Three Months Ended Nine Months Ended September 30 September 30

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HIGHLIGHTS

Three Months Ended Nine Months Ended

September 30 September 30

(millions of Canadian dollars, unless otherwise noted) ₂₀₁₁ ₂₀₁₀

2011 2010

Total revenues 788.2 552.0 2,251.1 1,748.2

Operating margin (1) 144.4 150.1 466.5 476.8

Earnings before interest and income taxes (EBIT) (1) 48.5 48.2 181.1 199.6

Net earnings 41.9 29.7 141.8 135.3

Return on equity (2) 10.0% 10.0%

Return on assets (3) 7.8% 7.7%

Total assets 4,243.5 3,826.4

Total shareholder’s equity 1,912.3 1,788.4

Electricity sold (gigawatt hours (GWh)) 5,247 4,896 15,871 14,444

Natural gas sold (terajoules (TJ)) 4,109 4,482 30,565 24,279

Distribution volumes (GWh) 2,282 2,258 6,908 6,709

(1) Non-GAAP financial measure. See discussion that follows in the Management’s Discussion & Analysis (MD&A).

(2) Return on equity is equal to the rolling prior 12-month net earnings divided by average Shareholder’s equity for the same 12-month period. (3) Return on assets is equal to the rolling prior 12-month net earnings before after-tax interest charges divided by average total assets (adjusted for

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Summary financial information

Three Months Ended Nine Months Ended September 30 September 30

(millions of Canadian dollars, unless otherwise noted) ₂₀₁₁ ₂₀₁₀ ₂₀₁₁ ₂₀₁₀

EBIT (1) 48.5 48.2 181.1 199.6

Net earnings before discontinued operations 42.1 33.1 138.6 140.0

Capital assets (2) 3,230.8 2,874.8

Total debt (3) 1,606.4 1,445.5

Total capitalization (4) 3,518.7 3,233.9

Long-term debt to total capitalization ratio (5) 43.8% 44.7%

Funds generated from operations (1) 83.8 83.1 287.2 272.9

Cash used by investing activities 137.7 51.6 336.4 281.8

Cash provided / (used) by financing activities 40.4 (26.5) 135.1 58.4

(1) Non-GAAP financial measure.

(2) Capital assets include property, plant and equipment (PPE), power purchase arrangements and intangible assets. (3) Total debt includes short-term financing and long-term debt.

(4) Total capitalization is equal to total debt plus Shareholder’s equity.

(5) Long-term debt to total capitalization is equal to total long-term debt divided by total capitalization.

Summary of key operating statistics

2011 2010 2011 2010

Generation volume (GWh) 2,832 2,857 9,092 8,671

Market heat rate – flat average (GJ/MWh) 27.29 10.65 21.49 13.40

Average wholesale market spark spread ($/MWh) (1) $66.95 $8.89 $48.16 $21.10

Electricity sales volumes (GWh) 5,247 4,896 15,871 14,444

Average flat pool price ($/MWh) $94.71 $35.69 $76.72 $52.38

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FORWARD-LOOKING INFORMATION

This document contains statements about future events and financial and operating results of ENMAX Corporation and its subsidiaries (ENMAX or the Corporation) that are looking. By their nature, forward-looking statements require the Corporation to make assumptions and are subject to inherent risks and uncertainties. There is significant risk that predictions and other forward-looking statements will not prove to be accurate. Readers are cautioned not to place undue reliance on forward-looking statements as a number of factors could cause actual future results, conditions, actions or events to differ materially from financial and operating targets, expectations, estimates or intentions expressed in the forward-looking statements.

When used in this MD&A, the words “may”, “would”, “could”, “will”, “intend”, “plan”, “anticipate”, “believe”, “seek”, “propose”, “estimate”, “expect” and similar expressions, as they relate to the Corporation or an affiliate of the Corporation, are intended to identify forward-looking statements. Such statements reflect the Corporation’s current views with respect to future events and are subject to certain risks, uncertainties and assumptions. Many factors could cause the Corporation’s actual results, performance or achievements to vary from those described in this MD&A. Should one or more of these risks or uncertainties materialize, or should assumptions underlying forward-looking statements prove incorrect, actual results may vary materially from those described in this MD&A. Intended, planned, anticipated, believed, estimated or expected and other forward-looking statements included in this MD&A herein should not be unduly relied upon. These statements speak only as of the date of this MD&A. The Corporation does not intend, and does not assume any obligation, to update these forward-looking statements except as required by law, and reserves the right to change, at any time at its sole discretion, the practice of updating annual targets and guidance.

Factors that could cause actual results to differ materially include, but are not limited to:

- competitive factors and pricing pressures, including the supply side and demand side of the Alberta power market and the volatile fluctuations in the pricing of natural gas in the North American market; - regulatory developments as they relate to transmission and distribution rate-making and the impact of

deregulation in the industry;

- human resources, including possible labour disruptions;

- financing and debt requirements, including ability to carry out refinancing activities;

- tax matters, including acceleration or deferral of required cash payments, realization of timing differences and potential reassessments by tax authorities;

- litigation and legal matters;

- business continuity events (including man-made and natural threats);

- economic growth and fluctuations as they relate to the natural resource-based Alberta economy;

- change in customers’ wants and needs due to evolving technologies and a movement to more environmentally sensitive ways of living; and

- other risk factors discussed herein and listed from time to time in ENMAX’s reports and other public disclosure documents.

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MANAGEMENT’S DISCUSSON AND ANALYSIS (MD&A)

This MD&A, dated November 1, 2011, is a review of the results of operations of ENMAX for the three and nine months ended September 30, 2011, compared with the same period in 2010, and of the Corporation’s financial condition and future prospects. This MD&A should be read in conjunction with the three and nine month ended interim financial statements and the MD&A included in ENMAX’s 2010 Financial Report. This discussion contains forward-looking information that is qualified by reference to and should be read together with, the caution regarding forward-looking statements previously mentioned.

ENMAX’s consolidated financial statements have been prepared in accordance with Canadian Generally Accepted Accounting Principles (GAAP). The consolidated financial statements and MD&A were reviewed by ENMAX’s Audit and Finance Committee and approved by the Board. All amounts are in Canadian dollars unless otherwise specified.

The Corporation reports on certain non-GAAP financial measures such as operating margin and funds from operations that are used by management to evaluate performance of business units and segments. Because non-GAAP financial measures do not have a standardized meaning, the Corporation has defined and reconciled them with their nearest GAAP measure. For the reader’s reference, the definition, calculation and reconciliation of consolidated non-GAAP financial measures is provided in Section 4: Non-GAAP Financial Measures.

The Corporation has chosen to defer the adoption of IFRS as permitted by the Accounting Standards Board (AcSB) amendment and will be reporting interim and annual consolidated financial statements in IFRS, including comparative periods, beginning January 1, 2012.

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TABLE OF CONTENTS

Section Contents Page

1. Overall financial performance.

Discussion of consolidated results for the three and nine months ended September 30, 2011.

