6-K

FORM 6-K
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Report of Foreign Private Issuer

Pursuant to Rule 13a-16 or 15d-16
of the Securities Exchange Act of 1934

For the month of April 2013

TRANSALTA CORPORATION

(Translation of registrant’s name into English)

110-12^th Avenue S.W., Box 1900, Station “M”, Calgary, Alberta, T2P 2M1

(Address of principal executive offices)

Indicate by check mark whether the registrant files or will file annual reports under cover Form 20-F or Form 40-F.

Form 20-F____ Form 40-F    X

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1): ____

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7): ____

Indicate by check mark whether the registrant by furnishing the information contained in this Form is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934.

Yes     _____ No      X

If “Yes” is marked, indicate below the file number assigned to the registrant in connection with Rule 12g3-2(b): 82-________

1

I

The documents listed below in this Section and filed as Exhibits 13.1 and 13.2 to this form 6-K are hereby filed with the Securities and Exchange Commission for the purpose of being and hereby are incorporated by reference into the following registration statements filed by TransAlta Corporation under the Securities Act of 1933, as amended:

Form	Registration No.
S-8	333-72454
S-8	333-101470
F-10	333-185157

13.1	Consolidated comparative interim unaudited financial statements of the registrant for the three month period ended March 31, 2013.
13.2	Management’s Discussion and Analysis of Financial Condition and Results of Operations of the registrant as at and for the period ended March 31, 2013.

II

The document listed below in this Section as 99.1 is being furnished, not filed, and will not be incorporated by reference into any registration statement filed by TransAlta Corporation under the Securities Act of 1933, as amended.

99.1 Press release dated April 23, 2013

2

Signatures

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

TransAlta Corporation

By:	/s/Brett Gellner
	Brett Gellner
	Chief Financial Officer

Date: April 23, 2013

3

EXHIBIT INDEX

13.1	Consolidated comparative interim unaudited financial statements of the registrant for the three month period ended March 31, 2013.
13.2	Management’s Discussion and Analysis of Financial Condition and Results of Operations of the registrant as at and for the period ended March 31, 2013.
31.1	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	Certification of Chief Executive Officer regarding Periodic Report Containing Financial Statements.
32.2	Certification of Chief Financial Officer regarding Periodic Report Containing Financial Statements.
99.1	Press release dated April 23, 2013.

4

Exhibit 31.1

CERTIFICATIONS

I, Dawn L. Farrell, certify that:

1. I have reviewed this quarterly report on Form 6-K of TransAlta Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(c) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

	/s/ Dawn L. Farrell
Dated April 23, 2013	Dawn L. Farrell
	President and Chief Executive Officer

5

Exhibit 31.2

CERTIFICATIONS

I, Brett Gellner, certify that:

1. I have reviewed this quarterly report on Form 6-K of TransAlta Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

c. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

	/s/ Brett Gellner
Dated April 23, 2013	Brett Gellner
	Chief Financial Officer

6

Exhibit 32.1

Certification of Chief Executive Officer

Pursuant to 18 U.S.C. § 1350, as created by Section 906 of the Sarbanes-Oxley Act of 2002, the undersigned officer of TransAlta Corporation (the “Company”) hereby certifies, to such officer’s knowledge, that:

(i) the accompanying Report of Foreign Private Issuer on Form 6-K of the Company (the “Report”) fully complies with the requirements of Section 13(a) or Section 15(d), as applicable, of the Securities Exchange Act of 1934, as amended; and

(ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

	/s/ Dawn L. Farrell
Dated April 23, 2013	Dawn L. Farrell
	President and Chief Executive Officer

7

Exhibit 32.2

Certification of Chief Financial Officer

Pursuant to 18 U.S.C. § 1350, as created by Section 906 of the Sarbanes-Oxley Act of 2002, the undersigned officer of TransAlta Corporation (the “Company”) hereby certifies, to such officer’s knowledge, that:

(i) the accompanying Report of Foreign Private Issuer on Form 6-K of the Company (the “Report”) fully complies with the requirements of Section 13(a) or Section 15(d), as applicable, of the Securities Exchange Act of 1934, as amended; and

(ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

	/s/ Brett Gellner
Dated April 23, 2013	Brett Gellner
	Chief Financial Officer

EX-13.1

TRANSALTA CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF EARNINGS (LOSS)
(in millions of Canadian dollars except per share amounts)
	3 months ended March 31
	2013	2012
Unaudited		(Restated)*
Revenues (Note 5)	540	644
Fuel and purchased power (Note 6)	201	175
Gross margin	339	469
Operations, maintenance, and administration (Note 6)	115	128
Depreciation and amortization	127	129
Inventory writedown (Note 14)	14	34
Taxes, other than income taxes	7	7
Operating income	76	171
Finance lease income	11	2
Equity loss (Note 7)	(4)	-
Gain on sale of assets (Note 4)	-	3
Foreign exchange loss	(1)	(6)
Loss on assumption of pension obligations (Note 3)	(29)	-
Net interest expense (Notes 8 and 11)	(62)	(60)
Earnings (loss) before income taxes	(9)	110
Income tax expense (recovery) (Note 9)	(17)	2
Net earnings	8	108
Net earnings (loss) attributable to:
TransAlta shareholders	(2)	95
Non-controlling interests	10	13
	8	108
Net earnings (loss) attributable to TransAlta shareholders	(2)	95
Preferred share dividends (Note 21)	9	7
Net earnings (loss) attributable to common shareholders	(11)	88
Weighted average number of common shares
outstanding in the period (millions)	258	225
Net earnings (loss) per share attributable to common
shareholders, basic and diluted	(0.04)	0.39
* See Note 2 for prior period restatements.
See accompanying notes.

TRANSALTA CORPORATION / Q1 2013 1

TRANSALTA CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(in millions of Canadian dollars)
	3 months ended March 31
	2013	2012
Unaudited		(Restated)*
Net earnings	8	108
Net actuarial gains (losses) on defined benefit plans, net of tax(1)	7	(9)
Reclassification of losses on derivatives designated as cash flow hedges to non-financial assets, net of tax(2)	1	1
Total items that will not be reclassified subsequently to
net earnings	8	(8)
Gains (losses) on translating net assets of foreign operations	25	(32)
Gains (losses) on financial instruments designated as hedges of foreign operations, net of tax(3)	(21)	21
Gains (losses) on derivatives designated as cash flow hedges, net of tax(4)	14	(9)
Reclassification of gains on derivatives designated as cash flow hedges to net earnings, net of tax(5)	(19)	(9)
Other comprehensive income (loss) of equity investees, net of tax(6)	(2)	-
Total items that may be reclassified subsequently to
net earnings	(3)	(29)
Other comprehensive income (loss)	5	(37)
Total comprehensive income	13	71
Total comprehensive income (loss) attributable to:
Common shareholders	(4)	65
Non-controlling interests	17	6
	13	71

*	See Note 2 for prior period restatements.
(1)	Net of income tax expense of 2 for the three months ended March 31, 2013 (2012 - 3 recovery).
(2)	Net of income tax expense of nil for the three months ended March 31, 2013 (2012 - nil).
(3)	Net of income tax recovery of 3 for the three months ended March 31, 2013 (2012 - 3 expense).
(4)	Net of income tax recovery of 2 for the three months ended March 31, 2013 (2012 - 1 expense).
(5)	Net of income tax expense of 3 for the three months ended March 31, 2013 (2012 - 17 expense).
(6)	Net of income tax recovery of 1 for the three months ended March 31, 2013 (2012 - nil).

See accompanying notes.

TRANSALTA CORPORATION / Q1 2013 2

TRANSALTA CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF FINANCIAL POSITION
(in millions of Canadian dollars)
	March 31, 2013	Dec. 31, 2012	Jan. 1, 2012
Unaudited		(Restated)*	(Restated)*
Cash and cash equivalents (Note 13)	50	27	49
Accounts receivable	457	597	541
Current portion of finance lease receivable	2	2	3
Collateral paid (Note 12)	17	19	45
Prepaid expenses	25	7	8
Risk management assets (Notes 11 and 12)	123	201	391
Inventory (Note 14)	95	93	92
Income taxes receivable	6	3	2
	775	949	1,131
Investments (Note 7)	170	172	193
Long-term receivable	-	-	18
Long-term portion of finance lease receivable	363	357	42
Property, plant, and equipment (Note 15)
Cost	11,641	11,481	11,386
Accumulated depreciation	(4,563)	(4,437)	(4,115)
	7,078	7,044	7,271
Goodwill	447	447	447
Intangible assets	283	284	276
Deferred income tax assets	75	50	169
Risk management assets (Notes 11 and 12)	63	69	99
Other assets (Note 16)	103	90	90
Total assets	9,357	9,462	9,736
Accounts payable and accrued liabilities	450	495	463
Decommissioning and other provisions (Note 17)	25	33	99
Collateral received (Notes 11 and 12)	1	2	16
Risk management liabilities (Notes 11 and 12)	110	167	208
Income taxes payable	5	6	22
Dividends payable (Notes 20 and 21)	76	75	67
Current portion of finance lease obligation (Note 3)	9	-	-
Current portion of long-term debt (Notes 11, 12, and 18)	620	607	316
	1,296	1,385	1,191
Long-term debt (Notes 11, 12, and 18)	3,611	3,610	3,721
Finance lease obligation (Note 3)	12	-	-
Decommissioning and other provisions (Note 17)	287	279	283
Deferred income tax liabilities	424	433	486
Risk management liabilities (Notes 11 and 12)	112	106	142
Deferred credits and other long-term liabilities (Note 19)	303	301	281
Equity
Common shares (Note 20)	2,780	2,726	2,273
Preferred shares (Note 21)	781	781	562
Contributed surplus	9	9	9
Retained earnings (deficit)	(448)	(362)	524
Accumulated other comprehensive loss (Note 22)	(138)	(136)	(94)
Equity attributable to shareholders	2,984	3,018	3,274
Non-controlling interests (Note 10)	328	330	358
Total equity	3,312	3,348	3,632
Total liabilities and equity	9,357	9,462	9,736
* See Note 2 for prior period restatements.
Contingencies (Note 23)
Commitments (Note 24)
See accompanying notes.

TRANSALTA CORPORATION / Q1 2013 3

TRANSALTA CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(in millions of Canadian dollars)
3 months ended March 31, 2013
Unaudited	Common shares	Preferred shares	Contributed surplus	Retained deficit	Accumulated other comprehensive income (loss)(1)	Attributable to shareholders	Attributable to non-controlling interests	Total
Balance, Dec. 31, 2012	2,726	781	9	(362)	(136)	3,018	330	3,348
Net earnings (loss)	-	-	-	(2)	-	(2)	10	8
Other comprehensive income (loss):
Net gains on translating net assets of foreign operations, net of hedges and of tax	-	-	-	-	4	4	-	4
Net gains (losses) on derivatives designated as cash flow hedges, net of tax	-	-	-	-	(11)	(11)	7	(4)
Net actuarial gains on defined benefits plans, net of tax	-	-	-	-	7	7	-	7
Other comprehensive loss of equity investees, net of tax	-	-	-	-	(2)	(2)	-	(2)
Total comprehensive income						(4)	17	13
Common share dividends	-	-	-	(75)	-	(75)	-	(75)
Preferred share dividends	-	-	-	(9)	-	(9)	-	(9)
Distributions to non-controlling interests	-	-	-	-	-	-	(19)	(19)
Common shares issued	54	-	-	-	-	54	-	54
Balance, March 31, 2013	2,780	781	9	(448)	(138)	2,984	328	3,312

TRANSALTA CORPORATION / Q1 2013 4

3 months ended March 31, 2012
(Restated)*
Unaudited	Common shares	Preferred shares	Contributed surplus	Retained earnings	Accumulated other comprehensive income (loss)(1)	Attributable to shareholders	Attributable to non-controlling interests	Total
Balance, Dec. 31, 2011	2,273	562	9	524	(94)	3,274	358	3,632
Net earnings	-	-	-	95	-	95	13	108
Other comprehensive income (loss):
Net losses on translating net assets of
foreign operations, net of hedges and of
tax	-	-	-	-	(11)	(11)	-	(11)
Net losses on derivatives designated
as cash flow hedges, net of tax	-	-	-	-	(10)	(10)	(7)	(17)
Net actuarial losses on defined benefits
plans, net of tax	-	-	-	-	(9)	(9)	-	(9)
Total comprehensive income						65	6	71
Common share dividends	-	-	-	(65)	-	(65)	-	(65)
Preferred share dividends	-	-	-	(7)	-	(7)	-	(7)
Distributions to non-controlling interests	-	-	-	-	-	-	(19)	(19)
Common shares issued	20	-	-	-	-	20	-	20
Balance, March 31, 2012	2,293	562	9	547	(124)	3,287	345	3,632

*	See Note 2 for prior period restatements.
(1)	Refer to Note 22 for details on components of, and changes in, Accumulated other comprehensive income (loss).

See accompanying notes.

TRANSALTA CORPORATION / Q1 2013 5

TRANSALTA CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions of Canadian dollars)
	3 months ended March 31
	2013		2012
Unaudited			(Restated)*
Operating activities
Net earnings (loss)	8		108
Depreciation and amortization (Note 25)	139		140
Gain on sale of assets (Note 4)	-		(3)
Accretion of provisions (Note 17)	4		4
Decommissioning and restoration costs settled (Note 17)	(5)		(6)
Deferred income tax expense (recovery) (Note 9)	(25)		3
Unrealized (gain) loss from risk management activities	41		(69)
Unrealized foreign exchange loss	4		9
Provisions	(7)		-
Equity loss, net of distributions received (Note 7)	4		-
Other non-cash items	16		3
Cash flow from operations before changes in working capital	179		189
Change in non-cash operating working capital balances (Note 26)	77		(6)
Cash flow from operating activities	256		183
Investing activities
Additions to property, plant, and equipment (Note 15)	(125	)	(137)
Additions to intangibles	(7)		(6)
Proceeds on sale of assets (Note 4)	-		3
Realized losses on financial instruments	(2)		(2)
Net decrease in collateral received from counterparties	(1)		-
Net (increase) decrease in collateral paid to counterparties	3		(6)
Decrease in finance lease receivable	1		1
Other	-		(5)
Change in non-cash investing working capital balances	(19)		(12)
Cash flow used in investing activities	(150)		(164)
Financing activities
Net increase (decrease) in borrowings under credit facilities (Note 18)	(33)		40
Repayment of long-term debt (Note 18)	(2)		(2)
Dividends paid on common shares (Note 20)	(20)		(45)
Dividends paid on preferred shares (Note 21)	(9)		(8)
Distributions paid to subsidiaries' non-controlling interests (Note 10)	(19)		(19)
Other	(1)		(3)
Cash flow used in financing activities	(84)		(37)
Cash flow from (used in) operating, investing, and financing activities	22		(18)
Effect of translation on foreign currency cash	1		-
Increase (decrease) in cash and cash equivalents	23		(18)
Cash and cash equivalents, beginning of period	27		49
Cash and cash equivalents, end of period	50		31
Cash income taxes paid	12		15
Cash interest paid	39		46
* See Note 2 for prior period restatements.
See accompanying notes.

TRANSALTA CORPORATION / Q1 2013 6

N O T E S   T O   C O N D E N S E D   C O N S O L I D A T E D   F I N A N C I A L   S T A T E M E N T S

( U N A U D I T E D )

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

1 . A C C O U N T I N G   P O L I C I E S

A. Basis of Preparation

These unaudited interim condensed consolidated financial statements have been prepared in accordance with International Accounting Standard (“IAS”) 34 Interim Financial Reporting using the same accounting policies as those used in TransAlta Corporation’s (“TransAlta” or “the Corporation”) most recent annual consolidated financial statements, except as outlined in Note 2(A). These unaudited interim condensed consolidated financial statements do not include all of the disclosures included in the Corporation’s annual consolidated financial statements. Accordingly, these should be read in conjunction with the Corporation’s most recent annual consolidated financial statements.

The unaudited interim condensed consolidated financial statements include the accounts of the Corporation and the subsidiaries that it controls. Refer to the discussion on the adoption of International Financial Reporting Standards (“IFRS”) 10 Consolidated Financial Statements, found in Note 2(A) for information on the impacts of applying the new IFRS definition of control.

The unaudited interim condensed consolidated financial statements have been prepared on a historical cost basis, except for certain financial assets and liabilities, which are stated at fair value.

These unaudited interim condensed consolidated financial statements reflect all adjustments which consist of normal recurring adjustments and accruals that are, in the opinion of management, necessary for a fair presentation of results. TransAlta’s results are partly seasonal due to the nature of the electricity market and related fuel costs. Higher maintenance costs are ordinarily incurred in the second and third quarters when electricity prices are expected to be lower, as electricity prices generally increase in the winter months in the Canadian market.

These unaudited interim condensed consolidated financial statements were authorized for issue by the Board of Directors on April 22, 2013.

B. Use of Estimates

The preparation of these condensed consolidated financial statements in accordance with IFRS requires management to use judgment and 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 condensed 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 these estimates due to factors such as fluctuations in interest rates, foreign exchange rates, inflation and commodity prices, and changes in economic conditions, legislation and regulations. Refer to Note 2(W) of the 2012 annual consolidated financial statements for a more detailed discussion of the critical accounting judgments and key sources of estimation uncertainty.

TRANSALTA CORPORATION / Q1 2013 7

2 . A C C O U N T I N G   C H A N G E S

A. Adoption of New or Amended IFRS

On Jan. 1, 2013, the Corporation adopted the following new accounting standards that were previously issued by the IASB:

I. IFRS 10 Consolidated Financial Statements

IFRS 10 replaces the parts of IAS 27 Consolidated and Separate Financial Statements that deal with consolidated financial statements and Standing Interpretations Committee (“SIC”) Interpretation 12 Consolidation - Special Purpose Entities. IFRS 10 defines the principle of control, establishes control as the basis for determining when entities are to be consolidated, and provides guidance on how to apply the principle of control to identify whether an investor controls an investee. Under IFRS 10, an investor controls an investee when it has all of the following: (i) power over the investee; (ii) exposure, or rights, to variable returns from the investee; and (iii) the ability to affect those returns.

IFRS 10 was applied retrospectively by the Corporation by reassessing whether, on Jan. 1, 2013, the Corporation had control of all of its previously consolidated entities. As a result of adopting IFRS 10, no changes arose in the entities controlled and consolidated by the Corporation.

II. IFRS 11 Joint Arrangements

IFRS 11 replaces IAS 31 Interests in Joint Ventures and SIC-13 Jointly Controlled Entities – Non-Monetary Contributions by Venturers. IFRS 11 provides for a principles-based approach to the accounting for joint arrangements that requires an entity to recognize its contractual rights and obligations arising from its involvement in joint arrangements. A joint arrangement is an arrangement in which two or more parties have joint control. Under IFRS 11, joint arrangements are classified as either a joint operation or a joint venture, whereas under IAS 31, they were classified as a jointly controlled asset, jointly controlled operation or a jointly controlled entity. IFRS 11 requires the use of the equity method of accounting for interests in joint ventures, whereas IAS 31 permitted a choice of the equity method or proportionate consolidation for jointly controlled entities. Under IFRS 11, for joint operations, each party recognizes its respective share of the assets, liabilities, revenues and expenses of the arrangement, generally resulting in proportionate consolidation accounting.

