Regulatory Matters [Line Items]
Increase (Decrease) in other comprehensive income	(391)	670
Post-Retirement and Post-Employment Benefits [Member]
Regulatory Matters [Line Items]
Increase (Decrease) in other comprehensive income	35	12
PCB Liability [Member]
Regulatory Matters [Line Items]
Regulatory asset increase (decrease)	(33)	(3)
LAR Liability [Member]
Regulatory Matters [Line Items]
Regulatory asset increase (decrease)	13	26
Environmental Expenditure [Member]
Regulatory Matters [Line Items]
Increase (decrease) in operation, maintenance and administration expenses	(20)	23
Increase (decrease) in amortization expense)	(18)	(16)
Increase (decrease) in financing chargers	11	10
Pension Cost Variance [Member]
Regulatory Matters [Line Items]
Increase (decrease) in revenue	(10)	(19)
Retail Settlement Variance Accounts [Member]
Regulatory Matters [Line Items]
Disposition of accumulated balance including accrued interest	24 months
Long-Term Project Development Costs [Member]
Regulatory Matters [Line Items]
Transmission projects identified	20
Accrued interest recovery period	1 year
Hydro One Brampton Networks Rider [Member]
Regulatory Matters [Line Items]
Disposed period of approved balances be aggregated into single regulatory account	2 years
Rider 9 [Member]
Regulatory Matters [Line Items]
Disposition of accumulated balance including accrued interest	24 months

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Related Party Transactions

12 Months Ended

Dec. 31, 2014

Related Party Transactions [Abstract]

Related Party Transactions

20. RELATED PARTY TRANSACTIONS

Hydro One is owned by the Province. The OEFC, IESO, OPA, Ontario Power Generation Inc. (OPG) and the OEB are related parties to Hydro One because they are controlled or significantly influenced by the Province.

The Province

During 2014, Hydro One paid dividends to the Province totalling $287 million (2013 – $218 million).

In November 2014, the Company redeemed the $250 million Province of Ontario Floating-Rate Notes held as a long-term investment. These notes were originally purchased in January 2010 with a maturity date of November 19, 2014.

IESO

In 2014, Hydro One purchased power in the amount of $2,601 million (2013 – $2,477 million) from the IESO-administered electricity market.

Hydro One receives revenues for transmission services from the IESO, based on OEB-approved uniform transmission rates. Transmission revenues for 2014 include $1,556 million (2013 – $1,509 million) related to these services.

Hydro One receives amounts for rural rate protection from the IESO. Distribution revenues for 2014 include $127 million (2013 – $127 million) related to this program.

Hydro One also receives revenues related to the supply of electricity to remote northern communities from the IESO. Distribution revenues for 2014 include $32 million (2013 – $33 million) related to these services.

OPA

The OPA funds substantially all of the Company’s conservation and demand management programs. The funding includes program costs, incentives, and management fees. In 2014, Hydro One received $33 million (2013 – $34 million) from the OPA related to these programs.

OPG

In 2014, Hydro One purchased power in the amount of $23 million (2013 – $15 million) from OPG.

Hydro One has service level agreements with OPG. These services include field, engineering, logistics and telecommunications services. In 2014, revenues related to the provision of construction and equipment maintenance services with respect to these service level agreements were $12 million (2013 – $9 million), primarily for the Transmission Business. Operation, maintenance and administration costs in 2014 related to the purchase of services with respect to these service level agreements were $1 million (2013 – $1 million).

OEFC

In 2014, Hydro One made payments in lieu of corporate income taxes to the OEFC totalling $86 million (2013 – $138 million).

In 2014, Hydro One purchased power in the amount of $9 million (2013 – $8 million) from power contracts administered by the OEFC.

Hydro One pays a $5 million annual fee to the OEFC for indemnification against adverse claims in excess of $10 million paid by the OEFC with respect to certain of Ontario Hydro’s businesses transferred to Hydro One on April 1, 1999.

PILs and payments in lieu of property taxes are paid to the OEFC.