6 2. Business segment

results.

Discussion of the strategy, key performance indicators, results of operations and capital investments of the business segments.

9 3. Selected quarterly

financial data.

Summary of selected financial information for the past eight quarters.

15 4. Non-GAAP

financial measures.

Description, calculation and reconciliation of certain measures used by management.

16 5. Financial condition. Discussion of significant changes in ENMAX’s balance sheet

between September 30, 2011, and December 31, 2010.

18 6. Liquidity and capital

resources.

Discussion of cash flow, liquidity, credit facilities and other disclosures.

19 7. Future accounting

changes.

Description of changes to accounting policies to be adopted in future periods.

24 8. Critical accounting

estimates.

Description of accounting estimates that are critical to determining financial results.

26 9. Risk management

and uncertainties.

Update on certain risks and uncertainties facing the Corporation and how these risks are managed.

26 10. Financial

instruments.

Discussion of ENMAX’s off-balance sheet arrangements and monetary obligations under financial agreements.

27 11. Climate change

and the environment.

Discussion of environmental matters relating to ENMAX’s operations and asset base.

27

12. Transactions with related parties.

Description of transactions with The City of Calgary. 28

13. Outlook. Discussion of expected results for 2011. 28

14. Additional information.

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1 OVERALL FINANCIAL PERFORMANC E

Selected Consolidated Financial Information

(millions of dollars) 2011 2010 2011 2010

Total revenue 788.2 552.0 2,251.1 1,748.2

Operating margin (1) 144.4 150.1 466.5 476.8

EBIT (1) 48.5 48.2 181.1 199.6

Net earnings before discontinued operations Net earnings 42.1 41.9 33.1 29.7 138.6 141.8 140.0 135.3 Total assets

Total long-term financial liabilities(2)

Funds generated from operations (1) 83.8 83.1

4,243.5 1,597.9 287.2 3,826.4 1,510.5 272.9 (1) Non-GAAP financial measure. See discussion that follows in Section 4: Non-GAAP Financial Measures.

(2) Total long-term financial liabilities include all of the Corporation’s long-term liabilities excluding future income taxes.

ENMAX’s consolidated net earnings for the three months ended September 30, 2011, have increased $12.2 million to $41.9 million compared with $29.7 million for the three months ended September 30, 2010. For the nine months ended September 30, 2011, net earnings have increased $6.5 million to $141.8 million compared with $135.3 million for the same period in 2010. This increase was driven primarily by higher natural gas margins, transmission and distribution margins, contractual services and other margins; and lower amortization, interest and tax costs. These favourable variances were offset by lower electricity margins and higher operations, maintenance and administration (OM&A) expenses on a year-to-date basis.

ENMAX’s results of operations are not necessarily indicative of future performance due to fluctuating commodity prices and the performance and retirement of existing and addition of new generation facilities. Further details on specific operations can be found in Section 2: Business Segment Results. A reconciliation of earnings before interest and income taxes (EBIT) for the three and nine months ended September 30, 2011, as compared with the same periods in 2010 is as follows:

(millions of dollars)

Three Months Ended

Nine Months Ended

EBIT for the period ended September 30, 2010 48.2 199.6

Increased / (decreased) margins attributable to:

Electricity (12.5) (25.7)

Natural gas 1.5 5.3

Transmission and distribution 2.7 3.6

Contractual services and other 2.6 6.5

(Increased) / decreased expenses: OM&A Amortization 2.3 3.7 (9.7) 1.5

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Electricity margins for the three months ended September 30, 2011, decreased $12.5 million to $83.7 million from $96.2 million in the three months ended September 30, 2010. For the nine months ended September 30, 2011, electricity margins decreased $25.7 million to $279.6 million from $305.3 million in the same period in 2010. While average pool prices are higher than the prior year, forward contracts in both the retail and wholesale markets were realized at lower prices. In addition, higher power purchase arrangement (PPA) costs were experienced and the increased margins due to price spikes seen in the second quarter of 2010 did not recur. These factors have been partially offset by higher volumes due primarily to new customer sign-ups and strong electricity prices in the first quarter.

Natural gas margins increased $1.5 million for the three months ended September 30, 2011, to $0.3 million from a loss of $1.2 million in the same period in 2010. For the nine months ended September 30, 2011, natural gas margins increased $5.3 million to $7.9 million from $2.6 million in the same period in 2010. This increase is a result of higher year-to-date margins and increased sales volumes as a result of new site acquisitions across all lines of business. The impact of this volume increase was partially offset by downward pressure on gas prices experienced in the first quarter and the turn back of excess volumes acquired under fixed price contracts at lower market prices.

For the three months ended September 30, 2011, transmission and distribution margins increased $2.7 million to $46.8 million from the $44.1 million of earnings recorded in the same period in 2010. For the nine months ended September 30, 2011, transmission and distribution margins increased $3.6 million to $137.9 million from $134.3 million in the same period in 2010. This increase was due primarily to revenues related to rate increases and the timing of system access fees. This was partially offset by the non-recurrence of the collection of a prior period rate adjustment in 2010.

For the three months ended September 30, 2011, margins from contractual services and other sources increased $2.6 million to $13.6 million from the $11.0 million recorded in the same three months of 2010. For the nine months ended September 30, 2011, contractual services and other margins increased $6.5 million to $41.1 million from $34.6 million in the same period in 2010. The increase in margins was mainly due to unrealized foreign exchange gains on a purchase agreement denominated in U.S. dollars and higher activity levels in Calgary light rail transit (LRT) projects and underground residential development.

OM&A costs for the three months ended September 30, 2011, decreased $2.3 million to $55.5 million from $57.8 million for the same quarter in 2010. For the nine months ended September 30, 2011, OM&A costs increased $9.7 million to $163.0 million from $153.3 million in the same period in 2010. The increase in OM&A in the nine month period was primarily attributable to severance amounts paid in the first quarter, general inflationary salary increases, increased pension costs and increased advertising spending. These unfavourable variances have been partially offset by a decline in asset write-offs, lower bad debts, an insurance reimbursement and an increase in billing fee recoveries. The reduction in OM&A costs in the quarter was mainly due to higher billing fee recoveries.

Amortization expense for the three months ended September 30, 2011, decreased $3.7 million to $40.4 million from $44.1 million for the same period in 2010. For the nine months ended September 30, 2011, amortization expense decreased $1.5 million to $122.4 million from $123.9 million in the same period in 2010. The decreased charges were the result of a 2010 write down of IT assets no longer in use.

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Other Net Earnings Items

For the three months ended September 30, 2011, interest expense decreased $4.8 million to $13.0 million from $17.8 million for the same period in 2010. Interest expense decreased $6.7 million to $39.4 million from $46.1 million for the nine months ended September 30, 2011, compared to the nine months ended September 30, 2010. The decrease was primarily due to an increase in the capitalization of interest related to capital projects. This decrease was partially offset by interest on new debt acquired during the past twelve months.