IFRS 11 was applied retrospectively by the Corporation by reassessing the type of, and accounting for, each joint arrangement in existence at Jan. 1, 2013. No significant impacts resulted.

III. IFRS 12 Disclosure of Interests in Other Entities

IFRS 12 contains enhanced disclosure requirements about an entity’s interests in subsidiaries, joint arrangements, associates, and consolidated and unconsolidated structured entities (special purpose entities). The objective of IFRS 12 is that an entity should disclose information that helps financial statement users evaluate the nature of, and risks associated with, its interests in other entities and the effects of those interests on its financial statements. Disclosures arising from the adoption of IFRS 12 can be found in Notes 7, 10, and 18.

TRANSALTA CORPORATION / Q1 2013 8

IV. IFRS 13 Fair Value Measurement

IFRS 13 establishes a single source of guidance for all fair value measurements required by other IFRS, clarifies the definition of fair value, and enhances disclosures about fair value measurements. IFRS 13 applies when other IFRS require or permit fair value measurements or disclosures. IFRS 13 specifies how an entity should measure fair value and disclose fair value information. It does not specify when an entity should measure an asset, a liability, or its own equity instrument at fair value. The Corporation’s adoption of IFRS 13, prospectively on Jan. 1, 2013, did not have a material financial impact upon the consolidated financial position or results of operations, however, certain new or enhanced disclosures are required and can be found in Note 11.

V. IAS 1 Presentation of Financial Statements

Amendments to IAS 1 Presentation of Financial Statements issued in June 2011 were intended to improve the consistency and clarity of the presentation of items of comprehensive income by requiring that items presented in Other Comprehensive Income (Loss) (“OCI”) be grouped on the basis of whether they are at some point reclassified from OCI to net earnings or not. The Consolidated Statements of Comprehensive Income (Loss) have been reorganized to comply with the required groupings.

VI. IAS 19 Employee Benefits

Amendments to IAS 19 Employee Benefits are intended to improve the recognition, presentation, and disclosure of defined benefit plans. The amendments require the recognition of changes in defined benefit obligations and in fair value of plan assets when they occur, thus eliminating the “corridor approach” previously permitted. All actuarial gains and losses must be recognized immediately through other comprehensive income and the net pension liability or asset recognized at the full amount of the plan deficit or surplus. Additional changes relate to the presentation, into three components, of changes in defined benefit obligations and plan assets: service cost and net interest cost is recognized in net earnings and remeasurements are recognized in other comprehensive income. The net interest cost introduced in these amendments removes the concept of expected return on plan assets that was previously recognized in net earnings.

The Corporation calculates the net interest cost for its defined benefit plans by applying the discount rate at the beginning of the reporting period to the net defined benefit liability at the beginning of the reporting period. An expected return on plan assets is no longer calculated and recognized as part of pension expense. The elimination of the corridor method had no impact as the Corporation has, since adoption of IFRS, recognized actuarial gains and losses in OCI in the period in which they occurred.

On adoption, the Corporation applied the amendments retrospectively. The impacts as at Dec. 31, 2012 and Jan 1, 2012, respectively, were an increase in the cumulative prior periods’ pre-tax pension expense of $17 million and $11 million ($12 million and $8 million after-tax, respectively), as a result of the application of the net interest cost requirements.

For the three months ended March 31, 2012, Operations, maintenance, and administration expense increased by $1 million as a result of increased pension expense, Net actuarial losses on defined benefit plans as reported in OCI decreased by $1 million, and basic and diluted net earnings per share attributable to common shareholders decreased by $0.01.

VII. Interpretation 20 Stripping Costs in the Production Phase of a Surface Mine (“IFRIC 20”)

IFRIC 20 clarifies the requirements for accounting for stripping costs in the production phase of a surface mine. Stripping costs are costs associated with the process of removing waste from a surface mine in order to gain access to mineral ore deposits. The Interpretation clarifies when production stripping should lead to the recognition of an asset and how that asset should be measured, both initially and in subsequent periods.

TRANSALTA CORPORATION / Q1 2013 9

The Corporation recognizes a stripping activity asset for its Highvale mine when all of the following are met: (i) it is probable that the future benefit associated with improved access to the coal reserves associated with the stripping activity will be realized; (ii) the component of the coal reserve to which access has been improved can be identified; and (iii) the costs related to the stripping activity associated with that component can be measured reliably. Costs include those directly incurred to perform the stripping activity as well as an allocation of directly attributable overheads. The resulting stripping activity asset is amortized on a unit-of-production basis over the expected useful life of the identified component that it relates to. The amortization is recognized as a component of the standard cost of coal inventory.

As required by the transitional provision of IFRIC 20, the Interpretation was applied by the Corporation to production stripping costs incurred on or after Jan. 1, 2011, which will be the earliest comparative period presented within the Corporation’s annual financial statements for the year ended Dec. 31, 2013. The impacts on the Condensed Consolidated Statements of Financial Position as at Dec. 31, 2012 were to recognize $9 million in costs as a stripping activity asset, increase coal inventory by $2 million, both classified within Inventory, increase Deferred income tax liabilities by $3 million, and decrease Retained deficit by $8 million. The impacts on the Condensed Consolidated Statements of Financial Position as at Jan. 1, 2012 were to recognize $9 million in costs as a stripping activity asset, decrease coal inventory by $2 million, both classified within Inventory, increase Deferred income tax liabilities by $2 million, and increase Retained earnings by $5 million.

The impact of this change in accounting policy on the three months ended March 31, 2012 was not material.

VIII. IFRS 7 Financial Instruments: Disclosures

Amendments to IFRS 7 include disclosures about all recognized financial instruments that are set off in accordance with IAS 32. The amendments also require disclosure of information about recognized financial instruments subject to enforceable master netting arrangements and similar agreements even if they are not set off under IAS 32. The resulting disclosures can be found in Note 12.

IX. Annual Improvements 2009-2011

In May 2012, the IASB issued a collection of necessary, non-urgent amendments to several IFRS resulting from its annual improvements process. The amendments, as applicable, have been applied by the Corporation on Jan. 1, 2013. None of the amendments, which are generally technical and narrow in scope, had a material financial impact upon the consolidated financial position or results of operations.

B.	Current Accounting Changes
I.	Change in Estimates - Useful Lives

During the three months ended March 31, 2013, management completed a comprehensive review of the estimated useful lives of the hydro assets, having regard for, among other things, the economic life cycle maintenance program, and existing condition of the assets. As a result, depreciation was reduced by $1 million for the three months ended March 31, 2013. Pre-tax depreciation expense is expected to be reduced by $5 million for the year ended Dec. 31, 2013 and by $5 million annually thereafter.

II. Leases

Leases are classified as finance leases whenever the terms of the lease transfer substantially all the risks and rewards of ownership to the lessee. Property, plant and equipment (“PP&E”) under finance leases are initially recognized at their fair value at the inception of the lease, or if lower, at the present value of the minimum lease payments. The corresponding liability is included in the Condensed Consolidated Statements of Financial Position as a finance lease obligation. Lease payments are apportioned between interest expense and reduction of the lease obligation so as to achieve a constant rate of interest on the remaining balance of the liability.

TRANSALTA CORPORATION / Q1 2013 10

C. Future Accounting Changes

Additional new or amended accounting standards that have been previously issued by the IASB but are not yet effective, and have not been applied by the Corporation, are as follows: IFRS 9 Financial Instruments, IAS 32 Financial Instruments: Presentation, and Investment Entities (Amendments to IFRS 10 and 11 and IAS 27). Please refer to Note 3(D) of the Corporation’s 2012 annual consolidated financial statements for more information.

3 . S U N H I L L S   M I N I N G   L I M I T E D   P A R T N E R S H I P

Effective Jan. 17, 2013, the Corporation assumed, through its wholly owned SunHills Mining Limited Partnership (“SunHills”), operations and management control of the Highvale Mine from Prairie Mines and Royalty Ltd. (“PMRL”). PMRL employees working at the Highvale Mine were offered employment by SunHills which agreed to assume responsibility for certain pension plan and pension funding obligations, which had been previously funded by the Corporation through the payments made under the PMRL mining contracts. As a result, a pre-tax loss of $29 million was recognized, along with the corresponding liabilities.

The Corporation also entered into a related finance lease for certain mining equipment that was used by PMRL in mining operations. As a result, $21 million in mining equipment has been capitalized to PP&E and the related finance lease obligation recognized. At the end of the lease term, the Corporation is eligible to purchase the assets, for a nominal amount. The amounts payable under the finance lease are as follows:

As at	March 31, 2013
	Minimum lease payments	Present value of minimum lease payments
Within one year	9	9
Second to fifth years inclusive	14	12
	23	21
Less: interest cost	2	-
Total finance lease obligation	21	21
Included in the Condensed Consolidated Statements of Financial Position as:
Current portion of finance lease obligation	9
Non-current finance lease obligation	12
	21

4 . D I S P O S A L S

During the three months ended March 31, 2012, the Corporation realized a pre-tax gain of $3 million related to the 2011 sale of its biomass facility. The gain resulted from the release of the remaining consideration related to the achievement of the Environmental Attribute Conditions by the purchaser.

TRANSALTA CORPORATION / Q1 2013 11

5 . O P E R A T I N G   L E A S E S

Several of the Corporation’s Power Purchase Arrangements and other long-term contracts meet the criteria of operating leases. Total rental income, including contingent rent, related to these contracts reported in Revenues in the Condensed Consolidated Statements of Earnings for the three months ended March 31, 2013, was $49 million (March 31, 2012 - $42 million).

6 . E X P E N S E S   B Y   N A T U R E
Expenses classified by nature are as follows:
	3 months ended March 31, 2013		3 months ended March 31, 2012
				(Restated)*
	Fuel and purchased power	Operations, maintenance, and administration	Fuel and purchased power	Operations, maintenance, and administration
Fuel	171	-	139	-
Purchased power	17	-	25	-
Salaries and benefits	2	61	1	66
Depreciation	11	-	10	-
Other operating expenses	-	54	-	62
Total	201	115	175	128

*      See Note 2 for prior period restatements.

7 . I N V E S T M E N T S

The Corporation’s investments in joint ventures accounted for using the equity method consist of its investments in CE Generation, LLC (“CE Gen”) and Wailuku River Hydroelectric, L.P (“Wailuku”).

Summarized financial information on the results of operations and financial position relating to the Corporation’s pro-rata interests in CE Gen and Wailuku is as follows:

		3 months ended March 31
	2013		2012
Results of operations
Revenues	20		26
Expenses	(24)		(26)
Proportionate share of net loss	(4)		-

TRANSALTA CORPORATION / Q1 2013 12

Summarized financial information relating to 100 per cent of CE Gen, including adjustments for the application of consistent accounting policies and the Corporation’s purchase price adjustments, is as follows:

	3 months ended March 31
	2013	2012
Revenues	38	50
Depreciation and amortization	23	21
Interest expense	5	6
Income tax recovery	(15)	(10)
Net loss from continuing operations	(8)	(3)
Other comprehensive loss	(4)	-
Total comprehensive loss	(12)	(3)
Distributions received	-	-
As at		March 31, 2013	Dec. 31, 2012
Current assets		96	93
Long-term assets		674	675
Current liabilities		(76)	(62)
Long-term liabilities		(403)	(409)
Net assets		291	297
Additional items included above
Cash and cash equivalents		29	27
Current financial liabilities(1)		(41)	(35)
Long-term financial liabilities(1)		(238)	(233)
(1) Excludes trade and other payables and provisions

A reconciliation of the carrying amount to the Corporation’s 50 per cent interest in the CE Gen joint venture is as follows:

As at	March 31, 2013	Dec. 31, 2012
Net assets	291	297
Less: minority interest in CE Gen	(14)	(14)
Less: 50 per cent of CE Gen's net assets not owned by the Corporation	(112)	(116)
Net investment	165	167

CE Gen’s ability to make distributions to its owners, including the Corporation, is restricted by covenants and conditions, including principal and interest funding deposit requirements, imposed by certain project-related debt agreements.

At March 31, 2013 the carrying amount of Wailuku’s net investment is $5 million (Dec. 31, 2012 - $5 million).
8 . N E T   I N T E R E S T   E X P E N S E
The components of net interest expense are as follows:
	3 months ended March 31
	2013	2012
Interest on debt	60	56
Capitalized interest	(2)	-
Interest expense	58	56
Accretion of provisions (Note 17)	4	4
Net interest expense	62	60

TRANSALTA CORPORATION / Q1 2013 13

The Corporation capitalizes interest during the construction phase of growth capital projects. The capitalized interest in 2013 related to the New Richmond wind farm.

9 . I N C O M E   T A X E S
The components of income tax expense are as follows:
	3 months ended March 31
	2013	2012
Current income tax expense	8	13
Deferred income tax expense (recovery) related to the origination and reversal of temporary differences	(19)	13
Deferred income tax recovery resulting from changes in tax rates or laws(1)	(6)	-
Benefit arising from previously unrecognized tax loss, tax credit, or temporary difference of a prior period used to reduce current income tax expense	-	(14)
Benefit arising from previously unrecognized tax loss, tax credit, or temporary difference of a prior period used to reduce deferred income tax expense	-	(10)
Income tax expense (recovery)	(17)	2
(1) Relates to the impact of adjusting the deferred tax rate to incorporate the Ontario M&P tax credit. Previously, the Corporation had been using the Ontario general corporate tax rate of 11.5 per cent.
Presented in the Condensed Consolidated Statements of Earnings (Loss) as follows:
	3 months ended March 31
	2013	2012
Current income tax expense (recovery)	8	(1)
Deferred income tax expense (recovery)	(25)	3
Income tax expense (recovery)	(17)	2

TRANSALTA CORPORATION / Q1 2013 14

1 0 . N O N - C O N T R O L L I N G   I N T E R E S T S

The Corporation’s subsidiaries and operations that have non-controlling interests are as follows:

Subsidiary/Operation	Non-controlling interest
TransAlta Cogeneration L.P. ("TA Cogen")	49.99% - Stanley Power Inc.
Kent Hills wind farm	17% - Natural Forces Technologies Inc.

Summarized financial information relating to TA Cogen, the subsidiary with a significant non-controlling interest, is as follows:

	3 months ended March 31
	2013	2012
Revenues	80	84
Net earnings	18	25
Total comprehensive income	32	10
Amounts attributable to the non-controlling interest:
Net earnings	9	12
Total comprehensive income	16	5
Distributions paid to Stanley Power Inc.	18	19
As at	March 31, 2013	Dec. 31, 2012
Current assets	58	70
Long-term assets	662	678
Current liabilities	(63)	(75)
Long-term liabilities	(76)	(87)
Total equity	(581)	(588)
Equity attributable to the non-controlling interest	(288)	(290)

1 1 . F I N A N C I A L   I N S T R U M E N T S

 

A. Financial Assets and Liabilities - Classification and Measurement

Financial assets and financial liabilities are measured on an ongoing basis at cost, fair value, or amortized cost.

B.	Fair Value of Financial Instruments
I.	Energy Trading

Energy trading includes risk management assets and liabilities that are used in the Energy Trading and Generation segments in relation to trading activities and certain contracting activities. To the extent applicable, changes in net risk management assets and liabilities for non-hedge positions are reflected within earnings of the Energy Trading and Generation business segments.

TRANSALTA CORPORATION / Q1 2013 15

The following tables summarize the key factors impacting the fair value of energy trading risk management assets and liabilities by classification level during the three months ended March 31, 2013 and 2012, respectively:

	Hedges				Non-Hedges			Total
	Level I	Level II	Level III	Level I	Level II	Level III	Level I	Level II	Level III
Net risk management assets (liabilities) at Dec. 31, 2012	-	(63)	3	(1)	79	28	(1	16	31
Changes attributable to:
Market price changes on existing contracts	-	(10)	(3)	-	(19)	10	-	(29)	7
Market price changes on new contracts	-	(2)	-	-	(10)	(17)	-	(12)	(17)
Contracts settled	-	2	-	1	(5)	(4)	1	(3)	(4)
Net risk management assets
(liabilities) at March 31, 2013	-	(73)	-	-	45	17	-	(28)	17
Additional Level III gain (loss) information:
Change in fair value included in OCI			-			-			-
Total losses included in earnings before income taxes			-			(7)			(7)
Unrealized gain included in earnings before income taxes relating to net assets held at March 31, 2013						(11)			(11)

		Hedges			Non-Hedges			Total
	Level I	Level II	Level III	Level I	Level II	Level III	Level I	Level II	Level III
Net risk management assets (liabilities) at
Dec. 31, 2011	-	(90)	(14)	-	287	7	-	197	(7)
Changes attributable to:
Market price changes on existing
contracts	-	16	3	-	37	11	-	53	14
Market price changes on new contracts	-	-	-	-	4	-	-	4	-
Contracts settled	-	7	4	-	(67)	(5)	-	(60)	(1)
Discontinued hedge accounting on
certain contracts	-	(26)	-	-	26	-	-	-	-

Net risk management assets
(liabilities) at March 31, 2012	-	(93)	(7)	-	287	13	-	194	6
Additional Level III gain (loss) information:
Change in fair value included in OCI			7			-			7
Total gains (losses) included in earnings
before income taxes			(4)			11			7
Unrealized gain included in earnings before
income taxes relating to net assets held
at March 31, 2012			-			6			6

TRANSALTA CORPORATION / Q1 2013 16

a. Levels II and III Fair Value Measurements

i. Level II

Fair values are determined, directly or indirectly, using inputs that are observable for the asset or liability.

Fair values falling within the Level II category are determined through the use of quoted prices in active markets, which in some cases are adjusted for factors specific to the asset or liability, such as basis, credit valuation, and location differentials.

Energy Trading includes, in Level II, over-the-counter derivatives with values based on observable commodity futures curves and derivatives with inputs validated by broker quotes or other publicly available market data providers. Level II fair values are also determined using valuation techniques, such as option pricing models and regression or extrapolation formulas, where the inputs are readily observable, including commodity prices for similar assets or liabilities in active markets, and implied volatilities for options.

ii. Level III

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

Energy Trading may enter into commodity transactions for which market-observable data is not available. In these cases, Level III fair values are determined using valuation techniques such as the Black-scholes, Mark-to-forecast, and Historical bootstrap models with inputs that are based on historical data such as unit availability, transmission congestion, demand profiles for individual nonstandard deals and structured products, and/or volatilities and correlations between products derived from historical prices.

Energy Trading also has various contracts with terms that extend beyond a liquid trading period. As forward price forecasts are not available for the full period of these contracts, the value of these contracts is derived by reference to a forecast that is based on a combination of external and internal fundamental modelling, including discounting. As a result, these contracts are classified in Level III.

Policies and procedures regarding energy trading Level III fair value measurements are determined by the Corporation’s Risk Management department, in compliance with the Corporation’s Commodity Exposure Management Policy (“the Policy”), which 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 trading activities, as well as the nature and frequency of required reporting of such activities. Level III fair values are calculated within the Corporation’s Energy Trading Risk Management system based on underlying contractual data and observable and non-observable inputs. Development of non-observable inputs requires the use of judgment. To ensure reasonability, system generated Level III fair value measurements are reviewed and validated by Risk Management personnel. Review occurs formally on a quarterly basis or more frequently if daily review and monitoring procedures identify unexpected changes to fair value, or changes to key parameters.

