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, 2009, 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 CE Generation, Sheerness, Wailuku, and Genesee 3 joint ventures, which are included in the 2009 consolidated financial statements of the Corporation and constituted $1,576 million and $849 million of total and net assets, respectively, as of December 31, 2009, and $437 million and $79 million of revenues and net earnings, respectively, for the year then ended. Management’s assessment of and conclusion on the effectiveness of internal control over financial reporting also did not include the internal controls of Canadian Hydro Developers, Inc. which is included in the 2009 consolidated financial statements of the Corporation and constituted $1,534 million and $484 million of total and net assets, respectively, as of December 31, 2009, and $29 million of revenues and nil of 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 CE Generation, Sheerness, Wailuku, Genesee 3 joint ventures, and Canadian Hydro Developers, Inc.

In our opinion, TransAlta Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, 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 financial position of TransAlta Corporation as at December 31, 2009 and 2008 and the consolidated results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2009, and our report dated February 23, 2010, expressed an unqualified opinion thereon.

Ernst & Young LLP

Chartered Accountants

Calgary, Canada

February 23, 2010

Consolidated Financial Statements | 3

CONSOLIDATED STATEMENTS OF EARNINGS AND RETAINED EARNINGS

Year ended Dec. 31 (in millions of Canadian dollars except where noted)	2009		2008		2007
Revenues	2,770		3,110		2,775
Fuel and purchased power	(1,228	)	(1,493	)	(1,231	)
	1,542		1,617		1,544
Operations, maintenance, and administration	667		637		577
Depreciation and amortization	475		428		406
Taxes, other than income taxes	22		19		20
	1,164		1,084		1,003
	378		533		541
Foreign exchange gain (loss) (Note 7)	8		(12	)	3
Writedown of mining development costs (Note 3)	(16	)	–		–
Net interest expense (Notes 7 and 17)	(144	)	(110	)	(133	)
Equity loss (Note 24)	–		(97	)	(50	)
Other income (Note 4)	8		5		16
Earnings before non-controlling interests and income taxes	234		319		377
Non-controlling interests (Note 5)	38		61		48
Earnings before income taxes	196		258		329
Income tax expense (Note 6)	15		23		20
Net earnings	181		235		309
Retained earnings
Opening balance	688		763		710
Common share dividends	(235	)	(215	)	(202	)
Shares cancelled under NCIB (Notes 20 and 21)	–		(95	)	(54	)
Closing balance	634		688		763
Weighted average number of common shares outstanding in the year	201		199		202

Net earnings per share, basic and diluted (Note 20)	0.90		1.18		1.53

See accompanying notes.

Consolidated Financial Statements | 5

CONSOLIDATED BALANCE SHEETS

Dec. 31 (in millions of Canadian dollars)	2009		2008
			(Restated, Note 2	)
Cash and cash equivalents (Notes 7 and 24)	82		50
Accounts receivable (Notes 7, 8, 24, and 28)	421		505
Collateral paid (Note 7)	27		37
Prepaid expenses (Note 24)	18		6
Risk management assets (Notes 7, 9, and 10)	144		200
Future income tax assets (Note 6)	17		3
Income taxes receivable	39		61
Inventory (Note 11)	90		51
	838		913
Long-term receivable (Note 12)	49		14
Property, plant, and equipment (Notes 13 and 24)
Cost	11,721		9,932
Accumulated depreciation	(4,143	)	(3,898	)
	7,578		6,034
Goodwill (Notes 14, 24, and 29)	434		142
Intangible assets (Notes 15 and 24)	333		213
Future income tax assets (Note 6)	204		248
Risk management assets (Notes 7, 9, and 10)	224		221
Other assets (Notes 16 and 24)	102		39
Total assets	9,762		7,824
Accounts payable and accrued liabilities (Notes 7 and 24)	521		658
Collateral received (Note 7)	86		24
Risk management liabilities (Notes 7, 9, and 10)	45		148
Income taxes payable	10		15
Future income tax liabilities (Note 6)	57		14
Dividends payable	61		52
Current portion of long-term debt–recourse (Notes 7 and 17)	7		211
Current portion of long-term debt–non-recourse (Notes 7, 17, and 24)	24		33
Current portion of asset retirement obligation (Note 18)	32		45
	843		1,200
Long-term debt–recourse (Notes 7 and 17)	3,857		2,332
Long-term debt–non-recourse (Notes 7, 17, and 24)	554		232
Asset retirement obligation (Notes 18 and 24)	250		252
Deferred credits and other long-term liabilities (Note 19)	136		131
Future income tax liabilities (Notes 6 and 24)	637		596
Risk management liabilities (Notes 7, 9,10, and 24)	78		102
Non-controlling interests (Note 5)	478		469
Common shareholders’ equity
Common shares (Notes 20 and 21)	2,169		1,761
Retained earnings (Note 21)	634		688
Accumulated other comprehensive income (Note 21)	126		61
Total shareholders’ equity	2,929		2,510
Total liabilities and shareholders’ equity	9,762		7,824
Contingencies (Notes 26 and 28)
Commitments (Notes 7 and 27)
Subsequent events (Note 33)

On behalf of the Board:

Donna Soble Kaufman
Director

William D. Anderson

Director

See accompanying notes.

6 | TransAlta Corporation

CONSOLIDATED STATEMENTS OF CASH FLOWS

Year ended Dec. 31 (in millions of Canadian dollars)	2009		2008		2007
Operating activities
Net earnings	181		235		309
Depreciation and amortization (Note 29)	493		451		415
Gain on sale of equipment (Note 4)	–		(5	)	(16	)
Non-controlling interests (Note 5)	38		61		48
Asset retirement obligation accretion (Note 18)	24		22		24
Asset retirement costs settled (Note 18)	(35	)	(37	)	(38	)
Future income taxes (Note 6)	21		1		(34	)
Unrealized loss from risk management activities	2		12		26
Unrealized foreign exchange gain	(11	)	(5	)	(3	)
Writedown of mining development costs (Note 3)	16		–		–
Equity loss (Note 24)	–		97		50
Other non-cash items	–		(4	)	–
	729		828		781
Change in non-cash operating working capital balances (Note 22)	(149	)	210		66
Cash flow from operating activities	580		1,038		847
Investing activities
Acquisition of Canadian Hydro Developers, Inc., net of cash acquired (Note 24)	(766	)	–		–
Additions to property, plant, and equipment	(904	)	(1,006	)	(599	)
Proceeds on sale of property, plant, and equipment	7		30		47
Proceeds on sale of minority interest in Kent Hills (Note 4)	29		–		–
Equity investment	–		–		(20	)
Restricted cash	–		248		57
Long-term receivable (Note 12)	(41	)	(8	)	–
Realized (losses) gains on financial instruments	(16	)	52		107
Loan to equity investment	–		(245	)	–
Proceeds on sale of equity investment (Note 24)	–		332		–
Net increase in collateral received from counterparties	87		–		–
Net decrease in collateral paid to counterparties	7		–		–
Settlement of adjustments on sale of Mexican equity investment	(7	)	–		–
Other	6		16		(2	)
Cash flow used in investing activities	(1,598	)	(581	)	(410	)
Financing activities
Net increase (decrease) in credit facilities (Note 17)	620		(243	)	289
Repayment of long-term debt (Note 17)	(796	)	(308	)	(252	)
Issuance of long-term debt (Note 17)	1,119		502		30
Dividends paid on common shares	(226	)	(212	)	(205	)
Redemption of preferred securities	–		–		(175	)
Funds paid to repurchase common shares under NCIB (Note 21)	–		(130	)	(75	)
Net proceeds on issuance of common shares (Note 20)	398		15		20
Decrease in advances to TransAlta Power	–		–		6
Realized gains on financial instruments	–		12		–
Distributions paid to subsidiaries' non-controlling interests (Note 5)	(58	)	(98	)	(87	)
Other	(4	)	(5	)	5
Cash flow from (used in) financing activities	1,053		(467	)	(444	)
Cash flow from (used in) operating, investing, and financing activities	35		(10	)	(7	)
Effect of translation on foreign currency cash	(3	)	9		(8	)
Increase (decrease) in cash and cash equivalents	32		(1	)	(15	)
Cash and cash equivalents, beginning of year	50		51		66
Cash and cash equivalents, end of year	82		50		51
Cash taxes paid	43		47		75
Cash interest paid	149		106		142
See accompanying notes.

8 | TransAlta Corporation

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 two reportable segments that are supported by a corporate group that provides finance, treasury, tax, legal, environmental health and safety, sustainable development, corporate communications, government relations, information technology, human resources, internal audit, and other administrative support.

The two reportable segments of the Corporation are as follows:

I. Generation

The Generation segment owns coal, gas, wind, geothermal, biomass, and hydro plants in Canada, the United States (“U.S.”), and Australia. It generates its revenues from the sale of electricity, steam, gas, and ancillary services.

II. Commercial Operations & Development (“COD”)

The COD segment derives revenues from the wholesale trading of electricity and other energy-related commodities and derivatives not supported by TransAlta-owned generation assets. COD also utilizes contracts of various durations for the forward sales of electricity and purchases of natural gas and transmission capacity to effectively manage available generating capacity and fuel and transmission needs on behalf of Generation.

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 (Notes 7, 9, 10, 13, 14, 15, 17, 18, 26, 30, and 31).

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 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 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.

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.

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.

Notes to Consolidated Financial Statements | 9

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.

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.

10 | TransAlta Corporation

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.

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

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.

Notes to Consolidated Financial Statements | 11

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.

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 Corporation’s businesses, the market and 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, 2009 and 2008.

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 32). 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 25 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.

12 | TransAlta Corporation

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.

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 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 (“EARL”). 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. Transition obligations and assets arising from the prospective adoption of new accounting standards are amortized over EARL. This method has not been applied to the Centralia plan as it did not qualify because the majority of its members are still active. The U.S. plan is amortized using Estimated Average Remaining Service Life (“EARSL”).

In 2007, the past service costs and actuarial gains and losses on defined benefit plans had been amortized using EARSL (Note 2).

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 ARO 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 accrued 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 30. 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.

Notes to Consolidated Financial Statements | 13

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.

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. Current Year Reclassifications

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

I. Classification of Pension Assets

During 2009, pension assets were classified on the Consolidated Balance Sheets as other assets. In 2008, $9 million was reclassified from deferred credits and other long-term liabilities to other assets in order to present comparable figures.

II. Classification of Collateral

During 2009, collateral paid to counterparties was reclassified on the Consolidated Balance Sheets from accounts receivable to collateral paid in order to be presented separately. In 2008, $37 million was also reclassified from accounts receivable in order to present comparable figures.

During 2009, collateral received from counterparties was reclassified on the Consolidated Balance Sheets from accounts payable to collateral received in order to be presented separately. In 2008, $24 million was also reclassified from accounts payable in order to present comparable figures.