OEB

Under the Ontario Energy Board Act, 1998, the OEB is required to recover all of its annual operating costs from gas and electricity distributors and transmitters. In 2014, Hydro One incurred $12 million (2013 – $12 million) in OEB fees.

Sales to and purchases from related parties occur at normal market prices or at a proxy for fair value based on the requirements of the OEB’s Affiliate Relationships Code. Outstanding balances at period end are interest free and settled in cash.

The amounts due to and from related parties as a result of the transactions referred to above are as follows:

December 31 (millions of Canadian dollars)	2014			2013
Due from related parties		224			197
Due to related parties1		(227	)		(230	)
Investment		—			251

¹  Included in due to related parties at December 31, 2014 are amounts owing to the IESO in respect of power purchases of $214 million (2013 – $217 million).

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Subsequent Event - Additional Information (Detail) (CAD) In Millions, unless otherwise specified	12 Months Ended		0 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Feb. 11, 2015
Subsequent Event [Line Items]
Preferred share dividends declared amount	18	18
Common share dividends declared amount	269	200
Subsequent Event [Member]
Subsequent Event [Line Items]
Preferred share dividends declared amount			4
Common share dividends declared amount			25
Dividends declared, date			Feb. 11, 2015

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Fair Value of Financial Instruments and Risk Management - Summary of Fair Values and Carrying Values of Long-Term Debt (Parenthetical) (Detail) (CAD)	Dec. 31, 2014
$500 Million of MTN Series 19 Notes [Member]
Schedule Of Carrying Values And Estimated Fair Values Of Debt Instruments [Line Items]
Long term debt, face value	500,000,000
$250 Million of MTN Series 21 Notes [Member]
Schedule Of Carrying Values And Estimated Fair Values Of Debt Instruments [Line Items]
Long term debt, face value	250,000,000

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Provision for Payments in Lieu of Corporate Income Taxes (Tables)

12 Months Ended

Dec. 31, 2014

Income Tax Disclosure [Abstract]

Reconciliation between Statutory and Effective Tax Rates

The reconciliation between the statutory and the effective tax rates is provided as follows:

Year ended December 31 (millions of Canadian dollars)	2014			2013
Income before provision for PILs		836			912
Canadian federal and Ontario statutory income tax rate		26.50	%		26.50	%
Provision for PILs at statutory rate		222			242
Increase (decrease) resulting from:
Net temporary differences included in amounts charged to customers:
Capital cost allowance in excess of depreciation and amortization		(72	)		(72	)
Pension contributions in excess of pension expense		(24	)		(23	)
Overheads capitalized for accounting but deducted for tax purposes		(15	)		(14	)
Interest capitalized for accounting but deducted for tax purposes		(13	)		(13	)
Environmental expenditures		(5	)		(4	)
Prior year’s adjustments		(4	)		(8	)
Non-refundable investment tax credits		(3	)		(4	)
Post-retirement and post-employment benefit expense in excess of cash payments		3			4
Other		(1	)		(1	)
Net temporary differences		(134	)		(135	)
Net permanent differences		1			2
Total provision for PILs		89			109

Major Components of Income Tax Expense

The major components of income tax expense are as follows:

Year ended December 31 (millions of Canadian dollars)	2014			2013
Current provision for PILs		79			111
Deferred provision (recovery) for PILs		10			(2	)
Total provision for PILs		89			109
Effective income tax rate		10.63	%		11.98	%

The current provision for PILs is remitted to, or received from, the OEFC. At December 31, 2014, $39 million due from the OEFC was included in due from related parties on the Consolidated Balance Sheet (2013 – $29 million).

