MANAGEMENT S DISCUSSION AND ANALYSIS

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MANAGEMENT’S DISCUSSION AND ANALYSIS

FOR THE THREE MONTHS ENDED

MARCH 31, 2013

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M A N A G E M E N T’S D I S C U S S I O N A N D A N A L Y S I S

This MD&A should be read in conjunction with the Corporation’s unaudited interim consolidated financial statements for the three months ended March 31, 2013, (2013 Interim Financial Statements), the previous MD&A (2012 MD&A) and the audited consolidated financial statements for the year ended December 31, 2012. Information contained in the 2012 MD&A is not discussed if it remains

substantially unchanged. This MD&A is dated April 25, 2013. Additional information relating to the

Corporation, including the Corporation’s annual information form, is available on SEDAR at www.sedar.com.

Terms used throughout this MD&A are defined in the Glossary located at the end of the document.

 The first quarter Adjusted Earnings were higher mainly due to the growth in rate base in ATCO Electric and ATCO Gas, offset by lower Adjusted Earnings in ATCO Power due to lower realized prices on forward power sales contracts compared to the prior year and an unfavourable PPA arbitration decision.

Dividends

 On April 19, 2013, the Board of Directors declared a second quarter dividend of 48.5 cents per share.

Financing Activities

 On February 21, 2013, the Corporation announced that it intends to split its Class A non-voting shares and Class B common shares on a two-for-one basis by way of a share dividend in 2013.  On March 1, 2013, the Corporation issued 438,597 Class A non-voting shares under its dividend

reinvestment plan (DRIP) in lieu of making cash dividend payments of $33 million.

 On March 19, 2013, the Corporation issued $175 million of 4.50% Cumulative Redeemable Second Preferred Shares Series CC.

Recent Developments

 Direct Energy has advised that it intends to transition the billing and call centre services provided by ATCO I-Tek to a new service provider following the expiration of their contract on December 31, 2014.

 On April 23, 2013, ATCO Energy Solutions announced it had reached agreement with North West Redwater Partnership (NWR) to provide essential industrial water infrastructure services, through its expanded Alberta Industrial Heartland Water System, to NWR’s Sturgeon Refinery near Redwater, Alberta.

Regulatory Decisions

 Effective January 1, 2013, ATCO Gas and the distribution operations of ATCO Electric moved to a form of rate regulation referred to as Performance Based Regulation (PBR). This form of regulation continues to allow these Utilities to recover prudently incurred operating costs of providing regulatory services and earn a fair return on investment.

 On February 28, 2013, ATCO Pipelines received a decision on its 2012 Final Revenue Requirement. In this decision, the AUC approved one of three Urban Pipeline Replacement (UPR) projects that had been denied in ATCO Pipelines’ 2012 Interim Revenue Requirement Decision.

 On March 4, 2013, the AUC denied the review and variance application that the Corporation had filed in respect of the AUC’s original PBR decision but the AUC approved interim rates effective April 1, 2013, for the recovery of 60% of the incremental capital related funding requested in ATCO Electric’s and ATCO Gas’ capital tracker applications.

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C O M P A N Y O V E R V I E W

Canadian Utilities Limited, an ATCO Company, with more than 7,100 employees and assets of approximately $14 billion, delivers service excellence and innovative business solutions worldwide with leading companies engaged in utilities (pipelines, natural gas and electricity transmission and distribution), energy (power generation, natural gas gathering, processing, storage and liquids extraction), and technologies (business systems solutions).

The consolidated interim financial statements include the accounts of Canadian Utilities Limited, its subsidiaries, including the equity investment in joint ventures and a proportionate share of joint operations, and its 24.5% equity investment in ATCO Structures & Logistics. The consolidated interim financial statements for the three months ended March 31, 2013, have been prepared in accordance with International Financial Reporting Standards (IFRS) applicable to the preparation of interim financial statements, including International Accounting Standard 34, Interim Financial Reporting. The reporting currency is the Canadian dollar.

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Simplified Organization Structure

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Regulated operations include ATCO Gas, ATCO Electric, ATCO Pipelines, ATCO Gas Australia and the Battle River and Sheerness generating plants of ATCO Power.

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R E S U L T S O F O P E R A T I O N S

S U M M A R Y O F A C C O U N T I N G C H A N G E S

The Corporation adopted IFRS 11 Joint Arrangements effective January 1, 2013. Under IFRS 11, the Corporation’s joint arrangements that are classified as joint ventures are accounted for under the equity method of accounting, whereas previously they were proportionately consolidated. ATCO Power and ATCO Australia are affected by the adoption of IFRS 11. This change in accounting policy reduced total assets, total liabilities, revenues and expenses but had no impact on the Corporation’s net assets, earnings, earnings per share or Adjusted Earnings.

The Corporation adopted amendments to IAS 19 Employee Benefits effective January 1, 2013. The Corporation has applied the amendments retrospectively effective January 1, 2012, in accordance with the transition provisions of IAS 19. The only significant change for the Corporation is that the expected return on assets and interest cost on pension obligations are combined into a net interest cost calculated using a single discount rate on net pension assets or liabilities. As the expected return on assets, which included an equity and management premium, was previously higher than the liability discount rate, this change resulted in higher retirement benefit costs, lower earnings and increased retirement benefit obligations. This change in accounting policy decreased Adjusted Earnings by $1 million (earnings per share by $0.03) for each of the three months ended March 31, 2013 and 2012, respectively.

Comparative data for 2012 has been restated and the effects of these changes on the Corporation’s consolidated results for the three months ended March 31, 2012, are summarized in Appendix I.

