EX-13.3 4 a11-6156_2ex13d3.htm CONSOLIDATED AUDITED ANNUAL FINANCIAL STATEMENTS FOR THE YEAR ENDED DECEMBER 31, 2010.

Exhibit 13.3

TransAlta Consolidated Financial Statements

December 31, 2010

Management’s Report

To the Shareholders of TransAlta Corporation

The consolidated financial statements and other financial information included in this annual report have been prepared by management. It is management’s responsibility to ensure that sound judgment, appropriate accounting principles and methods, and reasonable estimates have been used to prepare this information. They also ensure that all information presented is consistent.

Management is also responsible for establishing and maintaining internal controls and procedures over the financial reporting process. The internal control system includes an internal audit function and an established business conduct policy that applies to all employees. In addition, the Corporation has a code of conduct that applies to all employees and is signed annually. The code of conduct can be viewed on TransAlta’s website (www.transalta.com). Management believes the system of internal controls, review procedures, and established policies provide reasonable assurance as to the reliability and relevance of financial reports. Management also believes that TransAlta’s operations are conducted in conformity with the law and with a high standard of business conduct.

The Board of Directors is responsible for ensuring that management fulfills its responsibilities for financial reporting and internal control. The Board carries out its responsibilities principally through its Audit and Risk Committee (“the Committee”). The Committee, which consists solely of independent directors, reviews the financial statements and annual report and recommends them to the Board for approval. The Committee meets with management, internal auditors, and external auditors to discuss internal controls, auditing matters, and financial reporting issues. Internal and external auditors have full and unrestricted access to the Committee. The Committee also recommends the firm of external auditors to be appointed by the shareholders.

Stephen G. Snyder |  | Brett Gellner
President & Chief Executive Officer |  | Chief Financial Officer
February 23, 2011 |

C o n s o l i d a t e d F i n a n c i a l S t a t e m e n t s | 1

Management’s Annual Report on Internal Control over Financial Reporting

To the Shareholders of TransAlta Corporation

The following report is provided by management in respect of TransAlta Corporation’s internal control over financial reporting (as defined in Rules 13a-15f and 15d-15f under the United States Securities Exchange Act of 1934).

TransAlta’s management is responsible for establishing and maintaining adequate internal control over financial reporting for TransAlta.

Management has used the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) framework to evaluate the effectiveness of TransAlta Corporation’s internal control over financial reporting. Management believes that the COSO framework is a suitable framework for its evaluation of TransAlta Corporation’s internal control over financial reporting because it is free from bias, permits reasonably consistent qualitative and quantitative measurements of TransAlta Corporation’s internal controls, is sufficiently complete so that those relevant factors that would alter a conclusion about the effectiveness of TransAlta Corporation’s internal controls are not omitted, and is relevant to an evaluation of internal control over financial reporting.

Internal control over financial reporting cannot provide absolute assurance of achieving financial reporting objectives because of its inherent limitations. Internal control over financial reporting is a process that involves human diligence and compliance and is subject to lapses in judgment and breakdowns resulting from human failures. Internal control over financial reporting also can be circumvented by collusion or improper overrides. Because of such limitations, there is a risk that material misstatements may not be prevented or detected on a timely basis by internal control over financial reporting. However, these inherent limitations are known features of the financial reporting process, and it is possible to design safeguards into the process to reduce, though not eliminate, this risk.

TransAlta Corporation proportionately consolidates the accounts of the Sheerness, CE Generation, Wailuku, and Genesee 3 joint ventures in accordance with Canadian GAAP. Management does not have the contractual ability to assess the internal controls of these joint ventures. Once the financial information is obtained from the joint ventures it falls within the scope of TransAlta Corporation’s internal controls framework. Management’s conclusion regarding the effectiveness of internal controls does not extend to the internal controls at the transactional level of the joint ventures. The 2010 consolidated financial statements of TransAlta Corporation included $1,454 million and $804 million of total and net assets, respectively, as of Dec. 31, 2010, and $344 million and $64 million of revenues and net earnings, respectively, for the year then ended related to these joint ventures.

Management has assessed the effectiveness of TransAlta Corporation’s internal control over financial reporting, as at Dec. 31, 2010, and has concluded that such internal control over financial reporting is effective.

Ernst & Young LLP, who has audited the consolidated financial statements of TransAlta Corporation for the year ended Dec. 31, 2010, has also issued a report on internal control over financial reporting under Auditing Standard No. 5 of the Public Company Accounting Oversight Board (United States). This report is located on the following page of this Annual Report.

Stephen G. Snyder |  | Brett Gellner
President & Chief Executive Officer |  | Chief Financial Officer
February 23, 2011 |

2 | T r a n s A l t a C o r p o r a t i o n

Independent Auditors’ Report on Internal Controls under Standards

of the Public Company Accounting Oversight Board (United States)

To the Shareholders of TransAlta Corporation

We have audited TransAlta Corporation’s internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). The Corporation’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Corporation’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A corporation’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A corporation’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the corporation; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the corporation are being made only in accordance with authorizations of management and directors of the corporation; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the corporation’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate.

As indicated in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting, management’s assessment of and conclusion on the effectiveness of internal control over financial reporting did not include the internal controls of the Sheerness, CE Generation, Wailuku, and Genesee 3 joint ventures, which are included in the 2010 consolidated financial statements of the Corporation and constituted $1,454 million and $804 million of total and net assets, respectively, as of December 31, 2010, and $344 million and $64 million of revenues and net earnings, respectively, for the year then ended. Our audit of internal control over financial reporting of the Corporation did not include an evaluation of the internal control over financial reporting of the Sheerness, CE Generation, Wailuku, and Genesee 3 joint ventures.

In our opinion, TransAlta Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on the COSO criteria.

We have also audited, in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of TransAlta Corporation as of December 31, 2010 and 2009 and the related consolidated statements of earnings and retained earnings, comprehensive income and cash flows for each of the years in the three-year period ended December 31, 2010, and our report dated February 23, 2011, expressed an unqualified opinion thereon.

Ernst & Young LLP
Chartered Accountants
Calgary, Canada
February 23, 2011

C o n s o l i d a t e d F i n a n c i a l S t a t e m e n t s | 3

Independent Auditors’ Report of Registered Public Accounting Firm

To the Shareholders of TransAlta Corporation

We have audited the accompanying consolidated financial statements of TransAlta Corporation, which comprise the consolidated balance sheets as at December 31, 2010 and 2009, and the consolidated statements of earnings and retained earnings, comprehensive income and cash flows for each of the years in the three-year period ended December 31, 2010, and a summary of significant accounting policies and other explanatory information.

Management’s Responsibility for the Consolidated Financial Statements

Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with Canadian generally accepted accounting principles, and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

Auditors’ Responsibility

Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we comply with ethical requirements and plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on the auditors’ judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.

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

Opinion

In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of TransAlta Corporation as at December 31, 2010 and 2009, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2010 in accordance with Canadian generally accepted accounting principles.

Other Matter

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), TransAlta Corporation’s internal control over financial reporting as of December 31, 2010, based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 23, 2011 expressed an unqualified opinion on TransAlta Corporation’s internal control over financial reporting.

Ernst & Young LLP
Chartered Accountants
Calgary, Canada
February 23, 2011

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Consolidated Statements of Earnings and Retained Earnings

Year ended Dec. 31 (in millions of Canadian dollars except where noted) | 2010 |  | 2009 |  | 2008 |
Revenues | 2,819 |  | 2,770 |  | 3,110 |
Fuel and purchased power | 1,202 |  | 1,228 |  | 1,493 |
| 1,617 |  | 1,542 |  | 1,617 |
Operations, maintenance, and administration | 634 |  | 667 |  | 637 |
Depreciation and amortization | 459 |  | 475 |  | 428 |
Taxes, other than income taxes | 27 |  | 22 |  | 19 |
| 1,120 |  | 1,164 |  | 1,084 |
| 497 |  | 378 |  | 533 |
Foreign exchange gain (loss) (Note 8) | 10 |  | 8 |  | (12 | )
Asset impairment charges (Note 3) | (89 | ) | (16 | ) | - |
Net interest expense (Notes 8 and 17) | (178 | ) | (144 | ) | (110 | )
Equity loss (Note 24) | - |  | - |  | (97 | )
Other income (Note 4) | - |  | 8 |  | 5 |
Earnings before non-controlling interests and income taxes | 240 |  | 234 |  | 319 |
Non-controlling interests (Note 5) | 20 |  | 38 |  | 61 |
Earnings before income taxes | 220 |  | 196 |  | 258 |
Income tax expense (Note 6) | 1 |  | 15 |  | 23 |
Net earnings | 219 |  | 181 |  | 235 |
Preferred share dividends (Note 21) | 1 |  | - |  | - |
Net earnings applicable to common shares | 218 |  | 181 |  | 235 |
Retained earnings |  |  |  |  |  |
Opening balance | 634 |  | 688 |  | 763 |
Common share dividends (Note 20) | (319 | ) | (235 | ) | (215 | )
Shares cancelled under NCIB (Note 20) | - |  | - |  | (95 | )
Closing balance | 533 |  | 634 |  | 688 |
Weighted average number of common shares outstanding in the year | 219 |  | 201 |  | 199 |
Net earnings per common share, basic and diluted (Note 20) | 1.00 |  | 0.90 |  | 1.18 |

See accompanying notes.

C o n s o l i d a t e d F i n a n c i a l S t a t e m e n t s | 5

Consolidated Balance Sheets

Dec. 31 (in millions of Canadian dollars) | 2010 |  | 2009 |
|  |  | (Note 2) |
Cash and cash equivalents (Notes 7 and 24) | 58 |  | 82 |
Accounts receivable (Notes 7, 9, 24, and 28) | 428 |  | 421 |
Collateral paid (Notes 7 and 8) | 27 |  | 27 |
Prepaid expenses (Note 24) | 10 |  | 18 |
Risk management assets (Notes 7 and 8) | 265 |  | 144 |
Income taxes receivable | 19 |  | 39 |
Inventory (Note 10) | 53 |  | 90 |
| 860 |  | 821 |
Long-term receivable (Notes 7 and 11) | - |  | 49 |
Property, plant, and equipment (Notes 12, 24, and 29) |  |  |  |
Cost | 11,706 |  | 11,701 |
Accumulated depreciation | (4,129 | ) | (4,142 | )
| 7,577 |  | 7,559 |
Assets held for sale (Note 13) | 60 |  | - |
Goodwill (Notes 14, 24, and 29) | 517 |  | 434 |
Intangible assets (Notes 15 and 24) | 304 |  | 344 |
Future income tax assets (Note 6) | 240 |  | 234 |
Risk management assets (Notes 7 and 8) | 208 |  | 224 |
Other assets (Notes 16 and 24) | 127 |  | 121 |
Total assets | 9,893 |  | 9,786 |
Short-term debt (Note 7) | 1 |  | - |
Accounts payable and accrued liabilities (Notes 7 and 24) | 503 |  | 521 |
Collateral received (Notes 7 and 8) | 126 |  | 86 |
Risk management liabilities (Notes 7, 8, and 24) | 35 |  | 45 |
Income taxes payable | 8 |  | 10 |
Future income tax liabilities (Note 6) | 77 |  | 45 |
Dividends payable (Note 7) | 130 |  | 61 |
Current portion of long-term debt - recourse (Notes 7 and 17) | 235 |  | 7 |
Current portion of long-term debt - non-recourse (Notes 7 and 17) | 20 |  | 24 |
Current portion of asset retirement obligation (Note 18) | 38 |  | 32 |
| 1,173 |  | 831 |
Long-term debt - recourse (Notes 7 and 17) | 3,450 |  | 3,857 |
Long-term debt - non-recourse (Notes 7, 17, and 24) | 529 |  | 554 |
Asset retirement obligation (Notes 18 and 24) | 204 |  | 250 |
Liabilities held for sale (Note 13) | 3 |  | - |
Deferred credits and other long-term liabilities (Note 19) | 169 |  | 147 |
Future income tax liabilities (Notes 6 and 24) | 630 |  | 662 |
Risk management liabilities (Notes 7, 8, and 24) | 123 |  | 78 |
Non-controlling interests (Note 5) | 435 |  | 478 |
Shareholders’ equity |  |  |  |
Common shares (Notes 20 and 22) | 2,211 |  | 2,169 |
Preferred shares (Notes 21 and 22) | 293 |  | - |
Retained earnings (Note 22) | 533 |  | 634 |
Accumulated other comprehensive income (Note 22) | 140 |  | 126 |
Total shareholders’ equity | 3,177 |  | 2,929 |
Total liabilities and shareholders’ equity | 9,893 |  | 9,786 |
Contingencies (Notes 26 and 28) |  |  |  |
Commitments (Notes 7 and 27) |  |  |  |
Subsequent events (Note 34) |  |  |  |

See accompanying notes. |  |  |  |
On behalf of the Board: |  | Donna Soble Kaufman |  | William D. Anderson
|  | Director |  | Director

6 | T r a n s A l t a C o r p o r a t i o n

Consolidated Statements of Comprehensive Income

Year ended Dec. 31 (in millions of Canadian dollars) | 2010 |  | 2009 |  | 2008 |
Net earnings | 219 |  | 181 |  | 235 |
Other comprehensive income |  |  |  |  |  |
(Losses) gains on translating net assets of self-sustaining foreign operations | (60 | ) | (209 | ) | 342 |
Gains (losses) on financial instruments designated as hedges of self-sustaining |  |  |  |  |  |
foreign operations, net of tax 1 | 33 |  | 140 |  | (295 | )
Gains on derivatives designated as cash flow hedges, net of tax 2 | 164 |  | 280 |  | 198 |
Loss on sale of Mexico equity investment reclassified to the |  |  |  |  |  |
Consolidated Statements of Earnings, net of tax 3 (Note 24) | - |  | - |  | (8 | )
Reclassification of losses (gains) on derivatives designated as |  |  |  |  |  |
cash flow hedges to the Consolidated Balance Sheets, net of tax 4 | 8 |  | (11 | ) | 8 |
Reclassification of (gains) losses on derivatives designated as |  |  |  |  |  |
cash flow hedges to net earnings, net of tax 5 | (129 | ) | (135 | ) | 61 |
Reclassification of gains on translation of self-sustaining |  |  |  |  |  |
foreign operations to net earnings, net of tax 6 | (2 | ) | - |  | - |
Other comprehensive income | 14 |  | 65 |  | 306 |
Comprehensive income | 233 |  | 246 |  | 541 |

1 Net of income tax expense of 6 for the year ended Dec. 31, 2010 (2009 - 26 expense, 2008 - 61 recovery).

2 Net of income tax expense of 87 for the year ended Dec. 31, 2010 (2009 - 120 expense, 2008 - 129 expense).

3 Net of income tax expense of 9 for the year ended Dec. 31, 2008.

4 Net of income tax recovery of 3 for the year ended Dec. 31, 2010 (2009 - 4 expense, 2008 - nil).

5 Net of income tax expense of 65 for the year ended Dec. 31, 2010 (2009 - 69 expense, 2008 - 30 recovery).

6 Net of income tax expense of 3 for the year ended Dec. 31, 2010.

See accompanying notes.

C o n s o l i d a t e d F i n a n c i a l S t a t e m e n t s | 7

Consolidated Statements of Cash Flows

Year ended Dec. 31 (in millions of Canadian dollars) | 2010 |  | 2009 |  | 2008 |
Operating activities |  |  |  |  |  |
Net earnings | 219 |  | 181 |  | 235 |
Depreciation and amortization (Note 29) | 490 |  | 493 |  | 451 |
Gain on sale of equipment | (4 | ) | - |  | (5 | )
Non-controlling interests (Note 5) | 20 |  | 38 |  | 61 |
Asset retirement obligation accretion (Note 18) | 21 |  | 24 |  | 22 |
Asset retirement costs settled (Note 18) | (37 | ) | (35 | ) | (37 | )
Future income taxes (Note 6) | 28 |  | 21 |  | 1 |
Unrealized (gain) loss from risk management activities | (47 | ) | 2 |  | 12 |
Unrealized foreign exchange gain | (5 | ) | (11 | ) | (5 | )
Asset impairment charges (Note 3) | 89 |  | 16 |  | - |
Equity loss (Note 24) | - |  | - |  | 97 |
Other non-cash items | 9 |  | - |  | (4 | )
| 783 |  | 729 |  | 828 |
Change in non-cash operating working capital balances (Note 30) | 28 |  | (149 | ) | 210 |
Cash flow from operating activities | 811 |  | 580 |  | 1,038 |
Investing activities |  |  |  |  |  |
Acquisition of Canadian Hydro Developers, Inc., net of cash acquired (Note 24) | - |  | (766 | ) | - |
Additions to property, plant, and equipment (Note 12) | (790 | ) | (904 | ) | (1,006 | )
Proceeds on sale of property, plant, and equipment | 6 |  | 7 |  | 30 |
Proceeds on sale of minority interest in Kent Hills (Notes 4 and 5) | 15 |  | 29 |  | - |
Restricted cash | - |  | - |  | 248 |
Resolution of certain tax matters (Note 11) | 29 |  | (41 | ) | (8 | )
Realized (losses) gains on financial instruments | (29 | ) | (16 | ) | 52 |
Loan to equity investment | - |  | - |  | (245 | )
Proceeds on sale of equity investment (Note 24) | - |  | - |  | 332 |
Net increase in collateral received from counterparties | 47 |  | 87 |  | - |
Net (increase) decrease in collateral paid to counterparties | (2 | ) | 7 |  | - |
Settlement of adjustments on sale of Mexican equity investment | - |  | (7 | ) | - |
Other | 4 |  | 6 |  | 16 |
Cash flow used in investing activities | (720 | ) | (1,598 | ) | (581 | )
Financing activities |  |  |  |  |  |
Net (decrease) increase in borrowings under credit facilities (Note 17) | (400 | ) | 620 |  | (243 | )
Repayment of long-term debt (Note 17) | (31 | ) | (796 | ) | (308 | )
Issuance of long-term debt (Note 17) | 301 |  | 1,119 |  | 502 |
Dividends paid on common shares | (216 | ) | (226 | ) | (212 | )
Funds paid to repurchase common shares under NCIB (Note 20) | - |  | - |  | (130 | )
Net proceeds on issuance of common shares (Note 20) | 1 |  | 398 |  | 15 |
Net proceeds on issuance of preferred shares (Note 21) | 291 |  | - |  | - |
Realized gains on financial instruments | 3 |  | - |  | 12 |
Distributions paid to subsidiaries’ non-controlling interests (Note 5) | (62 | ) | (58 | ) | (98 | )
Other | - |  | (4 | ) | (5 | )
Cash flow (used in) from financing activities | (113 | ) | 1,053 |  | (467 | )
Cash flow (used in) from operating, investing, and financing activities | (22 | ) | 35 |  | (10 | )
Effect of translation on foreign currency cash | (2 | ) | (3 | ) | 9 |
(Decrease) increase in cash and cash equivalents | (24 | ) | 32 |  | (1 | )
Cash and cash equivalents, beginning of year | 82 |  | 50 |  | 51 |
Cash and cash equivalents, end of year | 58 |  | 82 |  | 50 |
Cash taxes (recovered) paid | (49 | ) | 43 |  | 47 |
Cash interest paid | 153 |  | 149 |  | 106 |

See accompanying notes.

8 | T r a n s A l t a C o r p o r a t i o n

Notes to Consolidated Financial Statements

(Tabular amounts in millions of Canadian dollars, except as otherwise noted)

1. Summary of Significant Accounting Policies

A. Description of the Business

TransAlta Corporation (“TransAlta” or “the Corporation”) was incorporated under the Canada Business Corporations Act in March 1985. The Corporation became a public company in December 1992 after TransAlta Utilities Corporation (“TAU”) became a subsidiary. The Corporation has three reportable segments.

The three reportable segments of the Corporation are as follows:

I. Generation

The Generation segment owns and operates hydro, wind, geothermal, biomass, natural gas- and coal-fired facilities, and related mining operations in Canada, the United States (“U.S.”), and Australia. Generation’s revenues are derived from the availability and production of electricity and steam as well as ancillary services such as system support.

II. Energy Trading 1

The Energy Trading segment derives revenue and earnings from the wholesale trading of electricity and other energy-related commodities and derivatives.

Energy Trading manages available generating capacity as well as the fuel and transmission needs of the Generation business by utilizing contracts of various durations for the forward sales of electricity and for the purchase of natural gas and transmission capacity. Energy Trading is also responsible for recommending portfolio optimization decisions. The results of all of these activities are included in the Generation segment.

III. Corporate

The Corporate segment provides finance, tax, treasury, legal, regulatory, environmental, health and safety, sustainable development, corporate communications, government and investor relations, information technology, risk management, human resources, internal audit, and other administrative support to the Generation and Energy Trading groups.

B. Consolidation

These consolidated financial statements have been prepared by management in accordance with Canadian Generally Accepted Accounting Principles (“Canadian GAAP”).

The consolidated financial statements include the accounts of TransAlta, all subsidiaries, and the proportionate share of the accounts of joint ventures and jointly controlled corporations.

C. Use of Estimates

The preparation of consolidated financial statements in accordance with Canadian GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the period. These estimates are subject to uncertainty. Actual results could differ from those estimates due to factors such as fluctuations in interest rates, currency exchange rates, inflation levels and commodity prices, changes in economic conditions, and legislative and regulatory changes.

D. Revenue Recognition

The majority of the Corporation’s revenues are derived from the sale of physical power and from energy marketing and trading activities. Revenues under long-term electricity and thermal sales contracts generally include one or more of the following components: fixed capacity payments for being available, energy payments for generation of electricity, availability payments or penalties for exceeding or not meeting availability targets, excess energy payments for power generation above committed capacity, and ancillary services. Each is recognized upon output, delivery, or satisfaction of specific targets, all as specified by contractual terms. Revenues from non-contracted capacity are comprised of energy payments for each megawatt hour (“MWh”) produced at market prices, and are recognized upon delivery.

Trading activities use derivatives such as physical and financial swaps, forward sales contracts, and futures contracts and options, which are used to earn trading revenues and to gain market information. These derivatives are accounted for using fair value accounting and are presented on a net basis in the Consolidated Statements of Earnings. The initial recognition of

1 The Energy Trading segment was referred to as “Commercial Operations and Development” in 2009 and 2008.

N o t e s to C o n s o l i d a t e d F i n a n c i a l S t a t e m e n t s | 9

fair value and subsequent changes in fair value affect reported net earnings in the period the change occurs. The fair values of those instruments that remain open at the balance sheet date represent unrealized gains or losses and are presented on the Consolidated Balance Sheets as risk management assets or liabilities.

The fair value of derivatives traded by the Corporation that are not traded on an active exchange, or extend beyond the time period for which exchange-based quotes are available, are determined using valuation techniques or models.

E. Foreign Currency Translation

The Corporation’s functional currency is Canadian dollars, while self-sustaining foreign operations’ functional currencies are U.S. and Australian dollars.

The Corporation’s self-sustaining foreign operations are translated using the current rate method. Translation gains and losses resulting from translating these foreign operations are included in Other Comprehensive Income (“OCI”) with the cumulative gain or loss reported in Accumulated Other Comprehensive Income (“AOCI”). Foreign currency denominated monetary and non-monetary assets and liabilities of self-sustaining foreign operations are translated at exchange rates in effect on the balance sheet date. The amounts previously recognized in AOCI are recognized in net earnings when there is a permanent reduction in the hedged net investment as a result of a dilution or sale of the net investment.

Transactions denominated in a currency other than the functional currency are translated at the exchange rate on the transaction date. The resulting exchange gains and losses on these items are included in net earnings.

F. Financial Instruments and Hedges

I. Financial Instruments

Financial assets and financial liabilities, including derivatives, and certain non-financial derivatives are recognized on the Consolidated Balance Sheets from the point when the Corporation becomes a party to the contract. Financial liabilities are removed from the consolidated financial statements when the liability is extinguished either through settlement of or release from the obligation of the underlying liability. All financial instruments are measured at fair value upon initial recognition except for certain non-financial derivative contracts that meet the Corporation’s expected purchase, sale, or usage requirements, commonly termed normal purchase/normal sale (“NPNS”) contracts. Measurement in subsequent periods depends on whether the financial instrument has been classified as held for trading, available-for-sale, held-to-maturity, loans and receivables, or other financial liabilities. Classification of the financial instrument is determined at inception depending on the underlying exposure that is being hedged.

