Document:

EX-4.3

 Exhibit 4.3 
 HYDRO ONE INC. 
 MANAGEMENT’S DISCUSSION AND ANALYSIS 

For the three and six months ended June 30, 2013 and 2012 
 The following Management’s Discussion and Analysis (MD&A) of the financial condition and results of operations should be read together with the unaudited interim consolidated financial statements
and accompanying notes of Hydro One Inc. (the Company) for the three and six months ended June 30, 2013, as well as the Company’s audited consolidated financial statements and accompanying notes, and MD&A, for the fiscal year ended
December 31, 2012. 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 with reference to National Instrument
51-102—Continuous Disclosure Obligations of the Canadian Securities Administrators. 
 RESULTS OF OPERATIONS 

As used in this section, references to increases and decreases, whether in terms of amounts or percentages, are made by comparison of the three and six
months ended June 30, 2013 to the three and six months ended June 30, 2012, respectively. 
 Revenues 

 

																																	
	  	  	Three months ended June 30	 	 	Six months ended June 30	 
	 (millions of dollars)
	  	2013	 	  	2012	 	  	$
Change	 	 	%
Change	 	 	2013	 	  	2012	 	  	$
Change	 	 	%
Change	 
	 Transmission
	  	 	368	  	  	 	370	  	  	 	(2	) 	 	 	(1	) 	 	 	741	  	  	 	731	  	  	 	10	  	 	 	1	  
	 Distribution
	  	 	1,020	  	  	 	974	  	  	 	46	  	 	 	5	  	 	 	2,204	  	  	 	2,065	  	  	 	139	  	 	 	7	  
	 Other
	  	 	15	  	  	 	15	  	  	 	—  	  	 	 	—  	  	 	 	30	  	  	 	31	  	  	 	(1	) 	 	 	(3	) 
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 
		  	 	1,403	  	  	 	1,359	  	  	 	44	  	 	 	3	  	 	 	2,975	  	  	 	2,827	  	  	 	148	  	 	 	5	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 
	 Average Ontario 60-minute peak demand (MW) 1
	  	 	20,668	  	  	 	21,029	  	  	 	(361	) 	 	 	(2	) 	 	 	20,977	  	  	 	20,870	  	  	 	107	  	 	 	1	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 
	 Distribution – units distributed to customers (TWh) 1
	  	 	6.5	  	  	 	6.7	  	  	 	(0.2	) 	 	 	(3	) 	 	 	14.8	  	  	 	14.5	  	  	 	0.3	  	 	 	2	  

  

	1	 System-related
statistics are preliminary 

 Electricity demand generally follows normal weather-related variations, and consequently, our
energy-related revenues, all other things being equal, will tend to be higher in the first and third quarters than in the second and fourth quarters. 
 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 transmission revenues were lower by $2 million, or 1%, in the second
quarter of 2013, but increased by $10 million, or 1%, in the first six months of 2013, compared to the same periods in 2012. 
 On
December 20, 2012, the Ontario Energy Board (OEB) rendered its decision on our 2013 and 2014 transmission rate application. This decision followed extensive review of our evidence submitted for the necessary funding in support of aging critical
infrastructure and investments. The revenue requirement approved for 2013 resulted in no change to rates for the transmission portion of the customer bill compared to previous 2012 OEB-approved rate levels. However, we experienced higher revenues of
$6 million in the quarter and $9 million on a year-to-date basis associated with the OEB’s approval of export service revenues and ancillary services associated with the same decision. 

  
 

 

 HYDRO ONE INC. 
 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) 
 For the three and six months
ended June 30, 2013 and 2012 
  

 The average Ontario 60-minute peak demand was 361 MW lower in the second quarter of 2013 than in the
same period in 2012, resulting in lower revenues of $8 million. This reduction in demand was attributable to milder weather experienced in the second quarter of 2013, compared to 2012. However, the average monthly peak demand was higher during the
first six months of 2013, resulting in increased transmission revenues of $1 million on a year-to-date basis. 
 Distribution

 Our consolidated Distribution Business consists of the separately regulated distribution businesses of our subsidiaries Hydro One
Networks Inc. (Hydro One Networks), Hydro One Brampton Networks Inc., and Hydro One Remote Communities Inc. (Hydro One Remote Communities). Distribution revenues include our distribution tariff and amounts to recover the cost of purchased power used
by the customers of our Distribution Business. Accordingly, our distribution revenues are influenced by the amount of electricity we distribute, the cost of purchased power and our distribution tariff rates. Distribution revenues also include minor
ancillary distribution services revenues, such as fees related to the joint use of our distribution poles by the telecommunications and cable television industries, as well as miscellaneous charges such as those charged for late payments.

 Our distribution revenues increased by $46 million, or 5%, in the second quarter of 2013, and by $139 million, or 7%, in the first six months
of 2013, compared to 2012. These increases are primarily due to the recovery of higher purchased power costs of $44 million and $113 million for the three and six month periods ended June 30, 2013, as described below in the section
“Purchased Power.” 
 Distribution revenues increased by $7 million and $9 million for the three and six months ended June 30,
2013, respectively, related to our placement in service of new smart grid and smart meter investments, which are currently recovered through separate rate mechanisms. 
 On December 14, 2012, the OEB approved new tariff rates effective January 1, 2013, on the basis of its 3rd Generation Incentive Regulation Mechanism (IRM) process. The OEB’s IRM decision
also resulted in higher distribution revenues of $2 million in the second quarter of 2013 and $4 million in the first six months of the year, which will support the maintenance and investment requirements of our distribution system and enable the
safe and reliable delivery of electricity to our customers throughout Ontario. Also as part of its IRM decision, the OEB approved our application for an incremental capital module (ICM) adjustment to our rates, reflecting our placement in service of
certain specific capital investments. This ICM approval resulted in an increase of $2 million to our revenue in the quarter and a $6 million increase in the first six months, compared to the same periods in 2012. 

The impact of these distribution revenue increases was partially offset by lower energy consumption of $4 million in the second quarter resulting
primarily from the milder weather. However, on a year-to-date basis, higher consumption stemming primarily from the colder winter resulted in an increase in distribution revenue of $12 million. 

Lastly, our distribution revenues decreased by $3 million in the quarter and $1 million in the first six months due to regulatory recoveries, and by $2
million in the quarter and $4 million in the first six months associated with external revenues. 
 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 Independent Electricity System Operator’s (IESO) wholesale market service charges, and transmission charges levied by the IESO. The commodity cost
of energy for certain low-volume and designated customers is based on the OEB’s Regulated Price Plan (RPP), which consists of a two-tiered pricing structure with threshold amounts and a separate pricing structure for RPP customers subject to
time-of-use (TOU) billing, both of which are adjusted twice annually. We began transitioning our RPP customers to TOU billing in May 2010, and substantially all of our RPP customers are now subject to TOU billing. We received an exemption from the
OEB, effective until December 31, 2014, from implementing mandatory TOU pricing for approximately 120,000 customers that are currently out of reach of our smart meter telecommunications infrastructure. Customers who are not eligible for the RPP
pay the market price for electricity, adjusted for the difference between market prices and the prices paid to generators under the Electricity Restructuring Act, 2004. A summary of the RPP for the reporting and comparative periods is
provided below. 

  

					
		  	2	  	

 HYDRO ONE INC. 
 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) 
 For the three and six months
ended June 30, 2013 and 2012 
  

																	
	 RPP
	  	Tier Threshold (kWh/month)	 	  	Tier Rates (cents/kWh)	 
	 Effective Date
	  	Residential	 	  	Non-Residential	 	  	First Tier	 	  	Second Tier	 
	 November 1, 2011
	  	 	1,000	  	  	 	750	  	  	 	7.1	  	  	 	8.3	  
	 May 1, 2012
	  	 	600	  	  	 	750	  	  	 	7.5	  	  	 	8.8	  
	 November 1, 2012
	  	 	1,000	  	  	 	750	  	  	 	7.4	  	  	 	8.7	  
	 May 1, 2013
	  	 	600	  	  	 	750	  	  	 	7.8	  	  	 	9.1	  

  

													
	 RPP TOU
	  	Rates (cents/kWh)	 
	 Effective Date
	  	On Peak	 	  	Mid Peak	 	  	Off Peak	 
	 November 1, 2011
	  	 	10.8	  	  	 	9.2	  	  	 	6.2	  
	 May 1, 2012
	  	 	11.7	  	  	 	10.0	  	  	 	6.5	  
	 November 1, 2012
	  	 	11.8	  	  	 	9.9	  	  	 	6.3	  
	 May 1, 2013
	  	 	12.4	  	  	 	10.4	  	  	 	6.7	  

 Purchased power costs increased by $44 million, or 7%, in the second quarter of 2013, and by $113 million, or 8%, in the
first six months of 2013, compared to the same periods in 2012. 
 The increase in our second quarter purchased power costs was primarily due to
an increase of $33 million from higher RPP rates for residential and other eligible customers, $30 million due to higher purchased power costs for customers who are not eligible for the RPP, and a $3 million increase resulting from the IESO’s
Smart Meter Entity Charge, which came into effect May 1, 2013. Our second quarter purchased power costs were partially offset by a $21 million decrease resulting from lower electricity demand and a $1 million reduction in wholesale market
service charges levied by the IESO. 
 The increase in our purchased power costs for the six months ended June 30, 2013 was primarily due
to an increase of $50 million resulting from changes to the RPP rates for residential and other eligible customers, $43 million in higher purchased power costs for customers who are not eligible for the RPP, $18 million due to higher electricity
demand, and $3 million resulting from the new Smart Meter Entity Charge. The increase in our purchased power costs on a year-to-date basis was slightly offset by a $1 million decrease resulting from the OEB transmission rate decision effective
January 1, 2013. 
 Operation, Maintenance and Administration 
 Our operation, maintenance and administration costs consist of labour, materials, equipment and purchased services which support the operation and maintenance of the transmission and distribution systems.
Also included in these costs are property taxes and payments in lieu thereof on our transmission and distribution lines, stations and buildings. 
 Operation, maintenance and administration costs for each of our three business segments were as follows: 
  

																																	
	 	  	Three months ended June 30	 	 	Six months ended June 30	 
	 (millions of dollars)
	  	2013	 	  	2012	 	  	$
Change	 	 	%
Change	 	 	2013	 	  	2012	 	  	$
Change	 	 	%
Change	 
	 Transmission
	  	 	105	  	  	 	102	  	  	 	3	  	 	 	3	  	 	 	177	  	  	 	214	  	  	 	(37	) 	 	 	(17	) 
	 Distribution
	  	 	170	  	  	 	156	  	  	 	14	  	 	 	9	  	 	 	317	  	  	 	296	  	  	 	21	  	 	 	7	  
	 Other
	  	 	16	  	  	 	20	  	  	 	(4	) 	 	 	(20	) 	 	 	30	  	  	 	30	  	  	 	—  	  	 	 	—  	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 
		  	 	291	  	  	 	278	  	  	 	13	  	 	 	5	  	 	 	524	  	  	 	540	  	  	 	(16	) 	 	 	(3	) 
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 

 Our company continues to focus on managing its costs, while continuing to substantially complete our planned work
programs for both our transmission and distribution businesses. 
 Transmission 

Transmission operation, maintenance and administration costs incurred to sustain our high-voltage transmission stations, lines and rights-of-way,
increased by $3 million, or 3%, to $105 million in the second quarter of 2013, and decreased by $37 million, or 17%, to $177 million in the first six months of 2013, compared to the same periods in 2012. Within our work programs, we continued to
invest in the safe and reliable operation of our transmission system that spans Ontario. Our work program costs were comparable in the second quarter of 2013 and decreased by $4 million in the first six months of 2013, 

  

					
		  	3	  	

 HYDRO ONE INC. 
 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) 
 For the three and six months
ended June 30, 2013 and 2012 
  

 compared to 2012. During the second quarter and year-to-date periods, we incurred lower expenditures
related to the Ontario Power Authority’s (OPA) recommendation to increase short circuit and/or transformer capacity at ten of our transmission stations to enable the connection of small renewable projects, as this work was substantially
completed by the end of 2012. Expenditures for these station upgrades were recorded within operation, maintenance and administration rather than as capital expenditures, given that recovery was restricted pursuant to a shareholder declaration made
on April 19, 2011. Offsetting this decrease in the quarter were higher expenditures related to our forestry work program on our transmission rights of way, as we experienced higher tree densities, and higher expenditures relating to increased
power equipment refurbishment work. Expenditures in support of our transmission system increased by $3 million in the second quarter of 2013 but decreased by $33 million in the first six months, compared to 2012. In the second quarter, we
experienced an increase in minor IT requirements and ancillary services. These increases were more than offset in the year-to-date period by a reduction to our provision for payments in lieu of property taxes related to transmission stations for the
years 1999 to 2012, inclusive, following the finalization of the related regulations and receipt of an assessment of our property tax returns. 

Distribution 

Distribution operation, maintenance and administration costs required to maintain our low-voltage distribution system increased by $14 million, or 9%, to
$170 million in the second quarter of 2013, and by $21 million, or 7%, to $317 million in the first six months of 2013, compared to 2012. Our work program expenditures increased by $7 million in the second quarter, and by $12 million in the first
six months, mainly as a result of: increased power restoration expenditures following a major storm that hit Southern Ontario on April 12, 2013; increased customer driven work related to trouble calls and cable locates; and higher requirements
within our meter replacement and line patrol programs. These impacts were partially offset by lower forestry expenditures in the first six months reflecting a later start to our Brush Control Program due to unfavourable winter weather conditions
compared to last year. Our expenditures in support of our distribution system increased by $7 million in the second quarter of 2013, and by $9 million in the first six months, a result of the Customer Information System (CIS) phase of our
entity-wide information system replacement and improvement project, which was successfully placed in service in May, 2013. 
 Depreciation
and Amortization 
 Depreciation and amortization expense increased by $2 million, or 1%, to $160 million in the second quarter and by $11
million, or 4%, to $321 million in the first six months compared to the same periods last year. The increases were mainly attributable to higher depreciation expense of $2 million in the quarter and $8 million year-to-date related to our placement
of new assets in service, consistent with our ongoing capital work program, partially offset by the implementation of new depreciation rates. Higher asset removal costs of $2 million and $4 million in the quarter and year-to-date periods,
respectively, also contributed to the increase. These increases were partially offset by lower amortization associated with certain regulatory accounts of $2 million and $1 million, in the quarter and first six months, respectively. 