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S E L E C T E D Q U A R T E R L Y I N F O R M A T I O N

The following table shows the quarterly financial information for each of the eight quarters ended June 30, 2011, through March 31, 2013:

($ millions except per share data) (1) Q2 2012 Q3 2012 Q4 2012 Q1 2013

Revenues 685 714 829 876

Earnings attributable to equity owners of the Corporation 104 117 142 183

Earnings per Class A and Class B Share 0.74 0.85 1.05 1.36 Diluted earnings per Class A and Class B Share 0.73 0.85 1.05 1.36 Adjusted Earnings: Utilities 50 33 91 126

Energy 9 49 31 28

ATCO Australia 18 12 7 10

Corporate & Other 18 11 12 16

Total Adjusted Earnings 95 105 141 180

($ millions except per share data) (1) Q2 2011 Q3 2011 Q4 2011 Q1 2012 Revenues 666 697 827 811

Earnings attributable to equity owners of the Corporation 98 66 156 190

Earnings per Class A and Class B Share 0.70 0.47 1.14 1.42 Diluted earnings per Class A and Class B Share 0.70 0.47 1.14 1.42 Adjusted Earnings: Utilities 42 34 59 108

Energy 28 50 32 47

ATCO Australia 2 11 2 6

Corporate & Other 18 11 16 13

Total Adjusted Earnings 90 106 109 174

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The above data has been extracted from financial statements prepared in accordance with IFRS. The reporting currency is the Canadian dollar. The figures for 2012 have been restated to incorporate the impact of adopting IFRS 11 Joint Arrangements and amendments to IAS 19 Employee Benefits. The figures for 2011 have not been restated.

The principal factors that caused variations in the results and financial condition for the previous eight quarters remain substantially unchanged from the factors discussed in the 2012 MD&A.

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C O N S O L I D A T E D R E V E N U E S A N D E A R N I N G S

Revenues for the three months ended March 31, 2013, increased by $65 million over the same period in

2012. This increase was mainly due to the growth in rate base in ATCO Electric and ATCO Gas, and higher flow-through natural gas sales in ATCO Energy Solutions’ NGL extraction operations.

Adjusted Earnings for the three months ended March 31, 2013, were $180 million, an increase of

$6million over the same period in 2012, primarily due to the growth in rate base in ATCO Electric and ATCO Gas, partially offset by lower realized prices on forward power sales contracts compared to the prior year and an unfavourable PPA arbitration decision in ATCO Power.

Earnings attributable to equity owners of the Corporation for the three months ended

March 31, 2013, were $183 million, a decrease of $7 million compared to the same period in 2012. Earnings attributable to equity owners of the Corporation will differ from Adjusted Earnings because of the timing of recovery from or refunds to customers related to amounts that are deferred for regulatory purposes; however, over time, there is no difference. Refer to the “Importance of Adjusted Earnings” section for a reconciliation of Adjusted Earnings to earnings attributable to equity owners of the Corporation.

C O N S O L I D A T E D E X P E N S E S

($ millions) 2013 2012(1) Change

Costs and expenses:

Salaries, wages and benefits 106 108 (2)

Energy transmission and transportation 35 32 3

Plant and equipment maintenance 40 44 (4)

Fuel costs 99 70 29

Purchased power 18 17 1

Materials and consumables 10 9 1

Franchise fees 59 52 7

Property and other taxes 23 20 3

Other 77 52 25

467 404 63

Depreciation and amortization 110 100 10

Interest expense 67 68 (1)

Income taxes 58 58 -For the Three Months Ended

March 31

(1)

The figures for 2012 have been restated to incorporate the impact of adopting IFRS 11 Joint Arrangements and amendments to IAS 19 Employee Benefits. Also, certain comparative amounts have been reclassified to conform to the presentation adopted in the current year.

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Fuel costs for the three months ended March 31, 2013, increased by $29 million over the same period in

2012, primarily due to higher flow-through natural gas purchases for NGL extraction operations in ATCO Energy Solutions and increased flow-through costs of coal supply at the Battle River generating plant in ATCO Power. The flow-through costs are offset in revenues resulting in no impact to Adjusted Earnings.

Other expenses for the three months ended March 31, 2013, increased by $25 million over the same

period in 2012, mainly due to charges recorded for an unfavourable PPA arbitration decision and lower realized prices on forward power sales contracts compared to the prior year in ATCO Power.

Depreciation and amortization expense for the three months ended March 31, 2013, increased by

$10 million over the same period in 2012, primarily due to capital investments in the Utilities.

C O N S O L I D A T E D C A S H F L O W

($ millions) 2013 2012 Change

Cash position, beginning of period 349 586 (237)

Cash provided by Operating activities Funds Generated by Operations 411 411

-Changes in non-cash working capital 52 10 42

Cash flow from operations 463 421 42

Investing activities (456) (425) (31)

Financing activities 81 (137) 218

Foreign currency impact on cash balances 1 - 1

Cash position, end of period 438 445 (7) For the Three Months Ended

March 31

Operating Activities

Funds Generated by Operations were unchanged compared to the same period in 2012. Funds

Generated by Operations increased primarily due to higher income tax payments in ATCO Power in the first quarter of 2012, offset against lower contributions by customers in ATCO Electric.

Cash flow from operations increased by $42 million over the same period in 2012 due to an increase in

changes in non-cash working capital, mainly from lower accounts receivable in ATCO Power due to timing of receipt of the monthly settlement from the Alberta Electric System Operator (AESO).

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Investing Activities

Capital expenditures for the three months ended March 31, 2013, are shown in the following table:

($ millions) (1) 2013 2012 Change Utilities Electric Transmission 374 354 20 Electric Distribution 68 77 (9) Gas Distribution 55 56 (1) Pipeline Transmission 14 12 2 Energy 3 4 (1) ATCO Australia 18 11 7

Corporate & Other 7 3 4

Total 539 517 22 March 31

For the Three Months Ended

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Includes additions to property, plant and equipment and intangibles as well as $18 million (2012 - $12 million) of interest capitalized during construction for the three months ended March 31, 2013.

Cash used in investing activities increased by $31 million over the same period in 2012, mainly due to

the higher capital investment in regulated transmission infrastructure projects in ATCO Electric, which included significant expenditures related to the Hanna Region Transmission Development (HRTD) and the Eastern Alberta Transmission Line (EATL) projects.