Financial assets and financial liabilities classified as held for trading are measured at fair value with changes in those fair values recognized in net earnings. Financial assets classified as either held-to-maturity or loans and receivables, and other financial liabilities are measured at amortized cost using the effective interest method of amortization. Investments in equity instruments classified as available-for-sale that do not have a quoted market price in an active market are measured at cost.

Derivative instruments are recorded on the Consolidated Balance Sheets at fair value, including those derivatives that are embedded in financial or non-financial contracts that are not closely related to the host contracts. TransAlta recognizes as separate assets and liabilities only those derivatives embedded in hybrid instruments issued, acquired, or substantively modified after Jan. 1, 2003. Changes in the fair values of derivative instruments are recognized in net earnings with the exception of the effective portion of (i) derivatives designated as cash flow hedges or (ii) hedges of foreign currency exposure of a net investment in a self-sustaining foreign operation, which are recognized in OCI. Derivatives used in trading activities are described in more detail in Note 1(D).

Certain financial instruments can be designated as held for trading (the fair value option) on initial recognition even if the financial instrument was not acquired or incurred principally for the purpose of selling or repurchasing it in the near term. An instrument that is classified as held for trading by way of this fair value option must have reliable fair values and satisfy one of the following criteria: (i) when doing so eliminates or significantly reduces a measurement or recognition inconsistency that would otherwise arise from measuring assets or liabilities, or recognizing gains and losses on them on a different basis or (ii) it belongs to a group of financial assets, financial liabilities, or both that are managed and evaluated on a fair value basis in accordance with TransAlta’s risk management strategy, and are reported to senior management personnel on that basis.

Transaction costs are expensed as incurred for financial instruments classified or designated as held for trading. For other financial instruments, transaction costs are capitalized on initial recognition. The Corporation uses the effective interest method of amortization for any transaction costs or fees, premiums or discounts earned or incurred for financial instruments measured at amortized cost. Financial guarantees that meet the definition of a derivative are measured at fair value and are subsequently re-measured at fair value at each balance sheet date.

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II. Hedges

Where hedge accounting can be applied and the Corporation chooses to seek hedge accounting treatment, a hedge relationship is designated as a fair value hedge, a cash flow hedge, or a hedge of foreign currency exposure of a net investment in a self-sustaining foreign operation. In order to manage the ratio of floating rate versus fixed rate debt, the Corporation uses interest rate swaps as fair value or cash flow hedges. To hedge exposures to anticipated changes in interest rates for forecasted issuances of debt, the Corporation uses interest rate swaps as cash flow hedges. For cash flow hedges, the Corporation primarily uses physical and financial swaps, forward contracts, futures contracts, and options to hedge its exposure to fluctuations in electricity and natural gas prices. The Corporation also uses foreign currency forward contracts as cash flow hedges to hedge the foreign exchange exposures resulting from anticipated transactions and firm commitments denominated in foreign currencies. To hedge exposure to changes in the carrying value of net investments in foreign operations that are a result of changes in foreign exchange rates, the Corporation primarily uses cross-currency interest rate swaps, foreign currency forward contracts, and foreign denominated debt.

To be accounted for as a hedge, a derivative must be designated and documented as a hedge, and must be highly effective at inception and on an ongoing basis. The documentation prepared for the derivative at inception defines all relationships between hedging instruments and hedged items, as well as the Corporation’s risk management objective and strategy for undertaking various hedge transactions. The process of hedge accounting includes linking derivatives to specific assets and liabilities on the Consolidated Balance Sheets or to specific firm commitments or anticipated transactions.

The Corporation also formally assesses, both at the hedge’s inception and on an ongoing basis, whether the derivatives used are highly effective in offsetting changes in fair values or cash flows of hedged items. To be classified as effective, it is reasonable to expect that the Corporation will fulfill its contractual obligations without having to purchase commodities in the market and cash flow exposure does not exist. If the above hedge criteria are not met, the derivative is accounted for on the Consolidated Balance Sheets at fair value, with subsequent changes in fair value recorded in net earnings in the period of change. For those instruments that the Corporation does not seek or are ineligible for hedge accounting, changes in fair value are recorded in net earnings.

a. Fair Value Hedges

In a fair value hedging relationship, the carrying value of the hedged item is adjusted for changes in fair value attributable to the hedged risk and is recognized in net earnings. Changes in the fair value of the hedged item, to the extent that the hedging relationship is effective, are offset by changes in the fair value of the hedging derivative, which is also recorded in net earnings. Hedge effectiveness of fair value hedges is achieved if changes in the fair value of the derivative substantially offset changes in the fair value of the item hedged. When hedge accounting is discontinued, the carrying value of the hedged item is no longer adjusted and the cumulative fair value adjustments to the carrying value of the hedged item are amortized to net earnings over the remaining term of the original hedging relationship.

The Corporation primarily uses interest rate swaps as fair value hedges to manage the ratio of floating rate versus fixed rate debt. Interest rate swaps require the periodic exchange of payments without the exchange of the notional principal amount on which the payments are based. If hedge criteria are met, interest expense on the debt is adjusted to include the payments made or received under the interest rate swaps.

b. Cash Flow Hedges

In a cash flow hedging relationship, the effective portion of the change in the fair value of the hedging derivative is recognized in OCI, while any ineffective portion is recognized in net earnings. Hedge effectiveness of cash flow hedges is achieved if the derivatives’ cash flows substantially offset the cash flows of the hedged item and the timing of the cash flows is similar. When hedge accounting is discontinued, the amounts previously recognized in AOCI are reclassified to net earnings during the periods when the variability in the cash flows of the hedged item affects net earnings. Gains and losses on derivatives are reclassified from OCI immediately to net earnings when it is probable that the forecasted transaction will not occur within the specified time period.

The Corporation primarily uses physical and financial swaps, forward sales contracts, futures contracts, and options as cash flow hedges to hedge the Corporation’s exposure to fluctuations in electricity and natural gas prices. If hedging criteria are met, as described above, gains and losses on these derivatives are recognized in net earnings in the same period and financial statement caption as the hedged exposure. Up to the date of settlement, the fair values of the hedges are recorded in risk management assets or liabilities with changes in value being reported in OCI.

The Corporation also uses foreign currency forward contracts as cash flow hedges to hedge the foreign exchange exposures resulting from anticipated transactions and firm commitments denominated in foreign currencies. If the hedging criteria are met, changes in value are reported in OCI with the fair value being reported in risk management assets or liabilities, as appropriate. Upon settlement of the derivative, any gain or loss on the forward contracts is included in the cost of the asset acquired or liability incurred.

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The Corporation uses forward starting interest rate swaps as cash flow hedges to hedge exposures to anticipated changes in interest rates for forecasted issuances of debt. If the hedging criteria are met, changes in value are reported in OCI with the fair value being reported in risk management assets or liabilities, as appropriate.

c. Foreign Currency Exposure of a Net Investment in a Self-Sustaining Foreign Operation Hedges

In hedging a foreign currency exposure of a net investment in a self-sustaining foreign operation, the effective portion of foreign exchange gains and losses on the hedging instruments is recognized in OCI and the ineffective portion is recognized in net earnings. The amounts previously recognized in AOCI are recognized in net earnings when there is a reduction in the hedged net investment as a result of a dilution or sale of the net investment.

The Corporation primarily uses cross-currency interest rate swaps, foreign currency forward contracts, and foreign denominated debt to hedge exposure to changes in the carrying values of the Corporation’s net investments in self-sustaining foreign operations as a result of changes in foreign exchange rates. Gains and losses on these instruments that qualify for hedge accounting are reported in OCI with fair values recorded in risk management assets or liabilities.

G. Cash and Cash Equivalents

Cash and cash equivalents are comprised of cash and highly liquid investments with original maturities of three months or less.

H. Collateral Paid and Received

The terms and conditions of certain contracts may require the counterparties to provide collateral when the fair value of the obligation pursuant to these contracts is in excess of any credit limits granted. Downgrades in creditworthiness by certain credit rating agencies may decrease the credit limits granted and accordingly increase the amount of collateral that may have to be provided.

I. Inventory

I. Fuel

The majority of fuel and purchased power recorded on the Consolidated Statements of Earnings reflects the cost of inventory consumed in the generation of electricity. All inventory is carried at the lower of cost and net realizable value and cost is determined using the weighted average cost method.

The cost of internally produced coal inventory is determined using absorption costing which is defined as the sum of all applicable expenditures and charges directly incurred in bringing inventory to its existing condition and location. Available coal inventory tends to increase during the second and third quarters as a result of favourable weather conditions and lower production as maintenance is performed. Due to the limited amount of processing steps incurred in mining coal and preparing it for consumption and the relatively low value on a per-unit basis, management does not distinguish between work in process and coal available for consumption.

The cost of natural gas inventory includes all applicable expenditures and charges incurred in bringing inventory to its existing condition and location.

II. Energy Trading

Commodity inventories held in the Energy Trading segment are measured at fair value less costs to sell. Changes in fair value less costs to sell are recognized in net earnings in the period of change.

J. Property, Plant, and Equipment

The Corporation’s investment in property, plant, and equipment (“PP&E”) is stated at original cost at the time of construction, purchase, or acquisition. Original cost includes items such as materials, labour, interest, and other appropriately allocated costs. As costs are expended for new construction, these costs are capitalized as PP&E on the Consolidated Balance Sheets and are subject to depreciation upon commencement of commercial operations. The cost of routine maintenance and repairs, such as inspections and corrosion removal, and the replacement of minor parts, are charged to expense as incurred. Certain expenditures relating to the replacement of components incurred during major maintenance are capitalized and amortized over the estimated benefit period of such expenditures. A component is a tangible portion of the asset that can be separately identified as an asset and depreciated over its own expected useful life, and is expected to provide a benefit of greater than one year.

The estimate of the useful life of PP&E is based on current facts and past experience, and takes into consideration existing long-term sales agreements and contracts, current and forecasted demand, and the potential for technological obsolescence. The useful life is used to estimate the rate at which the PP&E is depreciated or amortized. These estimates are subject to revision in future periods based on new or additional information. Depreciation and amortization are calculated using straight-line and unit-of-production methods. Coal rights are amortized on a unit-of-production basis, based on the estimated mine reserves.

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TransAlta capitalizes interest on capital invested in projects under construction. Upon commencement of commercial operations, capitalized interest, as a portion of the total cost of the plant, is amortized over the estimated useful life of the plant.

On an annual basis, and when indicators of impairment exist, TransAlta determines whether the net carrying amount of PP&E is recoverable from future undiscounted cash flows. Factors that could indicate an impairment exists include significant underperformance relative to historical or projected future operating results, significant changes in the manner or use of the assets, significant negative industry or economic trends, or a change in the strategy for the Corporation’s overall business. In some cases, these events are clear. However, in many cases, a clearly identifiable event indicating possible impairment does not occur. Instead, a series of individually insignificant events occur over a period of time leading to an indication that an asset may be impaired. This can be further complicated where TransAlta is not the operator of the facility. Events can occur in these situations that may not be known until a date subsequent to their occurrence.

The conditions affecting the Corporation, the market, and the business environment are routinely monitored and judgments and assessments are made to determine whether an event has occurred that indicates possible impairment. If such an event has occurred, an estimate is made of future undiscounted cash flows from the PP&E. If the total of the undiscounted future cash flows, excluding financing charges with the exception of plants that have specifically dedicated debt, is less than the carrying amount of the PP&E, an asset impairment must be recognized in the consolidated financial statements. The amount of the impairment charge to be recognized is calculated by subtracting the fair value of the asset from the carrying value of the asset. Fair value is the amount at which an item could be bought or sold in a current transaction between willing parties, and is normally estimated by calculating the present value of expected future cash flows related to the asset.

K. Goodwill

Goodwill is the cost of an acquisition less the fair value of the related identifiable net assets of an acquired business. Goodwill is not subject to amortization, but instead is tested for impairment at least annually, or more frequently if an analysis of events and circumstances indicate that a possible impairment may exist. These events could include a significant change in financial position of the reporting segment to which the goodwill relates or significant negative industry or economic trends. To test for impairment, the fair value of the reporting segments to which the goodwill relates is compared to the carrying values of the reporting segments. The Corporation determined that the fair value of each reporting segment exceeded its carrying values as at Dec. 31, 2010 and 2009.

L. Intangible Assets

Intangible assets consist of power sale contracts, with rates higher than market rates at the date of acquisition, primarily acquired in the purchase of Canadian Hydro Developers, Inc. (“Canadian Hydro”) (Note 24) and CE Generation LLC (“CE Gen”), a jointly controlled enterprise (Note 33). Sale contracts are valued at cost and are amortized on a straight-line basis over the remaining applicable contract period, which ranges from one to 24 years.

M. Project Development Costs

Deferred project development costs include external, direct, and incremental costs that are necessary for completing an acquisition or construction project. These costs are included in operating expenses until construction of a plant or acquisition of an investment is likely to occur, there is reason to believe that future costs are recoverable, and that efforts will result in future value to the Corporation, at which time the future costs are included in PP&E or investments. The appropriateness of the carrying value of these costs is evaluated each reporting period, and unrecoverable amounts of capitalized costs for projects no longer probable of occurring are charged to expense.

N. Income Taxes

The Corporation follows Canadian GAAP for non-regulated entities for all electricity generation operations and as a result, future income taxes have been recorded for all operations.

The Corporation uses the liability method of accounting for income taxes for its operations. Under the liability method, income taxes are recognized for the differences between financial statement carrying values and the respective income tax basis of assets and liabilities (temporary differences), and the carryforward of unused tax losses. Future income tax assets and liabilities are measured using income tax rates expected to apply in the years in which temporary differences are expected to be recovered or settled. The effect on future income tax assets and liabilities of a change in tax rates is included in net earnings in the period the change is substantively enacted. Future income tax assets are evaluated annually and if realization is not considered ‘more likely than not’, a valuation allowance is provided.

TransAlta’s income tax positions are based on research and interpretations of the income tax laws and rulings in each of the jurisdictions in which the Corporation operates. The Corporation’s operations are complex, and the computation and provision for income taxes involves tax interpretations, regulations, and legislation that are continually changing and as such, further appeals and audits by taxation authorities may result. The outcome of some audits may change the tax liability of the Corporation. Management believes it has adequately provided for income taxes based on all information currently available.

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O. Employee Future Benefits

The Corporation accrues its obligations under employee benefit plans and the related costs, net of plan assets. The cost of pensions and other post-employment and post-retirement benefits earned by employees is actuarially determined using the projected benefit method pro-rated on services and management’s best estimate of expected plan investment performance, salary escalation, retirement ages of employees, and expected health care costs. The defined benefit pension plans are based on an employee’s final average earnings and years of service. The expected return on plan assets is based on expected future capital market returns. The discount rate used to calculate the interest cost on the accrued benefit obligation is determined by reference to market interest rates at the balance sheet date on high-quality debt instruments with cash flows that match the timing and amount of expected future benefit payments. As the members of the Canadian Registered Plan are now almost all inactive, the past service costs from plan amendments and the excess of the net cumulative unamortized actuarial gain or loss over 10 per cent of the greater of the accrued benefit obligation and the market value of plan assets are amortized over the Estimated Average Remaining Life. When the restructuring of a benefit plan gives rise to both a curtailment and settlement of obligations, the curtailment is accounted for prior to the settlement. This method has not been applied to the other plans as they did not qualify because the majority of their members are still active. These plans are amortized using Estimated Average Remaining Service Life.

P. Long-Term Debt

Transaction costs are recorded against the carrying value of long-term debt. The Corporation uses the effective interest method to amortize issuance costs and fees associated with long-term debt. A portion of the debt has been hedged using fixed to floating interest rate swaps and therefore the Corporation has included the fair value of these swaps with the value of the debt.

Q. Asset Retirement Obligation (“ARO”)

The Corporation recognizes AROs in the period in which they are incurred if a reasonable estimate of a fair value can be determined. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The ARO liability is accreted over the estimated time period until settlement of the obligation and the asset is depreciated over the estimated useful life of the asset. Reclamation costs for mining assets are recognized on a unit-of-production basis.

TransAlta has recorded an ARO for all generating facilities for which it is legally required to remove the facilities at the end of their useful lives and restore the plant and mine sites to their original condition. For some hydro facilities, the Corporation is required to remove the generating equipment, but is not legally required to remove the structures. TransAlta has recognized legal obligations arising from government legislation, written agreements between entities, and case law. The asset retirement liabilities are recognized when the ARO is incurred. Asset retirement liabilities for coal mines are incurred over time, as new areas are mined, and a portion of the liability is settled over time as areas are reclaimed prior to final pit reclamation.

For active mines, accretion expense is included in fuel and purchased power.

R. Stock-Based Compensation Plans

The Corporation has two types of stock-based compensation plans as described in Note 31. Under the fair value method for stock options, compensation expense is measured at the grant date at fair value and recognized over the service period.

Stock grants under the Performance Share Ownership Plan (“PSOP”) are accrued in Operations, Maintenance, and Administration (“OM&A”) expense as earned to the balance sheet date, based upon the percentile ranking of the total shareholder return of the Corporation’s common shares in comparison to the total shareholder returns of companies comprising the comparator group. Compensation expense under the phantom stock option plan is recognized in OM&A for the amount by which the quoted market price of TransAlta’s shares exceed the option price, and adjusted for changes in each period for changes in the excess over the option price. If stock options or stock are repurchased from employees, the excess of the consideration paid over the carrying amount of the stock option or stock cancelled is charged to retained earnings. Compensation expense is reduced by forfeitures in the period they are incurred.

S. Accounting for Emission Credits and Allowances

Purchased emission allowances are recorded on the Consolidated Balance Sheets at historical cost and are carried at the lower of weighted average cost and net realizable value. Allowances granted to TransAlta or internally generated are recorded at nil. TransAlta records an emission liability on the Consolidated Balance Sheets using the best estimate of the amount required to settle the Corporation’s obligation in excess of government-established caps and targets. To the extent compliance costs are recoverable under the terms of contracts with third parties, these amounts are recognized as revenue in the period of recovery.

Proprietary trading of emissions allowances that meet the definition of a derivative are accounted for using the fair value method of accounting. Allowances that do not satisfy the criteria of a derivative are accounted for using the accrual method.

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T. Planned Maintenance

Planned maintenance is performed at regular intervals and the expenditures include both expense and capital portions. The planned major maintenance includes repairs and maintenance of existing components and the replacement of existing components. Repairs and maintenance of existing components are expensed in the period incurred. Costs of replacing existing components are capitalized in the period of maintenance activities and amortized on a straight-line basis over the life of the asset. Any remaining net book value of the component being replaced is expensed through depreciation. A component is a tangible portion of the asset that can be separately identified as an asset and depreciated over its own expected useful life, and is expected to provide a benefit of greater than one year.

U. Business Combinations

Acquisitions are recorded using the purchase method of accounting in accordance with Handbook Section 1581, Business Combinations, with the results of operations included in these consolidated financial statements from the date of acquisition (Note 24). The purchase price has been allocated to assets acquired and liabilities assumed at the date of acquisition. The amounts assigned to the net assets acquired have given rise to future income tax liabilities that have been recorded as part of the purchase price allocation. The excess of the purchase price over the fair values assigned to the identifiable net assets acquired has been recorded as goodwill.

2. Accounting Changes

A. Comparative Figures

Certain comparative figures have been reclassified to conform to the current year’s presentation. These reclassifications did not impact previously reported net earnings or retained earnings.

B. Current Year Accounting Changes

I. Inventory

During the second quarter of 2010, the Corporation modified its inventory measurement policy for commodity inventories held in its Energy Trading business segment to better reflect the nature of the underlying inventory and the segment’s business objectives. Commodity inventories held in the Energy Trading segment are now measured at fair value less costs to sell, as opposed to the lower of cost and net realizable value. Changes in fair value less costs to sell are recognized in net earnings in the period of change. The effect of this change on current and prior periods was not material. Accordingly, the change has been applied prospectively and prior periods have not been restated.

II. Change in Estimate - Useful Lives

In 2010, management initiated a comprehensive review of the estimated useful lives of all generating facilities and coal mining assets, having regard for, among other things, TransAlta’s economic lifecycle maintenance program, the existing condition of the assets, progress on carbon capture and other technologies, as well as other market-related factors.

Management concluded its review of the coal fleet, as well as its mining assets, and updated the estimated useful lives of these assets to reflect their current expected economic lives. As a result, depreciation was reduced by $26 million for the year ended Dec. 31, 2010 compared to the same period in 2009.

Any other adjustments resulting from the review of the balance of the fleet will be reflected in future periods.

C. Prior Year Accounting Changes

I. Financial Instruments - Disclosures

On Oct. 1, 2009, the Corporation adopted amendments to Section 3862, Financial Instruments - Disclosures, to converge with Improving Disclosures about Financial Instruments (Amendments to IFRS 7). The amendments expand the disclosures required in respect of recognized fair value measurements and clarify existing principles for disclosures about the liquidity risk associated with financial instruments. The implementation of this standard did not have an impact upon the consolidated financial statements as the disclosure requirements are already provided as part of the Corporation’s existing financial instrument disclosures.

II. Financial Instruments - Recognition and Measurement

On July 29, 2009, the Corporation retrospectively adopted, to Jan. 1, 2009, Impairment of Financial Assets, amending Section 3855, Financial Instruments - Recognition and Measurement. The amendments changed the categories into which debt instruments could be classified and the impairment requirements for certain financial assets. Consequential amendments to Section 3025, Impaired Loans, were made to incorporate these changes. The implementation of this standard did not have an impact upon the consolidated financial statements.

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On July 1, 2009, the Corporation adopted Embedded Derivatives on Reclassification of Financial Assets, amending Section 3855, Financial Instruments - Recognition and Measurement. The amendment indicates that contracts with embedded derivatives cannot be reclassified out of the held for trading category if the embedded derivative cannot be fair valued. The implementation of this standard did not have an impact upon the consolidated financial statements.

III. Credit Risk

On Jan. 1, 2009, the Corporation adopted the Emerging Issues Committee (“EIC”) Abstract 173, Credit Risk and the Fair Value of Financial Assets and Financial Liabilities. Under EIC-173, an entity’s own credit risk and the credit risk of the counterparty should be taken into account in determining the fair value of financial assets and liabilities, including derivative instruments. Disclosure required as a result of adopting this standard can be found in Note 8.

IV. Deferral of Costs and Internally Developed Intangibles

On Jan. 1, 2009, the Corporation adopted Handbook Section 3064, Goodwill and Intangible Assets, replacing Section 3062, Goodwill and Other Intangible Assets, and Section 3450, Research and Development Costs. Section 3064 further defines that an internally developed intangible asset must demonstrate technical feasibility, an intention for use or sale, the generation of future economic benefits, and adequate access to resources to complete the development of the intangible asset in order to be able to capitalize associated costs. The implementation of this standard did not have an impact upon the consolidated financial statements.

V. Mining Exploration Costs

On Jan. 1, 2009, the Corporation adopted EIC-174, Mining Exploration Costs. EIC-174 provides guidance on the capitalization of mining exploration costs, particularly when mining reserves have not been proven. The EIC also defines when an impairment test should be performed on previously capitalized costs. The implementation of this standard did not have an impact upon the consolidated financial statements.

D. Future Accounting Changes

I. International Financial Reporting Standards (“IFRS”) Convergence

On Jan. 1, 2011, the Corporation adopted IFRS for publicly accountable enterprises as required by the Accounting Standards Board of Canada.

While IFRS uses a conceptual framework similar to Canadian GAAP, there are several significant differences in accounting policies that have been addressed as part of the convergence project. In respect of PP&E, additional disclosures reconciling the changes in individual classes of PP&E and accumulated amortization are required, and costs related to major inspection activities are recognized as part of the carrying value of PP&E and depreciated over the period until the next major inspection. For employee future benefits, the Corporation recognizes all experience and transitional gains and losses to retained earnings with subsequent experience gains and losses being recorded in OCI. Long-term contracts deemed to be finance leases resulted in the associated PP&E being removed from the Consolidated Balance Sheets and the recognition of a long-term receivable, representing the present value of lease payments to be received over the life of the contract. A portion of the payments received under the contract are recognized as a reduction of the finance lease receivable and a portion is recognized as interest income, the amount which will vary dependent upon the interest rate and duration of the contract. Provisions for asset retirement obligations are revalued at the end of each quarterly and annual reporting period using current-market based interest rates instead of remaining at historic rates. The related accretion expense is classified as finance (interest) cost under IFRS. Asset impairment testing no longer utilizes undiscounted cash future cash flows to initially assess for impairment. Instead, when an indicator of impairment exists, an asset’s carrying amount is compared to the greater of its value in use or fair value less costs to sell. IFRS also requires asset impairment charges to be reversed in subsequent periods if the initial indicator of impairment has reversed.