III. Classification of Mining Development Costs

During 2009, mining development costs were classified on the Consolidated Balance Sheets as PP&E. In 2008, $13 million was reclassified from other assets to PP&E in order to present comparable figures.

IV. Classification of Debt

The Corporation’s credit facilities extend for more than one year, and as a result the outstanding balance of the Corporation’s credit facilities has been reclassified from short-term debt to recourse long-term debt on the Consolidated Balance Sheets. In 2008, $443 million was reclassified in order to present comparable figures.

B. Current 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.

14 | TransAlta Corporation

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.

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 9.

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.

C. Prior Year Accounting Changes

I. Employee Future Benefits

During 2008, TransAlta assessed the accounting treatment for the amortization of the past service costs and actuarial gains and losses on defined benefit plans. In prior years, the past service costs and actuarial gains and losses on defined benefit plans had been amortized using EARSL, which was determined by the actuary to be seven years. As a result of the assessment, TransAlta amortized the past service costs and actuarial gains and losses on defined benefit plans under Canadian GAAP using EARL for plans whose members are almost all retired, which is determined by the actuary to be 17 years. As the members of the Canadian Registered Plan are now almost all inactive, starting in 2008 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 will be amortized over EARL.

II. Financial Instruments

On Jan. 1, 2007, TransAlta adopted four new accounting standards that were issued by the CICA: Section 1530, Comprehensive Income, Section 3855, Financial Instruments – Recognition and Measurement, Section 3861, Financial Instruments – Disclosure and Presentation, and Section 3865, Hedges. TransAlta adopted these standards retroactively with an adjustment of opening AOCI solely related to accumulated unrealized foreign currency losses on the translation of self-sustaining foreign operations.

Section 3861 outlines disclosure requirements that are designed to enhance financial statement users’ understanding of the significance of financial instruments to an entity’s financial position, performance, and cash flows. The presentation requirements outlined in this section have been adopted in the Corporation’s financial instruments presentation and related disclosure.

III. Comprehensive Income

Section 1530 introduces comprehensive income, which consists of net earnings and OCI. OCI represents changes in shareholders’ equity during a period arising from transactions and changes in prices, markets, interest rates, and exchange rates and includes unrealized gains and losses on financial assets classified as available-for-sale, unrealized foreign currency translation gains or losses arising from self-sustaining foreign operations, net of hedging activities, and changes in the fair value of the effective portion of cash flow hedging instruments. TransAlta has included in the consolidated financial statements the Consolidated Statements of Comprehensive Income. The cumulative changes in OCI are included in AOCI, which is presented as a new category of shareholders’ equity on the Consolidated Balance Sheets.

Notes to Consolidated Financial Statements | 15

IV. Financial Instruments – Recognition and Measurement

Section 3855 establishes standards for recognizing and measuring financial assets, financial liabilities, and non-financial derivatives. It requires that financial assets and financial liabilities, including derivatives, be recognized on the Consolidated Balance Sheets when the Corporation becomes a party to the contractual provisions of the financial instrument or non-financial derivative contract. Under this standard, all financial instruments are required to be measured at fair value upon initial recognition except for certain related party transactions. 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. 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 and amortized using the effective interest method. 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.

Financial assets and financial liabilities held for trading are measured at fair value with changes in those fair values recognized in net earnings. Financial assets held-to-maturity, 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. 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 effective 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.

Section 3855 also provides an entity the option to designate a financial instrument as held for trading (the fair value option) on its initial recognition or upon adoption of the standard, even if the financial instrument, other than loans and receivables, 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 which 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.

Other significant accounting implications arising upon the adoption of Section 3855 include the use of 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, and the recognition of the inception fair value of the obligation undertaken in issuing a guarantee that meets the definition of a guarantee pursuant to Accounting Guideline 14, Disclosure of Guarantees (“AcG-14”). No subsequent re-measurement at fair value is required unless the financial guarantee qualifies as a derivative. If the financial guarantee meets the definition of a derivative it is remeasured at fair value at each balance sheet date and reported as a derivative in other assets or other liabilities, as appropriate.

In addition, Section 3855 requires that an entity must select an accounting policy of either expensing debt issue costs as incurred or applying them against the carrying value of the related asset or liability. TransAlta is currently applying all eligible debt transaction costs against the carrying value of the debt.

As part of the implementation of Handbook Section 3855, TransAlta selected Jan. 1, 2003 as the transition date with respect to the assessment of embedded derivatives. TransAlta recognizes as separate assets and liabilities only those derivatives embedded in hybrid instruments issued, acquired or substantively modified on or after the selected transition date.

V. Hedges

Section 3865 specifies the criteria that must be satisfied in order for hedge accounting to be applied and the accounting for each of the permitted hedging strategies: fair value hedges, cash flow hedges, and hedges of foreign currency exposures of net investments in self-sustaining foreign operations. Hedge accounting is discontinued prospectively when the derivative no longer qualifies as an effective hedge, or the derivative is terminated or sold, or upon the sale or early termination of the hedged item.

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 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. 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.

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. 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 immediately to net earnings when the hedged item is sold or early terminated, or it is probable that the anticipated transaction will not occur.

16 | TransAlta Corporation

Prior to the adoption of Section 3865, gains and losses on physical and financial swaps, forward sales contracts, futures contracts and options used to hedge the Corporation’s exposure to fluctuations in electricity and natural gas prices related to output from the plants and designated as hedges were recognized in net earnings in the same period and financial statement caption as the hedged exposure (settlement accounting). The derivatives were not recorded on the Consolidated Balance Sheets. Foreign currency forward contracts used to hedge the foreign exchange exposures resulting from anticipated contracts and firm commitments denominated in foreign currencies where hedge criteria were met were not recognized on the Consolidated Balance Sheets. Interest rate swaps used to manage the impact of fluctuating interest rates on existing debt were not recognized on the Consolidated Balance Sheets if they met hedge criteria.

VI. Impact upon adoption of Sections 1530, 3855 and 3865

For hedging relationships existing prior to adopting Section 3865 that continue to qualify for hedge accounting under the new standard, the transition accounting is as follows: (i) fair value hedges – any gain or loss on the hedging instrument was recognized in opening retained earnings and the carrying amount of the hedged item was adjusted by the cumulative change in fair value attributable to the designated hedged risk and was also included in opening retained earnings and (ii) cash flow hedges and hedges of net investments in self-sustaining foreign operations – the effective cumulative portion of any gain or loss on the hedging instrument was recognized in AOCI and the cumulative ineffective portion was included in opening retained earnings.

D. Future Accounting Changes

I. Business Combinations and Non-Controlling Interests

In January 2009, the Accounting Standards Board of Canada (“AcSB”) issued Section 1582, Business Combinations, Section 1601, Consolidated Financial Statements, and Section 1602, Non-controlling Interests which will be adopted concurrently. Section 1582 and Section 1602 propose significant changes with respect to accounting for business combinations and to the accounting and presentation of non-controlling interests, respectively. Section 1601 is a replacement of Section 1600, Consolidated Financial Statements, and its implementation is not expected to have an impact upon the consolidated financial position or results of operations. The Corporation is currently assessing the impact of adopting the above standards on the consolidated financial statements.

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

In 2005, the AcSB announced that accounting standards in Canada are to converge with IFRS. On May 8, 2009, the AcSB re-confirmed that IFRS will be required for interim and annual financial statements commencing on Jan. 1, 2011, with appropriate comparative IFRS financial information for 2010. While IFRS uses a conceptual framework similar to Canadian GAAP, there are significant differences in accounting policies that will be 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 will be required, and costs related to major inspection activities will be recognized as part of the carrying value of PP&E and depreciated over the period until the next major inspection. For employee future benefits, an entity may recognize as at Jan. 1, 2010, all experience and transitional gains and losses related to employee future benefits to retained earnings with subsequent experience gains and losses being recorded in other comprehensive income. Long-term contracts deemed to be finance leases results in the associated PP&E being removed from the Consolidated Balance Sheets and replaced with a long-term receivable representing the present value of lease payments to be received over the life of the contract. Payments received under the contract are recorded in revenue and interest income, dependent upon the interest rate and duration of the contract.

The project is on track and is currently in the solution development and implementation phase. Cross-functional, issue-specific teams have been established to analyze the impacts of adopting IFRS, and focus on developing and implementing specific solutions for convergence.

A steering committee, comprised of senior representatives across the Corporation, has been established to monitor the progress and critical decisions in the transition to IFRS, and continues to meet regularly. Quarterly updates are provided to the Audit and Risk Committee. The Corporation is continuing to assess the impact of adopting these standards on the consolidated financial statements.

3. WRITEDOWN OF MINING DEVELOPMENT COSTS

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, in 2009 the project to develop the Westfields site, has now been placed on hold indefinitely and the costs that have been capitalized were expensed.

4. OTHER INCOME

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

During 2008 and 2007, mining equipment with a net book value of $2 million and $31 million related to the cessation of mining activities at the Centralia coal mine was sold for proceeds of $7 million and $47 million, respectively.

Notes to Consolidated Financial Statements | 17

5. NON-CONTROLLING INTERESTS

A. Consolidated Statements of Earnings

Year ended Dec. 31	2009	2008	2007
Stanley Power’s interest in TransAlta Cogeneration L. P. (Note 32)	23	32	29
25 per cent interest in Saranac Partnership not owned by CE Gen	14	29	19
Natural Forces’ interest in Kent Hills (Note 4)	1	–	–
Total	38	61	48

B. Consolidated Balance Sheets

As at Dec. 31	2009	2008
Stanley Power’s interest in TransAlta Cogeneration L. P.	434	449
25 per cent interest in Saranac Partnership not owned by CE Gen	16	20
Natural Forces’ interest in Kent Hills	28	–
Total	478	469

The change in non-controlling interests is outlined below:

Balance, Dec. 31, 2008	469
Distributions paid	(58	)
Non-controlling interests portion of net earnings	38
Proceeds on sale of minority interest in Kent Hills (Note 4)	29
As at Dec. 31, 2009	478

C. Consolidated Statements of Cash Flows

The allocation of the distributions paid by subsidiaries to non-controlling interests is as follows:

Year ended Dec. 31	2009	2008	2007
Stanley Power	38	59	65
Minority interests of Saranac Partnership	18	39	22
Natural Forces	2	–	–
Total	58	98	87

6. INCOME TAXES

A. Consolidated Statements of Earnings

I. Rate Reconciliations

Year ended Dec. 31	2009		2008		2007
Earnings before income taxes	196		258		329
Equity loss	–		(97	)	(50	)
Earnings before income taxes and equity loss	196		355		379
Statutory Canadian federal and provincial income tax rate (%)	29		30		32
Expected income tax expense	57		105		121
Increase (decrease) in income taxes resulting from:
Lower effective foreign tax rates	(29	)	(24	)	(36	)
Resolution of uncertain tax positions	–		(15	)	(18	)
Tax recovery on sale of Mexican equity investment (Note 24)	–		(35	)	–
Capital taxes	1		1		2
Effect of tax rate changes	(6	)	–		(48	)
Statutory and other rate differences	(4	)	(7	)	(1	)
Other	(4	)	(2	)	–
Income tax expense	15		23		20
Effective tax rate (%)	8		6		5