Financing Activities

Financing activities increased by $218 million over the same period in 2012 primarily due to the

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S E G M E N T E D I N F O R M A T I O N

2013 ATCO Corporate

2012 (1) Utilities Energy Australia & Other Eliminations Total

($ millions) Revenues 551 249 61 55 (40) 876 517 223 52 56 (37) 811 Adjusted Earnings 126 28 10 17 (1) 180 108 47 6 13 - 174

Adjustments for rate (2) - (2) - (1) (5)

regulated activities (2) 11 - (3) - (1) 7

Dividends on equity preferred 1 - - 7 - 8

shares of Canadian Utilities Limited 1 - - 8 - 9

Earnings attributable 125 28 8 24 (2) 183

to equity owners of the Corporation 120 47 3 21 (1) 190 For the Three Months Ended March 31

(1)

Figures for 2012 have been restated to incorporate the impact of adopting IFRS 11 Joint Arrangements and amendments to IAS 19 Employee Benefits. Refer to Appendix I for a summary of the effects of these changes on the Corporation’s consolidated results for the three months ended March 31, 2012.

(2)

Refer to the “Importance of Adjusted Earnings” section for a description of the adjustments.

UTILITIES

The activities of the Utilities segment are conducted primarily through ATCO Gas, ATCO Electric and ATCO Pipelines within Western Canada.

2012. The increase was primarily attributable to the growth in rate base in ATCO Electric and ATCO Gas.

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Adjusted Earnings for each of the Utilities are shown in the following table:

($ millions) 2013 2012 Change ATCO Electric 58 47 11 ATCO Gas 57 53 4 ATCO Pipelines 11 8 3 Total Utilities 126 108 18 March 31

Adjusted Earnings for the three months ended March 31, 2013, were $126 million, an increase of

$18 million over the same period in 2012. This increase was mainly due to the growth in rate base in ATCO Electric and ATCO Gas.

Regulatory Environment

Rate Regulation

The Utilities are regulated primarily by the AUC, which administers acts and regulations covering such matters as rates, financing and service area. In 2013, the AUC introduced Performance Based Regulation (PBR) for distribution utilities in Alberta. Whereas previously, the distribution utilities would have made regular cost of service applications to the AUC to recover forecast costs from customers, under PBR, revenue will be determined by a formula that adjusts customer rates over a five-year period from 2013 to 2017 by inflation and expected productivity improvements.

The transmission operations of ATCO Pipelines and ATCO Electric continue to be subject to a cost of service regulatory mechanism; the distribution operations of ATCO Gas and ATCO Electric are under PBR. Both of these approaches establish the revenues required:

 To recover prudently incurred operating costs of providing the regulated services, and  To provide a fair return on utility investment.

The PBR formula incorporates the following “Factors”:

 Estimation of annual inflation relevant to the respective price of inputs (I Factor);

 Less an offset to reflect productivity improvements expected to be achieved during the PBR plan period (X Factor).

PBR also includes additional mechanisms to allow for:

 Recovery of capital expenditures that would not otherwise be recoverable through the PBR formula that are significant and meet certain criteria (K Factor);

 Recovery from or refund to customers of amounts that are outside of management’s ability to control, are material in nature, should not have significant influence on the I Factor, are prudently incurred, must be of a recurring nature and have potential for high variability from year to year (Y Factor); and

 Recovery from or refund to customers of amounts that are outside of management’s ability to control, are material in nature, should not have significant influence on the I Factor, are prudently incurred, are unforeseen and are not of a recurring nature (Z Factor).

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On March 4, 2013, the AUC denied the review and variance application that the Corporation had filed in the fourth quarter of 2012 in respect of the AUC’s original PBR decision. An application for leave to appeal this decision has been filed with the Alberta Court of Appeal. It is expected that this leave to appeal application, along with the leave to appeal application that was filed in the fourth quarter of 2012 in regard to the original PBR decision, will be held in reserve until final decisions on other outstanding PBR proceedings have been issued. Final rates for 2013 are not expected to be known before the fourth quarter of 2013. The AUC approved interim rates effective April 1, 2013, for the recovery of 60% of the incremental capital related funding requested (refer to K Factor above).

Pension Hearing

As a result of the AUC’s decision to limit recovery of annual cost of living allowance (COLA) adjustments to 50% of the Consumer Price Index subject to a maximum COLA adjustment of 3%, the current estimate for the reduction in pension cost recoveries from customers in 2013 is $26 million, which would result in a decrease to the Corporation’s Adjusted Earnings of $19 million. Adjusted Earnings decreased $4 million in the first quarter of 2013. The effect on 2013 is dependent on the results of the next actuarial valuation for funding purposes, which will be available in the second quarter of 2013. The Alberta Court of Appeal has granted the Utilities leave to appeal the AUC decision. The appeal hearing is set for the second quarter of 2013. In addition, the Corporation will make an application in the second quarter of 2013 to recover 100% of COLA adjustments for 2013.

The AESO Competitive Process

The Government of Alberta’s Provincial Energy Strategy directed the AESO to develop a process and model for the competitive procurement of new electricity transmission facilities without regard for service area. On February 14, 2013, the AUC approved the AESO’s Competitive Process Application subject to certain conditions. The competitive model is limited to those facilities designated as “Critical Transmission Infrastructure”.

The AESO has outlined a competitive process for the Fort McMurray West Transmission Project. This Project consists of a 500 kV transmission line from Edmonton to Fort McMurray, at an estimated cost of $1.6 billion, with an anticipated in service date of 2018. Currently, the process calls for the AESO to request for Expressions of Interest (EOI) in the second quarter of 2013 followed by Requests for Qualifications (RFQ) and then Requests for Proposal (RFP).

On April 10, 2013, the AESO challenged the bidding process approved by the AUC, which allows each participant to choose its own price adjustment mechanisms. On April 12, 2013, the AUC issued a letter indicating that it will review its decision to ensure that the competitive process be perceived by participants to be fair and transparent.

ATCO Gas 2011 and 2012 General Rate Application

In February 2012, ATCO Gas filed a review and variance application with the AUC focusing on challenging the AUC’s denial of ATCO Gas’ right to recover prudently incurred costs approved by the AUC in prior regulatory decisions. A decision was received on February 22, 2013. As a result of this decision, ATCO Gas recorded increased Adjusted Earnings of $2 million.