Financing Charges 
 Financing charges in
the quarter decreased by $1 million, or 1%, to $89 million compared to the same period in 2012, but increased by $4 million, or 2%, to $177 million for the year-to-date period. Increases primarily resulted from lower interest capitalization of $2
million in the quarter and $7 million year-to-date, reflecting a lower average level of construction in progress and a reduction in the interest capitalization rate used. Also contributing to the increase in the first six months was a $1 million
reduction in the level of interest income and higher miscellaneous financing charges of $1 million. The impact of these increases was more than offset in the quarter, and partially offset in the first six months, by lower interest expense related to
our long-term debt of $3 million in the quarter and $5 million year-to-date, resulting from a lower average effective interest rate, partially offset by a higher average level of debt. 
 Provision for Payments in Lieu of Corporate Income Taxes 
 The provision for payments in
lieu of corporate income taxes decreased by $13 million, or 54%, to $11 million in the second quarter and by $10 million, or 18%, to $46 million on a year-to-date basis, compared to the same periods last year. In the quarter and on a year-to-date
basis, the decrease primarily resulted from changes in net temporary differences, such as capital cost allowance in excess of depreciation and amortization, as well as a prior year adjustment related to scientific research and development
activities. This was partially offset in the year-to-date period by the impact of higher levels of pre-tax income. 

  

					
		  	4	  	

 HYDRO ONE INC. 
 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) 
 For the three and six months
ended June 30, 2013 and 2012 
  

 Net Income 
 Net income was $168 million for the second quarter and $425 million for the first six months of 2013, $1 million, or 1%, lower than our comparable 2012 net income in the quarter and $46 million, or 12%,
higher in the first six months. We experienced higher distribution revenues mainly reflecting increased purchased power costs, primarily related to the OEB’s regulated price plan rate-setting process and the IESO’s spot market. Our net
income was also positively impacted by lower operation, maintenance and administration expense primarily resulting from a reduction to our provision for payments in lieu of transmission station property taxes in the first quarter following the
finalization of the assessment of certain prior years’ property tax returns. 
 QUARTERLY RESULTS OF OPERATIONS 

The following table sets forth unaudited quarterly information for each of the eight quarters from the quarter ended September 30, 2011 through
June 30, 2013. This information has been derived from our unaudited interim Consolidated Financial Statements and our audited annual Consolidated Financial Statements, which include all adjustments, consisting only of normal recurring
adjustments, necessary for fair presentation of our financial position and results of operations for those periods. These operating results are not necessarily indicative of results for any future period and should not be relied upon to predict our
future performance. 
  

																																	
	 (millions of dollars)
	  	2013	 	  	2012	 	  	2011	 
	 Quarter ended
	  	Jun. 30	 	  	Mar. 31	 	  	Dec. 31	 	  	Sep. 30	 	  	Jun. 30	 	  	Mar. 31	 	  	Dec. 31	 	  	Sep. 30	 
	 Total revenue
	  	 	1,403	  	  	 	1,572	  	  	 	1,435	  	  	 	1,466	  	  	 	1,359	  	  	 	1,468	  	  	 	1,359	  	  	 	1,384	  
	 Net income
	  	 	168	  	  	 	257	  	  	 	165	  	  	 	201	  	  	 	169	  	  	 	210	  	  	 	120	  	  	 	167	  
	 Net income to common shareholder
	  	 	163	  	  	 	253	  	  	 	160	  	  	 	197	  	  	 	164	  	  	 	206	  	  	 	115	  	  	 	163	  

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

 

																	
	 	  	Three months ended June 30	 	 	Six months ended June 30	 
	 (millions of dollars)
	  	2013	 	 	2012	 	 	2013	 	 	2012	 
	 Operating activities
	  	 	333	  	 	 	217	  	 	 	475	  	 	 	454	  
	 Financing activities
	  				 				 				 			
	 Long-term debt issued
	  	 	—  	  	 	 	425	  	 	 	—  	  	 	 	725	  
	 Short-term notes payable
	  	 	44	  	 	 	—  	  	 	 	118	  	 	 	—  	  
	 Dividends paid
	  	 	(30	) 	 	 	(30	) 	 	 	(159	) 	 	 	(311	) 
	 Investing activities
	  				 				 				 			
	 Capital expenditures
	  	 	(351	) 	 	 	(350	) 	 	 	(621	) 	 	 	(667	) 
	 Other financing and investing activities
	  	 	(5	) 	 	 	2	  	 	 	(8	) 	 	 	(4	) 
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Net change in cash and cash equivalents
	  	 	(9	) 	 	 	264	  	 	 	(195	) 	 	 	197	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 

 Operating Activities 
 Net cash from operating activities increased by $116 million, to $333 million, in the second quarter of 2013, and by $21 million, to $475 million, in the first six months of 2013, compared to 2012. The
increase in the second quarter of 2013 was primarily due to a prepayment of pension plan contributions in the first quarter of 2013, as compared to a similar prepayment made in the second quarter of 2012, as well as changes in payable balances
mainly related to capital projects. The increase in 

  

					
		  	5	  	

 HYDRO ONE INC. 
 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) 
 For the three and six months
ended June 30, 2013 and 2012 
  

 
the first six months of 2013 was primarily due to higher net income compared to the prior year, as well as changes in payable balances mainly related to timing of tax payments and to capital
projects. The increase was partially offset by growth in accounts receivable balances resulting from higher revenues and purchased power costs in the period. 
 Financing Activities 
 Short-term liquidity is provided through funds from operations, our
Commercial Paper Program, under which we are authorized to issue up to $1,000 million in short-term notes with a term to maturity of less than 365 days, our revolving credit facility, and through our holding of Province of Ontario Floating-Rate
Notes. 
 Our Commercial Paper Program is supported by a total of $1,750 million in liquidity facilities comprised of our $1,500 million
committed revolving credit facility with a syndicate of banks, which matures in June 2018, and our investment in Province of Ontario Floating-Rate Notes of $250 million (with a fair value of $251 million at June 30, 2013). The short-term
liquidity under this program and anticipated levels of funds from operations should be sufficient to fund our normal operating requirements. 

As at June 30, 2013, we had $8,460 million in long-term debt outstanding, including the current portion. Our notes and debentures mature between
2013 and 2062. Long-term financing is provided by our access to the debt markets, primarily through our Medium-Term Note (MTN) Program. The maximum authorized principal amount of medium-term notes issuable under this program is $3,000 million. As at
June 30, 2013, $1,515 million remained available until September 2013. 
  

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

  

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

 We have the customary covenants normally
associated with long-term debt. Among other things, our long-term debt covenants limit our permissible debt as a percentage of our total capitalization, limit our ability to sell assets, and impose a negative pledge provision, subject to customary
exceptions. The credit agreements related to our credit facilities have no material adverse change clauses that could trigger default. However, the credit agreements require that we provide notice to the lenders of any material adverse change within
three business days of the occurrence. The agreements also provide limitations that debt cannot exceed 75% of total capitalization and that third party debt issued by our subsidiaries cannot exceed 10% of the total book value of our assets. We were
in compliance with all these covenants and limitations as at June 30, 2013. 
 In the first six months of 2013, we did not issue any
long-term debt under our MTN Program. In the second quarter and first six months of 2012, we issued $425 million and $725 million, respectively, in long-term debt under our MTN Program. There were no debt maturities in the first six months of 2013
and 2012. We had $118 million short-term notes outstanding as at June 30, 2013, but none as of June 30, 2012. 
 Common dividends are
declared at the sole discretion of our Board of Directors, and are recommended by management based on results of operations, maintenance of the deemed regulatory capital structure, financial condition, cash requirements, and other relevant factors
such as industry practice and shareholder expectations. Common dividends pertaining to our quarterly financial results are generally declared and paid in the immediately following quarter. 
 In the second quarter of 2013, we paid dividends to the Province of Ontario (Province) in the amount of $30 million, consisting of $25 million in common dividends and approximately $5 million in preferred
dividends. In the second quarter of 2012, we paid common dividends of $25 million and preferred dividends of approximately $5 million. 
 In the
first six months of 2013, we paid dividends to the Province in the amount of $159 million, consisting of $150 million in common dividends and $9 million of preferred dividends. In the first six months of 2012, we paid common dividends of $302
million and preferred dividends of $9 million. 

  

					
		  	6	  	

 HYDRO ONE INC. 
 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) 
 For the three and six months
ended June 30, 2013 and 2012 
  

 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 

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

																																	
	 	  	Three months ended June 30	 	 	Six months ended June 30	 
	 (millions of dollars)
	  	2013	 	  	2012	 	  	$
Change	 	 	%
Change	 	 	2013	 	  	2012	 	  	$
Change	 	 	%
Change	 
	 Transmission
	  	 	157	  	  	 	189	  	  	 	(32	) 	 	 	(17	) 	 	 	306	  	  	 	376	  	  	 	(70	) 	 	 	(19	) 
	 Distribution
	  	 	192	  	  	 	161	  	  	 	31	  	 	 	19	  	 	 	312	  	  	 	288	  	  	 	24	  	 	 	8	  
	 Other
	  	 	2	  	  	 	—  	  	  	 	2	  	 	 	100	  	 	 	3	  	  	 	3	  	  	 	—  	  	 	 	—  	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 
		  	 	351	  	  	 	350	  	  	 	1	  	 	 	—  	  	 	 	621	  	  	 	667	  	  	 	(46	) 	 	 	(7	) 
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 

 Transmission 
 Transmission capital expenditures decreased by $32 million, or 17%, to $157 million in the second quarter of 2013, and by $70 million, or 19%, to $306 million in the first six months of 2013, compared to
the same periods last year. Investments to expand and reinforce our transmission system were $43 million in the second quarter and $83 million for the first six months of 2013, representing respective reductions of $30 million and $83 million,
compared to 2012. The majority of these decreases were related to the successful completion of our Bruce to Milton Transmission Reinforcement Project to connect refurbished nuclear and new wind generation sources in the Huron-Grey-Bruce area. This
project was successfully declared in-service in May 2012. In addition, we experienced lower expenditures during the quarter as a result of completing our Commerce Way Transformer Station, a new load supply station in the City of Woodstock to address
load growth issues in the Woodstock area. This project was successfully declared in-service in February, 2013. 
 During both the second quarter
and year-to-date periods, we continued to invest in inter-area network projects to support the Province’s supply mix objectives for generation and in load customer connections and local area supply projects to address growing loads. Our local
area supply project expenditures include investments in our Midtown Electricity Infrastructure Renewal Project which will provide additional supply capability to meet future load growth in midtown Toronto as well as areas to the west. Work is
progressing at our Hearn Switching Station where we are rebuilding an existing switchyard that has reached its end-of-life. This project will also increase short circuit capability to accommodate future connection of renewable generation in central
and downtown Toronto. We are also constructing our West of London Transmission Reinforcement Project to increase transmission capability between our Lambton (Sarnia) and Longwood (London) transformer stations. This project is needed to enable the
incorporation of 10,700 MW of non-hydroelectric renewable generation resources by 2018, consistent with government policy. 
 Expenditures to
sustain our existing transmission system were $104 million in the second quarter, which was unchanged from the prior year, and $207 million in the first six months of 2013, representing an increase of $21 million compared to the same period in 2012.
We experienced increased expenditures both in the quarter and year-to-date periods related to the refurbishment and replacement of end-of-life equipment for overhead lines and protection and control equipment in order to improve reliability. We also
continued work on replacing end-of-life underground transmission cables between our Strachan Transformer Station and Riverside Junction. These new underground cables will maintain a reliable supply of electricity to downtown Toronto. Offsetting the
increased expenditures in the quarter were lower expenditures associated with the timing of work on the refurbishment and replacement of end-of-life transformers. 
 Our other transmission capital expenditures were $10 million in the second quarter and $16 million in the first six months of 2013, representing decreases of $2 million and $8 million respectively,
compared to 2012. The reductions were mainly due to lower investments in IT-related initiatives, including our entity-wide information system replacement and improvement project. These decreases were partially offset by increased fleet acquisitions
during the second quarter. 

  

					
		  	7	  	

 HYDRO ONE INC. 
 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) 
 For the three and six months
ended June 30, 2013 and 2012 
  

 Distribution 
 Our distribution capital expenditures increased by $31 million, or 19%, to $192 million in the second quarter, and by $24 million, or 8%, to $312 million in the first six months of 2013, compared to the
same periods in 2012. 
 Capital investments to expand and reinforce our distribution network were $71 million in the second quarter and $114
million in the first six months of 2013, representing decreases of $7 million and $19 million, respectively, compared to 2012. We experienced reduced expenditures related to our Advanced Distribution Solution (ADS) Project, as we successfully
completed the deployment of our Distribution Management System within our Owen Sound pilot area last year. During both the quarterly and year-to-date periods, we also experienced a lower demand for new customer connections and upgrades. These
impacts were partially offset by increased requirements to reinforce our distribution system compared to the same periods last year. We also continued to invest in our Smart Meter Project, which is focusing on network tuning to improve meter
communication performance and completing final core product updates to the Smart Metering Network system software. 
 Expenditures to sustain
our distribution system were $81 million in the second quarter and $132 million in the first six months of 2013, representing increases of $18 million and $24 million respectively compared to 2012, primarily due to increased expenditures for
component replacements related to storm restoration work resulting from a major storm that hit Ontario on April 12, 2013, increased work within our wood pole replacement program, and higher requirements for meter replacements, partially offset
by lower other work within our lines programs. The year-to-date variance was also impacted by the timing of customer contribution payments received last year in respect of work for joint use and relocation of our lines. 

Our other distribution capital expenditures were $40 million in the second quarter and $66 million for the first six months of 2013, representing
increases of $20 million and $19 million, respectively, compared to last year. The majority of these expenditures were related to the CIS phase of our entity-wide information system replacement and improvement project, which was successfully placed
into service in May, 2013. In addition to replacing end-of-life systems, this implementation will result in process improvements that are expected to provide many benefits including enhancements to customer satisfaction through reduced call times
and first call resolution of issues given faster availability of information. Productivity savings are also anticipated to result from performance improvements, consolidation of IT systems, and decommissioning of over a dozen legacy IT systems.

 Future Capital Expenditures 
  

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

 Excluding our pending acquisition of Norfolk Power Inc. (Norfolk Power), our capital expenditures for 2013 are currently
anticipated to be lower than budget by approximately $160 million mainly due to unavailability of long lead materials and changes in costs and timing of certain large transmission development programs and projects, partially offset by an anticipated
increase to our distribution capital expenditures. 