II. Components of Income Tax Expense

Year ended Dec. 31	2009		2008	2007
Current tax (recovery) expense	(6	)	22	54
Future income tax expense related to the origination and reversal of temporary differences	27		1	14
Future income tax (recovery) expense resulting from changes in tax rates or laws	(6	)	–	(48	)
Income tax expense	15		23	20

18 | TransAlta Corporation

B. Consolidated Balance Sheets

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

As at Dec. 31	2009		2008
Net operating and capital loss carryforwards	297		231
Future site restoration costs	75		71
Property, plant, and equipment	(839	)	(736	)
Risk management assets and liabilities	(82	)	(52	)
Employee future benefits and compensation plans	19		24
Allowance for doubtful accounts	19		22
Other deductible temporary differences	38		81
Net future income tax liability	(473	)	(359	)

7. FINANCIAL INSTRUMENTS

A. Analysis of Financial Assets and Liabilities by Measurement Basis

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

Carrying value of financial instruments as at Dec. 31, 2009
		Derivatives
	Derivatives	classified		Other
	used for	as held	Loans and	financial
	hedging	for trading	receivables	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
Financial liabilities			–
Accounts payable and accrued liabilities	–	–	–	521	521
Collateral received	–	–	–	86	86
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

Carrying value of financial instruments as at Dec. 31, 2008
		Derivatives
	Derivatives	classified		Other
	used for	as held	Loans and	financial
	hedging	for trading	receivables	liabilities	Total
Financial assets
Cash and cash equivalents	–	–	50	–	50
Accounts receivable	–	–	505	–	505
Collateral paid	–	–	37	–	37
Risk management assets
Current	121	79	–	–	200
Long-term	220	1	–	–	221
Financial liabilities
Accounts payable and accrued liabilities	–	–	–	658	658
Collateral received	–	–	–	24	24
Risk management liabilities
Current	74	74	–	–	148
Long-term	96	6	–	–	102
Long-term debt recourse(1)	–	–	–	2,543	2,543
Long-term debt non-recourse(1)	–	–	–	265	265
1 Includes current portion.

Notes to Consolidated Financial Statements | 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 input parameters that are not based on observable market data.

I. Level Determinations and Classifications

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

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 Energy Trading 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.

Energy Trading 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 in Level II. Level II fair values also include fair values 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, Energy Trading 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, 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 (Note 24). Valuation of these contracts must be extrapolated as the lengths of these contracts make reasonably alternate fundamental price forecasts unavailable.

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.

The fair values of the Corporation’s financial assets and liabilities are outlined below:

Total

Fair value(1)

carrying

As at Dec. 31, 2009

Level I

Level II

Level III(3)

Total

value

Financial assets and liabilities measured at fair value

Net risk management assets (liabilities)(2)

–

271

(26

)

245

Financial assets and liabilities measured at other than fair value

Long-term debt

–

4,499

–

4,499

4,442

Total

Fair value(1)

carrying

As at Dec. 31, 2008

Level I

Level II

Level III

Total

value

Financial assets and liabilities measured at fair value

Net risk management assets(2)

170

–

171

Financial assets and liabilities measured at other than fair value

Long-term debt

–

2,542

–

2,542

2,808

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, accounts payable and accrued liabilities, and collateral received).

2 Includes Energy Trading and other risk management assets and liabilities on a net basis (Note 9).

3 Resulting primarily from the acquisition of Canadian Hydro (Note 24).

20 | TransAlta Corporation

II. Fair Values Determined Using Valuation Models (Levels II & III)

Fair values determined using valuation models require the use of assumptions. Where assumptions and inputs are based on readily observable market data, the fair values are categorized as Level II. The key inputs to valuation models and regression or extrapolation formulas include interest rate yield curves, currency rates, credit spreads, implied volatilities, and commodity prices for similar assets or liabilities in active markets, as applicable.

Where the fair values have been developed using valuation models based on unobservable or internally developed assumptions or inputs (Level III Energy Trading Risk Management fair values), the key inputs include historical data such as plant performance, volatilities and correlations between products derived from historical prices, congestion on transmission paths, or demand profiles for individual non-standard deals and structured products. In limited circumstances, an internally-developed fundamental price forecast is used when commodity transactions extend into periods for which market-observable prices are not available.

The effect of using reasonably possible alternative assumptions as inputs to valuation techniques from which the Level III Energy Trading fair values are determined at Dec. 31, 2009 is estimated to be +/- $24 million (2008–nil). This estimate is based on a +/- one standard deviation move from the mean where historical data is used in the valuation. Where an internally-developed fundamental price forecast is used, reasonably alternate fundamental price forecasts sourced from external consultants are included in the estimate. For contracts with terms that extend beyond five years, valuation must be extrapolated as the lengths of these contracts make reasonably alternate fundamental price forecasts unavailable.

The total change in fair value estimated using a valuation technique with unobservable inputs, for financial assets and liabilities measured and recorded at fair value, that was recognized in pre-tax net earnings for the year ended Dec. 31, 2009 was a $1 million gain (2008–$16 million gain). A reconciliation of the movements in risk management fair values by Level, as well as additional Level III gain (loss) information can be found in Note 9.

C. Inception Gains and Losses

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 contracts. The difference yet to be recognized in net earnings and a reconciliation of changes during the period is as follows:

As at Dec. 31	2009		2008		2007
Unamortized gain at beginning of year	2		3		4
New transactions	(1	)	1		4
Recognized in the Consolidated Statements of Earnings during the period:
Amortization	(2	)	(2	)	(5	)
Unamortized (loss) gain at end of year	(1	)	2		3

D. 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 COD segment conducts proprietary trading activities and uses a variety of instruments to manage risk, earn trading revenue, and gain market information.

Notes to Consolidated Financial Statements | 21

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.

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, 2009 associated with the Corporation’s proprietary trading activities was $3 million (2008 – $6 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.

In addition, certain electricity sale contracts do not qualify as NPNS contracts. These contracts are designated as all-in-one hedges and result in a net asset or liability position on the Consolidated Balance Sheets. Upon physical delivery of the commodity, TransAlta receives a gross settlement at the contracted price. Upon receipt of payment, the related net risk management asset or liability is eliminated. If an all-in-one hedge contract cannot be settled by physical delivery of the underlying commodity, it will be settled financially.

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, 2009 associated with the Corporation’s commodity derivative instruments used in generation hedging activities was $45 million (2008–$86 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, 2009 associated with the Corporation’s commodity derivative instruments used in the generation business, but which are not designated as hedges, was nil (2008 – 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 revenues 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, 2009, 2008, and 2007, due to changes in market interest rates affecting the Corporation’s floating rate debt, interest-bearing assets, 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 the most reasonably possible change in market interest rates over the next quarter and is consistent with a +/– one standard deviation move from the mean.

Year ended Dec. 31

2009

2008

2007

Net earnings

increase (1)

OCI loss(1)

increase(1)

OCI loss(1)

increase(1)

OCI loss(1)

50 basis point change

(10

)

–

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

22 | TransAlta Corporation

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, 2009, 2008, and 2007, due to changes in the 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 five cent increase or decrease in these currencies relative to the Canadian dollar is a reasonable potential change over the next quarter and is consistent with a +/- one standard deviation move from the mean.

Year ended Dec. 31	2009		2008		2007
	Net earnings		Net earnings		Net earnings
Currency	decrease(1)	OCI gain(1, 2)	decrease(1)	OCI gain(1, 2)	decrease(1)	OCI gain(1, 2)
U.S.	4	2	4	2	–	4
AUD	1	–	2	–	1	–
Euro	–	–	–	3	1	2
Total	5	2	6	5	2	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, 2009, 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, 2009, without taking into account collateral held, 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 positions, net of any collateral held, at Dec. 31, 2009 was $63 million (2008 - $105 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, 2009:

	Investment	Non-investment
Per cent (%)	grade	grade	Total
Accounts receivable	92	8	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 8.

At Dec. 31, 2009, the Corporation did not have any significant past due trade receivables.

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.

Notes to Consolidated Financial Statements | 23

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

										2015 and
	2010		2011		2012		2013		2014	thereafter	Total
Accounts payable and accrued liabilities	521		—		—		—		—	—	521
Collateral received	86		—		—		—		—	—	86
Debt(1)	29		251		1,090		659		231	2,203	4,463
Energy Trading risk management (assets) liabilities(2)	(112	)	(103	)	(76	)	(12	)	1	31	(271	)
Other risk management liabilities (assets)(2)	15		(7	)	—		—		—	18	26
Interest on long-term debt	224		203		183		170		142	600	1,522
Total	763		344		1,197		817		374	2,852	6,347

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

2 Net risk management assets and liabilities (Note 9).

E. Financial Instruments Provided as Collateral

At Dec. 31, 2009, $45 million (2008 — $63 million) of financial assets, consisting of cash and accounts receivable, related to the Corporation’s proportionate share of CE Gen have been pledged as collateral for certain CE Gen debt. Should any defaults occur the debt-holders would have first claim on these assets.

At Dec. 31, 2009, the Corporation provided $27 million (2008 — $37 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.

F. Financial Assets Held as Collateral

At Dec. 31, 2009, the Corporation received $86 million (2008 — $24 million) in cash as 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.

G. Gains and Losses on Financial Instruments

The Corporation’s COD segment 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. For the year ended Dec. 31, 2009, the COD segment recognized a net unrealized loss of $6 million (2008 – $2 million net unrealized loss, 2007 – $3 million net unrealized loss).

The Corporation’s Generation segment utilizes a variety of derivatives in its operations, including certain commodity hedges 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 unrealized gains or losses from changes in the fair value of derivatives are reported as revenue in the period the change occurs. For the year ended Dec. 31, 2009, the Generation segment recognized a net unrealized gain of $3 million (2008 – $12 million net unrealized loss, 2007 – $30 million net unrealized loss).

Net interest expense as reported on the Consolidated Statements of Earnings includes interest income and expense, respectively, on the Corporation’s interest-bearing financial assets, primarily cash, and its interest-bearing financial liabilities, primarily long-term debt. Interest expense is calculated using the effective interest method (Note 17). Interest rate derivatives that are not designated as hedges are classified as held for trading and are marked-to-market each reporting period with the net gain or loss recorded in net interest expense.

Foreign exchange derivatives that are not designated as hedges are also classified as held for trading, with the net foreign exchange gain or loss on Energy Trading derivatives recorded in revenue, and the net gain or loss on other foreign exchange derivatives recorded in foreign exchange gain (loss) on the Consolidated Statements of Earnings.