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Generic Cost of Capital (GCOC)

On October 18, 2012, the AUC invited interested parties to comment on the proposed scope of the 2013 GCOC proceeding. On April 4, 2013, the AUC indicated its intent to commence the GCOC proceeding subsequent to the release of decisions on PBR capital expenditures and the Utility Asset Disposition proceeding later in 2013. The current interim rate of return on common equity is 8.75%.

Corporate Costs

On March 21, 2013, the AUC issued a decision in regards to the quantum of total corporate costs and revised the methodology by which these costs are allocated. As a result of this decision, there were no major cost disallowances in the quantum of total costs. However, this revised allocation methodology will impact the allocated corporate costs for ATCO Electric and ATCO Gas for 2012. The Corporation recognized lower Adjusted Earnings of $4 million for the period January 1, 2012, to March 31, 2013.

ATCO Electric Transmission 2013 and 2014 General Tariff Application (GTA)

In June 2012, ATCO Electric filed a GTA for its transmission operations for 2013 and 2014. The application requests, among other things, additional revenues to recover higher financing, depreciation and operating costs associated with growth in rate base in Alberta. On January 18, 2013, the AUC issued an interim rate decision approving 50% of the rate increase requested in the GTA. A decision on the application is expected in the second quarter of 2013.

Major Project Updates

The AESO has identified the need to reinforce Alberta's electricity system to meet growing demands for electricity in Alberta. ATCO Electric is dedicated to improving Alberta’s electrical system through responsible transmission development. Approximately $4 billion in ATCO Electric capital expenditures are expected in the 2013-2015 period assuming the associated regulatory approvals are obtained in a timely manner.

Eastern Alberta Transmission Line Project

On November 15, 2012, ATCO Electric received approval from the AUC to commence construction of the EATL project. The 500 kV high voltage direct-current transmission line and its associated converter stations and facilities extends approximately 485 km along a corridor on the east side of the province between Edmonton and Calgary adding additional capacity to Alberta’s existing electricity transmission system. The estimated project cost, excluding capitalized interest during construction, is $1.6 billion, of which $398 million has been incurred as of March 31, 2013. Approximately $700 million of project costs are expected to be incurred in 2013, with the balance in 2014. Construction commenced on the project in late December 2012 with an expected in service date of late 2014.

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Hanna Region Transmission Development Project

ATCO Electric’s share of the major transmission reinforcement of the southeast region of the province, the HRTD project, is comprised of approximately 355 km of transmission lines, the construction of six new substations, and modifications to and expansions of a further 14 existing substations. Construction began in May 2012 after final project approvals were received from the AUC. The estimated total project cost, excluding capitalized interest during construction, has decreased from $735 million to $693 million, of which $584 million has been incurred as of March 31, 2013. The majority of the remaining project costs of $109 million will be incurred in the second quarter of 2013 at which point the transmission infrastructure is expected to be in service.

Northwest Fort McMurray Transmission Development Project

ATCO Electric has received direction from the AESO to undertake a project northwest of Fort McMurray in response to several requests for transmission system access in the area where significant load and generation requirements have been forecast for oil sands developments. The AUC approved the AESO’s Needs Identification Document (NID) in June 2012. The project consists of constructing two new substations and approximately 140 km of transmission line. The estimated project cost, excluding capitalized interest during construction, is approximately $370 million, of which $4 million has been incurred as of March 31, 2013. Approximately $35 million of the project costs are expected to be incurred in 2013 with the balance being incurred evenly over 2014 and 2015. Final approvals from the AUC are expected in the fourth quarter of 2013 with an expected in service date of the second quarter of 2015.

Urban Pipeline Replacement Proceeding

In a decision issued on February 28, 2013, the AUC allowed the inclusion in ATCO Pipelines’ 2012 Final Revenue Requirement of one of the three previously approved UPR projects. The AUC allowed the two other projects to remain in construction work in progress. These projects will be reviewed in the AUC’s UPR proceeding. On March 19, 2013, ATCO Pipelines filed its UPR application requesting the approval of the entire UPR project. The AUC is planning its own public consultation program, in addition to the one carried out by ATCO Pipelines. A decision is not expected until late 2013 or early 2014.

ENERGY

The Energy segment includes the non-regulated supply of electricity and cogeneration steam by ATCO Power, the regulated supply of electricity by ATCO Power, and the non-regulated gathering, processing, storage and transmission of natural gas, extraction of natural gas liquids, transmission of electricity and provision of industrial water services by ATCO Energy Solutions.

2012. ATCO Energy Solutions’ revenues reflected increased throughput of natural gas at certain NGL extraction facilities and consequential higher flow-through natural gas sales, partially offset by lower prices. Storage revenues were also higher due to increased volumes and higher Storage Price Differentials. ATCO Power’s revenues were higher mainly because of higher flow-through revenues at the Battle River generating plant and higher amortization of unearned availability incentives, partially offset by lower merchant sales at the Muskeg River generating plant as the off-taker increased its capacity requirements.

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Adjusted Earnings for ATCO Power and ATCO Energy Solutions are shown in the following table:

ATCO Power

Independent Power Plants 13 25 (12)

Regulated Power Plants 12 18 (6)

Other 1 1

-Total ATCO Power 26 44 (18)

ATCO Energy Solutions Storage Operations 2 (1) 3

NGL Extraction and Gas Gathering & Processing 3 6 (3)

Other Operations (3) (2) (1)

Total ATCO Energy Solutions 2 3 (1)

Total Energy 28 47 (19) For the Three Months Ended

March 31

Adjusted Earnings for the three months ended March 31, 2013, decreased by $19 million compared to

the same period in 2012. Adjusted Earnings in ATCO Power’s independent power plants in Alberta were lower mainly due to lower realized prices on forward power sales contracts compared to the prior year. Also contributing to decreased earnings were lower merchant sales at the Muskeg River generating plant as the off-taker increased its capacity requirements. Adjusted Earnings in ATCO Power’s regulated power plants were lower mainly due to an unfavourable PPA arbitration decision of $5 million, partially offset by higher amortization of unearned availability incentives. Adjusted Earnings in ATCO Energy Solutions decreased due to lower Frac Spreads combined with lower volumes in NGL extraction operations, partially offset by higher storage volumes and Storage Price Differentials.