Schedule of Deferred Income Tax Assets and Liabilities

At December 31, 2014 and 2013, deferred income tax assets and liabilities consisted of the following:

December 31 (millions of Canadian dollars)	2014			2013
Deferred income tax assets
Post-retirement and post-employment benefits expense in excess of cash payments		8			7
Environmental expenditures		4			5
Depreciation and amortization in excess of capital cost allowance		(4	)		—
Other		(1	)		(1	)
Total deferred income tax assets		7			11
Less: current portion		—			—
		7			11
December 31 (millions of Canadian dollars)	2014			2013
Deferred income tax liabilities
Capital cost allowance in excess of depreciation and amortization		(1,713	)		(1,556	)
Regulatory amounts that are not recognized for tax purposes		(140	)		(144	)
Partnership interest		(38	)		—
Goodwill		(21	)		(20	)
Post-retirement and post-employment benefits expense in excess of cash payments		559			542
Environmental expenditures		59			66
Other		—			1
Total deferred income tax liabilities		(1,294	)		(1,111	)
Less: current portion		19			18
		(1,313	)		(1,129	)

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Fair Value of Financial Instruments and Risk Management

12 Months Ended

Dec. 31, 2014

Fair Value Disclosures [Abstract]

Fair Value of Financial Instruments and Risk Management

13. FAIR VALUE OF FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

Fair value is considered to be the exchange price in an orderly transaction between market participants to sell an asset or transfer a liability at the measurement date. The fair value definition focuses on an exit price, which is the price that would be received in the sale of an asset or the amount that would be paid to transfer a liability.

Hydro One classifies its fair value measurements based on the following hierarchy, as prescribed by the accounting guidance for fair value, which prioritizes the inputs to valuation techniques used to measure fair value into three levels:

Level 1 inputs are unadjusted quoted prices in active markets for identical assets or liabilities that Hydro One has the ability to access. An active market for the asset or liability is one in which transactions for the asset or liability occur with sufficient frequency and volume to provide ongoing pricing information.

Level 2 inputs are those other than quoted market prices that are observable, either directly or indirectly, for an asset or liability. Level 2 inputs include, but are not limited to, quoted prices for similar assets or liabilities in an active market, quoted prices for identical or similar assets or liabilities in markets that are not active and inputs other than quoted market prices that are observable for the asset or liability, such as interest-rate curves and yield curves observable at commonly quoted intervals, volatilities, credit risk and default rates. A Level 2 measurement cannot have more than an insignificant portion of the valuation based on unobservable inputs.

Level 3 inputs are any fair value measurements that include unobservable inputs for the asset or liability for more than an insignificant portion of the valuation. A Level 3 measurement may be based primarily on Level 2 inputs.

Non-Derivative Financial Assets and Liabilities

At December 31, 2014 and 2013, the Company’s carrying amounts of accounts receivable, due from related parties, cash and cash equivalents, bank indebtedness, accounts payable, and due to related parties are representative of fair value because of the short-term nature of these instruments.

Fair Value Measurements of Long-Term Debt

The fair values and carrying values of the Company’s long-term debt at December 31, 2014 and 2013 are as follows:

December 31 (millions of Canadian dollars)	2014 Carrying Value		2014 Fair Value		2013 Carrying Value		2013 Fair Value
Long-term debt
$500 million of MTN Series 19 notes1		—		—		506		506
$250 million of MTN Series 21 notes1		252		252		256		256
Other notes and debentures2		8,673		10,159		8,295		9,018
		8,925		10,411		9,057		9,780

¹  The fair value of $500 million of the MTN Series 19 notes and of $250 million of the MTN Series 21 notes subject to hedging is primarily based on changes in the present value of future cash flows due to a change in the yield in the swap market for the related swap (hedged risk).

² The fair value of other notes and debentures, and the portions of the MTN Series 19 notes and the MTN Series 21 notes that are not subject to hedging, represents the market value of the notes and debentures and is based on unadjusted period-end market prices for the same or similar debt of the same remaining maturities.