Income tax recovery for the quarter ended September 30, 2011, increased $3.9 million to $6.6 million from a recovery of $2.7 million in the same period in 2010. For the nine months ended September 30, 2011, income tax expense decreased $10.4 million to $3.1 million from $13.5 million for the same period in 2010. This decline was primarily due to lower taxable income in addition to a reduction in the corporate tax rate for 2011.

Losses from discontinued operations for the three months ended September 30, 2011, decreased $3.2 million to a loss of $0.2 million from a $3.4 million loss in the same three months of 2010. For the nine months ended September 30, 2011, earnings from discontinued operations increased $7.9 million to $3.2 million from a $4.7 million loss for the same period in 2010. The loss in the quarter represents additional closing costs incurred on the first quarter disposal of all of the British Columbia assets. Year-to-date earnings from discontinued operations include a $2.4 million gain on disposal of the British Columbia assets.

O t h e r C o m p r e h e n s i ve I n c o m e

Other comprehensive income illustrates the Corporation’s earnings under the assumption of full income recognition of gains and losses on securities and derivatives otherwise treated as hedges of future period revenues and expenses. The Corporation utilizes derivatives to hedge its electricity, natural gas, interest rate and foreign exchange exposures. For the three months ended September 30, 2011, other comprehensive income totalled losses of $15.8 million compared with losses of $5.6 million for the same period in 2010. For the nine months ended September 30. 2011, other comprehensive income totalled losses of $19.1 million compared with losses of $29.6 million for the same period in 2010. The losses in 2011 primarily reflect unfavourable fair value changes on electricity and interest rate swap positions from the conclusion of the previous year partially offset by favourable fair value changes on natural gas positions and favourable settled hedges on both electricity and natural gas.

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2 B U S I N E S S S E G M E N T R E S UL T S

The operating businesses of the Corporation are managed principally in two segments, ENMAX Energy and ENMAX Power. The results of those segments are discussed in the comments that follow.

E B I T

ENMAX Energy 27.0 33.4 133.3 144.3

ENMAX Power 19.8 13.4 49.8 49.6

Corporate & intersegment eliminations 1.7 1.4 (2.0) 5.7

EBIT 48.5 48.2 181.1 199.6

E N M A X E n e r g y

Business Update

ENMAX Energy combines fuel procurement, generation of electricity, wholesale market trading and retail sales into an integrated model. This segment operates or has exclusive access to approximately 2,067 MW of electricity generation that is used to supply retail customer demand.

During the third quarter of 2011, ENMAX Energy completed the preliminary site preparation for the construction of the Shepard Energy Centre. Construction of this 800 MW facility is underway with the facility expected to be operational in 2015.

Key Performance Indicators

2011 2010 2011 2010

Generation volume (GWh) 2,832 2,857 9,092 8,671

Market heat rate – flat average (GJ/MWh) 27.29 10.65 21.49 13.40

Average wholesale market spark spread ($/MWh) (1)

$66.95 $8.89 $48.16 $21.10

Average selling prices ($/MWh) $88.30 $59.89 $77.58 $64.36

Electricity sold (GWh) 5,247 4,896 15,871 14,444

Natural gas sold (TJ) 4,109 4,482 30,565 24,279

Average flat pool price ($/MWh) $94.71 $35.69 $76.72 $52.38

Average natural gas price ($/GJ) $3.47 $3.35 $3.57 $3.91 (1) Assuming an average CCGT heat rate of 8 GJ per MWh.

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Higher pool prices and relatively flat natural gas prices create higher heat rates and spark spreads in the third quarter of 2011 as compared to the prior year. This is a reverse of what was experienced in the second quarter, with the resulting higher year-to-date pool price and lower natural gas price more than offsetting the second quarter dip and resulting in an increase in market heat rate and spark spread year-to-date. As ENMAX Energy contracts most of its requirement from fixed price retail and wholesale contracts this swing in heat rates and spark spreads does not translate into earnings for the current quarter.

ENMAX Energy sold, under contract, 5,247 GWh of electricity to customers in the three months ended September 30, 2011, compared with 4,896 GWh in the same period of 2010. For the nine months ended September 30, 2011, ENMAX Energy sold, under contract, 15,871 GWh of electricity to customers compared with 14,444 GWh in the same period of 2010. The change in volume sold is due primarily to growth in the industrial, commercial and institutional customer portfolios.

ENMAX Energy’s natural gas customers purchased 4,109 TJ in the three months ended September 30, 2011, compared with 4,482 TJ in the same period in 2010. For the nine months ended September 30, 2011, ENMAX Energy sold 30,565 TJ of natural gas to customers compared with 24,279 TJ in the same period of 2010. The growth in volume for the nine months ended September 30, 2011 is the result of an increase in variable customer base including the addition of a large institutional customer. However, there was a decrease in the third quarter volumes compared to the prior year as a result of lower usage due to warmer temperatures.

Financial Results

ENMAX Energy recorded EBIT of $27.0 million and $133.3 million for the three and nine months ended September 30, 2011, respectively, compared with $33.4 million and $144.3 million, respectively, in the same periods in 2010. A reconciliation of EBIT for the periods ended September 30, 2011, as compared with the same periods in 2010 is as follows: (millions of dollars) Three Months Ended Nine Months Ended

Natural gas 1.5 5.3

Contractual services and other - 10.6

(Increased) / decreased expenses: OM&A Amortization 1.8 1.5 (4.2) 1.5

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Electricity margins for the three months ended September 30, 2011, decreased $11.2 million to $82.0 million compared with the $93.2 million recorded in the same three months of 2010. Electricity margins from operations for the nine months ended September 30, 2011, decreased $24.2 million to $272.4 million compared with the $296.6 million recorded in the same period of 2010. While average pool prices are higher than the prior year, forward contracts in both the retail and wholesale markets were realized at lower prices. In addition, higher PPA costs were experienced and the increased margins due to price spikes seen in the second quarter of 2010 did not recur. These margin decreases were partially offset by higher volumes of electricity sold, primarily in the industrial, commercial and institutional segment.

Natural gas margins were $0.3 million for the three months ended September 30, 2011, compared with a $1.2 million loss for the same period in the prior year. Natural gas margins were $7.9 million for the nine months ended September 30, 2011, compared with $2.6 million for the first nine months of 2010. This favourable year-to-date margin increase is due to an increase in sales volumes as a result of customer growth across all lines of business in addition to higher volumes from existing customers contributed to the higher margins, offset partially by downward pressure on gas prices experienced in the first quarter and the turn back of excess volumes acquired under fixed price contracts at lower market prices. The decrease in the third quarter volumes compared to the prior year is a result of lower usage as a result of warmer fall temperatures.

Contractual services margin and other revenues did not change in the three months ended September 30, 2011, from the $13.8 million recorded in the same period in 2010. Contractual services margin and other revenues increased $10.6 million in the nine months ended September 30, 2011, to $51.4 million compared to $40.8 million in the nine months ended September 30, 2010. The increase was primarily due to first quarter realized and unrealized gains on a purchase agreement denominated in a foreign currency and growth in the Corporation’s advanced data communication division.