  

					
		  	8	  	

 HYDRO ONE INC. 
 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) 
 For the three and six months
ended June 30, 2013 and 2012 
  

 On February 28, 2011, the OEB issued a decision amending Hydro One Networks’ transmission
licence in accordance with a directive from the Minister of Energy to the OEB. The licence amendment requires Hydro One Networks to develop and either seek approvals for, or implement, specified transmission projects and transformer station upgrades
to safely and reliably accommodate additional renewable energy in accordance with recommendations from the OPA. On April 7, 2011, the OPA provided the scope and timing to increase short circuit and/or transformer capacity at ten of 15
transformer stations. Seven of these station upgrades have now been completed. Expenditures for these station upgrades were recorded within operation, maintenance and administration expense rather than as capital expenditures, given that recovery
was restricted pursuant to a declaration made by our Shareholder, the Province, on April 19, 2011. Alternative solutions have been identified for the other three station upgrades. In June 2011, the OPA recommended the scope and timing of one of
the three priority specified transmission projects, the West of London Transmission Upgrade Project, with a required in-service date of December 2014. This project generally requires restringing conductor on existing towers along an existing
right-of-way and will enable the connection of additional renewable generation in the west of London area. It is needed to satisfy government policy relating to the incorporation of 10,700 MW of non-hydroelectric renewable generation resources by
2018. In October 2011, the OPA recommended the scope and timing of a second priority specified transmission project, the Southwestern Ontario Reactive Compensation Priority Project, that will increase the transmission capability of the Bruce
transmission system. Both of these projects are reflected in our budgeted capital expenditures. On April 17, 2013, we received a letter from the OPA notifying that the need and/or timing of the Southwestern Ontario Reactive Compensation
Priority Project may be deferred until further notice. An OPA recommendation regarding the third priority specified transmission project, construction of a new transmission line west of the City of London, is not expected in the foreseeable future
and is not included in our budgeted capital expenditures. 
 In August 2010, the OEB introduced a framework for competitive designation for the
development of eligible transmission projects. As a result, we did not include in our budgeted capital expenditures any projects that could meet the definition of expansions under the OEB’s competitive framework. We do not plan to undertake
large capital expenditures without a reasonable expectation of recovering them in our rates. 
 The actual timing and expenditures of many
development projects are uncertain as they are dependent upon: various approvals including OEB leave to construct approvals and environmental assessment approvals; negotiations with customers, neighbouring utilities and other stakeholders; and
consultations with First Nations and Métis communities. Projects are also dependent on the timing and level of generator contributions for enabling facilities. 
 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. 
  

																					
	 June 30, 2013 (millions of dollars)
	  	Total	 	  	20131	 	  	2014/2015	 	  	2016/2017	 	  	After 2017	 
	 Contractual Obligations (due by year)
	  				  				  				  				  			
	 Short-term notes payable
	  	 	118	  	  	 	118	  	  	 	—  	  	  	 	—  	  	  	 	—  	  
	 Long-term debt – principal repayments
	  	 	8,460	  	  	 	600	  	  	 	1,300	  	  	 	1,100	  	  	 	5,460	  
	 Long-term debt – interest payments
	  	 	7,132	  	  	 	205	  	  	 	735	  	  	 	651	  	  	 	5,541	  
	 Pension2
	  	 	172	  	  	 	—  	  	  	 	172	  	  	 	—  	  	  	 	—  	  
	 Environmental and asset retirement obligations3
	  	 	304	  	  	 	21	  	  	 	73	  	  	 	40	  	  	 	170	  
	 Inergi LP (Inergi) outsourcing agreement4
	  	 	219	  	  	 	67	  	  	 	152	  	  	 	—  	  	  	 	—  	  
	 Operating lease commitments
	  	 	51	  	  	 	6	  	  	 	16	  	  	 	15	  	  	 	14	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Total Contractual Obligations
	  	 	16,456	  	  	 	1,017	  	  	 	2,448	  	  	 	1,806	  	  	 	11,185	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Other Commercial Commitments (by year of expiry)
	  				  				  				  				  			
	 Bank line5
	  	 	1,500	  	  	 	—  	  	  	 	—  	  	  	 	—  	  	  	 	1,500	  
	 Letters of credit6
	  	 	133	  	  	 	127	  	  	 	6	  	  	 	—  	  	  	 	—  	  
	 Guarantees6
	  	 	326	  	  	 	326	  	  	 	—  	  	  	 	—  	  	  	 	—  	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Total Other Commercial Commitments
	  	 	1,959	  	  	 	453	  	  	 	6	  	  	 	—  	  	  	 	1,500	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 

  

	1	 The amounts
disclosed represent the amounts due over the period July 1, 2013 to December 31, 2013. 

	2	 Contributions to
the Hydro One Pension Fund are generally made one month in arrears. The 2013 and 2014 minimum contributions are based on an actuarial valuation filed in May 2012 and effective December 31, 2011. Based on expected levels of 2013 pensionable
earnings, our total 2013 annual 

  

					
		  	9	  	

 HYDRO ONE INC. 
 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) 
 For the three and six months
ended June 30, 2013 and 2012 
  

	 	
pension contributions of approximately $160 million were paid in the first quarter of 2013. Future minimum contributions beyond 2014 will be based on an actuarial valuation effective no later
than December 31, 2014, and will depend on future investment returns, changes in benefits or actuarial assumptions. Pension contributions beyond 2014 are not estimable at this time. 

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

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

	5 	 On May 31, 2013, we increased the size of the revolving standby credit facility used to support our liquidity requirements from $1,250 million to
$1,500 million and extended the maturity date from June 2017 to June 2018. 

	6 	 We currently have outstanding bank letters of credit of $127 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. As at June 30, 2013, we have provided letters of credit to the IESO in the amount of $5 million to meet our current
prudential requirement. In addition, we have approximately $1 million pertaining to operating letters of credit. We have also provided prudential support to the IESO on behalf of our subsidiaries as required by the IESO’s Market Rules, using
parental guarantees of up to a maximum of $325 million, and on behalf of two distributors using guarantees of up to approximately $1 million. 

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

RELATED PARTY TRANSACTIONS 
 Related
party transactions primarily consist of our transmission revenues received from, and our power purchases payments made to the IESO, which is a related party by virtue of its status as an agency of the Province. The year-over-year changes related to
these amounts are described more fully in the discussion of our transmission revenues and purchased power costs. Other significant related party transactions include our dividends, which are paid to the Province, and our payments in lieu of
corporate income taxes (PILs) and some of our payments in lieu of property taxes, which are paid to the Ontario Electricity Financial Corporation. In January 2010, we purchased $250 million of Province of Ontario Floating-Rate Notes, maturing on
November 19, 2014, as a form of alternate liquidity to supplement our bank credit facilities. 
 CONSIDERATIONS OF CURRENT ECONOMIC
CONDITIONS 
 Pension 

During the first six months of 2013, we contributed approximately $160 million to our pension plan and incurred $146 million in net periodic pension
benefit cost based on an actuarial valuation effective December 31, 2011 that was filed in May of 2012. Actuarial valuations are minimally required to be filed every three years. We currently estimate our total annual pension contributions to
be approximately $160 million for each of 2013 and 2014 based on the projected level of pensionable earnings and the same actuarial valuation effective December 31, 2011. Future minimum contributions beyond 2014 will be based on the actuarial
valuation effective no later than December 31, 2014. Our pension plan experienced positive returns of 6.57% during the six months ended June 30, 2013. 

  

					
		  	10	  	

 HYDRO ONE INC. 
 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) 
 For the three and six months
ended June 30, 2013 and 2012 
  

 INTERNATIONAL FINANCIAL REPORTING STANDARDS (IFRS) 

In 2011, the Ontario Securities Commission and our Board of Directors approved our application to adopt US GAAP as the basis for our accounting,
external financial reporting and periodic securities filings, without us becoming a Securities and Exchange Commission registrant, for our 2012, 2013 and 2014 fiscal years. Prior to our adoption of US GAAP as the basis for our accounting,
external financial reporting and periodic securities filings, we had planned to adopt IFRS effective January 1, 2012, with comparative restatement of our 2011 results. Accordingly, by mid-2011, we had substantively completed our four-phase IFRS
conversion project, which included separate diagnostic, design and planning, solution development, and implementation phases. Our IFRS conversion project involved, among other initiatives, a detailed assessment of the effects of IFRS on our
financial statements, a review and upgrade of our information systems to meet IFRS requirements, an assessment of our internal controls over financial reporting and disclosure controls and processes, as well as training of our key finance and
operational staff. 
 As a result of our 2011 decision to adopt US GAAP, our IFRS conversion project efforts were effectively halted.
However, our IFRS conversion work has been, and will continue to be, managed in such a way that it can effectively be restarted if a future transition to IFRS is required. We continue to monitor major accounting developments arising from initiatives
of the international standard setter, particularly as several major projects are joint efforts with the US Financial Accounting Standards Board. 
 Training of our key finance and operational staff commenced in 2007, and continues on a reduced but on-going basis, as we have certain subsidiaries that are required to prepare their separate financial
statements in accordance with IFRS. IFRS training was also previously provided to our Audit and Finance Committee and senior executive management. In 2013, we continue to provide IFRS training to specific staff with a focus on new IFRS accounting
and reporting developments and emerging issues. 
 Our company has the customary financial covenants normally associated with long-term debt.
Among other things, our long-term debt covenants limit our permissible debt as a percentage of our total capitalization. Depending on the outcome of various international standard setting initiatives, including the Rate-Regulated Activities Project,
a future adoption of IFRS could result in changes to our financial position and increased volatility in our results of operations that could impact our debt covenants. We continue to monitor the potential impact that an IFRS conversion could have
under various scenarios. On April 25, 2013, the International Financial Accounting Standards Board published for comment an Exposure Draft (ED) on Regulatory Deferral Accounts as part of its Rate-Regulated Activities Project. This proposed
interim standard for regulatory deferral accounts would permit an entity adopting IFRS to continue to use its previous GAAP accounting policies, as accepted in their local jurisdiction, for the recognition, measurement and impairment of regulatory
deferral account balances. The ED is open for comment until September 4, 2013. 
 As part of our company-wide information systems
improvement project, many of our major financial systems were replaced in 2008 and 2009. Our new financial systems were designed with maximum flexibility given the uncertainty of the outcome of certain impactive International Accounting Standards
Board projects. Our financial systems have the ability and capacity to handle current accounting and reporting processes in accordance with IFRS, should that be required in the future. 
 DISCLOSURE CONTROLS AND INTERNAL CONTROLS OVER FINANCIAL REPORTING 
 To optimize our
customer service operations, we have successfully implemented the Customer Information System (CIS) module of SAP. This new system will increase productivity by replacing multiple legacy applications currently providing service to our distribution
customers and key constituents for billing, customer contacts, field services, settlements and customer choice administration. Internal controls have been documented and successfully tested for adequacy and effectiveness. In addition to the benefits
associated with our CIS, we continue to leverage our other SAP enterprise systems to gain other productivity improvements. 
 In compliance with
the requirements of National Instrument 52-109, Certification of Disclosure in Issuers’ Annual and Interim Filings, our Certifying Officers have reviewed and certified the unaudited interim Consolidated Financial Statements for the
period ended June 30, 2013, together with other financial information included in our quarterly securities filings. Our Certifying Officers have also certified that disclosure controls and procedures have been designed to provide reasonable

  

					
		  	11	  	

 HYDRO ONE INC. 
 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) 
 For the three and six months
ended June 30, 2013 and 2012 
  

 assurance that material information relating to our company is made known within our company. Further,
our Certifying Officers have also certified that internal controls over financial reporting have been designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the unaudited interim Consolidated
Financial Statements. 
 RECENT DEVELOPMENTS 
 East-West Tie Proceeding 
 On August 7, 2013, the OEB rendered its decision in
the East-West Tie Line Designation proceeding after a public hearing was held to select a designated transmitter from six competing proposals. EWT LP, an equally shared partnership between Great Lakes Transmission, Bamkushwada LP (involving a number
of First Nations in the area of the East-West Tie), and our company, was not selected as the transmitter to complete the development work for the East-West Tie Line. 
 Renewed Regulatory Framework 
 Performance Measurement and Continuous Improvement

 On July 4, 2013, the OEB posted its Staff Report to the Board on Performance Measurement and Continuous Improvement for Electricity
Distributors. The report outlines the recommendations in relation to performance standards, measures, and the development of an electricity distributor scorecard. The OEB has requested stakeholder comments on the report to be filed by
August 12, 2013. 
 Smart Grid Advisory Committee 
 On June 27, 2013, the OEB announced the creation of the Smart Grid Advisory Committee. The committee will provide the OEB with ongoing assistance on emerging smart grid issues. The committee will
initially focus on smart grid matters identified in the February 11, 2013 Supplemental Report on Smart Grid. Specifically, it will focus on: the emergence of standard data access mechanisms; the deployment of smart grid technologies;
cyber-security; and interoperability among distributors. Membership will initially be composed of participants from the Smart Grid Working Group, including Hydro One Networks. 
 Electricity Reporting and Record Keeping Requirements (RRR) 
 On June 13, 2013, the OEB
issued amendments to its RRR including: improved definitions; a requirement for distributors to report whether any new reliability measuring and reporting practices, or the introduction of any new technologies, impacted the ability to compare
performance results from year to year; a requirement for distributors to report details on the cause of interruptions; and the removal of the reporting requirements related to the Customer Average Interruption Duration Index and the Momentary
Average Interruption Frequency Index. 
 OPA Licence 
 On June 3, 2013, the OEB provided notice of its intent to amend the licence of the OPA to address the OPA’s obligations in the regional planning process in Ontario. As part of the OEB’s
report on the renewed regulatory framework, it concluded that planning for transmission and distribution investments needs to be coordinated on a regional basis and that it was important for utilities to work with the OPA to identify where
conservation or generation options may also represent potential solutions to address the electricity needs of a region. The OEB is proceeding with a written hearing and we have provided some comments on the proposed amendments. 