Fair Value Measurements of Derivative Instruments

At December 31, 2014, the Company had interest-rate swaps totalling $250 million (2013 – $750 million) that were used to convert fixed-rate debt to floating-rate debt. These swaps are classified as fair value hedges. The Company’s fair value hedge exposure was equal to about 3% (2013 – 8%) of its total long-term debt of $8,925 million (2013 – $9,057 million). At December 31, 2014, the Company had the following interest-rate swaps designated as fair value hedges:

(a) two $125 million fixed-to-floating interest-rate swap agreements to convert $250 million of the $500 million MTN Series 21 notes maturing September 11, 2015 into three-month variable-rate debt.

At December 31, 2014, the Company also had interest-rate swaps with a total notional value of $409 million (2013 – $900 million) classified as undesignated contracts. The undesignated contracts consist of the following interest-rate swaps:

(b) a $150 million floating-to-fixed interest-rate swap agreement that locks in the floating rate the Company pays on a portion of the above fixed-to-floating interest-rate swaps from December 11, 2014 to September 11, 2015;

(c) a $50 million floating-to-fixed interest-rate swap agreement that locks in the floating rate the Company pays on the $50 million floating-rate MTN Series 22 notes from January 24, 2014 to January 24, 2015;

(d) a $137 million floating-to-fixed interest-rate swap agreement that locks in the floating rate the Company pays on the $228 million floating-rate MTN Series 31 notes from December 22, 2014 to December 21, 2015;

(e) a $30 million floating-to-fixed interest-rate swap agreement that locks in the floating rate the Company pays on the $50 million floating-rate MTN Series 27 notes from March 3, 2015 to December 3, 2015;

(f) a $30 million floating-to-fixed interest-rate swap agreement that locks in the floating rate the Company pays on the $50 million floating-rate MTN Series 22 notes from January 26, 2015 to July 24, 2015; and

(g) three interest-rate swaps with a total notional value of $12 million that were assumed as part of the Norfolk Power acquisition. These swaps consist of $8 million and $2 million floating-to-fixed interest-rate swap agreements maturing on September 20, 2029, and a $2 million floating-to-fixed interest-rate swap agreement maturing on September 20, 2019.

Fair Value Hierarchy

The fair value hierarchy of financial assets and liabilities at December 31, 2014 and 2013 is as follows:

December 31, 2014 (millions of Canadian dollars)	Carrying Value		Fair Value		Level 1		Level 2		Level 3
Assets:
Cash and cash equivalents		100		100		100		—		—
Derivative instruments
Fair value hedges – interest-rate swaps		2		2		—		2		—
		102		102		100		2		—
Liabilities:
Bank indebtedness		2		2		2		—		—
Derivative instruments
Undesignated contracts – interest-rate swaps		3		3		—		3		—
Long-term debt		8,925		10,411		—		10,411		—
		8,930		10,416		2		10,414		—
December 31, 2013 (millions of Canadian dollars)	Carrying Value		Fair Value		Level 1		Level 2		Level 3
Assets:
Cash and cash equivalents		565		565		565		—		—
Investment		251		251		—		251		—
Derivative instruments
Fair value hedges – interest-rate swaps		12		12		—		12		—
		828		828		565		263		—
Liabilities:
Bank indebtedness		31		31		31		—		—
Long-term debt		9,057		9,780		—		9,780		—
		9,088		9,811		31		9,780		—

Cash and cash equivalents include cash and short-term investments. At December 31, 2014, short-term investments consisted of bankers’ acceptances and money market funds totalling $nil (2013 – $515 million). The carrying values are representative of fair value because of the short-term nature of these instruments.

The investment at December 31, 2013 represented the Province of Ontario Floating-Rate Notes that matured in November 2014. The fair value of the investment was determined using inputs other than quoted prices that are observable for the asset, with unrecognized gains or losses recognized in financing charges. The Company obtained quotes from an independent third party for the fair value of the investment, who uses the market price of similar securities adjusted for changes in observable inputs such as maturity dates and interest rates.

The fair value of the derivative instruments is determined using inputs other than quoted prices that are observable for these assets. The fair value is primarily based on the present value of future cash flows using a swap yield curve to determine the assumptions for interest rates.