A steering committee, comprised of senior representatives across the Corporation, continues to monitor the progress of the transition to IFRS and will continue to meet regularly until the first interim report under IFRS is completed in 2011. Quarterly updates are provided to the Audit and Risk Committee.

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3. Asset Impairment Charges

During the fourth quarter of 2010, the Corporation completed its annual comprehensive impairment assessment based on fair value estimates derived from the long-range forecast and market values evidenced in the marketplace. As a result, the Corporation recorded a pre-tax impairment charge of $89 million ($79 million after deducting the amount that is attributable to the non-controlling interest) on certain Generation assets, comprised of a $65 million charge against the natural gas fleet and a $24 million charge against the coal fleet. The natural gas fleet impairment reflects lower forecast pricing at one of the Corporation’s merchant facilities and the pending sale of the Corporation’s 50 per cent interest in the Meridian facility, which had no impact to consolidated earnings as the impairment was attributable to the non-controlling interest. The coal fleet impairment relates to Units 1 and 2 at the Sundance facility and primarily reflects the Corporation’s shift in 2010 to managing the coal-fired generation facilities on a unit pair basis, resulting in the impairment assessment now being performed on a unit pair basis.

In 2006, TransAlta ceased mining activities at the Centralia mine but continued to develop the option to mine the Westfield site, a coal reserve located adjacent to Centralia Thermal. With the successful modifications of the boilers at Centralia Thermal and longer-term contracts in place to supply coal, the project to develop the Westfield site was placed on hold indefinitely in 2009, and the costs that had been capitalized were expensed.

4. Other Income

During 2010, the 54 megawatt (“MW”) expansion of the Kent Hills wind farm began commercial operations on budget and ahead of schedule. The total cost of the project is approximately $100 million. Natural Forces Technologies, Inc. (“Natural Forces”) exercised their option to purchase a 17 per cent interest in the Kent Hills expansion project subsequent to the commencement of commercial operations for proceeds of $15 million based on costs incurred in 2010, and an additional $2 million of proceeds related to costs expected in 2011. The pre-tax gain recorded related to this transaction did not have a significant impact on net earnings.

During 2009, the Corporation sold a 17 per cent interest in its initial Kent Hills project to Natural Forces for proceeds of $29 million, and recorded a pre-tax gain of $1 million. The Corporation also settled an outstanding commercial issue related to the sale of its Mexican equity investment for a pre-tax gain of $7 million.

During 2008, mining equipment with a net book value of $2 million related to the cessation of mining activities at the Centralia coal mine was sold for proceeds of $7 million.

5. Non-Controlling Interests

A. Consolidated Statements of Earnings

Year ended Dec. 31 |  | 2010 |  | 2009 |  | 2008 |
Stanley Power’s interest in TransAlta Cogeneration, L.P. (Note 33) |  | 19 |  | 23 |  | 32 |
25 per cent interest in Saranac Partnership not owned by CE Gen |  | - |  | 14 |  | 29 |
Natural Forces’ interest in Kent Hills (Note 4) |  | 1 |  | 1 |  | - |
Total |  | 20 |  | 38 |  | 61 |

B. Consolidated Balance Sheets

As at Dec. 31 |  | 2010 |  | 2009 |
Stanley Power’s interest in TransAlta Cogeneration, L.P. |  | 393 |  | 434 |
25 per cent interest in Saranac Partnership not owned by CE Gen |  | 15 |  | 16 |
Natural Forces’ interest in Kent Hills |  | 43 |  | 28 |
Non-controlling interests portion of OCI |  | (16 | ) | - |
Total |  | 435 |  | 478 |

The change in non-controlling interests is provided below:

Balance, Dec. 31, 2009 |  | 478 |
Distributions paid |  | (62 | )
Non-controlling interests portion of net earnings, including asset impairment (Note 3) |  | 20 |
Non-controlling interests portion of OCI |  | (16 | )
Acquisition of minority interest in Kent Hills (Note 4) |  | 15 |
As at Dec. 31, 2010 |  | 435 |

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C. Consolidated Statements of Cash Flows

Distributions paid by subsidiaries to non-controlling interests are as follows:

Year ended Dec. 31 |  | 2010 |  | 2009 |  | 2008 |
TransAlta Cogeneration, L.P. |  | 60 |  | 38 |  | 59 |
Saranac |  | - |  | 18 |  | 39 |
Kent Hills |  | 2 |  | 2 |  | - |
Total |  | 62 |  | 58 |  | 98 |

6. Income Taxes

A. Consolidated Statements of Earnings

I. Rate Reconciliations

Year ended Dec. 31 |  | 2010 |  | 2009 |  | 2008 |
Earnings before income taxes |  | 220 |  | 196 |  | 258 |
Equity loss |  | - |  | - |  | (97 | )
Earnings before income taxes and equity loss |  | 220 |  | 196 |  | 355 |
Statutory Canadian federal and provincial income tax rate (%) |  | 28 |  | 29 |  | 30 |
Expected income tax expense |  | 62 |  | 57 |  | 105 |
(Decrease) increase in income taxes resulting from: |  |  |  |  |  |  |
Lower effective foreign tax rates |  | (26 | ) | (29 | ) | (24 | )
Resolution of uncertain tax matters |  | (30 | ) | - |  | (15 | )
Tax recovery on sale of Mexican equity investment (Note 24) |  | - |  | - |  | (35 | )
Effect of tax rate changes |  | - |  | (6 | ) | - |
Statutory and other rate differences |  | (10 | ) | (4 | ) | (7 | )
Other |  | 5 |  | (3 | ) | (1 | )
Income tax expense |  | 1 |  | 15 |  | 23 |
Effective tax rate (%) |  | 1 |  | 8 |  | 6 |

II. Components of Income Tax Expense

The components of income tax expense (recovery) are as follows:

Year ended Dec. 31 |  | 2010 |  | 2009 |  | 2008 |
Current tax (recovery) expense |  | (27 | ) | (6 | ) | 22 |
Future income tax expense related to the origination and reversal of temporary differences |  | 28 |  | 27 |  | 1 |
Future income tax recovery resulting from changes in tax rates or laws |  | - |  | (6 | ) | - |
Income tax expense |  | 1 |  | 15 |  | 23 |

During 2010, TransAlta recognized a $30 million income tax recovery related to the resolution of certain outstanding tax matters, which was received in 2010. Interest expense also decreased by $14 million as a result of tax-related interest recoveries.

B. Consolidated Balance Sheets

Significant components of the Corporation’s future income tax assets (liabilities) are as follows:

As at Dec. 31 |  | 2010 |  | 2009 |
Net operating and capital loss carryforwards |  | 382 |  | 297 |
Future site restoration costs |  | 86 |  | 75 |
Property, plant, and equipment |  | (886 | ) | (839 | )
Risk management assets and liabilities, net |  | (113 | ) | (82 | )
Employee future benefits and compensation plans |  | 14 |  | 19 |
Allowance for doubtful accounts |  | 18 |  | 19 |
Other deductible temporary differences |  | 32 |  | 38 |
Net future income tax liability |  | (467 | ) | (473 | )

Presented in the Consolidated Balance Sheets as follows:

As at Dec. 31 |  | 2010 |  | 2009 |
Assets |  |  |  |  |
Long-term |  | 240 |  | 234 |
Liabilities |  |  |  |  |
Current |  | (77 | ) | (45 | )
Long-term |  | (630 | ) | (662 | )
Net future income tax liability |  | (467 | ) | (473 | )

18 |  | T r a n s A l t a C o r p o r a t i o n

7. Financial Instruments

A. Financial Assets and Liabilities – Classification and Measurement

Financial assets and financial liabilities are measured on an ongoing basis at cost, fair value, or amortized cost (Note 1(F)). The following table highlights the carrying amounts and classifications of the financial assets and liabilities:

Carrying value of financial instruments as at Dec. 31, 2010

|  | Derivatives used for hedging |  | Derivatives classified as held for trading |  | Loans and receivables |  | Other financial liabilities |  | Total |
Financial assets |  |  |  |  |  |  |  |  |  |  |
Cash and cash equivalents |  | - |  | - |  | 58 |  | - |  | 58 |
Accounts receivable |  | - |  | - |  | 428 |  | - |  | 428 |
Collateral paid |  | - |  | - |  | 27 |  | - |  | 27 |
Risk management assets |  |  |  |  |  |  |  |  |  |  |
Current |  | 186 |  | 79 |  | - |  | - |  | 265 |
Long-term |  | 204 |  | 4 |  | - |  | - |  | 208 |
Financial liabilities |  |  |  |  |  |  |  |  |  |  |
Short-term debt |  | - |  | - |  | - |  | 1 |  | 1 |
Accounts payable and accrued liabilities |  | - |  | - |  | - |  | 503 |  | 503 |
Collateral received |  | - |  | - |  | - |  | 126 |  | 126 |
Dividends payable |  |  |  |  |  |  |  | 130 |  | 130 |
Risk management liabilities |  |  |  |  |  |  |  |  |  |  |
Current |  | 5 |  | 30 |  | - |  | - |  | 35 |
Long-term |  | 123 |  | - |  | - |  | - |  | 123 |
Long-term debt recourse 1 |  | - |  | - |  | - |  | 3,685 |  | 3,685 |
Long-term debt non-recourse 1 |  | - |  | - |  | - |  | 549 |  | 549 |

Carrying value of financial instruments as at Dec. 31, 2009

|  | Derivatives used for hedging |  | Derivatives classified as held for trading |  | Loans and receivables |  | Other financial liabilities |  | Total |
Financial assets |  |  |  |  |  |  |  |  |  |  |
Cash and cash equivalents |  | - |  | - |  | 82 |  | - |  | 82 |
Accounts receivable |  | - |  | - |  | 421 |  | - |  | 421 |
Collateral paid |  | - |  | - |  | 27 |  | - |  | 27 |
Risk management assets |  |  |  |  |  |  |  |  |  |  |
Current |  | 130 |  | 14 |  | - |  | - |  | 144 |
Long-term |  | 219 |  | 5 |  | - |  | - |  | 224 |
Long-term receivable |  |  |  |  |  | 49 |  |  |  | 49 |
Financial liabilities |  |  |  |  |  |  |  |  |  |  |
Accounts payable and accrued liabilities |  | - |  | - |  | - |  | 521 |  | 521 |
Collateral received |  | - |  | - |  | - |  | 86 |  | 86 |
Dividends payable |  | - |  | - |  | - |  | 61 |  | 61 |
Risk management liabilities |  |  |  |  |  |  |  |  |  |  |
Current |  | 28 |  | 17 |  | - |  | - |  | 45 |
Long-term |  | 75 |  | 3 |  | - |  | - |  | 78 |
Long-term debt recourse 1 |  | - |  | - |  | - |  | 3,864 |  | 3,864 |
Long-term debt non-recourse 1 |  | - |  | - |  | - |  | 578 |  | 578 |

1 Includes current portion. |  |  |  |  |  |  |  |  |  |  |

N o t e s to C o n s o l i d a t e d F i n a n c i a l S t a t e m e n t s | 19

B. Fair Value of Financial Instruments

The fair value of a financial instrument is the amount of consideration that would be agreed upon in an arm’s-length transaction between knowledgeable and willing parties who are under no compulsion to act. Fair values can be determined by reference to prices for that instrument in active markets to which the Corporation has access. In the absence of an active market, the Corporation determines fair values based on valuation models or by reference to other similar products in active markets.

Fair values determined using valuation models require the use of assumptions. In determining those assumptions, the Corporation looks primarily to external readily observable market inputs. In limited circumstances, the Corporation uses inputs that are not based on observable market data.

Level Determinations and Classifications

The Level I, II, and III classifications in the fair value hierarchy utilized by the Corporation are defined below:

Level I

Fair values are determined using inputs that are quoted prices (unadjusted) in active markets for identical assets or liabilities that the Corporation has the ability to access. In determining Level I fair values, the Corporation uses quoted prices for identically traded commodities obtained from active exchanges such as the New York Mercantile Exchange.

Level II

Fair values are determined using inputs other than unadjusted quoted prices that are observable for the asset or liability, either directly or indirectly.

Fair values falling within the Level II category are determined through the use of quoted prices in active markets adjusted for factors specific to the asset or liability, such as basis and location differentials. The Corporation includes over-the-counter derivatives with values based upon observable commodity futures curves and derivatives with input validated by broker quotes or other publicly available market data providers. Level II fair values are also determined using valuation techniques, such as option pricing models and regression or extrapolation formulas, where the inputs are readily observable, including commodity prices for similar assets or liabilities in active markets, and implied volatilities for options.

In determining Level II fair values of other risk management assets and liabilities, the Corporation uses observable inputs other than unadjusted quoted prices that are observable for the asset or liability, such as interest rate yield curves and currency rates. For certain financial instruments where insufficient trading volume or lack of recent trades exists, the Corporation relies on similar interest or currency rate inputs and other third-party information such as credit spreads.

Level III

Fair values are determined using inputs for the asset or liability that are not readily observable.

In limited circumstances, the Corporation may enter into commodity transactions involving non-standard features for which market-observable data is not available. In these cases, Level III fair values are determined using valuation techniques with inputs that are based on historical data such as unit availability, transmission congestion, demand profiles for individual non-standard deals and structured products, and/or volatilities and correlations between products derived from historical prices. Where commodity transactions extend into periods for which market-observable prices are not available, an internally developed fundamental price forecast is used in the valuation.

As a result of the acquisition of Canadian Hydro, TransAlta also has various contracts with terms that extend beyond five years. As forward price forecasts are not available for the full period of these contracts, the value of these contracts is derived by reference to a forecast that is based on a combination of external and internal fundamental modelling, including discounting. As a result, these contracts are classified in Level III. These contracts are for a specified price with creditworthy counterparties.

The fair value measurement of a financial instrument is included in only one of the three levels, the determination of which is based upon the lowest level input that is significant to the derivation of the fair value.

20 | T r a n s A l t a C o r p o r a t i o n

Energy Trading

Energy trading includes risk management assets and liabilities that are used in the Energy Trading and Generation segments in relation to trading activities and certain contracting activities.

The following table summarizes the key factors impacting the fair value of the energy trading risk management assets and liabilities by classification level during the year ended Dec. 31, 2010:

|  | Hedges |  | Non-hedges |  | Total |
|  | Level I |  | Level II |  | Level III |  | Level I |  | Level II |  | Level III |  | Level I |  | Level II |  | Level III |
Net risk management assets (liabilities) at Dec. 31, 2009 |  | - |  | 297 |  | (27 | ) | - |  | - |  | 1 |  | - |  | 297 |  | (26 | )
Changes attributable to: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Market price changes on existing contracts |  | - |  | 146 |  | 11 |  | - |  | (5 | ) | 2 |  | - |  | 141 |  | 13 |
Market price changes on new contracts |  | - |  | 30 |  | - |  | (1 | ) | 10 |  | (2 | ) | (1 | ) | 40 |  | (2 | )
Contracts settled |  | - |  | (108 | ) | (4 | ) | - |  | 2 |  | (1 | ) | - |  | (106 | ) | (5 | )
Discontinued hedge accounting on certain contracts |  | - |  | (46 | ) | - |  | - |  | 46 |  | - |  | - |  | - |  | - |
Net risk management assets (liabilities) at Dec. 31, 2010 |  | - |  | 319 |  | (20 | ) | (1 | ) | 53 |  | - |  | (1 | ) | 372 |  | (20 | )
Additional Level III gain (loss) information: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Change in fair value included in OCI |  |  |  |  |  | 7 |  |  |  |  |  | (1 | ) |  |  |  |  | 6 |
Realized gain included in earnings before income taxes |  |  |  |  |  | 4 |  |  |  |  |  | 1 |  |  |  |  |  | 5 |

To the extent applicable, changes in net risk management assets and liabilities for non-hedge positions are reflected within the gross margin of the Energy Trading and Generation business segments.

The effect of using reasonable possible alternative assumptions as inputs to valuation techniques from which the Level III energy trading fair values are determined at Dec. 31, 2010 is estimated to be +/- $14 million (2009 - $24 million). Where an internally developed fundamental price forecast is used, reasonable alternate fundamental price forecasts sourced from external consultants are included in the estimate. In limited circumstances, certain contracts have terms extending beyond five years that require valuations to be extrapolated as the lengths of these contracts make reasonable alternate fundamental price forecasts unavailable.

The total change in Level III financial assets and liabilities held at Dec. 31, 2010 that was recognized in pre-tax earnings for the year ended Dec. 31, 2010 was a $5 million gain (2009 - $1 million).

The anticipated settlement of the above contracts over each of the next five calendar years and thereafter is as follows:

|  |  |  |  |  |  |  |  |  |  |  |  |  | 2016 and |  |  |
|  |  |  | 2011 |  | 2012 |  | 2013 |  | 2014 |  | 2015 |  | thereafter |  | Total |
Hedges |  | Level I |  | - |  | - |  | - |  | - |  | - |  | - |  | - |
|  | Level II |  | 182 |  | 138 |  | 22 |  | (4 | ) | (9 | ) | (10 | ) | 319 |
|  | Level III |  | 1 |  | 1 |  | - |  | - |  | - |  | (22 | ) | (20 | )
Non-hedges |  | Level I |  | (1 | ) | (1 | ) | 1 |  | - |  | - |  | - |  | (1 | )
|  | Level II |  | 47 |  | 1 |  | 5 |  | - |  | - |  | - |  | 53 |
|  | Level III |  | 1 |  | - |  | - |  | (1 | ) | - |  | - |  | - |
Total by level |  | Level I |  | (1 | ) | (1 | ) | 1 |  | - |  | - |  | - |  | (1 | )
|  | Level II |  | 229 |  | 139 |  | 27 |  | (4 | ) | (9 | ) | (10 | ) | 372 |
|  | Level III |  | 2 |  | 1 |  | - |  | (1 | ) | - |  | (22 | ) | (20 | )
Total net assets (liabilities) |  | 230 |  | 139 |  | 28 |  | (5 | ) | (9 | ) | (32 | ) | 351 |

Other Risk Management Assets and Liabilities

Other risk management assets and liabilities include risk management assets and liabilities that are used in hedging non-energy trading transactions, such as debt, and the net investment in self-sustaining foreign subsidiaries.

N o t e s t o C o n s o l i d a t e d F i n a n c i a l S t a t e m e n t s | 21

The following table summarizes the key factors impacting the fair value of the other risk management assets and liabilities by classification level during the year ended Dec. 31, 2010:

|  | Hedges |  | Non-hedges |  | Total |
|  | Level I |  | Level II |  | Level III |  | Level I |  | Level II |  | Level III |  | Level I |  | Level II |  | Level III |
Net risk management liabilities at Dec. 31, 2009 |  | - |  | (24 | ) | - |  | - |  | (2 | ) | - |  | - |  | (26 | ) | - |
Changes attributable to: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Market price changes on existing contracts |  | - |  | (9 | ) | - |  | - |  | 2 |  | - |  | - |  | (7 | ) | - |
Market price changes on new contracts |  | - |  | (25 | ) | - |  | - |  | - |  | - |  | - |  | (25 | ) | - |
Contracts settled |  | - |  | 21 |  | - |  | - |  | 1 |  | - |  | - |  | 22 |  | - |
Net risk management (liabilities) assets at Dec. 31, 2010 |  | - |  | (37 | ) | - |  | - |  | 1 |  | - |  | - |  | (36 | ) | - |

Changes in other risk management assets and liabilities related to hedge positions are reflected within net earnings when such transactions have settled during the period or when ineffectiveness exists in the hedging relationship. For hedges that remain effective and qualify for hedge accounting, any change in value will be deferred in AOCI until the instrument is settled, or until such time as the hedged item affects net earnings, or there is a reduction in the net investment in the foreign operations.

The anticipated settlement of the above contracts over each of the next five calendar years and thereafter is as follows:

|  |  |  |  |  |  |  |  |  |  |  |  |  | 2016 and |  |  |
|  |  |  | 2011 |  | 2012 |  | 2013 |  | 2014 |  | 2015 |  | thereafter |  | Total |
Hedges |  | Level I |  | - |  | - |  | - |  | - |  | - |  | - |  | - |
|  | Level II |  | (1 | ) | (9 | ) | (6 | ) | (2 | ) | (32 | ) | 13 |  | (37 | )
|  | Level III |  | - |  | - |  | - |  | - |  | - |  | - |  | - |
Non-hedges |  | Level I |  | - |  | - |  | - |  | - |  | - |  | - |  | - |
|  | Level II |  | 1 |  | - |  | - |  | - |  | - |  | - |  | 1 |
|  | Level III |  | - |  | - |  | - |  | - |  | - |  | - |  | - |
Total by level |  | Level I |  | - |  | - |  | - |  | - |  | - |  | - |  | - |
|  | Level II |  | - |  | (9 | ) | (6 | ) | (2 | ) | (32 | ) | 13 |  | (36 | )
|  | Level III |  | - |  | - |  | - |  | - |  | - |  | - |  | - |
Total net (liabilities) assets |  | - |  | (9 | ) | (6 | ) | (2 | ) | (32 | ) | 13 |  | (36 | )

|  | Fair value 1 |  | Total |
|  | Level I |  | Level II |  | Level III |  | Total |  | carrying value |
Financial assets and liabilities measured at other than fair value |  |  |  |  |  |  |  |  |  |  |
Long-term debt - Dec. 31, 2010 2 |  | - |  | 4,460 |  | - |  | 4,460 |  | 4,234 |
Long-term debt - Dec. 31, 2009 2 |  | - |  | 4,499 |  | - |  | 4,499 |  | 4,442 |

1 Excludes financial assets and liabilities where book value approximates fair value due to the liquid nature of the asset or liability (cash and cash equivalents, accounts receivable, collateral paid, long-term receivable, short-term debt, accounts payable and accrued liabilities, collateral received, and dividends payable).

2 Includes current portion.

C. Inception Gains and Losses

The majority of derivatives traded by the Corporation are not traded on an active exchange or extend beyond the time period for which exchange-based quotes are available. The fair values of these derivatives have been determined using valuation techniques or models.

In some instances, a difference may arise between the fair value of a financial instrument at initial recognition (the “transaction price”) and the amount calculated through a valuation model. This unrealized gain or loss at inception is recognized in net earnings only if the fair value of the instrument is evidenced by a quoted market price in an active market, observable current market transactions that are substantially the same, or a valuation technique that uses observable market inputs. Where these criteria are not met, the difference is deferred on the Consolidated Balance Sheets in risk management assets or liabilities, and is recognized in net earnings over the term of the related contract. The difference between the transaction price and the valuation model yet to be recognized in net earnings and a reconciliation of changes during the year is as follows:

As at Dec. 31 |  | 2010 |  | 2009 |  | 2008 |
Unamortized (loss) gain at beginning of year |  | (1 | ) | 2 |  | 3 |
New inception gains (losses) |  | 3 |  | (1 | ) | 1 |
Amortization recorded in net earnings during the year |  | (1 | ) | (2 | ) | (2 | )
Unamortized gain (loss) at end of year |  | 1 |  | (1 | ) | 2 |

22 | T r a n s A l t a C o r p o r a t i o n

8. Risk Management Activities

A. Risk Management Assets and Liabilities

Aggregate risk management assets and liabilities are as follows:

As at Dec. 31 |  |  |  |  |  | 2010 |  |  |  |  |  | 2009 |
|  | Net |  |  |  |  |  | Not |  |  |  |  |
|  | investment |  | Cash flow |  | Fair value |  | designated |  |  |  |  |
|  | hedges |  | hedges |  | hedges |  | as a hedge |  | Total |  | Total |
Risk management assets |  |  |  |  |  |  |  |  |  |  |  |  |
Energy trading |  |  |  |  |  |  |  |  |  |  |  |  |
Current |  | - |  | 183 |  | - |  | 78 |  | 261 |  | 144 |
Long-term |  | - |  | 185 |  | - |  | 4 |  | 189 |  | 207 |
Total energy trading risk management assets |  | - |  | 368 |  | - |  | 82 |  | 450 |  | 351 |
Other |  |  |  |  |  |  |  |  |  |  |  |  |
Current |  | 1 |  | - |  | 2 |  | 1 |  | 4 |  | - |
Long-term |  | - |  | - |  | 19 |  | - |  | 19 |  | 17 |
Total other risk management assets |  | 1 |  | - |  | 21 |  | 1 |  | 23 |  | 17 |
Risk management liabilities |  |  |  |  |  |  |  |  |  |  |  |  |
Energy trading |  |  |  |  |  |  |  |  |  |  |  |  |
Current |  | - |  | - |  | - |  | 30 |  | 30 |  | 30 |
Long-term |  | - |  | 69 |  | - |  | - |  | 69 |  | 50 |
Total energy trading risk management liabilities |  | - |  | 69 |  | - |  | 30 |  | 99 |  | 80 |
Other |  |  |  |  |  |  |  |  |  |  |  |  |
Current |  | 5 |  | - |  | - |  | - |  | 5 |  | 15 |
Long-term |  | - |  | 54 |  | - |  | - |  | 54 |  | 28 |
Total other risk management liabilities |  | 5 |  | 54 |  | - |  | - |  | 59 |  | 43 |
Net energy trading risk management assets |  | - |  | 299 |  | - |  | 52 |  | 351 |  | 271 |
Net other risk management (liabilities) assets |  | (4 | ) | (54 | ) | 21 |  | 1 |  | (36 | ) | (26 | )
Net total risk management (liabilities) assets |  | (4 | ) | 245 |  | 21 |  | 53 |  | 315 |  | 245 |

Additional information on derivative instruments has been presented on a net basis below.