Proposed Amendments to the Distribution System Code (DSC) and Transmission System Code (TSC) 

On May 17, 2013, the OEB gave notice of proposed amendments to the DSC and the TSC, following an extensive consultation process. The purpose of the
proposed revisions is to implement the OEB’s policies set out in its report on the renewed regulatory framework related to: the establishment of a process in order to move to a more structured approach to 

  

					
		  	12	  	

 HYDRO ONE INC. 
 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) 
 For the three and six months
ended June 30, 2013 and 2012 
  

 regional infrastructure planning; and the determination of the appropriate redefinition of certain line
connection assets and modifications to the TSC cost responsibility rules to facilitate regional planning and the execution of regional infrastructure plans. We filed a submission on the proposed amendments on June 17, 2013, recommending
refinements to the regional infrastructure planning process and some aspects to be considered in assigning cost responsibility to connecting customers. 
 Hydro One Remote Communities 2013 Distribution Rate Application 
 On June 28,
2013, the OEB accepted a partial proposed settlement agreement reached between our subsidiary Hydro One Remote Communities Inc. and various intervenor groups in respect of the previously filed application for 2013 revenue requirement and
distribution rates. The two unsettled issues remained to be resolved through a written hearing, which began in July, 2013. An OEB decision is anticipated later this year. 
 Environment Canada Regulations 
 On June 22, 2013, the Government of Canada
issued a proposed amendment to its existing PCB regulations. The proposed amendment would extend our end-of-use deadline for concentrations, equal to or greater than 500 ppm, from December 31, 2014 (based on our approved end of use extension)
to December 31, 2025. 
 Distribution System Code 
 On June 13, 2013, the OEB issued amendments to the DSC in relation to the connection of micro-embedded generation facilities to the distribution system. The amendments include: extending the
processing timelines for offer to connect applications for micro-embedded generation facilities located at existing customer connections requiring a site assessment; and the harmonization of the connection timelines for micro-embedded generation
facilities with those for the connection of a new low voltage service. 
 2013 Export Service Rates 

On June 6, 2013, the OEB rendered a decision on Hydro One Networks’ export transmission service (ETS) rate. The rate will remain at $2/MWh. The
ETS rate was the only unsettled issue after the OEB approved the settlement agreement for Hydro One Networks’ revenue requirement and cost-of-service rate application for 2013 and 2014 transmission rates. As part of the June 6, 2013
decision, the OEB requested that Hydro One Networks submit a proposal of the appropriate cost-based ETS rate with supporting rationale at its next transmission rates application. 
 Collective Agreement Negotiations 
 Power Workers’ Union (PWU)

 On May 16, 2013, we successfully reached a settlement with the PWU. The collective agreement is for a two-year term covering
April 1, 2013 to March 31, 2015. It was approved and ratified by our Board of Directors on May 29, 2013 and was ratified by the PWU on July 31, 2013. 
 Society of Energy Professionals (Society) 
 In February 2013, we commenced bargaining for
the next collective agreement with the Society, and on March 13, 2013, we successfully reached a tentative settlement. In April 2013, the collective agreement was ratified by our Board of Directors and the Society. The new agreement has a
three-year term effective April 1, 2013. 
 Distribution Customer Incentive Rate-Setting (Custom IR) – Application for 2015-2019
Rates 
 We are conducting a series of stakeholder sessions on our five year distribution custom IR rate application. Our application
will be filed in the first quarter of 2014 for rates effective 2015 to 2019 inclusive. Because a custom IR is new, it is important to seek stakeholder feedback on the proposed features in our application to the OEB. The first session was held on
April 29, 2013 and gave an overview of the custom IR and our schedule for filing. It also highlighted our plans for customer surveys and studies on rate classification and seasonal rates. A second session was held on June 26, 2013 to
provide an update on 

  

					
		  	13	  	

 HYDRO ONE INC. 
 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) 
 For the three and six months
ended June 30, 2013 and 2012 
  

 studies on line losses and seasonal rates; and to introduce annual adjustments, off-ramps and
re-openers, and metrics for monitoring performance that we will include in our application. Stakeholder comments are encouraged and recorded in each session. Future sessions will be held in September and November of 2013. 

SELECTED FINANCIAL HIGHLIGHTS AND RATIOS 
  

																	
	 	  	Three months ended June 30	 	  	Six months ended June 30	 
	 (millions of dollars, except earnings per common share and ratios)
	  	    2013    	 	  	    2012    	 	  	    2013    	 	 	    2012    	 
	 Net income
	  	 	168	  	  	 	169	  	  	 	425	  	 	 	379	  
	 Net cash from operating activities
	  	 	333	  	  	 	217	  	  	 	475	  	 	 	454	  
	 Capital expenditures
	  	 	351	  	  	 	350	  	  	 	621	  	 	 	667	  
	 Earnings per common share
	  	 	1,633	  	  	 	1,651	  	  	 	4,158	  	 	 	3,705	  
	 Earnings coverage ratio1
	  				  				  	 	2.94	  	 	 	2.70	  
	 Net asset coverage on long-term debt ratio2
	  				  				  	 	1.84	  	 	 	1.81	  
	 Total debt to capitalization ratio3
	  				  				  	 	54	% 	 	 	55	% 

  

	1 	 The earnings coverage ratio has been presented for the twelve months ended June 30, 2013 and June 30, 2012, respectively, and has been
calculated as the sum of net income, provision for PILs and financing charges divided by the sum of financing charges, capitalized interest and cumulative preferred dividends. 

	2 	 The net asset coverage on long-term debt ratio has been presented as at June 30, 2013 and December 31, 2012 and has been calculated as total
assets minus total liabilities excluding long-term debt (including current portion) divided by long-term debt (including current portion). 

	3 	 Total debt to capitalization ratio has been presented as at June 30, 2013 and December 31, 2012 and has been calculated as total debt divided
by total debt plus total shareholder’s equity and preferred shares. 

 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 related to the use of our approved rates; 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 expenditures; statements regarding expected future capital and development expenditures,
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 arrangement with Inergi; statements relating to the Smart Grid Advisory Committee; and statements regarding accounting-related international standard setting
initiatives, including the potential future adoption of IFRS and its associated impacts as well as our training and conversion plans. 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; no unfavourable 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; a stable regulatory environment; no unfavourable changes in environmental regulation; and no 

  

					
		  	14	  	

 HYDRO ONE INC. 
 MANAGEMENT’S DISCUSSION AND ANALYSIS (continued) 
 For the three and six months
ended June 30, 2013 and 2012 
  

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

  

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

 

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

 

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

  

	 	•	 	 the risks associated with being subject to extensive regulation including risks associated with OEB action or inaction, including regulatory decisions
regarding our revenue requirements, cost recovery, rates, acquisitions and divestitures; 

  

	 	•	 	 unanticipated changes in electricity demand or in our costs; 

 

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

  

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

  

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

  

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

 

	 	•	 	 the risks associated with changes in interest rates; 

  

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

 

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

 

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

 

	 	•	 	 the risk that we may incur significant costs associated with transferring assets located on Reserves (as defined in the Indian Act (Canada));

  

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

  

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

We caution the reader that the above list of factors is not exhaustive. Some of these and other factors are discussed in more detail in the section Risk
Management and Risk Factors in the 2012 MD&A. You should review this section in detail. 
 In addition, we caution the reader that
information provided in this MD&A regarding our outlook on certain matters, including future expenditures, is provided in order to give context to the nature of some of our future plans and may not be appropriate for other purposes. 

This MD&A is dated as at August 9, 2013. Additional information about our company, including our Annual Information Form, is available on SEDAR
at www.sedar.com. 

  

					
		  	15	  	

 HYDRO ONE INC. 
 CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (unaudited) 
 For the
three and six months ended June 30, 2013 and 2012 
  

																	
	 	  	Three months ended
June 30	 	  	Six months ended
June 30	 
	 (millions of dollars, except per share amounts)
	  	2013	 	  	2012	 	  	2013	 	  	2012	 
	 Revenues
	  				  				  				  			
	 Distribution (includes related party revenues of $38 (2012—$39) and $77 (2012—$78) for three and six months ended
June 30, respectively) (Note 13)
	  	 	1,020	  	  	 	974	  	  	 	2,204	  	  	 	2,065	  
	 Transmission (includes related party revenues of $365 (2012—$373) and $735 (2012—$730) for three and six months ended
June 30, respectively) (Note 13)
	  	 	368	  	  	 	370	  	  	 	741	  	  	 	731	  
	 Other
	  	 	15	  	  	 	15	  	  	 	30	  	  	 	31	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
		  	 	1,403	  	  	 	1,359	  	  	 	2,975	  	  	 	2,827	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Costs
	  				  				  				  			
	 Purchased power (includes related party costs of $545 (2012—$520) and $1,258
(2012—$1,188) for three and six months
ended June 30, respectively) (Note 13)
	  	 	684	  	  	 	640	  	  	 	1,482	  	  	 	1,369	  
	 Operation, maintenance and administration (Note 13)
	  	 	291	  	  	 	278	  	  	 	524	  	  	 	540	  
	 Depreciation and amortization
	  	 	160	  	  	 	158	  	  	 	321	  	  	 	310	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
		  	 	1,135	  	  	 	1,076	  	  	 	2,327	  	  	 	2,219	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Income before financing charges and provision for payments in lieu of corporate income taxes
	  	 	268	  	  	 	283	  	  	 	648	  	  	 	608	  
	 Financing charges
	  	 	89	  	  	 	90	  	  	 	177	  	  	 	173	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Income before provision for payments in lieu of corporate income taxes
	  	 	179	  	  	 	193	  	  	 	471	  	  	 	435	  
	 Provision for payments in lieu of corporate income taxes (Note 5, 13)
	  	 	11	  	  	 	24	  	  	 	46	  	  	 	56	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Net income
	  	 	168	  	  	 	169	  	  	 	425	  	  	 	379	  
	 Other comprehensive income
	  	 	—  	  	  	 	—  	  	  	 	—  	  	  	 	—  	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Comprehensive income
	  	 	168	  	  	 	169	  	  	 	425	  	  	 	379	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Basic and fully diluted earnings per common share (dollars) (Note 11)
	  	 	1,633	  	  	 	1,651	  	  	 	4,158	  	  	 	3,705	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Dividends per common share declared (dollars) (Note 12)
	  	 	250	  	  	 	250	  	  	 	1,500	  	  	 	3,023	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 

 See accompanying notes to Consolidated Financial Statements (unaudited). 

  

					
		  	16	  	

 HYDRO ONE INC. 
 CONSOLIDATED BALANCE SHEETS (unaudited) 
 At June 30, 2013 and December 31,
2012 
  

									
	 (millions of dollars)
	  	June 30,
2013	 	  	December 31,
2012	 
	 Assets
	  				  			
	 Current assets:
	  				  			
	 Short-term investments (Note 8)
	  	 	—  	  	  	 	195	  
	 Accounts receivable (net of allowance for doubtful accounts – $22; 2012 – $23) (Note 6)
	  	 	962	  	  	 	845	  
	 Due from related parties (Note 13)
	  	 	207	  	  	 	154	  
	 Prepaid pension contributions (Note 9)
	  	 	80	  	  	 	—  	  
	 Regulatory assets
	  	 	44	  	  	 	29	  
	 Materials and supplies
	  	 	24	  	  	 	23	  
	 Deferred income tax assets
	  	 	18	  	  	 	18	  
	 Other current assets
	  	 	24	  	  	 	22	  
		  	  
	  
	 	  	  
	  
	 
		  	 	1,359	  	  	 	1,286	  
		  	  
	  
	 	  	  
	  
	 
	 Property, plant and equipment:
	  				  			
	 Property, plant and equipment in service
	  	 	23,048	  	  	 	22,650	  
	 Less: accumulated depreciation
	  	 	8,381	  	  	 	8,145	  
		  	  
	  
	 	  	  
	  
	 
		  	 	14,667	  	  	 	14,505	  
	 Construction in progress
	  	 	1,174	  	  	 	1,055	  
	 Future use land, components and spares
	  	 	151	  	  	 	147	  
		  	  
	  
	 	  	  
	  
	 
		  	 	15,992	  	  	 	15,707	  
		  	  
	  
	 	  	  
	  
	 
	 Other long-term assets:
	  				  			
	 Regulatory assets
	  	 	3,182	  	  	 	3,098	  
	 Intangible assets (net of accumulated amortization – $258; 2012 – $305)
	  	 	310	  	  	 	267	  
	 Long-term investment (Notes 7, 8, 13)
	  	 	251	  	  	 	251	  
	 Goodwill
	  	 	133	  	  	 	133	  
	 Deferred debt costs
	  	 	32	  	  	 	34	  
	 Derivative instruments (Note 8)
	  	 	14	  	  	 	19	  
	 Deferred income tax assets
	  	 	14	  	  	 	14	  
	 Other long-term assets
	  	 	2	  	  	 	2	  
		  	  
	  
	 	  	  
	  
	 
		  	 	3,938	  	  	 	3,818	  
		  	  
	  
	 	  	  
	  
	 
	 Total assets
	  	 	21,289	  	  	 	20,811	  
		  	  
	  
	 	  	  
	  
	 

 See accompanying notes to Consolidated Financial Statements (unaudited). 

  

					
		  	17	  	

 HYDRO ONE INC. 
 CONSOLIDATED BALANCE SHEETS (unaudited) (continued) 
 At June 30, 2013 and
December 31, 2012 
  

									
	 (millions of dollars, except number of shares)
	  	June 30,
2013	 	 	December 31,
2012	 
	 Liabilities
	  				 			
	 Current liabilities:
	  				 			
	 Bank indebtedness (Note 8)
	  	 	24	  	 	 	42	  
	 Accounts payable
	  	 	113	  	 	 	140	  
	 Accrued liabilities (Note 10)
	  	 	693	  	 	 	582	  
	 Due to related parties (Notes 5, 13)
	  	 	146	  	 	 	257	  
	 Short-term notes payable (Notes 7, 8)
	  	 	118	  	 	 	—  	  
	 Accrued interest
	  	 	94	  	 	 	95	  
	 Regulatory liabilities
	  	 	59	  	 	 	40	  
	 Long-term debt payable within one year (Notes 7, 8)
	  	 	600	  	 	 	600	  
		  	  
	  
	 	 	  
	  
	 
		  	 	1,847	  	 	 	1,756	  
		  	  
	  
	 	 	  
	  
	 
	 Long-term debt (includes $764 measured at fair value; 2012 – $769) (Notes 7, 8)
	  	 	7,874	  	 	 	7,879	  
		  	  
	  
	 	 	  
	  
	 
	 Other long-term liabilities:
	  				 			
	 Pension benefit liability (Note 9)
	  	 	1,515	  	 	 	1,515	  
	 Post-retirement and post-employment benefit liabilities (Note 9)
	  	 	1,454	  	 	 	1,416	  
	 Deferred income tax liabilities
	  	 	1,042	  	 	 	944	  
	 Environmental liabilities (Note 10)
	  	 	213	  	 	 	227	  
	 Regulatory liabilities
	  	 	196	  	 	 	181	  
	 Net unamortized debt premiums
	  	 	22	  	 	 	23	  
	 Asset retirement obligations
	  	 	13	  	 	 	15	  
	 Long-term accounts payable and other liabilities
	  	 	17	  	 	 	25	  
		  	  
	  
	 	 	  
	  
	 
		  	 	4,472	  	 	 	4,346	  
		  	  
	  
	 	 	  
	  
	 
	 Total liabilities
	  	 	14,193	  	 	 	13,981	  
		  	  
	  
	 	 	  
	  
	 
	 Contingencies and commitments (Notes 15, 16)
	  				 			
	 Preferred shares (authorized: unlimited; issued: 12,920,000) (Notes 11, 12)
	  	 	323	  	 	 	323	  
	 Shareholder’s Equity
	  				 			
	 Common shares (authorized: unlimited; issued: 100,000) (Notes 11, 12)
	  	 	3,314	  	 	 	3,314	  
	 Retained earnings
	  	 	3,468	  	 	 	3,202	  
	 Accumulated other comprehensive loss
	  	 	(9	) 	 	 	(9	) 
		  	  
	  
	 	 	  
	  
	 
	 Total shareholder’s equity
	  	 	6,773	  	 	 	6,507	  
		  	  
	  
	 	 	  
	  
	 
	 Total liabilities, preferred shares and shareholder’s equity
	  	 	21,289	  	 	 	20,811	  
		  	  
	  
	 	 	  
	  
	 

 See accompanying notes to Consolidated Financial Statements (unaudited). 