Other derivatives that are not designated as hedges are also classified as held for trading, with the net gain or loss recorded in operations, maintenance, and administration expense. Other derivatives consist of a total return swap that fixes a portion of the settlement cost of certain employee compensation and deferred share unit programs. The total return swap is cash settled every quarter.

The table below outlines the net realized and unrealized gains and losses included in net earnings that are associated with derivatives not designated as hedges:

Year ended Dec. 31	2009		2008	2007
Foreign exchange derivatives (losses) gains	(1	)	11	4
Interest rate derivatives losses	–		–	2
Other derivatives gains	–		1	–

24 | TransAlta Corporation

8. ACCOUNTS RECEIVABLE

As at Dec. 31	2009		2008
Gross accounts receivable	470		562
Allowance for doubtful accounts (Note 28)	(49	)	(57	)
Net accounts receivable	421		505

The change in allowance for doubtful accounts is outlined below:

Balance, Dec. 31, 2008			57
Change in foreign exchange rates			(8	)
Balance, Dec. 31, 2009			49

9. RISK MANAGEMENT ASSETS AND LIABILITIES

Risk management assets and liabilities are comprised of two major types: (1) those that are used in the COD and Generation segments in relation to trading activities and certain contracting activities (“Energy Trading”) and (2) those used in hedging non-Energy Trading transactions, such as debt, and the net investment in self-sustaining foreign subsidiaries (“other risk management assets and liabilities”).

The overall balances reported in risk management assets and liabilities are shown below:

As at Dec. 31		2009				2008
	Energy				Energy
Balance Sheet–Totals	Trading	Other		Total	Trading	Other	Total
Risk management assets
Current	144	–		144	176	24	200
Long-term	207	17		224	187	34	221
Risk management liabilities
Current	30	15		45	142	6	148
Long-term	50	28		78	57	45	102
Net risk management assets (liabilities)	271	(26	)	245	164	7	171

Energy Trading

The values of risk management assets and liabilities for Energy Trading are included on the Consolidated Balance Sheets as follows:

As at Dec. 31		2009		2008
Balance Sheet–EnergyTrading	Hedges	Non-hedges	Total	Total
Risk management assets
Current	130	14	144	176
Long-term	202	5	207	187
Risk management liabilities
Current	15	15	30	142
Long-term	47	3	50	57
Net risk management assets	270	1	271	164

The following table illustrates the disclosure on the movements in the fair value of the Corporation’s Energy Trading net risk management assets and liabilities separately by source of valuation during the year ended Dec. 31, 2009:

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 at Dec. 31, 2008

–

163

–

163

–

Changes attributable to:

Acquisition of Canadian Hydro (Note 24)

–

(31

)

–

(31

)

Commodity price changes

–

147

–

)

–

145

–

New contracts entered

–

)

–

Contracts settled

–

(20

)

–

)

–

)

(18

)

–

Change in foreign exchange rates

–

(25

)

–

(25

)

–

Transfers in/out of Level III

–

)

–

)

Net risk management assets (liabilities)
at Dec. 31, 2009

–

297

(27

)

–

297

(26

)

Additional Level III gain(loss) information:

Change in fair value included in OCI

–

Unrealized gain(loss) included in earnings before income taxes relating to those net assets
held at Dec. 31, 2009

–

Notes to Consolidated Financial Statements | 25

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

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

											2015 and
		2010		2011	2012		2013		2014		thereafter		Total
Hedges	Level I	–		–	–		–		–		–		–
	Level II	110		99	76		13		(1	)	–		297
	Level III	3		3	(1	)	(1	)	–		(31	)	(27	)
Non-hedges	Level I	–		–	–		–		–		–		–
	Level II	(2	)	1	1		–		–		–		–
	Level III	1		–	–		–		–		–		1
Total	Level I	–		–	–		–		–		–		–
	Level II	108		100	77		13		(1	)	–		297
	Level III	4		3	(1	)	(1	)	–		(31	)	(26	)
Total net assets (liabilities)		112		103	76		12		(1	)	(31	)	271

The Corporation’s outstanding Energy Trading derivative financial instruments at Dec. 31, 2009, were as follows:

	Electricity	Natural gas	Transmission	Oil
Units (000s)	(MWh)	(GJ)	(MWh)	(gallons)
Derivative financial instruments designated as hedges
Notional Amounts
Purchases	–	360	–	25,074
Sales	175,756	2,163	–	–
Derivative financial instruments held for trading (non-hedges)
Notional Amounts
Purchases	14,844	309,764	4,852	–
Sales	14,107	323,793	–	–

Other Risk Management Assets and Liabilities

The risk management assets and liabilities related to other non-Energy Trading are as follows:

As at Dec. 31			2009				2008
Balance Sheet–Other	Hedges		Non-hedges		Total		Total
Risk management assets
Current	–		–		–		24
Long-term	17		–		17		34
Risk management liabilities
Current	13		2		15		6
Long-term	28		–		28		45
Net risk management (liabilities) assets	(24	)	(2	)	(26	)	7

The following table illustrates the disclosure on the movements in the fair value of the Corporation’s other net risk management assets and liabilities separately by source of valuation during the year ended Dec. 31, 2009:

	Hedges		Non-hedges		Total
Net risk management assets (liabilities) at Dec. 31, 2008	8		(1	)	7
Changes in net asset value attributable to:
Market price changes	(20	)	–		(20	)
New contracts entered	(38	)	(2	)	(40	)
Contracts settled	26		1		27
Net risk management liabilities at Dec. 31, 2009	(24	)	(2	)	(26	)

Changes in non-Energy Trading risk management assets and liabilities for hedge positions are reflected within net earnings when such transactions have settled during the period or ineffectiveness exists in the hedging relationship. So long as these hedges remain effective and qualify for hedge accounting, the change in value of existing and new contracts will be deferred in OCI until settlement of the instrument or reduction in the net investment in self-sustaining foreign operations.

26 | TransAlta Corporation

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

							2015 and
	2010		2011	2012	2013	2014	thereafter		Total
Hedges	(13	)	7	–	–	–	(18	)	(24	)
Non-hedges	(2	)	–	–	–	–	–		(2	)
Total net (liabilities) assets	(15	)	7	–	–	–	(18	)	(26	)

Additional information related to other risk management assets and liabilities designated as hedges and non-hedges are outlined below:

A. Hedges

I. Hedges of Foreign Operations

U.S. dollar denominated long-term debt with a face value of U.S.$1,100 million (2008–U.S.$1,100 million) has 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:

a. Cross-Currency Interest Rate Swap

Outstanding liability resulting from cross-currency interest rate swap is as follows:

As at Dec. 31

2009

2008

Notional

Fair value

Notional

Fair value

amount

liability

Maturity

amount

asset

Maturity

AUD34

)

2010

AUD34

2009

b. Foreign Currency Contracts

Outstanding foreign currency forward sales (purchase) contracts are as follows:

As at Dec. 31

2009

2008

Notional

Fair value

Notional

Fair value

amount

liability

Maturity

amount

liability

Maturity

AUD120

)

2010

AUD108

)

2009

U.S.182

)

2010

U.S.(107)

)

2009

II. Hedges of Future Foreign Currency Obligations

a. Foreign Exchange Forward Contract

TransAlta’s future foreign currency obligations are primarily related to foreign denominated capital asset purchases. The Corporation has hedged a portion of these obligations through forward purchase contracts as follows:

As at Dec. 31

2009

2008

Amount

Fair value

Amount

Fair value

sold

purchased

liability

Maturity

sold

purchased

asset

Maturity

U.S.78

)

2010

U.S.48

2009–2010

U.S.14

–

2010

–

AUD4

U.S.3

–

2010

–

EUR57

2009

b. Cross-Currency Interest Rate Swap

Outstanding liability resulting from cross-currency interest rate swap is as follows:

As at Dec. 31

2009

2008

Notional

Fair value

Notional

Fair value

amount

liability

Maturity

amount

asset

Maturity

U.S.(500)

(16

)

2015

–

III. 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 6.65 per cent, to floating rate debt through interest rate swaps as shown below:

As at Dec. 31

2009

2008

Notional

Fair value

Notional

Fair value

amount

asset (liability)

Maturity

amount

asset

Maturity

100

2011

100

2011

U.S.50

)

2013

–

U.S.150

2018

U.S.100

2018

Notes to Consolidated Financial Statements | 27

Including the interest rate swaps above, 31 per cent of the Corporation’s debt is subject to floating interest rates as at Dec. 31, 2009 (2008–24 per cent).

The Corporation also has an outstanding forward start interest rate swap that converts floating rate debt into fixed rate debt. The commencement date for this swap is March 5, 2010, with fixed rates ranging from 3.5 per cent to 4.6 per cent, as shown below:

As at Dec. 31

2009

2008

Notional

Fair value

Notional

Fair value

amount

liability

Maturity

amount

liability

Maturity

U.S.300

)

2020

U.S.300

(46

)

2019

B. Non-Hedges

I. 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) asset resulting from an outstanding cross-currency interest rate swap is as follows:

As at Dec. 31

2009

2008

Notional

Fair value

Notional

Fair value

amount

liability

Maturity

amount

asset

Maturity

AUD13

)

2010

AUD41

2009

II. 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 with these foreign currency forward sales (purchases) are as follows:

As at Dec. 31

2009

2008

Notional

Fair value

Notional

Fair value

amount

liability

Maturity

amount

liability

Maturity

U.S.13

–

2010

U.S.90

)

2009

III. 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 pursued. 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 (Note 7).

C. 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, 2009 the Corporation had posted collateral of $37 million in the form of letters of credit, on derivative instruments in a net liability position. If the credit-risk-contingent features included in certain derivative agreements were triggered, based upon the value of derivatives as at Dec. 31, 2009, the Corporation would be required to post an additional $29 million of collateral to its counterparties.

10. HEDGING ACTIVITIES

Derivative and non-derivative financial instruments are used to manage exposures to interest, commodity prices, currency, credit, and other market risks. When derivatives are used to manage the Corporation’s own exposures, the Corporation determines for each derivative whether hedge accounting can be applied. 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. The derivative must be highly effective in accomplishing the objective of offsetting either changes in the fair value or cash flows attributable to the hedged risk both at inception and over the life of the hedge. If it is determined that the derivative is not highly effective as a hedge, hedge accounting will be discontinued prospectively.

28 | TransAlta Corporation

A. Fair Value Hedges

Interest rate swaps are used to hedge exposures to the changes in a fixed interest rate instrument’s fair value caused by changes in interest rates.

No ineffective portion of fair value hedges was recorded in 2009, 2008, or 2007.

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

Year ended Dec. 31		2009		2008		2007
Instruments in fair value	Location of gain (loss) on the
hedging relationships	Consolidated Statements of Earnings
Interest rate contracts	Net interest expense	20		(26	)	(34	)
Long-term debt	Net interest expense	(20	)	26		34
Net earnings impact		–		–		–

B. Cash Flow Hedges

Forward sale and purchase contracts, as well as foreign exchange 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.