I. Hedges

a. Net Investment Hedges

i. Hedges of Foreign Operations

U.S. dollar denominated long-term debt with a face value of U.S.$820 million (2009 - U.S.$1,100 million), and borrowings under a U.S. dollar denominated credit facility with a face value of U.S.$300 million (2009 - U.S.$300 million) have been designated as a part of the hedge of TransAlta’s net investment in self-sustaining foreign operations.

The Corporation has also hedged a portion of its net investment in self-sustaining foreign operations with cross-currency interest rate swaps and foreign currency forward sales (purchase) contracts as shown below:

Cross-Currency Interest Rate Swap

Outstanding liability resulting from cross-currency interest rate swap used as part of the net investment hedge is as follows:

As at Dec. 31 |  | 2010 |  |  |  |  |  | 2009 |  |  |
Notional amount |  | Fair value liability |  | Maturity |  | Notional amount |  | Fair value liability |  | Maturity |
- |  | - |  | - |  | AUD34 |  | (2 | ) | 2010 |

Foreign Currency Contracts

Outstanding foreign currency forward sale (purchase) contracts used as part of the net investment hedge are as follows:

As at Dec. 31 |  | 2010 |  |  |  |  |  | 2009 |  |  |
Notional amount |  | Fair value liability |  | Maturity |  | Notional amount |  | Fair value liability |  | Maturity |
AUD180 |  | (1 | ) | 2011 |  | AUD120 |  | (2 | ) | 2010 |
U.S.(41) |  | (3 | ) | 2011 |  | U.S.(182 | ) | (1 | ) | 2010 |

N o t e s t o C o n s o l i d a t e d F i n a n c i a l S t a t e m e n t s | 23

ii. Effect on the Consolidated Statements of Comprehensive Income

For the year ended Dec. 31, 2010, a net after-tax loss of $27 million (2009 - loss of $69 million, 2008 - gain of $47 million), relating to the translation of the Corporation’s net investment in self-sustaining foreign operations, net of hedging, was recognized in OCI.

All net investment hedges currently have no ineffective portion. The following tables summarize the pre-tax impact of net investment hedges on the Consolidated Statements of Comprehensive Income:

Financial instruments |  | Pre-tax gain (loss) |  |  |  |  |
in net investment |  | recognized in OCI for the |  | Location of gain |  | Pre-tax gain |
hedging relationships |  | year ended Dec. 31, 2010 |  | reclassified from OCI |  | reclassified from OCI |
Long-term debt |  | 68 |  | Foreign exchange |  | (5 | )
Foreign exchange |  | (29 | ) |  |  |  |
OCI impact |  | 39 |  | OCI impact |  | (5 | )

Financial instruments |  | Pre-tax gain (loss) |  | Pre-tax loss |
in net investment |  | recognized in OCI for the |  | recognized in OCI for the |
hedging relationships |  | year ended Dec. 31, 2009 |  | year ended Dec. 31, 2008 |
Long-term debt |  | 233 |  | (257 | )
Cross currency |  | (3 | ) | (62 | )
Foreign exchange |  | (64 | ) | (37 | )
OCI impact |  | 166 |  | (356 | )

b. Cash Flow Hedges

i. Energy Trading Risk Management

The Corporation’s outstanding energy trading derivative instruments designated as hedging instruments at Dec. 31, 2010, were as follows:

(Thousands) |  | Dec. 31, 2010 |  | Dec. 31, 2009 |
|  | Notional amount |  | Notional amount |  | Notional amount |  | Notional amount |
Type |  | sold |  | purchased |  | sold |  | purchased |
Electricity (MWh) |  | 28,814 |  | 10 |  | 28,989 |  | - |
Natural gas (GJ) |  | 1,925 |  | 32,751 |  | 2,163 |  | 360 |
Oil (gallons) |  | - |  | 12,432 |  | - |  | 25,074 |

During the fourth quarter of 2010, unrealized pre-tax gains of $13 million were recognized in earnings due to certain power hedging relationships being deemed ineffective for accounting purposes. These unrealized gains were calculated using current forward prices that will change between now and the time the underlying hedged transactions were expected to occur. Had these hedges not been deemed ineffective for accounting purposes, the revenues associated with these contracts would have been recorded in the period that they settle, the majority of which will occur during the second quarter of 2011. While future reported earnings will be lower, the expected cash flows from these contracts will not change.

ii. Foreign Currency Rate Risk Management

Foreign Exchange Forward Contracts on Foreign Denominated Receipts and Expenditures

The Corporation uses forward foreign exchange contracts to hedge a portion of its future foreign denominated receipts and expenditures as follows:

As at Dec. 31 |  | 2010 |  |  |  |  |  | 2009 |  |  |
Notional |  | Notional |  |  |  |  |  | Notional |  | Notional |  |  |  |  |
amount |  | amount |  | Fair value |  |  |  | amount |  | amount |  | Fair value |  |  |
sold |  | purchased |  | liability |  | Maturity |  | sold |  | purchased |  | liability |  | Maturity |
217 |  | U.S.200 |  | (12 | ) | 2011-2017 |  | 91 |  | U.S.78 |  | (8 | ) | 2010 |
U.S.8 |  | 8 |  | - |  | 2011 |  | U.S.14 |  | 15 |  | - |  | 2010 |
- |  | - |  | - |  | - |  | AUD4 |  | U.S.3 |  | - |  | 2010 |

24 | T r a n s A l t a C o r p o r a t i o n

Foreign Exchange Forward Contracts on Foreign Denominated Debt

Outstanding foreign exchange forward purchase contracts used to manage foreign exchange exposure on debt not designated as a net investment hedge are as follows:

As at Dec. 31 |  | 2010 |  |  |  |  |  | 2009 |  |  |
Notional amount |  | Fair value liability |  | Maturity |  | Notional amount |  | Fair value liability |  | Maturity |
U.S.300 |  | (7 | ) | 2012 |  | - |  | - |  | - |
U.S.300 |  | (7 | ) | 2013 |  | - |  | - |  | - |

Cross-Currency Swap

TransAlta uses cross-currency swaps to manage foreign exchange risk exposures on foreign denominated debt as follows:

As at Dec. 31 |  | 2010 |  |  |  |  |  | 2009 |  |  |
Notional amount |  | Fair value liability |  | Maturity |  | Notional amount |  | Fair value liability |  | Maturity |
U.S.500 |  | (28 | ) | 2015 |  | U.S.500 |  | (16 | ) | 2015 |

iii. Interest Rate Risk Management

The Corporation also had outstanding forward start interest rate swaps that converted floating rate debt into fixed rate debt with fixed rates ranging from 3.5 per cent to 4.6 per cent. These swaps were closed out upon the issuance of the U.S.$300 million senior notes during the first quarter of 2010 and the resulting losses have been included in AOCI and will be amortized to earnings over the original 10-year term of the swaps.

As at Dec. 31 |  | 2010 |  |  |  |  |  | 2009 |  |  |
Notional amount |  | Fair value liability |  | Maturity |  | Notional amount |  | Fair value liability |  | Maturity |
- |  | - |  | - |  | U.S.300 |  | (8 | ) | 2020 |

iv. Effect on the Consolidated Statements of Comprehensive Income

Forward sale and purchase commodity contracts, foreign exchange contracts, cross-currency swaps, as well as interest rate contracts, are used to hedge the variability in future cash flows. All components of each derivative’s change in fair value have been included in the assessment of cash flow hedge effectiveness.

The following tables summarize the impact of cash flow hedges on the Consolidated Statements of Comprehensive Income, Consolidated Statements of Earnings, and the Consolidated Balance Sheets:

Year ended Dec. 31, 2010 |  |  |  |  |  |  |  |  |
|  | Effective portion |  |  |  | Ineffective portion |
Derivatives in cash flow hedging relationships |  | Pre-tax gain (loss) recognized in OCI |  | Location of (gain) loss reclassified from OCI |  | Pre-tax (gain) loss reclassified from OCI |  | Location of gain recognized in earnings |  | Pre-tax gain recognized in earnings |
Commodity |  | 299 |  | Revenue |  | (234 | ) | Revenue |  | 13 |
Foreign exchange loss on project hedges |  | (15 | ) | Property, plant and equipment |  | 11 |  | Interest expense |  | - |
Foreign exchange loss on U.S. debt |  | (14 | ) | Foreign exchange loss on U.S. debt |  | 39 |  |  |  |  |
Cross-currency swaps |  | (10 | ) |  |  |  |  |  |  |  |
Interest rate |  | (9 | ) | Interest expense |  | 1 |  |  |  |  |
OCI impact |  | 251 |  | OCI impact |  | (183 | ) | Earnings impact |  | 13 |

Year ended Dec. 31, 2009 |  |  |  |  |  |  |  |  |
|  | Effective portion |  |  |  | Ineffective portion |
Derivatives in cash |  | Pre-tax gain |  | Location of (gain) |  | Pre-tax (gain) |  | Location of |  | Pre-tax loss |
flow hedging |  | (loss) recognized |  | loss reclassified |  | loss reclassified |  | loss recognized |  | recognized |
relationships |  | in OCI |  | from OCI |  | from OCI |  | in earnings |  | in earnings |
Commodity |  | 394 |  | Revenue |  | (205 | ) | Revenue |  | - |
Foreign exchange loss on project hedges |  | (31 | ) | Property, plant and equipment |  | (15 | ) | Interest expense |  | (2 | )
Interest rate |  | 37 |  | Interest expense |  | 1 |  |  |  |  |
OCI impact |  | 400 |  | OCI impact |  | (219 | ) | Earnings impact |  | (2 | )

N o t e s t o C o n s o l i d a t e d F i n a n c i a l S t a t e m e n t s | 25

Year ended Dec. 31, 2008 |  |  |  |  |  |  |
|  | Effective portion |  |  |
Derivatives in cash flow |  | Pre-tax gain (loss) |  | Location of loss |  | Pre-tax loss |
hedging relationships |  | recognized in OCI |  | reclassified from OCI |  | reclassified from OCI |
Commodity |  | 352 |  | Revenue |  | 91 |
Foreign exchange gain on project hedges |  | 31 |  | Property, plant and equipment |  | 8 |
Interest rate |  | (56 | ) | Interest expense |  | - |
OCI impact |  | 327 |  | OCI impact |  | 99 |

Over the next 12 months, the Corporation estimates that $121 million of after-tax gains will be reclassified from AOCI to net earnings. These estimates assume constant gas and power prices, interest rates, and exchange rates over time; however, the actual amounts that will be reclassified will vary based on changes in these factors. In addition, it is the Corporation’s intent to settle a substantial portion of the cash flow hedges by physical delivery of the underlying commodity, resulting in gross settlement at the contract price. These contracts are designated as all-in-one hedges and are required to be accounted for as cash flow hedges.

c. Fair Value Hedges

i. Interest Rate Risk Management

The Corporation has converted a portion of its fixed interest rate debt, with rates ranging from 5.75 per cent to 6.9 per cent, to floating rate debt through interest rate swaps as shown below (Note 17):

As at Dec. 31 |  | 2010 |  |  |  |  |  | 2009 |  |  |
|  |  |  |  |  |  |  | Fair value asset |  |  |
Notional amount |  | Fair value asset |  | Maturity |  | Notional amount |  | (liability) |  | Maturity |
100 |  | 2 |  | 2011 |  | 100 |  | 7 |  | 2011 |
U.S.100 |  | 3 |  | 2013 |  | U.S.50 |  | (1 | ) | 2013 |
U.S.200 |  | 16 |  | 2018 |  | U.S.100 |  | 7 |  | 2018 |

Including the interest rate swaps above, 25 per cent of the Corporation’s debt is subject to floating interest rates (2009 - 31 per cent).

ii. Effect on the Consolidated Statements of Comprehensive Income

No ineffective portion of fair value hedges was recorded in 2010, 2009, or 2008.

The following table summarizes the impact and location of fair value hedges on the Consolidated Statements of Earnings:

Year ended Dec. 31 |  |  |  | 2010 |  | 2009 |  | 2008 |
Derivatives in fair value hedging relationships |  | Location of gain (loss) on the Consolidated Statements of Earnings |  |  |  |  |  |  |
Interest rate contracts |  | Net interest expense |  | 8 |  | 20 |  | (26 | )
Long-term debt |  | Net interest expense |  | (8 | ) | (20 | ) | 26 |
Net earnings impact |  |  |  | - |  | - |  | - |

II. Non-Hedges

The Corporation enters into various derivative transactions that do not qualify for hedge accounting or where a choice was made not to apply hedge accounting where the related assets and liabilities are classified as held for trading. The net realized and unrealized gains or losses from changes in the fair value of these derivatives are reported in earnings in the period the change occurs.

26 | T r a n s A l t a C o r p o r a t i o n

a. Energy Trading Risk Management

The Corporation enters into certain commodity hedging transactions that are classified as held for trading. The net realized and unrealized gains or losses from changes in the fair value of these derivatives are reported as revenue in the period the change occurs. The Corporation’s outstanding energy trading derivative instruments that are not designated as hedging instruments were as follows:

(Thousands) |  | Dec. 31, 2010 |  | Dec. 31, 2009 |
|  | Notional |  | Notional amount |  | Notional |  | Notional amount |
Type |  | amount sold |  | purchased |  | amount sold |  | purchased |
Electricity (MWh) |  | 26,553 |  | 24,924 |  | 14,107 |  | 14,844 |
Natural gas (GJ) |  | 633,483 |  | 640,731 |  | 323,793 |  | 309,764 |
Transmission (MWh) |  | - |  | 7,535 |  | - |  | 4,852 |
Oil (gallons) |  | - |  | 5,040 |  | - |  | - |

b. Cross-Currency Interest Rate Swaps

Cross-currency interest rate swaps are periodically entered into in order to limit the Corporation’s exposure to fluctuations in foreign exchange and interest rates. The liability resulting from an outstanding cross-currency interest rate swap is as follows:

As at Dec. 31 |  | 2010 |  |  |  |  |  | 2009 |  |  |
Notional amount |  | Fair value liability |  | Maturity |  | Notional amount |  | Fair value liability |  | Maturity |
- |  | - |  | - |  | AUD13 |  | (2 | ) | 2010 |

c. Foreign Currency Contracts

The Corporation periodically enters into foreign exchange forwards to hedge future foreign denominated revenues and expenses for which hedge accounting is not pursued. These items are classified as held for trading, and changes in the fair values associated with these transactions are recognized in net earnings.

Outstanding notional amounts and fair values associated with these forward contracts are as follows:

As at Dec. 31 |  | 2010 |  |  |  |  |  | 2009 |  |  |
Notional |  | Notional |  |  |  |  |  | Notional |  | Notional |  |  |  |  |
amount |  | amount |  | Fair value |  |  |  | amount |  | amount |  | Fair value |  |  |
sold |  | purchased |  | asset |  | Maturity |  | sold |  | purchased |  | asset |  | Maturity |
20 |  | AUD20 |  | 1 |  | 2011 |  | - |  | - |  | - |  | - |
1 |  | U.S.1 |  | - |  | 2011-2012 |  | - |  | - |  | - |  | - |
- |  | - |  | - |  | - |  | U.S.13 |  | 14 |  | - |  | 2010 |

d. Total Return Swaps

The Corporation also has certain compensation and deferred share unit programs, the values of which depend on the common share price of the Corporation. The Corporation has fixed a portion of the settlement cost of these programs by entering into a total return swap for which hedge accounting has not been chosen. The total return swap is cash settled every quarter based upon the difference between the fixed price and the market price of the Corporation’s common shares at the end of each quarter.

e. Effect on the Consolidated Statements of Comprehensive Income

The Corporation utilizes a variety of derivatives in its proprietary trading activities, including certain commodity hedging activities that do not qualify for hedge accounting or where a choice was made not to apply hedge accounting as well as other contracting activities, and the related assets and liabilities are classified as held for trading. The net realized and unrealized gains or losses from changes in the fair value of derivatives are reported as revenue in the period the change occurs. During the fourth quarter of 2010, unrealized pre-tax gains of $30 million were recognized in earnings due to certain power hedging relationships being discontinued as they were deemed ineffective for accounting purposes. These unrealized gains were calculated using current forward prices that will change between now and the time the underlying hedged transactions were expected to occur. Had these hedges not been deemed ineffective for accounting purposes, the revenues associated with these contracts would have been recorded in the period that they settle, the majority of which will occur during the second quarter of 2011. While future reported earnings will be lower, the expected cash flows from these contracts will not change. For the year ended Dec. 31, 2010, the Corporation recognized a net unrealized gain of $33 million (2009 - $3 million net unrealized loss, 2008 - $14 million net unrealized loss).

N o t e s t o C o n s o l i d a t e d F i n a n c i a l S t a t e m e n t s | 27

The tables below summarize the net realized and unrealized gains and losses included in net earnings that are associated with other risk management derivatives not designated as hedges:

Year ended Dec. 31 |  | 2010 |  |  |  |  |
|  | Net |  |  |  | Net |  |  |  |  |
|  | unrealized |  |  |  | realized |  |  |  |  |
|  | gains |  |  |  | losses |  |  |  | Total |
Foreign exchange |  | 2 |  |  |  | (1 | ) |  |  | 1 |
Other |  | - |  |  |  | (1 | ) |  |  | (1 | )
Year ended Dec. 31 |  | 2009 |  |  |  |  |
|  | Net |  |  |  | Net |  |  |  |  |
|  | unrealized |  |  |  | realized |  |  |  |  |
|  | losses |  |  |  | losses |  |  |  | Total |
Foreign exchange |  | - |  |  |  | (1 | ) |  |  | (1 | )
Year ended Dec. 31 |  | 2008 |  |  |  |  |
|  | Net |  |  |  | Net |  |  |  |  |
|  | unrealized |  |  |  | realized |  |  |  |  |
|  | losses |  |  |  | gains |  |  |  | Total |
Foreign exchange |  | (3 | ) |  |  | 14 |  |  |  | 11 |
Other |  | - |  |  |  | 1 |  |  |  | 1 |

B. Nature and Extent of Risks Arising from Financial Instruments

The following discussion is limited to the nature and extent of risks arising from financial instruments.

I. Market Risk

a. Commodity Price Risk

The Corporation has exposure to movements in certain commodity prices in both its electricity generation and proprietary trading businesses, including the market price of electricity and fuels used to produce electricity. Most of the Corporation’s electricity generation and related fuel supply contracts are considered to be contracts for delivery or receipt of a non-financial item in accordance with expected NPNS contracts that are not considered to be financial instruments. As such, the discussion related to commodity price risk is limited to the Corporation’s proprietary trading business and commodity derivatives used in hedging relationships associated with the Corporation’s electricity generating activities.

The Corporation has a Commodity Exposure Management Policy (the “Policy”) that governs both the commodity transactions undertaken in its proprietary trading business and those undertaken to manage commodity price exposures in its generation business. The Policy defines and specifies the controls and management responsibilities associated with commodity activities, as well as the nature and frequency of required reporting of such activities.

i. Commodity Price Risk - Proprietary Trading

The Corporation’s Energy Trading segment conducts proprietary trading activities and uses a variety of instruments to manage risk, earn trading revenue, and gain market information.

In compliance with the Policy, proprietary trading activities are subject to limits and controls, including Value at Risk (“VaR”) limits. The Board of Directors approves the limit for total VaR from proprietary trading activities. VaR is the most commonly used metric employed to track and manage the market risk associated with trading positions. A VaR measure gives, for a specific confidence level, an estimated maximum pre-tax loss that could be incurred over a specified period of time. VaR is used to determine the potential change in value of the Corporation’s proprietary trading portfolio, over a three-day period within a 95 per cent confidence level, resulting from normal market fluctuations. VaR is estimated using the historical variance/covariance approach.

VaR is a measure that has certain inherent limitations. The use of historical information in the estimate assumes that price movements in the past will be indicative of future market risk. As such, it may only be meaningful under normal market conditions. Extreme market events are not addressed by this risk measure. In addition, the use of a three-day measurement period implies that positions can be unwound or hedged within three days, although this may not be possible if the market becomes illiquid.

28 | T r a n s A l t a C o r p o r a t i o n

The Corporation recognizes the limitations of VaR and actively uses other controls, including restrictions on authorized instruments, volumetric and term limits, stress-testing of individual portfolios and of the total proprietary trading portfolio, and management reviews when loss limits are triggered.

Changes in market prices associated with proprietary trading activities affect net earnings in the period that the price changes occur. VaR at Dec. 31, 2010 associated with the Corporation’s proprietary energy trading activities was $5 million (2009 - $3 million).

ii. Commodity Price Risk - Generation

The Generation segment utilizes various commodity contracts to manage the commodity price risk associated with its electricity generation, fuel purchases, emissions, and byproducts, as considered appropriate. A Commodity Exposure Management Plan is prepared and approved annually, which outlines the intended hedging strategies associated with the Corporation’s generation assets and related commodity price risks. Controls also include restrictions on authorized instruments, management reviews on individual portfolios, and approval of asset transactions that could add potential volatility to the Corporation’s reported net earnings.

TransAlta has entered into various contracts with other parties whereby the other parties have agreed to pay a fixed price for electricity to TransAlta based on the average monthly Alberta Power Pool prices. While the contracts do not create any obligation for the physical delivery of electricity to other parties, the Corporation believes it has sufficient electrical generation available to satisfy these contracts.

Changes in market prices associated with cash flow hedges do not affect net earnings in the period in which the price change occurs. Instead, changes in fair value are deferred until settlement through OCI, at which time the net gain or loss resulting from the combination of the hedging instrument and hedged item affects net earnings.

VaR at Dec. 31, 2010 associated with the Corporation’s commodity derivative instruments used in generation hedging activities was $52 million (2009 - $45 million).

The Corporation’s policy on asset-backed transactions is to seek NPNS contract status or hedge accounting treatment. For positions and economic hedges that do not meet hedge accounting requirements or short-term optimization transactions such as buybacks entered into to offset existing hedge positions, these transactions are marked to the market value with changes in market prices associated with these transactions affecting net earnings in the period in which the price change occurs. VaR at Dec. 31, 2010 associated with the Corporation’s commodity derivative instruments used in the generation segment, but which are not designated as hedges, was $6 million (2009 - nil).

b. Interest Rate Risk

Interest rate risk arises as the fair value or future cash flows of a financial instrument can fluctuate because of changes in market interest rates. Changes in interest rates can impact the Corporation’s borrowing costs and the capacity payments received from Power Purchase Arrangements (“PPAs”). Changes in the cost of capital may also affect the feasibility of new growth initiatives.

The possible effect on net earnings and OCI, for the years ended Dec. 31, 2010, 2009, and 2008, due to changes in market interest rates affecting the Corporation’s floating rate debt and held for trading and hedging interest rate derivatives outstanding at the balance sheet date, is outlined below. The sensitivity analysis has been prepared using management’s assessment that a 50 basis point increase or decrease is a reasonable potential change in market interest rates over the next quarter.

Year ended Dec. 31 |  | 2010 |  | 2009 |  | 2008 |
|  | Net earnings increase 1 |  | OCI loss 1 |  | Net earnings increase 1 |  | OCI loss 1 |  | Net earnings increase 1 |  | OCI loss 1 |
50 basis point change |  | 4 |  | - |  | 5 |  | (10 | ) | 2 |  | - |

1 This calculation assumes a decrease in market interest rates. An increase would have the opposite effect.

N o t e s t o C o n s o l i d a t e d F i n a n c i a l S t a t e m e n t s | 29

c. Currency Rate Risk

The Corporation has exposure to various currencies, such as the Euro and the U.S. and Australian dollars, as a result of investments and operations in foreign jurisdictions, the net earnings from those operations, and the acquisition of equipment and services from foreign suppliers.