  

					
		  	18	  	

 HYDRO ONE INC. 
 CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDER’S EQUITY (unaudited) 
 For the six
months ended June 30, 2013 and 2012 
  

																	
	 Six months ended June 30, 2013

(millions of dollars)
	  	Common
Shares	 	  	Retained
Earnings	 	 	Accumulated
Other
Comprehensive
Loss	 	 	Total
Shareholder’s
Equity	 
	 January 1, 2013
	  	 	3,314	  	  	 	3,202	  	 	 	(9	) 	 	 	6,507	  
	 Net income
	  	 	—  	  	  	 	425	  	 	 	—  	  	 	 	425	  
	 Other comprehensive income
	  	 	—  	  	  	 	—  	  	 	 	—  	  	 	 	—  	  
	 Dividends on preferred shares
	  	 	—  	  	  	 	(9	) 	 	 	—  	  	 	 	(9	) 
	 Dividends on common shares
	  	 	—  	  	  	 	(150	) 	 	 	—  	  	 	 	(150	) 
		  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 June 30, 2013
	  	 	3,314	  	  	 	3,468	  	 	 	(9	) 	 	 	6,773	  
		  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	 	  
	  
	 
					
	 Six months ended June 30, 2012

(millions of dollars)
	  	Common
Shares	 	  	Retained
Earnings	 	 	Accumulated
Other
Comprehensive
Loss	 	 	Total
Shareholder’s
Equity	 
	 January 1, 2012
	  	 	3,314	  	  	 	2,827	  	 	 	(10	) 	 	 	6,131	  
	 Net income
	  	 	—  	  	  	 	379	  	 	 	—  	  	 	 	379	  
	 Other comprehensive income
	  	 	—  	  	  	 	—  	  	 	 	—  	  	 	 	—  	  
	 Dividends on preferred shares
	  	 	—  	  	  	 	(9	) 	 	 	—  	  	 	 	(9	) 
	 Dividends on common shares
	  	 	—  	  	  	 	(302	) 	 	 	—  	  	 	 	(302	) 
		  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 June 30, 2012
	  	 	3,314	  	  	 	2,895	  	 	 	(10	) 	 	 	6,199	  
		  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	 	  
	  
	 

 See accompanying notes to Consolidated Financial Statements (unaudited). 

  

					
		  	19	  	

 HYDRO ONE INC. 
 CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited) 
 For the three and six months ended
June 30, 2013 and 2012 
  

																	
	 	  	Three months ended
June 30	 	 	Six months ended
June 30	 
	 (millions of dollars)
	  	2013	 	 	2012	 	 	2013	 	 	2012	 
	 Operating activities
	  				 				 				 			
	 Net income
	  	 	168	  	 	 	169	  	 	 	425	  	 	 	379	  
	 Environmental expenditures
	  	 	(3	) 	 	 	(4	) 	 	 	(7	) 	 	 	(7	) 
	 Adjustments for non-cash items:
	  				 				 				 			
	 Depreciation and amortization (excluding removal costs)
	  	 	142	  	 	 	140	  	 	 	286	  	 	 	279	  
	 Regulatory asset and liability accounts
	  	 	23	  	 	 	8	  	 	 	30	  	 	 	15	  
	 Deferred income taxes
	  	 	1	  	 	 	(1	) 	 	 	5	  	 	 	—  	  
	 Asset retirement obligations
	  	 	(2	) 	 	 	—  	  	 	 	(2	) 	 	 	—  	  
	 Other
	  	 	1	  	 	 	(1	) 	 	 	1	  	 	 	—  	  
	 Changes in non-cash balances related to operations (Note 14)
	  	 	3	  	 	 	(94	) 	 	 	(263	) 	 	 	(212	) 
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Net cash from operating activities
	  	 	333	  	 	 	217	  	 	 	475	  	 	 	454	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Financing activities
	  				 				 				 			
	 Long-term debt issued
	  	 	—  	  	 	 	425	  	 	 	—  	  	 	 	725	  
	 Short-term notes payable
	  	 	44	  	 	 	—  	  	 	 	118	  	 	 	—  	  
	 Dividends paid
	  	 	(30	) 	 	 	(30	) 	 	 	(159	) 	 	 	(311	) 
	 Change in bank indebtedness
	  	 	(15	) 	 	 	(9	) 	 	 	(18	) 	 	 	(16	) 
	 Other
	  	 	—  	  	 	 	2	  	 	 	—  	  	 	 	1	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Net cash from (used in) financing activities
	  	 	(1	) 	 	 	388	  	 	 	(59	) 	 	 	399	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Investing activities
	  				 				 				 			
	 Capital expenditures
	  				 				 				 			
	 Property, plant and equipment
	  	 	(317	) 	 	 	(331	) 	 	 	(557	) 	 	 	(627	) 
	 Intangible assets
	  	 	(34	) 	 	 	(19	) 	 	 	(64	) 	 	 	(40	) 
	 Other
	  	 	10	  	 	 	9	  	 	 	10	  	 	 	11	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Net cash used in investing activities
	  	 	(341	) 	 	 	(341	) 	 	 	(611	) 	 	 	(656	) 
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Net change in cash and cash equivalents
	  	 	(9	) 	 	 	264	  	 	 	(195	) 	 	 	197	  
	 Cash and cash equivalents, beginning of period
	  	 	9	  	 	 	161	  	 	 	195	  	 	 	228	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Cash and cash equivalents, end of period
	  	 	—  	  	 	 	425	  	 	 	—  	  	 	 	425	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 

 See accompanying notes to Consolidated Financial Statements (unaudited). 

  

					
		  	20	  	

 HYDRO ONE INC. 
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited) 
 For the three and six months
ended June 30, 2013 and 2012 
 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). 

The demand for electricity generally follows normal weather-related variations, and therefore the Company’s energy-related revenues, all other
things being equal, will tend to be higher in the first and third quarters than in the second and fourth quarters. 
 2. SIGNIFICANT
ACCOUNTING POLICIES 
 Basis of Consolidation 
 These unaudited interim 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 Lake Erie Link Management Inc., and Hydro One Lake Erie Link Company Inc. 

Intercompany transactions and balances have been eliminated. 
 Basis of Accounting 
 These unaudited interim Consolidated Financial Statements are
prepared and presented in accordance with United States (US) generally accepted accounting principles (GAAP) and in Canadian dollars. These unaudited interim Consolidated Financial Statements do not contain all disclosures required by US GAAP
for annual audited consolidated financial statements. Accordingly, they should be read in conjunction with the Company’s annual Consolidated Financial Statements as at, and for the year ended December 31, 2012. In particular, the
Company’s significant accounting policies, presented as Note 2 to the annual Consolidated Financial Statements, have been applied consistently in the preparation of these unaudited interim Consolidated Financial Statements. In the opinion of
management, these unaudited interim Consolidated Financial Statements include all adjustments that are necessary to fairly state the financial position and results of operations of Hydro One as at, and for the three and six months ended
June 30, 2013. Financial results for the interim periods are not necessarily indicative of results that may be expected for any other interim periods or for the year ending December 31, 2013. 

Hydro One performed an evaluation of subsequent events through to August 9, 2013, the date these unaudited interim Consolidated Financial Statements
were issued, to determine whether any events or transactions warranted recognition and disclosure in these unaudited interim Consolidated Financial Statements. No such events or transactions were identified. 

Rate Setting 
 In May 2012, Hydro
One Networks filed a cost-of-service application with the OEB for 2013 transmission rates, seeking approval for 2013 revenue requirement of $1,465 million. In December 2012, the OEB approved a revenue requirement of $1,438 million. The reduced
approved revenue requirement included reductions to proposed operation, maintenance and administration costs, and capital expenditures. 
 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 approved an increase of approximately 1.3% to
distribution rates for 2013. 
 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 approved an increase of approximately 0.3% to distribution rates for 2013. 

  

					
		  	21	  	

 HYDRO ONE INC. 
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited) (continued) 
 For the three and
six months ended June 30, 2013 and 2012 
  

 In September 2012, Hydro One Remote Communities filed a cost-of-service application with the OEB for
2013 distribution rates, seeking approval for 2013 revenue requirement of $53 million. In June 2013, the OEB approved a revenue requirement of $51 million. The reduced approved revenue requirement included reductions to proposed operation,
maintenance and administration costs, depreciation and amortization costs, and financing charges. 
 Depreciation and Amortization

 The Company periodically initiates an external independent review of the useful lives of its property, plant and equipment and
intangible assets, as required by the OEB. Any changes arising from OEB approval are implemented on a remaining service life basis, consistent with their inclusion in the Company’s revenue requirement and resulting electricity rates. The last
OEB-approved review resulted in changes to the useful lives of the Company’s transmission and common assets and was effective January 1, 2013. These changes resulted in a decrease in the Company’s depreciation and amortization expense
of approximately $6 million and $13 million for the three and six months ended June 30, 2013, respectively, with a corresponding reduction in the Company’s revenue requirement. Accordingly, these changes had no impact on the Company’s
results of operations. 
 3. NEW ACCOUNTING PRONOUNCEMENTS 
 Recently Adopted Accounting Pronouncements 
 In December 2011, the Financial
Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2011-11, Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities. This ASU requires an entity to disclose both gross and net information about
financial instruments and transactions eligible for offset on the Consolidated Balance Sheets as well as financial instruments and transactions executed under a master netting or similar arrangement. The ASU was issued to enable users of financial
statements to understand the effects or potential effects of those arrangements on an entity’s financial position. This ASU was required to be applied retrospectively and was effective for fiscal years, and interim periods within those years,
beginning on or after January 1, 2013. The adoption of this ASU did not have a significant impact on the Company’s interim Consolidated Financial Statements. 
 In February 2013, the FASB issued ASU 2013-02, Comprehensive Income (Topic 220): Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income. This ASU requires an entity to provide
information about the amounts reclassified out of accumulated other comprehensive income by component. In addition, an entity is required to present, either on the face of the statement where net income is presented or in the notes, significant
amounts reclassified out of accumulated other comprehensive income by the respective line items of net income, but only if the amount reclassified is required under US GAAP to be reclassified to net income in its entirety in the same reporting
period. For other amounts that are not required under US GAAP to be reclassified in their entirety to net income, an entity is required to cross-reference to other disclosures required under US GAAP that provide additional detail about
those amounts. This ASU was required to be applied prospectively and was effective for fiscal years, and interim periods within those years, beginning after December 15, 2012. The adoption of this ASU did not have a significant impact on the
Company’s interim Consolidated Financial Statements. 
 4. BUSINESS ACQUISITION 

Norfolk Power Purchase Agreement 

On April 2, 2013, Hydro One reached an agreement with Norfolk County to acquire 100% of the common shares of Norfolk Power Inc. (Norfolk Power), an
electricity distribution and telecom company in southwestern Ontario. The acquisition is pending regulatory approval from the OEB. The purchase price for Norfolk Power will be approximately $93 million, subject to final closing adjustments. The
transaction is anticipated to be completed before December 31, 2013. In anticipation of the Norfolk Power acquisition, the Company made a deposit totalling $5 million, which was recorded in other current assets on the interim Consolidated
Balance Sheet at June 30, 2013. 

  

					
		  	22	  	

 HYDRO ONE INC. 
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited) (continued) 
 For the three and
six months ended June 30, 2013 and 2012 
  

 5. PROVISION FOR PAYMENTS IN LIEU OF CORPORATE INCOME TAXES 

The current provision for payments in lieu of corporate income taxes (PILs) is remitted to, or received from, the Ontario Electricity Financial
Corporation (OEFC). At June 30, 2013, $28 million due from the OEFC was included in due from related parties on the interim Consolidated Balance Sheet (December 31, 2012 – $10 million included in due to related parties). The total
provision for PILs includes deferred income taxes that are not expected to be recovered from ratepayers, using the liability method of accounting. Deferred PILs balances expected to be recovered from ratepayers result in regulatory assets and
liabilities to reflect the anticipated recovery or disposition of these balances within future electricity rates. 
 For the six months ended
June 30, 2013, the Company’s overall effective tax rate of 9.77% differed from the enacted statutory rate of 26.50% primarily due to the temporary differences expected to be recovered from ratepayers, 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. 

6. ACCOUNTS RECEIVABLE 
  

									
	 (millions of dollars)
	  	June 30,
2013	 	 	December 31,
2012	 
	 Accounts receivable – billed
	  	 	413	  	 	 	224	  
	 Accounts receivable – unbilled
	  	 	571	  	 	 	644	  
		  	  
	  
	 	 	  
	  
	 
	 Accounts receivable, gross
	  	 	984	  	 	 	868	  
	 Allowance for doubtful accounts
	  	 	(22	) 	 	 	(23	) 
		  	  
	  
	 	 	  
	  
	 
	 Accounts receivable, net
	  	 	962	  	 	 	845	  
		  	  
	  
	 	 	  
	  
	 

 The following table shows the movements in the allowance for doubtful accounts for the six months ended June 30,
2013 and the year ended December 31, 2012. 
  

					
	 Six months ended June 30, 2013 (millions of dollars)
	  	 	 
	 Allowance for doubtful accounts – January 1, 2013
	  	 	(23	) 
	 Write-offs
	  	 	10	  
	 Additions
	  	 	(9	) 
		  	  
	  
	 
	 Allowance for doubtful accounts – June 30, 2013
	  	 	(22	) 
		  	  
	  
	 
		
	 Year ended December 31, 2012 (millions of dollars)
	  	 	 
	 Allowance for doubtful accounts – January 1, 2012
	  	 	(18	) 
	 Write-offs
	  	 	            17	  
	 Additions
	  	 	(22	) 
		  	  
	  
	 
	 Allowance for doubtful accounts – December 31, 2012
	  	 	(23	) 
		  	  
	  
	 

 7. 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 $118
million in commercial paper borrowings outstanding as at June 30, 2013 (December 31, 2012 – $nil). 
 The Commercial Paper Program is
supported by a total of $1,750 million in liquidity facilities comprised of a $1,500 million committed revolving standby credit facility and a long-term investment in Province of Ontario Floating-Rate Notes with a notional value of $250 million at
June 30, 2013 (December 31, 2012 – $250 million). 