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 March 31, 2013 is estimated to be +/- $29 million (Dec. 31, 2012 - $26 million). Fair values are stressed for volumes and prices. The volumes are stressed up and down one standard deviation from historically available production data. Prices are stressed for longer term deals where there are no liquid market quotes using various internal and external forecasting sources to establish a high and a low price range.

TRANSALTA CORPORATION / Q1 2013 17

Information about the significant unobservable inputs used in determining Level III fair values is as follows:

Description	Fair value as at March 31, 2013	Valuation Technique	Unobservable input	Range
			Price discount	1 - 2 per cent
Unit power contingent purchases	20	Historical bootstrap	Volumetric discount(1)	1 - 8 per cent
			Illiquid future
Long term power sale	(11)	Mark-to-forecast	power prices	$40.30 - $83.50
				16 - 25 per cent
			Volumes (MWh)	of capacity
Coal supply			Illiquid future implied
revenue sharing	(13)	Black-scholes	volatilities in MidC power	29 per cent
			Volumetric discount	0 per cent
Unit contingent			Illiquid future implied
power sales	21	Black-scholes	volatilities in MidC power	39 per cent

(1) A change in the volumetric discount, could, depending on other market dynamics, result in a directionally similar change in the price discount.

II. Other Risk Management Assets and Liabilities

Other risk management assets and liabilities primarily include risk management assets and liabilities that are used in hedging non-energy trading transactions, such as interest rates, the net investment in foreign operations, and other foreign currency risks.

The following tables summarize the key factors impacting the fair value of other risk management assets and liabilities by classification level during the three months ended March 31, 2013 and 2012, respectively:

		Hedges				Non-Hedges				Total
	Level I	Level II		Level III		Level I	Level II	Level III	Level I	Level II	Level III
Net risk management liabilities at
Dec. 31, 2012	-		(50)		-	-	1	-	-	(49)	-
Changes attributable to:
Market price changes on existing
contracts	-		28		-	-	-	-	-	28	-
New contracts	-		(3)		-	-	1	-	-	(2)	-
Contracts settled	-		(1)		-	-	(1)	-	-	(2)	-
Net risk management assets
(liabilities) at March 31, 2013	-		(26)		-	-	1	-	-	(25)	-
			Hedges				Non-Hedges			Total
	Level I		Level II		Level III	Level I	Level II	Level III	Level I	Level II	Level III
Net risk management assets
(liabilities) at Dec. 31, 2011	-		(50)		-	-	-	-	-	(50)	-
Changes attributable to:
Market price changes on existing	-		(12)		-	-	-	-	-	(12)	-
contracts
New contracts	-		-		-	-	(2)	-	-	(2)	-
Contracts settled	-		3		-	-	-	-	-	3	-
Net risk management liabilities at March 31, 2012	-		(59)		-	-	(2)	-	-	(61)	-

TRANSALTA CORPORATION / Q1 2013 18

a. Level II Fair Value Measurements

Fair values are determined, directly or indirectly, using inputs that are observable for the asset or liability.

Level II fair values of other risk management assets and liabilities are determined using valuation techniques, such as discounted cash flow methods. The Corporation uses observable inputs other than unadjusted quoted prices that are observable for the asset or liability, such as interest rate yield curves, credit valuation adjustments, 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.

III. Other Financial Assets and Liabilities
The fair value of financial assets and liabilities measured at other than fair value is as follows:
					Total carrying value
	Fair value(1)
	Level I	Level II	Level III	Total
Long-term debt - March 31, 2013	-	4,409	-	4,409	4,231
Long-term debt - Dec. 31, 2012	-	4,426	-	4,426	4,217
(1) Includes current portion.

The fair values of the Corporation’s debentures and senior notes are determined using prices observed in secondary markets. Non-recourse and other long-term debt fair values are determined by calculating an implied price based on a current assessment of the yield to maturity.

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

C. Inception Gains and Losses

An inception gain or loss arises due to differences between the fair value of a financial instrument at initial recognition (the transaction price) and the amount calculated through a valuation model. The unrealized gain or loss related to Level III financial instruments is deferred in risk management assets or liabilities, and is recognized in net earnings over the term of the related contract. At March 31, 2013, the unamortized gain is $3 million (Dec. 31, 2012 - $5 million gain).

TRANSALTA CORPORATION / Q1 2013 19

1 2 . R I S K   M A N A G E M E N T   A C T I V I T I E S

A. Risk Management Assets and Liabilities

Aggregate risk management assets and liabilities are as follows:

As at			March 31, 2013			Dec. 31, 2012
	Net  investment  hedges	Cash flow hedges	Fair value  hedges	Not  designated  as a hedge	Total	Total
Risk management assets
Energy trading
Current	-	-	-	118	118	198
Long-term	-	3	-	50	53	59
Total energy trading risk
management assets	-	3	-	168	171	257
Other
Current	1	2	-	2	5	3
Long-term	-	1	9	-	10	10
Total other risk management assets	1	3	9	2	15	13
Risk management liabilities
Energy trading
Current	-	21	-	73	94	141
Long-term	-	55	-	33	88	70
Total energy trading risk	-	76	-	106	182	211
management liabilities
Other
Current	3	12	-	1	16	26
Long-term	-	24	-	-	24	36
Total other risk	3	36	-	1	40	62
management liabilities
Net energy trading risk management assets (liabilities)
	-	(73)	-	62	(11)	46
Net other risk management assets (liabilities)
	(2)	(33)	9	1	(25)	(49)
Net total risk management assets (liabilities)
	(2)	(106)	9	63	(36)	(3)
Additional information on derivative instruments has been presented on a net basis below.

TRANSALTA CORPORATION / Q1 2013 20

I. Netting Arrangements

Information about the Corporation’s financial management assets and liabilities that are subject to enforceable master netting arrangements or similar agreements is as follows:

As at		March 31, 2013				Dec. 31, 2012
	Current financial assets	Long-term financial assets	Current financial liabilities	Long-term financial liabilities	Current financial assets	Long-  term  financial  assets	Current financial liabilities	Long-  term  financial  liabilities
Gross amounts recognized	536	93	(504)	(106)	522	331	(452)	(317)
Gross amounts set-off	(301)	(10)	301	10	(252)	(186)	252	186
Net amounts as presentedin the Condensed Consolidated Statements of Financial Position(1)	235	83	(203)	(96)	270	145	(200)	(131)
(1) Excludes credit reserves.

II.	Hedges
a.	Cash Flow Hedges
i.	Energy Trading Risk Management

Certain of TransAlta’s hedging relationships had previously been de-designated and deemed ineffective for accounting purposes. The hedges were in respect of power production and the associated gains remain in Accumulated Other Comprehensive Income (Loss) (“AOCI”) until the underlying production occurs or until such time that the production has been assessed as highly probable not to occur. No gains related to these previously de-designated hedges were reclassified to earnings during the three months ended March 31, 2013 (March 31, 2012 - $75 million pre-tax gain).

As at March 31, 2013, cumulative gains of $7 million related to cash flow hedges that were de-designated and no longer meet the criteria for hedge accounting continued to be deferred in AOCI and will be reclassified to net earnings as the forecasted transactions occur or if the forecasted transactions are assessed as highly probable not to occur.

ii. Cash Flow Hedge Impacts

Over the next 12 months ended March 31, 2014, the Corporation estimates that $29 million of after-tax losses will be reclassified from AOCI to net earnings. These estimates assume constant natural 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.

B. Nature and Extent of Risks Arising from Financial Instruments

The following discussion is limited to the nature and extent of certain risks arising from financial instruments, which are also more fully discussed in Note 16(B) of the most recent annual consolidated financial statements.

TRANSALTA CORPORATION / Q1 2013 21

I. Commodity Price Risk

Value at Risk (“VaR”) is the most commonly used metric employed to track and manage the market risk associated with commodity and other derivatives. 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.

a. Commodity Price Risk - Proprietary Trading

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

VaR at March 31, 2013 associated with the Corporation’s proprietary energy trading activities was $2 million (Dec. 31, 2012 - $2 million).

b. Commodity Price Risk - Generation

The Generation Segment utilizes various commodity contracts and other financial instruments to manage the commodity price risk associated with its electricity generation, fuel purchases, emissions, and byproducts, as considered appropriate. VaR at March 31, 2013 associated with the Corporation’s commodity derivative instruments used in generation hedging activities was $3 million (Dec. 31, 2012 - $5 million). VaR at March 31, 2013 associated with positions and economic hedges that do not meet hedge accounting requirements was $7 million (Dec. 31, 2012 - $9 million).

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 uses external credit ratings, as well as internal ratings in circumstances where external ratings are not available, to establish credit limits for customers and counterparties. The following table outlines the distribution, by credit rating, of certain financial assets as at March 31, 2013:

(Per cent)	Investment grade	Non-investment grade	Total
Accounts receivable	88	12	100
Risk management assets	97	3	100

The Corporation’s maximum exposure to credit risk at March 31, 2013, without taking into account collateral held or right of set-off, is represented by the carrying amounts of accounts receivable and risk management assets as per the Condensed Consolidated Statements of Financial Position. 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 counterparty for commodity trading operations and hedging, excluding the California market receivables (Refer to Note 36 of the 2012 annual consolidated financial statements), and including the fair value of open trading positions, net of any collateral held, at March 31, 2013 was $21 million (Dec. 31, 2012 - $25 million).

At March 31, 2013, TransAlta had one counterparty whose net settlement position accounted for greater than 10 per cent of the total trade receivables outstanding. The Corporation has evaluated the risk of default related to this counterparty to be minimal.

TRANSALTA CORPORATION / Q1 2013 22

III. Liquidity Risk

Liquidity risk relates to the Corporation’s ability to access capital to be used for proprietary trading activities, commodity hedging, capital projects, debt refinancing, and general corporate purposes.

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

	2013	2014	2015	2016	2017	2018 and   thereafter	Total
Accounts payable and accrued liabilities	450	-	-	-	-	-	450
Collateral received	1	-	-	-	-	-	1
Debt(1)	618	209	665	647	2	2,081	4,222
Energy trading risk management (assets) liabilities	(14)	(23)	11	18	9	10	11
Other risk management (assets) liabilities	11	2	19	1	1	(9)	25
Interest on long-term debt(2)	161	186	154	138	129	821	1,589
Dividends payable	76	-	-	-	-	-	76
Total	1,303	374	849	804	141	2,903	6,374

(1) Excludes impact of hedge accounting and includes drawn credit facilities that are currently scheduled to mature in 2013, 2014, and 2016.

(2) Not recognized as a financial liability on the Condensed Consolidated Statements of Financial Position

C. Collateral and 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 March 31, 2013, the Corporation had posted collateral of $79 million (Dec. 31, 2012 - $85 million) in the form of letters of credit on derivative instruments in a net liability position. Certain derivative agreements contain credit-risk-contingent features, including a credit rating downgrade to below investment grade, which if triggered would result in the Corporation having to post an additional $92 million of collateral to its counterparties based upon the value of the derivatives at March 31, 2013.

1 3 . R E S T R I C T E D   C A S H

The Corporation has $2 million of cash and cash equivalents at March 31, 2013 (Dec. 31, 2012 - $2 million) that is not available for general use, all of which relates to Project Pioneer.

TRANSALTA CORPORATION / Q1 2013 23

1 4 . I N V E N T O R Y

Inventory held in the normal course of business includes coal, emission credits, and natural gas, and is valued at the lower of cost and net realizable value. Inventory held for trading, which also includes natural gas and purchased emission credits, is valued at fair value less costs to sell.

The classifications are as follows:
	March 31, 2013	Dec. 31, 2012
As at		(Restated)*
Coal	72	78
Deferred stripping costs	18	9
Natural gas	2	2
Purchased emission credits	3	4
Total	95	93
* See Note 2 for prior period restatements.

For the three months ended March 31, 2013, coal inventory at the Corporation’s Centralia plant was written down by $14 million (March 31, 2012 - $34 million) to its net realizable value.

1 5 . P R O P E R T Y ,   P L A N T ,   A N D   E Q U I P M E N T
A reconciliation of the changes in the carrying amount of PP&E is as follows:
	Land	Thermal generation	Gas generation	Renewable generation	Mining  property and equipment	Assets under construction	Capital spares and other (1)	Total
As at Dec. 31, 2012	75	2,874	996	2,004	517	342	236	7,044
Additions	-	-	-	-	-	122	3	125
Additions - finance lease (Note 3)	-	-	-	-	21	-	-	21
Depreciation	-	(65)	(25)	(22)	(15)	-	(30	(130
Revisions and additions to
decommissioning and restoration  costs	-	4	(6	2	4	-	-	4
Change in foreign exchange rates	1	8	4	-	-	-	1	14
Transfers	-	4	3	216	5	(242)	14	-
As at March 31, 2013	76	2,825	972	2,200	532	222	251	7,078

(1) Includes major spare parts and stand-by equipment available, but not in service, and spare parts used for routine, preventative or planned maintenance.

During the three months ended March 31, 2013, the Corporation capitalized $2 million (March 31, 2012 - a nominal amount) of interest to PP&E at a weighted average rate of 5.46 per cent (March 31, 2012 - 5.38 per cent).

TRANSALTA CORPORATION / Q1 2013 24

1 6 . O T H E R   A S S E T S
The components of other assets are as follows:
As at		March 31, 2013		Dec. 31, 2012
Deferred licence fees			21			21
Project development costs			35			35
Deferred service costs			19			19
Long-term prepaids			19			5
Keephills Unit 3 transmission deposit			7			7
Other			2			3
Total other assets			103			90
1 7 . D E C O M M I S S I O N I N G   A N D   O T H E R   P R O V I S I O N S
The change in decommissioning and other provision balances is outlined below:
	Decommissioning	Restructuring	Other		Total
	and restoration
Balance, Dec. 31, 2012	262	8		42		312
Liabilities incurred in period	2	-		4		6
Liabilities settled in	(5)	(4)		-		(9)
period
Accretion (Note 8)	4	-		-		4
Revisions in estimated cash flows (Note 15)	4	-		1		5
Revisions in discount rates	(1)	-				(1)
Reversals	-	-		(8)		(8)
Change in foreign exchange rates	2	-		1		3
	268	4		40		312
Less: current portion	14	4		7		25
Balance, March 31, 2013	254	-		33		287

The restructuring provision relates to the Corporation’s 2012 restructuring of resources as part of its ongoing strategy to continuously improve operational excellence and accelerate growth.

Other provisions include an amount related to a portion of the Corporation’s fixed price commitments under several natural gas transportation contracts for firm transportation that is not expected to be used. Accordingly, the unavoidable costs of meeting these obligations exceed the economic benefits expected to be received. The contracts extend to 2018.

Other provisions also include provisions arising from ongoing business activities and include amounts related to commercial disputes between the Corporation and customers or suppliers. Information about the expected timing of settlement and uncertainties that could impact the amount or timing of settlement has not been provided as this may impact the Corporation’s ability to settle the provisions in the most favourable manner.

TRANSALTA CORPORATION / Q1 2013 25

1 8 . L O N G - T E R M   D E B T
A. Debt and Letters of Credit
The amounts outstanding are as follows:
As at	March 31, 2013			Dec. 31, 2012
	Carrying	Face		Carrying	Face
	value	value	Interest(1)	value	value	Interest(1)
Credit facilities(2)	923	923	2.3%	950	950	2.4%
Debentures	841	851	6.6%	839	851	6.6%
Senior notes(3)	2,058	2,034	5.6%	2,017	1,990	5.6%
Non-recourse(4)	375	380	5.9%	375	380	5.9%
Other	34	34	6.4%	36	36	6.5%
	4,231	4,222		4,217	4,207
Less: recourse current portion	(619)	(619)		(606)	(606)
Less: non-recourse current portion	(1)	(1)		(1)	(1)
Total long-term debt	3,611	3,602		3,610	3,600

(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. Includes U.S.$300 million at March 31, 2013 (Dec. 31, 2012 - U.S.$300 million).

(3) U.S. face value at March 31, 2013 - U.S.$2.0 billion (Dec. 31, 2012 - U.S.$2.0 billion).

(4) Includes U.S.$20 million at March 31, 2013 (Dec. 31, 2012 - U.S.$20 million).

TransAlta has a total of $2.0 billion (Dec. 31, 2012 - $2.0 billion) of committed credit facilities, of which $0.8 billion (Dec. 31, 2012 - $0.8 billion) is not drawn, and is available as of March 31, 2013, subject to customary borrowing conditions. The $1.5 billion committed syndicated bank facility is a four-year revolving credit facility that matures in 2016. The U.S.$300 million facility is a five-year facility that matures in the third quarter of 2013. The Corporation also has $240 million in committed bilateral credit facilities, all of which matures in the fourth quarter of 2014. In addition to the $0.8 billion available under the credit facilities, TransAlta also has $48 million of available cash and cash equivalents.

Letters of credit are issued to counterparties under various contractual arrangements with the Corporation and 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 under these contracts are reflected in the Consolidated Statements of Financial Position. All letters of credit expire within one year and are expected to be renewed, as needed, in the normal course of business. The total outstanding letters of credit as at March 31, 2013 were $327 million (Dec. 31, 2012 - $336 million) with no (Dec. 31, 2012 - nil) amounts exercised by third parties under these arrangements.

B. Restrictions

Debt agreements of $34 million related to the Windsor plant, owned by the Corporation’s TA Cogen subsidiary, include principal and interest funding provisions that restrict the Corporation’s ability to access funds generated by the operations of the plant. The Corporation has provided a letter of credit in the amount of the funding requirements, thereby permitting it to access the funds.

Debentures of $339 million issued by the Corporation’s Canadian Hydro Developers, Inc. subsidiary include restrictive covenants requiring the proceeds received from the sale of assets to be reinvested into similar renewables assets. Accordingly, the Corporation is not able to use such proceeds for other purposes.

TRANSALTA CORPORATION / Q1 2013 26

1 9 . D E F E R R E D   C R E D I T S   A N D   O T H E R   L O N G - T E R M   L I A B I L I T I E S

The components of deferred credits and other long-term liabilities are as follows:

As at	March 31, 2013	Dec. 31, 2012
Deferred coal revenues	51	51
Defined benefit obligations	227	220
Long-term incentive accruals	7	15
Other	18	15
Total deferred credits and other long-term liabilities	303	301

20. C O M M O N   S H A R E S

A. Issued and Outstanding

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

A reconciliation of changes in common shares is as follows:

		3 months ended March 31
	2013		2012
	Common shares (millions)	Amount	Common shares (millions)	Amount
Issued and outstanding, beginning of period	254.7	2,730	223.6	2,274
Issued under the dividend reinvestment and share purchase plan	3.7	53	0.9	20
Issued under the PSOP	-	-	0.1	1
	258.4	2,783	224.6	2,295
Amounts receivable under Employee Share Purchase Plan	-	(3)	-	(2)
Issued and outstanding, end of period	258.4	2,780	224.6	2,293
B. Dividends

The following table summarizes the common share dividends declared or paid within the three months ended March, 31:

Date  declared	Payment  date	Dividend per  share ($)	Total  dividends	Dividends  paid in  cash	Dividends paid  in shares
2013
Jan. 28, 2013	Apr. 1, 2013	0.29	75	22	53
Oct. 24, 2012	Jan. 1, 2013	0.29	73	20	53
2012
Jan. 25, 2012	Apr. 1, 2012	0.29	65	23	43
Oct. 27, 2011	Jan. 1, 2012	0.29	65	45	20

There have been no other transactions involving common shares between the reporting date and the date of completion of these condensed consolidated financial statements.