Power Generation

Availability of the generating plants by geographic region is provided below:

2013 2012 Change

Independent Power Plants - Canada and U.K. (1) 96.1% 96.0% 0.1%

Regulated Plants - Canada (1) 96.7% 97.6% (0.9%)

For the Three Months Ended March 31

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Merchant Operations

As at March 31, 2013, ATCO Power owned a total generating capacity of 2,550 MW, of which 1,815 MW is in Alberta.

The majority of ATCO Power’s electricity sales to the Alberta Power Pool are from natural gas fired generating plants and, as a result, earnings are affected primarily by Alberta Power Pool prices and natural gas prices. ATCO Power uses financial and physical forward power and gas contracts to manage electricity and natural gas prices for a portion of its portfolio. The average Alberta Power Pool electricity prices, natural gas prices and resulting Spark Spreads for the three months ended March 31, 2013, are shown in the following table:

2013 2012 Change

Average Alberta Power Pool electricity price ($/MWh) 65.33 60.12 9%

Average natural gas price ($/GJ) 3.03 2.06 47%

Average Spark Spread ($/MWh) 42.61 44.70 (5%)

March 31

The following chart demonstrates the volatility of monthly average Spark Spreads for the Alberta electricity market since the beginning of 2009. Earnings do not necessarily correlate with these monthly average Spark Spreads as they are also dependent on short term price volatility. The volatility of prices is dependent on a number of key factors which, in combination or in isolation, impact the market and ultimate electricity price. These major factors include, but are not limited to, electricity demand and electricity supply primarily from Alberta’s coal and wind generation. ATCO Power may periodically use financial forward power sales and natural gas contracts to secure favourable Alberta Spark Spreads.

Alberta Spark Spreads

$0 $20 $40 $60 $80 $100 $120 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 2009 2010 2011 2012 2013 A lbe r ta Spa r k Spr e a d ($ / M e gaw at t h ou r )

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ATCO Energy Solutions

Storage Operations

ATCO Energy Solutions owns 43.5 PJs of natural gas storage capacity in Alberta. The majority of ATCO Energy Solutions’ natural gas storage revenues come from seasonal differences in the price of natural gas (Storage Price Differentials). The natural gas storage business is impacted by volatility in the seasonal natural gas price spreads, which are determined by the differential in natural gas prices between the traditional summer injection (April to October) and winter withdrawal (November to March) season. These differences are the result of imbalances between supply and demand for natural gas. ATCO Energy Solutions contracts with a range of customers, including financial institutions, marketers, and utilities. ATCO Energy Solutions provides customers with services to contract for long term (multi-year) as well as short term (less than one year).

Seasonal Storage Price Differentials in the 2012-2013 storage year, which ended on March 31, 2013, were higher than the Storage Price Differentials for the 2011-2012 storage year which ended on March 31, 2012, resulting in higher storage revenues in the first quarter of 2013 compared to the same period in 2012.

NGL Extraction and Gas Gathering & Processing Operations

ATCO Energy Solutions’ revenues derived from natural gas and liquids gathering, processing, extraction and transportation operations are a combination of fixed fee, take or pay and cost of service contracts. Operating statistics for the three months ended March 31, 2013, are shown in the following table:

2013 2012 Change

NGL Extraction

NGL extraction plant capacity (mmcf/d) 411.0 411.0 -Extraction inlet gas processed (mmcf/d)(1) 412.5 392.4 20.1 Extraction ethane volumes (Bbls/d) (1) 9,222 9,729 (507) Extraction NGL volumes (Bbls/d) (1) 4,980 5,602 (622)

Total extraction volumes (Bbls/d) 14,202 15,331 (1,129)

Average Industry Frac Spreads ($/GJ Propane Plus) 8.19 11.57 (3.38) Gas Gathering & Processing

Gas gathering & processing capacity (mmcf/d) (1)(2) 150.8 198.8 (48.0) Processing throughput (gross mmcf/d) (1) 46.3 52.7 (6.4)

(1)

Average for the period.

(2)

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The majority of NGL extraction operations involve the extraction of natural gas liquids from natural gas and their replacement (on a heat content equivalent basis) with Shrinkage Gas. For Propane Plus, the difference between the price of natural gas and the value of the liquids extracted is commonly referred to as the Frac Spread. Frac Spreads vary with fluctuations in the input price of natural gas and the revenue derived from the applicable liquids extracted. The average Industry Frac Spreads for the three months ended March 31, 2013, were $8.19 per GJ, a decrease of 29% compared to $11.57 per GJ in the same period in 2012, due to increased natural gas input costs and continued decreases in NGL prices.

ATCO AUSTRALIA

ATCO Australia consists of three distinct business operations: ATCO Gas Australia, which is a fully

regulated provider of natural gas distribution services in Western Australia; ATCO Power Australia, which provides electricity from three natural gas-fired generating plants in Adelaide, South Australia (50% interest), Brisbane, Queensland (50% interest), and Karratha, Western Australia (100% interest). ATCO I-Tek Australia provides a variety of information technology services.

2012, primarily due to increased customer rates from the ATCO Gas Australia appeal decision received in June 2012 and the recovery of carbon taxes instituted July 1, 2012.

Adjusted Earnings for ATCO Australia are shown in the following table:

ATCO Gas Australia 5 3 2

ATCO Power Australia 7 6 1

Other (1) (2) (3) 1

Total ATCO Australia 10 6 4 For the Three Months Ended

March 31

(1)

Other includes ATCO I-Tek Australia and ATCO Australia’s corporate office.

Adjusted Earnings for the three months ended March 31, 2013, increased by $4 million over the same

period in 2012, mainly due to the appeal decision received in 2012, which increased the allowed return and provided for the recovery of certain costs, and growth in rate base in ATCO Gas Australia and strong performance in ATCO Power Australia.