The fair value of the hedged portion of the long-term debt is primarily based on the present value of future cash flows using a swap yield curve to determine the assumption for interest rates. The fair value of the unhedged portion of the long-term debt is based on unadjusted period-end market prices for the same or similar debt of the same remaining maturities.

There were no significant transfers between any of the fair value levels during the years ended December 31, 2014 and 2013.

Risk Management

Exposure to market risk, credit risk and liquidity risk arises in the normal course of the Company’s business.

Market Risk

Market risk refers primarily to the risk of loss that results from changes in commodity prices, foreign exchange rates and interest rates. The Company does not have commodity risk. The Company does have foreign exchange risk as it enters into agreements to purchase materials and equipment associated with capital programs and projects that are settled in foreign currencies. This foreign exchange risk is not material, although the Company could in the future decide to issue foreign currency-denominated debt which would be hedged back to Canadian dollars consistent with its risk management policy. Hydro One is exposed to fluctuations in interest rates as the regulated rate of return for the Company’s Transmission and Distribution Businesses is derived using a formulaic approach that is based on the forecast for long-term Government of Canada bond yields and the spread in 30-year “A”-rated Canadian utility bonds over the 30-year benchmark Government of Canada bond yield. The Company estimates that a 1% decrease in the forecasted long-term Government of Canada bond yield or the “A”-rated Canadian utility spread used in determining the Company’s rate of return would reduce the Transmission Business’ 2014 annual results of operations by approximately $20 million (2013 – $19 million) and Hydro One Networks’ distribution business’ 2014 annual results of operations by approximately $10 million (2013 – $10 million).

The Company uses a combination of fixed and variable-rate debt to manage the mix of its debt portfolio. The Company also uses derivative financial instruments to manage interest-rate risk. The Company utilizes interest-rate swaps, which are typically designated as fair value hedges, as a means to manage its interest rate exposure to achieve a lower cost of debt. In addition, the Company may utilize interest-rate derivative instruments to lock in interest-rate levels in anticipation of future financing. Hydro One may also enter into derivative agreements such as forward-starting pay fixed-interest-rate swap agreements to hedge against the effect of future interest-rate movements on long-term fixed-rate borrowing requirements. Such arrangements are typically designated as cash flow hedges. No cash flow hedge agreements were in existence as at December 31, 2014 or 2013.

A hypothetical 10% increase in the interest rates associated with variable-rate debt would not have resulted in a significant decrease in Hydro One’s results of operations for the years ended December 31, 2014 or 2013.

Fair Value Hedges

For derivative instruments that are designated and qualify as fair value hedges, the gain or loss on the derivative as well as the offsetting loss or gain on the hedged item attributable to the hedged risk are recognized in the Consolidated Statements of Operations and Comprehensive Income. The net unrealized loss (gain) on the hedged debt and the related interest-rate swaps for the years ended December 31, 2014 and 2013 are included in financing charges as follows:

Year ended December 31 (millions of Canadian dollars)	2014			2013
Unrealized loss (gain) on hedged debt		(3	)		(8	)
Unrealized loss (gain) on fair value interest-rate swaps		3			8
Net unrealized loss (gain)		—			—

At December 31, 2014, Hydro One had $250 million (2013 – $750 million) of notional amounts of fair value hedges outstanding related to interest-rate swaps, with assets at fair value of $2 million (2013 – $12 million). During the years ended December 31, 2014 and 2013, there was no significant impact on the results of operations as a result of any ineffectiveness attributable to fair value hedges.

Credit Risk

Financial assets create a risk that a counterparty will fail to discharge an obligation, causing a financial loss. At December 31, 2014 and 2013, there were no significant concentrations of credit risk with respect to any class of financial assets. The Company’s revenue is earned from a broad base of customers. As a result, Hydro One did not earn a significant amount of revenue from any single customer. At December 31, 2014 and 2013, there was no significant accounts receivable balance due from any single customer.

At December 31, 2014, the Company’s provision for bad debts was $66 million (2013 – $36 million). Adjustments and write-offs were determined on the basis of a review of overdue accounts, taking into consideration historical experience. At December 31, 2014, approximately 6% of the Company’s net accounts receivable were aged more than 60 days (2013 – 4%).