For the year ended Dec. 31, 2009, a pre-tax unrealized gain of $400 million (2008–gain of $327 million, 2007–loss of $57 million) was recorded in OCI for the effective portion of the cash flow hedges, and a pre-tax total of $204 million (2008–$91 million, 2007–$25 million) related to amounts previously related to OCI was reclassified to net earnings. For the year ended Dec. 31, 2009, a realized loss of $2 million (2008–nil, 2007–nil), was recognized in net earnings for ineffectiveness.

Over the next 12 months, the Corporation estimates that $77 million (2008–$17 million after-tax losses) 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.

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

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

Year ended Dec. 31, 2007
	Effective portion
Derivatives in	Pre-tax gain		Location of (loss)	Pre-tax (loss)
cash flow hedging	(loss) recognized		gain reclassified	gain reclassified
relationships	in OCI		from OCI	from OCI
Interest rate	9		Net interest expense	(5	)
Foreign exchange	(10	)	Foreign exchange	–
			Property, plant,
			and equipment	1
Commodity	(56	)	Revenue	30
OCI impact	(57	)	OCI impact	26

Notes to Consolidated Financial Statements | 29

C. Net Investment Hedges

Foreign exchange contracts and foreign currency denominated liabilities are used to manage the Corporation’s foreign currency exposures to net investments in self-sustaining foreign operations having a functional currency other than the Canadian dollar. Foreign denominated expenses are also used to assist in managing foreign currency exposures on net earnings from self-sustaining foreign operations.

For the year ended Dec. 31, 2009, a net after-tax loss of $69 million (2008–gain of $47 million, 2007–gain of $19 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 table summarizes the pre-tax impact of net investment hedges on the Consolidated Statements of Comprehensive Income:

	Pre-tax (losses) gains		Pre-tax losses		Pre-tax (losses) gains
Derivatives in net	recognized in OCI		recognized in OCI		recognized in OCI
investment hedging	for the year ended		for the year ended		for the year ended
relationships	Dec. 31, 2009		Dec. 31, 2008		Dec. 31, 2007
Foreign exchange	(64	)	(37	)	(2	)
Cross currency	(3	)	(62	)	152
Long-term debt	233		(257	)	90
OCI impact	166		(356	)	240

Summary

The following table summarizes the fair values of derivative instruments categorized by their hedging relationships, as well as derivatives that are not designated as hedges:

As at Dec. 31			2009			2008
			Net	Not
	Fair Value	Cash Flow	Investment	Designated
	Hedges	Hedges	Hedges	as a Hedge	Total	Total
Financial derivative assets
Energy Trading	–	332	–	19	351	363
Non-Energy Trading	14	3	–	–	17	58
Total	14	335	–	19	368	421
Financial derivative liabilities
Energy Trading	–	62	–	18	80	199
Non-Energy Trading	1	35	5	2	43	51
Total	1	97	5	20	123	250

Additional information on derivative instruments has been presented on a net basis in Note 9.

11. INVENTORY

Inventory includes coal, natural gas, and emission credits which are valued at the lower of cost and net realizable value.

As at Dec. 31	2009	2008
Coal	86	45
Natural gas	4	5
Purchased emission credits	–	1
Total	90	51

The increase in coal inventory in 2009 compared to 2008 is primarily due to lower production at the Centralia and Alberta Thermal plants.

The change in inventory is outlined below:

Balance, Dec. 31, 2008	51
Net additions	44
Change in foreign exchange rates	(5	)
Balance, Dec. 31, 2009	90

No inventory is pledged as security for liabilities.

For the years ended Dec. 31, 2009 and 2008, no inventory was written down from its carrying value nor were any writedowns recorded in previous periods reversed back into net earnings.

30 | TransAlta Corporation

12. LONG-TERM RECEIVABLE

In 2008, the Corporation received a notice of reassessment from the federal taxation authority in Canada related to the disposal of the Transmission Business in the 2002 taxation year. As a result of the reassessment, the Corporation was required by law to pay approximately $49 million in taxes plus interest and penalties notwithstanding the Corporation’s ability to challenge this reassessment. The Corporation funded a portion of this amount in 2008 by transferring $8 million from its tax prepayment account. Additional cash payments and a loss carryback were applied in 2009 to fund the remaining balance. The Corporation is in the process of challenging this reassessment. Since it is anticipated that the dispute will not be resolved within one year, these prepayments have been recorded as a long-term receivable.

13. PROPERTY, PLANT, AND EQUIPMENT

As at Dec. 31

2009

2008

Accumulated

depreciation

Depreciable

and

Net book

and

Net book

lives

Cost

amortization

value

Cost

amortization

value

Thermal generation equipment

3–50

4,709

2,267

2,442

4,835

1,993

2,842

Mining property & equipment

4–50

795

415

380

776

352

424

Gas generation

2–30

2,135

883

1,252

2,244

1,030

1,214

Geothermal generation

10–20

333

101

232

386

299

Hydro generation

3–60

611

172

439

399

226

173

Wind generation

1,556

125

1,431

375

336

Biomass

15–30

–

Capital spares and other

2–15

270

205

228

160

Assets under construction

–

1,038

–

1,038

443

–

443

Coal rights(1)

–

133

134

Land

–

Transmission systems

15–50

Total

11,721

4,143

7,578

9,932

3,898

6,034

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

The Corporation capitalized $36 million of interest to PP&E in 2008 (2008 – $21 million, 2007 – $6 million).

The change in PP&E is outlined below:

			Accumulated
			depreciation
			and		Net book
	Cost		amortization		value
Balance, Dec. 31, 2008	9,932		3,898		6,034
Acquisition of Canadian Hydro (Note 24)	1,291		–		1,291
Additions	904		–		904
Disposals	(10	)	(6	)	(4	)
Depreciation	–		463		(463	)
Change in foreign exchange rates	(273	)	(94	)	(179	)
Retirement of assets	(132	)	(118	)	(14	)
Transfers	9		–		9
Balance, Dec. 31, 2009	11,721		4,143		7,578

14. GOODWILL

The change in goodwill is outlined below:

Balance, Dec. 31, 2008	142
Acquisition of Canadian Hydro (Note 24)	304
Change in foreign exchange rates	(12	)
Balance, Dec. 31, 2009	434

A portion of goodwill in Generation is related to CE Gen, a self-sustaining foreign operation denominated in U.S. dollars (Note 29). Unrealized foreign exchange gains and losses related to the translation of self-sustaining foreign operations do not affect net earnings and as such translation gains and losses are reflected in AOCI.

Notes to Consolidated Financial Statements | 31

15. INTANGIBLE ASSETS

The change in intangible assets is outlined below:

			Accumulated		Net book
	Cost		amortization		value
Balance, Dec. 31, 2008	499		286		213
Acquisition of Canadian Hydro (Note 24)	176		–		176
Change in foreign exchange rates	(68	)	(43	)	(25	)
Amortization	–		31		(31	)
Balance, Dec. 31, 2009	607		274		333

A portion of intangible assets are related to CE Gen, a self-sustaining foreign operation denominated in U.S. dollars. Unrealized foreign exchange gains and losses related to the translation of self-sustaining foreign operations do not affect net earnings and as such translation gains and losses are reflected in AOCI.

16. OTHER ASSETS

As at Dec. 31	2009	2008
Deferred license fees	22	21
Accrued pension benefit asset (Note 31)	18	9
Project development costs	45	4
Keephills 3 transmission deposit	8	–
Other	9	5
Total other assets	102	39

Deferred license fees consist primarily of a license 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 license relates.

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.

Project development costs include external, direct, and incremental costs incurred during the development phase of future power projects.

17. LONG-TERM DEBT AND NET INTEREST EXPENSE

A. Amounts Outstanding

As at Dec. 31			2009					2008
	Carrying					Carrying
	value		Face value		Interest(1)	value		Face value		Interest(1)
Credit facilities(2)	1,063		1,063		1.0%	443		443		2.8	%
Debentures, due 2011 to 2030	1,055		1,076		6.7%	682		681		6.8	%
Senior notes(3)	1,687		1,684		5.9%	1,352		1,344		6.3	%
Non-recourse	578		581		6.3%	265		265		7.4	%
Other	59		59		6.7%	66		66		6.7	%
	4,442		4,463			2,808		2,799
Less: current portion	(31	)	(31	)		(244	)	(244	)
Total long-term debt	4,411		4,432			2,564		2,555

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 2009–U.S.$1,600 million, 2008-U.S.$1,100 million.

A portion of the fixed rate components of debentures and senior notes have 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. Non-recourse debt is not hedged and therefore recorded at cost.

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 revolver 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. The Corporation also has $240 million available in committed bilateral credit facilities all of which mature in 2011.

32 | TransAlta Corporation

Debentures bear interest at fixed rates ranging from 6.4 per cent to 7.3 per cent. The Corporation has converted $100 million fixed interest rate debt with a rate of 6.9 per cent to floating rates through the use of interest rate swaps (Note 9). These interest rate swaps mature in 2011. During 2009, the Corporation issued a total of $600 million in debentures; $200 million was issued in May 2009 at a fixed interest rate of 6.45 per cent, maturing in 2014 and $400 million was issued in November 2009 at a fixed rate of 6.4 per cent, maturing in 2019.

Senior Notes U.S.$300 million of the senior notes bear an interest rate of 5.75 per cent and mature in 2013 and another U.S.$300 million bear an interest rate of 6.75 per cent and mature in 2012. U.S.$500 million bear interest at 6.65 per cent and mature in 2018, and the remaining U.S.$500 million of the senior notes were issued in November 2009 and bear an interest rate of 4.75 per cent and mature in 2015. In addition, the Corporation converted U.S.$50 million and U.S.$150 million fixed interest rate debt with rates of 5.8 per cent and 6.7 per cent, respectively, to floating rates through the use of interest rate swaps (Note 9). These interest rate swaps mature in 2013 and 2018, respectively. A total of U.S.$1,100 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 2010 to 2018 and interest rates ranging from 7.5 per cent to 8.3 per cent. This debt is recorded at cost; the fair value as at Dec. 31, 2009 was U.S.$184 million (2008–U.S.$208 million). Wailuku debt at Dec. 31, 2009 has a cost of U.S.$8 million (2008–U.S.$9 million) and bears interest at a floating rate currently of 1.2 per cent. The Canadian Hydro debt has maturity dates ranging from 2010 to 2018 and interest rates ranging from 5.3 per cent to 10.9 per cent and includes debt with a cost of $355 million and U.S.$20 million. This debt is recorded at cost; the fair value as at Dec. 31, 2009 was $376 million.

Other consist of notes payable for the Windsor Plant which bears 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 which 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.