  

					
		  	23	  	

 HYDRO ONE INC. 
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited) (continued) 
 For the three and
six months ended June 30, 2013 and 2012 
  

 Long-Term Debt 
 The Company issues notes for long-term financing under its Medium-Term Note (MTN) Program. The maximum authorized principal amount of notes issuable under this program is $3,000 million. At June 30,
2013, $1,515 million remained available for issuance until September 2013. 
 The following table presents the outstanding long-term debt at
June 30, 2013 and December 31, 2012: 
  

									
	 (millions of dollars)
	  	June 30,
2013	 	 	December 31,
2012	 
	 Notes and debentures
	  	 	8,460	  	 	 	8,460	  
	 Add: Unrealized marked-to-market loss1
	  	 	14	  	 	 	19	  
	 Less: Long-term debt payable within one year
	  	 	(600	) 	 	 	(600	) 
		  	  
	  
	 	 	  
	  
	 
	 Long-term debt
	  	 	7,874	  	 	 	7,879	  
		  	  
	  
	 	 	  
	  
	 

  

	1 	 The unrealized marked-to-market loss relates to $500 million of the Series 19 notes due 2014, and $250 million of the Series 21 notes due 2015. The
unrealized marked-to-market loss is offset by a $14 million (December 31, 2012 – $19 million) unrealized marked-to-market gain on the related fixed-to-floating interest-rate swap agreements, which are accounted for as fair value hedges.

 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 8 – Fair Value of Financial Instruments and Risk Management. 
 Credit Agreements 

Hydro One has a $1,500 million committed and unused revolving standby credit facility with a syndicate of banks, maturing in June 2018. If used, interest
on the facility would apply based on Canadian benchmark rates. This credit facility supports the Company’s Commercial Paper Program. 
 The
Company may use the credit facility for general corporate purposes, including meeting short-term funding requirements. The obligation of each lender to make any credit extension to the Company under its credit facility is subject to various
conditions including, among other things, that no event of default has occurred, or would result from, such credit extension. 
 8. 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. 

  

					
		  	24	  	

 HYDRO ONE INC. 
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited) (continued) 
 For the three and
six months ended June 30, 2013 and 2012 
  

 Non-Derivative Financial Assets and Liabilities 

At June 30, 2013 and December 31, 2012, the Company’s carrying amounts of accounts receivable, amounts due from related parties, short-term
investments, bank indebtedness, short-term notes payable, accounts payable, accrued liabilities, and amounts 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 June 30, 2013 and December 31, 2012 are as follows: 

 

																	
	 	  	June 30, 2013	 	  	December 31, 2012	 
	 (millions of dollars)
	  	Carrying
Value	 	  	Fair
Value	 	  	Carrying
Value	 	  	Fair
Value	 
	 Long-term debt
	  				  				  				  			
	 $500 million of MTN Series 19 notes1
	  	 	509	  	  	 	509	  	  	 	512	  	  	 	512	  
	 $250 million of MTN Series 21 notes2
	  	 	255	  	  	 	255	  	  	 	257	  	  	 	257	  
	 Other notes and debentures3
	  	 	7,710	  	  	 	8,661	  	  	 	7,710	  	  	 	9,188	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
		  	 	8,474	  	  	 	9,425	  	  	 	8,479	  	  	 	9,957	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 

  

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

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

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

 Fair Value Measurements of Derivative Instruments 

At June 30, 2013, the Company had interest-rate swaps totalling $750 million (December 31, 2012 – $750 million) that were used to convert
fixed-rate debt to floating-rate debt. These swaps are classified as fair value hedges. The Company’s fair value hedge exposure was equal to about 9% (December 31, 2012 – 9%) of its total long-term debt of $8,474 million (December 31, 2012
– $8,479 million). At June 30, 2013, the Company had the following interest-rate swaps designated as fair value hedges: 
  

	 	(a)	two $250 million fixed-to-floating interest-rate swap agreements to convert $500 million of the $750 million MTN Series 19 notes maturing November 19, 2014 into
three-month variable rate debt; and 

  

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

 At June 30, 2013, the Company also had interest-rate swaps with a total notional value of
$600 million (December 31, 2012 – $900 million) classified as undesignated contracts. The undesignated contracts consist of the following interest-rate swaps: 
  

	 	(c)	two $250 million floating-to-fixed interest-rate swap agreements that lock in the floating rate the Company pays on a portion of the above fixed-to-floating
interest-rate swaps from December 11, 2012 to December 11, 2013, and from February 19, 2013 to February 19, 2014; 

  

	 	(d)	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, 2013 to January 24, 2014; and 

  

	 	(e)	a $50 million floating-to-fixed interest-rate swap agreement that locks in the floating rate the Company pays on the $50 million floating-rate MTN Series 27 notes from
March 4, 2013 to December 3, 2013. 

  

					
		  	25	  	

 HYDRO ONE INC. 
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited) (continued) 
 For the three and
six months ended June 30, 2013 and 2012 
  

 Fair Value Hierarchy 
 The fair value hierarchy of financial assets and liabilities at June 30, 2013 and December 31, 2012 was as follows: 

 

																					
	 June 30, 2013 (millions of dollars)
	  	Carrying
Value	 	  	Fair
Value	 	  	Level 1	 	  	Level 2	 	  	Level 3	 
	 Assets:
	  				  				  				  				  			
	 Long-term investment
	  	 	251	  	  	 	251	  	  	 	—  	  	  	 	251	  	  	 	—  	  
	 Derivative instruments
	  				  				  				  				  			
	 Fair value hedges – interest-rate swaps
	  	 	14	  	  	 	14	  	  	 	—  	  	  	 	14	  	  	 	—  	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
		  	 	265	  	  	 	265	  	  	 	—  	  	  	 	265	  	  	 	—  	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Liabilities:
	  				  				  				  				  			
	 Bank indebtedness
	  	 	24	  	  	 	24	  	  	 	24	  	  	 	—  	  	  	 	—  	  
	 Short-term notes payable
	  	 	118	  	  	 	118	  	  	 	—  	  	  	 	118	  	  	 	—  	  
	 Long-term debt
	  	 	8,474	  	  	 	9,425	  	  	 	—  	  	  	 	9,425	  	  	 	—  	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
		  	 	8,616	  	  	 	9,567	  	  	 	24	  	  	 	9,543	  	  	 	—  	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
						
	 December 31, 2012 (millions of dollars)
	  	Carrying
Value	 	  	Fair
Value	 	  	Level 1	 	  	Level 2	 	  	Level 3	 
	 Assets:
	  				  				  				  				  			
	 Short-term investments
	  	 	195	  	  	 	195	  	  	 	—  	  	  	 	195	  	  	 	—  	  
	 Long-term investment
	  	 	251	  	  	 	251	  	  	 	—  	  	  	 	251	  	  	 	—  	  
	 Derivative instruments
	  				  				  				  				  			
	 Fair value hedges – interest-rate swaps
	  	 	19	  	  	 	19	  	  	 	—  	  	  	 	19	  	  	 	—  	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
		  	 	465	  	  	 	465	  	  	 	—  	  	  	 	465	  	  	 	—  	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Liabilities:
	  				  				  				  				  			
	 Bank indebtedness
	  	 	42	  	  	 	42	  	  	 	42	  	  	 	—  	  	  	 	—  	  
	 Long-term debt
	  	 	8,479	  	  	 	9,957	  	  	 	—  	  	  	 	9,957	  	  	 	—  	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
		  	 	8,521	  	  	 	9,999	  	  	 	42	  	  	 	9,957	  	  	 	—  	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 

 The fair value of the short-term investments is determined using inputs other than quoted prices that are observable for
these assets. The fair value is primarily based on the purchase price, the purchase yield, and the maturity date. 
 The long-term investment
represents the Province of Ontario Floating-Rate Notes. The fair value of the long-term investment is determined using inputs other than quoted prices that are observable for the asset, with unrecognized gains or losses recognized in financing
charges. The Company obtains quotes from an independent third party for the fair value of the long-term investment, who uses the market price of similar securities adjusted for changes in observable inputs such as maturity dates and interest rates.

 The fair value of the derivative instruments is determined using 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 short-term notes payable is determined using inputs other than quoted prices that are observable for these liabilities. The fair value is primarily based on the issue price, the issue
yield, and the maturity date. 
 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 six months ended June 30, 2013, or the
year ended December 31, 2012. 

  

					
		  	26	  	

 HYDRO ONE INC. 
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited) (continued) 
 For the three and
six months ended June 30, 2013 and 2012 
  

 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. 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 annual results of operations of the Transmission Business by approximately $19
million (2012 – $18 million) and the annual results of operations of the Distribution Business by approximately $10 million (2012 – $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 June 30, 2013 or December 31, 2012. 

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 six months ended June 30, 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 three and six
months ended June 30, 2013 and 2012 are included in financing charges as follows: 
  

																	
	 	  	Three months ended
June 30	 	 	Six months ended
June 30	 
	 (millions of dollars)
	  	2013	 	 	2012	 	 	2013	 	 	2012	 
	 Unrealized (gain) loss on hedged debt
	  	 	(5	) 	 	 	2	  	 	 	(6	) 	 	 	(7	) 
	 Unrealized loss (gain) on fair value interest-rate swaps
	  	 	5	  	 	 	(2	) 	 	 	6	  	 	 	7	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Net unrealized loss (gain)
	  	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 

 At June 30, 2013, Hydro One had $750 million (December 31, 2012 – $750 million) of notional amounts of fair
value hedges outstanding related to interest-rate swaps, with assets having a fair value of $14 million (December 31, 2012 – $19 million). During the six months ended June 30, 2013 and 2012, 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 June 30, 2013 and
December 31, 2012, 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 

  

					
		  	27	  	

 HYDRO ONE INC. 
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited) (continued) 
 For the three and
six months ended June 30, 2013 and 2012 
  

 of revenue from any single customer. At June 30, 2013 and December 31, 2012, there was no
significant accounts receivable balance due from any single customer. In addition, the Company obtains letters of credit from certain customers and vendors as security for their contractual obligations. The Company could draw on these letters of
credit when deemed necessary if these parties fail to meet their obligations. 
 At June 30, 2013, the Company’s allowance for bad
debts was $22 million (December 31, 2012 – $23 million). Additions and write-offs were determined on the basis of a review of overdue accounts, taking into consideration historical experience. At June 30, 2013, approximately 5% of the
Company’s accounts receivable were aged more than 60 days (December 31, 2012 – 3%). 
 Hydro One manages its counterparty credit risk
through various techniques including: entering into transactions with highly-rated counterparties; limiting total exposure levels with individual counterparties, consistent with the Company’s Board-approved Credit Risk Policy; entering into
master agreements which enable net settlement and the contractual right of offset; and monitoring the financial condition of counterparties. In addition to payment netting language in master agreements, the Company establishes credit limits,
margining thresholds and collateral requirements for each counterparty. Counterparty credit limits are based on an internal credit review that considers a variety of factors, including the results of a scoring model, leverage, liquidity,
profitability, credit ratings and risk management capabilities. The determination of credit exposure for a particular counterparty is the sum of current exposure plus the potential future exposure with that counterparty. The current exposure is
calculated as the sum of the principal value of money market exposures and the market value of all contracts that have a positive mark-to-market position on the measurement date. The Company would only offset the positive market values against
negative values with the same counterparty where permitted by the existence of a legal netting agreement such as an International Swap Dealers Association master agreement. The potential future exposure represents a safety margin to protect against
future fluctuations of interest rates, currencies, equities, and commodities. It is calculated based on factors developed by the Bank of International Settlements, following extensive historical analysis of random fluctuations of interest rates and
currencies. To the extent that a counterparty’s margining thresholds are exceeded, the counterparty is required to post collateral with the Company as specified in each agreement. The Company monitors current and forward credit exposure to
counterparties both on an individual and an aggregate basis. The Company’s credit risk for accounts receivable is limited to the carrying amounts on the Consolidated Balance Sheets. 
 Derivative financial instruments result in exposure to credit risk since there is a risk of counterparty default. The credit exposure of derivative contracts, before collateral, is represented by the fair
value of contracts at the reporting date. At June 30, 2013, the counterparty credit risk exposure on the fair value of these interest-rate swap contracts was $16 million (December 31, 2012 – $22 million). At June 30, 2013, Hydro
One’s credit exposure for all derivative instruments, and related payables and receivables, had a credit rating of investment grade, with three financial institutions as the counterparties. The credit exposure of each counterparty accounted for
more than 10% of the total credit exposure. 
 Liquidity Risk 
 Liquidity risk refers to the Company’s ability to meet its financial obligations as they come due. Hydro One meets its short-term liquidity requirements using cash and cash equivalents on hand, funds
from operating activities, the issuance of commercial paper, the revolving standby credit facility, and by holding Province of Ontario Floating-Rate Notes. The Commercial Paper Program is supported by a total of $1,750 million in liquidity
facilities comprised of a $1,500 million committed revolving standby credit facility with a syndicate of banks maturing in June 2018 and the Province of Ontario Floating-Rate Notes with a fair value of $251 million. The short-term liquidity under
this program and anticipated levels of funds from operating activities should be sufficient to fund the Company’s normal operating requirements. 
 At June 30, 2013, accounts payable and accrued liabilities in the amount of $806 million (December 31, 2012 – $722 million) were expected to be settled in cash at their carrying amounts within
the next 12 months. 
 At June 30, 2013, Hydro One had issued long-term debt in the notional amount of $8,460 million (December 31, 2012
– $8,460 million). Principal outstanding, interest payments and related weighted average interest rates are summarized by the number of years to maturity in the following table. 

  

					
		  	28	  	

 HYDRO ONE INC. 
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited) (continued) 
 For the three and
six months ended June 30, 2013 and 2012 
  

													
	 Years to Maturity
	  	Principal Outstanding
on Long-term Debt
(millions of dollars)	 	  	Interest 
Payments1
(millions of dollars)	 	  	Weighted Average
Interest Rate1
(%)	 
	 1 year2
	  	 	600	  	  	 	205	  	  	 	5.0	  
	 2 years
	  	 	750	  	  	 	379	  	  	 	3.1	  
	 3 years
	  	 	550	  	  	 	356	  	  	 	2.8	  
	 4 years
	  	 	500	  	  	 	331	  	  	 	4.3	  
	 5 years
	  	 	600	  	  	 	320	  	  	 	5.2	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
		  	 	3,000	  	  	 	1,591	  	  	 	4.1	  
	 6 – 10 years
	  	 	900	  	  	 	1,403	  	  	 	3.6	  
	 Over 10 years
	  	 	4,560	  	  	 	4,138	  	  	 	5.6	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
		  	 	8,460	  	  	 	7,132	  	  	 	4.9	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 

  

	1	 Interest payments
and weighted average interest rates beyond 1 year exclude the impact of the $50 million floating-rate Series 22 notes due 2015 and the $50 million floating-rate Series 27 notes due 2016. 