Hydro One manages its counterparty credit risk through various techniques including: entering into transactions with highly-rated counterparties; limiting total exposure levels with individual counterparties consistent with the Company’s Board-approved Credit Risk Policy; entering into master agreements which enable net settlement and the contractual right of offset; and monitoring the financial condition of counterparties. In addition to payment netting language in master agreements, the Company establishes credit limits, margining thresholds and collateral requirements for each counterparty. Counterparty credit limits are based on an internal credit review that considers a variety of factors, including the results of a scoring model, leverage, liquidity, profitability, credit ratings and risk management capabilities. The determination of credit exposure for a particular counterparty is the sum of current exposure plus the potential future exposure with that counterparty. The current exposure is calculated as the sum of the principal value of money market exposures and the market value of all contracts that have a positive mark-to-market position on the measurement date. The Company would offset the positive market values against negative values with the same counterparty only where permitted by the existence of a legal netting agreement such as an International Swap Dealers Association master agreement. The potential future exposure represents a safety margin to protect against future fluctuations of interest rates, currencies, equities, and commodities. It is calculated based on factors developed by the Bank of International Settlements, following extensive historical analysis of random fluctuations of interest rates and currencies. To the extent that a counterparty’s margining thresholds are exceeded, the counterparty is required to post collateral with the Company as specified in each agreement. The Company monitors current and forward credit exposure to counterparties both on an individual and an aggregate basis. The Company’s credit risk for accounts receivable is limited to the carrying amounts on the Consolidated Balance Sheets.

Derivative financial instruments result in exposure to credit risk since there is a risk of counterparty default. The credit exposure of derivative contracts, before collateral, is represented by the fair value of contracts at the reporting date. At December 31, 2014, the counterparty credit risk exposure on the fair value of these interest-rate swap contracts was $3 million (2013 – $14 million). At December 31, 2014, Hydro One’s credit exposure for all derivative instruments, and applicable payables and receivables, had a credit rating of investment grade, with five financial institutions as the counterparties. The credit exposure of three of the five counterparties accounted for more than 10% of the total credit exposure of derivative contracts.

Liquidity Risk

Liquidity risk refers to the Company’s ability to meet its financial obligations as they come due. Hydro One meets its short-term liquidity requirements using cash and cash equivalents on hand, funds from operations, the issuance of commercial paper, and the revolving standby credit facility of $1,500 million. The short-term liquidity under the Commercial Paper Program, and anticipated levels of funds from operations should be sufficient to fund normal operating requirements.

At December 31, 2014, accounts payable and accrued liabilities in the amount of $784 million (2013 – $789 million) were expected to be settled in cash at their carrying amounts within the next 12 months.

At December 31, 2014, Hydro One had issued long-term debt in the principal amount of $8,923 million (2013 – $9,045 million). Principal repayments, interest payments and related weighted average interest rates are summarized by the number of years to maturity in the following table:

	Long-term Debt Principal Repayments		Interest Payments		Weighted Average Interest Rate
Years to Maturity	(millions of Canadian dollars)		(millions of Canadian dollars)		(%)
1 year		550		419		2.8
2 years		500		393		4.3
3 years		600		381		5.2
4 years		750		350		2.8
5 years		228		327		1.6
		2,628		1,870		3.5
6 – 10 years		900		1,522		3.6
Over 10 years		5,395		4,373		5.4
		8,923		7,765		4.7

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Pension and Post-Retirement and Post-Employment Benefits - Changes in Fair Value of Financial Instruments Classified in Level 3 (Detail) (Level 3 [Member], CAD) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Level 3 [Member]
Fair Value Of Financial Instruments [Line Items]
Fair value of plan assets, beginning of year	119	106
Realized and unrealized gains	30	23
Purchases	23
Sales and disbursements	(28)	(10)
Fair value of plan assets, end of year	144	119