The foreign currency risk sensitivities outlined below are limited to the risks that arise on financial instruments denominated in currencies other than the functional currency.

The possible effect on net earnings and OCI, for the years ended Dec, 31, 2010, 2009, and 2008, due to changes in foreign exchange rates associated with financial instruments outstanding at the balance sheet date, is outlined below. The sensitivity analysis has been prepared using management’s assessment that a six cent increase or decrease in these currencies relative to the Canadian dollar is a reasonable potential change over the next quarter.

Year ended Dec. 31 |  | 2010 |  | 2009 |  | 2008 |
|  | Net earnings |  |  |  |  |  |  |  |  |  |  |
|  | (decrease) |  |  |  | Net earnings |  |  |  | Net earnings |  |  |
|  | increase 1 |  | OCI gain 1, 2 |  | decrease 1 |  | OCI gain 1, 2 |  | decrease 1 |  | OCI gain 1, 2 |
U.S. |  | (4 | ) | 9 |  | (5 | ) | 3 |  | (5 | ) | 3 |
AUD |  | 1 |  | - |  | (1 | ) | - |  | (3 | ) | - |
Euro |  | - |  | - |  | - |  | - |  | - |  | 3 |
Total |  | (3 | ) | 9 |  | (6 | ) | 3 |  | (8 | ) | 6 |

1 These calculations assume an increase in the value of these currencies relative to the Canadian dollar. A decrease would have the opposite effect.

2 The foreign exchange impact related to financial instruments used as the hedging instruments in the net investment hedges have been excluded.

II. Credit Risk

Credit risk is the risk that customers or counterparties will cause a financial loss for the Corporation by failing to discharge their obligations, and the risk to the Corporation associated with changes in creditworthiness of entities with which commercial exposures exist. The Corporation actively manages its exposure to credit risk by assessing the ability of counterparties to fulfill their obligations under the related contracts prior to entering into such contracts. The Corporation makes detailed assessments of the credit quality of all counterparties and, where appropriate, obtains corporate guarantees, cash collateral, and/or letters of credit to support the ultimate collection of these receivables. For commodity trading and origination, the Corporation sets strict credit limits for each counterparty and monitors exposures on a daily basis. TransAlta uses standard agreements that allow for the netting of exposures and often include margining provisions. If credit limits are exceeded, TransAlta will request collateral from the counterparty or halt trading activities with the counterparty. TransAlta is exposed to minimal credit risk for Alberta Generation PPAs as receivables are substantially all secured by letters of credit.

At Dec. 31, 2010, TransAlta had one counterparty whose net settlement position accounted for greater than 10 per cent of the total trade receivables outstanding at year-end.

The Corporation’s maximum exposure to credit risk at Dec. 31, 2010, without taking into account collateral held or right of set-off, is represented by the current carrying amounts of accounts receivable and risk management assets as per the Consolidated Balance Sheets. Letters of credit and cash are the primary types of collateral held as security related to these amounts. The maximum credit exposure to any one customer for commodity trading operations and hedging, excluding the California market receivables and including the fair value of open trading, net of any collateral held, at Dec 31, 2010 was $43 million (2009 - $63 million).

The Corporation uses external credit ratings, as well as internal ratings in circumstances where external ratings are not available, to establish credit limits for counterparties. The following table outlines the distribution, by credit rating, of financial assets as at Dec. 31, 2010:

|  | Investment |  | Non-investment |  |  |
(Per cent) |  | grade |  | grade |  | Total |
Accounts receivable |  | 96 |  | 4 |  | 100 |
Risk management assets |  | 100 |  | - |  | 100 |

The Corporation utilizes an allowance for doubtful accounts to record potential credit losses associated with trade receivables. A reconciliation of the account for the year is presented in Note 9.

At Dec. 31, 2010, the Corporation did not have any significant past due trade receivables except as disclosed in Note 28.

30 | T r a n s A l t a C o r p o r a t i o n

III. Liquidity Risk

Liquidity risk relates to the Corporation’s ability to access capital to be used in proprietary trading activities, commodity hedging, capital projects, debt refinancing, and general corporate purposes. Investment grade ratings support these activities and provide better access to capital markets through commodity and credit cycles. TransAlta is focused on maintaining a strong balance sheet and stable investment grade credit ratings.

Counterparties enter into certain electricity and natural gas purchase and sale contracts for the purposes of asset-backed sales and proprietary trading. The terms and conditions of these contracts may require the counterparties to provide collateral when the fair value of the obligation pursuant to these contracts is in excess of any credit limits granted. Downgrades in creditworthiness by certain credit rating agencies may decrease the credit limits granted and accordingly increase the amount of collateral that may have to be provided.

TransAlta manages liquidity risk by monitoring liquidity on trading positions; preparing and revising longer-term financing plans to reflect changes in business plans and the market availability of capital; reporting liquidity risk exposure for proprietary trading activities on a regular basis to the Exposure Management Committee, senior management, and Board of Directors; and maintaining investment grade credit ratings.

A maturity analysis for the Corporation’s financial assets and liabilities is as follows:

|  |  |  |  |  |  |  |  |  |  |  | 2016 and |  |  |
|  | 2011 |  | 2012 |  | 2013 |  | 2014 |  | 2015 |  | thereafter |  | Total |
Accounts payable and accrued liabilities |  | 503 |  | - |  | - |  | - |  | - |  | - |  | 503 |
Collateral received |  | 126 |  | - |  | - |  | - |  | - |  | - |  | 126 |
Debt 1 |  | 254 |  | 674 |  | 629 |  | 231 |  | 681 |  | 1,769 |  | 4,238 |
Energy trading risk management (assets) liabilities 2 |  | (230 | ) | (139 | ) | (28 | ) | 5 |  | 9 |  | 32 |  | (351 | )
Other risk management liabilities (assets)2 |  | - |  | 9 |  | 6 |  | 2 |  | 32 |  | (13 | ) | 36 |
Interest on long-term debt |  | 237 |  | 214 |  | 194 |  | 157 |  | 127 |  | 960 |  | 1,889 |
Dividends payable |  | 130 |  | - |  | - |  | - |  | - |  | - |  | 130 |
Total |  | 1,020 |  | 758 |  | 801 |  | 395 |  | 849 |  | 2,748 |  | 6,571 |

1 Excludes impact of hedge accounting and includes drawn credit facilities that are currently scheduled to mature in 2012 and 2013.

2 Net risk management assets and liabilities as above.

C. Collateral

I. Financial Assets Provided as Collateral

At Dec. 31, 2010, $40 million (2009 - $45 million) of financial assets, consisting of cash and accounts receivable, related to the Corporation’s proportionate share of CE Gen has been pledged as collateral for certain CE Gen debt. Should any defaults occur, the debtholders would have first claim on these assets.

At Dec. 31, 2010, the Corporation provided $27 million (2009 - $27 million) in cash as collateral to regulated clearing agents as security for commodity trading activities. These funds are held in segregated accounts by the clearing agents.

II. Financial Assets Held as Collateral

At Dec. 31, 2010, the Corporation received $126 million (2009 - $86 million) in cash collateral associated with counterparty obligations. Under the terms of the contract, the Corporation may be obligated to pay interest on the outstanding balance and to return the principal when the counterparty has met its contractual obligations, or when the amount of the obligation declines as a result of changes in market value. Interest payable to the counterparties on the collateral received is calculated in accordance with each contract.

III. Contingent Features in Derivative Instruments

Collateral is posted in the normal course of business based on the Corporation’s senior unsecured credit rating as determined by certain major credit rating agencies. Certain of the Corporation’s derivative instruments contain financial assurance provisions that require collateral to be posted only if a material adverse credit-related event occurs. If a material adverse event resulted in the Corporation’s senior unsecured debt to fall below investment grade, the counterparties to such derivative instruments could request ongoing full collateralization.

As at Dec. 31, 2010, the Corporation had posted collateral of $17 million (2009 - $37 million) in the form of letters of credit on derivative instruments in a net liability position. Certain derivative agreements contain credit-risk-contingent features, including a credit rating downgrade to below investment grade, which if triggered would result in the Corporation having to post an additional $40 million of collateral to its counterparties based upon the value of the derivatives at Dec. 31, 2010.

N o t e s t o C o n s o l i d a t e d F i n a n c i a l S t a t e m e n t s | 31

9. Accounts Receivable

As at Dec. 31 |  | 2010 |  | 2009 |
Gross accounts receivable |  | 474 |  | 470 |
Allowance for doubtful accounts (Note 28) |  | (46 | ) | (49 | )
Net accounts receivable |  | 428 |  | 421 |

The change in allowance for doubtful accounts is outlined below:

Balance, Dec. 31, 2009 |  | 49 |
Change in foreign exchange rates |  | (3 | )
Balance, Dec. 31, 2010 |  | 46 |

10. Inventory

Inventory held in the normal course of business, which includes coal, emission credits, and natural gas, are valued at the lower of cost and net realizable value. Inventory held for Energy Trading, which also includes natural gas, is valued at fair value less costs to sell (Note 2). The classifications are as follows:

As at Dec. 31 |  | 2010 |  | 2009 |
Coal |  | 47 |  | 86 |
Natural gas |  | 5 |  | 4 |
Purchased emission credits |  | 1 |  | - |
Total |  | 53 |  | 90 |

The decrease in coal inventory in 2010 compared to 2009 is primarily due to higher production at the coal facilities.

The change in inventory is outlined below:

Balance, Dec. 31, 2009 |  | 90 |
Net consumed |  | (36 | )
Change in foreign exchange rates |  | (1 | )
Balance, Dec. 31, 2010 |  | 53 |

No inventory is pledged as security for liabilities.

For the years ended Dec. 31, 2010 and 2009, no inventory was written down from its carrying value nor were any writedowns recorded in previous periods reversed back into net earnings.

11. Long-Term Receivable

In 2008, the Corporation was reassessed by taxation authorities in Canada relating to the sale of its previously operated Transmission Business, requiring the Corporation to pay $49 million in taxes and interest. The Corporation challenged this reassessment. During 2010, a decision from the Tax Court of Canada was received that allowed for the recovery of $38 million of the previously paid taxes and interest. TransAlta filed an appeal with the Federal Court in 2010 to pursue the remaining $11 million.

32 | T r a n s A l t a C o r p o r a t i o n

12. Property, Plant, and Equipment

As at Dec. 31 |  | 2010 |  | 2009 |
|  |  |  |  |  | Accumulated |  |  |  |  |  | Accumulated |  |  |
|  |  |  |  |  | depreciation |  |  |  |  |  | depreciation |  |  |
|  | Depreciable |  |  |  | and |  | Net book |  |  |  | and |  | Net book |
|  | lives |  | Cost |  | amortization |  | value |  | Cost |  | amortization |  | value |
Thermal generation equipment |  | 2-50 |  | 4,396 |  | 2,103 |  | 2,293 |  | 4,693 |  | 2,266 |  | 2,427 |
Mining property & equipment |  | 3-50 |  | 917 |  | 368 |  | 549 |  | 795 |  | 415 |  | 380 |
Gas generation |  | 2-30 |  | 2,047 |  | 955 |  | 1,092 |  | 2,135 |  | 883 |  | 1,252 |
Geothermal generation |  | 10-20 |  | 334 |  | 127 |  | 207 |  | 333 |  | 101 |  | 232 |
Hydro generation |  | 3-60 |  | 614 |  | 255 |  | 359 |  | 609 |  | 238 |  | 371 |
Wind generation |  | 5-30 |  | 1,820 |  | 114 |  | 1,706 |  | 1,554 |  | 59 |  | 1,495 |
Biomass |  | 10-25 |  | 2 |  | - |  | 2 |  | 25 |  | 1 |  | 24 |
Capital spares and other |  | 3-41 |  | 310 |  | 87 |  | 223 |  | 270 |  | 65 |  | 205 |
Assets under construction |  | - |  | 995 |  | - |  | 995 |  | 1,038 |  | - |  | 1,038 |
Coal rights 1 |  | - |  | 148 |  | 92 |  | 56 |  | 133 |  | 86 |  | 47 |
Land |  | - |  | 71 |  | - |  | 71 |  | 68 |  | - |  | 68 |
Transmission systems |  | 15-50 |  | 52 |  | 28 |  | 24 |  | 48 |  | 28 |  | 20 |
Total |  |  |  | 11,706 |  | 4,129 |  | 7,577 |  | 11,701 |  | 4,142 |  | 7,559 |

1 Coal rights are amortized on a unit-of-production basis, based on the estimated mine reserve.

The Corporation capitalized $48 million of interest to PP&E in 2010 (2009 - $36 million, 2008 - $21 million).

The change in PP&E is outlined below:

|  |  |  | Accumulated |  |  |
|  |  |  | depreciation |  |  |
|  |  |  | and |  | Net book |
|  | Cost |  | amortization |  | value |
Balance, Dec. 31, 2009 |  | 11,701 |  | 4,142 |  | 7,559 |
Additions |  | 790 |  | - |  | 790 |
Adjustment of Canadian Hydro purchase price allocation (Note 24) |  | (104 | ) | - |  | (104 | )
Assets held for sale (Note 13) |  | (89 | ) | (29 | ) | (60 | )
Asset impairment charges (Note 3) |  | (80 | ) | - |  | (80 | )
Change in foreign exchange rates |  | (70 | ) | (26 | ) | (44 | )
Depreciation |  | - |  | 465 |  | (465 | )
Disposals |  | (3 | ) | (1 | ) | (2 | )
Resolution of certain tax matters (Note 9) |  | (11 | ) | - |  | (11 | )
Retirement of assets |  | (60 | ) | (60 | ) | - |
Transfers |  | 13 |  | - |  | 13 |
Wabamun decommissioning |  | (381 | ) | (362 | ) | (19 | )
Balance, Dec. 31, 2010 |  | 11,706 |  | 4,129 |  | 7,577 |

13. Assets and Liabilities Held for Sale

On Dec. 20, 2010, TransAlta Cogeneration, L.P. (“TA Cogen”), a subsidiary that is owned 50.01 per cent by TransAlta, entered into an agreement for the sale of its 50 per cent interest in the Meridian facility. As a result, all associated assets and liabilities have been classified as held for sale under the Generation segment. The sale is effective Jan. 1, 2011 and is expected to close in early 2011. The impact of this transaction on net earnings is not expected to be significant.

14. Goodwill

The change in goodwill is outlined below:

Balance, Dec. 31, 2009 |  | 434 |
Adjustment of Canadian Hydro purchase price allocation (Note 24) |  | 87 |
Change in foreign exchange rates |  | (4 | )
Balance, Dec. 31, 2010 |  | 517 |

A portion of goodwill in Generation relates to CE Gen, a self-sustaining foreign operation denominated in U.S. dollars (Note 29).

N o t e s t o C o n s o l i d a t e d F i n a n c i a l S t a t e m e n t s | 33

15. Intangible Assets

The change in intangible assets is outlined below:

|  |  |  | Accumulated |  | Net book |
|  | Cost |  | amortization |  | value |
Balance, Dec. 31, 2009 |  | 618 |  | 274 |  | 344 |
Adjustment of Canadian Hydro purchase price allocation (Note 24) |  | (10 | ) | - |  | (10 | )
Additions |  | 3 |  | - |  | 3 |
Change in foreign exchange rates |  | (21 | ) | (13 | ) | (8 | )
Amortization |  | - |  | 25 |  | (25 | )
Balance, Dec. 31, 2010 |  | 590 |  | 286 |  | 304 |

A portion of intangible assets relates to CE Gen, a self-sustaining foreign operation denominated in U.S. dollars.

16. Other Assets

As at Dec. 31 |  | 2010 |  | 2009 |
Deferred license fees |  | 23 |  | 22 |
Accrued benefit asset (Note 32) |  | 25 |  | 18 |
Project development costs |  | 49 |  | 45 |
Deferred service costs |  | 12 |  | 19 |
Keephills 3 transmission deposit |  | 8 |  | 8 |
Other |  | 10 |  | 9 |
Total other assets |  | 127 |  | 121 |

Deferred license fees consist primarily of licenses to lease the land on which certain generating assets are located, and are being amortized on a straight-line basis over the useful life of the generating assets to which the licenses relate.

Project development costs include external, direct, and incremental costs incurred during the development phase of future power projects. The appropriateness of the carrying value of these costs is evaluated each reporting period, and unrecoverable amounts for projects no longer probable of occurring are charged to expense.

Deferred service costs are TransAlta’s contracted payments for shared capital projects required at the Genesee site. These costs are being amortized over the life of these projects.

The Keephills 3 transmission deposit is TransAlta’s proportionate share of a provincially required deposit for Keephills 3. The full amount of the deposit is anticipated to be reimbursed over the next 10 years, as long as certain performance criteria are met.

17. Long-Term Debt and Net Interest Expense

A. Amounts Outstanding

As at Dec. 31 |  | 2010 |  | 2009 |
|  | Carrying |  |  |  |  |  | Carrying |  |  |  |  |
|  | value |  | Face value |  | Interest 1 |  | value |  | Face value |  | Interest 1 |
Credit facilities 2 |  | 645 |  | 645 |  | 1.4% |  | 1,063 |  | 1,063 |  | 1.0% |
Debentures |  | 1,057 |  | 1,076 |  | 6.7% |  | 1,055 |  | 1,076 |  | 6.7% |
Senior notes 3 |  | 1,931 |  | 1,902 |  | 6.0% |  | 1,687 |  | 1,684 |  | 5.9% |
Non-recourse |  | 549 |  | 562 |  | 6.5% |  | 578 |  | 589 |  | 6.3% |
Other |  | 52 |  | 52 |  | 6.7% |  | 59 |  | 59 |  | 6.7% |
|  | 4,234 |  | 4,237 |  |  |  | 4,442 |  | 4,471 |  |  |
Less: current portion |  | (255 | ) | (253 | ) |  |  | (31 | ) | (31 | ) |  |
Total long-term debt |  | 3,979 |  | 3,984 |  |  |  | 4,411 |  | 4,440 |  |  |

1 Interest is an average rate weighted by principal amounts outstanding before the effect of hedging.

2 Composed of bankers’ acceptances and other commercial borrowings under long-term committed credit facilities.

3 2010 - U.S.$1,900 million, 2009 - U.S.$1,600 million.

A portion of the fixed rate components of the Corporation’s debentures and senior notes have been hedged using fixed to floating interest rate swaps (Note 8) and therefore the Corporation has included the fair value of these swaps with the value of the debt which is also recorded at fair value. The balance of long-term debt is not hedged and therefore recorded at amortized cost.

34 | T r a n s A l t a C o r p o r a t i o n

Credit facilities are drawn on the Corporation’s $1.5 billion committed syndicated bank credit facility and on the Corporation’s U.S.$300 million committed facility. The $1.5 billion committed syndicated bank facility is the primary source for short-term liquidity after the cash flow generated from the Corporation’s businesses. The facility is a five-year revolving credit facility which was last renewed in May 2007 and matures in 2012. The U.S.$300 million committed facility is a five-year facility that matures in 2013. Interest rates on the credit facilities vary depending on the option selected: Canadian prime, bankers’ acceptance, U.S. LIBOR or U.S. base rate, in accordance with a pricing grid that is standard for such facilities. A total of U.S.$300 million of the credit facilities has been designated as a hedge of the Corporation’s net investment of U.S. self-sustaining foreign operations. The Corporation also has $240 million available in committed bilateral credit facilities, all of which mature in 2012.

Debentures bear interest at fixed rates ranging from 6.4 per cent to 7.3 per cent and have maturity dates ranging from 2011 to 2030.

Senior Notes bear interest at rates ranging from 4.75 per cent to 6.75 per cent and have maturity dates ranging from 2012 to 2040. During 2010, the Corporation issued senior notes in the amount of U.S.$300 million, bearing interest at a rate of 6.5 per cent and maturing in 2040. A total of U.S.$800 million of the senior notes has been designated as a hedge of the Corporation’s net investment of U.S. self-sustaining foreign operations.

Non-Recourse Debt consists of project financing debt, debt securities and senior secured bonds of CE Gen, debt related to the Wailuku River Hydroelectric L.P. (“Wailuku”) acquisition, and debentures issued by Canadian Hydro. The CE Gen related assets have been pledged as security for the project financing debt. The CE Gen debt has maturity dates ranging from 2011 to 2018 and bears interest at rates ranging from 7.5 per cent to 8.3 per cent and includes debt with a cost of U.S.$171 million (2009 - U.S.$192 million). The Wailuku debt has a maturity date of 2021 and bears interest at a floating rate currently of 0.3 per cent and includes debt with a cost of U.S.$7 million (2009 - U.S.$8 million). The Canadian Hydro debt has maturity dates ranging from 2012 to 2018 and bears interest at rates ranging from 5.3 per cent to 10.9 per cent and includes debt with a cost of $363 million and U.S.$20 million (2009 - $365 million and U.S.$20 million).

Other consists of notes payable for the Windsor plant that bear interest at fixed rates and are recourse to the Corporation through a standby letter of credit. These mature in November 2014. Also included is a commercial loan obligation that bears an interest rate of 5.9 per cent and will mature in 2023. This is an unsecured loan and requires annual payments of interest and principal.

TransAlta’s debt contains terms and conditions, including financial covenants, that are considered normal and customary. As at Dec. 31, 2010, the Corporation was in compliance with all debt covenants.

B. Principal Repayments

2011 |  | 253 |
2012 |  | 674 |
2013 |  | 629 |
2014 |  | 231 |
2015 |  | 681 |
2016 and thereafter |  | 1,769 |
Total 1 |  | 4,237 |

1 Excludes impact of derivatives and includes drawn credit facilities that are currently scheduled to mature in 2012 and 2013.

C. Interest Expense

Year ended Dec. 31 |  | 2010 |  | 2009 |  | 2008 |
Interest on long-term debt |  | 243 |  | 183 |  | 177 |
Interest income |  | (17 | ) | (6 | ) | (46 | )
Capitalized interest |  | (48 | ) | (36 | ) | (21 | )
Other |  | - |  | 3 |  | - |
Net interest expense |  | 178 |  | 144 |  | 110 |

The Corporation capitalizes interest during the construction phase of growth capital projects. The capitalized interest in 2010 relates primarily to Keephills 3, Ardenville, and Kent Hills. In 2009, the capitalized interest related primarily to Keephills 3 and associated mine capital, Blue Trail, and Summerview 2.

In 2008, an appeal was resolved pertaining to the timing of revenue recognition and deductions on previous years’ tax returns based on applicable income tax laws. Consequently, a $30 million interest refund from taxation authorities was recorded as interest income.

N o t e s t o C o n s o l i d a t e d F i n a n c i a l S t a t e m e n t s | 35

D. Guarantees

Letters of Credit

Letters of credit are issued to counterparties under some contractual arrangements with certain subsidiaries of the Corporation. If the Corporation or its subsidiary does not perform under such contracts, the counterparty may present its claim for payment to the financial institution through which the letter of credit was issued. Any amounts owed by the Corporation or its subsidiaries are reflected in the Consolidated Balance Sheets. All letters of credit expire within one year and are expected to be renewed, as needed, through the normal course of business. The total outstanding letters of credit as at Dec. 31, 2010 totalled $297 million (2009 - $334 million) with no (2009 - nil) amounts exercised by third parties under these arrangements. TransAlta has a total of $2.0 billion (2009 - $2.1 billion) of committed credit facilities, of which $1.1 billion (2009 - $0.7 billion) is not drawn, and is available as of Dec. 31, 2010, subject to customary borrowing conditions.

In addition to the $1.1 billion available under the credit facilities, TransAlta also has $58 million of cash available.

18. Asset Retirement Obligation

The change in asset retirement obligation balances is summarized below:

Balance, Dec. 31, 2009 |  | 282 |
Liabilities incurred in period |  | 3 |
Liabilities settled in period |  | (37 | )
Accretion expense |  | 21 |
Transfer to liabilities held for sale (Note 13) |  | (3 | )
Revisions in estimated cash flows |  | (20 | )
Change in foreign exchange rates |  | (4 | )
|  | 242 |
Less: current portion |  | (38 | )
Balance, Dec. 31, 2010 |  | 204 |

The Corporation has a right to recover a portion of future asset retirement costs.

Revisions in estimated cash flows are primarily due to changes in the estimated costs associated with the decommissioning of the Wabamun plant, which was shut down on March 31, 2010.