	2	 The amounts
disclosed represent amounts due over the period July 1, 2013 to December 31, 2013. 

 9. PENSION AND
POST-RETIREMENT AND POST-EMPLOYMENT BENEFITS 
 Estimated 2013 annual pension plan employer contributions of $160 million were paid during
the first quarter of 2013, based on an actuarial valuation effective December 31, 2011 and the expected level of 2013 pensionable earnings, resulting in a prepaid pension contributions asset of $80 million at June 30, 2013 (December 31,
2012 – $nil). 
 The following tables provide the components of the net periodic benefit costs for the three and six months ended
June 30, 2013 and 2012: 
  

																	
	  	  	Pension Benefits	 	 	Post-Retirement and
Post-Employment
Benefits	 
	 Three months ended June 30 (millions of dollars)
	  	2013	 	 	2012	 	 	2013	 	  	2012	 
	 Current service cost, net of employee contributions
	  	 	37	  	 	 	24	  	 	 	10	  	  	 	7	  
	 Interest cost
	  	 	69	  	 	 	71	  	 	 	16	  	  	 	16	  
	 Expected return on plan assets net of expenses1
	  	 	(77	) 	 	 	(72	) 	 	 	—  	  	  	 	—  	  
	 Actuarial loss amortization
	  	 	44	  	 	 	28	  	 	 	4	  	  	 	1	  
	 Prior service cost amortization
	  	 	—  	  	 	 	1	  	 	 	1	  	  	 	1	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	  	  
	  
	 
	 Net Periodic Benefit Cost
	  	 	73	  	 	 	52	  	 	 	31	  	  	 	25	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	  	  
	  
	 
	 Charged to results of operations2
	  	 	        18	  	 	 	        19	  	 	 	        13	  	  	 	        11	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	  	  
	  
	 
			
	  	  	Pension Benefits	 	 	Post-Retirement 
and
Post-Employment
Benefits	 
	 Six months ended June 30 (millions of dollars)
	  	2013	 	 	2012	 	 	2013	 	  	2012	 
	 Current service cost, net of employee contributions
	  	 	74	  	 	 	48	  	 	 	20	  	  	 	14	  
	 Interest cost
	  	 	138	  	 	 	142	  	 	 	32	  	  	 	32	  
	 Expected return on plan assets net of expenses1
	  	 	(154	) 	 	 	(144	) 	 	 	—  	  	  	 	—  	  
	 Actuarial loss amortization
	  	 	88	  	 	 	56	  	 	 	8	  	  	 	2	  
	 Prior service cost amortization
	  	 	—  	  	 	 	2	  	 	 	2	  	  	 	2	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	  	  
	  
	 
	 Net Periodic Benefit Cost
	  	 	146	  	 	 	104	  	 	 	62	  	  	 	50	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	  	  
	  
	 
	 Charged to results of operations2
	  	 	36	  	 	 	37	  	 	 	26	  	  	 	22	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	  	  
	  
	 

  

	1	 The expected
long-term rate of return on pension plan assets is 6.25%. 

	2	 The Company
follows the cash basis of accounting consistent with the inclusion of pension benefit costs in OEB-approved rates. 

  

	    	During the three and six months ended June 30, 2013, pension benefit costs of $39 million (2012 – $40 million) and $80 million (2012—$78 million),
respectively, were attributed to labour, of which $18 million (2012 – $19 million) and $36 million (2012—$37 million), respectively, was charged to operations, and $21 million (2012 – $21 million) and $44 million (2012—$41
million), respectively, was capitalized as part of the cost of property, plant and equipment and intangible assets. 

  

					
		  	29	  	

 HYDRO ONE INC. 
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited) (continued) 
 For the three and
six months ended June 30, 2013 and 2012 
  

 10. ENVIRONMENTAL LIABILITIES 
 The following table shows the movements in environmental liabilities for the six months ended June 30, 2013 and the year ended December 31, 2012. 

 

													
	 Six months ended June 30, 2013 (millions of dollars)
	  	PCB	 	 	LAR	 	 	Total	 
	 Environmental liabilities, January 1, 2013
	  	 	    197	  	 	 	    52	  	 	 	    249	  
	 Interest accretion
	  	 	4	  	 	 	1	  	 	 	5	  
	 Expenditures
	  	 	(1	) 	 	 	(6	) 	 	 	(7	) 
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Environmental liabilities, June 30, 2013
	  	 	200	  	 	 	47	  	 	 	247	  
	 Less: current portion
	  	 	(24	) 	 	 	(10	) 	 	 	(34	) 
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 
		  	 	176	  	 	 	37	  	 	 	213	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 
				
	 Year ended December 31, 2012 (millions of dollars)
	  	PCB	 	 	LAR	 	 	Total	 
	 Environmental liabilities, January 1, 2012
	  	 	199	  	 	 	58	  	 	 	257	  
	 Interest accretion
	  	 	9	  	 	 	2	  	 	 	11	  
	 Expenditures
	  	 	(8	) 	 	 	(10	) 	 	 	(18	) 
	 Revaluation adjustment
	  	 	(3	) 	 	 	2	  	 	 	(1	) 
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Environmental liabilities, December 31, 2012
	  	 	197	  	 	 	52	  	 	 	249	  
	 Less: current portion
	  	 	(13	) 	 	 	(9	) 	 	 	(22	) 
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 
		  	 	184	  	 	 	43	  	 	 	227	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 

 The following tables illustrate 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: 
  

													
	 June 30, 2013 (millions of dollars)
	  	PCB	 	 	LAR	 	 	Total	 
	 Undiscounted environmental liabilities
	  	 	    232	  	 	 	    48	  	 	 	    280	  
	 Less: discounting accumulated liabilities to present value
	  	 	(32	) 	 	 	(1	) 	 	 	(33	) 
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Discounted environmental liabilities
	  	 	200	  	 	 	47	  	 	 	247	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 
				
	 December 31, 2012 (millions of dollars)
	  	PCB	 	 	LAR	 	 	Total	 
	 Undiscounted environmental liabilities
	  	 	233	  	 	 	54	  	 	 	287	  
	 Less: discounting accumulated liabilities to present value
	  	 	(36	) 	 	 	(2	) 	 	 	(38	) 
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Discounted environmental liabilities
	  	 	197	  	 	 	52	  	 	 	249	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 

 At June 30, 2013, the estimated future environmental expenditures were as follows: 

 

					
	 (millions of dollars)
	  	 	 
	
20131
	  	 	15	  
	 2014
	  	 	38	  
	 2015
	  	 	36	  
	 2016
	  	 	22	  
	 2017
	  	 	17	  
	 Thereafter
	  	 	152	  
		  	  
	  
	 
		  	 	        280	  
		  	  
	  
	 

  

	1	 The amounts
disclosed represent amounts for the period July 1, 2013 to December 31, 2013. 

 At June 30, 2013, of the total estimated
future undiscounted environmental expenditures, $232 million (December 31, 2012 – $233 million) relate to polychlorinated biphenyl (PCB) and $48 million (December 31, 2012 – $54 million) relate to land assessment and remediation (LAR). The
estimated future environmental expenditures related to PCB and LAR are expected to be incurred over the period from 2013 to 2025, and from 2013 to 2020, respectively. 

  

					
		  	30	  	

 HYDRO ONE INC. 
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited) (continued) 
 For the three and
six months ended June 30, 2013 and 2012 
  

 Consistent with its accounting policy for environmental costs, Hydro One records a liability for the
estimated mandatory future expenditures associated with the removal and destruction of PCB-contaminated insulating oils and related electrical equipment and for the assessment and remediation of chemically-contaminated lands. 

There are uncertainties in estimating future environmental costs due to potential external events such as changes in legislation or regulations and
advances in remediation technologies. All factors used in estimating the Company’s environmental liabilities represent management’s best estimates of the present value of the cost required to meet existing legislation or regulations.
However, it is reasonably possible that numbers or volumes of contaminated assets, cost estimates to perform work, inflation assumptions and the assumed pattern of annual cash flows may differ significantly from the Company’s current
assumptions. In addition, with respect to the PCB environmental liability, the availability of critical resources such as skilled labour and replacement assets and the ability to take maintenance outages in critical facilities may influence the
timing of expenditures. Estimated environmental liabilities are reviewed annually or more frequently if significant changes in regulation or other relevant factors occur. Estimate changes are accounted for prospectively. The Company records a
regulatory asset reflecting its expectation that future environmental costs will be recoverable in rates. 
 In determining the amounts to be
recorded as environmental liabilities, the Company estimates the current cost of completing required work and makes assumptions as to when the future expenditures will actually be incurred, in order to generate future cash flow information. A
long-term inflation assumption of 2% has been used to express these current cost estimates as estimated future expenditures. Future environmental expenditures have been discounted using factors ranging from 3.57% to 6.25%, depending on the
appropriate rate for the period when increases in the obligations were first recorded. 
 In September 2008, Environment Canada published its
final regulations governing the management, storage and disposal of PCBs. These regulations were enacted under the Canadian Environmental Protection Act, 1999. These regulations impose timelines for disposal of PCBs based on certain criteria,
including type of equipment, in-use status and PCB-contamination thresholds. All PCBs in concentrations of 500 parts per million (ppm) or more, except for specified equipment, had to be disposed of by the end of 2009, with the exception of
specifically exempted equipment. Under the regulations, PCBs in equipment in concentrations greater than 50 ppm and less than 500 ppm, or greater than 50 ppm for pole-top transformers, pole-top auxiliary electrical equipment and light ballasts must
be disposed of by the end of 2025. 
 Management judges that the Company currently has very few PCB-contaminated assets in excess of 500 ppm.
Assets to be disposed of by 2025 primarily consist of pole-mounted distribution line transformers and light ballasts. Contaminated distribution and transmission station equipment will generally be replaced or will be decontaminated by removing
PCB-contaminated insulating oil and retro filling with replacement oil that contains PCBs in concentrations of less than 2 ppm. 
 11. 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. 

  

					
		  	31	  	

 HYDRO ONE INC. 
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited) (continued) 
 For the three and
six months ended June 30, 2013 and 2012 
  

 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 them in the event of change in ownership without approval of the Company’s Board of Directors. Because the conditional redemption feature is outside the control of the Company, the preferred
shares are classified outside of Shareholder’s Equity on the Consolidated Balance Sheets. Management believes that it is not probable that the preferred shares will become redeemable. No adjustment to the carrying value of the preferred shares
has been recognized at June 30, 2013 or December 31, 2012. If it becomes probable in the future that the preferred shares will be redeemed, the redemption value would be adjusted. 
 Common Shares 
 The Company has 100,000 issued and outstanding common shares. The Company is
authorized to issue an unlimited number of common shares. 
 Common share dividends are declared at the sole discretion of the Hydro One Board
of Directors, and are recommended by management based on results of operations, maintenance of the deemed regulatory capital structure, financial conditions, cash requirements, and other relevant factors, such as industry practice and shareholder
expectations. 
 Earnings per Share 
 Earnings per share is calculated as net income for the year, after cumulative preferred dividends, divided by the weighted average number of common shares outstanding during the year. 

12. DIVIDENDS 
 During the three months
ended June 30, 2013, preferred share dividends in the amount of $5 million (2012 – $5 million) and common share dividends in the amount of $25 million (2012 – $25 million) were declared. 

During the six months ended June 30, 2013, preferred share dividends in the amount of $9 million (2012 – $9 million) and common share dividends
in the amount of $150 million (2012 – $302 million) were declared. 
 13. RELATED PARTY TRANSACTIONS 

Hydro One is owned by the Province. The OEFC, Independent Electricity System Operator (IESO), Ontario Power Authority (OPA), Ontario Power Generation Inc.
(OPG) and the OEB are related parties to Hydro One because they are controlled or significantly influenced by the Province. 
 Hydro One
received revenue for transmission services from the IESO, based on OEB-approved uniform transmission rates. Transmission revenues for the three and six months ended June 30, 2013 include $363 million (2012 – $371 million) and $731 million
(2012 – $726 million), respectively, related to these services. Hydro One receives amounts for rural rate protection from the IESO. Distribution revenues for the three and six months ended June 30, 2013 include $31 million (2012 – $32
million) and $63 million (2012 – $64 million), respectively, 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 the three and
six months ended June 30, 2013 include $7 million (2012 – $7 million) and $14 million (2012 – $14 million), respectively, related to these services. 
 During the three and six months ended June 30, 2013, Hydro One purchased power in the amount of $538 million (2012 – $518 million) and $1,244 million (2012 – $1,180 million), respectively,
from the IESO-administered electricity market; $4 million (2012 – $1 million) and $9 million (2012 – $5 million), respectively, from OPG; and $3 million (2012 – $1 million) and $5 million (2012 – $3 million), respectively, from
the OEFC. 
 Under the Ontario Energy Board Act, 1998, the OEB is required to recover all of its annual operating costs from gas and
electricity distributors and transmitters. During the three and six months ended June 30, 2013, Hydro One incurred $3 million (2012 – $3 million) and $6 million (2012 – $6 million), respectively, in OEB fees. 

  

					
		  	32	  	

 HYDRO ONE INC. 
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited) (continued) 
 For the three and
six months ended June 30, 2013 and 2012 
  

 Hydro One has service level agreements with OPG. These services include field, engineering, logistics
and telecommunications services. During the three and six months ended June 30, 2013, revenues related to the provision of construction and equipment maintenance services with respect to these service level agreements were $3 million (2012
– $3 million) and $5 million (2012 – $5 million), respectively, primarily for the Transmission Business. Operation, maintenance and administration costs related to the purchase of services with respect to these service level agreements
were $1 million (2012 – $1 million) for the six months ended June 30, 2013, and insignificant for the three months ended June 30, 2013. 
 The OPA funds substantially all of the Company’s conservation and demand management programs. The funding includes program costs, incentives, and management fees. During the three and six months
ended June 30, 2013, Hydro One received $8 million (2012 – $7 million) and $15 million (2012 – $19 million), respectively, from the OPA related to these programs. 
 PILs and payments in lieu of property taxes are paid to the OEFC, and dividends are paid to the Province. 
 Sales to and purchases from related parties occur at normal market prices or at a proxy for fair value based on the requirements of the OEB’s Affiliate Relationships Code. Outstanding balances at
period end are unsecured, interest free and settled in cash. At June 30, 2013, the Company held $250 million in Province of Ontario Floating-Rate Notes with a fair value of $251 million (December 31, 2012 – $251 million). 