TRANSALTA CORPORATION / Q1 2013 27

2 1 . P R E F E R R E D   S H A R E S

A. Issued and Outstanding

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

Preferred shares outstanding are as follows:
As at	March 31, 2013		Dec. 31, 2012
Cumulative Redeemable Rate Reset First Preferred Shares	Number of shares (millions)	Amount	Number of shares (millions)	Amount	Dividend rate per share ($)	Redemption price per share ($)
Series A	12	293	12	293	1.15	25.00
Series C	11	269	11	269	1.15	25.00
Series E	9	219	9	219	1.25	25.00
Issued and outstanding, end of period	32	781	32	781
B. Dividends

The following table summarizes the preferred share dividends declared or paid within the three months ended March 31:

		Series A		Series C		Series E
Date declared	Payment date	Dividend per share ($)	Total dividends	Dividend per share ($)	Total dividends	Dividend per share ($)	Total dividends
2013
Jan. 28, 2013	March 31, 2013	0.2875	3	0.2875	3	0.3125	3
2012
Jan. 25, 2012	March 31, 2012	0.2875	3	0.3844(1)	4	-	-

(1) Includes dividends of $0.0969 per share ($1 million in total) for the period from Nov. 29, 2011 to Dec. 31, 2011, which were accrued at Dec. 31, 2011.

TRANSALTA CORPORATION / Q1 2013 28

2 2 .   A C C U M U L A T E D   O T H E R   C O M P R E H E N S I V E   I N C O M E  ( L O S S )
The components of, and changes in, AOCI are presented below:
	2013	2012
		(Restated)*
Currency translation adjustment
Opening balance	(38)	(28)
Gains (losses) on translating net assets of foreign operations	25	(32)
Gains (losses) on financial instruments designated as hedges of foreign operations, net of tax(1)	(21)	21
Balance, March 31	(34)	(39)
Cash flow hedges
Opening balance	(37)	(28)
Gains (losses) on derivatives designated as cash flow hedges, net of tax(2)	10	(2)
Reclassification of losses on derivatives designated as cash flow hedges to non-financial assets, net of tax(3)	1	1
Reclassification of gains on derivatives designated as cash flow hedges to net earnings, net of tax(4)	(22)	(9)
Balance, March 31	(48)	(38)
Employee future benefits
Opening balance	(61)	(38)
Net actuarial gains (losses) on defined benefit plans, net of tax(5)	7	(9)
Balance, March 31	(54)	(47)
Equity investees
Opening balance	-	-
Other comprehensive loss of equity investees, net of tax(6)	(2)	-
Balance, March 31	(2)	-
Accumulated other comprehensive loss	(138)	(124)

*	See Note 2 for prior period restatements.
(1)	Net of income tax recovery of 3 for the three months ended March 31, 2013 (2012 - 3 expense).
(2)	Net of income tax recovery of 2 for the three months ended March 31, 2013 (2012 - 1 expense).
(3)	Net of income tax expense of nil for the three months ended March 31, 2013 (2012 - nil).
(4)	Net of income tax expense of 3 for the three months ended March 31, 2013 (2012 - 17 expense).
(5)	Net of income tax expense of 2 for the three months ended March 31, 2013 (2012 - 3 recovery).
(6)	Net of income tax recovery of 1 for the three months ended March 31, 2013 (2012 - nil).

2 3 . C O N T I N G E N C I E S

TransAlta is occasionally named as a party in various claims and legal proceedings that arise during the normal course of its business. TransAlta reviews each of these claims, including the nature of the claim, the amount in dispute or claimed, and the availability of insurance coverage. There can be no assurance that any particular claim will be resolved in the Corporation’s favour or that such claims may not have a material adverse effect on TransAlta. Inquiries from regulatory bodies may also arise in the normal course of business, to which the Corporation responds as required.

2 4 . C O M M I T M E N T S

During March 2013, the New Richmond wind farm commenced operations and as such, the 15 year long-term service agreement for repairs and maintenance became effective. The future payments over the term of the agreement are approximately $35 million.

TRANSALTA CORPORATION / Q1 2013 29

2 5 . S E G M E N T   D I S C L O S U R E S

 

A. Reported Segment Earnings (Loss)

Each business segment assumes responsibility for its operating results to operating income.
3 months ended March 31, 2013	Generation	Energy Trading	Corporate	Total
Revenues	523	17	-	540
Fuel and purchased power	201	-	-	201
Gross margin	322	17	-	339
Operations, maintenance, and administration	92	7	16	115
Depreciation and amortization	122	-	5	127
Inventory writedown	14	-	-	14
Taxes, other than income taxes	7	-	-	7
Intersegment cost allocation	4	(4)	-	-
Operating income (loss)	83	14	(21)	76
Finance lease income	11	-	-	11
Equity loss	(4)	-	-	(4)
Foreign exchange loss				(1)
Loss on assumption of pension obligations				(29)
Net interest expense				(62)
Loss before income taxes				(9)
3 months ended March 31, 2012 (Restated)*	Generation	Energy Trading	Corporate	Total
Revenues	627	17	-	644
Fuel and purchased power	175	-	-	175
Gross margin	452	17	-	469
Operations, maintenance, and administration	99	7	22	128
Depreciation and amortization	124	-	5	129
Inventory writedown	34	-	-	34
Taxes, other than income taxes	7	-	-	7
Intersegment cost allocation	3	(3)	-	-
Operating income (loss)	185	13	(27	171
Finance lease income	2	-	-	2
Gain on sale of assets	3	-	-	3
Foreign exchange loss				(6)
Net interest expense				(60)
Earnings before income taxes				110
* See Note 2 for prior period restatements.

Included in the Generation Segment results for the three months ended March 31, 2013 are $7 million (March 31, 2012 - $7 million) of incentives received under a Government of Canada program in respect of power generation from qualifying wind and hydro projects.

TRANSALTA CORPORATION / Q1 2013 30

B. Selected Condensed Consolidated Statements of Financial Position Information
Total segment assets	Generation	Energy Trading	Corporate	Total
March 31, 2013	8,889	216	252	9,357
Dec. 31, 2012 (Restated)*	8,994	262	206	9,462

*	See Note 2 for prior period restatements.
C.	Depreciation and Amortization on the Condensed Consolidated Statements of Cash Flows

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

	3 months ended March 31
	2013	2012
Depreciation and amortization expense on the Condensed Consolidated Statement of Earnings	127	129
Depreciation included in fuel and purchased power (Note 6)	11	10
Other	1	1
Depreciation and amortization expense on the Condensed Consolidated Statements of Cash Flows	139	140

2 6 . C H A N G E S   I N   N O N - C A S H   O P E R A T I N G   W O R K I N G   C A P I T A L
	3 months ended March 31
	2013	2012
Source (use) of cash:
Accounts receivable	142	104
Prepaid expenses	(22)	(15)
Income taxes receivable	(3)	(14)
Inventory	(1)	(2)
Accounts payable and accrued liabilities	(37)	(90)
Decommissioning and other provisions	-	12
Income taxes payable	(2)	(1)
Change in non-cash operating working capital	77	(6)

TRANSALTA CORPORATION / Q1 2013 31

EX-13.2

  TransAlta Corporation first quarter report for 2013

management’s discussion and analysis

This Management’s Discussion and Analysis (“MD&A”) contains forward-looking statements. These statements are based on certain estimates and assumptions and involve risks and uncertainties. Actual results may differ materially. See the
Forward-Looking Statements section of this MD&A for additional information.

This MD&A should be read in conjunction with unaudited interim condensed consolidated financial statements of TransAlta Corporation as at and for the three months ended March 31, 2013 and 2012, and should also be read in conjunction with the audited consolidated financial statements and MD&A contained within our 2012 Annual Report. In this MD&A, unless the context otherwise requires, ‘we’, ‘our’, ‘us’, the ‘Corporation’ and ‘TransAlta’ refers to TransAlta Corporation and its subsidiaries. The consolidated financial statements have been prepared in accordance with International Financial Reporting Standards (“IFRS”). All tabular amounts in the following discussion are in millions of Canadian dollars unless otherwise noted. This MD&A is dated April 22, 2013. Additional information respecting TransAlta, including its Annual Information Form, is available on SEDAR at www.sedar.com.

rESULTS OF OPERATIONS

The results of operations are presented on a consolidated basis and by business segment. We have three business segments: Generation, Energy Trading, and Corporate. In this MD&A, the impact of foreign exchange fluctuations on foreign currency denominated transactions and balances is discussed with the relevant Condensed Consolidated Statements of Earnings (Loss) and Condensed Consolidated Statements of Financial Position items. While individual line items in the Condensed Consolidated Statements of Financial Position may be impacted by foreign exchange fluctuations, the net impact of the translation of these items relating to foreign operations to our presentation currency is reflected in Accumulated Other Comprehensive Income (Loss) (“AOCI”) in the equity section of the Condensed Consolidated Statements of Financial Position.

highlights

Generation Results

• Comparable gross margins, which doesn’t include finance lease income, decreased $4 million to $363 million quarter over quarter, primarily due to lower contract pricing at Centralia Thermal and higher Alberta coal Power Purchase Arrangement (“PPA”) penalties due to higher prices in Alberta during outages, offset by lower planned outages at the Alberta coal PPA facilities, lower market curtailments, and higher hydro margins.

• Total finance lease income increased $9 million in the quarter due to the new Solomon finance lease.

• Overall fleet availability was 91.5 per cent compared to 91.7 per cent in 2012.

• Production increased 1,203 gigawatt hours (“GWh”) to 10,644 GWh compared to 2012.

• Through continued efforts to lower costs and focus on productivity, Operations, Maintenance, and Administration (“OM&A”) costs have been reduced by $7 million to $92 million.

transalta corporation / Q1 2013   1

Energy Trading Results

• Energy Trading gross margins were consistent with the prior year at $17 million.

Financial Highlights

• Funds from Operations (“FFO”) increased $3 million to $192 million compared to the prior year.

• Comparable Earnings Before Interest, Taxes, Depreciation, and Amortization (“EBITDA”) increased $15 million in the quarter to $267 million compared to 2012.

• Comparable earnings were $32 million ($0.12 per share), down from $44 million ($0.20 per share) in 2012. The decrease in comparable earnings is primarily due to lower earnings in the Generation Segment driven by a higher comparable inventory writedown and lower tax recoveries, partially offset by OM&A savings.

• Reported net losses attributable to common shareholders were $11 million ($0.04 net loss per share), down from net earnings attributable to common shareholders of $88 million ($0.39 net earnings per share) in 2012. The change is driven by the following non-comparable amounts, net of tax:

• Impact of de-designated hedges $82 million

• Loss on assumption of pension obligations of $22 million

• During the quarter, our New Richmond wind farm was commissioned.

The following table depicts key financial results and statistical operating data:

	3 months ended March 31
	2013	2012
Availability (%)(1)	91.5	91.7
Production (GWh)(1)	10,644	9,441
Revenues	540	644
Gross margin(2)	339	469
Comparable gross margin(3)	380	374
Operating income(2)	76	171
Comparable operating income(3)	128	122
Net earnings (loss) attributable to common shareholders	(11)	88
Net earnings (loss) per share attributable to common shareholders, basic and diluted	(0.04)	0.39
Comparable net earnings per share(3)	0.12	0.20
Comparable EBITDA(3)	267	252
Funds from operations(3)	192	189
Funds from operations per share(3)	0.74	0.84
Cash flow from operating activities	256	183
Free cash flow(3)	76	10
Dividends paid per common share	0.29	0.29

(1) Availability and production includes all generating assets (generation operations, finance leases, and equity investments).

(2) These items are Additional IFRS Measures. Refer to the Additional IFRS Measures section of this MD&A for further discussion of these items.

(3) These comparable items are not defined under IFRS. Presenting these items from period to period provides management and investors with the ability to evaluate earnings trends more readily in comparison with prior periods’ results. Refer to the Non-IFRS Measures section of this MD&A for further discussion of these items, including, where applicable, reconciliations to measures calculated in accordance with IFRS

transalta corporation / Q1 2013   2

As at	March 31, 2013	Dec. 31, 2012
Total assets	9,357	9,462
Total long-term liabilities	4,749	4,729

AVAILABILITY & PRODUCTION

Availability for the three months ended March 31, 2013 was 91.5 per cent compared to 91.7 per cent in the first quarter of 2012.

Production for the three months ended March 31, 2013 increased 1,203 GWh compared to the same period in 2012 due to lower economic dispatching at Centralia Thermal, lower planned outages at the Alberta coal PPA facilities, and lower market curtailments, partially offset by higher unplanned outages at the Alberta coal PPA facilities and lower PPA customer demand.

NET EARNINGs attributable to common shareholders

The primary factors contributing to the change in net earnings attributable to common shareholders for the three months ended March 31, 2013 are presented below:

	3 months ended March 31
Net earnings attributable to common shareholders, 2012	88
Decrease in Generation comparable gross margins	(4)
Mark-to-market movements and de-designations - Generation	(126)
Decrease in operations, maintenance, and administration costs	13
Decrease in depreciation and amortization expense	2
Decrease in gain on sale of assets	(3)
Decrease in inventory writedown	20
Increase in finance lease income	9
Decrease in equity income	(4)
Increase in loss on assumption of pension obligations	(29)
Increase in net interest expense	(2)
Decrease in income tax expense	19
Increase in preferred share dividends	(2)
Other	8
Net loss attributable to common shareholders, 2013	(11)

Generation comparable gross margins for the three months ended March 31, 2013, excluding the impact of mark-to-market movements, decreased by $4 million compared to the same period in 2012, as there was lower contract pricing at Centralia Thermal and higher Alberta coal PPA penalties due to higher prices in Alberta during outages were largely offset by lower planned outages at the Alberta coal PPA facilities, lower market curtailments, and higher hydro margins.

Mark-to-market movements decreased for the three months ended March 31, 2013 compared to the same period in 2012 due to the recognition of higher mark-to-market gains in 2012 resulting from certain power hedging relationships being deemed ineffective and released from AOCI to net earnings.

OM&A costs for the three months ended March 31, 2013 decreased compared to the same period in 2012 primarily due to lower compensation costs as a result of organizational restructuring in the fourth quarter of 2012 and a continued focus on costs.

transalta corporation / Q1 2013   3

Depreciation and amortization expense for the three months ended March 31, 2013 decreased compared to 2012 primarily due to a lower depreciable asset base caused by asset impairments and the change in the economic useful lives of Alberta coal-fired plants resulting from amendments to Canadian federal regulations in 2012, partially offset by an increased asset base through acquiring new assets.

The decrease in the gain on sale of assets in the three months ended March 31, 2013 compared to 2012 is due to the release of a contingent provision on the sale of our Grande Prairie facility in 2012.

Coal inventory has been written down to its net realizable value at our Centralia plant.  The writedown in March 2013 is lower compared to the same period in 2012 due to an increase in prices in the Pacific Northwest and a decrease in inventory costs.

Finance lease income for the three months ended March 31, 2013 increased compared to the same period in 2012 due to the acquisition of the Solomon Power station. We began receiving lease payments in the fourth quarter of 2012.

Equity income for the three months ended March 31, 2013 decreased compared to 2012 primarily due to unfavourable pricing and higher planned outages at CE Generation, LLC (“CE Gen”).

During the quarter, we assumed certain pension obligations upon the assumption of operating and management control of the Highvale Mine.

Net interest expense for the three months ended March 31, 2013 increased compared to the same period in 2012 due to higher debt levels.

Income tax expense for the three months ended March 31, 2013 decreased compared to the same period in 2012 due to lower
pre-tax earnings and an income tax recovery related to an adjustment in the deferred tax rate.

The preferred share dividends for the three months ended March 31, 2013 increased compared to the same period in 2012 due to a higher balance of preferred shares outstanding during 2013.

Funds from operations AND FREE CASH FLOW

FFO for the three months ended March 31, 2013 increased $3 million compared to the same period in 2012 to $192 million after adjusting net earnings for the non-cash impacts from risk management activities.

Free cash flow for the three months ended March 31, 2013 increased $66 million compared to the same period in 2012 due to lower cash dividends paid as a result of increased participation in the Premium Dividend^TM, Dividend Reinvestment and Optional Common Share Purchase Plan (the “Plan”) and lower sustaining capital expenditures, partially offset by lower net earnings.

transalta corporation / Q1 2013   4

significant Events

Keephills Unit 1

On March 26, 2013, we announced that an outage occurred on March 5, 2013 at Unit 1 of our Keephills facility due to a winding failure found in the generator. In response to the event, we gave notice of a High Impact Low Probability event and claimed force majeure relief under the PPA. In the event of a force majeure, we are entitled to continue to receive our PPA capacity payment and are protected under the terms of the PPA from having to pay availability penalties. As a result, we do not expect the outage to have a material financial impact on the Corporation. We are working with the original equipment manufacturer of the generator to safely return the Unit to service, which is currently expected to be in early May of 2013. During the quarter, the PPA Buyer informed us that they will be taking the matter to arbitration.

Centralia Thermal

On July 25, 2012, we announced that we entered into an 11-year agreement to provide electricity from the Centralia Thermal plant to Puget Sound Energy (“PSE”).  The agreement was approved, with conditions, by the Washington Utilities and Transportation Commission (“WUTC”) on Jan. 9, 2013. On Jan. 23, 2013, it was announced that PSE had filed a petition for reconsideration of certain conditions within the decision issued by the WUTC. On March 22, 2013, the administrative law judge managing the regulatory hearing process issued two Commission Orders to establish an amended timeline for addressing the petition for reconsideration. The deadline for filing answers to the reconsideration motion is May 30, 2013 and the timeline for a decision on the reconsideration motion is no later than June 28, 2013.

New Richmond

On March 13, 2013, our 68 megawatt (“MW”) New Richmond wind farm began commercial operations. The total cost of the project is still forecasted to be approximately $212 million.

SunHills Mining Limited Partnership

Effective Jan. 17, 2013, we assumed, through our wholly owned SunHills Mining Limited Partnership (“SunHills”), operations and management control of the Highvale Mine from Prairie Mines and Royalty Ltd. (“PMRL”). PMRL employees working at the Highvale Mine were offered employment by SunHills which agreed to assume responsibility for certain pension plan and pension funding obligations, which we had previously funded through the payments made under the PMRL mining contracts. As a result, a pre-tax loss of $29 million was recognized, along with the corresponding liabilities.

We also entered into a related finance lease for certain mining equipment that was used by PMRL in mining operations. As a result,
$21 million in mining equipment has been capitalized to property, plant and equipment and the related finance lease obligation recognized. At the end of the lease term, we are eligible to purchase the assets subject to lease, for a nominal amount.