B. Principal Repayments

2010		29
2011		251
2012		1,090
2013		659
2014		231
2015 and thereafter		2,203
Total(1)		4,463

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

C. Interest Expense

Year ended Dec. 31	2009		2008		2007
Interest on long-term debt	183		177		171
Interest income	(6	)	(46	)	(32	)
Capitalized interest	(36	)	(21	)	(6	)
Other	3		–		–
Net interest expense	144		110		133

The Corporation capitalizes interest during the construction phase of longer-term capital projects. The capitalized interest in 2009 relates primarily to Keephills 3 and associated mine capital, Blue Trail, and Summerview II. In 2008 the capitalized interest related to the Corporation’s investment in Keephills 3 and associated mine capital, Kent Hills, Summerview, and Blue Trail.

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.

Notes to Consolidated Financial Statements | 33

D. Guarantees

I. 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, 2009 totalled $334 million (2008–$430 million) with nil (2008–nil) amounts exercised by third parties under these arrangements. TransAlta has a total of $2.1 billion of committed credit facilities of which $0.7 billion is not drawn and is available as of Dec. 31, 2009, subject to customary borrowing conditions.

18. ASSET RETIREMENT OBLIGATION

A reconciliation between the opening and closing asset retirement obligation balances is provided below:

Balance, Dec. 31, 2008	297
Liabilities incurred in period	3
Liabilities settled in period	(35	)
Accretion expense	24
Revisions in estimated cash flows	10
Acquisition of Canadian Hydro (Note 24)	3
Change in foreign exchange rates	(20	)
	282
Less: current portion	(32	)
Balance, Dec. 31, 2009	250

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

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 2010 and 2072. The majority of the costs will be incurred between 2020 and 2030. 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, 2009, the Corporation had provided a surety bond in the amount of U.S.$192 million (2008–U.S.$192 million) in support of future retirement obligations at the Centralia coal mine. At Dec. 31, 2009, the Corporation had provided letters of credit in the amount of $67 million (2008–$57 million) in support of future retirement obligations at the Alberta mines.

19. DEFERRED CREDITS AND OTHER LONG-TERM LIABILITIES

As at Dec. 31	2009	2008
Deferred coal revenues (Note 25)	51	31
Sale of emission credits	1	7
Power purchase arrangement in limited partnership	21	23
Accrued benefit liability (Note 31)	49	49
Other	14	21
Total deferred credits and other long-term liabilities	136	131

The power purchase arrangement in the limited partnership represents the fair value adjustments for the Sheerness Generating Station to deliver power at less than the prevailing market price at the time of the acquisition of the plant by TransAlta Cogeneration, L.P. (“TA Cogen”). The power purchase arrangement is amortized on a straight-line basis over the life of the contract.

20. COMMON SHARES

A. Issued and Outstanding

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

Year ended Dec. 31	2009		2008
	Common		Common
	shares		shares
	(millions)	Amount	(millions)		Amount
Issued and outstanding, beginning of year	197.6	1,761	200.9		1,781
Issued under stock option plans	–	–	0.4		8
Issued under Performance Share Ownership Plan	0.2	6	0.2		7
Shares purchased under NCIB (Note 21)	–	–	(3.9	)	(35	)
Issued, net of tax(1)	20.6	402	–		–
Issued and outstanding, end of year	218.4	2,169	197.6		1,761

1 Net of issuance costs of $16 million and tax expense of $4 million.

34 | TransAlta Corporation

At Dec. 31, 2009 the Corporation had 1.5 million outstanding employee stock options (2008 – 1.7 million). For the year ended Dec. 31, 2009, no options were exercised.

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 26, 2007.

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, participants are able to purchase additional common shares by reinvesting dividends. Shares purchased under the DRASP plan are acquired in the open market at 100 per cent of the average purchase price of common shares acquired on the Toronto Stock Exchange on the investment dates.

D. Earnings Per Share (“EPS”)

Year ended Dec. 31	2009	2008	2007
Net earnings	181	235	309
Basic and diluted weighted average number of common shares outstanding	201	199	202
Earnings per share
Basic and diluted	0.90	1.18	1.53

The effect of the PSOP does not materially affect the calculation of the total weighted average number of common shares outstanding (Note 30).

21. SHAREHOLDERS’ EQUITY

				Accumulated
				other		Total
	Common	Retained		comprehensive		shareholders’
	shares	earnings		income/(loss)		equity
Balance, Dec. 31, 2008	1,761	688		61		2,510
Net earnings	–	181		–		181
Common shares issued	408	–		–		408
Dividends declared		(235	)			(235	)
Losses on translating net assets of self-sustaining foreign operations, net of hedges and of tax	–	–		(69	)	(69	)
Gains on derivatives designated as cash flow hedges, net of tax	–	–		280		280
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	–	–		(146	)	(146	)
Balance, Dec. 31, 2009	2,169	634		126		2,929

Components of AOCI

As at Dec. 31	2009		2008
Cumulative unrealized (losses) gains on translating self-sustaining foreign operations, net of hedges and of tax	(63	)	6
Cumulative unrealized gains on cash flow hedges, net of tax	189		55
Total accumulated other comprehensive income	126		61

Normal Course Issuer Bid (“NCIB”) program

On May 6, 2009, TransAlta announced plans to renew the NCIB program until May 6, 2010. The Corporation received the approval to purchase, for cancellation, up to 9.9 million of its common shares representing five per cent of the 198 million common shares issued and outstanding as at April 30, 2009. Any purchases undertaken will be made on the open market through the Toronto Stock Exchange at the market price of such shares at the time of acquisition.

No purchases were made under the NCIB program in 2009.

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. For the year ended Dec. 31, 2007, TransAlta purchased 2,371,800 shares at an average of $31.59 per share for a total of $75 million.

Notes to Consolidated Financial Statements | 35

22. CHANGES IN NON-CASH OPERATING WORKING CAPITAL

Year ended Dec. 31	2009		2008		2007
Source (use):
Accounts receivable	114		80		44
Prepaid expenses	(7	)	3		(3	)
Income taxes receivable	(1	)	(20	)	(29	)
Inventory	(42	)	(10	)	22
Accounts payable and accrued liabilities	(208	)	157		32
Income taxes payable	(5	)	–		–
Change in non-cash operating working capital	(149	)	210		66

23. CAPITAL

TransAlta’s components of capital are listed below:

					Increase/
As at Dec. 31	2009		2008		(decrease)
Current portion of long-term debt	31		244		(213	)
Less: cash and cash equivalents	(82	)	(50	)	(32	)
	(51	)	194		(245	)
Long-term debt
Recourse	3,857		2,332		1,525
Non-recourse	554		232		322
Non-controlling interests	478		469		9
Common shareholders’ equity
Common shares	2,169		1,761		408
Retained earnings	634		688		(54	)
AOCI	126		61		65
	7,818		5,543		2,275
Total capital	7,767		5,737		2,030

The long-term portion of recourse debt increased from Dec. 31, 2008 as a result of the issuance of senior notes and debentures primarily related to the acquisition of Canadian Hydro. This increase in long-term debt was partially offset by scheduled repayments and changes in exchange rates.

TransAlta’s strategy for managing capital remained unchanged from Dec. 31, 2008.

TransAlta’s objectives in managing capital are to:

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 capital 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 manages capital in line with those expectations:

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 this ratio to be 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 this ratio to be 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 this ratio to be 55 to 60 per cent.

36 | TransAlta Corporation

These ratios are presented below:

Year ended Dec. 31	2009	2008
Cash flow to interest coverage (times)(1)	4.9	7.2
Cash flow to debt (%)(1)	20.1	31.1
Debt to invested capital (%)	56.1	48.1

1 Last 12 months.

The decrease in cash flow to interest coverage resulted from decreased cash flows from operating activities and higher interest expense. The decrease in cash flow to debt resulted from a decrease in cash flows from operating activities and an increase in debt balances (Note 17). The increase in debt to invested capital resulted from an increase in debt balances (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.

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

These amounts are summarized in the table below:

Year ended Dec. 31	2009		2008		Increase/ (decrease)
Cash flow from operating activities	580		1,038		(458	)
Dividends paid	(226	)	(212	)	(14	)
Capital asset expenditures	(904	)	(1,006	)	102
Net cash outflow	(550	)	(180	)	(370	)

The decrease in the total net cash flows primarily resulted from lower cash flows from operating activities. TransAlta seeks to maintain sufficient cash balances and committed credit facilities to fund periodic net cash outflows related to its business. At Dec. 31, 2009, $0.7 billion of the Corporation’s available credit facilities were not drawn.

While any of the existing debentures are outstanding, the Corporation will not issue or in any other manner become liable for any indebtedness, unless the aggregate principal amount of the Corporation’s indebtedness, as defined in the Corporation’s trust indenture, does not exceed 75 per cent of total capital.

TransAlta’s credit facilities are unsecured and provide funds in either Canadian or U.S. currencies. They contain standard terms and conditions including covenants with respect to financial leverage and cash flow coverage that would be considered typical of bank credit facilities of this nature.

During 2009, the Corporation issued a total of $600 million in debentures; $200 million was issued in May 2009 at a fixed interest rate of 6.45 per cent, maturing in 2014 and $400 million was issued in November 2009 at a fixed rate of 6.4 per cent, maturing in 2019. Both issuances have financial terms and conditions similar to the other debentures of the Corporation. The financial terms and conditions of all other debentures remain unchanged from Dec. 31, 2008. During 2009, the Corporation also issued U.S.$500 million in senior notes at an interest rate of 4.75 per cent and mature in 2015.

During 2009, the Corporation issued 20.8 million common shares for total net proceeds of $408 million.

TransAlta’s formal dividend policy targets to pay shareholders an annual dividend in the range of 60 to 70 per cent of comparable net earnings. TransAlta’s management defines comparable net earnings as net earnings adjusted for items that would not be considered to be part of normal operations.

Notes to Consolidated Financial Statements | 37

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

The allocation of the aggregate purchase price based on the estimated fair values of the assets of Canadian Hydro on the acquisition date is as follows:

Assets:
Cash	19
Accounts receivable	25
Prepaid expenses	5
Property, plant, and equipment	1,291
Intangible assets	176
Development costs	22
Goodwill	304
Total assets acquired		1,842
Liabilities:
Accounts payable and accrued liabilities	54
Current risk management liabilities	6
Long-term risk management liabilities	34
Long-term debt	931
Future income tax liabilities	29
Asset retirement obligation	3
Total liabilities assumed		1,057
Total purchase price		785

The long-term risk management liabilities consist of financial contracts used to hedge exposures to fluctuations in electricity prices. These contracts qualify for hedge accounting treatment.

Although TransAlta does not anticipate material changes to this preliminary allocation, the values may change when the evaluation of fair value information is complete. Any subsequent adjustments will be accounted for in the period incurred.

38 | TransAlta Corporation

B. Disposals

On Oct. 8, 2008, TransAlta successfully completed the sale of the Mexican equity investment to InterGen 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 $2 million (2008–$ 13 million).