The results for ATCO Gas Australia will fluctuate due to the seasonal nature of demand for natural gas and the impact of fluctuations in temperatures. Temperature fluctuations are measured in Heating Degree Days (HDD) which is defined as the difference between the average daily temperature and 18 degrees Celsius. In a normal year, approximately 0% of the HDD are experienced from January to March, 30% from April to June, 60% from July to September, and the remaining 10% from October to December. HDD that are 10% warmer or colder than normal on an annual basis impact the Corporation’s annual earnings by approximately $2 million. As expected, the amount of HDD was negligible for the three months ended March 31, 2013.

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ATCO Power Australia

Availability of the generating plants in Australia is a key driver of financial performance and will fluctuate due to the timing and duration of outages. For the three months ended March 31, 2013, availability of the generating plants continued to be strong at 99.8% compared to 98.4% in the corresponding period in 2012.

The electricity and steam produced are sold under 20 year offtake contracts expiring between 2018 and 2030.

CORPORATE

&

OTHER

Adjusted Earnings for the three months ended March 31, 2013, increased by $4 million over the same

period in 2012, mainly due to differences in the amounts recorded for short-term incentives.

ATCO I-Tek

ATCO I-Tek is engaged in the development, operation and support of information systems and technologies in Canada. ATCO I-Tek provides billing, payment processing, credit, collection and call centre services to its clients which include ATCO Gas and ATCO Electric. ATCO I-Tek has a contract with Direct Energy which expires December 31, 2014, to provide billing and call centre services for its regulated retail and competitive energy supply businesses in Alberta. Direct Energy has advised that it intends to transition these services to a new service provider following the expiration of the contract. Earnings from the existing contract with Direct Energy will continue through to the end of 2014.

I M P O R T A N C E O F A D J U S T E D E A R N I N G S

Adjusted Earnings are earnings attributable to equity owners of the Corporation after adjusting for the

timing of revenues and expenses associated with rate regulated activities and dividends on equity preferred shares of the Corporation. Adjusted Earnings also exclude one-time gains and losses and items that are not in the normal course of business or day-to-day operations.

Adjusted Earnings are a key measure of segment earnings used by management for purposes of assessing segment performance and allocating resources. Furthermore, it is management’s view that Adjusted Earnings allows a better assessment of the economics of rate regulation in Canada and Australia and facilitates comparability of the Corporation’s financial results with peer companies that have either deferred the adoption of IFRS as permitted in Canada or utilize U.S. generally accepted accounting principles for rate regulated entities.

In management’s judgment, the operations subject to PBR meet the criteria established by U.S. generally accepted accounting principles to be accounted for as rate regulated activities.

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The following table reconciles Adjusted Earnings to earnings attributable to equity owners of the Corporation:

Adjusted Earnings 180 174 6

Adjustments for rate regulated activities (5) 7 (12)

Dividends on equity preferred shares of the Corporation 8 9 (1)

Earnings attributable to equity owners of the Corporation 183 190 (7) For the Three Months Ended

March 31

Adjustments for Regulated Activities

Rate regulated accounting reduces the volatility of earnings, because the Corporation defers the recognition of cash received in advance of future expenditures and recognizes revenues associated with recoverable costs in advance of future billings to customers. Under IFRS, the Corporation records revenues when amounts are billed to customers and recognizes costs when they are incurred, but does not recognize their recovery until changes to customer rates are reflected in future customer billings.

Under rate regulated accounting, the Corporation recognizes revenues from regulatory decisions that pertain to current and prior periods upon receipt of the decisions. Under IFRS, the Corporation recognizes revenues when customer rates are changed and amounts are billed to customers. In addition, under rate regulated accounting, amounts relating to intercompany profits that are recognized in rate base by a regulator are not eliminated upon consolidation. Under IFRS, intercompany profits are eliminated upon consolidation. The Corporation then recognizes those profits in earnings as amounts are billed to customers over the life of the related asset.

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The adjustments are shown in the following table:

(i) Additional revenues billed in current period

Future removal and site restoration costs 12 10 2

Retirement benefits - 4 (4)

Finance costs on major transmission capital projects 11 6 5

Transmission capital deferral(1) - 8 (8)

Other - 2 (2)

Total 23 30 (7)

(ii) Revenues to be billed in future period Deferred income taxes (20) (17) (3)

Transmission access payments (3) (3)

-Transmission capital deferral(1) (8) - (8)

Impact of warmer temperatures on revenues (4) (7) 3

Impact of inflation on rate base for ATCO Gas Australia (4) (3) (1)

Other (8) (3) (5)

Total (47) (33) (14)

(iii) Regulatory decisions related to current and prior periods(2) 21 12 9

(iv) Elimination of intercompany profits related to the construction (2) (2)

-Total Adjustments (5) 7 (12) of property, plant and equipment and intangible assets

(1)

Transmission capital deferral

For major transmission capital projects, ATCO Electric’s billings to customers include a return on forecast rate base. When actual capital costs vary from forecast capital costs, the return on rate base, and the resulting billings to the AESO, will be higher or lower than expected. Under rate regulated accounting, differences between billings to the AESO and the return on actual rate base are deferred. Recoveries from or refunds to the AESO of variances between forecast and actual returns on rate base are expected to occur in the following year.

On January 18, 2013, the AUC issued an interim rate decision approving 50% of the 2013 rate increase requested in the ATCO Electric Transmission 2013 and 2014 GTA, whereas in the first quarter of 2012 ATCO Electric was on final AUC approved rates which allowed recovery of 100% of the forecast transmission capital costs. The $8 million in 2013 revenues to be billed in future periods reflects the AUC’s approval of interim rates that included only 50% of the rate increase requested in the 2013 and 2014 GTA related to forecast transmission capital costs. The remaining 50% has been deferred pending a final rate decision which is expected in the second quarter of 2013.

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(2)

Regulatory decisions

In June 2012, the Australian Competition Tribunal (ACT) issued a decision on ATCO Gas Australia’s appeal of an earlier Economic Regulation Authority (ERA) decision for the 2010 to 2014 Access Arrangement. As a result of the ACT’s decision, the ERA amended its decision and ATCO Gas Australia recorded Adjusted Earnings of $10 million in the second quarter of 2012 representing the period January 1, 2010 to June 30, 2012. An additional $1 million of Adjusted Earnings will be recorded in each succeeding quarter to June 30, 2014. Under IFRS, these earnings are billed to customers over a period of 24 months that commenced in July 2012.