Change in Estimates - Useful Lives

During the three months ended March 31, 2013, management completed a comprehensive review of the estimated useful lives of our hydro assets, having regard for, among other things, our economic life cycle maintenance program and the existing condition of the assets. As a result, depreciation was reduced by $1 million for the three months ended March 31, 2013. Pre-tax depreciation expense is expected to be reduced by $5 million for the year ended Dec. 31, 2013 and by $5 million annually thereafter.

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Centralia Coal Inventory Writedown

During the quarter, we recognized a pre-tax writedown of $14 million related to the coal inventory at our Centralia plant to write the inventory down to its net realizable value.

BUSINESS environment

We operate in a variety of business environments to generate electricity, find buyers for the power we generate, and arrange for its transmission. The major markets we operate in are Western Canada, the Western United States (“U.S.”), and Eastern Canada. For a further description of the regions in which we operate as well as the impact of prices of electricity and natural gas upon our financial results, refer to our 2012 Annual MD&A.

Contracted Cash Flows

During the first quarter of 2013, approximately 90 per cent of our consolidated power portfolio was contracted through the use of PPAs and other long-term contracts. We also entered into short-term physical and financial contracts for the remaining volumes, which are primarily for periods of up to five years. The average price of these contracts for the balance of 2013 are approximately $60 per megawatt hour (“MWh”) in Alberta and approximately U.S.$40 per MWh in the Pacific Northwest.

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Electricity Prices

Please refer to the Business Environment section of our 2012 Annual MD&A for a full discussion of the spot electricity market and the impact of electricity prices on our business, as well as our strategy to hedge our risks associated with changes in these prices.

The average spot electricity prices for the three months ended March 31, 2013 and 2012 in our three major markets is shown in the following graph.

For the three months ended March 31, 2013, average spot prices in Alberta increased compared to the same period in 2012 primarily due to overall higher planned and unplanned outages leading to tighter supply and demand conditions. In the Pacific Northwest, average spot prices increased due to higher natural gas prices and lower hydro generation. The average spot prices in Ontario increased compared to 2012 due to higher natural gas prices and stronger weather-driven loads.

In 2013, power prices in Alberta are expected to be lower than 2012 due to fewer planned turnarounds and increased capacity due to additional generation facilities coming online, partially offset by load growth. In the Pacific Northwest, we expect prices to be modestly stronger than in 2012; however, we expect that overall prices will still remain weak due to anticipated low natural gas prices and slow load growth.

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Spark Spreads

Please refer to the Business Environment section of our 2012 Annual MD&A for a full discussion of spark spreads and the impact of spark spreads on our business.

The average spark spreads for the three months ended March 31, 2013 and 2012 in our three major markets is shown in the following graph.

(1) For a 7,000 British Thermal Units per Kilowatt hour heat rate plant.

For the three months ended March 31, 2013, average spark spreads decreased in Alberta compared to the same period in 2012 due to natural gas prices rising faster than power prices. In the Pacific Northwest average spark spreads were consistent with 2012 as power prices and natural gas prices increased at relatively similar rates. For the three months ended March 31, 2013, average spark spreads increased in Ontario compared to the same period in 2012 as a result of power prices increasing more than natural gas prices.

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GENERATION: TransAlta owns and operates hydro, wind, natural gas-fired and coal-fired facilities, and related mining operations in Canada, the U.S., and Australia. Generation revenues and overall profitability are derived from the availability and production of electricity and steam as well as ancillary services such as system support. For a full listing of all of our generating assets and the regions in which they operate, refer to the Plant Summary section of our 2012 Annual MD&A.

Generation Operations: During the first quarter of 2013, we began commercial operations at New Richmond, a 68 MW wind farm in Quebec. At March 31, 2013, our generating assets had 8,268 MW of gross generating capacity⁽²⁾ in operation (7,926 MW net ownership interest) and 560 MW under restoration in the Sundance Units 1 and 2 major project. The following information excludes assets that are accounted for as a finance lease or using the equity method, which are discussed separately within this discussion of the Generation Segment.

The results of Generation Operations are as follows:

	2013				2012
3 months ended March 31	Total	Comparable adjustments	Comparable total(2)	Per installed MWh	Comparable total(2)	Per installed MWh
Revenues	523	41	564	31.59	542	30.36
Fuel and purchased power	201	-	201	11.26	175	9.80
Gross margin	322	41	363	20.33	367	20.55
Operations, maintenance, and administration	92	-	92	5.15	99	5.55
Depreciation and amortization	122	-	122	6.83	124	6.95
Inventory writedown	14	-	14	0.78	-	-
Taxes, other than income taxes	7	-	7	0.39	7	0.39
Intersegment cost allocation	4	-	4	0.22	3	0.17
Operating income	83	41	124	6.96	134	7.49
Installed capacity (GWh)	17,856		17,856		17,851
Production (GWh)	10,112		10,112		8,913
Availability (%)	91.6		91.6		91.6

(1) We measure capacity as net maximum capacity (see glossary for definition of this and other key terms), which is consistent with industry standards. Capacity figures represent capacity owned and in operation unless otherwise stated.

(2) Comparable figures are not defined under IFRS. Refer to the Non-IFRS Measures section of this MD&A for further discussion of these items, including, where applicable, reconciliations to net earnings attributable to common shareholders and cash flow from operating activities.

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Generation Operations Production and Comparable Gross Margins

Production volumes, comparable revenues, fuel and purchased power expenses, and comparable gross margins based on geographical regions and fuel types are presented below.

3 months ended March 31, 2013	Production (GWh)	Installed (GWh)	Comparable revenues	Comparable fuel & purchased power	Comparable gross margin	Comparable revenues per installed MWh	Fuel & purchased power per installed MWh	Comparable gross margin per installed MWh
Coal	5,275	6,926	228	94	134	32.92	13.57	19.35
Gas	668	769	30	7	23	39.01	9.10	29.91
Renewables	739	2,889	56	3	53	19.38	1.04	18.34
Total Western Canada	6,682	10,584	314	104	210	29.67	9.83	19.84
Gas	1,001	1,619	105	51	54	64.85	31.50	33.35
Renewables	425	1,573	42	2	40	26.70	1.27	25.43
Total Eastern Canada	1,426	3,192	147	53	94	46.05	16.60	29.45
Coal	1,678	2,896	71	31	40	24.52	10.70	13.82
Gas	326	1,184	32	13	19	27.03	10.98	16.05
Total International	2,004	4,080	103	44	59	25.25	10.78	14.47
	10,112	17,856	564	201	363	31.59	11.26	20.33

3 months ended March 31, 2012	Production (GWh)	Installed (GWh)	Comparable revenues	Fuel & purchased power	Comparable gross margin	Comparable revenues per installed MWh	Fuel & purchased power per installed MWh	Comparable gross margin per installed MWh
Coal	5,263	6,944	210	81	129	30.24	11.66	18.58
Gas	704	778	31	6	25	39.85	7.71	32.14
Renewables	751	2,921	48	3	45	16.43	1.03	15.40
Total Western Canada	6,718	10,643	289	90	199	27.15	8.46	18.69
Gas	1,003	1,638	99	43	56	60.44	26.25	34.19
Renewables	460	1,444	45	2	43	31.16	1.39	29.77
Total Eastern Canada	1,463	3,082	144	45	99	46.72	14.60	32.12
Coal	404	2,929	82	32	50	28.00	10.93	17.07
Gas	328	1,197	27	8	19	22.56	6.68	15.88
Total International	732	4,126	109	40	69	26.42	9.69	16.73
	8,913	17,851	542	175	367	30.36	9.80	20.55

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Western Canada

Our Western Canada assets consist of coal, natural gas, hydro, and wind facilities. Refer to the Discussion of Segmented Results section of our 2012 Annual MD&A for further details on our Western Canadian operations.

The primary factors contributing to the change in production for the three months ended March 31, 2013 are presented below:

	3 months ended March 31
	(GWh)
Production, 2012	6,718
Higher unplanned outages at the Alberta coal PPA facilities	(356)
Lower PPA customer demand	(108)
Lower production at natural gas-fired facilities	(36)
Lower wind volumes	(8)
Lower hydro volumes	(4)
Lower planned outages at the Alberta coal PPA facilities	283
Market curtailments	111
Lower unplanned outages at Genesee Unit 3	75
Other	7
Production, 2013	6,682

The primary factors contributing to the change in comparable gross margin for the three months ended March 31, 2013 are presented below:

	3 months ended March 31
Comparable gross margin, 2012	199
Lower planned outages at the Alberta coal PPA facilities	16
Market curtailments	7
Higher hydro margins	6
Lower unplanned outages at Genesee Unit 3	4
Pricing, primarily related to hedging and penalties paid under Alberta coal PPAs	(11)
Higher unplanned outages at the Alberta coal PPA facilities	(5)
Unfavourable coal pricing	(3)
Other	(3)
Comparable gross margin, 2013	210

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Eastern Canada

Our Eastern Canada assets consist of natural gas, hydro, and wind facilities. Refer to the Discussion of Segmented Results section of our 2012 Annual MD&A for further details on our Eastern Canadian operations.

The primary factors contributing to the change in production for the three months ended March 31, 2013 are presented below:

	3 months ended March 31
	(GWh)
Production, 2012	1,463
Lower wind volumes	(31)
Unfavourable market conditions at natural gas-fired facilities	(2)
Other	(4)
Production, 2013	1,426

The primary factors contributing to the change in gross margin for the three months ended March 31, 2013 are presented below:

	3 months ended March 31
Gross margin, 2012	99
Unfavourable contracted gas input costs	(2)
Lower wind volumes	(2)
Other	(1)
Gross margin, 2013	94

International

Our International assets consist of coal, natural gas, and hydro facilities in various locations in the United States, and natural gas and diesel assets in Australia. Refer to the Discussion of Segmented Results section of our 2012 Annual MD&A for further details on our International operations.

The primary factors contributing to the change in production for the three months ended March 31, 2013 are presented below:

	3 months ended March 31
	(GWh)
Production, 2012	732
Lower economic dispatching at Centralia Thermal	1,301
Higher planned and unplanned outages at Centralia Thermal	(25)
Other	(4)
Production, 2013	2,004

transalta corporation / Q1 2013   12

The primary factors contributing to the change in comparable gross margin for the three months ended March 31, 2013 are presented below:

	3 months ended March 31
Comparable gross margin, 2012	69
Lower contract pricing, including margins on purchased power	(35)
Coal pricing(1)	23
Other	2
Comparable gross margin, 2013	59

During the quarter, we recognized a pre-tax writedown of $14 million related to the coal inventory at our Centralia plant to write the inventory down to its net realizable value.

Operations, Maintenance, and Administration Expense

OM&A expenses for the three months ended March 31, 2013 decreased compared to the same period in 2012, primarily due to lower compensation costs as a result of restructuring in the fourth quarter of 2012 and a continued focus on costs.

Depreciation and Amortization Expense

The primary factors contributing to the change in depreciation and amortization expense for the three months ended March 31, 2013 are presented below:

	3 months ended March 31
Depreciation and amortization expense, 2012	124
Increase in asset base	7
Impact of asset impairments	(8)
Change in economic life(2)	(5)
Change in useful lives of hydro assets	(1)
Other	5
Depreciation and amortization expense, 2013	122

Finance Leases

Solomon

On Sept. 28, 2012, we completed the acquisition from Fortescue Metals Group Ltd. (“Fortescue”) of its 125 MW natural gas-fired and diesel-fired Solomon power station in Western Australia for U.S.$318 million. The facility and associated Power Purchase Agreement (“Agreement”) are accounted for as a finance lease and we began receiving payments under the Agreement in the fourth quarter of 2012. The facility is currently under construction and is expected to be commissioned during the second quarter of 2013.

(1) Coal price includes the impact of the inventory writedown which is not included in gross margin.

(2) As a result of amendments to Canadian federal regulations requiring that coal-fired plants be shut down after a maximum of 50 years of operation. The previous draft regulations proposed shut down after 45 years. The useful lives of these assets were changed in the third quarter of 2012.

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Fort Saskatchewan

Fort Saskatchewan is a natural gas-fired facility with a gross generating capacity of 118 MW in operation, of which TransAlta Cogeneration, L.P. has a 60 per cent ownership interest (35 MW net ownership interest). Key operational information adjusted to reflect our interest in the Fort Saskatchewan facility, which we continue to operate, is summarized below:

	3 months ended March 31
	2013	2012
Availability (%)	104.5	102.6
Production (GWh)	138	137

Availability for the three months ended March 31, 2013 increased compared to the same period in 2012, due to lower unplanned outages.

Production for the three months ended March 31, 2013 is consistent with the same period in 2012.

Total Finance Lease Income

Total finance lease income for the three months ended March 31, 2013 increased $9 million compared to the same period in 2012 due to the payments we began receiving in October 2012 under the Agreement with Fortescue.

Equity Investments

Our interests in the CE Gen and Wailuku River Hydroelectric, L.P. joint ventures are accounted for using the equity method and are comprised of geothermal, natural gas, and hydro facilities in various locations throughout the U.S., with 839 MW of gross generating capacity (390 MW net ownership interest). The table below summarizes key operational information adjusted to reflect our interest in these investments:

	3 months ended March 31
	2013	2012
Availability (%)	86.9	92.9
Production (GWh)
Gas	140	91
Renewables	254	300
Total production	394	391

Availability for the three months ended March 31, 2013 decreased compared to the same period in 2012 due to higher planned outages, partially offset by lower unplanned outages.

Production for the three months ended March 31, 2013 increased compared to the same period in 2012 due to lower unplanned outages and higher customer demand, partially offset by higher planned outages.

Equity loss for the three months ended March 31, 2013 was $4 million compared to equity income of nil for the same period in 2012. The decrease is primarily due to unfavourable pricing and higher planned outages.

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Since 2001, a significant portion of the CE Gen plants have been operating under modified fixed energy price contracts.  Commencing May 1, 2012, the terms of the contracts reverted to a pricing clause that permits the power purchaser to pay their short-run avoided costs (“SRAC”) as the price for power.  The SRAC is linked to the price of natural gas.  There can be no assurances that prices based on the avoided cost of energy after May 1, 2012 will result in revenues equivalent to those realized under the fixed energy price structure.

ENERGY TRADING: Derives revenue and earnings from the wholesale trading of electricity and other energy-related commodities and derivatives. Achieving gross margins, while remaining within Value at Risk (“VaR”) limits, is a key measure of Energy Trading’s activities. Refer to the Value at Risk and Trading Positions discussion in the Risk Management section of our 2012 Annual MD&A for further discussion on VaR.

Energy Trading utilizes contracts of various durations for the forward purchase and sale of electricity and for the purchase and sale of natural gas and transmission capacity. If the activities are performed on behalf of the Generation Segment, the results of these activities are included in the Generation Segment.

For a more in-depth discussion of our Energy Trading activities, refer to the Discussion of Segmented Results section of our 2012 Annual MD&A.

The results of the Energy Trading Segment, with all trading results presented on a net basis, are as follows:

	3 months ended March 31
	2013	2012
Revenues	17	17
Fuel and purchased power	-	-
Gross margin	17	17
Operations, maintenance, and administration	7	7
Intersegment cost allocation	(4)	(3)
Operating income	14	13

For the three months ended March 31, 2013, Energy Trading gross margins and OM&A expenses are consistent compared to the same period in 2012.

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CORPORATE: Our Generation and Energy Trading Segments are supported by a Corporate group that provides finance, tax, treasury, legal, regulatory, environmental, health and safety, sustainable development, corporate communications, government and investor relations, information technology, risk management, human resources, internal audit, and other administrative support.

The expenses incurred by the Corporate Segment are as follows:

	3 months ended March 31
	2013	2012
Operations, maintenance, and administration	16	22
Depreciation and amortization	5	5
Operating loss	21	27

OM&A expenses for the three months ended March 31, 2013 decreased compared to the same period in 2012, primarily due to lower compensation costs as a result of restructuring in the fourth quarter of 2012 and a continued focus on costs.

NET INTEREST EXPENSE

The components of net interest expense are shown below:

	3 months ended March 31
	2013	2012
Interest on debt	60	56
Capitalized interest	(2)	-
Interest expense	58	56
Accretion of provisions	4	4
Net interest expense	62	60

The change in net interest expense for the three months ended March 31, 2013,compared to the same period in 2012, is shown below:

	3 months ended March 31
Net interest expense, 2012	60
Higher capitalized interest	(2)
Unfavourable foreign exchange impacts	1
Higher financing costs	1
Higher debt levels	2
Net interest expense, 2013	62

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INCOME TAXES

A reconciliation of income taxes and effective tax rates on earnings, excluding non-comparable items, is presented below:

	3 months ended March 31
	2013	2012
Earnings (loss) before income taxes	(9)	110
Income attributable to non-controlling interests	(10)	(13)
Equity loss	4	-
Impacts associated with certain de-designated and ineffective hedges	41	(85)
Inventory writedown	-	34
Gain on sale of assets	-	(3)
Loss on assumption of pension obligations	29	-
Earnings attributable to TransAlta shareholders, excluding non-comparable items, subject to tax	55	43
Income tax expense (recovery)	(17)	2
Income tax recovery (expense) related to impacts associated with certain de-designated and ineffective hedges	14	(30)
Income tax recovery related to inventory writedown	-	12
Income tax expense related to gain on sale of assets	-	(1)
Income tax recovery related to deferred tax rate adjustment	6	-
Income tax recovery related to the resolution of certain outstanding tax matters	-	9
Income tax recovery related to loss on assumption of pension obligations	7	-
Income tax expense (recovery) excluding non-comparable items	10	(8)
Effective tax rate on earnings (loss) attributable to TransAlta shareholders excluding non-comparable items (%)	18	(19)

The income tax expense excluding non-comparable items for the three months ended March 31, 2013 increased compared to the same period in 2012 due to higher taxable comparable earnings and the positive resolution of certain comparable tax contingency matters in the prior period.

The effective tax rate on earnings attributable to TransAlta shareholders excluding non-comparable items for the three months ended March 31, 2013 increased compared to the same period in 2012 due to changes in the amount of earnings between the jurisdictions in which pre-tax income is earned, the effect of certain deductions that do not fluctuate with earnings, and due to the positive resolution of certain comparable tax contingency matters in the prior period.

NON-CONTROLLING INTERESTS

Net earnings attributable to non-controlling interests for the three months ended March 31, 2013 was comparable to the same period in 2012.