During 2007, the Mexican equity investment incurred a loss of $50 million.

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, 2009, TAGP had received $51 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.

CE Gen has entered into contracts with related parties to provide administrative and maintenance services. The total value of these contracts are U.S.$3 million per year for the years ending Dec. 31, 2009 and 2010.

For the period November 2002 to November 2012, one of TransAlta’s subsidiaries, TA Cogen, entered into various transportation swap transactions with TAGP. TAGP operates and maintains TA Cogen’s three combined-cycle power plants in Ontario and a plant in Fort Saskatchewan, Alberta. TAGP also provides management services to the Sheerness thermal plant, which is operated by Canadian Utilities Limited. 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 three of its plants over the period of the swap. The notional gas volume in the swap transactions is equal to the total delivered fuel for each of the facilities. Exchange amounts are based on the market value of the contract. TransAlta entered into an offsetting contract and therefore has no risk other than counterparty risk.

Notes to Consolidated Financial Statements | 39

26. CONTINGENCIES

TransAlta is occasionally named as a party in various claims and legal proceedings which 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 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, interest on long-term debt, and growth project commitments are as follows:

	Fixed price			Coal supply	Long-term	Interest on
	gas purchase		Operating	and mining	service	long-term	Growth project
	contracts	Transmission	leases	agreements	agreement	debt(1)	commitments	Total
2010	8	–	10	51	14	224	497	804
2011	7	2	10	47	16	203	87	372
2012	7	3	9	47	16	183	14	279
2013	7	3	9	47	16	170	–	252
2014	7	3	8	51	16	142	–	227
2015 and thereafter	25	38	56	269	18	600	–	1,006
Total	61	49	102	512	96	1,522	598	2,940

1 Includes impact of derivatives.

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 megawatts (“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 ranging from June 1, 2008 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 Jan. 11, 2010, TransAlta announced the expansion of its existing 96 MW Kent Hills wind facility. The capital cost of the project is estimated at $100 million and is expected to begin commercial operations by the end of 2010. As at Dec. 31, 2009 total capital incurred on this project was $18 million. Natural Forces will have the option to purchase up to a 17 per cent interest in the new operating facility upon completion.

As part of the acquisition of Canadian Hydro on Oct. 23, 2009, TransAlta assumed the plans to design, build, and operate Bone Creek, an 18 MW hydro facility in British Columbia. The capital cost of the project is estimated at $48 million and is expected to begin commercial operations in the first quarter of 2011. As at Dec. 31, 2009, the total capital incurred on this project was $4 million.

40 | TransAlta Corporation

On April 28, 2009, TransAlta announced plans to design, build, and operate Ardenville, a 69 MW wind power project in southern Alberta. The capital cost of the project is estimated at $135 million. Included in the purchase was an operational 3 MW wind power project in southern Alberta. As at Dec. 31, 2009, the total capital incurred on this project was $27 million. Commercial operations of the remainder of the facility are expected to commence in the first quarter of 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 2011 and 2012, respectively. The capital cost of the projects is estimated at $68 million. As at Dec. 31, 2009, the total capital incurred on these projects was $2 million.

On May 27, 2008, TransAlta announced a 66 MW expansion of its Summerview wind farm located in southern Alberta near Pincher Creek. The capital cost of the project is estimated at $123 million with construction commencing in the second quarter of 2009 and commercial operations expected to begin in the first quarter of 2010. As at Dec. 31, 2009, total capital spend on this project was $106 million. Commercial operations commenced on Feb. 23, 2010 and the total capital cost of the project was $123 million (Note 33).

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, 2009, total spend on this project was $707 million.

On June 21, 2007, TAGP entered into an agreement with Bucyrus Canada Limited and Bucyrus International Inc. for the purchase of a dragline to be used primarily in the supply of coal to the Keephills 3 joint venture project. The total dragline purchase costs include approximately $121 million for the purchase of the equipment, and an additional $29 million for the assembly and commissioning of the dragline, for a total of approximately $150 million, with final payments for goods and services due by completion and acceptance of the asset in the third quarter of 2010. As at Dec. 31, 2009, total payments under this agreement were $125 million.

Growth project commitments are as follows:

Keephills

Kent Hills

Bone Creek

Ardenville

Unit 1 uprate

Unit 2 uprate

Summerview

Unit 3

Total

2010

108

238

497

2011

–

2012

–

2013

–

2014

–

2015 and thereafter

–

Total

108

281

598

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. Remaining coal capacity in Alberta is sold on 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 three five-year options for extensions to the contracts. The contracts allow for up to 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. On Sept. 30, 2009, TransAlta signed a new agreement with the Ontario Power Authority to supply up to 444 MWs of electricity to the Ontario electricity market, which was effective on July 1, 2009 and expires on Dec. 31, 2025. The remaining capacity at Sarnia is available for export to the merchant market, based on market prices. Electrical production at the remaining Ontario plants is subject to contracts expiring in three to eight 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 (“OEFC”) 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.

Notes to Consolidated Financial Statements | 41

B. Reported Segment Earnings and Segment Assets

I. Earnings information

Year ended Dec. 31, 2009	Generation		COD		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 7)							8
Writedown of mining development costs (Note 3)							(16	)
Net interest expense (Notes 7 and 17)							(144	)
Other income (Note 4)							8
Earnings before non-controlling interests and income taxes							234

Year ended Dec. 31, 2008	Generation		COD		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 7)							(12	)
Net interest expense (Notes 7 and 17)							(110	)
Equity loss (Note 24)							(97	)
Other income (Note 4)							5
Earnings before non-controlling interests and income taxes							319

Year ended Dec. 31, 2007	Generation		COD		Corporate		Total
Revenues	2,720		55		–		2,775
Fuel and purchased power	(1,231	)	–		–		(1,231	)
	1,489		55		–		1,544
Operations, maintenance, and administration	447		34		96		577
Depreciation and amortization	391		1		14		406
Taxes, other than income taxes	20		–		–		20
Intersegment cost allocation	27		(27	)	–		–
	885		8		110		1,003
	604		47		(110	)	541
Foreign exchange gain (Note 7)							3
Net interest expense (Notes 7 and 17)							(133	)
Equity loss (Note 24)							(50	)
Other income (Note 4)							16
Earnings before non-controlling interests and income taxes							377

Included above in Generation is $9 million (2008–$5 million, 2007–$5 million) of incentives received under a Government of Canada program in respect of power generation from qualifying wind and hydro projects.

Notes to Consolidated Financial Statements | 43

II. Selected Consolidated Balance Sheets information

As at Dec. 31, 2009	Generation	COD	Corporate	Total
Goodwill (Note 14)	404	30	–	434
Total segment assets	9,133	148	481	9,762

As at Dec. 31, 2008
Goodwill (Note 14)	112	30	–	142
Total segment assets	7,119	206	499	7,824

A portion of goodwill is related to CE Gen, a self-sustaining foreign operation denominated in U.S. dollars. Unrealized foreign exchange gains and losses related to the translation of self-sustaining foreign operations do not affect net earnings and as such translation gains and losses are reflected in AOCI.

III. Selected Consolidated Statements of Cash Flows information

Year ended Dec. 31, 2009		Generation		COD		Corporate		Total
Capital expenditures		879		5		20		904

Year ended Dec. 31, 2008
Capital expenditures		992		7		7		1,006

Year ended Dec. 31, 2007
Capital expenditures		577		5		17		599

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

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

Year ended Dec. 31	2009		2008		2007
Depreciation and amortization expense on the Consolidated Statements of Earnings	475		428		406
Depreciation included in fuel and purchased power	40		38		30
Accretion expense included in depreciation and amortization expense	(24	)	(22	)	(24	)
Other	2		7		3
Depreciation and amortization on the Consolidated Statements of Cash Flows	493		451		415

C. Geographic Information

I. Revenues

Year ended Dec. 31	2009	2008	2007
Canada	1,631	1,839	1,742
U.S.	1,042	1,165	932
Australia	97	106	101
Total revenue	2,770	3,110	2,775

II. Property, Plant, and Equipment and Goodwill

	Property, Plant, and
	Equipment (Note 13)		Goodwill (Note 14)
As at Dec. 31	2009	2008	2009	2008
Canada	6,220	4,464	360	57
U.S.	1,182	1,418	74	85
Australia	176	152	–	–
Total	7,578	6,034	434	142

A change in foreign exchange rates from 2008 to 2009 has resulted in a $179 million decrease in net book value of PP&E and a $12 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.

44 | TransAlta Corporation

30. STOCK-BASED COMPENSATION PLANS

At Dec. 31, 2009, 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. Fixed Stock Option Plans

I. Canadian Employee Plan

This plan is offered to all full-time and part-time employees in Canada at or 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.

III. Australian Phantom Plan

This plan came into effect in 2001 and was offered to all full-time and part-time employees in Australia, excluding directors and officers. 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 fixed stock option plans at Dec. 31, 2009 are shown below:

	Options outstanding			Options exercisable
		Weighted
	Number	average	Weighted	Number	Weighted
	outstanding at	remaining	average	exercisable at	average
	Dec. 31, 2009	contractual	exercise price	Dec. 31, 2009	exercise price
Range of exercise prices (per share)	(millions)	life (years)	(per share)	(millions)	(per share)
11.47–17.70	0.2	2.9	14.81	0.2	14.81
17.71–23.94	0.4	4.2	18.81	0.4	18.81
23.95–30.18	0.1	1.3	27.70	0.1	27.70
30.19–36.41	0.8	8.1	32.29	0.2	32.29
11.47–36.41	1.5	5.9	26.36	0.9	22.28

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

Year ended Dec. 31

2009

2008

2007

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

1.7

26.80

1.2

19.69

2.2

20.20

Granted

–

1.0

32.10

–

Exercised

–

(0.3

)

20.52

(0.8

)

21.39

Cancelled or expired

(0.2

)

26.47

(0.2

)

27.96

(0.2

)

17.52

Outstanding, end of year

1.5

26.36

1.7

26.80

1.2

19.69

Notes to Consolidated Financial Statements | 45

B. Performance Share Ownership Plan (“PSOP”)

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. The number of common shares that could be issued under both the PSOP and the share option plans, however, can not 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. Once a participant’s PSOP eligibility has been established, 50 per cent of the shares may be released to the participant, while the remaining 50 per cent will be held in trust for one additional year. 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)	2009		2008		2007
Number of awards outstanding, beginning of year	0.9		1.0		1.2
Granted	0.5		0.2		0.4
Exercised	(0.2	)	(0.2	)	(0.1	)
Cancelled or expired	(0.2	)	(0.1	)	(0.5	)
Number of awards outstanding, end of year	1.0		0.9		1.0

In 2009, PSOP compensation expense was $7 million after-tax (2008–$5 million after-tax, 2007–$7 million after-tax), which is included in OM&A expense in the Consolidated Statements of Earnings. In 2009, 224,591 common shares were issued at $22.08 per share. In 2008, 221,855 common shares were issued at $24.30 per share. In 2007, 103,896 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, 2009, accounts receivable from employees under the plan totalled $3 million (2008–$3 million).