TransAlta estimates that the undiscounted amount of cash flow required to settle the asset retirement obligation is approximately $0.8 billion, which will be incurred between 2011 and 2072. The majority of the costs will be incurred between 2020 and 2050. An average discount rate of eight per cent and an inflation rate of two per cent were used to calculate the carrying value of the asset retirement obligation. At Dec. 31, 2010, the Corporation had provided a surety bond in the amount of U.S.$192 million (2009 - U.S.$192 million) in support of future retirement obligations at the Centralia coal mine. At Dec. 31, 2010, the Corporation had provided letters of credit in the amount of $72 million (2009 - $67 million) in support of future retirement obligations at the Alberta mines.

19. Deferred Credits and Other Long-Term Liabilities

As at Dec. 31 |  | 2010 |  | 2009 |
Deferred coal revenues (Note 25) |  | 61 |  | 51 |
Long-term power contracts |  | 28 |  | 32 |
Accrued benefit liability (Note 32) |  | 51 |  | 49 |
Commitments for transportation of natural gas |  | 9 |  | - |
Long-term incentive accruals |  | 8 |  | 4 |
Other |  | 12 |  | 11 |
Total deferred credits and other long-term liabilities |  | 169 |  | 147 |

The long-term power contracts represent the fair value adjustments for various plants to deliver power at less than the prevailing market price at the time of the acquisition. The long-term power contracts are amortized on a straight-line basis over the life of the contract.

36 | T r a n s A l t a C o r p o r a t i o n

20. Common Shares

A. Issued and Outstanding

TransAlta is authorized to issue an unlimited number of voting common shares without nominal or par value.

Year ended Dec. 31 |  | 2010 |  | 2009 |
|  | Common |  |  |  | Common |  |  |
|  | shares |  |  |  | shares |  |  |
|  | (millions) |  | Amount |  | (millions) |  | Amount |
Issued and outstanding, beginning of year |  | 218.4 |  | 2,169 |  | 197.6 |  | 1,761 |
Issued under dividend reinvestment and share purchase plan |  | 1.6 |  | 37 |  | - |  | - |
Issued under stock option plans |  | 0.1 |  | 1 |  | - |  | - |
Issued under Performance Share Ownership Plan |  | 0.2 |  | 4 |  | 0.2 |  | 6 |
Issued 1 |  | - |  | - |  | 20.6 |  | 402 |
Issued and outstanding, end of year |  | 220.3 |  | 2,211 |  | 218.4 |  | 2,169 |

1 Net of issuance costs of $12 million after tax.

On Feb. 1, 2010, 0.9 million stock options were granted at a strike price of $22.46, being the last sale price of board lots of the shares on the Toronto Stock Exchange the day prior to the day the options were granted for Canadian employees, and U.S.$20.75, being the closing sale price on the New York Stock Exchange on the same date for U.S. employees. These options will vest in equal installments over four years starting Feb. 1, 2011 and expire after 10 years (Note 31).

At Dec. 31, 2010 the Corporation had 2.2 million outstanding employee stock options (2009 - 1.5 million). For the year ended Dec. 31, 2010, 0.1 million options with a weighted average exercise price of $16.20 were exercised resulting in 0.1 million shares issued, and 0.1 million options were cancelled with a weighted average exercise price of $26.61 (Note 31).

During 2010, no shares were acquired or cancelled under the Normal Course Issuer Bid (“NCIB”) program prior to its expiry on May 6, 2010. For the year ended Dec. 31, 2009, no shares were acquired or cancelled under the NCIB program. For the year ended Dec. 31, 2008, TransAlta purchased 3,886,400 shares at an average price of $33.46 per share for a total of $130 million.

B. Shareholder Rights Plan

The primary objective of the Shareholder Rights Plan is to provide the Corporation’s Board of Directors sufficient time to explore and develop alternatives for maximizing shareholder value if a takeover bid is made for the Corporation and to provide every shareholder with an equal opportunity to participate in such a bid. The plan was originally approved in 1992, and has been revised since that time to ensure conformity with current practices. The plan is put before the shareholders every three years for approval, and was last approved on April 29, 2010.

When an acquiring shareholder commences a bid to acquire 20 per cent or more of the Corporation’s common shares, other than by way of a Permitted Bid, where the offer is made to all shareholders by way of a takeover bid circular, the rights granted under the Shareholder Rights Plan become exercisable by all shareholders except those held by the acquiring shareholder. Each right will entitle a shareholder other than the acquiring shareholder, to acquire an additional $200 worth of common shares for $100.

C. Dividend Reinvestment and Share Purchase (“DRASP”) Plan

Under the terms of the DRASP plan, eligible participants are able to purchase additional common shares by reinvesting dividends or making an additional contribution of up to $5,000 per quarter. On April 29, 2010, in accordance with the terms of the DRASP plan, the Board of Directors approved the issuance of shares from Treasury at a three per cent discount from the weighted average price of the shares traded on the Toronto Stock Exchange on the last five days preceding the dividend payment date. During the year ended Dec. 31, 2010, the Corporation issued 1.6 million common shares for $37 million. Under the terms of the DRASP plan, the Corporation reserves the right to alter the discount or return to purchasing the shares on the open market at any time.

N o t e s t o C o n s o l i d a t e d F i n a n c i a l S t a t e m e n t s | 37

D. Earnings Per Share

Year ended Dec. 31 |  | 2010 |  | 2009 |  | 2008 |
Net earnings applicable to common shares |  | 218 |  | 181 |  | 235 |
Basic and diluted weighted average number of common shares outstanding |  | 219 |  | 201 |  | 199 |
Earnings per common share |  |  |  |  |  |  |
Basic and diluted |  | 1.00 |  | 0.90 |  | 1.18 |

The effect of the PSOP does not materially affect the calculation of the total weighted average number of common shares outstanding (Note 31).

E. Dividends

The following tables summarize the common share dividends in 2010 and 2009:

|  |  |  |  |  | Dividends |  |  |  |  |  | Dividends paid |
Date |  | Payment |  | Dividend per |  | payable as at |  | Total |  | Dividends |  | in shares |
declared |  | date |  | share ($) |  | Dec. 31, 2010 |  | dividends |  | paid in cash 1 |  | under DRASP 1 |
Jan. 29, 2010 |  | April 1, 2010 |  | 0.29 |  | - |  | 63 |  | 60 |  | 3 |
April 1, 2010 |  | July 1, 2010 |  | 0.29 |  | - |  | 64 |  | 49 |  | 15 |
July 22, 2010 |  | Oct. 1, 2010 |  | 0.29 |  | - |  | 63 |  | 44 |  | 19 |
Oct. 28, 2010 |  | Jan. 1, 2011 |  | 0.29 |  | 64 |  | 64 |  | 47 |  | 17 |
Dec. 7, 2010 |  | April 1, 2011 |  | 0.29 |  | 65 |  | 65 |  |  |  |  |
Total |  |  |  | 1.45 |  | 129 |  | 319 |  |  |  |  |
1 Allocation of dividends paid in cash or shares will be determined at the payment date. |  |  |  |  |
|  |  |  |  |  | Dividends |  |  |  |  |  | Dividends paid |
Date |  | Payment |  | Dividend per |  | payable as at |  | Total |  | Dividends |  | in shares |
declared |  | date |  | share ($) |  | Dec. 31, 2009 |  | dividends |  | paid in cash |  | under DRASP |
Jan. 29, 2009 |  | April 1, 2009 |  | 0.29 |  | - |  | 57 |  | 57 |  | - |
April 30, 2009 |  | July 1, 2009 |  | 0.29 |  | - |  | 57 |  | 57 |  | - |
July 23, 2009 |  | Oct. 1, 2009 |  | 0.29 |  | - |  | 58 |  | 58 |  | - |
Oct. 29, 2009 |  | Jan. 1, 2010 |  | 0.29 |  | 63 |  | 63 |  | 63 |  | - |
Total |  |  |  | 1.16 |  | 63 |  | 235 |  |  |  |  |

21. Preferred Shares

A. Issued and Outstanding

The Corporation is authorized to issue an unlimited number of first preferred shares, and the Board of Directors is authorized to determine the rights, privileges, restrictions and conditions attaching to such shares, subject to certain limitations.

Year ended Dec. 31 |  | 2010 |
|  | Number of |  |  |  | Dividend |  | Redemption |
|  | shares |  |  |  | rate per |  | price per |
|  | (millions) |  | Amount |  | share |  | share |
Issued and outstanding, beginning of year |  | - |  | - |  | - |  | - |
Issued 1 |  | 12.0 |  | 293 |  | 1.15 |  | 25 |
Issued and outstanding, end of year |  | 12.0 |  | 293 |  |  |  |  |

1 Net of issuance costs of $7 million after tax.

On Dec. 10, 2010, TransAlta completed a public offering of 12 million Series A Cumulative Rate Reset First Preferred Shares under a prospectus supplement to the short form base shelf prospectus dated Oct. 19, 2009 for gross proceeds of $300 million. The holders of the preferred shares are entitled to receive fixed cumulative cash dividends at an annual rate of $1.15 per share as approved by the Board of Directors, payable quarterly, yielding 4.60 per cent per annum, for the initial period ending March 31, 2016. The dividend rate will reset on March 31, 2016 and every five years thereafter to a yield per annum equal to the sum of the then five-year Government of Canada bond yield plus 2.03 per cent. The preferred shares are redeemable at the option of TransAlta on or after March 31, 2016 and on March 31 of every fifth year thereafter at a price of $25.00 per share plus all declared and unpaid dividends. The first dividend was declared on Dec. 13, 2010.

38 | T r a n s A l t a C o r p o r a t i o n

The preferred shareholders will have the right to convert their shares into Series B Cumulative Rate Reset First Preferred Shares on March 31, 2016 and on March 31 of every fifth year thereafter. The holders of Series B preferred shares will be entitled to receive quarterly floating rate cumulative dividends as approved by the Board of Directors at a yield per annum equal to the sum of the then three-month Government of Canada Treasury Bill rate plus 2.03 per cent.

B. Dividends

The following table summarizes the preferred share dividends declared in 2010:

|  |  |  |  |  | Dividends |  |  |
|  | Payment |  | Dividend per |  | payable as at |  | Total |
Date declared |  | date |  | share ($) |  | Dec. 31, 2010 |  | dividends |
Dec. 13, 2010 |  | March 31, 2011 |  | 0.3497 |  | 1 |  | 1 |

22. Shareholders’ Equity

A reconciliation of shareholders’ equity is as follows:

|  |  |  |  |  |  |  | Accumulated |  |  |
|  |  |  |  |  |  |  | other |  | Total |
|  | Common |  | Preferred |  | Retained |  | comprehensive |  | shareholders’ |
|  | shares |  | shares |  | earnings |  | income |  | equity |
Balance, Dec. 31, 2009 |  | 2,169 |  | - |  | 634 |  | 126 |  | 2,929 |
Net earnings |  | - |  | - |  | 219 |  | - |  | 219 |
Shares issued |  | 42 |  | 293 |  | - |  | - |  | 335 |
Dividends declared on common shares |  | - |  | - |  | (319 | ) | - |  | (319 | )
Dividends declared on preferred shares |  | - |  | - |  | (1 | ) | - |  | (1 | )
Losses on translating net assets of self-sustaining foreign operations, net of hedges and of tax |  | - |  | - |  | - |  | (27 | ) | (27 | )
Gains on derivatives designated as cash flow hedges, net of tax |  | - |  | - |  | - |  | 164 |  | 164 |
Derivatives designated as cash flow hedges in prior periods transferred to the Consolidated Balance Sheets and net earnings in the current period, net of tax |  | - |  | - |  | - |  | (121 | ) | (121 | )
Gains on translation of self-sustaining foreign operations transferred to net earnings, net of tax |  | - |  | - |  | - |  | (2 | ) | (2 | )
Balance, Dec. 31, 2010 |  | 2,211 |  | 293 |  | 533 |  | 140 |  | 3,177 |
The components of AOCI are presented below: |  |  |  |  |  |  |  |  |  |  |
As at Dec. 31 |  |  |  |  |  |  |  | 2010 |  | 2009 |
Cumulative unrealized losses on translating self-sustaining foreign operations, net of hedges and of tax |  | (92 | ) | (63 | )
Cumulative unrealized gains on cash flow hedges, net of tax |  |  |  |  |  |  |  | 232 |  | 189 |
Total accumulated other comprehensive income |  |  |  |  |  |  |  | 140 |  | 126 |

N o t e s t o C o n s o l i d a t e d F i n a n c i a l S t a t e m e n t s | 39

23. Capital

TransAlta’s capital is comprised of the following:

|  |  |  |  |  | Increase/ |
As at Dec. 31 |  | 2010 |  | 2009 |  | (decrease) |
Short-term debt and current portion of long-term debt |  | 256 |  | 31 |  | 225 |
Less: cash and cash equivalents |  | (58 | ) | (82 | ) | 24 |
|  | 198 |  | (51 | ) | 249 |
Long-term debt |  |  |  |  |  |  |
Recourse |  | 3,450 |  | 3,857 |  | (407 | )
Non-recourse |  | 529 |  | 554 |  | (25 | )
Non-controlling interests |  | 435 |  | 478 |  | (43 | )
Shareholders’ equity |  |  |  |  |  |  |
Common shares |  | 2,211 |  | 2,169 |  | 42 |
Preferred shares |  | 293 |  | - |  | 293 |
Retained earnings |  | 533 |  | 634 |  | (101 | )
AOCI |  | 140 |  | 126 |  | 14 |
|  | 7,591 |  | 7,818 |  | (227 | )
Total capital |  | 7,789 |  | 7,767 |  | 22 |

Total capital remains largely unchanged from the prior year. The decrease in long-term debt is primarily due to the issuance of preferred shares and favourable foreign exchange movements.

TransAlta’s overall capital management strategy has remained unchanged from Dec. 31, 2009.

TransAlta’s objectives in managing its capital structure are as follows:

A. Maintain an Investment Grade Credit Rating

The Corporation operates in a long-cycle and capital-intensive commodity business, and it is therefore a priority to maintain an investment grade credit rating as it allows the Corporation to access capital markets at reasonable rates. TransAlta monitors key credit ratios similar to those used by key rating agencies. While these ratios are not publicly available from credit agencies, TransAlta’s management has defined these ratios and seeks to manage the Corporation’s capital in line with the following targets:

Cash flow to interest coverage Cash flow from operating activities before changes in working capital plus net interest expense divided by interest on debt less interest income. TransAlta targets to maintain this ratio in a range of four to five times.

Cash flow to debt Cash flow from operating activities before changes in working capital divided by average total debt. TransAlta targets to maintain this ratio in a range of 20 to 25 per cent.

Debt to invested capital Debt less cash and cash equivalents divided by debt, non-controlling interests, and shareholders’ equity less cash and cash equivalents. TransAlta targets to maintain this ratio in a range of 55 to 60 per cent.

These ratios are presented below:

Year ended Dec. 31 |  | 2010 |  | 2009 |
Cash flow to interest coverage (times)1 |  | 4.3 |  | 4.9 |
Cash flow to debt (%)1 |  | 18.3 |  | 20.5 |
Debt to invested capital (%) |  | 53.6 |  | 56.1 |

1 Last 12 months.

The decrease in cash flow to interest coverage resulted from higher interest expense. The decrease in cash flow to debt resulted from an increase in debt balances (Note 17). The decrease in debt to invested capital is due to U.S. dollar denominated debt being valued lower in Canadian dollar terms at Dec. 31, 2010 (Note 17). TransAlta routinely monitors forecasts for net earnings, capital expenditures, and scheduled repayment of debt with a goal of meeting the above ratio targets.

40 | T r a n s A l t a C o r p o r a t i o n

B. Ensure Sufficient Cash and Credit is Available to Fund Operations, Pay Dividends,
and Invest in Capital Assets

For the years ended Dec. 31, 2010 and 2009, net cash outflows, after cash dividends and capital asset additions, are summarized below:

Year ended Dec. 31 |  | 2010 |  | 2009 |  | Increase in cash flows |
Cash flow from operating activities |  | 811 |  | 580 |  | 231 |
Dividends paid on common shares |  | (216 | ) | (226 | ) | 10 |
Capital asset expenditures |  | (790 | ) | (904 | ) | 114 |
Net cash outflow |  | (195 | ) | (550 | ) | 355 |

The increase in the total net cash flows primarily resulted from higher cash flows from operating activities and lower capital asset expenditures. TransAlta maintains sufficient cash balances and committed credit facilities to fund periodic net cash outflows related to its business. At Dec. 31, 2010, $1.1 billion of the Corporation’s available credit facilities were not drawn.

Periodically, TransAlta opportunistically accesses the capital market to help fund some of these periodic net cash outflows, to maintain its available liquidity, and to maintain its capital structure and credit metrics within targeted ranges.

During 2010, the Corporation issued senior notes in the amount of U.S.$300 million, bearing interest at a rate of 6.5 per cent and maturing in 2040.

During 2010, the Corporation issued 1.9 million common shares for total net proceeds of $42 million. The Corporation also issued 12.0 million preferred shares for total net proceeds of $293 million.

TransAlta’s formal dividend policy targets to pay common shareholders an annual dividend in the range of 60 to 70 per cent of comparable net earnings, a non-GAAP measure, which in general excludes items that would not be considered to be part of normal operations.

24. Acquisitions and Disposals

A. Acquisitions

On Oct. 23, 2009, TransAlta acquired 87 per cent of Canadian Hydro through the purchase of the issued and outstanding shares of Canadian Hydro. On Nov. 4, 2009, TransAlta acquired the remaining 13 per cent of the issued and outstanding shares. The total cash consideration was $785 million. The results of Canadian Hydro are included in the consolidated financial statements of the Corporation from the acquisition date of Oct. 23, 2009.

The details of the cash consideration are as follows:

Total shares acquired (millions) |  | 143.8 |
Price per share |  | 5.25 |
Total consideration paid |  | 755 |
Transaction costs |  | 30 |
Total cash consideration |  | 785 |

N o t e s t o C o n s o l i d a t e d F i n a n c i a l S t a t e m e n t s | 41

Final Allocation of Purchase Price

During the fourth quarter of 2010, the preliminary purchase price allocation was revised to reflect the results of management’s assessment of value. The significant adjustments between the preliminary and final purchase price allocation were primarily due to the finalization of the fair values of property, plant, and equipment and intangible assets. As a result, a pre-tax decrease of $4 million has been reflected in depreciation expense. The resulting adjustments and final purchase price allocation are highlighted below:

|  | Acquisition |  |  |  | Revised |
|  | fair values |  | Adjustments |  | balances |
Assets: |  |  |  |  |  |  |
Cash |  | 19 |  | - |  | 19 |
Accounts receivable |  | 25 |  | - |  | 25 |
Prepaid expenses |  | 5 |  | - |  | 5 |
Property, plant, and equipment, net |  | 1,291 |  | (104 | ) | 1,187 |
Intangible assets |  | 176 |  | (10 | ) | 166 |
Other assets |  | 22 |  | - |  | 22 |
Total assets acquired |  | 1,538 |  | (114 | ) | 1,424 |
Liabilities: |  |  |  |  |  |  |
Accounts payable and accrued liabilities |  | 54 |  | 2 |  | 56 |
Current risk management liabilities |  | 6 |  | - |  | 6 |
Long-term debt |  | 931 |  | - |  | 931 |
Asset retirement obligation |  | 3 |  | - |  | 3 |
Future income tax liabilities |  | 29 |  | (29 | ) | - |
Long-term risk management liabilities |  | 34 |  | - |  | 34 |
Total liabilities assumed |  | 1,057 |  | (27 | ) | 1,030 |
Net assets purchased |  | 481 |  | (87 | ) | 394 |
Goodwill |  | 304 |  | 87 |  | 391 |
Total purchase price |  | 785 |  | - |  | 785 |

B. Disposals

Mexican Equity Investment

On Oct. 8, 2008, TransAlta successfully completed the sale of the Mexican equity investment to InterGen Global Ventures B.V. for a sale price of $334 million. The sale included the plants at both facilities and all associated commercial arrangements.

The details of the sale are as follows:

Contractual proceeds |  |  |  | 334 |
Less: closing costs |  |  |  | (3 | )
Net proceeds excluding cash on hand of $1 million |  |  |  | 331 |
Book value of investment |  |  |  | 420 |
Loss before deferred foreign exchange losses |  |  |  | 89 |
Deferred foreign exchange losses on the net assets of the Mexican equity investment |  | 147 |  |  |
Deferred gains on financial instruments designated as hedges of the net assets of the Mexican equity investment |  | (148 | ) |  |
Income tax expense on financial instruments |  | 9 |  |  |
Deferred foreign exchange losses |  |  |  | 8 |
Loss before income taxes |  |  |  | 97 |
Income tax recovery |  |  |  | 35 |
Net loss |  |  |  | 62 |

Included in the book value of the investment is a provision for representations and warranties of $2 million.

42 | T r a n s A l t a C o r p o r a t i o n

25. Related Party Transactions

On Jan. 1, 2009, TAU and TransAlta Energy Corporation transferred certain generation and transmission assets to a newly formed internal partnership, TransAlta Generation Partnership (“TAGP”), before amalgamating with TransAlta Corporation.

On Dec. 16, 2006, predecessors of TAGP, a firm owned by the Corporation and one of its subsidiaries, entered into an agreement with the partners of the Keephills 3 joint venture project to supply coal for the coal-fired plant. The joint venture project is held in a partnership owned by Keephills 3 Limited Partnership (“K3LP”), a wholly owned subsidiary of the Corporation, and Capital Power Corporation. TAGP will supply coal until the earlier of the permanent closure of the Keephills 3 facility or the early termination of the agreement by TAGP and the partners of the joint venture. As at Dec. 31, 2010, TAGP had received $61 million from K3LP for future coal deliveries. Commercial operation of the Keephills plant is scheduled to commence in the second quarter of 2011. Payments received prior to that date for future coal deliveries are recorded in deferred revenues and will be amortized into revenue over the life of the coal supply agreement when TAGP starts delivering coal for commissioning activities (Note 19).

TAGP operates and maintains three combined-cycle power plants in Ontario, a combined-cycle power plant in Fort Saskatchewan, Alberta, and a cogeneration plant in Lloydminster, Alberta on behalf of TA Cogen, which is a subsidiary of TransAlta. TAGP also provides management services to the Sheerness thermal plant, which is operated by Canadian Utilities Limited.

For the period November 2002 to October 2012, TA Cogen entered into various transportation swap transactions with TransAlta Energy Marketing Corporation (“TEMC”). The business purpose of these transportation swaps is to provide TA Cogen with the delivery of fixed price gas without being exposed to escalating costs of pipeline transportation for two of its plants over the period of the swap. The notional gas volumes in the swap transactions are equal to the total delivered fuel for each of the facilities. Exchange amounts are based on the market value of the contract.

For the period October 2010 to October 2011, TA Cogen entered into physical gas purchase transactions with TEMC for volumes to be consumed by one of its plants.

For the period November 2012 to October 2017, TA Cogen entered into financial and foreign currency swap transactions with TEMC to mitigate the natural gas price exposure at one of its plants.

TEMC has entered into offsetting contracts and therefore has no risk other than counterparty risk.

26. Contingencies

TransAlta is occasionally named as a party in various claims and legal proceedings that arise during the normal course of its business. TransAlta reviews each of these claims, including the nature of the claim, the amount in dispute or claimed and the availability of insurance coverage. Although there can be no assurance that any particular unrecorded claim will be resolved in the Corporation’s favour, the Corporation does not believe that the outcome of any claims or potential claims of which it is currently aware, when taken as a whole, will have a material adverse effect on the Corporation.

27. Commitments

The Corporation has entered into a number of long-term gas purchase agreements, transportation and transmission agreements, royalty, and right-of-way agreements in the normal course of operations.