OM&A costs decreased $1.8 million in the three months ended September 30, 2011, to $41.4 million compared to $43.2 million in the same period in 2010. OM&A costs increased $4.2 million in the nine months ended September 30, 2011, to $115.8 million compared to $111.6 million in the nine months ended September 30, 2010. The increase in the nine month period was primarily attributable to severance amounts paid in the first quarter, general inflationary salary increases, increased pension costs, staffing increases for the operation and management of the developing generation business and increased advertising spending. These cost increases were partially offset during the quarter by a decline in asset write-offs, an increase in billing fee recoveries and lower bad debts. In the quarter, OM&A costs also declined due to the non-recurrence of 2010 contractor costs related to operating procedure development in the generation business.

Amortization expense decreased $1.5 million in the three months ended September 30, 2011, to $27.7 million compared to $29.2 million in the same period in 2010. Amortization expense decreased $1.5 million in the nine months ended September 30, 2011, to $82.6 million compared to $84.1 million in the nine months ended September 30, 2011. This decrease was due to a 2010 write down of IT assets no longer in use.

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E N M A X P o w er

Business Update

ENMAX Power owns, operates and maintains transmission and distribution assets in the Calgary service area. As well, it has the responsibility to provide electricity for its customers who have elected to stay with the regulated rate option service (RRO). ENMAX Power also has some non-regulated businesses and provides engineering, procurement, construction and maintenance services.

Distribution capital projects which either commenced or continued in the nine months ended September 30, 2011, resulted in $25.4 million being incurred for residential and non-residential development and $5.7 million for system infrastructure. Capital work also was completed on asset replacement and modification projects with $12.4 million being incurred during the nine months ended September 30, 2011, to meet industry standards and safety codes and for distribution automation. Investments of $17.6 million were made in Alberta Electric System Operator (AESO) required capital projects during the nine month period ended September 30, 2011.

During the first nine months of 2011, ENMAX Power commenced and continued work on major transmission projects which will help meet load growth within Calgary, as well as to replace aging infrastructure. The projects include multiple cable replacement projects, the 69 kilovolt (kV) south conversion project, interconnections to new generating facilities, new substations as well as substation upgrades to handle the additional transmission requirements. Capital investment in these transmission projects in the nine months ended September 30, 2011, totalled $30.4 million.

ENMAX Power operates under a capital structure regulated by the Alberta Utilities Commission (AUC) of 59% debt to 41% equity for the distribution business and 63% debt to 37% equity in the transmission business.

The permitted ROE under the formula based ratemaking (FBR) framework is 9.0%. This key measure for ENMAX Power’s regulated transmission and distribution businesses is only filed annually and as such is not tracked on a quarterly interim basis.

2011 2010 2011 2010

Electricity sold through the Calgary service area RRO

(GWh) 507 546 1,665 1,722

Distribution volumes (GWh) 2,282 2,258 6,908 6,709

Distribution system circuit lines (km) 7,683 7,550 7,683 7,550

Transmission system lines (km) 273 266 273 266

RRO electricity volumes sold decreased to 507 GWh in the three months ended September 30, 2011, compared with 546 GWh in the same period in 2010. For the nine months ended September 30, 2011, RRO electricity volumes sold decreased to 1,665 GWh compared with 1,722 GWh in the same period in 2010. The decline in volumes sold is primarily a result of customers switching from the RRO option to competitive options.

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Total electricity delivered in the Calgary service area increased in the third quarter of 2011 from the same period in the prior year with electricity volumes delivered during the three months ended September 30, 2011, at 2,282 GWh compared with 2,258 GWh in the same period in 2010. For the nine months ended September 30, 2011, total electricity delivered in the Calgary service area increased from the same period in the prior year with electricity volumes delivered of 6,908 GWh compared with 6,709 GWh in the same period in 2010. This increase was primarily due to growth within the Calgary service area as the number of serviced sites in Calgary continues to grow.

Financial Results

ENMAX Power’s financial results are driven by tariffs approved by the AUC for the regulated transmission, distribution and RRO businesses, as well as earnings from its non-regulated power services business. The regulated segment accounted for 86.1% and 87.7%, respectively, of ENMAX Power’s total revenue in the three and nine months ended September 30, 2011, compared with 90.0% and 90.6%, respectively, in the same periods in 2010.

ENMAX Power recorded EBIT of $19.8 million and $49.8 million for the three and nine months ended September 30, 2011, respectively, compared with $13.4 million and $49.6 million, respectively, in the same periods in 2010. A reconciliation of EBIT for the periods ended September 30, 2011, as compared with the same periods in 2010 is as follows: (millions of dollars) Three Months Ended Nine Months Ended

Transmission and distribution 2.7 3.6

Contractual services and other 2.3 2.7

(Increased) / decreased expenses: OM&A Amortization (0.1) 2.8 (5.5) 0.9

EBIT for the period ended September 30, 2011 19.8 49.8

Electricity margins from RRO customers decreased $1.3 million to $1.8 million for the three months ended September 30, 2011, compared with $3.1 million in the same period in 2010. For the nine months ended September 30, 2011, electricity margins from RRO customers decreased $1.5 million to $7.6 million, compared with $9.1 million for the nine months ended September 30, 2010. This decrease was primarily the result of lower volumes.

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Transmission and distribution margins are comprised of amounts charged for wires services, net of electrical grid charges and local access fees. Transmission and distribution margins increased $2.7 million to $46.8 million for the three months ended September 30, 2011, compared with $44.1 million in the same period in 2010. Transmission and distribution margins increased $3.6 million to $137.9 million for the nine months ended September 30, 2011, compared with $134.3 million for the nine months ended September 30, 2010. This increase was due primarily to increased revenues due to related rate increases and timing of recognition of system access fees. This was partially offset by the non-recurrence of the collection of a prior period rate adjustment in the second quarter of 2010.

For the third quarter ended September 30, 2011, margins for contractual services and other increased $2.3 million to $6.9 million compared with $4.6 million in the third quarter last year. For the nine months ended September 30, 2011, margins for contractual services and other increased $2.7 million to $14.8 million compared with $12.1 million for the nine months ended September 30, 2010. The increased margins were driven primarily by continued work related to the LRT expansion and underground residential development.

OM&A expenses for the three and nine months ended September 30, 2011 were $23.7 million and $72.4 million, respectively, compared with $23.6 million and $66.9 million, respectively, in the same period in 2010. The increase in OM&A was driven primarily by an increase in pension costs, general inflationary salary increases and severance amounts paid in the first quarter. These increases were offset partially by a reduction in RRO bad debt expenses, insurance reimbursement and increased billing recoveries due to a regulatory decision.

Amortization for the three months ended September 30, 2011, totalled $12.0 million, compared with $14.8 million in the same period in 2010. For the nine months ended September 30, 2011, amortization totalled $38.1 million compared with $39.0 million in the same period in 2010. The decreased charges were the result of a 2010 write down of IT assets no longer in use and a change in amortization rates.