D. Stock-Based Compensation

At Dec. 31, 2009, the Corporation had 1.5 million outstanding employee stock options (2008–1.7 million).

The Corporation uses the fair value method of accounting for awards granted under its fixed stock option plans.

The estimated fair value of these options granted was determined using the Black-Scholes option-pricing model in 2008 and the binomial model in 2005 and 2002 using the following assumptions:

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

31. 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, 2009. The measurement date used to determine plan assets and accrued benefit obligation was Dec. 31, 2009. The last actuarial valuation for funding purposes of the registered plan was Dec. 31, 2007, and the effective date of the next required valuation for funding purposes is Dec. 31, 2010. 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 $58 million to secure the obligations under the supplemental plan.

46 | TransAlta Corporation

The Corporation provides other health and dental benefits to the age of 65 for both disabled members (other post-employment benefits) and retired members (other post-retirement benefits). The latest actuarial valuation of these other plans was as at Dec. 31, 2007. The measurement date used to determine the accrued benefit obligation was also Dec. 31, 2009.

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, 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	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 option expense of registered pension plan	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	(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 costs	–		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 option expense of registered pension plan	17		–		–		17
Net expense	8		5		3		16

Year ended Dec. 31, 2007	Registered		Supplemental		Other		Total
Current service cost	4		2		1		7
Interest cost	19		2		2		23
Actual return on plan assets	(10	)	–		–		(10	)
Actuarial (gain) loss	(15	)	6		(2	)	(11	)
Difference between expected return and actual return on plan assets	(15	)	–		–		(15	)
Difference between amortized and actuarial loss (gain) on accrued benefit obligation for the year	16		(4	)	2		14
Amortization of net transition asset	(9	)	–		–		(9	)
Defined benefit (income) expense	(10	)	6		3		(1	)
Defined contribution option expense of registered pension plan	15		–		–		15
Net expense	5		6		3		14

In 2009, 2008, and 2007, the entire net expense is related to continuing operations.

Notes to Consolidated Financial Statements | 47

C. Status of Plans

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

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 gains	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

Year ended Dec. 31, 2008	Registered		Supplemental		Other		Total
Fair value of plan assets	279		3		–		282
Accrued benefit obligation	324		47		20		391
Funded status–plan deficit	(45	)	(44	)	(20	)	(109	)
Amounts not yet recognized in the consolidated financial statements:
Unrecognized past service costs	–		1		3		4
Unamortized transition (asset) obligation	(18	)	1		–		(17	)
Unamortized net actuarial gains	72		9		–		81
Total recognized in the consolidated financial statements:
Accrued benefit liability	9		(33	)	(17	)	(41	)
Amortization period in years	15		13		15

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, 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

Year ended Dec. 31, 2008	Registered		Supplemental	Other	Total
Accrued current liabilities	–		–	1	1
Other long-term (assets) liabilities	(9	)	33	16	40
Accrued benefit (asset) liability	(9	)	33	17	41

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
2010 (expected)	6	3	3	12
Expected benefit payments
2010	26	3	3	32
2011	27	3	3	33
2012	27	3	3	33
2013	27	3	3	33
2014	28	3	3	34
2015–2019	141	18	14	173

48 | TransAlta Corporation

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, 2007	356		2		–		358
Contributions	3		4		2		9
Benefits paid	(27	)	(3	)	(2	)	(32	)
Effect of translation on U.S. plans	2		–		–		2
Actual return on plan assets(1)	(55	)	–		–		(55	)
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(2)	4		–		–		4
Effect of translation on U.S. plans	(3	)	–		–		(3	)
Actual return on plan assets(1)	38		–		–		38
Fair value of plan assets at Dec. 31, 2009	299		3		–		302

1 Net of expenses.

2 Transfer of pension assets for addition of employees.

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 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.

The allocation of defined benefit plan assets by major asset category at Dec. 31, 2009 and 2008 is as follows:

Year ended Dec. 31, 2009	Registered	Supplemental
Equity securities	52%	–
Debt securities	45%	–
Cash and cash equivalents	3%	100%
Total	100%	100%

Year ended Dec. 31, 2008	Registered	Supplemental
Equity securities	51%	–
Debt securities	48%	–
Cash and cash equivalents	1%	100%
Total	100%	100%

Plan assets do not include any common shares of the Corporation at Dec. 31, 2009. The Corporation charged the registered plan $0.1 million for administrative services provided for the year ended Dec. 31, 2009 (2008 – $0.1 million).

The fair value of the total defined benefit plan assets by major asset category at Dec. 31, 2009 is as follows:

Year ended Dec. 31, 2009	Level I	Level II	Level III	Total
Equity securities	132	11	12	155
Debt securities	125	11	–	136
Cash and cash equivalents	11	–	–	11
Total	268	22	12	302

Notes to Consolidated Financial Statements | 49

The fair value of the Canadian defined benefit plan assets by major category at Dec. 31, 2009 is as follows:

Year ended Dec. 31, 2009	Level I	Level II	Level III	Total
Equity securities	132	–	12	144
Debt securities	125	–	–	125
Cash and cash equivalents	7	–	–	7
Total	264	–	12	276

The fair value of the U.S. defined benefit plan assets by major category at Dec. 31, 2009 is as follows:

Year ended Dec. 31, 2009	Level I	Level II	Level III	Total
Equity securities	–	11	–	11
Debt securities	–	11	–	11
Cash and cash equivalents	1	–	–	1
Total	1	22	–	23

The fair value of the supplemental plan assets by major category at Dec. 31, 2009 is as follows:

Year ended Dec. 31, 2009	Level I	Level II	Level III	Total
Equity securities	–	–	–	–
Debt securities	–	–	–	–
Cash and cash equivalents	3	–	–	3
Total	3	–	–	3

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, 2007	373		49		23		445
Current service cost	3		1		1		5
Past service cost	–		2		–		2
Interest cost	20		3		1		24
Benefits paid	(27	)	(3	)	(2	)	(32	)
Effect of translation on U.S. plans	4		–		1		5
Actuarial gain	(49	)	(5	)	(4	)	(58	)
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

1 Transfer of accrued benefit obligation for addition of employees.

50 | TransAlta Corporation

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, 2009	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

Year ended Dec. 31, 2008	Registered	Supplemental	Other
Accrued benefit obligation at Dec. 31
Discount rate (%)	7.2	7.3	7.1
Rate of compensation increase (%)	3.2	3.3	–
Benefit cost for year ended Dec. 31
Discount rate (%)	5.5	5.5	5.7
Rate of compensation increase (%)	3.7	3.8	–
Expected rate of return on plan assets (%)	7.1	–	–
Assumed health care cost trend rate at Dec. 31
Health care cost escalation (%)	–	–	9.0–10.5	(1)
Dental care cost escalation (%)	–	–	4.0
Provincial health care premium escalation (%)	–	–	2.5

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.

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, 2009	Registered		Supplemental		Other
1% increase in the discount rate
Impact on 2009 accrued benefit obligation	(30	)	(6	)	(1	)
Impact on 2010 estimated expense	(1	)	(1	)	–
1% decrease in the discount rate
Impact on 2009 accrued benefit obligation	35		8		2
Impact on 2010 estimated expense	1		1		–
1% increase in the trend rate
Impact on 2009 accrued benefit obligation	–		–		2
Impact on 2010 estimated expense	–		–		–
1% decrease in the trend rate
Impact on 2009 accrued benefit obligation	–		–		(1	)
Impact on 2010 estimated expense	–		–		–
1% increase in the expected rate of return on plan assets
Impact on 2010 estimated expense	(3	)	–		–
1% decrease in the expected rate of return on plan assets
Impact on 2010 estimated expense	3		–		–

Notes to Consolidated Financial Statements | 51

U.S. plans:

Year ended Dec. 31, 2009	Pension		Other
1% increase in the discount rate
Impact on 2009 accrued benefit obligation	(2	)	(1	)
Impact on 2010 estimated expense	–		–
1% decrease in the discount rate
Impact on 2009 accrued benefit obligation	3		1
Impact on 2010 estimated expense	–		–
1% increase in the trend rate
Impact on 2009 accrued benefit obligation	–		2
Impact on 2010 estimated expense	–		–
1% decrease in the trend rate
Impact on 2009 accrued benefit obligation	–		(1	)
Impact on 2010 estimated expense	–		–
1% increase in the expected rate of return on plan assets
Impact on 2010 estimated expense	–		–
1% decrease in the expected rate of return on plan assets
Impact on 2010 estimated expense	–		–

32. JOINT VENTURES

Joint ventures at Dec. 31, 2009 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 United States 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

52 | TransAlta Corporation

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:

	2009		2008		2007
Results of operations
Revenues	539		619		609
Expenses	(409	)	(494	)	(454	)
Non-controlling interests	(34	)	(55	)	(44	)
Proportionate share of net earnings	96		70		111
Cash flows
Cash flow from operations	111		273		112
Cash flow used in investing activities	(168	)	(376	)	(147	)
Cash flow (used in) from financing activities	(60	)	30		(93	)
Proportionate share of decrease in cash and cash equivalents	(117	)	(73	)	(128	)
Financial position
Current assets	147		166		91
Long-term assets	2,371		2,144		1,924
Current liabilities	(114	)	(202	)	(144	)
Long-term liabilities	(356	)	(503	)	(390	)
Non-controlling interests	(325	)	(351	)	(373	)
Proportionate share of net assets	1,723		1,254		1,108

33. SUBSEQUENT EVENTS

TransAlta has evaluated subsequent events through to Feb. 23, 2010, which represents the date the consolidated financial statements were issued. TransAlta has not evaluated any subsequent events after that date.

Summerview 2

On Feb. 23, 2010, the 66 MW Summerview 2 wind farm began commercial operations on budget and ahead of schedule. The total cost of the project was $123 million.

Kent Hills Expansion

On Jan. 11, 2010, TransAlta announced that it had been awarded a 25-year contract to provide an additional 54 MW of wind power to New Brunswick Power Distribution and Customer Service Corporation. Under the agreement, TransAlta will expand its existing 96 MW Kent Hills wind facility. The total capital cost of the project is estimated to be $100 million and is expected to begin commercial operations by the end of 2010. Natural Forces will have the option to purchase up to a 17 per cent interest in the new operating facility upon completion.

Notes to Consolidated Financial Statements | 53


STEPHEN G. SNYDER	BRIAN BURDEN
President & Chief Executive Officer	Chief Financial Officer
February 23, 2010


STEPHEN G. SNYDER	BRIAN BURDEN
President & Chief Executive Officer	Chief Financial Officer
February 23, 2010