ATCO Electric received decisions from the AUC approving the recovery of approximately $10 million in each of the three months ended March 31, 2013, and 2012 associated with higher than forecast transmission access payments. Under IFRS, these revenues are recognized as customers are billed.

L I Q U I D I T Y A N D C A P I T A L R E S O U R C E S

The Corporation’s financial position is supported by regulated utility and long term contracted operations. Maintaining strong investment grade credit ratings and access to capital markets at competitive rates supports the Corporation’s business strategies and funding of operations and planned future growth. The primary sources of capital are cash flow from operations and the debt and preferred share capital markets. In addition, the Corporation issues Class A non-voting shares under its DRIP.

The Corporation considers it prudent to maintain sufficient liquidity to fund approximately one full year of cash requirements in order to preserve strong financial flexibility. This liquidity is generated by cash flow from operations, maintenance of minimum cash balances, and available committed credit facilities. At March 31, 2013, the Corporation had $1.9 billion in committed and uncommitted credit facilities, of which $1.8 billion was available.

Preferred Shares

On March 19, 2013, the Corporation issued $175 million of 4.50% Cumulative Redeemable Second Preferred Shares Series CC under its base shelf prospectus (refer to the Base Shelf Prospectuses section). The proceeds will be used for capital expenditures, to repay indebtedness and for other general corporate purposes.

Common Shares and Dividends

On February 21, 2013, the Corporation announced that it intends to split its Class A non-voting shares and Class B common shares on a two-for-one basis by way of a share dividend in 2013. The Corporation intends to undertake the share splits because the market prices for the Class A and Class B Shares have significantly increased. The share splits would make the Class A and Class B Shares more readily accessible to individual share owners, increase and broaden the Corporation’s share owner base, and improve the liquidity of the market for the shares. The share splits would not change a share owner’s proportionate ownership in the Corporation.

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Total dividends paid in the first quarter of 2013, includingdividends paid to Class A and Class B Share owners in cash and Class A Shares issued in lieu of cash dividends under the DRIP (refer to the Canadian Utilities Dividend Reinvestment Plan section), totaled $63 million, an increase of $7 million over the corresponding period of 2012. For the three months ended March 31, 2013, the quarterly dividend payment on the Class A and Class B Shares was 48.5 cents per share, a 10% increase over the 44.25 cents per share paid in each of the four previous quarters. On April 19, 2013, the Board of Directors declared a second quarter dividend of 48.5 cents per share. The Corporation has increased its annual common share dividend each year since its inception as a holding company in 1972. The payment of any dividend is at the discretion of the Board of Directors and depends on the financial position of the Corporation and other factors.

Canadian Utilities Dividend Reinvestment Plan

For the three months ended March 31, 2013, the Corporation issued 438,597 Class A non-voting shares under its DRIP in lieu of making cash dividend payments of $33 million.

Base Shelf Prospectuses

CU Inc. Debentures

On June 11, 2012, CU Inc. filed a base shelf prospectus that permits CU Inc. to issue up to an aggregate of $2.6 billion of debentures over the twenty-five month life of the prospectus. At April 24, 2013, aggregate issuances of debentures amounted to $900 million.

Canadian Utilities Debt Securities and Preferred Shares

On September 12, 2011, the Corporation filed a base shelf prospectus that permits the Corporation to issue up to an aggregate of $2 billion of debt securities and preferred shares over the twenty-five month life of the prospectus. At April 24, 2013, aggregate issuances of debentures and preferred shares amounted to $1 billion.

S H A R E C A P I T A L

The equity securities of the Corporation consist of Class A Shares and Class B Shares.

At April 24, 2013, the Corporation had outstanding 88,820,583 Class A Shares, 40,261,949 Class B Shares, and options to purchase 536,050 Class A Shares.

Class A Non-Voting Shares and Class B Common Shares

The owners of the Class A Shares and the Class B Shares are entitled to share equally, on a share for share basis, in all dividends declared by the Corporation on either of such classes of shares as well as the remaining property of the Corporation upon dissolution. The owners of the Class B Shares are entitled to vote and to exchange at any time each share held for one Class A Share.

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If a take-over bid is made for the Class B Shares which would result in the offeror owning more than 50% of the outstanding Class B Shares and which would constitute a change in control of the Corporation, owners of Class A Shares are entitled, for the duration of the bid, to exchange their Class A Shares for Class B Shares and to tender such Class B Shares pursuant to the terms of the take-over bid. Such right of exchange is conditional upon the completion of the take-over bid giving rise to the right of exchange, and if the take-over bid is not completed, then the right of exchange shall be deemed never to have existed. In addition, owners of the Class A Shares are entitled to exchange their shares for Class B Shares if ATCO Ltd., the controlling share owner of the Corporation, ceases to own or control, directly or indirectly, more than 10,000,000 of the issued and outstanding Class B Shares. In either case, each Class A Share is exchangeable for one Class B Share, subject to changes in the exchange ratio for certain events such as a stock split or rights offering.

Of the 6,400,000 Class A Shares authorized for grant in respect of options under the Corporation’s stock option plan, 2,816,850 Class A Shares were available for issuance at March 31, 2013. Options may be granted to officers and key employees of the Corporation and its subsidiaries at an exercise price equal to the weighted average of the trading price of the shares on the Toronto Stock Exchange for the five trading days immediately preceding the date of grant. The vesting provisions and exercise period (which cannot exceed 10 years) are determined at the time of grant.

F U T U R E A C C O U N T I N G C H A N G E S

Certain new or amended standards have been issued by the International Accounting Standards Board (IASB) that are not required to be adopted in the current period. These changes and amendments are substantially unchanged from those discussed in the 2012 MD&A. The Corporation has not early adopted these standards. There were no new or amended standards issued by the IASB in the first quarter of 2013 which the Corporation anticipates will have a material effect on the consolidated financial statements or note disclosures.

I N T E R N A L C O N T R O L O V E R F I N A N C I A L R E P O R T I N G

There was no change in the Corporation’s internal control over financial reporting that occurred during the period beginning on January 1, 2013, and ended on March 31, 2013, that has materially affected, or is reasonably likely to materially affect, the Corporation’s internal control over financial reporting.