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financial position

The following chart highlights significant changes in the Condensed Consolidated Statements of Financial Position from
Dec. 31, 2012 to March 31, 2013:

	Increase/
	(Decrease)	Primary factors explaining change
Cash and cash equivalents	23	Timing of receipts and payments
Accounts receivable	(140)	Timing of customer receipts and overall lower revenues
Prepaid expenses	18	Prepayment of annual insurance premiums
Property, plant, and equipment, net	34	Additions partially offset by depreciation
Deferred income tax assets	25	Tax benefits of losses related to the profitability of U.S. operations
Risk management assets (current and long-term)	(84)	Price movements and changes in underlying positions and settlements
Other assets	13	Increase in long-term prepaids
Accounts payable and accrued liabilities	(45)	Timing of payments and lower capital accruals
Long-term debt (including current portion)	14	Unfavourable foreign exchange, partially offset by repayments and decreased borrowings under credit facilities
Finance lease obligation (including current portion)	21	Finance lease for certain equipment used in mining operations at the Highvale Mine
Risk management liabilities (current and long-term)	(51)	Price movements and changes in underlying positions and settlements
Equity attributable to shareholders	(34)	Net loss for the period and share dividends, partially offset by issuance of common shares

financial instruments

Refer to Note 13 of the notes to the audited consolidated financial statements within our 2012 Annual Report and Note 11 of our interim condensed consolidated financial statements as at and for the three months ended March 31, 2013 for details on Financial Instruments. Refer to the Risk Management section of our 2012 Annual Report and Note 12 of our interim condensed consolidated financial statements for further details on our risks and how we manage them. Our risk management profile and practices have not changed materially from Dec. 31, 2012.

Energy Trading may enter into commodity transactions involving non-standard features for which market observable data is not available. These are defined under IFRS as Level III financial instruments. Level III financial instruments are not traded in an active market and fair value is, therefore, developed using valuation models based upon internally developed assumptions or inputs. Our
Level III fair values are determined using data such as unit availability, transmission congestion, or demand profiles. Fair values are validated on a quarterly basis by using reasonably possible alternative assumptions as inputs to valuation techniques, and any material differences are disclosed in the notes to the financial statements.

We also have various contracts with terms that extend beyond five years.  As forward price forecasts are not available for the full period of these contracts, the value of these contracts must be derived by reference to a forecast that is based on a combination of external and internal fundamental modeling, including discounting.  As a result, these contracts are classified in Level III. These contracts are for specified prices with counterparties that we believe to be creditworthy.

transalta corporation / Q1 2013   18

At March 31, 2013, total Level III financial instruments had a net asset carrying value of $17 million (Dec. 31, 2012 - $31 million net asset).

Certain of our hedging relationships had previously been de-designated and deemed ineffective for accounting purposes.  The hedges were in respect of power production and the associated gains remain in AOCI until the underlying production occurs or until such time that the production has been assessed as highly probable not to occur.  No gains related to these previously
de-designated hedges were reclassified to earnings during the three months ended March 31, 2013 (March 31, 2012 - $75 million pre-tax gain). 

As at March 31, 2013, cumulative gains of $7 million related to cash flow hedges that were de-designated and no longer meet the criteria for hedge accounting continued to be deferred in AOCI and will be reclassified to net earnings as the forecasted transactions occur or if the forecasted transactions are assessed as highly probable not to occur. 

STATEMENTS OF CASH FLOWS

The following charts highlight significant changes in the Condensed Consolidated Statements of Cash Flows for the three months ended March 31, 2013 compared to the same period in 2012:

3 months ended March 31	2013	2012	Primary factors explaining change
Cash and cash equivalents, beginning of period	27	49
Provided by (used in):
Operating activities	256	183	Favourable changes in working capital of $83 million partially offset by lower cash earnings of $10 million
Investing activities	(150)	(164)	Decrease in additions to PP&E and intangibles of $11 million and a net positive cash impact of $8 million related to changes in collateral received from or paid to counterparties, partially offset by an unfavourable change in non-cash investing working capital balances of $7 million and lower proceeds on sale of assets of $3 million
Financing activities	(84)	(37)	Decrease in borrowings under credit facilities of $73 million partially offset by a decrease in common share cash dividends of $25 million due to dividends reinvested through the dividend reinvestment plan
Translation of foreign currency cash	1	-
Cash and cash equivalents, end of period	50	31

transalta corporation / Q1 2013   19

Liquidity and Capital Resources

Liquidity risk arises from our ability to meet general funding needs, engage in trading and hedging activities, and manage the assets, liabilities, and capital structure of the Corporation. Liquidity risk is managed by maintaining sufficient liquid financial resources to fund obligations as they come due in the most cost-effective manner.

Our liquidity needs are met through a variety of sources, including cash generated from operations, borrowings under our long-term credit facilities, and long-term debt or equity issued under our Canadian and U.S. shelf registrations. Our primary uses of funds are operational expenses, capital expenditures, dividends, distributions to non-controlling limited partners, and interest and principal payments on debt securities.

Debt

Long-term debt totalled $4.2 billion as at March 31, 2013 compared to $4.2 billion as at Dec. 31, 2012.

Credit Facilities

At March 31, 2013, we had a total of $2.0billion (Dec. 31, 2012 - $2.0 billion) of committed credit facilities, of which $0.8billion (Dec. 31, 2012 - $0.8 billion) is not drawn and is available, subject to customary borrowing conditions. At March 31, 2013, the $1.2 billion (Dec. 31, 2012 - $1.3 billion) of credit utilized under these facilities was comprised of actual drawings of $0.9 billion (Dec. 31, 2012 - $1.0 billion) and letters of credit of $0.3 billion (Dec. 31, 2012 - $0.3 billion). These facilities are comprised of a $1.5 billion committed syndicated bank facility that matures in 2016, with the remainder comprised of bilateral credit facilities, of which $0.3 billion matures in the third quarter of 2013 and $0.2 billion matures in the fourth quarter of 2014. We anticipate renewing these facilities, based on reasonable commercial terms, prior to their maturities.

In addition to the $0.8 billion available under the credit facilities, we also have $48 million of available cash.

Share Capital

On April 22, 2013, we had 262.1 million common shares outstanding, 12.0 million Series A, 11.0 million Series C, and 9.0 million Series E first preferred shares outstanding.  At March 31, 2013, we had 258.4 million (Dec. 31, 2012 - 254.7 million) common shares issued and outstanding. At March 31, 2013, we also had 32.0 million (Dec. 31, 2012 - 32.0 million) preferred shares issued and outstanding.

We issue common shares for cash proceeds, on exercise of stock options and other share-based payment plans, or for reinvestment of dividends.  During February 2012, we added a Premium Dividend^TM component to the Plan. Please refer to Note 28 of our audited consolidated financial statements within our 2012 Annual Report for additional information regarding the amendments.

During the three months ended March 31, 2013, 3.7 million (March 31, 2012 - 0.9 million) common shares were issued for $53 million (March 31, 2012 - $20 million), which were comprised of dividends reinvested under the terms of the Plan.

transalta corporation / Q1 2013   20

Guarantee Contracts

We have obligations to issue letters of credit and cash collateral to secure potential liabilities to certain parties, including those related to potential environmental obligations, energy trading activities, hedging activities, and purchase obligations. At March 31, 2013, we provided letters of credit totalling $327 million (Dec. 31, 2012 - $336 million) and cash collateral of $17 million (Dec. 31, 2012 - $19 million). These letters of credit and cash collateral secure certain amounts included on our Condensed Consolidated Statements of Financial Position under risk management liabilities and decommissioning and other provisions.

Commitments

During March 2013, the New Richmond wind farm commenced operations and as such, the 15 year long-term service agreement for repairs and maintenance became effective.  The future payments over the term of the agreement are approximately $35 million. 

climate change and the environment

In Alberta, there are requirements for coal-fired generation units to implement additional air emission controls for oxides of nitrogen (“NOx”), sulphur dioxide (“SO₂”), and particulate matter, once they reach the end of their respective PPAs, in most cases at 2020.  These regulatory requirements were developed by the province in 2004 as a result of multi-stakeholder discussions under Alberta’s Clean Air Strategic Alliance (“CASA”).  However, the release of the federal Greenhouse Gas (“GHG”) regulations may create a potential misalignment between the CASA air pollutant requirements and schedules, and the GHG retirement schedules for older coal plants, which in themselves will result in significant reductions of NOx, SO₂, and particulates.  We are in discussions with the provincial government to ensure coordination between GHG and air pollutant regulations, such that emission reduction objectives are achieved in the most effective manner while taking into consideration the reliability and cost of Alberta’s generation supply.

On March 27, 2012, the U.S. Environmental Protection Agency (“EPA”) proposed GHG emission standards for future coal-fired power plants. Compliance under the proposed standard will likely be met with fuel switching or clean coal technologies. As this regulatory framework is for new coal-fired plants, we expect no material impact on our existing coal units at Centralia.

In December 2011, the EPA issued national standards for mercury emissions from power plants. Existing sources will have up to four years to comply. We have already voluntarily installed mercury capture technology at our Centralia coal-fired plant, and began full capture operations in early 2012. We have also installed additional technology to further reduce NOx, consistent with the Washington State Bill passed in April 2011.

We continue to make operational improvements and investments to our existing generating facilities to reduce the environmental impact of generating electricity. We installed mercury control equipment at our Alberta Thermal operations in 2010 in order to meet the province’s 70 per cent reduction objectives, and voluntarily at our Centralia coal-fired plant in 2012. Our Keephills Unit 3 plant began operations in September 2011 using supercritical combustion technology to maximize thermal efficiency, as well as SO₂ capture and low NOx combustion technology, which is consistent with the technology that is currently in use at Genesee Unit 3. Uprate projects completed at our Keephills and Sundance plants are expected to improve the energy and emissions efficiency of those units.

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2013 Outlook

Business Environment

Power Prices

Over the balance of 2013, power prices in Alberta are expected to be lower than in 2012 due to fewer planned turnarounds and increased capacity due to additional generation facilities coming online, partially offset by load growth. In the Pacific Northwest, we expect prices to be modestly stronger than in 2012; however, we expect that overall prices will still remain weak due to low natural gas prices and slow load growth.

Environmental Legislation

The finalization of the federal Canadian GHG regulations for coal-fired power has initiated further activities. We are in discussions with the provincial government to ensure coordination between GHG and air pollutant regulations, such that emission reduction objectives are achieved in the most effective manner while taking into consideration the reliability and cost of Alberta’s generation supply. This may provide additional flexibility to coal-fired generators in meeting the regulatory requirements. For further information on the Canadian GHG regulations, please refer to the Significant Events section of our 2012 Annual MD&A.

In addition, there are ongoing discussions between the federal and provincial governments regarding a national Air Quality Management System for air pollutants. In Alberta’s recently released Clean Air Strategy, the province indicated that its provincial air quality management system will operationalize any national system. Our current outlook is that, for Alberta, provincial regulations will be considered as equivalent to any future national framework.

On Jan. 21, 2013, the Ontario government released a discussion paper for public input on reducing GHG emissions in the province, with the stated intent of developing GHG regulations for all major industrial sectors by 2015. No specific targets or regulatory approaches have yet been proposed.

In the U.S., it is not yet clear how climate change legislation for existing fossil-fuel-based generation will unfold. Additionally, new air pollutant regulations for the power sector are anticipated, but are not expected to directly affect our coal-fired operations in Washington State. TransAlta’s agreement with Washington State, established in April 2011, provides regulatory clarity at the state level regarding an emissions regime related to the Centralia Coal plant until 2025.

Beginning in 2013, direct deliveries of power to the California Independent System Operator will be subject to a compliance obligation established by the California Air Resources Board’s (“CARB”) cap and trade program.  As CARB continues to finalize their regulations, we will stay at the forefront of regulatory changes to enable us to remain in compliance with the cap and trade program.

In Australia, the carbon tax implemented in July 2012 remains in place and is due to increase from AUS$23.00 to AUS$24.15 per tonne in July 2013. While TransAlta’s gas-fired operations are subject to the tax, all related costs are flowed to contracted customers.

We continue to closely monitor the progress and risks associated with environmental legislation changes on our future operations.

The siting, construction, and operation of electrical energy facilities requires interaction with many stakeholders. Recently, certain stakeholders have brought actions against government agencies and owners over alleged adverse impacts of wind projects. We are monitoring these claims in order to assess the risk associated with these activities.

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Economic Environment

In 2013, we expect slow to moderate growth in Alberta and Australia, and low growth in other markets. We continue to monitor global events and their potential impact on the economy and our supplier and commodity counterparty relationships.

We had no material counterparty losses in the first quarter of 2013. We continue to monitor counterparty credit risk and have established risk management policies to mitigate counterparty risk. We do not anticipate any material change to our existing credit practices and continue to deal primarily with investment grade counterparties.

Operations

Capacity, Production, and Availability

Generating capacity is expected to increase for the remainder of 2013 due to Sundance Units 1 and 2 returning to service. Prior to the effect of any economic dispatching, overall production is expected to increase in 2013 due to lower planned outages, Sundance Units 1 and 2 returning to service, and the completion of the New Richmond wind farm. Overall availability is expected to be in the range of 89 to 90 per cent in 2013 due to lower planned outages across the fleet.

Contracted Cash Flows

Through the use of Alberta PPAs, long-term contracts, and other short-term physical and financial contracts, on average, approximately 75 per cent of our capacity is contracted over the next seven years. On an aggregated portfolio basis, depending on market conditions, we target being up to 90 per cent contracted for the upcoming calendar year. As at the end of the first quarter of 2013, approximately 89 per cent of our 2013 capacity was contracted. The average prices of our short-term physical and financial contracts for the balance of 2013 are approximately $60 per MWh in Alberta and approximately U.S.$40 per MWh in the Pacific Northwest.

Fuel Costs

Mining coal in Alberta is subject to cost increases due to greater overburden removal, inflation, capital investments, and commodity prices. Seasonal variations in coal costs at our Alberta mine are minimized through the application of standard costing. In January 2013, we assumed, through SunHills, operating and management control of the Highvale Mine from PMRL. Coal costs for 2013, on a standard cost basis, are expected to be comparable to 2012 with the assumption of operational and management control offsetting any cost increases mentioned above.

Although we own the Centralia mine in the State of Washington, it is not currently operational. Fuel at Centralia Thermal is purchased from external suppliers in the Powder River Basin and delivered by rail. The delivered cost of fuel per MWh for 2013 is expected to decrease between six to eight per cent.

The value of coal inventories is assessed for impairment at the end of each reporting period. If the inventory is impaired, further charges will be recognized in net earnings. For more information on the inventory impairment charges recorded in 2013, please refer to the Significant Events section of this MD&A.

We purchase natural gas from outside companies coincident with production or have it supplied by our customers, thereby minimizing our risk to changes in prices. The continued success of unconventional gas production in North America could reduce the year-to-year volatility of prices in the near term.

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We closely monitor the risks associated with changes in electricity and input fuel prices on our future operations and, where we consider it appropriate, use various physical and financial instruments to hedge our assets and operations from such price risks.

Operations, Maintenance, and Administration Costs

OM&A costs for 2013 are expected to be consistent with 2012 OM&A, with cost savings as a result of organizational restructuring in the fourth quarter offset by additional costs as Sundance Units 1 and 2 are returned to service and the commencement of operations at our New Richmond wind farm.

Energy Trading

Earnings from our Energy Trading Segment are affected by prices in the market, overall strategies adopted, and changes in legislation. We continuously monitor both the market and our exposure in order to maximize earnings while still maintaining an acceptable risk profile.  Our target is for Energy Trading to contribute between $40 million and $60 million in gross margin for 2013.

Exposure to Fluctuations in Foreign Currencies

Our strategy is to minimize the impact of fluctuations in the Canadian dollar against the U.S. dollar, Euro, and Australian dollar by offsetting foreign denominated assets with foreign denominated liabilities and by entering into foreign exchange contracts. We also have foreign denominated expenses, including interest charges, which largely offset our net foreign denominated revenues.

Net Interest Expense

Net interest expense for 2013 is not expected to change materially compared to 2012. However, changes in interest rates and in the value of the Canadian dollar relative to the U.S. dollar can affect the amount of net interest expense incurred.

Liquidity and Capital Resources

If there is increased volatility in power and natural gas markets, or if market trading activities increase, we may need additional liquidity in the future. We expect to maintain adequate available liquidity under our committed credit facilities.

Accounting Estimates

A number of our accounting estimates, including those outlined in the Critical Accounting Policies and Estimates section of our 2012 Annual MD&A, are based on the current economic environment and outlook. As a result of the current economic environment, market fluctuations could impact, among other things, future commodity prices, foreign exchange rates, and interest rates, which could, in turn, impact future earnings and the unrealized gains or losses associated with our risk management assets and liabilities and asset valuation for our asset impairment calculations. 

Income Taxes

The effective tax rate on earnings excluding non-comparable items for 2013 is expected to be approximately 10 to 15 per cent, which is lower than the statutory tax rate of 25 per cent, due to changes in the amount of earnings between the jurisdictions in which pre-tax income is earned and the effect of certain deductions that do not fluctuate with earnings.

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Capital Expenditures

Our major projects are focused on sustaining our current operations and supporting our growth strategy.

Growth and Major Project Expenditures

We have one major project with a targeted completion date of Q4 2013. A summary is outlined below:

	Total Project		2013		Target completion date
	Estimated spend	Spent to date(1)	Estimated spend	Spent to date(1)		Details
Growth
New Richmond	212	216	15 - 25	28	Commercial operations began Q1 2013	A 68 MW wind farm in Quebec
Major projects
Sundance Units 1 and 2	190	92	130 - 145	48	Q4 2013	Sundance Units 1 and 2 comprising 560 MW of our Sundance power plant
Total major projects and growth	402	308	145 - 170	76

The total estimated spend for New Richmond is less than the amount incurred to date due to estimated recoveries to be received in 2013.

Transmission

For the three months ended March 31, 2013, a total of $2 million was spent on transmission projects.  The estimated spend for 2013 on transmission projects is $7 million.  Transmission projects consist of the major maintenance and reconfiguration of Alberta’s transmission networks to increase capacity of power flow in the lines. 

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Sustaining Capital and Productivity Expenditures⁽¹⁾

For 2013, our estimate for total sustaining capital and productivity expenditures, net of any contributions received, is allocated among the following:

Category	Description	Expected cost	Spent to date(1)
Routine capital	Expenditures to maintain our existing generating capacity	90 - 100	15
Mining equipment and land purchases	Expenditures related to mining equipment and land purchases	40 - 50	8
Planned major maintenance	Regularly scheduled major maintenance	165 - 185	28
Total sustaining expenditures		295 - 335	51
Productivity capital	Projects to improve power production efficiency	30 - 50	4
Total sustaining and productivity expenditures		325 - 385	55

As a result of assuming the operating and management control of the Highvale Mine, sustaining capital and productivity expenditures for 2013 may be adjusted throughout the year as additional costs are incurred.  We are currently assessing the impact that this will have on our 2013 sustaining capital and productivity expenditures. During the quarter, we acquired $21 million of mining equipment under a finance lease.

Our planned major maintenance program relates to regularly scheduled major maintenance activities and includes costs related to inspection, repair and maintenance, and replacement of existing components. It excludes amounts for day-to-day routine maintenance, unplanned maintenance activities, and minor inspections and overhauls, which are expensed as incurred. Details of the 2013 planned major maintenance program are outlined as follows:

	Coal	Gas and Renewables	Expected spend in 2013	Spent to date(1)
Capitalized	90 - 105	75 - 80	165 - 185	28
Expensed	-	0 - 5	0 - 5	-
	90 - 105	75 - 85	165 - 190	28
	Coal	Gas and Renewables	Expected total	Lost to date
GWh lost	1,660 - 1,670	420 - 430	2,080 - 2,100	228

Financing

Financing for these capital expenditures is expected to be provided by cash flow from operating activities, existing borrowing capacity, reinvested dividends under the Plan, and capital markets. The funds required for committed growth, sustaining capital, and productivity projects are not expected to be significantly impacted by the current economic environment due to the highly contracted nature of our cash flows, our financial position, and the amount of capital available to us under existing committed credit facilities.