Approximate future payments under the fixed price purchase contracts, transmission, operating leases, mining agreements, long-term service agreements, interest on long-term debt, and growth project commitments are as follows:

|  | Fixed price |  |  |  |  |  | Coal supply |  | Long-term |  | Interest on |  | Growth |  |  |
|  | gas purchase |  |  |  | Operating |  | and mining |  | service |  | long-term |  | project |  |  |
|  | contracts |  | Transmission |  | leases |  | agreements |  | agreement |  | debt 1 |  | commitments |  | Total |
2011 |  | 8 |  | 1 |  | 14 |  | 55 |  | 19 |  | 237 |  | 106 |  | 440 |
2012 |  | 8 |  | 6 |  | 13 |  | 55 |  | 18 |  | 214 |  | 36 |  | 350 |
2013 |  | 9 |  | 7 |  | 12 |  | 55 |  | 17 |  | 194 |  | - |  | 294 |
2014 |  | 8 |  | 7 |  | 11 |  | 55 |  | 17 |  | 157 |  | - |  | 255 |
2015 |  | 8 |  | 7 |  | 10 |  | 60 |  | 9 |  | 127 |  | - |  | 221 |
2016 and thereafter |  | 22 |  | 12 |  | 52 |  | 320 |  | 3 |  | 960 |  | - |  | 1,369 |
Total |  | 63 |  | 40 |  | 112 |  | 600 |  | 83 |  | 1,889 |  | 142 |  | 2,929 |

1 Includes impact of derivatives.

N o t e s t o C o n s o l i d a t e d F i n a n c i a l S t a t e m e n t s | 43

A. Fixed Price Gas Purchase Contracts

Centralia Gas and the Corporation’s Australia operations have contracts in place for the fixed portion of the gas costs at the plants.

B. Transmission

During 2008, TransAlta entered into several five-year agreements with Bonneville Power Administration Transmission (“BPAT”) to purchase 400 MW of Pacific Northwest transmission network capacity. Provided BPAT can meet certain conditions for delivering the service, the Corporation is committed to taking the services at BPAT’s tariff rate whether it is awarded immediately or delivered in the future after additional facilities are constructed.

C. Operating Leases

TransAlta has operating leases in place for buildings, vehicles, and various types of equipment.

D. Coal Supply and Mining Agreements

At Centralia Thermal, a significant portion of production is subject to short- to medium-term energy sales contracts. Centralia Thermal also has various coal supply and associated rail transport contracts to provide coal for use in production. During 2008, TransAlta entered into various coal supply agreements with three suppliers for the Centralia Thermal plant. The coal supply agreements allow TransAlta to take delivery of coal at fixed volumes and prices, with dates extending to Dec. 31, 2013.

At Alberta Thermal, the mines are operated by a third party who is paid a fixed amount to provide a budgeted supply of coal.

E. Long-Term Service Agreements

TransAlta has various service agreements in place primarily for repairs and maintenance that may be required on turbines at various wind generating facilities.

F. Growth Project Commitments

On Sept. 13, 2010, TransAlta obtained approval from the Board of Directors for a 15 MW efficiency uprate at Unit 3 of its Sundance facility. The total capital cost of the project is estimated to be $27 million with commercial operations expected to begin during the fourth quarter of 2012. As at Dec. 31, 2010, the total capital incurred on this project was $3 million.

As part of the acquisition of Canadian Hydro on Oct. 23, 2009, TransAlta assumed the plans to design, build, and operate Bone Creek, a 19 MW hydro facility in British Columbia. The capital cost of the project is estimated at $48 million, net of expected cost recoveries of $6 million, and is expected to begin commercial operations in the first quarter of 2011. As at Dec. 31, 2010, the total capital incurred on this project was $54 million. The total estimated spend for Bone Creek is less than the amount incurred to date due to the timing of project spend and associated recoveries in 2011.

On Jan. 29, 2009, TransAlta announced two efficiency uprates at its Keephills plant in Alberta. Both Keephills units 1 and 2 will be upgraded by 23 MW each, to a total of 450 MW, and are expected to be operational by the end of 2012. The capital cost of the projects is estimated at $68 million. As at Dec. 31, 2010, the total capital incurred on these projects was $10 million.

Keephills 3 plant construction and associated mine capital costs are anticipated to be approximately $1.9 billion with final payments for goods and services due by 2011. TransAlta’s proportionate share is approximately $988 million. As at Dec. 31, 2010, total spend on this project was $928 million.

Growth project commitments are as follows:

|  |  |  | Keephills |  | Keephills |  |  |  |  |
|  | Sundance |  | Unit 1 |  | Unit 2 |  | Keephills |  |  |
|  | Unit 3 |  | uprate |  | uprate |  | Unit 3 |  | Total |
2011 |  | 7 |  | 14 |  | 25 |  | 60 |  | 106 |
2012 |  | 17 |  | 16 |  | 3 |  | - |  | 36 |
2013 |  | - |  | - |  | - |  | - |  | - |
2014 |  | - |  | - |  | - |  | - |  | - |
2015 |  | - |  | - |  | - |  | - |  | - |
2016 and thereafter |  | - |  | - |  | - |  | - |  | - |
Total |  | 24 |  | 30 |  | 28 |  | 60 |  | 142 |

44 | T r a n s A l t a C o r p o r a t i o n

G. Other

A significant portion of the Corporation’s electricity and thermal sales revenues are subject to PPAs and long-term contracts. Commencing Jan. 1, 2001, a large portion of Alberta’s coal generating assets became subject to long-term PPAs for a period approximating the remaining life of each plant or unit. These PPAs set a production requirement and availability target for each plant or unit and the price at which each MWh will be supplied to the customer. The remaining electrical capacity from these facilities is sold in the open electricity market.

A portion of Poplar Creek’s electrical and all of its steam capacity is committed to the customer under a long-term contract. The remaining electrical capacity may be taken by the customer at market prices or sold on the open electricity market by TransAlta. Other gas-fired facilities in Alberta supply steam and/or electricity to specified customers under long-term contracts with additional requirements for availability, reliability, and other plant-specific performance measures.

Sarnia has 20-year contracts with a customer group with two five-year options for extensions to the contracts. The contracts cover up to 202 MWs, or 40 per cent, of the plant’s maximum capacity. These contracts set payments for peak MWs, total MWhs supplied to the customers, and steam consumed, while TransAlta assumes the availability and heat rate risk. The remaining capacity at Sarnia is available for export to the merchant market, based on market prices. On Sept. 30, 2009, TransAlta entered a new agreement with the Ontario Power Authority to supply up to 444 MWs of electricity to the Ontario electricity market, which expires on Dec. 31, 2025. Electrical production at the remaining Ontario plants is subject to contracts expiring in two to seven years.

Mississauga, Windsor-Essex, and Ottawa have contracts that set availability targets and the price at which the plant will be paid per MWh produced, as well as risk sharing of fuel costs based on market prices. Thermal energy contracts for Mississauga and Windsor expire at the same time as the energy production contracts and are with a different customer base. Ottawa has thermal contracts with three different customers. The contract with the main customer expires at the end of 2022. These contracts set payments for volumes consumed, while TA Cogen assumes the heat rate risk. On Oct. 12, 2007, the Corporation signed an agreement amending the original PPA with the Ontario Electricity Financial Corporation for the Ottawa Cogeneration Power Plant. The agreement was entered into to ensure continued plant production following the expiry of long-term natural gas supply contracts. The agreement is in effect from Nov. 1, 2007 until Dec. 31, 2012.

28. Prior Period Regulatory Decision

In response to complaints filed by San Diego Gas & Electric Company, the California Attorney General, and other government agencies, the Federal Energy Regulatory Commission (“FERC”) ordered TransAlta to refund approximately U.S.$46 million for sales made by it in the organized markets of the California Power Exchange, the California Independent System Operator and the California Department of Water Resources during the 2000-2001 period. In addition, the California parties have sought additional refunds which to date have been rejected by FERC. TransAlta does not believe the California parties will be successful in obtaining additional refunds and is pursuing cost offsets to the refunds awarded by FERC. TransAlta established a U.S.$46 million provision to cover any potential refunds and continues to seek relief from this obligation. A final ruling is not expected in the near future.

29. Segment Disclosures

A. Description of Reportable Segments

The Corporation has three reportable segments as described in Note 1.

Each business segment assumes responsibility for its operating results measured as operating income or loss.

Generation expenses include Energy Trading’s intersegment charge for energy marketing in the amount of $5 million (2009 - $32 million, 2008 - $30 million). The intersegment cost allocation (recovery) decreased for the year ended Dec. 31, 2010 as a result of costs previously borne by the Energy Trading segment and recovered through the intersegment fee being directly charged to the Generation segment in 2010. The change has been applied prospectively and prior periods have not been restated. Energy Trading’s operating expenses are presented net of these intersegment charges.

The accounting policies of the segments are the same as those described in Note 1. Intersegment transactions are accounted for on a cost-recovery basis that approximates market rates.

N o t e s t o C o n s o l i d a t e d F i n a n c i a l S t a t e m e n t s | 45

B. Reported Segment Earnings and Segment Assets

I. Earnings Information

|  |  |  | Energy |  |  |  |  |
Year ended Dec. 31, 2010 |  | Generation |  | Trading |  | Corporate |  | Total |
Revenues |  | 2,778 |  | 41 |  | - |  | 2,819 |
Fuel and purchased power |  | 1,202 |  | - |  | - |  | 1,202 |
|  | 1,576 |  | 41 |  | - |  | 1,617 |
Operations, maintenance, and administration |  | 549 |  | 17 |  | 68 |  | 634 |
Depreciation and amortization |  | 438 |  | 2 |  | 19 |  | 459 |
Taxes, other than income taxes |  | 27 |  | - |  | - |  | 27 |
Intersegment cost allocation |  | 5 |  | (5 | ) | - |  | - |
|  | 1,019 |  | 14 |  | 87 |  | 1,120 |
|  | 557 |  | 27 |  | (87 | ) | 497 |
Foreign exchange gain (Note 8) |  |  |  |  |  |  |  | 10 |
Asset impairment charges (Note 3) |  |  |  |  |  |  |  | (89 | )
Net interest expense (Notes 8 and 17) |  |  |  |  |  |  |  | (178 | )
Earnings before non-controlling interests and income taxes |  |  |  |  |  |  |  | 240 |
|  |  |  | Energy |  |  |  |  |
Year ended Dec. 31, 2009 |  | Generation |  | Trading |  | Corporate |  | Total |
Revenues |  | 2,723 |  | 47 |  | - |  | 2,770 |
Fuel and purchased power |  | 1,228 |  | - |  | - |  | 1,228 |
|  | 1,495 |  | 47 |  | - |  | 1,542 |
Operations, maintenance, and administration |  | 550 |  | 31 |  | 86 |  | 667 |
Depreciation and amortization |  | 453 |  | 4 |  | 18 |  | 475 |
Taxes, other than income taxes |  | 22 |  | - |  | - |  | 22 |
Intersegment cost allocation |  | 32 |  | (32 | ) | - |  | - |
|  | 1,057 |  | 3 |  | 104 |  | 1,164 |
|  | 438 |  | 44 |  | (104 | ) | 378 |
Foreign exchange gain (Note 8) |  |  |  |  |  |  |  | 8 |
Asset impairment charges (Note 3) |  |  |  |  |  |  |  | (16 | )
Net interest expense (Notes 8 and 17) |  |  |  |  |  |  |  | (144 | )
Other income (Note 4) |  |  |  |  |  |  |  | 8 |
Earnings before non-controlling interests and income taxes |  |  |  |  |  |  |  | 234 |
|  |  |  | Energy |  |  |  |  |
Year ended Dec. 31, 2008 |  | Generation |  | Trading |  | Corporate |  | Total |
Revenues |  | 3,005 |  | 105 |  | - |  | 3,110 |
Fuel and purchased power |  | 1,493 |  | - |  | - |  | 1,493 |
|  | 1,512 |  | 105 |  | - |  | 1,617 |
Operations, maintenance, and administration |  | 487 |  | 53 |  | 97 |  | 637 |
Depreciation and amortization |  | 409 |  | 3 |  | 16 |  | 428 |
Taxes, other than income taxes |  | 19 |  | - |  | - |  | 19 |
Intersegment cost allocation |  | 30 |  | (30 | ) | - |  | - |
|  | 945 |  | 26 |  | 113 |  | 1,084 |
|  | 567 |  | 79 |  | (113 | ) | 533 |
Foreign exchange loss (Note 8) |  |  |  |  |  |  |  | (12 | )
Net interest expense (Notes 8 and 17) |  |  |  |  |  |  |  | (110 | )
Equity loss (Note 24) |  |  |  |  |  |  |  | (97 | )
Other income (Note 4) |  |  |  |  |  |  |  | 5 |
Earnings before non-controlling interests and income taxes |  |  |  |  |  |  |  | 319 |

Included above in Generation is $19 million (2009 - $9 million, 2008 - $5 million) of incentives received under a Government of Canada program in respect of power generation from qualifying wind and hydro projects and $3 million of government grants received as a reduction of PP&E.

46 | T r a n s A l t a C o r p o r a t i o n

II. Selected Consolidated Balance Sheets Information

|  |  |  | Energy |  |  |  |  |
As at Dec. 31, 2010 |  | Generation |  | Trading |  | Corporate |  | Total |
Goodwill (Note 14) |  | 487 |  | 30 |  | - |  | 517 |
Total segment assets |  | 9,323 |  | 132 |  | 438 |  | 9,893 |
As at Dec. 31, 2009 |  |  |  |  |  |  |  |  |
Goodwill (Note 14) |  | 404 |  | 30 |  | - |  | 434 |
Total segment assets |  | 9,144 |  | 148 |  | 494 |  | 9,786 |

A portion of goodwill relates to CE Gen, a self-sustaining foreign operation denominated in U.S. dollars.

III. Selected Consolidated Statements of Cash Flows Information

|  |  |  | Energy |  |  |  |  |
Year ended Dec. 31, 2010 |  | Generation |  | Trading |  | Corporate |  | Total |
Capital expenditures |  | 759 |  | - |  | 31 |  | 790 |
Year ended Dec. 31, 2009 |  |  |  |  |  |  |  |  |
Capital expenditures |  | 879 |  | 5 |  | 20 |  | 904 |
Year ended Dec. 31, 2008 |  |  |  |  |  |  |  |  |
Capital expenditures |  | 992 |  | 7 |  | 7 |  | 1,006 |

IV. Depreciation and Amortization on the Consolidated Statements of Cash Flows

The reconciliation between depreciation and amortization reported on the Consolidated Statements of Earnings and the Consolidated Statements of Cash Flows is presented below:

Year ended Dec. 31 |  | 2010 |  | 2009 |  | 2008 |
Depreciation and amortization expense on the Consolidated Statements of Earnings |  | 459 |  | 475 |  | 428 |
Depreciation included in fuel and purchased power |  | 42 |  | 40 |  | 38 |
Accretion expense included in depreciation and amortization expense |  | (21 | ) | (24 | ) | (22 | )
Other |  | 10 |  | 2 |  | 7 |
Depreciation and amortization on the Consolidated Statements of Cash Flows |  | 490 |  | 493 |  | 451 |

C. Geographic Information

I. Revenues

Year ended Dec. 31 |  | 2010 |  | 2009 |  | 2008 |
Canada |  | 1,764 |  | 1,631 |  | 1,839 |
U.S. |  | 951 |  | 1,042 |  | 1,165 |
Australia |  | 104 |  | 97 |  | 106 |
Total revenue |  | 2,819 |  | 2,770 |  | 3,110 |

II. Property, Plant, and Equipment and Goodwill

|  | Property, plant, and |  |  |
|  | equipment (Note 12) |  | Goodwill (Note 14) |
As at Dec. 31 |  | 2010 |  | 2009 |  | 2010 |  | 2009 |
Canada |  | 6,370 |  | 6,201 |  | 447 |  | 360 |
U.S. |  | 1,037 |  | 1,182 |  | 70 |  | 74 |
Australia |  | 170 |  | 176 |  | - |  | - |
Total |  | 7,577 |  | 7,559 |  | 517 |  | 434 |

A change in foreign exchange rates from 2009 to 2010 has resulted in a $44 million decrease in net book value of PP&E and a $4 million decrease in goodwill. The change in foreign exchange rates related to translation of self-sustaining foreign operations does not affect net earnings; rather, any cumulative translation gains and losses are reflected in AOCI.

N o t e s t o C o n s o l i d a t e d F i n a n c i a l S t a t e m e n t s | 47

30. Changes in Non-Cash Operating Working Capital

Year ended Dec. 31 |  | 2010 |  | 2009 |  | 2008 |
(Use) source: |  |  |  |  |  |  |
Accounts receivable |  | (9 | ) | 114 |  | 80 |
Prepaid expenses |  | 6 |  | (7 | ) | 3 |
Income taxes receivable |  | 17 |  | (1 | ) | (20 | )
Inventory |  | 31 |  | (42 | ) | (10 | )
Accounts payable and accrued liabilities |  | (15 | ) | (208 | ) | 157 |
Income taxes payable |  | (2 | ) | (5 | ) | - |
Change in non-cash operating working capital |  | 28 |  | (149 | ) | 210 |

31. Stock-Based Compensation Plans

At Dec. 31, 2010, the Corporation had two types of stock-based compensation plans and an employee share purchase plan.

The Corporation is authorized to grant employees options to purchase up to an aggregate of 13.0 million common shares at prices based on the market price of the shares as determined on the grant date. The Corporation has reserved 13.0 million common shares for issue.

A. Stock Option Plans

I. Canadian Employee Plan

This plan is offered to all full-time and part-time employees in Canada below the level of manager. Options granted under this plan may not be exercised until one year after grant and thereafter at an amount not exceeding 25 per cent of the grant per year on a cumulative basis until the fifth year, after which the entire grant may be exercised until the tenth year, which is the expiry date.

II. U.S. Plan

This plan mirrors the rules of the Canadian plan and is offered to all full-time and part-time employees in the U.S.

III. Australian Phantom Plan

This plan came into effect in 2001 and was offered to all full-time and part-time employees in Australia below the level of manager. Options under this plan are not physically granted; rather, employees receive the equivalent value of shares in cash when exercised. Options granted under this plan may not be exercised until one year after grant and thereafter at an amount not exceeding 25 per cent of the grant per year on a cumulative basis until the fifth year, after which the entire grant may be exercised until the tenth year, which is the expiry date.

The total options outstanding and exercisable under these stock option plans at Dec. 31, 2010 are shown below:

|  | Options outstanding |  | Options exercisable |
|  |  |  | Weighted |  |  |  |  |  |  |
|  | Number |  | average |  | Weighted |  | Number |  | Weighted |
|  | outstanding at |  | remaining |  | average |  | exercisable at |  | average |
|  | Dec.31, 2010 |  | contractual |  | exercise price |  | Dec. 31, 2010 |  | exercise price |
Range of exercise prices (per share) |  | (millions) |  | life (years) |  | (per share) |  | (millions) |  | (per share) |
11.00-17.01 |  | 0.1 |  | 2.6 |  | 14.21 |  | 0.1 |  | 14.21 |
17.02-23.03 |  | 1.2 |  | 7.5 |  | 21.33 |  | 0.4 |  | 18.83 |
23.04-29.05 |  | 0.1 |  | 0.3 |  | 27.70 |  | 0.1 |  | 27.70 |
29.06-35.05 |  | 0.8 |  | 7.1 |  | 32.05 |  | 0.4 |  | 32.06 |
11.00-35.05 |  | 2.2 |  | 6.6 |  | 24.94 |  | 1.0 |  | 24.55 |

48 | T r a n s A l t a C o r p o r a t i o n

The change in the number of options outstanding under the option plans are outlined below:

Year ended Dec. 31 |  | 2010 |  | 2009 |  | 2008 |
|  |  |  | Weighted |  |  |  | Weighted |  |  |  | Weighted |
|  | Number of |  | average |  | Number of |  | average |  | Number of |  | average |
|  | share options |  | exercise price |  | share options |  | exercise price |  | share options |  | exercise price |
|  | (millions) |  | (per share) |  | (millions) |  | (per share) |  | (millions) |  | (per share) |
Outstanding, beginning of year |  | 1.5 |  | 26.36 |  | 1.7 |  | 26.80 |  | 1.2 |  | 19.69 |
Granted |  | 0.9 |  | 22.27 |  | - |  | - |  | 1.0 |  | 32.10 |
Exercised |  | (0.1 | ) | 16.20 |  | - |  | - |  | (0.3 | ) | 20.52 |
Cancelled or expired |  | (0.1 | ) | 26.61 |  | (0.2 | ) | 26.47 |  | (0.2 | ) | 27.96 |
Outstanding, end of year |  | 2.2 |  | 24.94 |  | 1.5 |  | 26.36 |  | 1.7 |  | 26.80 |

B. Performance Share Ownership Plan

Under the terms of the PSOP, which commenced in 1997, the Corporation is authorized to grant to employees and directors up to an aggregate of 4.0 million common shares. During 2010, the authorized amount was increased to 6.5 million common shares. The number of common shares that could be issued under both the PSOP and the share option plans, however, cannot exceed 13.0 million common shares. Participants in the PSOP receive grants which, after three years, make them eligible to receive a set number of common shares or cash equivalent up to the maximum of the grant amount plus any accrued dividends thereon, and the ultimate granting of PSOP in any year is at the discretion of TransAlta’s Human Resource Committee. Once a participant’s PSOP eligibility for an award has been established, 50 per cent of the shares may be released to the participant when the Board of Directors uses share settlements on the awards, while the remaining 50 per cent will be held in trust for one additional year for employees below vice president level, and for two additional years for employees at the vice president level and above. The actual number of common shares or cash equivalent a participant may receive is determined by the percentile ranking of the total shareholder return over three years of the Corporation’s common shares amongst the companies comprising the comparator group. Expense related to this plan is recorded during the period earned, with the corresponding payable recorded in liabilities.

Year ended Dec. 31 (millions) |  | 2010 |  | 2009 |  | 2008 |
Number of awards outstanding, beginning of year |  | 1.0 |  | 0.9 |  | 1.0 |
Granted |  | 1.2 |  | 0.5 |  | 0.2 |
Exercised |  | (0.2 | ) | (0.2 | ) | (0.2 | )
Cancelled or expired |  | (0.3 | ) | (0.2 | ) | (0.1 | )
Number of awards outstanding, end of year |  | 1.7 |  | 1.0 |  | 0.9 |

In 2010, pre-tax PSOP compensation expense was $7 million (2009 - $9 million, 2008 - $7 million), which is included in OM&A expense in the Consolidated Statements of Earnings. In 2010, 166,169 common shares were issued at $23.48 per share. In 2009, 224,591 common shares were issued at $24.30 per share. In 2008, 221,855 common shares were issued at $33.35 per share.

C. Employee Share Purchase Plan

Under the terms of the employee share purchase plan, the Corporation will extend an interest-free loan (up to 30 per cent of an employee’s base salary) to employees below executive level and allow for payroll deductions over a three-year period to repay the loan. Executives are not eligible for this program in accordance with the Sarbanes-Oxley legislation. The Corporation will purchase these common shares on the open market on behalf of employees at prices based on the market price of the shares as determined on the date of purchase. Employee sales of these shares are handled in the same manner. At Dec. 31, 2010, accounts receivable from employees under the plan totalled $2 million (2009 - $3 million).

N o t e s t o C o n s o l i d a t e d F i n a n c i a l S t a t e m e n t s | 49

D. Stock-Based Compensation

At Dec. 31, 2010, the Corporation had 2.2 million outstanding employee stock options (2009 - 1.5 million).

The Corporation uses the fair value method of accounting for awards granted under its stock option plans. On Feb. 1, 2010, 0.9 million stock options were granted at a strike price of $22.46, being the last sale price of board lots of the shares on the Toronto Stock Exchange the day prior to the day the options were granted for Canadian employees, and U.S.$20.75, being the closing sale price on the New York Stock Exchange on the same date for U.S. employees. These options will vest in equal installments over four years starting Feb. 1, 2011 and expire after 10 years. The estimated fair value of these options granted was determined using the Black-Scholes option-pricing model in 2010 and 2008 and the binomial model in 2005 and 2002 using the following assumptions:

|  | 2010 |  | 2008 |  | 2005 |  | 2002 |
Weighted average fair value per option |  | 3.67 |  | 6.31 |  | 6.84 |  | 4.25 |
Risk-free interest rate (%) |  | 2.5 |  | 3.6 |  | 4.3 |  | 5.9 |
Expected life of the options (years) |  | 5 |  | 7 |  | 10 |  | 7 |
Dividend rate (%) |  | 5.1 |  | 3.4 |  | 5.6 |  | 4.9 |
Volatility in the price of the Corporation’s shares (%) |  | 29.7 |  | 23.2 |  | 47.0 |  | 28.3 |

32. Employee Future Benefits

A. Description

The Corporation has registered pension plans in Canada and the U.S. covering substantially all employees of the Corporation in these countries and specific named employees working internationally. These plans have defined benefit and defined contribution options, and in Canada there is an additional supplemental defined benefit plan for certain employees whose annual earnings exceed the Canadian income tax limit. The defined benefit option of the registered pension plans has been closed for new employees for all periods presented.