E N M A X C o r p o r a t e ( i n c l u d i n g i n t e r s e g m e n t e l i m i n a t i o n s )

Three Months Ended Nine Months Ended September 30 September 30

(As at and for the period ended September 30) 2011 2010 2011 2010

OM&A per employee (1) $32,274 $34,791 $94,819 $92,356

Employees (1) 1,719 1,659 1,719 1,659

Key performance indicators are at a consolidated level. (1) Employee count is on the full-time equivalent basis.

OM&A per employee has slightly decreased from the prior quarter due primarily to an increase in employee headcount and a reduction of non-salary related OM&A costs in the quarter. OM&A per employee for the nine months ended 2011 has increased due to higher employee costs related to inflationary salary increases and pension costs, as well as one-time severance costs incurred in the first quarter. Consistent OM&A per employee ensures operational efficiency and helps to improve profitability. This is in line with one of the Corporation’s strategies of providing safe, reliable and cost-effective services to our customers.

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Financial Results

ENMAX Corporate provides shared services and financing to ENMAX Power and ENMAX Energy. During the three and nine months ended September 30, 2011, EBIT for ENMAX Corporate was a gain of $1.7 million and a loss of $2.0 million, respectively, as compared with gains of $1.4 million and $5.7 million, respectively, in the same periods in the prior year. The decrease in earnings was due to lower interest being charged to operating segments.

3 SELE CT ED QU ART ER LY F I N A N C IA L DATA

2011 2010 2009

Third Second First Fourth Third Second First Fourth Third (millions of dollars, except

operating statistics)

Total revenue 788.2 647.3 815.6 656.0 552.0 587.4 608.8 600.2 500.8 Operating margin(1) 144.4 166.0 156.1 167.5 150.1 170.8 155.9 156.7 129.0

EBIT (1) 48.5 68.7 63.9 59.6 48.2 83.2 68.2 55.9 53.8

Net earnings before

discontinued operations 42.1 50.6 45.9 41.8 33.1 59.4 47.5 38.5 41.2

Net earnings 41.9 50.1 49.8 42.5 29.7 58.6 47.0 39.0 40.8

Funds generated from operations (1)

83.8 98.5 104.9 74.0 83.1 105.9 83.9 132.5 67.4

Cash used in investing activities 137.7 102.9 95.8

53.8 51.6 93.0 137.2 145.0 81.0 Cash provided by (used in)

financing activities 40.4 52.2 42.5 (33.2) (26.5) 36.1 48.8 (15.2) (35.2) (1) Non-GAAP financial measure. See discussion that follows in Section 4: Non-GAAP Financial Measures.

Electricity volumes sold and electricity volumes distributed to industrial and institutional customers are not normally seasonal in nature. Volumes are predominantly cyclical on a 24-hour period. Residential volumes sold and distributed do peak in the winter resulting in higher revenues during winter months. Volume requirements of commercial customers peak in the summer months with higher demand for air conditioning; this however is offset by a lower demand in the residential market. Over longer periods of time volumes can fluctuate with general economic activity and population growth.

Natural gas volumes and prices are correlated with the time of year as a result of weather patterns. Natural gas consumption and prices will increase with colder weather seen in the winter. As well, natural gas prices can rise in extreme hot weather in the summer as peak electricity demand results in increased gas-fired generation. Revenue levels tend to decline in the shoulder seasons due to lower natural gas prices and volumes during that part of the calendar year. With the cool spring in 2011, volumes continued at higher levels into the shoulder season. This was partially offset by a warm fall which resulted in a decline in natural gas volumes.

While there are other variables that may impact the seasonality of operating margin, EBITDA, net earnings and funds generated from operations, the bulk of the Corporation’s business does not experience material cyclical activities.

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4 NON-GAAP FINANCIAL MEASURES

The Corporation provides non-GAAP financial measures in the MD&A. These measures do not have any standard meaning prescribed by GAAP and may not be comparable to similar measures presented by other companies. The purpose of these financial measures and their reconciliation to GAAP financial measures are shown below. These non-GAAP measures are consistent with the measures used in the previous year, with the exception of EBIT, which has been added to measure operating profits less the accounting-based cost of capital assets.

O p e r a t i n g m a r g i n

Electricity margins 83.7 96.2 279.6 305.3

Natural gas margins 0.3 (1.2) 7.9 2.6

Transmission and distribution margins 46.8 44.1 137.9 134.3

Contractual services margins(1) and other revenue 13.6 11.0 41.1 34.6

Operating margin (non-GAAP financial measure) 144.4 150.1 466.5 476.8

Deduct: OM&A, Amortization, Interest and Income

taxes 102.3 117.0 327.9 336.8

Net earnings from continuing operations (GAAP

financial measure) 42.1 33.1 138.6 140.0

(1) Contractual services margins includes earnings from Envision’s advanced data communications division, distributed generation, home services, meter reading and data management services for non-Calgary municipalities, water meter reading, pole and duct rentals, service locates, streetlight repairs, LRT monitoring, mapping record management, engineering, procurement, construction and maintenance services, utility trenching, construction and maintenance of LRT systems and billing services,

Operating margin is a useful measure of business performance as changes in the market price of electricity and natural gas purchased for resale affect both revenue and costs of sales. Operating margin better reflects the profitability of the Corporation’s business than revenue levels alone.

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E B I T D A

Adjusted EBITDA (non-GAAP financial measure) 88.7 88.9 306.7 318.8

Deduct: EBITDA from discontinued operations (0.2) (3.4) 3.2 (4.7)

Standardized EBITDA 88.9 92.3 303.5 323.5

Deduct: Amortization 40.4 44.1 122.4 123.9

Interest 13.0 17.8 39.4 46.1

Income taxes (6.6) (2.7) 3.1 13.5

EBITDA is a useful measure of business performance as management believes it provides an indication of the operating results generated by the Corporation’s primary business activities without consideration as to how those activities are financed and amortized or how the results are taxed in various business jurisdictions. EBITDA is used to measure certain debt coverage ratios.

E B I T

EBIT (non-GAAP financial measure) 48.5 48.2 181.1 199.6

Deduct: Interest 13.0 17.8 39.4 46.1

Income taxes (6.6) (2.7) 3.1 13.5

EBIT is a useful measure of business performance as management believes it provides an indication of the operating results generated by the Corporation’s primary business activities including the costs of amortization however without consideration as to how those activities are financed or how the results are taxed in various business jurisdictions.

F u n d s g e n e r a t e d f r o m o p e r a t i o n s

Funds generated from operations (non-GAAP financial measure)

83.8 83.1 287.2 272.9

Changes in non-cash working capital (48.6) 75.0 (110.3) 5.0

Employee future benefits (1.3) (1.6) (4.9) (4.3)

Cash provided by operating activities (GAAP financial measure)

33.9 156.5 172.0 273.6

Funds generated from operations are used as an additional metric of cash flow without regard to changes in the Corporation’s non-cash working capital.