The amounts due to and from related parties as a result of the transactions referred to above are as follows: 

 

									
	 (millions of dollars)
	  	June 30,
2013	 	 	December 31,
2012	 
	 Due from related parties
	  	 	207	  	 	 	154	  
	 Due to related parties1
	  	 	(146	) 	 	 	(257	) 
	 Long-term investment
	  	 	251	  	 	 	251	  

  

	1	 Included in due to
related parties at June 30, 2013 are amounts owing to the IESO in respect of power purchases of $138 million (December 31, 2012 – $199 million). 

 14. CONSOLIDATED STATEMENTS OF CASH FLOWS 
 The changes in non-cash balances related to
operations consist of the following: 
  

																	
	 	  	Three months ended
June 30	 	 	Six months ended
June 30	 
	 (millions of dollars)
	  	2013	 	 	2012	 	 	2013	 	 	2012	 
	 Accounts receivable
	  	 	4	  	 	 	53	  	 	 	(117	) 	 	 	29	  
	 Due from related parties
	  	 	(40	) 	 	 	(17	) 	 	 	(53	) 	 	 	(26	) 
	 Materials and supplies
	  	 	1	  	 	 	1	  	 	 	(1	) 	 	 	2	  
	 Prepaid pension contributions
	  	 	39	  	 	 	(83	) 	 	 	(80	) 	 	 	(83	) 
	 Other assets
	  	 	(7	) 	 	 	(5	) 	 	 	(2	) 	 	 	4	  
	 Accounts payable
	  	 	2	  	 	 	(2	) 	 	 	(27	) 	 	 	(10	) 
	 Accrued liabilities
	  	 	59	  	 	 	17	  	 	 	99	  	 	 	(9	) 
	 Due to related parties
	  	 	(51	) 	 	 	(44	) 	 	 	(111	) 	 	 	(153	) 
	 Accrued interest
	  	 	(17	) 	 	 	(26	) 	 	 	(1	) 	 	 	9	  
	 Long-term accounts payable and other liabilities
	  	 	(6	) 	 	 	(1	) 	 	 	(8	) 	 	 	(1	) 
	 Post-retirement and post-employment benefit liability
	  	 	19	  	 	 	13	  	 	 	38	  	 	 	26	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
		  	 	3	  	 	 	(94	) 	 	 	(263	) 	 	 	(212	) 
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Supplementary information:
	  				 				 				 			
	 Net interest paid
	  	 	116	  	 	 	133	  	 	 	198	  	 	 	202	  
	 PILs
	  	 	31	  	 	 	25	  	 	 	76	  	 	 	139	  

  

					
		  	33	  	

 HYDRO ONE INC. 
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited) (continued) 
 For the three and
six months ended June 30, 2013 and 2012 
  

 15. CONTINGENCIES 
 Legal Proceedings 
 Hydro One is involved in various lawsuits, claims and regulatory
proceedings in the normal course of business. In the opinion of management, the outcome of such matters will not have a material adverse effect on the Company’s consolidated financial position, results of operations or cash flows. 

Transfer of Assets 
 The transfer
orders by which the Company acquired certain of Ontario Hydro’s businesses as of April 1, 1999 did not transfer title to some assets located on Reserves (as defined in the Indian Act (Canada)). Currently, the OEFC holds these
assets. Under the terms of the transfer orders, the Company is required to manage these assets until it has obtained all consents necessary to complete the transfer of title of these assets to itself. The Company cannot predict the aggregate amount
that it may have to pay, either on an annual or one-time basis, to obtain the required consents. However, the Company anticipates having to pay more than the $1 million that it paid in 2012. If the Company cannot obtain the required consents, the
OEFC will continue to hold these assets for an indefinite period of time. If the Company cannot reach a satisfactory settlement, it may have to relocate these assets to other locations at a cost that could be substantial or, in a limited number of
cases, to abandon a line and replace it with diesel-generation facilities. The costs relating to these assets could have a material adverse effect on the Company’s results of operations if the Company is not able to recover them in future rate
orders. 
 16. COMMITMENTS 

Agreement with Inergi LP (Inergi) 

Effective March 1, 2002, Inergi, a wholly-owned subsidiary of Cap Gemini Canada Inc., began providing services to Hydro One. On May 1, 2010,
consistent with the terms of the contract, the Company extended the Master Services Agreement with Inergi for a further three-year period. This agreement will expire on February 28, 2015. As a result of this agreement, Hydro One receives from
Inergi a range of services including business processing and information technology outsourcing services, as well as core system support related primarily to SAP implementation and optimization. 

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 June 30, 2013, the Company provided prudential support to the IESO on behalf
of Hydro One Networks and Hydro One Brampton Networks using parental guarantees of $325 million (December 31, 2012 – $325 million), and on behalf of two distributors using guarantees of approximately $1 million (December 31, 2012 – $1
million). Based on its credit rating category, the Company has provided letters of credit in the amount of $5 million (December 31, 2012 – $22 million) to the IESO. The IESO could draw on these guarantees and/or letters of credit if these
subsidiaries or distributors fail to make a payment required by a default notice issued by the IESO. The maximum potential payment is the face value of any letters of credit plus the nominal amount of the parental guarantees. 

Retirement Compensation Arrangements 
 Bank letters of credit have been issued to provide security for the Company’s liability under the terms of a trust fund established pursuant to the supplementary pension plan for 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 June 30, 2013, Hydro One had letters of credit of $127 million (December 31, 2012 – $127 million) outstanding relating to retirement compensation arrangements. 

  

					
		  	34	  	

 HYDRO ONE INC. 
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited) (continued) 
 For the three and
six months ended June 30, 2013 and 2012 
  

 17. SEGMENTED REPORTING 
 Hydro One has three reportable segments: 
  

	 	•	 	 The Transmission Business, which comprises the core business of providing electricity transportation and connection services, is responsible for
transmitting electricity throughout the Ontario electricity grid; 

  

	 	•	 	 The Distribution Business, which comprises the core business of delivering and selling electricity to customers; and 

 

	 	•	 	 Other, the operations of which primarily consist of those of the telecommunications business. 

The designation of segments has been based on a combination of regulatory status and the nature of the products and services provided. Operating segments
for the Company are determined based on information used by the chief operating decision maker in deciding how to allocate resources and evaluate the performance at each of the segments. The Company evaluates segment performance based on income
before financing charges and provision for PILs from continuing operations (excluding certain allocated corporate governance costs). 
 The
accounting policies followed by the segments are the same as those followed by the Company. Segment information on the above basis is as follows: 
  

																	
	 Three months ended June 30, 2013 (millions of dollars)
	 	Transmission	 	 	Distribution	 	 	Other	 	 	Consolidated	 
	 Segment profit
	 				 				 				 			
	 Revenues
	 	 	368	  	 	 	1,020	  	 	 	15	  	 	 	1,403	  
	 Purchased power
	 	 	—  	  	 	 	684	  	 	 	—  	  	 	 	684	  
	 Operation, maintenance and administration
	 	 	105	  	 	 	170	  	 	 	16	  	 	 	291	  
	 Depreciation and amortization
	 	 	78	  	 	 	80	  	 	 	2	  	 	 	160	  
		 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Income (loss) before financing charges and provision for PILs
	 	 	185	  	 	 	86	  	 	 	(3	) 	 	 	268	  
	 Financing charges
	 				 				 				 	 	89	  
		 				 				 				 	  
	  
	 
	 Income before provision for PILs
	 				 				 				 	 	179	  
		 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Capital expenditures
	 	 	157	  	 	 	192	  	 	 	2	  	 	 	351	  
		 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
					
	 Three months ended June 30, 2012 (millions of dollars)
	 	Transmission	 	 	Distribution	 	 	Other	 	 	Consolidated	 
	 Segment profit
	 				 				 				 			
	 Revenues
	 	 	370	  	 	 	974	  	 	 	15	  	 	 	1,359	  
	 Purchased power
	 	 	—  	  	 	 	640	  	 	 	—  	  	 	 	640	  
	 Operation, maintenance and administration
	 	 	102	  	 	 	156	  	 	 	20	  	 	 	278	  
	 Depreciation and amortization
	 	 	77	  	 	 	78	  	 	 	3	  	 	 	158	  
		 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Income (loss) before financing charges and provision for PILs
	 	 	191	  	 	 	100	  	 	 	(8	) 	 	 	283	  
	 Financing charges
	 				 				 				 	 	90	  
		 				 				 				 	  
	  
	 
	 Income before provision for PILs
	 				 				 				 	 	193	  
		 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Capital expenditures
	 	 	189	  	 	 	161	  	 	 	—  	  	 	 	350	  
		 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 

  

					
		  	35	  	

 HYDRO ONE INC. 
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited) (continued) 
 For the three and
six months ended June 30, 2013 and 2012 
  

																	
	 Six months ended June 30, 2013 (millions of dollars)
	 	Transmission	 	 	Distribution	 	 	Other	 	 	Consolidated	 
	 Segment profit
	 				 				 				 			
	 Revenues
	 	 	741	  	 	 	2,204	  	 	 	30	  	 	 	2,975	  
	 Purchased power
	 	 	—  	  	 	 	1,482	  	 	 	—  	  	 	 	1,482	  
	 Operation, maintenance and administration
	 	 	177	  	 	 	317	  	 	 	30	  	 	 	524	  
	 Depreciation and amortization
	 	 	158	  	 	 	159	  	 	 	4	  	 	 	321	  
		 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Income (loss) before financing charges and provision for PILs
	 	 	406	  	 	 	246	  	 	 	(4	) 	 	 	648	  
	 Financing charges
	 				 				 				 	 	177	  
		 				 				 				 	  
	  
	 
	 Income before provision for PILs
	 				 				 				 	 	471	  
		 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Capital expenditures
	 	 	306	  	 	 	312	  	 	 	3	  	 	 	621	  
		 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
					
	 Six months ended June 30, 2012 (millions of dollars)
	 	Transmission	 	 	Distribution	 	 	Other	 	 	Consolidated	 
	 Segment profit
	 				 				 				 			
	 Revenues
	 	 	731	  	 	 	2,065	  	 	 	31	  	 	 	2,827	  
	 Purchased power
	 	 	—  	  	 	 	1,369	  	 	 	—  	  	 	 	1,369	  
	 Operation, maintenance and administration
	 	 	214	  	 	 	296	  	 	 	30	  	 	 	540	  
	 Depreciation and amortization
	 	 	152	  	 	 	153	  	 	 	5	  	 	 	310	  
		 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Income (loss) before financing charges and provision for PILs
	 	 	365	  	 	 	247	  	 	 	(4	) 	 	 	608	  
	 Financing charges
	 				 				 				 	 	173	  
		 				 				 				 	  
	  
	 
	 Income before provision for PILs
	 				 				 				 	 	435	  
		 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Capital expenditures
	 	 	376	  	 	 	288	  	 	 	        3	  	 	 	667	  
		 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 

  

									
	 	  	June 30,	 	  	December 31,	 
	 (millions of dollars)
	  	2013	 	  	2012	 
	 Transmission
	  	 	11,948	  	  	 	11,586	  
	 Distribution
	  	 	8,418	  	  	 	8,621	  
	 Other
	  	 	923	  	  	 	604	  
		  	  
	  
	 	  	  
	  
	 
	 Total assets
	  	 	21,289	  	  	 	20,811	  
		  	  
	  
	 	  	  
	  
	 

 All revenues, costs and assets, as the case may be, are earned, incurred or held in Canada. 

  

					
		  	36EX-10.2

 Exhibit 10.2 
 FIRST AMENDMENT TO 
 AMENDED AND RESTATED MASTER SEPARATION AGREEMENT

 This FIRST AMENDMENT TO AMENDED AND RESTATED MASTER SEPARATION AGREEMENT (this “First Amendment”), dated
as of July 22, 2013, is made by and between COMPUWARE CORPORATION, a Michigan corporation (“Compuware”) and COVISINT CORPORATION, a Michigan corporation (“Covisint”), and amends that certain Amended and
Restated Master Separation Agreement, dated as of May 13, 2013, by and between Compuware and Covisint (the “Master Separation Agreement”). Capitalized terms used and not defined herein have the respective meanings ascribed
thereto in the Master Separation Agreement. 
 Background 

Compuware and Covisint have requested a modification to the definition of “Purchase Date” in the Master Separation Agreement.

 NOW, THEREFORE, in consideration of the promises and the agreements, provisions and covenants herein contained, Compuware and
Covisint hereby agree as follows: 
 1. Amendment. The definition of “Purchase Date”, as set forth in
Section 1.1 of the Master Separation Agreement, is hereby amended in its entirety to read as follows: 

“Purchase Date” means (i) the delivery date of an option holder’s notice of intended exercise
of options to purchase Common Stock granted pursuant to the Covisint 2009 Long Term Incentive Plan or (ii) the date immediately preceding the effective date of the occurrence of any other event that would (but for Section 7.1) cause
the Vote Ownership Percentage to fall below 80.1%. 
 2. Miscellaneous. 

(a) Ratification. The terms and provisions set forth in this First Amendment shall modify and supersede all inconsistent
terms and provisions set forth in the Master Separation Agreement and except as expressly modified and superseded by this First Amendment, the terms and provisions of the Master Separation Agreement are ratified and confirmed and shall continue in
full force and effect. Compuware and Covisint agree that the Master Separation Agreement as amended hereby shall continue to be legal, valid, binding and enforceable in accordance with its terms. 

(b) Counterparts. This First Amendment may be executed in one or more counterparts and on facsimile counterparts, each of
which when so executed shall be deemed to be an original, but all of which when taken together shall constitute one and the same agreement. 
 (c) Interpretation. The headings contained in this First Amendment are for reference purposes only and shall not affect in any way the meaning or interpretation of this First Amendment.

 IN WITNESS WHEREOF, the parties hereto have executed this First Amendment as of the date
first above written. 
  

			
	COMPUWARE CORPORATION
		
	By:	 	 /S/ DANIEL S. FOLLIS,
JR.

		
	Name:	 	Daniel S. Follis, Jr.
		
	Title:	 	Senior Vice President, General Counsel and Secretary

  

			
	COVISINT CORPORATION
		
	By:	 	 /S/ DAVID A. MCGUFFIE

		
	Name:	 	David A. McGuffie
		
	Title:	 	President and Chief Executive Officer

 [Signature Page to Amended and Restated Master Separation Agreement]

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