The latest actuarial valuations for accounting purposes of the registered and supplemental pension plans were as at Dec. 31, 2010. The measurement date used to determine plan assets and accrued benefit obligation was Dec. 31, 2010. The last actuarial valuation for funding purposes of the registered plan was Dec. 31, 2009, and the effective date of the next required valuation for funding purposes is Dec. 31, 2012. The supplemental pension plan is solely the obligation of the Corporation. The Corporation is not obligated to fund the supplemental plan but is obligated to pay benefits under the terms of the plan as they come due. The Corporation has posted a letter of credit in the amount of $62 million to secure the obligations under the supplemental plan.

The Corporation provides other health and dental benefits to the age of 65 for both disabled members and retired members (other post-retirement benefits). The latest actuarial valuation of these other plans was as at Dec. 31, 2010. The measurement date used to determine the accrued benefit obligation was also Dec. 31, 2010.

B. Costs Recognized

The costs recognized during the year on the defined benefit, defined contribution, and other health and dental benefit plans are as follows:

Year ended Dec. 31, 2010 |  | Registered |  | Supplemental |  | Other |  | Total |
Current service cost |  | 2 |  | 2 |  | 2 |  | 6 |
Interest cost |  | 21 |  | 4 |  | 2 |  | 27 |
Actual return on plan assets |  | (28 | ) | - |  | - |  | (28 | )
Actuarial loss (gain) on accrued benefit obligation |  | 30 |  | 8 |  | (3 | ) | 35 |
Difference between expected return and actual return on plan assets |  | 7 |  | - |  | - |  | 7 |
Difference between amortized and actuarial (gain) loss on accrued benefit obligation for the year |  | (26 | ) | (8 | ) | 3 |  | (31 | )
Amortization of net transition asset |  | (9 | ) | - |  | - |  | (9 | )
Defined benefit (income) expense |  | (3 | ) | 6 |  | 4 |  | 7 |
Defined contribution expense |  | 19 |  | - |  | - |  | 19 |
Net expense |  | 16 |  | 6 |  | 4 |  | 26 |

50 | T r a n s A l t a C o r p o r a t i o n

Year ended Dec. 31, 2009 |  | Registered |  | Supplemental |  | Other |  | Total |
Current service cost |  | 2 |  | 1 |  | 2 |  | 5 |
Interest cost |  | 22 |  | 3 |  | 2 |  | 27 |
Actual return on plan assets |  | (38 | ) | - |  | - |  | (38 | )
Actuarial loss on accrued benefit obligation |  | 36 |  | 7 |  | 13 |  | 56 |
Difference between expected return and actual return on plan assets |  | 19 |  | - |  | - |  | 19 |
Difference between amortized and actuarial gain on accrued benefit obligation for the year |  | (33 | ) | (6 | ) | (12 | ) | (51 | )
Amortization of net transition asset |  | (9 | ) | - |  | - |  | (9 | )
Defined benefit (income) expense |  | (1 | ) | 5 |  | 5 |  | 9 |
Defined contribution expense |  | 18 |  | - |  | - |  | 18 |
Net expense |  | 17 |  | 5 |  | 5 |  | 27 |

Year ended Dec. 31, 2008 |  | Registered |  | Supplemental |  | Other |  | Total |
Current service cost |  | 3 |  | 1 |  | 1 |  | 5 |
Interest cost |  | 20 |  | 3 |  | 1 |  | 24 |
Actual return on plan assets |  | 55 |  | - |  | - |  | 55 |
Actuarial gain on accrued benefit obligation |  | (49 | ) | (5 | ) | (4 | ) | (58 | )
Difference between expected return and actual return on plan assets |  | (79 | ) | - |  | - |  | (79 | )
Difference between amortized and actuarial loss on accrued benefit obligation for the year |  | 50 |  | 6 |  | 5 |  | 61 |
Past service cost |  | - |  | 2 |  | - |  | 2 |
Difference between amortized and actual plan amendments of past service costs for the year |  | - |  | (2 | ) | - |  | (2 | )
Amortization of net transition asset |  | (9 | ) | - |  | - |  | (9 | )
Defined benefit (income) expense |  | (9 | ) | 5 |  | 3 |  | (1 | )
Defined contribution expense |  | 17 |  | - |  | - |  | 17 |
Net expense |  | 8 |  | 5 |  | 3 |  | 16 |

In 2010, 2009, and 2008, the entire net expense is related to continuing operations.

C. Status of Plans

The status of the defined benefit and other health and dental benefit plans is as follows:

Year ended Dec. 31, 2010 |  | Registered |  | Supplemental |  | Other |  | Total |
Fair value of plan assets |  | 304 |  | 4 |  | - |  | 308 |
Accrued benefit obligation |  | 382 |  | 66 |  | 29 |  | 477 |
Funded status - plan deficit |  | (78 | ) | (62 | ) | (29 | ) | (169 | )
Amounts not yet recognized in the consolidated financial statements: |  |  |  |  |  |  |  |  |
Unrecognized past service costs |  | - |  | 2 |  | 2 |  | 4 |
Unamortized transition obligation |  | - |  | 1 |  | - |  | 1 |
Unamortized net actuarial losses |  | 103 |  | 23 |  | 6 |  | 132 |
Total recognized in the consolidated financial statements: |  |  |  |  |  |  |  |  |
Accrued benefit asset (liability) |  | 25 |  | (36 | ) | (21 | ) | (32 | )
Amortization period in years |  | 15 |  | 13 |  | 15 |  |  |

Year ended Dec. 31, 2009 |  | Registered |  | Supplemental |  | Other |  | Total |
Fair value of plan assets |  | 299 |  | 3 |  | - |  | 302 |
Accrued benefit obligation |  | 358 |  | 55 |  | 33 |  | 446 |
Funded status - plan deficit |  | (59 | ) | (52 | ) | (33 | ) | (144 | )
Amounts not yet recognized in the consolidated financial statements: |  |  |  |  |  |  |  |  |
Unrecognized past service costs |  | 1 |  | 2 |  | 2 |  | 5 |
Unamortized transition (asset) obligation |  | (9 | ) | 1 |  | - |  | (8 | )
Unamortized net actuarial losses |  | 85 |  | 15 |  | 11 |  | 111 |
Total recognized in the consolidated financial statements: |  |  |  |  |  |  |  |  |
Accrued benefit asset (liability) |  | 18 |  | (34 | ) | (20 | ) | (36 | )
Amortization period in years |  | 14 |  | 14 |  | 15 |  |  |

N o t e s t o C o n s o l i d a t e d F i n a n c i a l S t a t e m e n t s | 51

The current portion of the accrued benefit liability is included in accounts payable and accrued liabilities on the Consolidated Balance Sheets. The long-term portion is included in other assets and deferred credits and other long-term liabilities.

Year ended Dec. 31, 2010 |  | Registered |  | Supplemental |  | Other |  | Total |
Accrued current liabilities |  | - |  | 4 |  | 2 |  | 6 |
Other long-term (assets) liabilities |  | (25 | ) | 32 |  | 19 |  | 26 |
Accrued benefit (asset) liability |  | (25 | ) | 36 |  | 21 |  | 32 |

Year ended Dec. 31, 2009 |  | Registered |  | Supplemental |  | Other |  | Total |
Accrued current liabilities |  | - |  | 3 |  | 2 |  | 5 |
Other long-term (assets) liabilities |  | (18 | ) | 31 |  | 18 |  | 31 |
Accrued benefit (asset) liability |  | (18 | ) | 34 |  | 20 |  | 36 |

D. Contributions

Expected cash flows on the defined benefit and other health and dental benefit plans are as follows:

|  | Registered |  | Supplemental |  | Other |  | Total |
Employer contributions |  |  |  |  |  |  |  |  |
2011 (expected) |  | 3 |  | 4 |  | 3 |  | 10 |
Expected benefit payments |  |  |  |  |  |  |  |  |
2011 |  | 27 |  | 3 |  | 3 |  | 33 |
2012 |  | 27 |  | 3 |  | 2 |  | 32 |
2013 |  | 27 |  | 3 |  | 2 |  | 32 |
2014 |  | 28 |  | 4 |  | 2 |  | 34 |
2015 |  | 28 |  | 4 |  | 2 |  | 34 |
2016-2020 |  | 141 |  | 21 |  | 13 |  | 175 |

E. Plan Assets

The plan assets of the defined benefit and other health and dental benefit plans are as follows:

|  | Registered |  | Supplemental |  | Other |  | Total |
Fair value of plan assets at Dec. 31, 2008 |  | 279 |  | 3 |  | - |  | 282 |
Contributions |  | 7 |  | 3 |  | 2 |  | 12 |
Benefits paid |  | (26 | ) | (3 | ) | (2 | ) | (31 | )
Benefits transferred in 1 |  | 4 |  | - |  | - |  | 4 |
Effect of translation on U.S. plans |  | (3 | ) | - |  | - |  | (3 | )
Actual return on plan assets 2 |  | 38 |  | - |  | - |  | 38 |
Fair value of plan assets at Dec. 31, 2009 |  | 299 |  | 3 |  | - |  | 302 |
Contributions |  | 5 |  | 4 |  | 3 |  | 12 |
Benefits paid |  | (26 | ) | (3 | ) | (3 | ) | (32 | )
Effect of translation on U.S. plans |  | (2 | ) | - |  | - |  | (2 | )
Actual return on plan assets 2 |  | 28 |  | - |  | - |  | 28 |
Fair value of plan assets at Dec. 31, 2010 |  | 304 |  | 4 |  | - |  | 308 |

1 Transfer of pension assets for addition of employees.

2 Net of expenses.

The Corporation’s investment policy is to seek a consistently high investment return over time while maintaining an acceptable level of risk to satisfy the benefit obligations of the pension plans. The goal is to maintain a long-term rate of return on the fund that at least equals the growth of liabilities, currently approximately seven per cent. The pension fund may be invested in a variety of permitted investments, including publicly traded common or preferred shares, rights or warrants, convertible debentures or preferred securities, bonds, debentures, mortgages, notes or other debt instruments of government agencies or corporations, private company securities, guaranteed investment contracts, term deposits, cash or money market securities, and mutual or pooled funds eligible for pension fund investment. The targeted asset allocation is 50 per cent equity and 50 per cent fixed income. Cash and money market instruments may be held from time-to-time as short-term investments or as defensive reserves within the portfolios of each asset class. The fund may invest in derivatives for the purpose of hedging the portfolio or altering the desired mix of the fund. Derivative transactions that leverage the fund in any way are not permitted without the specific approval of the Corporation’s Pension Committee.

52 | T r a n s A l t a C o r p o r a t i o n

The allocation of defined benefit plan assets by major asset category at Dec. 31, 2010 and 2009 is as follows:

Year ended Dec. 31, 2010 (per cent) |  | Registered |  | Supplemental |
Equity securities |  | 51 |  | - |
Debt securities |  | 46 |  | - |
Cash and cash equivalents |  | 3 |  | 100 |
Total |  | 100 |  | 100 |

Year ended Dec. 31, 2009 (per cent) |  | Registered |  | Supplemental |
Equity securities |  | 52 |  | - |
Debt securities |  | 45 |  | - |
Cash and cash equivalents |  | 3 |  | 100 |
Total |  | 100 |  | 100 |

Plan assets do not include any common shares of the Corporation at Dec. 31, 2010. The Corporation charged the registered plan $0.1 million for administrative services provided for the year ended Dec. 31, 2010 (2009 - $0.1 million).

The fair value of the total defined benefit plan assets by major asset category at Dec. 31, 2010 is as follows:

Year ended Dec. 31, 2010 |  | Level I |  | Level II |  | Level III |  | Total |
Equity securities |  | - |  | 147 |  | 9 |  | 156 |
Debt securities |  | - |  | 141 |  | - |  | 141 |
Cash and cash equivalents |  | 7 |  | - |  | - |  | 7 |
Money market investments |  | - |  | 4 |  | - |  | 4 |
Total |  | 7 |  | 292 |  | 9 |  | 308 |

The fair value of the Canadian defined benefit plan assets by major category at Dec. 31, 2010 is as follows:

Year ended Dec. 31, 2010 |  | Level I |  | Level II |  | Level III |  | Total |
Equity securities |  | - |  | 138 |  | 9 |  | 147 |
Debt securities |  | - |  | 128 |  | - |  | 128 |
Cash and cash equivalents |  | 3 |  | - |  | - |  | 3 |
Money market investments |  | - |  | 4 |  | - |  | 4 |
Total |  | 3 |  | 270 |  | 9 |  | 282 |

The fair value of the U.S. defined benefit plan assets by major category at Dec. 31, 2010 is as follows:

Year ended Dec. 31, 2010 |  | Level I |  | Level II |  | Level III |  | Total |
Equity securities |  | - |  | 9 |  | - |  | 9 |
Debt securities |  | - |  | 13 |  | - |  | 13 |
Total |  | - |  | 22 |  | - |  | 22 |

The fair value of the supplemental plan assets by major category at Dec. 31, 2010 is as follows:

Year ended Dec. 31, 2010 |  | Level I |  | Level II |  | Level III |  | Total |
Cash and cash equivalents |  | 4 |  | - |  | - |  | 4 |
Total |  | 4 |  | - |  | - |  | 4 |

N o t e s t o C o n s o l i d a t e d F i n a n c i a l S t a t e m e n t s | 53

F. Accrued Benefit Obligation

The accrued benefit obligation on the defined benefit and other health and dental benefit plans is as follows:

|  | Registered |  | Supplemental |  | Other |  | Total |
Accrued benefit obligation as at Dec. 31, 2008 |  | 324 |  | 47 |  | 20 |  | 391 |
Current service cost |  | 2 |  | 1 |  | 2 |  | 5 |
Interest cost |  | 22 |  | 3 |  | 2 |  | 27 |
Benefits paid |  | (26 | ) | (3 | ) | (2 | ) | (31 | )
Benefits transferred in 1 |  | 4 |  | - |  | - |  | 4 |
Effect of translation on U.S. plans |  | (4 | ) | - |  | (2 | ) | (6 | )
Actuarial loss |  | 36 |  | 7 |  | 13 |  | 56 |
Accrued benefit obligation as at Dec. 31, 2009 |  | 358 |  | 55 |  | 33 |  | 446 |
Current service cost |  | 2 |  | 2 |  | 2 |  | 6 |
Interest cost |  | 21 |  | 4 |  | 2 |  | 27 |
Benefits paid |  | (26 | ) | (3 | ) | (3 | ) | (32 | )
Curtailment |  | (2 | ) | - |  | (1 | ) | (3 | )
Effect of translation on U.S. plans |  | (1 | ) | - |  | (1 | ) | (2 | )
Actuarial loss (gain) |  | 30 |  | 8 |  | (3 | ) | 35 |
Accrued benefit obligation as at Dec. 31, 2010 |  | 382 |  | 66 |  | 29 |  | 477 |

1 Transfer of accrued benefit obligation for addition of employees.

G. Assumptions

The significant actuarial assumptions adopted in measuring the Corporation’s accrued benefit obligation on the defined benefit and other health and dental benefit plans are as follows:

Year ended Dec. 31, 2010 (per cent) |  | Registered |  | Supplemental |  | Other |
Accrued benefit obligation at Dec. 31 |  |  |  |  |  |  |
Discount rate |  | 5.2 |  | 5.3 |  | 5.0 |
Rate of compensation increase |  | 3.0 |  | 3.0 |  | - |
Benefit cost for year ended Dec. 31 |  |  |  |  |  |  |
Discount rate |  | 6.0 |  | 6.0 |  | 5.7 |
Rate of compensation increase |  | 3.0 |  | 3.0 |  | - |
Expected rate of return on plan assets |  | 7.1 |  | - |  | - |
Assumed health care cost trend rate at Dec. 31 |  |  |  |  |  |  |
Health care cost escalation |  | - |  | - |  | 8.5-9.0 | 1
Dental care cost escalation |  | - |  | - |  | 4.0 |
Provincial health care premium escalation |  | - |  | - |  | 6.0 |
Year ended Dec. 31, 2009 (per cent) |  | Registered |  | Supplemental |  | Other |
Accrued benefit obligation at Dec. 31 |  |  |  |  |  |  |
Discount rate |  | 6.0 |  | 6.0 |  | 5.7 |
Rate of compensation increase |  | 3.0 |  | 3.0 |  | - |
Benefit cost for year ended Dec. 31 |  |  |  |  |  |  |
Discount rate |  | 7.2 |  | 7.3 |  | 7.0 |
Rate of compensation increase |  | 3.2 |  | 3.3 |  | - |
Expected rate of return on plan assets |  | 7.1 |  | - |  | - |
Assumed health care cost trend rate at Dec. 31 |  |  |  |  |  |  |
Health care cost escalation |  | - |  | - |  | 9.2-10.5 | 1
Dental care cost escalation |  | - |  | - |  | 4.0 |
Provincial health care premium escalation |  | - |  | - |  | 6.0 |

1 Decreasing gradually to five per cent by 2018 for Canadian plans and by 2017-2020 for U.S. plans and remaining at that level thereafter.

The expected long-term rate of return on plan assets is based on past performance and economic forecasts for the types of investments held by the plan.

54 | T r a n s A l t a C o r p o r a t i o n

H. Sensitivity Analysis

The following changes would occur in the defined benefit and other health and dental benefit plans if there was a change of +/- one percentage point in the discount rate, trend rate, or expected rate of return on plan assets:

Canadian plans: |  |  |  |  |  |  |
Year ended Dec. 31, 2010 |  | Registered |  | Supplemental |  | Other |
1% increase in the discount rate |  |  |  |  |  |  |
Impact on 2010 accrued benefit obligation |  | (33 | ) | (8 | ) | (1 | )
Impact on 2011 estimated expense under IFRS |  | 1 |  | - |  | - |
1% decrease in the discount rate |  |  |  |  |  |  |
Impact on 2010 accrued benefit obligation |  | 39 |  | 10 |  | 2 |
Impact on 2011 estimated expense under IFRS |  | (1 | ) | - |  | - |
1% increase in the trend rate |  |  |  |  |  |  |
Impact on 2010 accrued benefit obligation |  | - |  | - |  | 1 |
1% decrease in the trend rate |  |  |  |  |  |  |
Impact on 2010 accrued benefit obligation |  | - |  | - |  | (1 | )
1% increase in the expected rate of return on plan assets |  |  |  |  |  |  |
Impact on 2011 estimated expense under IFRS |  | (3 | ) | - |  | - |
1% decrease in the expected rate of return on plan assets |  |  |  |  |  |  |
Impact on 2011 estimated expense under IFRS |  | 3 |  | - |  | - |
U.S. plans: |  |  |  |  |  |  |
Year ended Dec. 31, 2010 |  |  |  | Pension |  | Other |
1% increase in the discount rate |  |  |  |  |  |  |
Impact on 2010 accrued benefit obligation |  |  |  | (2 | ) | (1 | )
Impact on 2011 estimated expense under IFRS |  |  |  | - |  | - |
1% decrease in the discount rate |  |  |  |  |  |  |
Impact on 2010 accrued benefit obligation |  |  |  | 3 |  | 1 |
Impact on 2011 estimated expense under IFRS |  |  |  | - |  | - |
1% increase in the trend rate |  |  |  |  |  |  |
Impact on 2010 accrued benefit obligation |  |  |  | - |  | 1 |
1% decrease in the trend rate |  |  |  |  |  |  |
Impact on 2010 accrued benefit obligation |  |  |  | - |  | (1 | )
1% increase in the expected rate of return on plan assets |  |  |  |  |  |  |
Impact on 2011 estimated expense under IFRS |  |  |  | - |  | - |
1% decrease in the expected rate of return on plan assets |  |  |  |  |  |  |
Impact on 2011 estimated expense under IFRS |  |  |  | - |  | - |

N o t e s t o C o n s o l i d a t e d F i n a n c i a l S t a t e m e n t s | 55

33. Joint Ventures

Joint ventures at Dec. 31, 2010 included the following:

Joint venture |  |  |  | Description
Sheerness joint venture |  | 50 | % | Coal-fired plant in Alberta, of which TA Cogen has a 50 per cent interest, operated by Canadian Utilities Limited
Meridian joint venture |  | 50 | % | Cogeneration plant in Alberta, of which TA Cogen has a 50 per cent interest, operated by TransAlta
Fort Saskatchewan joint venture |  | 60 | % | Cogeneration plant in Alberta, of which TA Cogen has a 60 per cent interest, operated by TransAlta
McBride Lake joint venture |  | 50 | % | Wind generation facilities in Alberta operated by TransAlta
Goldfields Power joint venture |  | 50 | % | Gas-fired plant in Australia operated by TransAlta
CE Generation LLC |  | 50 | % | Geothermal and gas plants in the U.S. operated by CE Gen affiliates
Genesee 3 |  | 50 | % | Coal-fired plant in Alberta operated by Capital Power Corporation
Wailuku |  | 50 | % | A run-of-river generation facility in Hawaii operated by MidAmerican Energy Holdings Company
Keephills 3 |  | 50 | % | Coal-fired plant under construction in Alberta. The plant is being developed jointly with Capital Power Corporation and will be operated by TransAlta
Taylor Hydro |  | 50 | % | Hydro facility in Alberta operated by TransAlta
Soderglen |  | 50 | % | Wind generation facilities in Alberta operated by TransAlta
Pingston |  | 50 | % | Hydro facility in British Columbia operated by TransAlta
Project Pioneer |  | 25 | % | Carbon capture and storage facility operated by TransAlta

Summarized information on the results of operations, financial position, and cash flows relating to the Corporation’s pro-rata interests in its jointly controlled corporations was as follows:

|  | 2010 |  | 2009 |  | 2008 |
Results of operations |  |  |  |  |  |  |
Revenues |  | 449 |  | 539 |  | 619 |
Expenses |  | (371 | ) | (409 | ) | (494 | )
Non-controlling interests |  | (7 | ) | (34 | ) | (55 | )
Proportionate share of net earnings |  | 71 |  | 96 |  | 70 |
Cash flows |  |  |  |  |  |  |
Cash flow from operations |  | 133 |  | 111 |  | 273 |
Cash flow used in investing activities |  | (211 | ) | (168 | ) | (376 | )
Cash flow (used in) from financing activities |  | (28 | ) | (60 | ) | 30 |
Proportionate share of decrease in cash and cash equivalents |  | (106 | ) | (117 | ) | (73 | )
Financial position |  |  |  |  |  |  |
Current assets |  | 139 |  | 147 |  | 166 |
Long-term assets |  | 2,512 |  | 2,371 |  | 2,144 |
Current liabilities |  | (87 | ) | (114 | ) | (202 | )
Long-term liabilities |  | (374 | ) | (426 | ) | (503 | )
Non-controlling interests |  | (301 | ) | (325 | ) | (351 | )
Proportionate share of net assets |  | 1,889 |  | 1,653 |  | 1,254 |

34. Subsequent Events

TransAlta has evaluated subsequent events through to the date the consolidated financial statements were issued. TransAlta has not evaluated any subsequent events after that date.

Sundance Unit 1 and 2 Outage

On Dec. 16, 2010 and Dec. 19, 2010, Unit 1 and Unit 2, respectively, of the Sundance facility were shut down due to conditions observed in the boilers at both units. As a result, all 560 MW from both units were unavailable as inspections were carried out to determine the scope of repairs that may be needed. The units cannot be restarted without inspection and approval from the Alberta Boiler Safety Association. As a result of the outage, production was reduced by 182 gigawatt hours for the year ended Dec. 31, 2010.

Under the terms of the PPA for these units, TransAlta notified the PPA Buyer and the Balancing Pool of a force majeure event. Under force majeure, the Corporation is entitled to receive PPA capacity payments and is protected from having to pay penalties for the units’ lack of availability, to the extent the event meets the force majeure criteria set out in the PPA.

On Feb. 8, 2011, the Corporation announced that it had issued a notice of termination for destruction on the Sundance 1 and 2 coal-fired generation units under the terms of the PPA. This action was based on the determination that the physical state of the boilers is such that the units cannot be economically restored to service under the terms of the PPA. Under the PPA, termination for destruction permits the recovery of the net book value specified in the PPA.

On Feb. 18, 2011, the PPA Buyer provided notice that it intends to dispute the notice of force majeure and termination for destruction, and intends to pursue the dispute resolution process as set out under the terms of the PPA. Although no assurance can be given as to the ultimate outcome of these matters, TransAlta believes that they will be resolved in the Corporation’s favour. TransAlta remains committed to continuing to work with the PPA Buyer and the Balancing Pool under the processes established within the PPA.

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