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T o t a l i n t e r e s t c o s t

Total interest cost (non-GAAP financial measure) 21.6 20.7 61.7 58.4

Ineffective portion of interest rate swaps 0.3 0.1 (0.2) (0.1)

Capitalized interest (9.9) (4.9) (24.4) (16.0)

Other non-interest financing costs 1.0 1.9 2.3 3.8

Interest expense (GAAP financial measure) 13.0 17.8 39.4 46.1

Total interest cost is used to determine the Corporation’s interest coverage ratios.

5 FINANC IAL COND I TI ON

Significant changes in the Corporation’s financial condition are as follows: (millions of dollars, except %

change) September 30, ₂₀₁₁ December 31, ₂₀₁₀ $ Change _Change% Explanation for _change

ASSETS

Cash and cash equivalents

36.5 65.8 (29.3) (45%) See Section 6: Liquidity and

capital resources.

Accounts receivable 667.0 499.4 167.6 34% Higher revenues due to

higher pool prices Income tax

receivable/payable (1)

32.1 (0.9) 33.0 3,667% Lower taxable earnings

have resulted in accrued tax recoveries.

Other current assets 78.9 103.2 (24.3) (24%) Change in the fair value of

short-term derivatives and unrealized hedging assets Property, plant and

equipment

2,637.1 2,273.6 363.5 16% Capital expenditures, net of

amortization Power purchase

arrangements

486.8 517.0 (30.2) (6%) Amortization on Keephills

and Battle River PPAs offset by capital expenditures related to mercury regulations on each facility

Intangible assets 106.9 113.2 (6.3) (6%) Intangible assets, net of

amortization

Other long-term assets

47.7 28.0 19.7 70% Change in the fair value of

long-term derivatives and increased restricted cash

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(millions of dollars, except %

change) September 30, ₂₀₁₁ December 31, ₂₀₁₀ _Change$ _Change% Explanation for _change

LIABILITIES AND SHAREHOLDER’S EQUITY

Short-term debt 65.1 - 65.1 100% Due to timing of cash

requirements Accounts payable and

accrued liabilities

414.5 327.7 86.8 26% Increase in construction

related payables and higher pool prices

Dividend payable 13.9 - 13.9 100% Dividend declared in March

to be paid in four equal payments over the course of the year.

Other current liabilities 84.7 77.6 7.1 9% Increase in deposits and

deferred revenue

Long-term debt (2) 1,541.3 1,427.7 113.6 8% Proceeds of new Alberta

Capital Finance Authority (ACFA) financing, net of regularly scheduled payments made. Other long-term

liabilities

96.2 58.4 37.8 65% Change in the fair value of

long-term derivatives and unrealized hedging assets. Asset retirement

obligations

13.6 7.1 6.5 92% Change of estimates used

to determine obligations. (1) Net of receivable and payable amounts.

(2) Includes current and long-term amounts.

6 LIQUIDITY AND CAPITAL RESOURCES

C a p i t a l i z a t i o n (millions of dollars) September 30, 2011 December 31, 2010 Total debt (1) 1,606.4 1,427.7 Shareholder’s equity Share capital 280.1 280.1 Retained earnings 1,689.6 1,603.4

Accumulated other comprehensive loss (57.4) (38.3)

Total shareholder’s equity 1,912.3 1,845.2

Total capitalization (total debt plus shareholder’s equity) 3,518.7 3,272.9

(1) Includes the current portion of long-term debt of $53.2 million (December 31, 2010 - $50.0 million) and short-term financing of $65.1 million (December 31, 2010 - $nil). Maturity dates range from October 2011 to September 2036. Comparative period excludes debt on assets held for sale.

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The details of share capital are as follows:

As at September 30, 2011 and December 31, 2010 Number

(millions of dollars, except share amounts) of Shares Amount

Authorized: Unlimited number of common shares

Issued and outstanding:

Issued on incorporation (one dollar) 1 -

Issued on transfer of net assets from Calgary Electric System (CES)

1 278.2 Issued on transfer of billing and customer care

assets from The City of Calgary (The City) in 2001

1 1.9

3 280.1

The details of total liquidity and capital reserves are as follows: (millions of dollars)

September 30, 2011

December 31, 2010

Committed and available bank credit facilities 900.0 750.0

Letters of credit issued: Power pool purchases Energy trading Regulatory commitments Asset commitments PPAs 170.7 26.0 65.8 16.7 67.3 88.1 50.0 74.4 5.6 65.8 346.5 283.9

Remaining available bank facilities 553.5 466.1

Cash on hand 36.5 65.8

Total liquidity and capital reserves 590.0 531.9

The increase in total liquidity and capital reserves over the past nine month period can be attributed to increases in the credit facilities partially offset by increased collateral requirements due to power pool purchases.

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The details of the long-term debt are as follows: As at (millions of dollars) September 30, 2011 December 31, 2010

Long-term debt, (1) consisting of:

ACFA debentures, with remaining terms of:

Less than 5 years 59.5 69.1

5 – 10 years 148.1 48.8

11 – 15 years - 106.9

16 – 20 years 61.2 38.8

21 – 25 years 481.5 368.0

Private debentures

Series 1, remaining term of 7 years, bullet maturity on June 19, 2018 297.4 297.1 Series 2, remaining term of 3 years, bullet maturity on April 8, 2014 249.1 248.8 Non-recourse term financing (Kettles and Calgary Energy Centre (CEC)),

remaining term of 6 and 16 years, respectively

239.2 244.7

Promissory note, remaining term of 16 years 5.3 5.5

1,541.3 1,427.7

(1) Includes current portion of long-term debt of $53.2 million (December 31, 2010 - $50.0 million). Maturity dates range from October 2011 to September 2036. Comparative period excludes debt on assets held for sale.

The Corporation has the following contractual obligations which will impact the Corporation’s financial condition in the future:

Payments Due by Period

Contractual Obligations (millions of dollars)

Total Less than 1

year

1 – 3 years 4 – 5 years After 5

years

Total debt 1,606.4 118.3 111.5 314.0 1,062.6

Capital lease obligations 17.7 0.2 0.3 0.2 17.0

Operating leases 70.5 18.4 22.4 11.6 18.1

Purchase obligations (1) 2,283.0 340.9 495.3 328.0 1,118.8

Asset retirement obligations 13.6 - - - 13.6

Other long-term obligations (2) 96.2 - 75.3 13.9 7.0

Total contractual obligations 4,087.4 477.8 704.8 667.7 2,237.1

(1) Purchase obligation means an agreement to purchase goods or services that is enforceable and legally binding on ENMAX that specifies all significant terms, including: fixed or minimum quantities to be purchased; fixed, minimum, or variable price provisions; and the approximate timing of the transaction.

(2) Other long-term obligations means other long-term liabilities reflected on the Corporation’s balance sheet.