([1]) Represents amounts incurred as of March 31, 2013.

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accounting changes

Adoption of New or Amended IFRS

On Jan. 1, 2013, we adopted the following new accounting standards that were previously issued by the International Accounting Standards Board (“IASB”):

IFRS 10 Consolidated Financial Statements

IFRS 10 replaces the parts of International Accounting Standard (“IAS”) 27 Consolidated and Separate Financial Statements that deal with consolidated financial statements and Standing Interpretations Committee (“SIC”) Interpretation 12 Consolidation - Special Purpose Entities.  IFRS 10 defines the principle of control, establishes control as the basis for determining when entities are to be consolidated, and provides guidance on how to apply the principle of control to identify whether an investor controls an investee.  Under IFRS 10, an investor controls an investee when it has all of the following: (i) power over the investee; (ii) exposure, or rights, to variable returns from the investee; and (iii) the ability to affect those returns.

We applied IFRS 10 retrospectively by reassessing whether, on Jan. 1, 2013, we had control of all of our previously consolidated entities. As a result of adopting IFRS 10, no changes arose in the entities we controlled and consolidated.

IFRS 11 Joint Arrangements

IFRS 11 replaces IAS 31 Interests in Joint Ventures and SIC-13 Jointly Controlled Entities – Non-Monetary Contributions by Venturers.  IFRS 11 provides for a principles-based approach to the accounting for joint arrangements that requires an entity to recognize its contractual rights and obligations arising from its involvement in joint arrangements.  A joint arrangement is an arrangement in which two or more parties have joint control.  Under IFRS 11, joint arrangements are classified as either a joint operation or a joint venture, whereas under IAS 31, they were classified as a jointly controlled asset, jointly controlled operation or a jointly controlled entity.  IFRS 11 requires the use of the equity method of accounting for interests in joint ventures, whereas IAS 31 permitted a choice of the equity method or proportionate consolidation for jointly controlled entities. Under IFRS 11, for joint operations, each party recognizes its respective share of the assets, liabilities, revenues and expenses of the arrangement, generally resulting in proportionate consolidation accounting. 

We applied IFRS 11 retrospectively by reassessing the type of, and accounting for, each joint arrangement in existence at
Jan. 1, 2013. No significant impacts resulted.

IFRS 12 Disclosure of Interests in Other Entities

IFRS 12 contains enhanced disclosure requirements about an entity’s interests in subsidiaries, joint arrangements, associates, and consolidated and unconsolidated structured entities (special purpose entities). The objective of IFRS 12 is that an entity should disclose information that helps financial statement users evaluate the nature of, and risks associated with, its interests in other entities and the effects of those interests on its financial statements. Disclosures arising from the adoption of IFRS 12 can be found in Notes 7, 10, and 18 of our interim consolidated financial statements.

IFRS 13 Fair Value Measurement

IFRS 13 establishes a single source of guidance for all fair value measurements required by other IFRS, clarifies the definition of fair value, and enhances disclosures about fair value measurements. IFRS 13 applies when other IFRS require or permit fair value measurements or disclosures. IFRS 13 specifies how an entity should measure fair value and disclose fair value information. It does not specify when an entity should measure an asset, a liability, or its own equity instrument at fair value. Our adoption of IFRS 13, prospectively on Jan. 1, 2013, did not have a material financial impact upon the consolidated financial position or results of operations, however, certain new or enhanced disclosures are required and can be found in Note 11 of our interim consolidated financial statements.

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IAS 1 Presentation of Financial Statements

Amendments to IAS 1 Presentation of Financial Statements issued in June 2011 were intended to improve the consistency and clarity of the presentation of items of comprehensive income by requiring that items presented in OCI be grouped on the basis of whether they are at some point reclassified from OCI to net earnings or not. The Consolidated Statements of Comprehensive Income (Loss) have been reorganized to comply with the required groupings.

IAS 19 Employee Benefits

Amendments to IAS 19 Employee Benefits are intended to improve the recognition, presentation, and disclosure of defined benefit plans. The amendments require the recognition of changes in defined benefit obligations and in fair value of plan assets when they occur, thus eliminating the “corridor approach” previously permitted. All actuarial gains and losses must be recognized immediately through other comprehensive income and the net pension liability or asset recognized at the full amount of the plan deficit or surplus. Additional changes relate to the presentation, into three components, of changes in defined benefit obligations and plan assets: service cost and net interest cost is recognized in net earnings and remeasurements are recognized in other comprehensive income. The net interest cost introduced in these amendments removes the concept of expected return on plan assets that was previously recognized in net earnings.

We calculate the net interest cost for our defined benefit plans by applying the discount rate at the beginning of the reporting period to the net defined benefit liability at the beginning of the reporting period. An expected return on plan assets is no longer calculated and recognized as part of pension expense. The elimination of the corridor method had no impact as we have, since adoption of IFRS, recognized actuarial gains and losses in OCI in the period in which they occurred.

On adoption, we applied the amendments retrospectively. The impacts as at Dec. 31, 2012 and Jan 1, 2012, respectively, were an increase in the cumulative prior periods’ pre-tax pension expense of $17 million and $11 million ($12 million and $8 million after-tax, respectively), as a result of the application of the net interest cost requirements.

For the three months ended March 31, 2012, OM&A expense increased by $1 million as a result of increased pension expense, Net actuarial losses on defined benefit plans as reported in OCI decreased by $1 million, and basic and diluted net earnings per share attributable to common shareholders decreased by $0.01.

Interpretation 20 Stripping Costs in the Production Phase of a Surface Mine (“IFRIC 20”)

IFRIC 20 clarifies the requirements for accounting for stripping costs in the production phase of a surface mine. Stripping costs are costs associated with the process of removing waste from a surface mine in order to gain access to mineral ore deposits. The Interpretation clarifies when production stripping should lead to the recognition of an asset and how that asset should be measured, both initially and in subsequent periods.

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We recognize a stripping activity asset for our Highvale mine when all of the following are met: (i) it is probable that the future benefit associated with improved access to the coal reserves associated with the stripping activity will be realized; (ii) the component of the coal reserve to which access has been improved can be identified; and (iii) the costs related to the stripping activity associated with that component can be measured reliably. Costs include those directly incurred to perform the stripping activity as well as an allocation of directly attributable overheads. The resulting stripping activity asset is amortized on a unit-of-production basis over the expected useful life of the identified component that it relates to. The amortization is recognized as a component of the standard cost of coal inventory.

As required by the transitional provision of IFRIC 20, we applied the Interpretation to production stripping costs incurred on or after Jan 1, 2011, which will be the earliest comparative period presented within our annual financial statements for the year ended
Dec. 31, 2013. The impacts on the Condensed Consolidated Statements of Financial Position as at Dec. 31, 2012 were to recognize $9 million in costs as a stripping activity asset, increase coal inventory by $2 million, both classified within Inventory, increase Deferred income tax liabilities by $3 million, and decrease Retained deficit by $8 million. The impacts on the Condensed Consolidated Statements of Financial Position as at Jan. 1, 2012 were to recognize $9 million in costs as a stripping activity asset, decrease coal inventory by $2 million, both classified within Inventory, increase Deferred income tax liabilities by $2 million, and increase Retained earnings by $5 million.

The impact of this change in accounting policy on the three months ended March 31, 2012 was not material.

IFRS 7 Financial Instruments: Disclosures

Amendments to IFRS 7 include disclosures about all recognized financial instruments that are set off in accordance with IAS 32. The amendments also require disclosure of information about recognized financial instruments subject to enforceable master netting arrangements and similar agreements even if they are not set off under IAS 32. The resulting disclosures can be found in Note 12 of our interim consolidated financial statements.

Annual Improvements 2009-2011

In May 2012, the IASB issued a collection of necessary, non-urgent amendments to several IFRS resulting from its annual improvements process. We have applied the amendments, as applicable, on Jan. 1, 2013. None of the amendments, which are generally technical and narrow in scope, had a material financial impact upon the consolidated financial position or results of operations.

future accounting changes

Additional new or amended accounting standards that have been previously issued by the IASB but are not yet effective, and have not yet been applied, are as follows: IFRS 9 Financial Instruments, IAS 32 Financial Instruments: Presentation, and Investment Entities (Amendments to IFRS 10 and 11 and IAS 27). Please refer to the Future Accounting Changes section of our 2012 Annual MD&A for more information.

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Additional IFRS Measures

An additional IFRS measure is a line item, heading, or subtotal that is relevant to an understanding of the financial statements but is not a minimum line item mandated under IFRS, or the presentation of a financial measure that is relevant to an understanding of the financial statements but is not presented elsewhere in the financial statements. We have included line items entitled “gross margin” and “operating income (loss)” in our Condensed Consolidated Statements of Earnings (Loss) for the three months ended
March 31, 2013 and 2012. Presenting these line items provides management and investors with a measurement of ongoing operating performance that is readily comparable from period to period.

NON-IFRS MEASURES

We evaluate our performance and the performance of our business segments using a variety of measures. Those discussed below, and elsewhere in this MD&A, are not defined under IFRS and, therefore, should not be considered in isolation or as an alternative to or to be more meaningful than net earnings attributable to common shareholders or cash flow from operating activities, as determined in accordance with IFRS, when assessing our financial performance or liquidity. These Non-IFRS measures are not necessarily comparable to a similarly titled measure of another company.

Presenting earnings on a comparable basis, comparable gross margin, comparable operating income, and comparable EBITDA from period to period provides management and investors with supplemental information to evaluate earnings trends in comparison with results from prior periods. In calculating these items, we exclude the impact related to certain hedges that are either
de-designated or deemed ineffective for accounting purposes, as management believes that these transactions are not representative of our business operations. As these gains (losses) have already been recognized in earnings in current or prior periods, future reported earnings will be lower; however, the expected cash flows from these contracts will not change. In calculating comparable earnings measures we have also excluded the first quarter 2012 coal inventory writedown, as the recognition of the writedown is related to the hedges that were de-designated or deemed ineffective during prior quarters.

Other adjustments to earnings, such as the income tax recovery related to the deferred tax rate adjustment, the income tax recovery related to the resolution of certain outstanding tax matters, the gain on sale of assets, and restructuring charges have also been excluded as management believes these transactions are not representative of our business operations. Earnings on a comparable basis per share are calculated using the weighted average common shares outstanding during the period.

Comparable operating income and EBITDA also include the earnings from the finance lease facilities that we operate.  The finance lease income is used as a proxy for the operating income and EBITDA of these facilities.

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Net Earnings on a Comparable Basis

Net earnings on a comparable basis are reconciled to net earnings attributable to common shareholders below:

	3 months ended March 31
	2013	2012
Net earnings (loss) attributable to common shareholders	(11)	88
Impacts associated with certain de-designated and ineffective hedges, net of tax	27	(55)
Inventory writedown, net of tax	-	22
Income tax recovery related to deferred tax rate adjustment	(6)	-
Income tax recovery related to the resolution of certain outstanding tax matters	-	(9)
Gain on sale of assets, net of tax	-	(2)
Loss on assumption of pension obligations, net of tax	22	-
Net earnings on a comparable basis	32	44
Weighted average number of common shares outstanding in the period	258	225
Net earnings on a comparable basis per share	0.12	0.20

Comparable Gross Margin

Comparable gross margin is calculated as follows:

	3 months ended March 31
	2013	2012
Gross margin	339	469
Impacts associated with certain de-designated and ineffective hedges	41	(85)
Impacts to revenue associated with Sundance Units 1 and 2(1)	-	(10)
Comparable gross margin	380	374

Comparable Operating Income

A reconciliation of comparable operating income is as follows:

	3 months ended March 31
	2013	2012
Operating income	76	171
Impacts associated with certain de-designated and ineffective hedges	41	(85)
Inventory writedown	-	34
Finance lease income	11	2
Comparable operating income	128	122

(1) The results have been adjusted retroactively for the impact of Sundance Units 1 and 2. Comparative figures have also been adjusted in this table only to provide period over period comparability. 

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Comparable EBITDA

Presenting comparable EBITDA from period to period provides management and investors with a proxy for the amount of cash generated from operating activities before net interest expense, non-controlling interests, income taxes, and working capital adjustments.

A reconciliation of comparable EBITDA to operating income is as follows:

	3 months ended March 31
	2013	2012
Operating income	76	171
Inventory writedown	-	34
Finance lease income	11	2
Depreciation and amortization per the Consolidated Statements of Cash Flows(1)	139	140
Impacts associated with certain de-designated and ineffective hedges	41	(85)
Impacts to revenue associated with Sundance Units 1 and 2	-	(10)
Comparable EBITDA	267	252

Funds from Operations and Funds from Operations per Share

Presenting funds from operations and funds from operations per share from period to period provides management and investors with a proxy for the amount of cash generated from operating activities, before changes in working capital, and provides the ability to evaluate cash flow trends more readily in comparison with results from prior periods. Funds from operations per share is calculated as follows using the weighted average number of common shares outstanding during the period:

	3 months ended March 31
	2013	2012
Cash flow from operating activities	256	183
Payment of restructuring costs	4	-
Timing of payments related to assumption of pension obligations	9	-
Change in non-cash operating working capital balances	(77)	6
Funds from operations	192	189
Weighted average number of common shares outstanding in the period	258	225
Funds from operations per share	0.74	0.84

(1) To calculate comparable EBITDA, we use depreciation and amortization per the Condensed Consolidated Statements of Cash Flows in order to account for depreciation related to mine assets, which is included in fuel and purchased power on the Condensed Consolidated Statements of Earnings.

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Free Cash Flow

Free cash flow represents the amount of cash generated from operations by our business, before changes in working capital, that is available to invest in growth initiatives, make scheduled principal repayments of debt, pay additional common share dividends, or repurchase common shares. Changes in working capital are excluded so as to not distort free cash flow with changes that we consider temporary in nature, reflecting, among other things, the impact of seasonal factors and the timing of capital projects.

Sustaining capital and productivity expenditures for the three months ended March 31, 2013 represent total additions to property, plant, and equipment and intangibles per the Condensed Consolidated Statements of Cash Flows less $77 million that we have invested in projects and growth. For the same period in 2012, we invested $37 million ($36 million net of joint venture contributions) in projects and growth.

The reconciliation between cash flow from operating activities and free cash flow is outlined below:

	3 months ended March 31
	2013	2012
Cash flow from operating activities	256	183
Add (deduct):
Changes in non-cash operating working capital	(77)	6
Sustaining capital and productivity expenditures	(55)	(107)
Dividends paid on common shares(1)	(20)	(45)
Dividends paid on preferred shares	(9)	(8)
Distributions paid to subsidiaries' non-controlling interests	(19)	(19)
Free cash flow	76	10

We seek to maintain sufficient cash balances and committed credit facilities to fund periodic net cash outflows related to our business.

SELECTED QUARTERLY INFORMATION

	Q2 2012	Q3 2012	Q4 2012	Q1 2013
Revenue	398	522	646	540
Net earnings (loss) attributable to common shareholders	(798)	56	39	(11)
Net earnings (loss) per share attributable to common shareholders, basic and diluted	(3.52)	0.24	0.15	(0.04)
Comparable earnings (loss) per share	(0.10)	0.18	0.22	0.12
	Q2 2011	Q3 2011	Q4 2011	Q1 2012
Revenue	507	613	688	644
Net earnings attributable to common shareholders	12	50	24	88
Net earnings per share attributable to common shareholders, basic and diluted	0.05	0.22	0.11	0.39
Comparable earnings per share	0.29	0.27	0.13	0.20

(1) Net of dividends reinvested under the Plan

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Basic and diluted earnings per share attributable to common shareholders and comparable earnings per share are calculated each period using the weighted average common shares outstanding during the period. As a result, the sum of the earnings per share for the four quarters making up the calendar year may sometimes differ from the annual earnings per share.

disclosure controls and procedures

As required by Rule 13a-15 under the Securities Exchange Act of 1934 (“Exchange Act”), management has evaluated, with the participation of our Chief Executive Officer and Chief Financial Officer, the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Disclosure controls and procedures refer to controls and other procedures designed to ensure that information required to be disclosed in the reports we file or submit under the Exchange Act are recorded, processed, summarized, and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in our reports that we file or submit under the Exchange Act is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding our required disclosure. In designing and evaluating our disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and management is required to apply its judgment in evaluating and implementing possible controls and procedures.

There has been no change in the internal control over financial reporting during the period covered by this report that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting. Based on the foregoing evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that, as of March 31, 2013, the end of the period covered by this report, our disclosure controls and procedures were effective at a reasonable assurance level.

FORWARD-LOOKING STATEMENTS

This MD&A, the documents incorporated herein by reference, and other reports and filings made with the securities regulatory authorities include forward-looking statements. All forward-looking statements are based on our beliefs as well as assumptions based on information available at the time the assumption was made and on management’s experience and perception of historical trends, current conditions and expected future developments, as well as other factors deemed appropriate in the circumstances. Forward-looking statements are not facts, but only predictions and generally can be identified by the use of statements that include phrases such as “may”, “will”, “believe”, “expect”, “anticipate”, “intend”, “plan”, “foresee”, “potential”, “enable”, “continue” or other comparable terminology. These statements are not guarantees of our future performance and are subject to risks, uncertainties, and other important factors that could cause our actual performance to be materially different from that projected.

In particular, this MD&A contains forward-looking statements pertaining to the following: expectations relating to the timing of the completion and commissioning of projects under development, including uprates and major projects, and their attendant costs; our estimated spend on growth and sustaining capital and productivity projects; expectations in terms of the cost of operations, capital spend, and maintenance, and the variability of those costs; the impact of certain hedges on future reported earnings and cash flows; expectations related to future earnings and cash flow from operating and contracting activities; estimates of fuel supply and demand conditions and the costs of procuring fuel; expectations for demand for electricity in both the short term and long term, and the resulting impact on electricity prices; expected impacts of fewer anticipated turnarounds, load growth, increased capacity, and natural gas costs on power prices; expectations in respect of generation availability, capacity, and production; expected financing of our capital expenditures; expected governmental regulatory regimes and legislation and their expected impact on us, as well as the cost of complying with resulting regulations and laws; our trading strategy and the risk involved in these strategies; estimates of future tax rates, future tax expense, and the adequacy of tax provisions; accounting estimates; anticipated growth rates in our markets; expectations for the outcome of existing or potential legal and contractual claims; expectations for the ability to access capital markets at reasonable terms; the estimated impact of changes in interest rates and the value of the Canadian dollar relative to the U.S. dollar; the monitoring of our exposure to liquidity risk; expectations in respect to the global economic environment; our credit practices; and the estimated contribution of Energy Trading activities to gross margin.

transalta corporation / Q1 2013   34

Factors that may adversely impact our forward-looking statements include risks relating to: fluctuations in market prices and the availability of fuel supplies required to generate electricity; our ability to contract our generation for prices that will provide expected returns; the regulatory and political environments in the jurisdictions in which we operate; environmental requirements and changes in, or liabilities under, these requirements; changes in general economic conditions including interest rates; operational risks involving our facilities, including unplanned outages at such facilities; disruptions in the transmission and distribution of electricity; the effects of weather; disruptions in the source of fuels, water, or wind required to operate our facilities; natural disasters; the threat of domestic terrorism and cyber-attacks; equipment failure; energy trading risks; industry risk and competition; fluctuations in the value of foreign currencies and foreign political risks; the need for additional financing; structural subordination of securities; counterparty credit risk; insurance coverage; our provision for income taxes; legal and contractual proceedings involving the Corporation; reliance on key personnel; labour relations matters; and development projects and acquisitions. The foregoing risk factors, among others, are described in further detail in the Risk Management section of our 2012 Annual MD&A and under the heading “Risk Factors” in our 2013 Annual Information Form.