N O N

-

G A A P A N D A D D I T I O N A L G A A P M E A S U R E S

Funds Generated by Operations is defined as cash flow from operations before changes in non-cash working capital. In management’s opinion, Funds Generated by Operations is a significant performance indicator of the Corporation’s ability to generate cash during a period to fund its capital expenditures without regard to changes in non-cash working capital during the period. Funds Generated by Operations does not have any standardized meaning under IFRS and might not be comparable to similar measures presented by other companies.

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Adjusted Earnings are defined as earnings attributable to equity owners of the Corporation after adjusting for the timing of revenues and expenses associated with rate regulated activities and dividends on equity preferred shares of the Corporation. Adjusted Earnings also exclude one-time gains and losses and items that are not in the normal course of business or day-to-day operations. Adjusted Earnings present earnings from rate regulated activities on the same basis as was used prior to adopting IFRS – that basis being the U.S. accounting principles for rate regulated activities. It is management’s view that Adjusted Earnings allow for a more effective analysis of operating performance and trends. A reconciliation of Adjusted Earnings to earnings attributable to equity owners of the Corporation is presented in the “Importance of Adjusted Earnings” section. Adjusted Earnings is an additional GAAP measure that is presented in Note 5 to the 2013 Interim Financial Statements.

F O R W A R D

-

L O O K I N G I N F O R M A T I O N

Certain statements contained in this MD&A constitute forward-looking information. Forward-looking information is often, but not always, identified by the use of words such as “anticipate”, “plan”, “estimate”, “expect”, “may”, “will”, “intend”, “should”, and similar expressions. Forward-looking information involves known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking information. The Corporation believes that the expectations reflected in the forward-looking information are reasonable, but no assurance can be given that these expectations will prove to be correct and such forward-looking information should not be unduly relied upon.

G L O S S A R Y

Adjusted Earnings means earnings attributable to equity owners of the Corporation after adjusting for

the timing of revenues and expenses associated with rate regulated activities and dividends on equity preferred shares of the Corporation. Adjusted Earnings also exclude one-time gains and losses and items that are not in the normal course of business or day-to-day operations. Refer to the “Importance of Adjusted Earnings” section for a description of these items.

AESO means the Alberta Electric System Operator.

Alberta Power Pool means the market for electricity in Alberta operated by the AESO.

ATCO Structures & Logistics means ATCO Structures & Logistics Ltd.

AUC means the Alberta Utilities Commission.

Availability is a measure of time, expressed as a percentage of continuous operation, that a generating

unit is capable of producing electricity, regardless of whether the unit is actually generating electricity.

Bbls/d means barrels per day extracted.

Class A Shares means Class A non-voting shares of the Corporation.

Class B Shares means Class B common shares of the Corporation.

Corporation means Canadian Utilities Limited and, unless the context otherwise requires, includes its

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Frac Spread means the premium or discount between the purchase price of natural gas and the selling

price of extracted natural gas liquids on a heat content equivalent basis.

GAAP means Canadian generally accepted accounting principles.

Gigajoule (GJ) means a unit of energy equal to approximately 948.2 thousand British thermal units;

Petajoule (PJ) means a unit of energy equal to approximately 948.2 billion British thermal units

.

Heating Degree Day means the difference between the average daily temperature and 18 degrees

Celsius.

IFRS means International Financial Reporting Standards.

MD&A means Management’s Discussion and Analysis.

Megawatt (MW) is a measure of electric power equal to 1,000,000 watts.

Megawatt hour (MWh) means a measure of electricity consumption equal to the use of 1,000,000 watts

of power over a one-hour period.

Mmcf/d means million cubic feet per day.

NGL means natural gas liquids, such as ethane, propane, butane and pentanes plus, that are extracted from natural gas and sold as distinct products or as a mix.

PBR means Performance Based Regulation.

PPA means Power Purchase Arrangements that became effective on January 1, 2001, as part of the process of restructuring the electric utility business in Alberta. The PPAs are legislatively mandated and approved by the AUC.

Propane Plus means propane, butane, pentane and other hydrocarbons other than methane and ethane.

Shrinkage Gas means the natural gas which is used to replace, on a heat equivalent basis, the NGL

extracted during NGL extraction operations.

Spark Spread means the difference between the selling price of electricity and the marginal cost of

producing electricity from natural gas. In this MD&A, Spark Spreads are based on an approximate industry heat rate of 7.5 GJ per MWh.

Storage Price Differentials means seasonal differences (summer/winter) in the prices of natural gas.

UAD means Utility Asset Disposition regulatory proceeding.

UPR means Urban Pipeline Replacement projects.

U.K. means United Kingdom.

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A P P E N D I X I

–

S U M M A R Y O F A C C O U N T I N G C H A N G E S

The effects of the change on the Corporation’s consolidated results upon adoption of IFRS 11 Joint

Arrangements and amendments to IAS 19 Employee Benefits are summarized below:

2012 Restated ATCO Corporate

2012 Previously Reported Utilities Energy Australia & Other Eliminations Total ($ millions) Revenues 517 223 52 56 (37) 811 517 236 65 56 (37) 837 Adjusted Earnings 108 47 6 13 - 174 108 47 6 13 1 175

Adjustments for rate 11 - (3) - (1) 7

regulated activities 11 - (3) - 1 9

Dividends on equity preferred 1 - - 8 - 9

shares of Canadian Utilities Limited 1 - - 8 - 9

Earnings attributable 120 47 3 21 (1) 190

to equity owners of the Corporation 120 47 3 21 2 193

For the Three Months Ended March 31 Previously Restated Reported ($ millions) 2012 2012 Change Cash position, beginning of period 586 613 (27)

Cash provided by Operating activities Funds Generated by Operations 411 418 (7)

Changes in non-cash working capital 10 13 (3)

Cash flow from operations 421 431 (10)

Investing activities (425) (425)

-Financing activities (137) (144) 7

Cash position, end of period 445 475 (30) For the Three Months Ended

MANAGEMENT S DISCUSSION AND ANALYSIS