ENMAX pays The City annual dividends equal to the minimum of 30% of the prior year’s net earnings or $30 million, plus any additional one-time special dividends declared. Dividends for a fiscal year are established in the first quarter of the same fiscal year. The payment and level of future dividends on the common shares will be impacted by such factors as financial performance and liquidity requirements.

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Coverage ratios

September 30, 2011

December 31, 2010

Long-term debt to total capitalization (1) 43.8% 43.6%

EBITDA to total interest (2) 4.9X 5.4X

Total debt to total capitalization (3) 45.7% 43.6%

(1) As at period end, long-term debt (including current portion) to total capitalization is equal to long-term debt divided by total debt plus Shareholder’s equity. If cash was netted against the debt, the ratio as at September 30, 2011, would be 42.8% (December 31, 2010 – 41.6%).

(2) EBITDA to total interest is equal to standardized EBITDA divided by gross interest cost (non-GAAP financial measures) calculated on a twelve month rolling basis.

(3) If cash was netted against the debt, the ratio as at September 30, 2011, would be 44.6% (December 31, 2010 – 41.6%).

C a p i t a l s t r a t e g y

The Corporation funds its business with a view to maintaining a conservative capital structure in line with its strategy of maintaining a stable, investment grade credit rating. While the Corporation has set long-term target ratios for debt to total capitalization at a maximum of 45% and EBITDA to total interest coverage ratios at 5 times or better, very low electricity prices, high capital expenditures associated with significant construction projects or other factors could result in the Corporation not reaching its targets for short periods of time. Targets are managed using a long-term view and set at more conservative levels than actual debt covenants. Standard & Poor’s has assigned a BBB+ rating with a stable outlook. Dominion Bond Rating Services has issued its credit rating of A (low) for unsecured debentures. These ratings provide reasonable access to debt capital markets. The principal financial covenants in ENMAX’s credit facilities and debentures are interest coverage and debt to capitalization. As at September 30, 2011, the Corporation is in compliance with its financial covenants related to debt classified as long-term debt on the balance sheet.

As at September 30, 2011, ENMAX classified $nil of non-recourse financing as liabilities held for sale related to the British Columbia assets sold (December 31, 2010 - $12.2 million).

C a s h p r o vi d e d b y o p e r a t i n g a c t i vi t i e s

Funds generated from operations for the three and nine months ended September 30, 2011, were $83.8 million and $287.2 million, respectively, compared with $83.1 million and $272.9 million, respectively, in the same periods in 2010. The increase in funds generated for the third quarter was primarily due to higher operating earnings experienced. On a year-to-date basis, funds generated from operations have increased as a result of higher net earnings and an increase in future income taxes which are offset by the lower realization of financial contracts.

Cash provided by operating activities for the three and nine months ended September 30, 2011, was $33.9 million and $172.0 million, respectively, compared with $156.5 million and $273.6 million, respectively, in the same periods last year. The decrease in cash flow from operations in the third quarter was driven by a significant swing in working capital requirements. This was primarily due to a larger increase in accounts receivable in the third quarter due to higher commodity prices and volumes. These higher revenues are collected in the month following

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I n ve s t i n g a c t i vi t i e s

Capital spending was $133.4 million and $439.6 million, respectively, in the three and nine months ended September 30, 2011, which represents an increase of $76.6 million and an increase of $124.1 million, respectively, over the same periods last year. Capital projects for the three and nine months ended September 30, 2011, included a $35.1 million and $87.1 million, respectively, investment in the transmission and distribution network in Calgary and surrounding area, $95.0 million and $345.6 million, respectively, in construction costs related to Calgary area generation projects and $3.0 million and $4.6 million, respectively, in information technology expansion. The investment in the transmission and distribution network in Calgary allows ENMAX Power to meet one of the Corporation’s core strategies of continuing to provide safe, reliable and cost-effective transmission and distribution services to the city of Calgary while meeting the challenges of a growing and expanding city. The investment in the Calgary area generation projects allows ENMAX Energy to move towards the Corporation’s core strategy of serving its growing customer base with a generation portfolio that emits fewer greenhouse gases than in the past and leading the development of a more efficient utility model. The investment in information technology will allow ENMAX to continue to comply with regulations and effectively operate the business, in line with the Corporation’s strategy to maintain the reliability and cost-effectiveness of the Corporation’s technology infrastructure while meeting the challenges of obsolescence and growth.

During the three and nine months ended September 30, 2011, the Corporation received $nil and $102.0 million of cash, respectively, net of cash disposed of, from the sale of the British Columbia assets. These funds were used to fund current capital spending activities.

F i n a n c i n g a c t i vi t i e s

ENMAX repaid $9.0 million and $32.6 million, respectively, of long-term debt in regularly scheduled principal payments during the three and nine months ended September 30, 2011, compared with $9.3 million and $30.3 million, respectively, in the same periods in 2010. These repayments were sourced through operating activities. ENMAX also disposed of $nil and $11.6 million, respectively, of long-term debt during the three and nine months ended September 30, 2011, as part of the sale of Furry Creek.

On March 9, 2011, the Corporation declared a dividend of $55.6 million payable to The City. The first three quarterly instalments of the dividend have been paid, and the remaining instalment will be paid before the end of 2011.

On June 15, 2011, the Corporation obtained $145.9 million of financing from The City through arrangements with the ACFA to fund ongoing investment relating to the regulated transmission and distribution network in Calgary and the surrounding area.

Due to higher pool prices, the timing of payments to the pool and collection of the related revenue from customers, ENMAX had $65.1 million of outstanding Commercial Paper as at September 30, 2011. This amount was repaid shortly after quarter end.

The Corporation has provided guarantees on behalf of certain consolidated subsidiaries for obligations to perform and make payments under various other contracts. The amount guaranteed under these contracts at September 30, 2011, was a maximum of $1,493.0 million, compared to $708.7 million as at December 31, 2010. The

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At September 30, 2011, cash and cash equivalents amounted to $36.5 million, compared with $65.8 million at December 31, 2010.

7 FUTURE ACCOUN TING CHANGES

I n t e r n a t i o n a l F i n a n c i a l R e p o r t i n g S t a n d a r d s ( I F R S )

On February 13, 2008, the Accounting Standards Board of Canada (AcSB) confirmed the changeover from GAAP to International Financial Reporting Standards (IFRS), as issued by the International Accounting Standards Board (IASB), will be effective for fiscal years beginning on or after January 1, 2011. On September 30, 2010, the AcSB issued an amendment to this directive which allows entities that have activities subject to rate regulation to delay adoption of IFRS until January 1, 2012. The Corporation chose to take this option and will apply IFRS in reporting interim and annual consolidated financial statements, including comparative periods, beginning January 1, 2012. While IFRS uses a conceptual framework similar to GAAP, there will be differences in accounting policies.

The Corporation is on track with its IFRS conversion plan. The discussion that follows describes specific adjustments which will impact the Corporation on transition and reflects expectations based on information available at the reporting date. The discussion of accounting policy selections and IFRS 1 exemptions are preliminary and circumstances may change prior to the changeover date which may cause the Corporation to select different accounting policies and/or IFRS 1 exemptions.