Readers are urged to consider these factors carefully in evaluating the forward-looking statements and are cautioned not to place undue reliance on these forward-looking statements. The forward-looking statements included in this document are made only as of the date hereof and we do not undertake to publicly update these forward-looking statements to reflect new information, future events or otherwise, except as required by applicable laws. In light of these risks, uncertainties, and assumptions, the forward-looking events might occur to a different extent or at a different time than we have described, or might not occur. We cannot assure that projected results or events will be achieved.

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Supplemental information

		March 31, 2013	Dec. 31, 2012
Closing market price (TSX) ($)		14.85	15.12
Price range for the last 12 months (TSX) ($)	High	16.86	21.37
	Low	14.59	14.11
Debt to invested capital (%)		55.8	55.6
Debt to invested capital excluding non-recourse debt (%)(1)		53.5	53.3
Debt to invested capital including finance lease obligation and non-recourse debt (%)		55.9	55.6
Return on equity attributable to common shareholders (%)		(27.5)	(23.7)
Comparable return on equity attributable to common shareholders(1), (2) (%)		4.0	4.5
Return on capital employed(2) (%)		(4.6)	(3.1)
Comparable return on capital employed(1), (2) (%)		5.9	5.3
Cash dividends per share(2) ($)		1.16	1.16
Price to comparable earnings ratio(2) (times)		35.4	30.2
Earnings coverage(2) (times)		(1.7)	(1.2)
Dividend payout ratio based on net earnings(2) (%)		(39.4)	(44.1)
Dividend payout ratio based on comparable earnings(1), (2) (%)		267.6	231.6
Dividend payout ratio based on funds from operations(1), (2), (3) (%)		35.9	34.7
Dividend yield(2) (%)		7.8	7.7
Adjusted cash flow to debt(2), (3) (%)		19.1	19.0
Adjusted cash flow to interest coverage(2), (3) (times)		4.4	4.4

(1) These ratios incorporate items that are not defined under IFRS. None of these measurements should be used in isolation or as a substitute for the Corporation’s reported financial performance or position as presented in accordance with IFRS. These ratios are useful complementary measurements for assessing the Corporation’s financial performance, efficiency, and liquidity and are common in the reports of other companies but may differ by definition and application. For a reconciliation of the Non-IFRS measures used in this calculation, refer to the Non-IFRS Measures section of this MD&A.

(2) Last 12 months.

(3) These ratios have been adjusted for the impact of the Sundance Units 1 and 2 arbitration, payment of restructuring costs, and timing of payments related to assumption of pension obligations.

Ratio Formulas

Debt to invested capital = long-term debt including current portion - cash and cash equivalents / long-term debt including current portion + non-controlling interests + equity attributable to shareholders - cash and cash equivalents

Return on equity attributable to common shareholders = net earnings attributable to common shareholders or earnings on a comparable basis / average equity attributable to common shareholders excluding AOCI

Return on capital employed = earnings before non-controlling interests and income taxes + net interest expense or comparable earnings before non-controlling interests and income taxes + net interest expense / average invested capital excluding AOCI

Price to comparable earnings ratio = current period’s closing market price / comparable earnings per share

Earnings coverage = net earnings attributable to common shareholders+ income taxes + net interest expense / interest on debt - interest income

Dividend payout ratio = common share dividends / net earnings attributable to common shareholders or earnings on a comparable basis or funds from operations

Dividend yield = dividend per common share / current period’s closing market price

Adjusted cash flow to debt = cash flow from operating activities before changes in working capital / average total debt - average cash and cash equivalents

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Adjusted cash flow to interest coverage = cash flow from operating activities before changes in working capital + interest on debt - interest income - capitalized interest / interest on debt - interest income

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GLOSSARY OF KEY TERMS

Availability - A measure of the time, expressed as a percentage of continuous operation 24 hours a day, 365 days a year that a generating unit is capable of generating electricity, regardless of whether or not it is actually generating electricity.

British Thermal Units (Btu) - A measure of energy. The amount of energy required to raise the temperature of one pound of water one degree Fahrenheit, when the water is near 39.2 degrees Fahrenheit.

Capacity - The rated continuous load-carrying ability, expressed in megawatts, of generation equipment.

Derate - To lower the rated electrical capability of a power generating facility or unit.

Force Majeure - Literally means “major force”. These clauses excuse a party from liability if some unforeseen event beyond the control of that party prevents it from performing its obligations under the contract.

Geothermal Plant - A plant in which the prime mover is a steam turbine. The turbine is driven either by steam produced from hot water or by natural steam that derives its energy from heat found in rocks or fluids at various depths beneath the surface of the earth. The energy is extracted by drilling and/or pumping.

Gigawatt - A measure of electric power equal to 1,000 megawatts.

Gigawatt Hour (GWh) - A measure of electricity consumption equivalent to the use of 1,000 megawatts of power over a period of one hour.

Greenhouse Gas (GHG) - Gases having potential to retain heat in the atmosphere, including water vapour, carbon dioxide, methane, nitrous oxide, hydrofluorocarbons, and perfluorocarbons.

Heat Rate - A measure of conversion, expressed as Btu/MWh, of the amount of thermal energy required to generate electrical energy.

Megawatt (MW) - A measure of electric power equal to 1,000,000 watts.

Megawatt Hour (MWh) - A measure of electricity consumption equivalent to the use of 1,000,000 watts of power over a period of one hour.

Net Maximum Capacity - The maximum capacity or effective rating, modified for ambient limitations, that a generating unit or power plant can sustain over a specific period, less the capacity used to supply the demand of station service or auxiliary needs.

Power Purchase Arrangement (PPA) - A long-term arrangement established by regulation for the sale of electric energy from formerly regulated generating units to PPA Buyers.

Renewable Power - Power generated from renewable terrestrial mechanisms including wind, geothermal, solar, and biomass with regeneration.

Spark Spread - A measure of gross margin per MW (sales price less cost of natural gas).

Supercritical Combustion Technology: The most advanced coal-combustion technology in Canada employing a supercritical boiler, high-efficiency multi-stage turbine, flue gas desulphurization unit (scrubber), bag house, and low nitrogen oxide burners.

Turbine - A machine for generating rotary mechanical power from the energy of a stream of fluid (such as water, steam, or hot gas). Turbines convert kinetic energy of fluids to mechanical energy through the principles of impulse and reaction or a mixture of the two.

Turnaround: Periodic planned shutdown of a generating unit for major maintenance and repairs. Duration is normally in weeks. The time is measured from unit shutdown to putting the unit back on line.

Unplanned Outage - The shut down of a generating unit due to an unanticipated breakdown.

Uprate - To increase the rated electrical capability of a power generating facility or unit.

Value at Risk (VaR) - A measure to manage earnings exposure from energy trading activities.

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TransAlta Corporation

110 - 12th Avenue S.W.

Box 1900, Station “M”

Calgary, Alberta Canada T2P 2M1

Phone

403.267.7110

Website

www.transalta.com

CIBC Mellon Trust Company

P.O. Box 7010 Adelaide Street Station

Toronto, Ontario Canada M5C 2W9

Phone

Toll-free in North America: 1.800.387.0825

Toronto or outside North America: 416.643.5500

Fax

416.643.5501

Website

www.cibcmellon.com

FOR MORE INFORMATION

Media and Investor Inquiries

Investor Relations

Phone

1.800.387.3598 in Canada and United States

or 403.267.2520

Fax

403.267.2590

E-mail

investor_relations@transalta.com

transalta corporation / Q1 2013   39

EX-99.1

TransAlta Reports Solid First Quarter 2013 Results

HIGHLIGHTS

· Strong fleet availability of 91.5 per cent for the quarter - supporting the annual target of 89 to 90 per cent

· Comparable EBITDA^(1,2,3) increased to $267 million for the quarter, up $15 million from the same period in 2012 driven by increased production from the generation segment

· Funds From Operations^(2,3) (“FFO”) increased $3 million to $192 million compared to prior year

· Operations Maintenance and Administration costs (“OM&A”) declined $13 million from the same period in 2012

· Energy Trading results delivered $17 million of gross margin in the first quarter

· New Richmond wind farm in Quebec began commercial operation on March 13, 2013, adding 68 MW to TransAlta’s renewables portfolio

CALGARY, Alberta (Apr. 23, 2013) – TransAlta Corporation (TransAlta) (TSX: TA; NYSE: TAC) today reported a comparable EBITDA increase of $15 million to $267 million compared to the first quarter of 2012 and an increase in funds from operations of $3 million to $192 million compared to the prior year.

“I am pleased to release results today that demonstrate another solid quarter for TransAlta with higher year over year production as well as strong fleet availability which support our annual targets,” said Dawn Farrell, President and CEO. “Furthermore, we have been able to offset declines in revenue from low pricing in our Centralia operations with strong performance by our fleet and growth from our Solomon acquisition. Our cost reduction efforts from last year are holding and our teams are focused on growth. The addition of the New Richmond wind farm will be a positive contribution to shareholder value going forward.”

Despite delivering a solid operational quarter and consistent EBITDA, comparable earnings⁽²⁾ decreased year over year largely due to lower comparable tax recoveries in the quarter compared to the same period in 2012 which recorded a substantial recovery from a one-time win.

(1) EBITDA refers to Earnings before interest, taxes, depreciation and amortization.

(2) Comparable earnings (loss), comparable earnings (loss) per share, comparable EBITDA, and funds from operations, are not defined under International Financial Reporting Standards (“IFRS”). Presenting these measures from period to period provides supplemental information to help management and shareholders evaluate earnings’ trends in comparison with prior periods' results. Refer to the Non-IFRS Measures section of the Management's Discussion and Analysis ("MD&A") for further discussion of these items, including, where applicable, reconciliations to net earnings (loss) attributable to common shareholders, operating income (loss), and cash flow from operating activities.

(3) Comparable EBITDA and funds from operations are key supplemental performance measures for TransAlta which provide additional information regarding the company’s ability to cover its capital requirements and dividends as well as strengthen its balance sheet and finance growth.

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The company recorded a loss of $11 million on reported earnings for the quarter primarily driven by the de-designation of hedges. For these contracts that settled in the first quarter of 2013, the related gain had already been recognized in earnings during the first quarter of 2012, with the cash received in 2013. TransAlta also recorded a one-time loss due to the realization of pension funding obligations associated with the management of the Highvale mine which were previously included in the cost of coal.

Consistent Strength in Generation Performance Helping Offset Unfavorable Contract Pricing Conditions

Fleet availability remained strong for first quarter 2013 at 91.5 per cent compared to 91.7 per cent over the same period last year. TransAlta is close to completing one of four major maintenance outages planned on its coal units for the year and remains on track to deliver on its fleet availability goal of 89 – 90 per cent for the full year.

Highlights - TransAlta first quarter 2013

Financial

· Funds from operations of $192 million or $0.74 per share

· Comparable earnings of $32 million or $0.12 per share

· Dividends paid of $0.29 per share to common shareholders

· Solomon acquisition contributed $9 million to comparable EBITDA

Operating

· Coal: Comparable gross margins from TransAlta’s coal fleet decreased $5 million quarter over quarter primarily as a result of higher unplanned outages and higher outage penalties due to higher rolling average pool prices.

· Gas: Comparable gross margins from TransAlta’s gas fleet, excluding contributions from the Solomon acquisition, decreased $4 million quarter over quarter as a result of increased gas input costs

· Renewables: Comparable gross margins increased $5 million quarter over quarter primarily due to higher hydro margins

· Energy Trading: Gross margins were consistent quarter over quarter at $17 million for the current quarter

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Major maintenance

· 2013 marks the return to a normalized planned major maintenance program. TransAlta has nearly completed the planned Sundance Unit 4 outage - the first of four major outages scheduled for 2013. The three remaining major maintenance coal outages are on track to be completed in 2013.

Growth

· TransAlta expanded its Canadian renewables fleet with the addition of the 68 MW New Richmond wind farm in Quebec, which began commercial operation on March 13, 2013

Significant Events

Keephills Unit 1

On March 26, 2013, TransAlta announced an outage that occurred on March 5, 2013 at Unit 1 of our Keephills facility due to a winding failure found in the generator. TransAlta has given notice under the Power Purchase Arrangement (“PPA”) to the PPA Buyer and the Balancing Pool of a High Impact Low Probability (“HILP”) Force Majeure event.  In the event of force majeure, TransAlta is entitled to continue to receive its PPA capacity payment and is protected under the terms of the PPA from having to pay availability penalties. As a result, TransAlta does not expect the outage to have a material financial impact on the Corporation.TransAlta is working with the original equipment manufacturer of the generator to safely return the Unit to service, which is currently expected to be in early May 2013.

Centralia Thermal

On July 25, 2012, TransAlta announced that it had entered into an 11-year agreement to provide electricity from the Centralia Thermal plant to Puget Sound Energy (“PSE”). The agreement was approved, with conditions, by the Washington Utilities and Transportation Commission (“WUTC”) on

January 9, 2013. On January 23, 2013, it was announced that PSE had filed a petition for reconsideration of certain conditions within the decision issued by the WUTC. On March 22, 2013, the administrative law judge managing the regulatory hearing process issued two Commission Orders to establish an amended timeline for addressing the petition for reconsideration. The deadline for filing answers to the reconsideration motion is May 30, 2013, and the timeline for a decision on the reconsideration motion is no later than June 28, 2013.

Sunhills Mining Limited Partnership

Effective January 17, 2013, TransAlta assumed, through its wholly owned Sunhills Mining Limited Partnership (“Sunhills”), operations and management control of the Highvale Mine. TransAlta and the previous service provider are committed to a seamless transition including continued employment at the Highvale Mine for more than 600 people and consequently, Sunhills agreed to assume responsibility for certain pension plan and pension funding obligations which we had previously funded through the payments made under the mining contracts. As a result, a pre-tax loss of $29 million was recognized, along with the corresponding liabilities.

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Sunhills also entered into a finance lease for certain mining equipment that was used by the service provider in mining operations. As a result, $21 million in mining equipment has been capitalized to property, plant and equipment and the related finance lease obligation recognized. Sunhills is eligible to purchase the assets subject to lease, at the end of the lease term, for a nominal amount.

The following table depicts key financial results and statistical operating data:

First Quarter 2013 Highlights

In $CAD millions, unless otherwise stated	3 months ended March 31, 2013	3 months ended March 31, 2012
Availability (%)	91.5	91.7
Production (GWh)	10,644	9,441
Revenue	$540	$644
Gross margin(1)	$339	$469
Operating income(1)	$76	$171
Net earnings (loss) attributable to common shareholders	$(11)	$88
Comparable earnings(2)	$32	$44
Basic and diluted earnings (loss) per common share	$(0.04)	$0.39
Comparable earnings per share(2)	$0.12	$0.20
Comparable Earnings before interest, taxes, depreciation, and amortization (EBITDA)(2)	$267	$252
Funds from operations(2)	$192	$189
Funds from operations per share(2)	$0.74	$0.84
Cash flow from operations	$256	$183

(1) Gross margin and operating income are Additional IFRS measures. Refer to the Additional IFRS measures section of the MD&A.

(2) Comparable earnings, comparable earnings per share, comparable EBITDA, funds from operations, and funds from operations per share are not defined under IFRS. Refer to the Non-IFRS financial measures section of the MD&A for an explanation and, where applicable, reconciliations to net earnings (loss) attributable to common shareholders, operating income (loss) and cash flow from operating activities.

The complete first quarter report for 2013, including MD&A and unaudited interim financial statements, as well as our first quarter presentation is available on the Investors section of our website: www.transalta.com.

Conference call

TransAlta will hold a conference call and web cast at 2:30 p.m. MT (4:30 p.m. ET) today to discuss first quarter 2013 results. The call will begin with a short address by Dawn Farrell, President and CEO, and Brett Gellner, Chief Financial Officer, followed by a question and answer period for investment analysts, investors, and other interested parties. A question and answer period for the media will immediately follow.

Please contact the conference operator five minutes prior to the call, noting "TransAlta Corporation" as the company and "Brent Ward" as moderator.

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Dial-in numbers:

Toll-free North American participants – 1-800-319-4610
Outside of Canada & USA call – 1-604-638-5340

A link to the live webcast will be available on the Investor Centre section of TransAlta’s website at http://www.transalta.com/investor-centre/events-presentations/webcasts-conference-calls. If you are unable to participate in the call, the instant replay is accessible at 1-604-638-9010 with TransAlta pass code 2231 followed by the # sign. A transcript of the broadcast will be posted on TransAlta’s website once it becomes available.

Note: If using a hands-free phone, lift the handset and press one to ask a question.

TransAlta is a power generation and wholesale marketing company focused on creating long-term shareholder value. TransAlta maintains a low-to-moderate risk profile by operating a highly contracted portfolio of assets in Canada, the United States and Australia. TransAlta’s focus is to efficiently operate geothermal, wind, hydro, natural gas and coal facilities in order to provide customers with a reliable, low-cost source of power. For over 100 years, TransAlta has been a responsible operator and a proud contributor to the communities in which it works and lives. TransAlta has been selected by Jantzi-Sustainalytics as one of Canada’s Top 50 Socially Responsible Companies since 2009 and is recognized globally for its leadership on sustainability and corporate responsibility standards by FTSE4Good. TransAlta is Canada’s largest investor-owned renewable energy provider.

This news release may contain forward looking statements, including statements regarding the business and anticipated financial performance of TransAlta Corporation. These statements are based on TransAlta Corporation’s belief and assumptions based on information available at the time the assumption was made. These statements are subject to a number of risks and uncertainties that may cause actual results to differ materially from those contemplated by the forward-looking statements. Some of the factors that could cause such differences include legislative or regulatory developments, competition, global capital markets activity, changes in prevailing interest rates, currency exchange rates, inflation levels, commodity prices and general economic conditions in geographic areas where TransAlta Corporation operates.

Note: All financial figures are in Canadian dollars unless noted otherwise.

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For more information:

Investor inquiries:	Media inquiries:
Brent Ward	Stacey Hatcher
Director, Corporate Finance and Investor Relations	Senior Corporate Relations Advisor
Phone: 1-800-387-3598 in Canada and U.S.	Cell: 587-216-2242
Email: investor_relations@transalta.com	Toll-free media number: 1-855-255-9184
	Alternate local number: 403-267-2540