Policy Area Description of IFRS Change Status and Significant Impacts

Rate Regulated Activities

There is a potential financial impact if

regulated assets and liabilities are not able to be recognized under IFRS.

Positions are being developed to support regulated assets and liabilities under other IFRS standards.

Property Plant and

Equipment (PP&E)

• Under IFRS, major overhauls are capitalized and subsequently amortized over the life until the next scheduled major overhaul.

• An IFRS 1 election will be used to lock in the capital overhead recognized in historical regulated PP&E. However, IFRS does not allow for the capitalization of regulatory approved overhead and inter-company profits so the amounts will be reduced after transition.

• The capitalization of major overhauls will result in a reduction to property, plant and equipment as at January 1, 2011. The associated quarterly impacts are insignificant.

• The change in the capital overhead rate will not have an impact on the transition to IFRS; however, it will result in a write off of capitalized overhead on a quarterly basis to the income statement. This amount will not be recovered through rates as the rate adjustment is being proposed for IFRS years of 2012 and go forward. As ENMAX Power Corporation is a non-taxable entity, there is no tax effect of this adjustment.

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Policy Area Description of IFRS Change Status and Significant Impacts

Transfers of Assets from Customers

IFRIC 18 requires that transfers of assets from customers be treated as revenue, either a one-time revenue or deferred revenue unlike Canadian GAAP where these amounts were treated as contra PPE assets and were amortized.

The result is an increase in PPE and

deferred revenue liabilities on transition. This has no impact on opening retained earnings. The amortization period of these

contributions remains consistent with the life of the asset; however, the amortization is recorded as revenue instead of an offset to the amortization of the asset. The impact will result in an increase in revenue and an increase in amortization of the same amount. Asset

Retirement Obligations

Under IFRS, the discount rate used for determining an asset retirement obligation is the risk-free rate. This is different than the credit risk adjusted rate used for GAAP.

The change in discount rate will result is an increase to both the Corporation’s liabilities and PPE on transition. This has no impact on opening retained earnings.

Employee Benefits

IFRS 1 allows a first-time adopter to reset to zero all cumulative actuarial gains and losses at the date of transition to IFRS. If this exemption is used, it must be used for all employee benefit plans. This election allows first-time adopters the ability to start their accounting under IFRS with a “clean state” as it pertains to actuarial gains and losses. This election reduces future costs related to the amortization of these losses.

The Corporation will reset its cumulative actuarial gains and losses on transition. This election will reduce future costs related to the amortization of these losses.

Changing standards

New standards issued in 2011 include the amendments to Employee Benefits and Financial Statement Presentation as well as new standards on Fair Value Measurement, Consolidated Financial Statements, Joint Arrangements and Disclosure of Interests in Other Entities. The Corporation expects to early adopt these new standards on transition to IFRS and impacts are being identified.

Information technology and data systems

Modifications have been implemented to extend the transition date from January 1, 2010; to January 1, 2011. Data conversion continued in the third quarter.

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8 CRITICAL ACCOUNTING ESTIMATES

Since a determination of the value of many assets, liabilities, revenues and expenses is dependent upon future events, the preparation of the Corporation’s consolidated financial statements requires the use of estimates and assumptions. Accounting policies have been developed to ensure appropriate implementation and interpretation of accounting rules and complex situations are addressed using careful judgment. Adjustments to previous estimates, which will impact net income and could be material, are recorded in the period they become known. ENMAX’s critical accounting estimates are related to revenue recognition, allowance for doubtful accounts, amortization expense, asset impairment, asset retirement obligations, provisions for income taxes, employee future benefits and financial instruments. The estimates and assumptions made in these areas can be highly uncertain at the time the estimate or assumption is made. Different or changing estimates and assumptions could potentially have a material impact on ENMAX’s financial position or results of operations. These critical estimates are described in ENMAX’s 2010 Financial Report in Section 9 of the Management’s Discussion and Analysis and in Note 2 in the Notes to Consolidated Financial Statements.

During the second quarter of 2011, the Corporation completed a reassessment of its asset retirement obligations. The Corporation’s asset retirement obligations relate to costs associated with the removal and decommissioning of its fibre optic network, certain electricity generating assets and proportionate share of jointly owned assets. For each of the Corporation’s obligations, the assumptions used in the calculations were reassessed which included the discount rate, time-frame, inflation rate and dollar amount of the future obligation. The new assumptions were applied prospectively and resulted in a $6.4 million increase in fixed assets and asset retirement liability.

9 RISK MANAGEME NT AND UNCERTAINTIES

ENMAX’s approach to risk management addresses risk exposures across all of the Corporation’s business activities and risk types. After consultation with the Board, management developed and implemented an Enterprise Risk Management (ERM) program in 2008 to identify, analyze, evaluate, treat and communicate the Corporation’s risk exposures in a manner consistent with ENMAX’s business objectives and risk appetite. For further information on risks, refer to Section 10 of Management’s Discussion and Analysis in ENMAX’s 2010 Financial Report.

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10 FINANCIAL INSTRUMENTS

E n e r g y T r a d i n g D e r i va t i ve s

The fair value of ENMAX Energy’s contracts-for-differences is determined by estimating the amounts that would have to be received or paid to counterparties to terminate the contracts at September 30, 2011, and December 31, 2010. The following contracts-for-differences were outstanding at the end of the period:

September 30, 2011 December 31, 2010 Notional Quantities Electricity sales (GW) 2,859 2,153

Natural gas sales (TJ) 164 654

Electricity purchases (GW) 1,257 1,707

Natural gas purchases (TJ) 15,235 10,981

At September 30, 2011, on the basis of electricity and natural gas prices at that date, the estimated cost of settling these contracts at the balance sheet date, excluding PPA sales, would be a negative mark-to-market adjustment amounting to $45.3 million (December 31, 2010 – $33.8 million). This amount does not reflect the fact that these contracts will settle at prices in effect in the future.

Refer to Note 5 in the Notes to the Consolidated Financial Statements for further information on financial instruments.

11 CLIMATE CHANGE AND THE ENVIRONMENT

Environmental Liabilities

The Corporation’s environmental liabilities consist of greenhouse gas (GHG) liabilities. These obligations relate to electricity generated from both of the Corporation’s PPAs and CEC. These items have been reflected as liabilities in the consolidated financial statements as at September 30, 2011. The Corporation will continue to abide by current and future environmental regulations.

There are currently no outstanding lawsuits against the Corporation for environmental matters. There are no other known environmental liabilities at this point in time or foreseen in the future.

Asset Retirement Obligations

At September 30, 2011, the Corporation has asset retirement obligations relating to the following project generating assets: McBride Lake, Taber, Crossfield, Kettles Hill and CEC. The Corporation also has an asset retirement obligation relating to the Envision business unit for its advanced data communication assets.